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HomeMy WebLinkAbout2024-04-17 AEA Agenda and docs 813 West Northern Lights Boulevard, Anchorage, Alaska 99503 T 907.771.3000 Toll Free 888.300.8534 F 907.771.3044 REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG Alaska Energy Authority Board Meeting Wednesday, April 17, 2024 8:30 AM AGENDA - UPDATED Dial 1 (888) 585-9008 and enter code 212-753-619# Public comment guidelines are below. 1. CALL TO ORDER 2. ROLL CALL BOARD MEMBERS 3. AGENDA APPROVAL 4. PRIOR MINUTES – March 6, 2024 5. PUBLIC COMMENTS (2 minutes per person) see call in number above 6. NEW BUSINESS - None 7. OLD BUSINESS – A. Resolution No. 2024-04 Railbelt Innovative Resiliency Project, GRIP 3, Round 2 Application Submittal B. FY25 Budget Update C. Indirect Cost Allocation Plan Update 8. DIRECTOR COMMENTS A. Railbelt Opportunities – Map and Pitch Sheets B. IIJA Update i. IIJA Tracker ii. Railbelt Innovative Resiliency Project (GRIP 3) Update iii. EPA’s Climate Pollution Reduction Grant (CPRG) – Dixon Diversion iv. EPA’s Climate Pollution Reduction Grant (CPRG) – Rural Energy Programs v. Energy Auditor Training Grant Concept Paper – Commercial (AEA) vi. Energy Auditor Training Grant Concept Paper- Residential (AEA for AHFC) vii. Naknek-Dillingham Intertie & BESS Project (GRIP 2, SmartGrid Grants) C. Power Cost Equalization (PCE) Endowment Fund Update D. Rural Update E. Legislative Update F. Community Outreach G. Articles of Interest H. Next Regularly Scheduled AEA Board Meeting Wednesday, May 15, 2024 9. BOARD COMMENTS 10. ADJOURNMENT Public Comment Guidelines Members of the public who wish to provide written comments, please email your comments to publiccomment@akenergyauthority.org by no later than 4 p.m. on the day before the meeting, so they can be shared with board members prior to the meeting. Alaska Energy Authority Page 2 of 2 On the meeting day, callers will enter the teleconference muted. After board roll call and agenda approval, we will ask callers to press *9 on their phones if they wish to make a public comment. This will initiate the hand-raising function. We will unmute callers individually in the order the calls were received. When an individual is unmuted, you will hear, “It is now your turn to speak.” Please identify yourself and make your public comments. 813 W Northern Lights Blvd, Anchorage, AK 99503  Phone: (907) 771-3000  Fax: (907) 771-3044  Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG Alaska Energy Authority Board MEETING MINUTES Wednesday, March 6, 2024 Anchorage, Alaska 1. CALL TO ORDER Chair Dana Pruhs called the meeting of the Alaska Energy Authority Board to order on March 6, 2024, at 8:40 a.m. 2. ROLL CALL BOARD MEMBERS Members present: Chair Dana Pruhs (Public Member); Vice Chair Bill Kendig (Public Member); Julie Sande (Commissioner DCCED); Q. Smyth on behalf of Adam Crum (Commissioner DOR); Bill Vivlamore (Public Member); and Randy Eledge (Public Member) Absent: Albert Fogle (Public Member) A quorum was established. 3. AGENDA APPROVAL MOTION: Commissioner Sande moved to approve the agenda as presented. Motion was seconded by Mr. Randy Eledge. The motion to approve the agenda passed without objection. 4: PRIOR MINUTES - January 24, 2024 MOTION: Commissioner Sande moved to approve the minutes of the January 24, 2024 board meeting. Motion was seconded by Mr. Randy Eledge. The motion to approve the meeting minutes passed without objection. 5. PUBLIC COMMENTS (2 minutes per person) There were no members of the public online or in-person who made any comments. 6. NEW BUSINESS - None 7. OLD BUSINESS A. Resolution 2024-01 FY25 Operating and Capital Budget Submission Ratification Alaska Energy Authority Page 2 of 12 Mr. Curtis Thayer stated that normally the Board approves the Governor’s operating and capital budget as presented in January. But we delayed this year in hopes that there would be an outcome of the $206.5 million matching funds and what that would look like. This item is still pending. So, we’re moving forward with our ratification of this resolution in support of the Governor’s operating and capital budget for Alaska Energy Authority (AEA) subject to approval by the state legislature. AEA’s operating budget for FY25 would be $60,541,800, which is for personnel and the Power Cost Equalization (PCE) program. This year, we are asking for an additional person in accounting for Bradley Lake, so there will be two. AEA’s capital budget is $14,000,515 from the state and $69,660,093 from the federal government for a total capital budget of $84,176,000. This figure does not include the $205.5 million in federal funds and whatever match the governor and legislature makes for the state. As an additional note, AEA is not the only agency looking for matching funds from the state for federal grants. So, our ask could be part of a larger package. AEA has $166 million in bonds, of which $90 million has already been set aside to upgrade the SSQ line that is underway. As a reminder, the board received approval from Department of Law, Bradley Lake Project Management Committee (BPMC), and the bondholders to dedicate $20 million of the $166 million for this grant match. The advantage of this path is that these funds are immediately available upon signing of the grant agreement. So we can begin project work in May or June. Otherwise, we would have to wait until July 1, 2024, for the funds to become available from the general fund and would not be able to start project work until July or August. Board members asked how the funding with federal dollars will work. Curtis responded that as the state provides matching funds, the Department of Energy (DOE) will release funds. So, we have this initial $20 million, they will release $20 million to us. And so it will go until we reach $206.5 million. If for some reason, the state funds the entire $206.5 million in a lump sum, DOE will release $206.5 million. AEA staff have a standing weekly call with DOE to work through the grant agreement and any questions that arise about the project or the process, including funding. There is more information about the grant in the board’s packet, including terms and conditions from AEA. Mr. Thayer wants to make sure the board has seen every document before he signs the grant agreement. Legal counsel is also reviewing these documents. Our original scope of work had the line going from Kenai to Beluga, and then on to Healy. DOE only wants to fund to Beluga. So we had to adjust the scope of work. In addition we had to submit a cyber security plan to DOE. AEA has met every deadline through this grant process and schedule. As we progress, either at the board’s April meeting or through a special meeting, Mr. Thayer stated he will ask for a resolution from the board granting him authorization to sign the grant agreement on behalf of AEA. Commissioner Sande stated that she has witnessed some of what Curtis and his team have done in achieving this grant for the state and it makes her very proud of them and appreciative of their efforts. She added that the delay in the budget process is not a reflection on the team, but rather on the timing of the award in the midst of our state budget process. In addition, there is Alaska Energy Authority Page 3 of 12 the change to the scope of work and the impact it has to the schedule. She asked if the portion of the project from Beluga to Healy will be included in round two application of the grant program. Mr. Thayer responded that yes, it will. Round One funds the line from Kenai to Beluga and battery storage energy systems in Anchorage and in Fairbanks. Round Two grant application will include the line from Beluga to Healy. At Healy, there will be two transmission lines to give us redundancy. We provided a concept paper to DOE on this project and were asked to submit a grant application. That application is due April 17. So we won’t know if we have the grant until July or August. Again, it would be a 50/50 match of funds. Board members discussed the potential cost of the second project. With approximately 240 miles of line, it will be a larger ask than the current $206.5 million. However, this project would provide transmission lines over land as opposed to undersea cable. Mr. Thayer has been in discussion with the utilities concerning project funding and sources other than state match. Board members discussed if the projects are dependent on each other. Mr. Thayer stated that these two projects are independent of each other. So, when phase one is complete, that line can be energized. There was discussion how the lines from Homer to Nikiski may need to be upgraded, depending on how much more power is generated out of the area due to these projects. Board members further discussed with Mr. Thayer the breakdown of the budget and how staff positions are paid for by various programs. Some positions are funded on the capital side while others come out of the operating budget. These breakdowns are in the board packet. Chair Pruhs asked for a breakdown of staff positions and whether they are paid for on the operating side or the capital side to be included in the board packet. It will help board members better understand the funding stream. Mr. Thayer wrapped up his presentation by going over other proposed project work and budget items with board members. Which items had state match for funding and which budget items did not need to wait of state matching funds to proceed. Chair Pruhs asked that a table or chart be included in future documents showing how many dollars are going through the books on an annual basis and what blocks they are coming from. This would help tell the story and show what an impact AEA has to both communities and to the state. In addition, by showing this graph, it may show that AEA is running a lot of projects. So, when you ask for that extra engineer or accountant to help out, it’s easy to justify hiring additional staff. Also helpful would be a chart comparing where AEA was five years ago, where we are today and where we will be five years from now. That’s a quick way to get the governor’s office, the legislature and the public up to speed on what AEA is doing now and in the future. There being no further questions or discussion, Chair Pruhs asked for a motion to approve Resolution 2024-01. MOTION: Commissioner Sande moved that the Alaska Energy Authority (AEA) Board approve Resolution 2024-01 ratifying the governor’s submission of AEA’s Fiscal Year 2025 Alaska Energy Authority Page 4 of 12 (FY25) operating and capital budget subject to approval and appropriation by the Legislature. Bill Kendig seconded the motion. A roll call vote was taken, and the motion passed unanimously, with board member Albert Fogle absent. 8. DIRECTOR’S COMMENTS A. Annual Report Mr. Thayer stated that the annual report was done completely in-house and met the March 1 deadline. Copies of AEA’s 2023 Annual Report have been mailed to the state legislature and emailed to board members. The report is posted on our website as well. A few highlights of the report shows everything that we have going on from our current programs, including the Grid Resilience and Innovation Partnership (GRIP), a photo of the subsea cable, and also a photo of the AEA team, which we haven’t done in a couple of years. When we’re talking about all of the administrative and project work that AEA does, it’s being done by this group of people. B. Power Cost Equalization (PCE): PCE Annual Report Mr. Thayer stated that previously, the PCE Annual Report was published in June of each year. However, for the past four years, it’s been prepared and submitted to the state legislature by March 1 along with AEA’s annual report, as it makes more sense for state legislators to have this information in front of them during the legislative session when they are discussing the PCE program. The nice thing about this report is that it provides statistical data by utility and by community. You can pick any community on PCE to look at data for energy consumed, sold, kilowatts, line efficiency, basically everything across the board. This report is also posted to AEA’s web site. PCE Endowment Update Mr. Thayer stated that last year on July 1, 2023, the state legislature moved the management of the PCE endowment from the Department of Revenue (DOR) to the Permanent Fund Corporation (PFC). Because PFC manages the endowment, AEA has no say in the matter. There is a graph in the board’s packet that shows where the endowment stands. In July, 2023, $950 million was transferred from DOR to PFC. As of January, 2024, our last report, the fund stands at $944 million, which is a loss of approximately $6 million. PFC does provide us with a monthly report of how the fund is performing. We track that information because the first $45 million is to fund the PCE program. The next $30 million covers power cost, equal Alaska Energy Authority Page 5 of 12 community revenue assistance in rural Alaska. And then there's community revenue assistant to fund renewable energy, powerhouses or bulk fuel. However, the ability to fund bulk fuel, powerhouses, and renewable energy has only happened a couple of times over the past years. Senator Hoffman envisioned fully funding the PCE at $45 million plus the community revenue assistance. To accomplish that, you need about $75 million in earnings. It’s also important to note that two years ago, the legislature changed the program. Originally, PCE paid up to 500 kW per household in rural Alaska. They increased that to 750 kW per household. So, in essence, the legislature increased the program size by 50%. What was previously a $30 million program is now a $45 million program, and no additional funds were added to the endowment to make up for that difference. Basically, with that change in formula, there was an additional $15 million in funds distributed in the last two years out of PCE. Mr. Thayer offered to invite Permanent Fund Corporation staff to a future board meeting for a presentation on the endowment. Board members discussed with Mr. Thayer how the funds are disbursed by AEA and then reimbursed by endowment funds through draws. This is done on a monthly basis. There is also a program for community buildings. Chair Pruhs stated that we’re hearing about a workforce shortage post-COVID. Are communities able to provide information and documents in a timely manner to the PCE program. Mr. Thayer responded that communities are current with their documentation. While there has been challenges in some communities with staff changeover or shortages, one tool that has helped tremendously with communities staying in compliance is our online portal. If communities don’t submit all of their information, or it’s incorrect, AEA staff can assist them to complete it. We are fully staffed and can assist communities both with their documentation and with training on the program. C. Dixon Diversion Update Mr. Bryan Carey provided a brief update on both the Dixon Diversion project and the SSQ line project. In December we revised the scope of work by removing the road going up to Dixon Glacier, which dropped project costs by about $75 million. Based on discharge data from last year, we increase the size of the tunnel from 12 feet to 14 feet. With the changes to the scope of work and the scheduling, the project costs went from $415 million to $342 million. This includes the 25% contingency cost, unlisted items and allowing for escalation during construction. Chair Pruhs asked about allowing for inflation, as there’s no way to predict that. Mr. Carey responded that since this is a eight to ten year project, as we get closer to project construction, we’ll revise that number. He continued that this year we’re performing environmental studies and moving two drill rigs up there to drill holes to get a better understanding of the base rock for tunneling. The cost for tunneling will be a substantial portion of the project. The funds for this summer’s work is from a $5 million state grant. Alaska Energy Authority Page 6 of 12 Our target schedule is to have construction begin in 2028 and be completed in 2030. The amount of displacement of energy is approximately 190,000 megawatt hours. It would be close to 50% of what Bradley Lake Project, the third largest renewable energy project in the state, is producing. The displacement of natural gas is approximately 1.5 billion cubic feet of gas. Based on current estimates for natural gas in the Cook Inlet, that would be about 7.5% of the unmet natural gas needs in 2030. Chair Pruhs asked if there are plans to install a third generator at Lake Bradley. Mr. Carey responded not at this time. First we need to upgrade the transmission lines before we put in a third generator. We're constrained by the transmission. We’re increasing the water, so we have a bigger gas tank to go through the existing generators. Once the transmission upgrades occur, we could potentially put in a third generator for better peaking and economic power. But right now, we don’t need a bigger gas tank because we don't have the third generator. Board members discussed if it’s more important to have the Dixon Diversion first before the power transmission line upgrade. Mr. Carey responded that it doesn’t matter. It’s more whichever project can move forward the quickest. We have a bit of a head start with the Dixon Diversion project because we’ve started the engineering and environmental work. The transmission upgrades project has more design work to do and a lot of environmental studies to perform. Board members discussed the need to also upgrade the lines between Bradely Lake and Nikiski. While it is a priority project, it’s not considered a top priority under the current funding structure. Homer does currently have two lines. And we also need to upgrade the SSQ line because that’s an AEA owned line that had fire damage on it. So, it’s the weakest link right now with line loss on it. Chugach Electric is upgrading form Quartz Creek into Anchorage. Since they’re already doing that, this is a critical section. Chair Pruhs commented that once we got the Dixon Diversion project going, we have great storage capacity, we maybe add another generator at Bradley Lake, the constraint is now going to change to downstream. What do we have to do to get this to match up with the $400 million project for ratepayers to have a benefit. Where would the funding come from to match this up. Mr. Thayer responded that most like a revenue bond by power sales agreement with utilities. There may be an initial cost, but we also haven’t factored in how the GRIP funding plays a role in this by funding projects. This will potentially lower the cost to rate payers as well. There was further discussion about the economics of project funding. Chair Pruhs requested that board members who are interested go in the field to take a look at Bradley Lake Project and the Dixon Diversion Project. It doesn’t need to be a special trip, just accompany workers scheduled to go down to the project site. Mr. Thayer responded that can be arranged. D. SSQ Line Update Alaska Energy Authority Page 7 of 12 Brian Carey stated that for the SSQ Line, the Quartz to Sterling portion is owned by AEA, while Homer Electric Association (HEA) owns the Sterling to Soldotna portion. Both sections require work. We broke the required work into four projects. Projects one and four are in non-national refuge areas and we can move quickly through them, permitting wise. We are procuring long lead electrical items, it will go out to bid this summer, so that next winter the work will occur on that section of line. For projects two and three, once we finish the environmental assessment (EA) we can then move forward with construction. Board members discussed how this was the line that failed between Whittier and Girdwood during a recent winter storm. Power stopped moving north from Bradley Lake. This line was also burned in the 2019 fire. It has been in place since 1969. It’s going to be upgraded to 230 specifications. Since poles need to be replaced, might as well replace them with taller poles, space them a little bit wider apart with larger conductors and fiber optic. It’s going to be more resilient and fire hardened. It will be able to hold a higher load and have less resistance or less line losses. Mr. Carey stated that for the schedule, project work will be broken into many years because the utilities don’t want Bradley Lake unavailable for more than 60 days a year for fear of spilling water and having Bradley Lake online in case any issues occur with power plants up here. They are considering changing it to 100 days a year, which is a little bit riskier, but you would cut down on your construction costs. And by changing the schedule you can entice larger bidders to go for it. Commissioner Sande commented that this may be more of a question for Director Thayer. But as the state moves forward with broadband initiatives and projects of more than $1 billion, has AEA been in conversations with the broadband teams to coordinate efforts to avoid duplication of work. Especially if you’re talking fiber optics on this project. Mr. Thayer responded that so far we have not discussed our project work with the broadband team because we are putting in fiber optics for our own purposes and control. However, we will have additional capacity on there and we can work with other entities to use that extra capacity. That’s a good suggestion and he will follow up on it. Commissioner Sande appreciates his efforts to look for opportunities to create efficiencies and reduce costs for Alaskans. Mr. Carey concluded his presentation by stated that between those two projects, there's close to $450,000,000 worth of work that we're doing that's not running. Chair Pruhs commented that timing is everything and with the Cook Inlet issue on gas looming over us, it would be very advantageous to figure out a way to accelerate some of these things which I think we take a lot of pressure off a lot of folks in south central Alaska. E. Electric Vehicle Update Ms. Audrey Alstrom stated that under the Department of Transportation’s National Electric Vehicle Infrastructure (NEVI) fund Alaska will be receiving about just over $50 million through 2028. We're in year three. Spring of 2022, we issued a request for applications for potential site Alaska Energy Authority Page 8 of 12 hosts along Alaska's sole alternative fuel corridor, which is between Anchorage and Fairbanks. We received a number of applications, and we selected nine sites along the corridor to receive NEVI funds for a total investment of just over $8 million. Since then, we've been working with those site hosts on preparing for their project agreements. They have to do an environmental or NEPA review, which Alaska Department of Transportation and Public Facilities (ADOT&PF) has taken the lead on that. Once the environmental review is completed, hosts can sign their project agreements and begin construction this summer. Some are pretty optimistic that they will be completed by the end of the fall. As an additional note, states that receive federal funding are required to have charging stations every 50 miles along the corridor to deal with potential range anxiety. However, in our corridor, some places just don’t have any infrastructure to support a charging station. So we were able to obtain a few exceptions from DOE. For example, in one area it is 73 miles instead of 50 miles between charging stations. We continue to hold our monthly electric vehicle (EV) working group meetings. We put out an EV newsletter to the team. We’re beginning to plan for our next NEVI plan update, which is due August 1. And, as a reminder, AEA got involved with EVs because of the Volkswagon Mitigation Trust Fund. We had set aside $1 million of the $8 million fund to set up EV charging stations between Anchorage and Healy down to Homer and Seward. All nine sites are commissioned and operated by private hosts. So, we are starting to close out those projects and focus on NEVI funded projects. We received a grant of about $1.6 million called Alaska Rural Electric Vehicle Development to work on level two charging stations throughout the state and in rural hub communities. Currently we are working with our project partners on grant agreements and hope to have those signed by the end of March. Chair Pruhs asked how long does it take to charge and electric vehicle. Ms. Alstrom responded about 20-40 minutes. Board members discussed about EV drivers encountering lines or waiting to charge vehicles. Ms. Alstrom stated that there is an app that drivers can download to their phone that shows where charging stations are located and if they’re online. AEA is partnering with the Alaska Department of Motor Vehicles (DMV) to gather general information on electric vehicles. Since Alaska has just over 2,000 EVs within the state, it’s not likely there will be wait lines for charging stations. But who knows what it will be like in ten years. The Alaska Marine Highway system will come online with charging stations during Phase 2, which is for projects off the corridor. Phase 1, alternate fuel corridor, has to be fully built out. We’re awaiting guidance from Federal Highway Administration to tell us what fully built out means to them. Then we could move on to Phase 2 projects. Mr. Eledge asked if program managers have data on what happens during the winter months. Is there a signature per vehicle that’s provided at each charging station and is it being tracked from station to station. Ms. Alstrom responded that both the Volkswagon trust fund projects and NEVI funded projects require site hosts to send us operational data such as how many vehicles are charging, how long they’re charging and when the sites are working. We review the Alaska Energy Authority Page 9 of 12 information and share it with the joint office for folks who are interested in this type of information on a national level. For tracking each vehicle, we will review the data as they use each station, but we won’t share data on each vehicle that can be traced back to the owner. Board members discussed the capability of EVs to travel during cold weather in winter. Does the cold, subzero weather reduce their radius of travel. The data collection may tell us some of this. But there are also privately owned and funded sites that aren’t required to share this data. It was suggested that providing an incentive for drivers to install a GPS device on their car to help track their movements throughout the year in different weather conditions may help with data collection and analysis. F. Infrastructure Investments and Jobs Act (IIJA) Updates IIJA Tracker Mr. Thayer referred board members to the IIJA tracker in their packet. The tracker is broken down by what has been awarded. AEA has been awarded approximately $74 million in federal funding and there has been some state matching funds. So if we look at grid resilience, for example, between the federal funds and a full match, that number would grow to $356 million in federal receipt authority and $217 million for state funds. However, that is assuming the $206.5 funding comes in one year. We have pending applications listed on the tracker, so they stay on our radar. This spreadsheet is updated regularly to keep it current and is shared with the state legislature, the utilities and board members. By updating the tracker, we may come across funding sources that we don’t qualify for or that we’re not applying for, so we share that information with others. For example, if there’s a funding opportunity for utilities, we forward this on to all the utilities in the state for them to review, as they may want to pursue it. AEA Training for Residential Energy Contractor Training (TREC) Program Grant Application Mr. Thayer stated that this is an application for a $1.2 million grant. The application is about 100 pages long and the funding is formula driven. There is no state match requirement. This application is included in the board packet to keep you informed. GRIP 3 - Grant Agreement Update Mr. Thayer stated that the scope of work along with terms and conditions of the agreement are included in the packet for board members to review and to stay informed as we move through these steps. Legal counsel is also reviewing the agreement and has raised some questions, and we have some questions as well. We’re working with Department of Energy to resolve these questions. Once the agreement has reached a semi-final state, we will ask the board to review and approve the agreement. Alaska Energy Authority Page 10 of 12 Clean Energy Innovator Fellowship 2024 - White Paper Mr. Thayer stated that AEA has submitted a white paper for a clean energy innovator fellowship. The Department of Energy (DOE) will identify people that are in their studies, whether they're in their graduate degree or doctorate program, and give them a stipend to work with state energy offices. We would provide a desk and a mentor, and the federal government, or DOE, would pay their stipend. This fellowship could be up to a year or 18 months. It’s a way to get additional staff at no cost to us. However, it's an application process, and you're going to have to find somebody who wants to move to Alaska for 12 to 18 months to specifically work on our projects. We didn't want to miss an opportunity of being able to land a couple of fellows to come in and study what we're doing and to work with us. G. Legislative Update Mr. Thayer referred board members to their packet for the Legislative update of various energy related bill. Last week AEA had four bill analysis or fiscal notes due. The Governor’s bill, SB 217, received its first hearing. Commissioner Sande asked Curtis to briefly explain for the record and the general public what a bill analysis or fiscal note analysis means so there an understanding of how much time an agency may spend on one analysis during the legislative session. Mr. Thayer explained that when a bill is introduced in the legislature for the first time and it affects a particular agency, say, AEA, for example, then we work with the governor's legislative office to do what we call a bill analysis, which walks through the bill and explains what it does. The analysis also includes any issues, concerns or support that we might have for that bill and if our recommended position is supportive, neutral, or against, or we would like to see the bill amended. It all depends on how in depth the analysis is. We had one where it might take a couple of hours. We had one that was introduced on a Friday and we actually worked on the analysis over the weekend. We probably spent no less than 40 man hours in that particular bill analysis. That actually was SB 257. It was a bill by Senate Resources, that not only restructures a little bit of the regulatory commission of Alaska, but it also sets up AEA as the ownership of transmission lines and how that would be done. In addition to any bill analysis, there's a fiscal note attached to it--what do we expect the cost of the agency to be? And costs could be a zero or indeterminate. For example, as part of SB 257, they would like us to do a whole integrated resource planning for the rail belt as a whole. We had done that in 2007. So we looked at the costs in 2007, looked at the consumer price index (CPI) and figured that alone is almost a $7 million project to do a report like that, and with a schedule of two years. So, the fiscal note is a definition of costs associated with a bill. The fiscal note is usually sent over by the administration to match up with the bill so the costs from an agency perspective, are known. To continue using SB 257 as an example, that bill also Alaska Energy Authority Page 11 of 12 required us to do a lot of regulatory changes, which has a cost, and if you need to add any additional personnel, whether short term or long term, also has a cost. And then we need to identify how we are going to pay for that bill. Commissioner Sande asked what is a typical turnaround time for a bill analysis. Mr. Tayer responded that sometimes it's as short as 24 hours. For SB 257, it was introduced on Friday and the bill analysis was due Monday at 09:00 a.m. So it was a weekend project to submit it. Commissioner Sande wanted to call this to the board’s and the public’s attention and to thank the team. She stated that she knows it's part of what we do and certainly what the teams and state agencies perhaps may be used to doing. But not having been a part of it before, she had no idea of both the expectations and how at times there's not much notice to get this work done. So the entire team might have to completely pivot off of their daily work and be able to respond quickly and with a lot of thought. She appreciates that effort. Mr. Thayer stated that he and Tim will be in Juneau next week to meet with 17 freshmen legislators for lunch. The main topic will be energy. There are meetings with other legislators that they missed during their last trip. In addition, both House and Senate Resource Committees would like an overview of AEA. So, we’re putting together a PowerPoint presentation, and we’ll share it with the governor’s office before we submit it. The board will have a copy as well. H. Community Outreach Mr. Thayer referred board members to their packets for information about their community outreach. The pace has been picking up and we’re spreading that across the team as more people are available to do it. I. Articles of Interest Articles of interest are included in the board’s packet for them to review. Mr. Thayer noted that during his State of the State speech, Governor Dunleavy recognized AEA for our recent work. And then both Senator Murkowski and Senator Sullivan acknowledged AEA for the hard work we’ve been doing, and the projects we’ve been working on as well. The recognition for the team was very good and appreciated. J. Next Regularly Scheduled AEA Board Meeting - Wednesday, April 17, 2024 Commissioner Sande mentioned that there may be a conflict for the May meeting with the Governor’s Energy Summit. And she would encourage board members to attend the summit because the conversations and information is really valuable. Mr. Thayer responded that they did adjust the AEA board meeting in May, so it doesn’t conflict with the summit. Alaska Energy Authority Page 12 of 12 9. BOARD COMMENTS Mr. Eledge stated that, in his opinion, Curtis and his staff have gained respect in the community by their demonstrated abilities and expertise. It's also reflective on the board as well as a positive note. He just wanted to share his sentiments about what a good job AEA is doing. Thank you. Mr. Kendig had no comments. Mr. Smyth had no comments. Commissioner Sande had no comments. Mr. Vivlamore had no comments. Chair Pruhs thanked Curtis, Jennifer and staff for putting today’s meeting it together. It was a good meeting with a lot of good information. 10. ADJOURNMENT There being no further business of the Board, the AEA meeting adjourned at 10:26 a.m. ____________________________________________ Curtis W. Thayer, Secretary AEA Resolution No. 2024-04 Page 1 of 2 ALASKA ENERGY AUTHORITY RESOLUTION NO. 2024-04 RESOLUTION OF THE ALASKA ENERGY AUTHORITY APPROVING THE SUBMITTAL OF THE RAILBELT INNOVATIVE RESILIENCY PROJECT, GRIP 3, ROUND 2 WHEREAS, Resolution No. 2021-3 authorized the Executive Director of the Alaska Energy Authority to work collaboratively with the Railbelt Utilities to prepare a strategic plan including “transmission upgrades addressing capacity, reliability and redundancy” and to “pursue opportunities that will benefit ratepayers”; and WHEREAS, Alaska Energy Authority, in partnership with the Railbelt Utilities submitted a concept paper to the Department of Energy Funding Opportunity Announcement (DE-FOA- 003195) DOE Grid Resilience and Innovated Partnerships(GRIP), Topic 3, Round 2; and WHEREAS, upon review of the submitted concept paper, the Department of Energy notified the Alaska Energy Authority, as the applicant of the concept paper, the concept paper was selected to submit a full grant application; and WHEREAS, the Railbelt Utilities (Chugach Electric Association, Golden Valley Electric Association, Matanuska Electric Association, Homer Electric Association and Seward Electric System) approved authorizing funds for the costs associated with preparing, finalizing, and submitting GRIP 3, Round 2, grant application; and WHEREAS, the grant application proposes Phase 2 of the Railbelt Innovative Resiliency Project (RIR). Phase 2 will construct 250 miles of HVDC transmission line from Beluga in the Central Region near Anchorage to Healy in the Northern Region; and WHEREAS, submitting this application is solely an application for consideration by the Department of Energy and does not commit the Authority to acceptance of any award to expenditure of any funds for the project. WHEREAS, the Alaska Energy Authority has communicated to the Railbelt Utilities that submission of this application does not commit the Alaska Energy Authority or the State of Alaska to providing matching funds for Grant if received; and AEA Resolution No. 2024-04 Page 2 of 2 WHERAS, the Railbelt Utilities endorse the application and commit to exploring funding opportunities for the grant matching funds, if awarded. NOW, THEREFORE, BE IT RESOLVED, BY THE ALASKA ENERGY AUTHORITY AS FOLLOWS: Section 1. The Board authorizes Alaska Energy Authority, as applicant, in collaboration with the Railbelt Utilities, to submit the Railbelt Innovative Resiliency Project (RIR), GRIP 3, Round 2 application. Section 2. The Executive Director is authorized to execute and submit the Department of Energy Funding Opportunity Announcement (DE-FOA-003195) DOE Grid Resilience and Innovated Partnerships (GRIP), Topic 3, Round 2 grant application on behalf of the Authority to the Department of Energy. Section 3. This Resolution takes effect immediately. DATED at Anchorage, Alaska, this 17th day of April 2024. ALASKA ENERGY AUTHORITY _______________________________________ Chair _______________________________________ Secretary The Railbelt Central- Northern Region HVDC Interconnect Control Number:3195-1942 •Project Goal:Strengthen and modernize Alaska's Railbelt Grid to enhance resilience, reliability, and clean energy integration, serving over 75% of the state’s population five critical national defense installations, the third largest air cargo airport in the world, and one of the nation’s US TRANSCOM designated strategic seaports, . •Project Team: Alaska Energy Authority in association with Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, Seward Electric System, and the Regulatory Commission of Alaska. •Key Components:Construction of an HVDC line between The Central and Northern regions of the Railbelt. Wide area integration of the HVDC lines and regional BESS to improve grid stability, transfer capacity, and economic dispatch across Alaska's diverse territories. •Community Impact:Creation of high-quality jobs, reduction in energy costs, and improved energy access for disadvantaged and tribal communities. •Environmental Strategy:Compliance with NEPA to protect natural and cultural resources, ensuring sustainable project development. •Climate Strategy: Reduce dependence on carbon based thermal generation, enhance integration of clean energy •Innovation Highlight:First-of-its-kind wide are integration of HVDC and large-scale BESS technologies to optimize grid performance and energy distribution, paving the way for future renewable energy projects. •DOE Impact:Leveraging DOE funding to enhance infrastructure and enable significant state and private investments, promoting a cost-effective and fuel-diverse energy landscape. •Requested Funding: AEA is seeking $365 million for the $730 million project benefitting 75% of the Alaskan Population including 22 DACs and ANVSAs. Project Graphics Project Location Project Map Alaska in Comparison 3195-1942_AEA_Full Applica�on DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Summary/Abstract Railbelt Central-Northern Region HVDC Interconnect The Alaska Energy Authority (AEA) and the Railbelt u�li�es—including four member-owned coopera�ves and a municipal u�lity—in partnership with the private sector and the federal government under the Bipar�san Infrastructure Law’s Grid Resilience and the Department of Energy’s Innova�ve Partnerships (GRIP) program, aim to transform Alaska’s Railbelt Grid. This ini�a�ve aims to bolster grid resiliency and support a transi�on to a low-carbon economy through innova�ve electrical infrastructure projects. The Railbelt Grid, which serves over 75% of Alaska’s popula�on, hosts five cri�cal na�onal defense installa�ons, the third largest air cargo airport in the world, and one of the na�on’s US TRANSCOM designated strategic seaports, is crucial for the state’s social, economic, and environmental well-being and is cri�cal to na�onal defense. Current limita�ons in grid resiliency hinder Alaska's resilient clean energy future, mo�va�ng this significant upgrade. The AEA is seeking $365 million toward the $730 million project. Project Components: This project involves construc�ng new High Voltage Direct Current (HVDC) transmission lines and integra�ng planned large-capacity Batery Energy Storage Systems (BESS) across mul�ple regions. This setup aims to enhance the interregional transfer capacity, op�mize economic dispatch, and stabilize the grid through advanced control systems. This “first of its kind” project leverages unique collabora�ve efforts among local u�li�es and is poised to set a precedent in grid moderniza�on. Community and Environmental Impact: The project promises substan�al benefits, including increased employment, enhanced community resiliency, and reduced energy costs, par�cularly benefi�ng indigenous people and disadvantaged communi�es. The strategic inclusion of local workforce training programs aims to ensure long-term economic and social benefits. Environmental considera�ons are thoroughly integrated, adhering to NEPA guidelines to mi�gate impacts on natural and cultural resources. Innova�on and Future Outlook: By addressing cri�cal gaps in the exis�ng infrastructure and introducing cu�ng-edge technology, the project sets the stage for a scalable clean energy future. It supports state and na�onal goals for a resilient and sustainable energy framework, significantly reducing dependency on fossil fuels and promo�ng economic growth through enhanced grid capabili�es. Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 1 STATEMENT OF OBJECTIVES (SOPO) Railbelt Central Northern Region HVDC Interconnect A. OBJECTIVE The Railbelt Innovation Resiliency Program (RIR) aims to enhance resiliency and transfer capability among the three regions of the Railbelt. The Railbelt has experienced decreasing frequency regulation, slowed disturbance response, and increased magnitude natural frequency oscillations. The current configuration of the Railbelt system restricts the adoption of clean energy, diversification of the fuel supply, and Alaska’s preparation for a sustainable carbon-free future. A key priority to achieve this objective is to reinforce interconnections between the primary regions of the Railbelt by adding parallel lines and implementing Battery Energy Storage Systems (BESS) to resolve long-standing frequency control and instability issues. Alongside the High Voltage Direct Current (HVDC) submarine cable between Kenai and Beluga (funded in cycle 1) this includes an HVDC line paralleling the existing AKNG pipeline ROW between Beluga and Healy, these additions will alleviate transmission congestion and maximize interregional transfer capability. The project's innovative solutions hold the promise of curbing escalating energy prices, which currently rank among the highest in the nation, while providing rural residents and disadvantaged communities with an opportunity to enhance community viability. Sharing these solutions with other communities will support collective efforts toward achieving clean, reliable, and affordable energy for all. B. SCOPE OF WORK The RIR encompasses three primary components designed to achieve its objectives. The Current RIR Project involves interconnecting the AC Transmission systems of the Central and Northern regions through a DC Bipolar High Voltage Direct Current (HVDC) system. The HVDC system is comprised of a Bipolar HVDC overhead line between Beluga and Healy, connecting the Central region’s existing 230kV AC System to the Northern regions 230kV system. The coordinated interregional control and operation of this line and the other BESS and HVDC assets in the Railbelt will resiliently integrate the three Railbelt regions, enhancing stability and increasing Railbelt-wide resiliency and increasing transfer capacity 2-3 times current capability. The first project, which included the HVDC link from Beluga to Kenai and the regional BESS, received funding from the DOE in its first GRIP funding cycle, totaling a maximum grant of $206.5 million. The objective for Topic 3 in funding cycle 2 is to complement the first project by constructing an HVDC overhead line from Beluga to Healy. This project will finalize the parallel interconnection of all three Railbelt Grid regions. As noted, the new parallel interconnection between Central and Northern regions will not only improve resiliency and reliability but will increase energy transfer capability between the Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 2 regions by 2-3 times. Providing a parallel path assures that all energy will continue to flow if the alternative path is lost. Major load swings between regions are also avoided by increasing system stability and allowing the lines to carry additional capacity, reducing congestion. C. TASKS TO BE PERFORMED Task 1.0: Project Management and Planning (PMP): Subtask 1.1 – Project Management Plan (PMP): Within 30 days of award, the Recipient shall provide the Project Management Plan (PMP) to the designated Federal Project Officer (FPO). The Recipient shall not proceed beyond Task 1.0 until the PMP has been accepted by the FPO. The PMP shall be revised and resubmitted as often as necessary, during the project, to capture any major/significant changes to the planned approach, budget, key personnel, major resources, etc. The Recipient shall manage and direct the project in accordance with the accepted PMP to meet all technical, schedule and budget objectives and requirements. The Recipient will coordinate activities to effectively accomplish the work. The Recipient will ensure that project plans, results, and decisions are appropriately documented, and that project reporting and briefing requirements are satisfied. Subtask 1.2 Community Benefits Plan Within 30 days of award, the Recipient shall revise the Community Benefits Plan (CBP) and submit to the designated Federal Project Officer (FPO). The Recipient shall not proceed beyond Task 1.0 until the CBP has been accepted by the FPO. The CBP shall be revised and resubmitted as often as necessary, during the project execution, to capture any major/significant changes to the CBP with regard to the four priority goals; Community and Labor Engagement; Investing in the American Workforce; Diversity, Equity, Inclusion, and Accessibility; and Justice 40 Initiative. The Recipient will coordinate activities to effectively implement the CBP goals. The Recipient will ensure that metrics, SMART community benefits plan commitments, and outcomes are appropriately documented, and that reporting and briefing requirements to stakeholders are satisfied.” Subtask 1.3: National Environmental Policy Act (NEPA) Compliance Sub Task 1.3.1: Permitting – Undertake EIS and apply for permits from appropriate agencies. Subtask 1.3.1.1 – Notice of Intent to Prepare EIS Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 3 Subtask 1.3.1.2 – Scoping process –DOE names lead agency; Federal agency begins the scoping process by publishing a Notice of Intent (NOI). The NOI describes the project and provides background on potential impacts. The public provides comments on the proposed project, proposed alternatives, and environmental impacts. Applicant holds public meetings to obtain comments. Meetings beyond the scope of those traditionally required in the EIS process may be required by the project’s CBP. Subtask 1.3.1.4 – Notice of Availability of Draft EIS – the Draft EIS presents, analyzes, and compares potential environmental impacts and proposed actions for mitigation. Subtask 1.3.1.5 – Notice of Availability of Final EIS – EIS prepared and distributed including comments from Draft EIS. Subtask 1.3.3 – Record of Decision – Notice of decision and rationale for decision giving factors such as cost, technical feasibility, agency and national objectives, and environmental impacts of any actions. The Applicant will undertake an Environmental Impact Study (EIS) with a lead agency (DOE) to identify and analyze possible adverse environmental impacts and investigate reasonable alternatives as appropriate. As required, the Recipient shall provide the documentation necessary for NEPA compliance. Subtask 1.4: Cybersecurity Plan (CSP) The Applicant will focus its efforts on protecting the Federal systems and its networks from cyber threats. The plan will incorporate processes to identify, investigate and mitigate threats from targeted phishing, denial of service attacks, and the introduction of malware into the system. A coordinated effort with the State, the utilities, and DOE will be undertaken to implement the tools necessary to provide continuous diagnostics and mitigation. The plan will be compliant with AKCIP standards. A full cybersecurity plan will be submitted during award negotiations and prior to receiving project funding. The CSP shall be revised and resubmitted as often as necessary, during the course of the project, to capture any major/significant changes. Subtask 1.5: Continuation Briefing(s): A continuation briefing will be done on an annual basis to explain the plans, progress, and results of the technical effort. Task 2.0: Design, Permitting and Siting – Design criteria for transmission lines, substations, cables, and converter stations. Subtask 2.1 – Risk Evaluation – Evaluate transmission components. Subtask 2.1.1 – Evaluate new transmission corridor for known events such as CBP input, avalanche, seismic, wildfire, heavy snow and ice loading. Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 4 Subtask 2.1.2 – Evaluate potential ROW or cable routing particularly around Denali State and National parks. This effort is broken into five phases based on primary land ownership or responsible agencies. Subtask 2.1.3– Evaluate potential uses of the parallel AKLNG Pipeline Right of Way as a buffer for natural conditions and obstacles (such as uphill tree impingement, river ice or drift snow accumulation) No impact or impingement on the AKLNG ROW is intended or implied in this analysis without prior approval of the Alaska Gasline Development Corporation Subtask 2.2 – Design Criteria – Develop tailored and innovative design criteria to mitigate input and risks identified in 2.1. Evaluate alternative routing alignment as necessary. Subtask 2.3 – Preliminary Design – Engineer for lines, converter stations, potential cable sections, foundations, anchors, guys, structure type, span length, conductor size, design, and sag. Evaluate potential right-of-way alignment, land ownership and permit requirements. Task 3.0: Public Notice – Consistent with the CBP provide public notice of intent to construct, provide data, seek input, and provide feedback. Adjust design and routing as necessary to secure permits. Task 4.0: Final Design & Engineering – Prepare final design documents for permitting and construction. Task 6.0: Procurement – Secure long-term materials such as insulators strings, inverters, converters, transformers, steel structures, and specialized equipment. Task 7.0: Construction – Undertake construction process Subtask 7.1 – Solicitation – prepare construction documents and evaluate most cost- effective method to seek bids. Subtask 7.2 – Award – Award contracts for construction Subtask 7.3 – Construction Management – Initiate project management office Subtask 7.4 – Construction Close Out Process Task 8.0: Testing & Commissioning – Undertake final inspection, energization, and system coordination testing with regional BESS and Southern-Central HVDC system, cutovers as necessary. D. DELIVERABLES I. Management Reporting a. Progress Report b. Project Management Plan (PMP)and updates c. NEEPA Compliance Environmental Impact Statement (ROD) Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 5 d. Community Benefit Plan and updates e. Cybersecurity Plan and updates f. Continuation Briefings g. Final study results and system benchmarking on the impact of inverter-based resources on grid voltage stability and short circuit current ratio at variable generation penetration present at commissioning. II. Financial Reporting III. Closeout Reporting E. BREIFINGS/TECHNICAL PRESENTATIONS Briefings and technical presentations will be prepared as requested by the Federal project Officer which will include at a minimum those listed below. Kickoff Briefing - Not more than 60 days after submission of the Project Management Plan, the Recipient shall prepare and present a project summary briefing as part of a Project Kickoff Meeting. Pre-Continuation Briefing - Not less than 90 days prior to the completion of approximately twelve (12) calendar months (no more than eighteen (18) months) of project execution, the Recipient shall brief the DOE on the performance relative to project success criteria, milestones, Go/No-Go Decision point metrics that are documented in the Project Management Plan (PMP), and their plans for the subsequent periods of work. The Go/No-Go Final Project Briefing - Not less than 30 days prior to the end of the project, the Recipient shall prepare and present a Final Project Briefing on the results and accomplishments of the entire project. Other Briefings – The Recipient shall prepare, and present technical, financial, and/or administrative briefings as requested by the DOE. A project technical review briefing will be conducted no less than annually. Additionally, the DOE may require Recipients to make technical presentations at national and/or industry conferences.” 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 1 April 17, 2024 Cover Page Topic Area 3: Grid Innovatfon Title: Railbelt Central-Northern Region HVDC Interconnect Applicant: The Alaska Energy Authority representfng the State of Alaska Business Point of Contact: Curtfs Thayer, Executfve Director, Alaska Energy Authority Technical Point of Contact: Jim Mendenhall, Program Manager, Alaska Energy Authority The Alaska Energy Authority and Railbelt utflitfes are partners on this project, representfng all the primary transmission owners and operators of Alaska’s largest electrical grid (the Railbelt) as collaboratfve decision-makers. The project partners include: 1. The Alaska Energy Authority (AEA), Executive Director: Curtis Thayer 2. Chugach Electric Association, Inc., (CEA), Central Region Cooperative; CEO: Arthur Miller 3. Golden Valley Electric Association, Inc., (GVEA), Northern Region Cooperative; John Burns: CEO 4. Homer Electric Association, Inc., (HEA), Southern Region Cooperative; CEO: Brad Janorschke 5. Matanuska Electric Association, Inc., (MEA), Central Region Cooperative: CEO: Tony Izzo 6. The City of Seward, Alaska, dba Seward Electric System, Southern Region Municipal Utility (SES); Brian Hickey, General Manager 7. The Regulatory Commission of Alaska (RCA) is participating as a team member in an advisory and regulatory role, as permitted by statutory authority) Chairman: Bob Doyle Project Location: All three regions (Northern, Central, and Southern) of the Alaska Railbelt electrical grid. Figure 1 The Railbelt Region and Scale 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 2 April 17, 2024 Table of Contents Cover Page .................................................................................................................................. 1 Project Overview ......................................................................................................................... 3 Project Goal: ............................................................................................................................ 6 DOE Impact ............................................................................................................................. 7 Community Benefits Plan: Job Quality and Equity ..................................................................... 8 Constraints on Resources ........................................................................................................ 9 Climate Strategy ...................................................................................................................... 9 Climate Resilience Strategies for Electricity: ........................................................................... 9 Technical Descriptfon, Innovatfon, and Impact ........................................................................... 9 Relevance and Outcomes ........................................................................................................ 9 Feasibility .............................................................................................................................. 10 Innovatfon and Impacts ........................................................................................................ 14 F.6 Topic Area 3: Grid Innovatfon Program ....................................................................... 14 Workplan ................................................................................................................................... 15 Project Objectfves ................................................................................................................. 15 Technical Scope Summary ..................................................................................................... 16 Work Breakdown Structure (WBS) and Task Descriptfon Summary ..................................... 18 Go/No-Go Decision Points (See Sectfon VI.B.xv. for more informatfon on the Go/No-Go Review) .................................................................................................................................. 21 End of Project Goal ............................................................................................................... 21 Project Schedule (Gantt or similar) ....................................................................................... 22 Project Management ............................................................................................................ 22 Technical Qualificatfons and Resources (Approximately 20% of the Technical Volume) .. 24 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 3 April 17, 2024 Project Overview Through the Bipartfsan Infrastructure Law’s (BIL) Grid Resilience and Innovatfve Partnerships program (GRIP), the Alaskan Energy Authority (AEA) and its four small-utflity, member-owned cooperatfves are seeking funding for this once-in-a-generatfon opportunity to build resiliency and develop a fuel-diverse, low-carbon economy by investfng in essentfal electrical infrastructure. Alaska’s largest—but electrically islanded—grid serves over 75 percent of the state’s populatfon. Termed the Railbelt grid, it includes 17 Alaskan Natfve Village Statfstfcal Areas (ANVSAs) as well as 22 census tracts in Disadvantaged Communitfes (DACs), primary commerce and shipping centers, critfcal-operatfon military bases, and access areas for key mineral deposits. The Railbelt plays a vital role in shaping the social, economic, cultural, and environmental landscape of Alaska, serving as a gateway to the state’s vast and diverse territories. Its significance extends beyond regional boundaries, as it influences the trajectory of the state’s development and identfty. Deficiencies in this grid’s resiliency undermine the state’s ability to usher in a clean energy future. The collectfve mission of the State of Alaska and the interconnected Railbelt utflitfes is to build a resilient, clean, smart, and low-cost electrical grid. This grid must support a fuel-diverse energy landscape that drives reliable and sustainable economic development in Alaska and ensures a cost-effectfve delivery of energy to Railbelt consumers, including defense infrastructure and more. As part of the broader Grid Modernizatfon and Resiliency Plan (GMRP), the Railbelt Innovatfve Resiliency Program (RIR) will construct new high-voltage direct current (HVDC) transmission lines parallel to the existfng single regional tfes. The HVDC system will be comprised of Project 1 a submarine circuit and overhead HVDC interconnects between the Kenai Peninsula and Beluga, and Project 2 a HVDC overhead line between Beluga and the town of Healy. Project 1 also integrates three large-capacity (40-70 MW; 2-hour) Battery Energy Storage Systems (BESS), one in each region. The HVDC -BESS system Figure 2 The Grid Modernization and Resiliency Plan (GMRP) Current project Railbelt Innovative Resilience (RIR)project in yellow 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 4 April 17, 2024 will feature wide area integrated and coordinated inter-regional control and operatfon of the three regional BESS and two HVDC lines to maximize transfer capacity and optf mize economic dispatch. This system will be technologically innovatfve—the first of its kind based in part on the unique collaboratfon of these entftfes. The purpose of the GMRP is to create programs that will significantly increase resiliency and transfer capability of the inter-regional transmission system, thus facilitatfng diverse clean-energy optfons for the future of Alaska. The GMRP is broken into two programs whose purpose is to reconstruct the Railbelt’s existfng lines: the Railbelt Backbone Reconstructfon Program (RBR) and the Railbelt Innovatfve Resiliency Program (RIR), which constructs innovatfve parallel interconnects with Battery Energy Storage Systems (BESS) between regions. The RIR specifically and the broader GMRP allow small electric- utflity providers from Fairbanks to Homer and Valdez to partfcipate, with the goal of driving down consumer costs via economies of scale; to utflize modern technologies such as energy storage to stabilize grid resiliency; and to integrate renewable energy seamlessly into the Railbelt grid. The RIR is broken into three projects: The first (Project 1) was DOE-funded during funding cycle 1 (F- 1). The project referred to in this applicatfon constftutes Project 2. Project 1 includes the HVDC link from Kenai Peninsula to Beluga and the regional BESS. As noted, Project 1 received funding from the DOE in its first F-1 funding cycle, with a maximum grant of $206.5 million. Project 2 is the HVDC interconnect between the Central and Northern regions. Project 2 is estfmated to cost $730M, with our request for a DOE grant of $365M. Project 3 is a long-term vision of an interconnectfon from the Central region through Glenallen to Fort Greely. Background The Railbelt electric grid is unique in North America as it is technically a fully functfoning, long- distance electrical grid designed on a very small scale. It encompasses three load-generatfon regions with four load-balancing areas. These are the Northern region (Fairbanks-Delta Junctfon), the Central region (Anchorage-Matanuska-Sustfna-or Mat-Su-Valley), and Southern region (the Kenai Peninsula); they are tfed together with two long transmission lines operatfng variously at 115kV and 138KV. The grid provides electricity to approximately 75 percent of the state's residents and generates 80 percent of the electricity in Alaska. It extends over 700 miles from the Bradley Lake Project located at the head of Kachemak Bay near Homer in the Southern region, to Delta Junctfon in Interior Alaska—roughly the distance from Washington, DC, to Atlanta. The grid transverses inhospitable, subarctfc, mountain terrain, along with the Cook Inlet, with its tremendous tfdes and currents. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 5 April 17, 2024 Climate change is dramatfcally affectfng Alaska. The state is laced with highly actfve seismic zones and is subject to volcanic eruptfons, droughts, forest fires, flooding, landslides, tsunamis and fierce annual winter storms. The Railbelt grid's assets vary from high-voltage (138 kV and 230 kV) submarine cable crossings in Cook Inlet1 to remote helicopter/riverboat-access-only river crossings and numerous transmission structures located in subarctfc climates that are well above 2,000 feet in elevatfon with the tree-line oflen well below 2,000 feet and extraordinarily harsh conditfons. Unlike numerous areas in the contfguous 48 states, the Railbelt received minimal federal investment in grid development prior to the GRIP F-1 award. The Eklutna Hydroelectric Project, initfally constructed in the 1950s, was the last major federal project in the Railbelt that included a transmission-line component. This project was rebuilt by the Bureau of Reclamatfon's Alaska Power Administratfon following an earthquake in 1964 and sold by the federal government to Central region utflitfes in the early 1990s. 1 Cook Inlet is a silt laden 180-mile inlet reaching from Knik Arm to the Gulf of Alaska. The Inlet has the fourth highest tidal range in the world at 35 feet and contains an endangered subspecies of the beluga whale. Railbelt Grid Figure 3: Alaska’s Relative Size 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 6 April 17, 2024 Due to the high cost of transmission lines, the regions are moderately interconnected, primarily at 69kV, 115kV, 138KV, 230kV. A tfght power pool2 operates in the Central region, and an actfve economy-energy market exists between regions but is severely limited by transmission constraints. There is no formal interconnectfon queue. A reserve-sharing pool exists between all three regions, but historically, the regions have planned for capacity separately due to weak interconnectfons. The Railbelt grid is technically characterized as "transient stability limited," with machines under dynamic stress swinging power-output against other machines within the region and with regions swinging against each other across light inter-regional interconnectfons. These power swings resolve in mechanical forces which stress, and sometfmes over-stress, generator windings, rotors, stators and other mechanical equipment. The grid is also susceptfble to and has experienced large-scale,3 small-signal instability oscillatfons, which lead to outages and damage power equipment. Voltage stability, which varies from marginal to good depending on the specific area, has been improved with the additfon of six statfc VAR compensators at critfcal locatfons. The Railbelt grid operates under a subset of North American Electric Reliability Corporatfon (NERC) standards modified to account for the scale and nature of the interconnectfon (the grid's system bias is variable and ranges from 3-10 MW/.1 hertz). The grid has a sophistfcated under-frequency load-shed scheme which sheds load to match generatfon in four stages, with varying tfme delays and, in some cases, considering frequency rate-of-change. Traditfonal day-ahead and real-tfme security-constrained economic dispatch is run in each of the Load Balancing Areas (LBA) with net interchange, and frequency monitored and managed to NERC Control Performance Standards 1 and 2. Dynamic events on the grid occur and resolve very quickly (in 2 to 10 seconds) when compared with the much larger North American grids which resolve in tens of minutes. The grid's peak demand is roughly 750 MW compared to that of Texas’s ERCOT system, which has a peak demand of 85,000 MW. The grid's annual energy consumptfon is approximately 4,500 GWH compared with ERCOT’s 339,000 GWH. Project Goal: This improved grid must support diversified energy landscape that drives sustainable economic development in Alaska and ensures a cost-effective delivery of energy to Railbelt consumers 2 Tight Power Pool is a term of art indicating the commitment required by the parties within a power pool. Loose pools are generally economy energy contracts, and tight pools generally require a single dispatch and a single Load Balancing Area. 3 Oscillations have been measured with a peak of 220 MW, a 1.1 second period and sustained for over 90 seconds on a grid with a summer valley peak load of approximately 500MW. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 7 April 17, 2024 and beyond. As noted, the Railbelt utflitfes and the state of Alaska share a vision: a collaboratfve future in the Railbelt in which our communitfes come together and share resources to strengthen and build a smart, clean electrical grid that promises our residents, our natfonal defense infrastructure, and communitfes adjacent to the Railbelt access to clean, low-cost energy from any source. Other goals include reducing reliance on fossil fuels; documentfng lessons learned, partfcularly relatfng to penetratfon of inverter-based resources and voltage stability; and the development of innovatfve rate-making strategies on which to incentfvize prudent transmission development. DOE Impact DOE investment is critical to mobilizing additional state and utility capital. Accomplishing a project of this magnitude in a 10-to-15-year tfme frame is beyond the financial capabilitfes of the Railbelt utflitfes without significant rate increases. The burden of such rate increases falls on all ratepayers, but disproportfonately on the disadvantaged and underserved. With the completfon of this project, fuel burn (which represents about 40 percent of an average consumer’s bill) may be reduced 10 to 15 percent, exclusive of increased clean-energy development. The requested $365 million in DOE funding has the potentfal to unlock an additfonal $700 million to $1 billion in non-federal and utflity funding, significantly enhancing the Railbelt transmission system and boostfng clean-energy productfon in the region. In combinatfon with the GRIP F-1 project, this will be the largest grid-infrastructure project undertaken in the Railbelt since the interconnectfon of the Central and Northern regions in 1984. The benefits will be significant and comparable to the recent economic benefit derived from convertfng the Railbelt generatfon fleet from GE Frame units to aero -derivatfve units—a conversion that reduced fuel burn (carbon emissions) by nearly 30 percent. The benefits of the RIR will include improved fuel-efficiency, reduced carbon emissions, increased variable- generatfon penetratfon, increased private capital investment from IPPs in energy development, and reduced O&M. Another benefit will be extended transitfon tfme for moving away from Cook Inlet natural gas4. Finally, the project will promote coordinated energy- and capacity-planning across the Railbelt. 4 The Cook Inlet Field provides heat to 140,000 homes and businesses in the Central region and is used to generate 70 percent of the electricity in the Railbelt. In early 2021, the field’s only remaining large-scale producer notified utilities (both gas and electric) that they would not extend existing gas contracts, most of which expire in 2028. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 8 April 17, 2024 Community Benefits Plan: Job Quality and Equity Through Alaska’s unique Power Cost Equalizatfon (“PCE”) program, improvements in Railbelt transfer capability, reliability, and resiliency will stabilize long-term power costs for the numerous tribal and disadvantaged communitfes on the Railbelt as well as rural villages outside the Railbelt. The Alaskan IBEW (Internatfonal Brotherhood of Electrical Workers) leadership has identffied this as an opportunity to train a new generatfon of linemen and wiremen, reinvigoratfng this sector of Alaska’s technical workforce. The broad and inclusive outreach program envisioned in our CBP will ensure that maximum benefit flows to diverse and disadvantaged communitfes on the Railbelt. The Beluga-Healy HVDC Line project will directly benefit people within Alaska Natfve Village Statfstfcal Areas (ANVSAs) and DACs in Alaska’s Railbelt region. The project will construct 250 miles of HVDC transmission line from Beluga, near Anchorage in the Central Region, to Healy in the Northern Region. This HVDC line will enable Railbelt utflitfes to transfer low-cost and reliable power to where it is most needed. Beluga-Healy HVDC Line community benefits outcomes and objectfves include:  A robust public participation plan followed by a public AEA memo responding to stakeholder feedback  Increased transfer capacity between regions to enable higher renewable-energy integration and a reduction in fossil fuel generation and associated emissions  Improved long-term air quality in communities near fuel-based power generation, including ANSVAs and DACs  Energy-access resiliency and reliability improvements for ANVSAs and DACs on the Railbelt  Retention of over 650 highly paid union jobs with competitive, employer-sponsored benefits  Creation of over a thousand high-value construction and support jobs  Creation of numerous ongoing positions at utilities  Creation of apprenticeship and internship programs to reinvigorate Alaska’s energy workforce, including local-hiring preference  Decreased Railbelt community energy burdens from reduced line loss and thermal spending. A one cent per kWh reduction in the average cost of Railbelt power saves $44,080,000 annually.  The same reduction in the average cost of Railbelt energy will result in decreased off-Railbelt community energy burdens via increased Power Cost Equalization (PCE) with potential consumer PCE credit increases of $1.5M annually The project team will coordinate with partfcipatfng tribal councils on the Railbelt to promote local hiring and open dialogue with this key stakeholder group. Procurement will comply with Alaska public-contractfng law, which contains provisions for local hiring, apprentfceship training, prevailing wages, and other forward-looking policies. The project will partner with the IBEW-NECA, the Alaska Joint Electrical Apprentfceship and Training Trust (AJEATT), the Alaska Natfve Science & Engineering Program (ANSEP) and the Alaska Operatfng Engineers/Employers Training Trust 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 9 April 17, 2024 (AOEETT) to source apprentfceship candidates and ensure the development of a skilled, inclusive local workforce. Constraints on Resources An evaluatfon per NEPA EIS process will be completed to identffy any areas of sensitfvity to the environment or to Tribal cultural resources. This is a critfcal step, as the line will extend through state and natfonal park systems as well as through or in close proximity to ANSVAs identffied in the project area. All best-practfce protocols identffied will be incorporated into the project executfon. Climate Strategy As previously discussed, the Railbelt region of Alaska spans a distance further than that of Washington DC to Atlanta. The climate challenges and extreme weather patterns the region encounters—or is at risk of encountering—include frequent thunderstorms, heavy and sustained precipitatfon, earthquakes, volcanic actfvity, avalanches, flooding, changes in permafrost conditfons, high winds, coastal erosion, landslides, droughts, wildfires, tsunami potentfal, and sea-ice dynamics. Climate Resilience Strategies for Electricity: Upgrade grid to allow for high clean energy and variable renewables penetratfon: The Railbelt grid is an interconnected electrical transmission system reaching from Homer to Fairbanks and then on to Delta Junctfon, approximately 700 miles further. It supplies electricity throughout this region. The network consists of various utflitfes, the state, and Independent Power Producers (IPPs) that allow sharing to meet demand fluctuatfons and ensure system reliability. Upgrading the infrastructure will better integrate this power (partfcularly variable resources like wind and solar) into the Railbelt, ensuring better system reliability and fewer and shorter power outages. Reducing greenhouse gas emissions and improving access to power: Promotfng energy diversificatfon and minimizing the use of traditfonal fossil fuel-based generators will reduce harmful greenhouse. Reductfon of carbon emissions supports forest and stream health, strengthening community well-being through subsistence and other traditfonal uses of the land. Technical Description, Innovation, and Impact Relevance and Outcomes This project aligns perfectly with the FOA goals; transforming community, inter-regional and natfonal resiliency including consideratfon of future shifls in generatfon and load; catalyzing and leveraging state and private-sector spending for impactiul technology and infrastructure development; and advancing community benefits especially to disadvantaged and tribal communitfes. Further, the project will provide training and job opportunitfes for the next 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 10 April 17, 2024 generatfon of power system line workers, electricians, equipment operators, technicians, and engineers. The project consists of an HVDC overhead line (with potentfal cable sectfons where resiliency, NEPA, or other requirements deem it prudent) and Voltage Source Converter (VSC) statfons at Beluga and Healy interconnectfng the HVDC with the existfng transmission system. The line will likely be a 150 kV /200 MW bipolar line for enhanced transfer capability and increased resiliency; however, these specificatfons will be finalized in final design. The project will complete a parallel transmission path between the Northern and Central regions, immediately enhancing reliability and improving resiliency and economic dispatch between the two regions by reducing the dispatch of thermal generatfon and thereby reducing carbon emissions. These enhancements in turn will provide more resilient and reliable grid power to the five critfcal military installatfons served by the Railbelt strengthening our natfonal defense posture. Once the project is fully integrated into the southern-central HVDC interconnectfon and the regional BESS, these benefits will increase significantly. The project will ensure grid reliability by increasing inter-regional transfer capability, allowing for diversificatfon of fuel supply, acceleratfng the adoptfon of variable renewable generatfon, reducing carbon emissions, improving frequency regulatfon, and aiding in eliminatfng potentfally catastrophic small signal instability oscillatfons. This project was identffied as a key requirement for a cost-effectfve, fuel- diverse, clean-energy future in the Alaska’s Energy Security Plan, published in December 2023.5 Feasibility The Railbelt is transmission-constrained, meaning the grid is only able to move 10 percent or less of its peak load between regions. These constraints, caused by transient stability limitatfons and small signal instability, limit the grid’s ability to cost-effectfvely deploy large-scale, renewable projects. Further, Railbelt utflity engineers have observed several concerning trends on the Railbelt over the past decade. These 5 Alaska Energy Security Task Force. (2023, December 1). Alaska Energy Security Task Force Report, p. 36. Figure 4 Distribution of Railbelt Frequency Readings over time 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 11 April 17, 2024 challenges include the degradatfon of frequency regulatfon; decreasing system-frequency response to generatfon trip disturbances; and increasing magnitude and duratfon of natural- frequency power oscillatfons and occasional large power swings, which impact the entfre Railbelt (see figures 4, above, and 5, below). The displacement of thermal generatfon with renewable generatfon such as wind or PV will further decrease inertfa in each region and may negatfvely impact stability across single inter-regional transmission lines. These phenomena are thoroughly described, and their solutfons are explored in detail in studies referenced below6. The completfon of the HVDC line stretching from Beluga to Healy will serve as a crucial and significant element of this solutfon. The Railbelt’s Northern region is interconnected to the Central region by a single, 200-mile-long transmission line. The Northern region, with the highest energy costs in the Railbelt, desires to import as much energy from the Southern and Central regions as is technically and reliably feasible. The existfng transmission line has a stability limit of 65-84 MW, approximately a third of the line’s thermal limit. Currently, the line has to be de- energized for several weeks at a tfme due to severe icing or structural damage at one of the many river crossings; these events can occur multfple tfmes per year depending on weather. Due to the single contfngency line, the Northern system is limited in the amount of variable renewable generatfon it can import from the Central and Southern regions into its system, which does not have base-load hydro-generatfon on-line to provide grid strength as measured by Short Circuit Ratfo (SCR) following the loss of the tfe to the Central region. The extremely low SCR following the loss of the single line puts the system with its large motors, and the existfng SVCs and BESS, at risk. 6 Bansal A, Anantharaman A, Donlagic T, Feltes T, Orikhi Z, Rachinger S, Silva D, Grande -Moran C; Alaska Railbelt Power System Oscillation Anchorage Bess unit Impact Analysis; 10-20-20; SPTI P# 620T-001718 6List B, Amrein J, Heimann A, Furtner N, Keck H, Dorfler P, Hickey B, Stead D, Bradley Lake Deflector Divider Model Tests; 9-10-2004 VA TCH Hydro 6Cote J, Burlingame D, Lai D; Railbelt Oscillation Investigation and Mitigation study; 3-1-22; Electric Power Systems Inc. Figure 5 System Oscillations Resulting from Trip of the Existing Central-Northern Region Intertie 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 12 April 17, 2024 The proposed Beluga–Healy line is projected to enhance transfer capabilitfes between regions by two to three tfmes. The plan is to evaluate the impact of integratfng inverter-based HVDC/BESS— along with wind and solar generatfon—on voltage stability and the short circuit ratfo in order to provide real-world data. This data will be scalable and valuable for planning within larger grids, both in the U.S. and globally. The new line will allow Northern region wind and PV resources to be totally developed as part of the integrated grid instead of in isolatfon. Regulatfon will be performed over multfple regions, significantly reducing integratfon costs for renewable resources. The geographical diversity of wind resources will reduce the overall variability of wind and solar resources, reducing the financial impact of the regulatfons that are required by the use of thermal resources. The Beluga-Healy line will allow the Northern region to operate without thermal generatfon during much of the year, but it will be available when system conditfons or climate events warrant it, or when renewables are unavailable. Further, the proposed routfng of the line along the existfng AKLNG pipeline will open access to new wind resources that are currently unavailable in that geographic area. The combinatfon of the Beluga – Healy line with the Kenai – Beluga line and regional BESS will virtually eliminate transmission constraints on clean-energy development in the Railbelt. Additfonal lines and upgrades may be needed to establish specific renewable projects. However, the bulk of the benefits to the Railbelt are realized with these two transmission lines. To understand the project’s technical contributfon and feasibility, please refer to Figure 6 and Figure 6A. These figures provide a mechanical analog representatfon of transient stability between two regions, namely the Central/Southern and Northern regions. In AC power system transmission, two key concepts are critfcal: First, generatfon and load must always maintain near-perfect balance; second, real power transfer across a transmission line is achieved by increasing the voltage phase angle difference at the sending end relatfve to the receiving end. Figure 6 uses the analogy of drums and a spring to represent the transmission line between two areas, where the weight symbolizes the power transferred, and the spring stfffness reflects the line's interconnectfon strength. As power transfer increases, symbolized by the weight, the arms— held only by the spring—begin to separate. This separatfon angle, denoted as δ, represents the power-transfer angle between the sending- and receiving-end voltages. An excessive power transfer can lead to the arms falling below horizontal, illustratfng a system collapse or an “out-of-step” Figure 6 Mechanical Analog of AC transmission 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 13 April 17, 2024 conditfon. Oscillatfons in the arms, stfmulated by pulling and releasing the weight, mimic the grid's response to rapid load or generatfon changes or faults, (disturbances) which can lead to out-of-step conditfons if uncontrolled. These disturbances to the generatfon -load balance are caused by physical events such as trees inadvertently contactfng lines, generators tripping oftfine, equipment failures or rapid loss of wind or solar resources due to meteorological changes. In contrast, DC systems, partfcularly those utflizing VSC technology, offer greater control. Here, DC voltage adjustments at the sending and receiving ends manage power transfer, akin to controlling system frequency and phase angle in AC systems. DC voltage management is performed by the VSC-Insulated Gate Bipolar Junctfon Transistor (VSC-IGBT) based converter statfon analogous to the high-speed controller in figure 6A. Installing an HVDC line between the Central/Southern and Northern regions introduces a shock absorber—adjustable in real-tfme for length and stfffness—in parallel with the mechanical spring. This additfon enhances the system's capacity to handle increased power transfers and dampen oscillatfons. When integrated with Battery Energy Storage Systems (BESS) and the Southern HVDC, this combined setup acts as a four-quadrant actfve device able to deliver and absorb both real and reactfve power. It injects energy to counteract oscillatfons and regulate frequency, thereby amplifying the stabilizing effect throughout the grid. Integratfng these geographically diverse resources in real-tfme represents a truly innovatfve solutfon for managing grid flows and is likely a first-of-its-kind implementatfon. Railbelt engineers' and operators' deep experience with stability and its effects on power flows makes them uniquely positfoned to successfully integrate and implement such a solutfon. Learnings gleaned from this solutfon will have applicatfons through the U.S. and globally. Beyond stabilizing large-scale oscillatfons and alleviatfng stability constraints, a new transmission line can remove barriers to developing new clean-energy sources in both the Central and Northern regions. Without the resilient and unconstrained access facilitated by a new line, the potentfal for renewable resource development in each region remains limited, contfngent on their ability to manage single-contfngency events. As noted, HVDC/BESS control will play an integral part in stability control of the entfre Railbelt grid. The controller will work in concert with BESS and HVDC controllers in the Northern, Central and Southern regions to control transient frequencies in each of the islands , increasing stability limits across each of the existfng AC transmission interconnectfons. The HVDC controller will help coordinate the system-wide regulatfon of clean-energy resources. will be integral to the ability to black-start either the Northern or Central region following a catastrophic event such as a repeat of the 1964 earthquake, the November 2018 earthquake, or the tremendous windstorm of 2022. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 14 April 17, 2024 Innovatfon and Impacts We know of no other single transmission line that has the capability to consolidate multfple planning areas into a single inter-regional planning area. The project will improve the grid's overall stability by establishing a parallel path between the Northern region and the Central/Southern regions. Enabling high-speed control of power flows will lower spinning-reserve requirements, thus diminishing reliance on Cook Inlet natural gas and decreasing carbon emissions. This control, coupled with the reductfon of impedance between the regions, will elevate transient stability limits and therefore increase transfer capacity. When operated in a coordinated fashion, the BESS and southern HVDC system will increase transfer capability, resiliency, and reliability, even more significantly by performing three functfons, all of which contribute to frequency stabilizatfon. The first functfon is to increase transfer capability. The second is to improve frequency regulatfon. And the third is address small-signal instability on the grid. The HVDC controllers and three BESS installatfons in three different regions of the system will operate in a coordinated manner to increase transfer limits across the interconnectfng transmission lines. Following completfon of the Beluga–Healy sectfon, the BESS and Southern/Central system controls will be modified to optfmize system security across all three regions. Such control will allow real-tfme optfmizatfon of grid operatfons in the face of events that result in d ecreased inertfa and other generatfon contfngencies. This enhanced grid performance will increase the ability to accept renewables into the system by aiding in the performance of regulatfon and reserve optfmizatfon. Further, the increase of inter-regional transfer capacity from approximately 75MW to over 200MW will allow the generatfon with the highest costs and emissions on the Railbelt to run only during rare contfngencies. It will also allow large-scale wind projects of approximately 200MW capacity to be located as needed to take full advantage of geographic diversity in wind resources, minimizing the amount of fossil-fuel generatfon required to regulate the output of the Railbelt’s future wind generatfon portiolio. As noted above, we believe this to be an innovatfve, first-of-its- kind solutfon. Knowledge gleaned from this project’s unique integratfon of multfple BESS and HVDC will be useful throughout the country and world as BESS and HVDC systems are installed to facilitate increased, variable, clean-energy project integratfon. Further, analysis of real-world experience with high penetratfon of inverter-based resources will provide valuable knowledge that can be scaled and applied to larger grids in other parts of the US and wor ldwide. F.6 Topic Area 3: Grid Innovation Program Strengthening the fragile connectfon between three service regions of the Central and Northern regions of the Railbelt will provide significant benefits to all five interconnected service areas 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 15 April 17, 2024 represented in this proposal, CEA, GVEA, HEA, MEA, and SES. The new HVDC line will eliminate the single-contfngency islanding conditfon that is created when the existfng intertfe is out of service (scheduled or non-scheduled). The HVDC line will also eliminate the small-signal instability events that occur on the loss of the existfng intertfe during high central regional exports in the summer valley season. The completfon of this project will increase transfer capability between the Central and Northern regions by two or three tfmes the current transfer capacity. Further, real-tfme control of transmission line flows will improve dynamic performance and enhance operatfonal flexibility related to disturbance response regulatfon and reserves. This project enhances and accelerates the Railbelt’s ability to integrate intermittent renewable resources such as wind and solar directly into the grid. To facilitate transmission constructfon, the Regulatory Commission of Alaska (RCA) has agreed to join our project team within their statutory limits. Recognizing the unique structure of Railbelt's electric cooperatfves, the RCA is prepared to initfate an investfgatfve docket to explore innovatfve funding mechanisms for transmission-investment-cost recovery. Larger-scale projects drive the price per unit of electricity down and make the benefit-cost hurdle lower and more achievable, driving greater private sector investment in the Railbelt energy field. Workplan Project Objectfves The project aims to achieve the following objectfves, each with specific measures of success to gauge progress and impact: 1. Create a reliable and resilient grid capable of supportfng a diverse mix of clean energy, reduced carbon emissions, enhanced stability and increased transfer capacity between regions at two to three tfmes current capability. This infrastructure is crucial for the Railbelt and Alaska’s future quality of life and economic growth. Success in this area will be measured by:  The reductfon in the number of grid-instability events over tfme  A decrease in transmission and generatfon outages due to weather, wildfires, and other disruptfve events  The improvement in transfer capability, assessed by comparison of sending- versus receiving-end phase angles  The megawatt-hours (MWh) of additfonal clean energy integrated into the grid over tfme 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 16 April 17, 2024 2. Successful constructfon and integratfon of an HVDC overhead line from Beluga to Healy, linking it with the BESS and Southern HVDC systems using innovatfve technical solutfons to enhance resiliency in extreme environments. This goal's achievement will be evaluated through:  Completfon of the project within the set schedule and budget  Improved heat rates in the Northern region and the overall system due to enhanced operatfng flexibility  Reduced islanding events between regions 3. Promotfon of economic growth by creatfng thousands of well-paid jobs and opportunitfes for Alaskans, ensuring that at least 40 percent of these benefits reach those residents in the Railbelt living in disadvantaged communitfes (DACs) or in Alaska Natfve Statfstfcal Areas (ANSAs). The success of this objectfve will be monitored by:  The total number of constructfon and long-term jobs created, as verified by certffied payrolls  The proportfon of these positfons filled by indigenous people or residents from Railbelt's disadvantaged communitfes  The number of journeyman craflsmen trained by the building trades during the project, compared to historical averages Technical Scope Summary Steps 1-a through 1-e is a 250-mile 150 kV/200 MW, HVDC bipolar transmission link between Beluga in the Central region and Healy in the Northern region. Permitting and routfng this segment will undergo a NEPA process expected to take three years. The transmission line uses a 230kV bay at the Beluga 230kV yard to interconnect to the existfng Central region 230kV AC system via a VSC-IGBT converter assembly. A similar configuratfon interconnects the line at Healy. The transmission route is designed to follow the AKLNG right-of-way (ROW) to Healy. Where practfcal, the AKLNG ROW will serve as a buffer to reinforce and harden the HVDC line against natural disasters, including the impacts of seismic actfvity and extreme weather events. This project will be sourced with American bought products in compliance with the Buy America program. The line will be constructed with ROW and towers designed to support a second circuit. Given the limitatfons of modifying a DC line for multf-terminal operatfons, should future opportunitfes for additfonal renewable generatfon or loads emerge along the HVDC line’s route, a second AC circuit can be added to integrate these resources into the grid. A NEPA route selectfon study will be completed to reach a final determinatfon on routfng. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 17 April 17, 2024 Special consideratfons for outreach and flexibility in constructfon techniques may be necessary and are expected as the line transitfons Denali Natfonal Park and state parks. Substatfon constructfon will include steel structures, foundatfons, conduit, cables, VSC-IGBT converter statfons, two 230kV/138kV power transformers, and associated breakers and switches with SCADA, communicatfons, protectfon and control devices. Line constructfon is envisioned using a combinatfon of steel H structures; angle and dead-end structures with all the associated guys, anchors, and overhead; and potentfally underground or advanced design conductors. Should the passage through Denali Natfonal Park necessitate it, the consideratfon of experiment al, tfght- bundled superconductors may be employed. A fiber-optfc cable will be included in the Optfcal Ground Wire (OPGW) for communicatfons. Due to the scale of the project (250-mile length), it will be broken into five sectfons for constructfon purposes, with multfple contractors working concurrent schedules to meet the constructfon tfmeline of just two years. The line's segmentatfon has been strategically designed to maximize the use of common constructfon techniques, considering the varying requirements for agency permits. Preliminary efforts to secure right-of-way access through easements, special permits, or land acquisitfon will start with Denali Natfonal Park. The acquisitfon process will be segmented into five phases, mirroring the line constructfon stages. Once final permits are secured, easements will be finalized. Land is available at both end points (Beluga and Healy) for converters and substatfons. Therefore, permits should be minimal to accommodate local design criteria. Transmission constructfon will start with right-of-way clearing followed by material delivery and installatfon of structures and anchors. Following erectfon, down guys are installed to support the structures, and conductors are strung using specialized pulling equipment. The conductor is then sagged and pulled to proper tension. Following installatfon, conductors are clipped (attached to tangent and angle structures) or dead-ended (attached to end structures), and jumpers are installed to carry current from one side of the dead-end structure to the other. To expedite constructfon and minimize environmental impacts, helicopter constructfon is recommended in inaccessibly remote locatfons. The use of helicopters to set structures and pull sock line (stringing lines or rope) can reduce labor costs and increase productfvity. Helicopters can also be used to deliver material to staged locatfons along the transmission path. The constructfon will entail the additfon of a 230kV bay at Beluga and a line sectfon extending to the converter statfon. This sectfon is to include terminatfon structures for the line as well as the necessary infrastructure for switches and breakers. It will enable interconnectfon with the existfng 230kV AC system in the Central region via a bi-pole HVDC statfon that employs an HVDC converter. At the project’s northern terminus, the Healy substatfon will act as a terminatfon point, a 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 18 April 17, 2024 switching statfon, and a transitfon point from the HVDC to the Northern region’s 230kV AC system, facilitated again by a bi-pole HVDC statfon using an HVDC converter. The interconnectfons will be equipped with relaying protectfon and communicatfon systems to ensure the transmission line sectfons leading to the converter statfons operate safely. The procurement and testfng of the integrated control system's soflware and hardware will occur concurrently with line constructfon, ensuring it is ready and in place for commissioning as the final sectfons of the line are installed. The commissioning of the integrated control system will proceed afler the HVDC system has been commissioned and checked out in standalone mode. The Beluga-Healy HVDC line will provide improved energy-transfer grid stability and resilience between the Central and North regions of the Railbelt. The existfng 138kV AC transmission line traverses some of Alaska's most challenging landscapes, encompassing numerous river crossings, areas prone to snow and ice-loading, mountainous topography, and terrain that is constantly changing due to permafrost degradatfon and processes like solifluctfon and creep. Additfonally, the existfng line’s proximity to areas where lightning strikes are prevalent increases the risk of fire danger; implementfng an alternatfve path will enhance the resiliency and reliability of the transmission network, thereby reducing instances of transmission downtfme and improving the capacity to transfer power throughout the Railbelt. This additfonal line will also unlock acces s to previously inaccessible renewable-energy sources, including wind, hydroelectric, and photovoltaic (PV) opportunitfes. Work Breakdown Structure (WBS) and Task Descriptfon Summary The overall approach for the project workplan follows accepted project-management techniques identffied more completely in the Project Management Body of Knowledge (PMBOK). The project will engage stakeholders through the comprehensive process, which is more fully defined in our Community Benefit Plan; execute analysis and permitting in compliance with NEPA requirements; and engineer, design, procure and construct a 150kV/200 MW Bipolar HVDC line from the Central region to the Northern region of Alaska’s Railbelt. This HVDC system will be fully integrated into the HVDC/BESS system from F-1. The integratfon will be the first-of-its-kind, real-tfme integratfon of multfple large-scale BESS and HVDC systems. The WBS of Figure 7 is summary task roll -up of the 92 task WBS and Gantt chart developed for the project. Additfonal WBS details are available upon request but were summarized here to meet page-count requirements. Milestone Summary 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 19 April 17, 2024 Work Breakdown Structure 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 20 April 17, 2024 Figure 7 Summary Work Breakdown Structure for the Railbelt’s Beluga-Healy HVDC line. Outline Number Task Name Duration Start Finish 1 Project Management and Planning 2087 days?Thu 5/15/25 Fri 5/13/33 1.1 Project management Plan (PMP) 22 days Thu 5/15/25 Fri 6/13/25 1.2 Community Benefit Plan (CBP) Early Stakeholder Engagement determination and meetings 2087 days?Thu 5/15/25 Fri 5/13/33 1.3 National Environmental Policy Act (NEPA) Process - EIS Required Conceptual Desgn and Environmental Impact 784 days Thu 5/15/25 Tue 5/16/28 1.3.1 Permitting Undertake EIS and apply for permits 487 days Thu 5/15/25 Fri 3/26/27 1.3.1.1 NOI to prepare EIS -HVDC interconnect Central Region and the Northern Region-Environmental and Permitting 1 day Thu 5/15/25 Thu 5/15/25 1.3.1.2 Scoping and Project alternative analysis 487 days Thu 5/15/25 Fri 3/26/27 1.3.2 NEPA Revisions & Identification long-termconstraints on comm. Access to res. & to tribal cultural resources 296 days Fri 3/26/27 Fri 5/12/28 1.3.3 Record of Decsion Approval Milestone 0 days Mon 5/15/28 Mon 5/15/28 1.3.4 EIS Record of Decision Go/No Go 1 day Tue 5/16/28 Tue 5/16/28 1.4 Cyber Security Plan (CSP)2087 days?Thu 5/15/25 Fri 5/13/33 1.4.1 Develop Cyber Security Plan 43 days Thu 5/15/25 Mon 7/14/25 1.4.2 Cybersecurity Plan Milestone 0 days Tue 7/15/25 Tue 7/15/25 1.4.3 Cyber security Go/No Go 1 day Wed 7/16/25 Wed 7/16/25 1.4.4 Ongoing Cyber Security monitoring and iterative updates 2043 days Wed 7/16/25 Fri 5/13/33 1.5 Continuation Briefing(s)1763 days Fri 8/15/25 Tue 5/18/32 2 SOPO Phase 1 Design Permitting and Siting 1828 days Thu 5/15/25 Mon 5/17/32 2.1 Risk Evaluation (ongoing)1828 days Thu 5/15/25 Mon 5/17/32 2.1.1 Intital Risk Probability Impact and Mitigation Matrix (Focus on CBP, natural hazards,preliminary 2.1.2 & 2.1.3 Topics)10 days Thu 5/15/25 Wed 5/28/25 2.1.2 Formal Review 1 (Focus on routing through Denali National and State Parks)2 days Thu 5/29/25 Fri 5/30/25 2.1.3 Formal Review 2 (Focus on potential uses of AKLNG ROW as mitigation buffer)2 days Fri 5/15/26 Mon 5/18/26 2.1.4 Formal Review 3 2 days Sat 5/15/27 Mon 5/17/27 2.1.5 Formal Review 4 2 days Mon 5/15/28 Tue 5/16/28 2.1.6 Formal Review 5 2 days Tue 5/15/29 Wed 5/16/29 2.1.7 Formal Review 6 2 days Wed 5/15/30 Thu 5/16/30 2.1.8 Formal Review 7 2 days Thu 5/15/31 Fri 5/16/31 2.1.9 Formal Review 8 2 days Sat 5/15/32 Mon 5/17/32 2.2 Design Criteria 308 days Thu 5/15/25 Mon 7/20/26 2.3 Prelimnary design 308 days Thu 5/15/25 Mon 7/20/26 3 Public Notice per CBP 5 days Tue 4/15/25 Mon 4/21/25 4 Final Design and Engineering 1416 days Mon 9/15/25 Mon 2/17/31 5 Permitting 418 days Fri 3/26/27 Tue 10/31/28 5.1 Permits complete and valid GO/ No Go 0 days Fri 3/26/27 Fri 3/26/27 5.2 ROW and land Acquisition 262 days Fri 3/26/27 Sun 3/26/28 5.3 Land Acquisition 122 days Mon 5/15/28 Tue 10/31/28 6 SOPO Phase 2 Procurement and Acquisition (Materials and Services)-Long-lead Equipment Purchase 644 days Tue 5/16/28 Sat 11/2/30 7 SOPO Phase 3 Construction and Deployment 1156 days Wed 7/12/28 Wed 12/15/32 8 SOPO Phase 4 Testing and Commissioning 1216 days Fri 9/15/28 Sun 5/15/33 9 Project Completion Milestone 0 days Sun 5/15/33 Sun 5/15/33 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 21 April 17, 2024 Go/No-Go Decision Points (See Sectfon VI.B.xv. for more informatfon on the Go/No-Go Review) End of Project Goal Create reliable and resilient grid capable of supportfng a diverse mix of clean energy, reduced carbon emissions, enhanced stability, and increased transfer capacity between regions two to three tfmes current capability. This infrastructure is crucial for the Railbelt and Alaska ’s future quality of life and economic growth. Successful constructfon and integratfon of an HVDC overhead line from Beluga to Healy, linking it with the BESS and Southern HVDC systems using innovatfve technical solutfons to enhance resiliency in extreme environments. Promote economic growth by creatfng well-paid jobs and opportunitfes for Alaskans, ensuring that at least 40 percent of these benefits reach those residents in the Railbelt living in DACs or ANVSAs. Outline Number Task Name Duration Start Finish 1.3.4 EIS Record of Decision Go/No Go 1 day Tue 5/16/28 Tue 5/16/28 1.4.3 Cyber security Go/No Go 1 day Wed 7/16/25 Wed 7/16/25 1.5.2 Kickoff Go/ No Go 1 day Wed 8/20/25 Wed 8/20/25 1.5.4 Risk Briefing 2 Go/ No Go 1 day Wed 5/20/26 Wed 5/20/26 1.5.6 Risk Briefing 3 Go/ No Go 1 day Wed 5/19/27 Wed 5/19/27 1.5.8 Risk Briefing 4 Go/ No Go 1 day Thu 5/18/28 Thu 5/18/28 1.5.10 Risk Briefing 5 Go/ No Go 1 day Fri 5/18/29 Fri 5/18/29 1.5.12 Risk Briefing 6 Go/ No Go 1 day Mon 5/20/30 Mon 5/20/30 1.5.14 Risk Briefing 7 Go/ No Go 1 day Tue 5/20/31 Tue 5/20/31 2.3.3 Preliminary Design StudyWorks Go/ No Go 1 day Mon 7/20/26 Mon 7/20/26 4.11 Design and Engineering Completion Go/No Go 1 day Mon 2/17/31 Mon 2/17/31 5.2 Permits Complete and Valid GO/ No Go 1 day Tue 10/31/28 Tue 10/31/28 5.4.6 Right of Way and Land Acquisition Go/No Go 1 day Tue 10/31/28 Tue 10/31/28 6.6 Equipment Procurement Go/No Go 1 day Sat 11/2/30 Sat 11/2/30 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 22 April 17, 2024 Project Schedule (Gantt or similar) Project Management Overall Approach The project-management approach will follow the key tenets of the PMBOK’s successful project- management guidelines. This approach is structured around the concept of process groups and knowledge areas. Process Groups: PMBOK organizes project management into five process groups that represent the stages of a project's lifecycle:  Initiating: Defining and authorizing the project or a project phase.  Planning: Establishing the scope, objectives, and procedures necessary for accomplishing the project.  Executing: Performing the work defined in the project-management plan to achieve the project's objectives.  Monitoring and Controlling: Tracking, reviewing, and regulating the progress and performance of the project; identifying any areas in which changes to the plan are required.  Closing: Finalizing activities across all process groups to formally close the project or phase. Knowledge Areas: PMBOK also delineates 10 knowledge areas that are key to successful project executfon. These areas encompass the core technical subject matters necessary for effectfve project management:  Stakeholder Management: managing stakeholders' expectations and engagement. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 23 April 17, 2024  Risk Management: identifying, analyzing, and responding to project risks.  Communication Management: ensuring timely and appropriate planning, collection, creation, distribution, storage, retrieval, management, control, monitoring, and ultimate disposition of project information.  Procurement Management: managing procurement of goods and services from outside the project team.  Integration Management: ensuring that project processes are properly coordinated.  Scope Management: managing the project's scope.  Schedule Management: managing the project schedule.  Cost Management: managing the project budget.  Quality Management: Ensuring the project will satisfy the stated or implied needs for which it was undertaken.  Resource Management: managing project resources, including human resources and materials. As noted above, the project will use traditfonal project management techniques and controls such as change management, budget and cost control, and scope management as identffied in the PMBOK. A comprehensive risk log will be maintained by the project manager. At a minimum, all risk and mitfgatfon strategies will be updated at each milestone. The project will be managed by an overall project lead under the guidance of a team comprised of Railbelt utflity engineers, system operators, and managers. Actfng as the project steering committee, the team will guide the project lead’s efforts and provide access to resources and data. The team and DOE will validate and verify the performance of the systems at each milestone and go/no -go point. Role Descriptfon Project Lead Manages overall project Engineering Liaison Evaluates process to secure needed design & engineering expertfse Lands Liaison Evaluates process to secure land acquisitfon, easements, and permits Constructfon Liaison Evaluates the best method to secure constructfon contracts Labor Liaison Works with labor unions, workforce development organizatfons, universitfes, and trade schools to arrange for needed labor Project Management Lead Manages overall schedule and coordinates individual projects Finance & Grant Management Lead Coordinates work with AEA, utflitfes, DOE, RUS, and private lenders Government Relatfons Lead Communicates project details with local, state, and federal entftfes Purchasing & Materials Lead Assures key materials are available and monitors and works with vendors on unforeseen Buy America goals 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 24 April 17, 2024 Public Relatfons Lead Communicates with key stakeholders and the general public, and executes the Community Benefit Plan outreach Legal & Contracts Lead Develops contracts and provides guidance with appropriate terms and conditfons Accountfng and Closeout Coordinator Coordinates with project leads, assuring all proper documentatfon is secured to tfmely close out projects; coordinates with Finance and Grant Management Lead Project Value and Change Management Projects will be competftfvely bid. Traditfonal project change control methods will be used. Quality Assurance/Control QA/QC Performed by the project management team; strict check-out and commissioning procedures will be developed in the Factory Acceptance (FAT)and Site Acceptance test (SAT) plans. Project Communicatfon Project initfatfon documents, and Project Management Plan (PMP) will contain a project communicatfons plan detailing chain of command and appropriate communicatfon meetfng cadence and tempo. Technical Qualifications and Resources (Approximately 20% of the Technical Volume) The team has a combined 200 years of Railbelt system operatfons, constructfon, and engineering experience. Members are experienced and well-versed in executfng complex transmission-line and substatfon projects in Alaska’s challenging environment. The Railbelt utflitfes have skilled engineers and designers, and the local work force includes IBEW journeymen, technicians, and linemen who have built the electrical system we have today. Engineering and design firms, who routfnely propose projects as envisioned in the applicatfon, are available locally and in the Pacific Northwest. Alaska has multfple highly skilled electrical contractors through the Natfonal Electrical Contractor Associatfon (NECA), which employs workers from IBEW local 1547. They are versed both in high- voltage transmission and substatfon constructfon. The IBEW has out-of-state traveler availability and a state-of-the-art apprentfceship school that can ramp up to meet demand. The NECA contractors have specialized tools and equipment to undertake remote, off-road transmission constructfon. These specialized techniques have expedited constructfon and minimized environmental damage in the past. Unique Qualifications and Expertise The project team is unique in that it includes all relevant decision-makers in the Railbelt. The team has decades of experience in constructfng transmission lines and installing , operatfng, and maintaining high-voltage (34.5kV, 69kV, 115kV, 138 kV and 230kV Alternatfng Current (AC)) submarine cables in Cook Inlet. In additfon, they have decades of experience with BESS systems. The existfng BESS in Fairbanks at 46MW—5 minutes was the largest BESS in the world at the tfme of its installatfon in 2003, and the Southern region BESS (46.5MW—2hours) was commissioned and installed in 2022. Further, with six Statfc VAR Compensators (SVCs) on the Railbelt, the team 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 25 April 17, 2024 is very familiar with installatfon, commissioning, and operatfng high-powered electronics like those used in HVDC converters. The team is currently rebuilding the 39-mile Sterling-to-Quarts Creek line to 230 kV. The team has also collaborated on a number of other projects, including the constructfon of the $350M Bradley Lake hydroelectric facility in 1991; the $47M Battle Creek diversion at Bradley Lake in 2020; and $10M controls replacement on the Northern SVCS. Team members have also done significant transmission-line constructfon individually. Existing Equipment and Facilities The team works with state-of-the-art SCADA/EMS systems with an inter-regional ICCP link for data transfer: a complex network of ringed SONET-compatfble digital microwave and fiber assets and hardened statfons for high-speed communicatfons. The microwave and fiber systems are currently used for SEL high speed mirrored-bit communicatfons to enable high-speed transfer tripping. As noted above, there are several high-voltage AC submarine cables, BESS systems and SVCs, as well as the equipment and technical know-how to work on them. Relevant, Previous Work Efforts, Demonstrated Innovations Numerous complex systems have been studied and successfully placed in the Railbelt by project team members. These include the Northern region BESS in 2003, the Southern region BESS in 2022, and the Central region BESS, which is currently under constructfon. High-voltage AC submarine cables have been installed, the earliest at 138kV in 1973. Statfc Var Compensators have been added, the earliest of which was in 1985, and more recently, the control systems on all the Alaska Intertfe and Bradley Lake SVCs have been completely replaced. Installatfon of SCADA and EMS systems at all five utflitfes; installatfon of inter-regional digital-microwave and fiber-optfc systems; installatfon of high-speed, communicatfon-assisted transfer trip- and line-current differentfal protectfon on all Railbelt transmission lines; eigenvector/value analysis that defined and mitfgated the small-signal instability points between the weak Summer Valley Railbelt grid and the Bradley Lake hydroelectric project. The study of development and installatfon of the Railbelt’s multf-stage, multf-delayed under-frequency load shed schemes is another example of a complex real-tfme control system developed and installed by members of the project team. Key Team Members’ Time Commitment Key members will be assigned to this project as necessary to ensure successful completfon. Page 1 of 21 REQUIRED USE -- Community Benefits Plan Template for Funding Opportunity Announcement (FOA) Number: DE-FOA-0003195 Bipartisan Infrastructure Law (BIL) – Grid Resilience and Innovative Partnerships (GRIP) Alaska Energy Authority Topic Area 3 – Railbelt Central-Northern Region HVDC Interconnect General Project Informatfon 1. High-level description of the CBP and project The Beluga-Healy HVDC Line project will benefit Tribes in Alaskan Natfve Village Statfstfcal Areas (“ANVSAs") and disadvantaged communitfes (“DACs”) in Alaska’s Railbelt region. The project will construct 240 miles of HVDC transmission line from Beluga in the Central Region near Anchorage to Healy in the Northern Region near Fairbanks. By increasing operatfng voltages, this HVDC line will enable Railbelt utflitfes to transfer low-cost and reliable power to where it is most needed. Beluga-Healy HVDC Line Community Benefits outcomes and objectfves include:  Robust public partfcipatfon plan followed by public AEA (Alaska Energy Authority) memo responding to stakeholder feedback.  Increased transfer capacity between regions to enable higher renewable energy integratfon and a reductfon in fossil fuel generatfon and associated emissions.  Energy access resilience and reliability improvements for Tribal communitfes in ANVSAs and DACs on the Railbelt.  Retentfon of over 650 highly paid union jobs with competftfve employer-sponsored benefits.  Creatfon of 1,000s of temporary constructfon jobs.  Creatfon of 10-15 new positfons at four partfcipatfng utflity cooperatfves.  Improvement and growth of apprentfceship and internship programs that include recruitment focused in ANVSAs and DACs.  Decrease in energy burdens from reduced line loss in Railbelt communitfes.  Decreased community energy burdens for remote communitfes (outside of Railbelt) via increased Power Cost Equalizatfon (PCE) with potentfal consumer PCE credit increases of $1.5M annually based on FY22 PCE Community Report.pdf (akenergyauthority.org). The project team plans to pursue an overarching Memoranda of Agreement with interested Tribal Councils on the Railbelt to encourage local partfcipatfon and open dialogue with this key stakeholder group. AEA will promote and commit to local hiring where possible, barrier reductfon for entry into apprentfceship and internship programs, contracts that pay above prevailing wages, and other forward looking policies. The project will partner with the Internatfonal Brotherhood of Electrical Workers- Natfonal Electrical Contractors Associatfon (IBEW-NECA) and Alaska Joint Electrical Apprentfceship and Training Trust (AJEATT) to source apprentfce candidates and ensure the development of a skilled, inclusive local workforce. Page 2 of 21 2. Construction Information AEA will develop and maintain a risk register complete with ongoing mitfgatfon strategies. At this point we antfcipate the primary risks to be (1) staffing (2) procurement, cost, and supply chain management and (3) permitting the sectfon near Denali State Park and Denali Natfonal Park. Mitfgatfon strategies for each are outlined in the following paragraphs. Staffing Shortages. To address the natfonal shortage of electrical workers, the Project Team will contfnue ongoing discussions with the IBEW 1547, NECA, and their AJEATT to inform them of project tfming and staffing needs and to reinforce AEA’s desire to hire local workers. For additfonal staffing needs, workers will be sourced from the Lower 48 states through IBEW. The Project Team is also working to develop training opportunitfes for Alaskan Natfve workers in a proposed partnership between the utflitfes, IBEW/NECA, and local Natfve village and regional corporatfons. Procurement. The engineering and project management plan will include periodic evaluatfons of the supply chain for major equipment. The schedule is flexible with modular engineering and constructfon plans to navigate around supply chain challenges while maintaining productfvity: procurement of scarce items can be delayed minimizing supply chain and inflatfonary cost impacts without derailing the schedule. Permitting. A two-pronged approach has been developed to address antfcipated permitting challenges. First, a robust and early stakeholder engagement plan is intended to bolster support and advocacy for the project by transparently identffying and attemptfng to resolve any issues that stakeholders have. Second, the project will build in contfngencies/optfons such as using innovatfve advanced conductors to minimize conductor size and spacing, potentfally undergrounding some portfons of the line, or routfng the line around the state and natfonal parks. It should be noted that an Alaska Department of Transportatfon & Public Facilitfes (AKDOT-PF)-managed ROW exists through both Denali State Park and Denali Natfonal Park, and Alaska Gasline Development Corporatfon (AGDC) previously obtained permits in both parks. Existfng partnerships with these agencies could pave the way for better permitting outcomes. 3. Locations and Communities Affected The new HVDC transmission line will run 240 miles from Beluga to Healy. Importantly, this route will be entfrely in remote locatfons untfl it connects in Healy. Beluga is located in Kenai Peninsula Borough (#02122000100), populatfon 526. This tract is considered disadvantaged because it meets more than 1 burden threshold and the associated socioeconomic threshold. The one ANVSA in this tract is also considered disadvantaged. From there the line travels through Matanuska-Susitna Borough (#02170000101), populatfon also 526. This tract is considered disadvantaged because it meets more than 1 burden threshold and the associated socioeconomic threshold. From there the line will travel through Denali Borough (#02068000100), populatfon 2,246, to its terminatfon point in Healy, which already houses a significant power generatfon plant and grid infrastructure. Denali Borough is considered disadvantaged because it meets more than 1 burden threshold and the associated socioeconomic threshold.1 The one ANVSA in this tract is also considered disadvantaged. Every single mile of transmission line that will be installed through this project will be installed on DAC lands. These DACs 1 https://screeningtool.geoplatiorm.gov/en/ Page 3 of 21 and ANVSAs are antfcipated to capture the majority of project benefits, partfcularly local hiring preference. There is no demolitfon of any lines or facilitfes included in the project; minimal waste materials are antfcipated to be generated. There are no DACs antfcipated to be adversely affected by the project, since the project occurs almost entfrely in remote locatfons. All communitfes where constructfon occurs will have multfple opportunitfes to engage on preliminary and final design through the project’s public partfcipatfon plan. Sacred tribal lands will be identffied through the Environmental Impact Assessment study prior to deployment of constructfon and through public engagement with Tribal Councils and leaders in the service areas. A. Community and Labor Engagement 1. Community and Labor Stakeholders Engaged to Date Alaska Federatfon of Natfves, Alaska Village Electric Cooperatfve, Alaska Black Caucus, Alaska Municipal League, IBEW Local 1547, Internatfonal Union of Operatfng Engineers (IUOE) Local 302, Alaska Operatfng Engineers Training Trust, Alaska Joint Electrical Apprentfceship & Training Trust, Fairbanks Chamber of Commerce, Alaska AFL-CIO, Anchorage Economic Development Corporatfon. Type of Engagement: Preliminary meetfngs and phone calls to alert organizatfons to existence of project and desire for partnership if funded. No known oppositfon to the project has been expressed by any of these organizatfons to date. Date of Engagement: Between February 2023 – April 2024. Outcome of Engagement Ongoing discussion. 2. Community and Labor Stakeholders to be Engaged. Beluga-Healy HVDC Line Public Partfcipatfon Plan: Phase 1: Draft public participation plan 1. Select public engagement firm to assist with public participation plan (cost estimate for scope of work included in this section = $156,410). 2. Select environmental consultant to complete EIS and field related stakeholder questions. 3. Meet with and draft overarching MOA with representatives from receptive Railbelt Tribal Councils to ensure robust public participation and local hiring preference. 4. Draft outreach media. Include strategies designed to ensure participation from minority groups and disadvantaged communities affected by project. A focus group will be used to test effectiveness of materials on diverse populations. 5. Launch website with public meeting schedule, project description, public comment section, and ArcGIS Online mapping tool with public comments geocoded by location, allowing identification of site-specific issues, needs, and themes. Phase 2: Implement Public Participation Plan Alaska Energy Authority (AEA), representfng the State of Alaska, is the lead applicant for this project. They are accustomed to engaging with local governments and tribal entftfes regarding permitting Page 4 of 21 and regulatory processes for capital projects. As noted in B.1. many of these conversatfons have already begun and will contfnue to inform project development. AEA believes that local governments and Tribal entftfes are uniquely situated to identffy actfons the project can take to advance progressive workforce, DEIA, and environmental justfce outcomes at both the community and regional levels. AEA will work closely with each utflity provider to determine the appropriate tfme and setting for community meetfngs to avoid conflicts with other events. The core team will devote special attentfon to ensuring diverse demographic partfcipatfon at all meetfngs, including hostfng meetfngs at a range of tfmes, including outside of typical working hours. Task 1: Introductory Work Sessions Each of the four utility providers involved in the project and AEA will host an introductory public work session. These work sessions will be advertised at least two weeks in advance via social media, public postings, utility cooperative mailers, and the project website ($5,000 in marketing/outreach materials is estimated). Topics will include: Task 2: Data Collection 1. Conduct surveys to address data gaps identified by public during introductory public work sessions. Surveys will be distributed electronically and/or made available at key community locations. AEA does not expect to get a statistically valid sample of the entire Railbelt population, but enough feedback to assess community perspectives from a cross -section of stakeholders. Task 3: Organizational Work Sessions and “Going to the People” 1. Review the Beluga-Healy HVDC Line (and other ongoing Railbelt grid-modernization projects). Communicate what it encompasses, costs, projected timeline, and potential impacts. Identify stakeholders affected and their various value propositions. 2. Communicate how the public can learn more, track project progress, and how their feedback will be used. 3. Share success stories as well as lessons learned from other electrical infrastructure upgrades conducted on the Railbelt. 4. Present benefits and constraints of Alaska public contracting law. Solicit feedback on DEIA goals and commitments to workers. 5. Identify areas where stakeholders wish they had more data or information via questions like: “What should AEA consider that we haven't covered today?” “What information would you like to see at a future meeting?” “What additional questions do you have?” 6. Meeting minutes will be made public on the project website. Page 5 of 21 Task 4: Follow-up Work Sessions A second round of public meetfngs will be hosted by the four utflitfes as well as Alaska Energy Authority. Topics will include: Task 5: Public Participation Plan report (September-November 2024) Workforce and Community Agreements Agreement A: Overarching Memorandum of Agreement with participating Tribal Councils for ANVSAs on the Railbelt 1. Work sessions with relevant organizations will be conducted, including those organizations listed in B1 with whom preliminary contact has already been made. Engagement with these groups will guide project design and implementation. Discussion topics to include: environmental impacts (particularly around transmission line easements through Denali State Park and Denali National Park), viewshed impacts, subsistence impacts, state and federal land management, Power Cost Equalization, workforce development (including apprenticeships), support for minority business enterprises, DEIA recruitment, DEIA workplace policies, and state legislation. 2. Additional AEA outreach will be conducted at existing meetings in each project area, such as: Tribal Council meetings, City Council meetings, and Chamber of Commerce lunches. AEA outreach will also be conducted in more informal settings to recruit a more diverse group o f stakeholders. AEA refers to this process as “G2P” or “going to the people.” Examples of events suitable for G2P include, but are not limited to: Alaska Federation of Natives convention, Alaska Black Caucus Sunday night Zoom meetings, Alaska State Fair, community farmers’ markets, Juneteenth programming, Alaska Federation of Filipino Americans programming, Sportsman shows, music festivals, and more. Events may vary from community to community. At least one informal event will be hosted/attended in Healy, the northern terminus of the line. 1. Recap project purpose, goals, and timeline. 2. Themes and key takeaways from intro work sessions, one -on-one organizational meetings, G2P events, and survey results. 3. Have stations set up around different topics: people can walk from station to station to learn about different elements of the project (DEIA goals, labor commitments, environmental impacts, employment opportunities, homeowner impacts, etc.), and ask questions of project staff about specific areas they are interested in. 4. Request for additional feedback or concerns not captured thus far. 5. Minutes from this meeting will be posted to the project website. 1. Public Participation Plan Report published by AEA, along with memo in response, summarizing and responding to comments. Page 6 of 21 Agreement Summary: This single MOA, ratified by multiple Tribal councils, will outline criteria for a robust public engagement process as well as targeted recruiting of Alaskan Native people for apprenticeship and internship opportunities in clean energy. This includes apprenticeships for construction work and access to “job pipelines” for long-term employment maintaining local electrical infrastructure. Scope: A single overarching MOA will be established with participating Tribal councils. These can include but are not limited to: Cantwell ANVSA, Chickaloon ANVSA, Chitfna ANVSA, Copper Center ANVSA, Eklutna ANVSA, Gakona ANVSA, Gulkana ANVSA, Kenaitze ANVSA, Knik ANVSA, Nanwalek ANVSA, Nenana ANVSA, Ninilchik ANVSA, Northway ANVSA, Port Graham ANVSA, Seldovia ANVSA, Tanacross ANVSA, Tazlina ANVSA. Budget Period to be completed: Budget period 1. Milestones with timelines: Milestones include one on one organizational meetings with select Tribal Councils to draft a Tribal MOA for the project, this MOA appearing on Tribal Council agendas, and being ratified (with revisions as needed) by various Tribal Councils within the first budget period of the project. Agreement B: Collective Bargaining Agreements with Utilities Agreement Summary: The four utilities included in this project currently maintain collective bargaining agreements (CBA) with 659 of 1,071 (62%) total employees. Alaska is not a Right to Work state; utflity employees whose positfons are covered by bargaining unit agreements are required to join unions consistent with those agreements. The Railbelt utflitfes have used project labor agreements in the past for projects of this scale, such as constructfon of the Alaska Intertfe. Each of the utflitfes has CBAs with IBEW 1547, among other unions. AEA and the four utflitfes in this project intend to engage labor partners early to initfate discussions around labor agreements, local and targeted hiring goals, card-check neutrality, and programs to attract, train, and retain new workers. HR directors at these utflitfes confirmed that their organizatfons have plans in place that minimize the risk of labor disputes via contracts with “appropriate grievance resolutfon stfpulatfons”2 and a staffed positfon of “Labor Relatfons Program Manager.”3 Melinda Taylor, Communicatfons Director at IBEW 1547, wrote: “we would generally consider our relatfonship with each utflity to be positfve. We work well with each of these utflitfes and understand that the success of our membership is tfed to the success of each utflity. Because we have separate collectfve bargaining agreements with each utflity (some of these utflitfes have multfple CBAs), the applicable work rules and expectatfons are much clearer than if there were no CBA in place. For these reasons, we believe that the IBEW is well-positfoned to 2 Email correspondence between Reagan M. Russell, RMRussel@gvea.com, Human Resources at Golden Valley Electric Associatfon, and Clare Boersma, clareboersma@northerncompassgroup.com, Monday, March 6, 2023, 10:39 AM. 3 Email correspondence between Justfn Patterson, justfn.patterson@mea.coop, Human Resources at Matanuska Electric Associatfon, and Clare Boersma, clareboersma@northerncompassgroup.com, Monday, March 9, 2023, 3:27 PM. Page 7 of 21 maintain strong labor relatfons with our partner utflitfes throughout any Railbelt grid modernizatfon and revitalizatfon projects.”4 AEA and Railbelt utflitfes intend to maintain these CBAs for existfng employees throughout the project lifespan. Scope: 659 employees at GVEA, MEA, CEA, and HEA covered under CBAs. Budget Period to be completed: Budget period 1, 2, 3, and 4. Milestones with timelines: Existing. Agreement C: Alaska Public Contracting Law Agreement Summary: Alaska Public Contracting Law contains provisions for preference in hiring Alaskan-owned corporatfons, reductfon in barriers to Natfve Alaskans seeking apprentfceship training, local hiring preference, prevailing wages, and other forward-looking policies. Scope: AEA commits to completing all work done with GRIP funds in compliance with Federal Laws and Alaska Public Contracting Law. Budget Period to be completed: Budget period 1, 2. Milestones with timelines: RFP in alignment with all federal laws and Alaska Public Contracting Law issued for contractor to complete project scope of work in Budget Period 2. RFP in alignment with Alaska Public Contracting Law awarded for contractor to complete project scope of work. 3. Other Community and Labor Engagement Goals, Commitments, and Milestones The contractor hired to complete the Public Partfcipatfon Plan included in this Community Benefits Plan will issue a Public Partfcipatfon Plan report to AEA that summarizes key themes and concerns related to the project, as well as meetfng minutes from all public meetfngs and one-on-one organizatfonal meetfngs. This report will be made public on the project website alongside a public memo responding to the report from AEA. The memo will respond to themes and concerns surfaced during the engagement process and detail what changes to the project will be made to improve project outcomes and stakeholder contentment (in alignment with the awarded grant agreement). The transparency of this process ensures that AEA is accountable for responding to and addressing any significant concerns over project implementatfon. B. Investing in Job Quality and Workforce Continuity This project will retain high-quality jobs at all four Railbelt utflitfes by creatfng new infrastructure that will require operatfon and maintenance for the next 25 years. The average wage of a journeyman lineman at these utflitfes ranges from $54.40 to $58.00 an hour and includes employer-sponsored benefits (medical, 4 Email correspondence between Melinda Taylor, mtaylor@ibew1547.org, Communicatfons Director IBEW 1547, and Clare Boersma, clareboersma@northerncompassgroup.com, Tuesday, March 7, 2023, 6:00 PM. Page 8 of 21 dental, vision, life insurance, defined contributfon retfrement, 401(k), pension, short-term disability, long/short-term disability, tuitfon reimbursement, paid tfme off, and paid holidays). Project employees will be dispatched by organized labor and benefit from registered apprentfceship programs represented by the Alaska Apprentfceship Training Coordinators Associatfon (AATCA). AEA will conduct work sessions with IBEW 1547 as part of the public partfcipatfon plan. AEA will attempt to establish an overarching MOA with partfcipatfng Tribal councils on the Railbelt and local governments to implement targeted recruitment of Alaskan Natfve workers, local preference policies for project constructfon and establish job pipelines to enable local workers to maintain this infrastructure critfcal to their communitfes. Support for Worker Organizing/Collective Bargaining 1. Worker Organizing and Collective Bargaining Commitment C1.1: The AEA commits to contfnue to engage labor partners early to initfate discussions around future contracts, local and targeted hiring goals, and programs to attract, train, and retain a skilled workforce. Commitment C1.2: AEA pledges to remain neutral during union organizing campaigns. Commitment C1.3: AEA seeks to enter into binding arbitratfon to settle contracts. Commitment C1.4: AEA pledges to allow union organizers access to appropriate onsite non-work spaces. Commitment C1.5: AEA pledges to refrain from holding captfve audience meetfngs Commitment C1.6: Other commitments or pledges: Each of the four utflitfes in this project pledges to maintain a collectfve bargaining agreement with their employees. 2. Union support IBEW 1547 and NECA have demonstrated support for this project. They have expressed their willingness to collaborate around workforce development opportunitfes and partfcipate in the public engagement process. 3. Job Quality and Workforce Continuity a. Ongoing Operations and Production Jobs Commitment C3a.1: The four utflitfes associated with this project will retain high-quality jobs at all four Railbelt utflitfes by creatfng new infrastructure that will require operatfon and maintenance for the next 25 years. The average wage of a journeyman lineman at these utflitfes ranges from $54.40 to $58.00 an hour with employer-sponsored benefits (medical, dental, vision, life insurance, defined contributfon retfrement, 401(k), pension, short-term disability, long/short-term disability, tuitfon reimbursement, paid tfme off, and paid holidays). Commitment C3a.2: AEA will provide workforce educatfon and training for project operators through existfng utflity training programs and partfcipatfon with programs offered through Alaska Apprentfceship Page 9 of 21 Training Coordinators Associatfon (AATCA). AATCA, composed of 16 different constructfon trades, is a member of the Alaska Works Partnership, a non-profit organizatfon focused solely on getting Alaskans into careers in the constructfon industry. Alaska Works is jointly funded by the U.S. Department of Labor, the Alaska Department of Labor and Workforce Development, the Alaska Department of Transportatfon & Public Facilitfes, and the North American Building Trades Unions. Commitment C3a.3: AEA will ensure workers are engaged in the design and implementatfon of workplace safety and health plans. The existfng collectfve bargaining agreements establish Safety Committees at each of the utflitfes; contracted employees will have the same access to safety protocols on all work sites in additfon to local dispatch protocols. Employees who join the committee will be paid their normal hourly rate for their partfcipatfon on the committee. Committee members will be enrolled in mandatory worksite safety analysis, hazard preventfon and control, safety and health training, antf- harassment and by-stander interventfon training to give them an understanding of best practfces to inform their recommendatfons as further described in CBAs. b. Construction Jobs Commitment C3b.1 This project is projected to create approximately 100 new constructfon jobs. These jobs will receive competftfve wage and benefit rates benchmarked against local Davis Bacon prevailing wages. Commitment C3b.2 AEA will provide workforce educatfon and training for project constructfon employees through partfcipatfon with AATCA. By engaging registered apprentfces in this project, AEA is assured of accessing the resources brought to bear by the Alaska Works Partnership in support of local hire, veteran hire, and as diverse a workforce as Alaska has to offer. The utflizatfon of registered apprentfces will constftute approximately 15 percent of total project labor hours as prescribed in the Alaska Public Contractfng Law. Commitment C3b.3: Recipient will ensure the highest standards of constructfon site health and safety, including a site free of harassment and discriminatfon, are met. This committee includes mandatory trainings in worksite analysis, hazard preventfon and control, safety and health training, and antf- harassment training. C. Diversity, Equity, Inclusion, and Accessibility Alaska Energy Authority plans to incorporate DEIA objectfves into the project through the following means: 1. Work performed with GRIP funding will be done in compliance with Alaska Public Contractfng Law, which contains provisions for preference of local hire, apprentfceship training, prevailing wages, and other forward-looking policies. 2. Project is subject to the Office of Federal Contract Compliance Programs’ requirements for hiring and adheres to an Affirmatfve Actfon Plan. 3. Affirmatfve actfon and antf-bias training for project hires and project Health and Safety Committee members. 4. Partnership with IBEW-NECA Alaska Joint Electrical Apprentfceship and Training Trust (AJEATT) and individual utflity training programs for apprentfceship and internship programs. Page 10 of 21 5. Work sessions with the AJEATT will assess how apprentfceship programs serve workers facing systemic barriers to employment, and how to reduce those barriers through project implementatfon. Findings to be included in public partfcipatfon report. 6. Collect and monitor data on workforce veteran status, ethnicity, gender, and disability status through project implementatfon to ensure a diverse and inclusive workforce. This data will be made public on the project webpage. 7. Conduct one-on-one work sessions with organizatfons representfng ANVSAs and DACs potentfally affected by the project. Commitment C1. AEA commits to leveraging local hiring preference in Alaska public contractfng law to hire a local workforce that is as diverse as possible. Per state statute, work completed by AEA must be done in compliance with Alaska public contractfng law. Alaska public contractfng law does not allow for hiring preference specifically for economically disadvantaged minority residents, however it does include provisions for local hiring preference which may be utflized in project areas proximate to ANVSAs to create a more diverse workforce. Commitment C1.2 Per sectfon 36.10.040 of Alaska Public Contractfng law, AEA commits to adhere to all federal statutes giving preference to veterans or prohibitfng other preferences or discriminatfons among Alaskan Natfve people and United States citfzens. Commitment C1.3 AEA commits to leveraging local hiring preference in Alaska public contractfng law to hire a local workforce that is as sexually equitable as possible. Commitment C2 AEA commits to conductfng work sessions with the Alaska Joint Electrical Apprentfceship & Training Trust (AJEATT) to assess how apprentfceship programs serve workers facing systemic barriers to employment, and how to reduce those barriers through project implementatfon. The minutes from these meetfngs will be made public on the project website. Commitment C2.1 The project team will pursue a single overarching Memoranda of Agreement (MOA) with partfcipatfng Tribal governments in ANVSAs on the Railbelt to promote local hiring and create meaningful engagement. Commitment C2.3 The public partfcipatfon plan outreach materials will be piloted with focus groups composed of diverse partfcipants to evaluate their effectfveness in recruitfng diverse stakeholders to partfcipate in the Public Partfcipatfon Plan. Commitment C2.4 The Public Partfcipatfon Plan will include a “G2P” or “Going to the People” outreach component focused on recruitfng diverse populatfons to partfcipate in the engagement process. Project representatfves will staff informatfonal booths at public events such as Juneteenth programming, Alaska Federatfon of Natfves Conventfon, the Alaska State Fair, and more. Project partners will help identffy events that will reach a diversity of audiences from across the project area. These events will—when possible—focus on high-impact project areas, such as Healy, where the line will be terminated. D. Justice40 Initiative D.1. A decrease in energy burden (energy costs for low-income households) Page 11 of 21 The Beluga-Healy HVDC line, which is a part of the Railbelt’s larger Grid Modernizatfon and Resiliency Plan (GMRP), is antfcipated to provide significant benefits to Alaskan DACs both on and off the Railbelt. There are 22 census tracts that qualify as disadvantaged5 on the Railbelt, with a combined populatfon of 81,921.6 There are 17 ANVSAs on the Railbelt,7 with a combined populatfon of 160,486. All of these communitfes will receive direct benefits from the Beluga-Healy HVDC Line via long-term reductfon of their energy cost burdens. Railbelt engineers believe Beluga-Healy HVDC line, in conjunctfon with other grid upgrades, will result in decreased line losses and reduced reserves, due to increased transfer capability and improved economic dispatch leading to reduced thermal spending of 10-15%.8 Because the utflitfes are member-owned, these savings will translate to reduced consumer costs. The Railbelt’s 260,0009 residentfal utflity accounts serve 623,916 individuals,10 242,407 (39%) of whom live in a DAC or ANVSA. AEA engineers project that GMRP’s overall fuel savings could result in a reductfon of 0.5 cents/kWh to 1.5 cents/kWh for users. The combined Railbelt utflitfes sold 4,408 GWh (Gigawatt-Hours) in 2020,11 suggestfng total savings of $44,080,000 for a one cent per kWh cost reductfon. Much of this antfcipated $44 million in annual savings will be passed through to member- owners; as a percentage of populatfon served, 39% of these savings will flow to those who live in a DAC or ANVSA. A unique feature of the Beluga-Healy HVDC line as a component of the GMRP is that it will also have significant economic impacts outside of the Railbelt due to Alaska’s Power Cost Equalizatfon program (PCE). The PCE program was established in 1985 to provide economic assistance to residents and community facilitfes in rural Alaska, where electricity rates can be two to five tfmes higher than in more populated areas. The primary beneficiaries of PCE are residentfal customers, who are eligible for subsidy of actual consumptfon up to 750 kWh. If a household uses more than 750 kWh of electricity in a given month, the amount used above 750 kWh is not subsidized. Community facilitfes are also eligible for actual consumptfon up to 70 kWh per month per community resident. AEA administers the PCE program by making payments directly to individual utflitfes enrolled in the program who then pass the benefits on to qualified customers. The PCE program is funded by earnings of the PCE Endowment Fund. Alaska Statute 42.45.085 provides that five percent of the PCE Endowment Fund’s three-year monthly average market value may be appropriated to the PCE Program. In recent years, the five percent draw on the endowment has been sufficient to fully fund PCE payments. By decreasing (or incrementally reducing over the long-term) electricity rates in Anchorage and Fairbanks, PCE credit for eligible communitfes and residents will increase compared to baseline. In FY22 PCE served 188 communitfes, 15412 (82%) of whom qualify as DACs or ANVSAs. Approximately 108,914,53013 of PCE-eligible kWh were produced between 5 DOE Disadvantaged Communitfes Reporter 6 American Community Survey 2021 5 Year Populatfon Estfmates 7 2020 U.S. Census, DOE Disadvantaged Communitfes Reporter 8 Brian Hickey, Project Lead, P.E., PMP., Brian.Hickey@mea.coop, Zoom, 8:00-8:30 am, March 1st, 2023. 9 Summed from: Homer Electric Associatfon, Golden Valley Electric Associatfon, Chugach Electric Associatfon Inc., Matanuska Electric Associatfon, Inc. 10 Alaska Department of Labor and Workforce Development, Research and Analysis Sectfon. 11 U.S. Energy Informatfon Administratfon, 2020 12 https://www.energy.gov/diversity/justfce40-initfatfve 13 FY22 PCE Community Report.pdf (akenergyauthority.org) Page 12 of 21 residentfal and community facilitfes in those 154 DACs. At a one cent decrease in the average class rate, the increased credit amount that would be issued by AEA to PCE-enrolled DACs is $1,089,145.14 In sum: GMRP and the Beluga-Healy HVDC Line’s projected one cent/kWh reductfon in energy costs for users is calculated to result in $44,080,000 in reduced energy burdens for on-Railbelt electricity users, 39% of whom belong to DACs or live in ANVSAs. Through AEA’s power-cost-equalizatfon program, that same one cent/kWh reductfon in on-Railbelt energy costs is antfcipated to result in an additfonal $1,329,60615 in PCE subsidies to off-Railbelt communitfes, 82% of which will flow to DACs or ANVSAs. Taken together, this reduced energy burden for on-Railbelt residents and increased PCE subsidy for off- Railbelt residents represents cumulatfve annual benefits to DACs or ANVSAs of $18,215,330, or slightly over 40% of a calculated $45,409,606 in total annual benefits. Benefit D1.1: Increased PCE credit for 154 off-Railbelt DACs  154 DACs and/or ANVSAs will benefit from increased PCE credits.  The benefit will be delivered via off-Railbelt utflitfes, including Alaska Village Electric Cooperatfve.  When benefit will be delivered: Benefits will be delivered after project completfon in year 2034.  Milestones toward benefit delivery: Project close out.  Metrics to track and report on benefits: AEA Power Cost Equalizatfon Program annual report allows for the calculatfon of the delta in PCE credits to DACs pre-and-post project completfon.  Unantfcipated barriers and strategies to address barriers: These projectfons rely on reduced thermal spending and line loss cost reductfons being passed through from utflity operatfons to electric co-operatfve member-owners in the form of reduced rates. Rate setting for public utflitfes is complicated and includes many factors other than thermal spending; exact cost savings are therefore difficult to predict, but the project is, at the very least, antfcipated to keep Railbelt electricity rates lower for longer, and increase PCE credits versus baseline.  Community-based organizatfon(s) involved in identffying or negotfatfng benefit or developing plan for benefit delivery: Power Cost Equalizatfon is stfpulated by Alaska Statute 44.83.940. D.2. A decrease in environmental exposure and burdens Benefit D2.1: This work is projected to result in long-term increased integratfon of renewables in the Railbelt grid by improving economy of scale. Such integratfon would reduce emissions from power generatfon from coal and natural gas. Although woodstoves result in the majority of PM2.5 partfculate contaminatfon throughout interior Alaska, this project’s projected reduced thermal spending via increased renewables can be reasonably assumed to have air quality benefits, especially for the community of Healy (located 14 Actual savings would be less than this, since Juneau, which is outside the Railbelt, is included in the “Average Class Rate”, and their rates would not be affected by thermal spending reductfons from GMRP. It should also be noted that PCE payments received by a partfcular utflity are not uniformly distributed and will vary from year-to- year based on the utflitfes’ energy cost reportfng. 15 FY22 PCE Community Report.pdf (akenergyauthority.org) Page 13 of 21 within Denali Borough—a DAC), which is home to a coal power plant with a peak generatfon capacity of 92.8 MW. D.3. An increase in quality job creation, the clean energy job pipeline, and job training for individuals All procurement will comply with Alaska public contractfng law, which contains provisions for local hire, apprentfceship training, prevailing wages, and other forward-looking policies. The project will partner with IBEW-NECA Alaska Joint Electrical Apprentfceship and Training Trust (AJEATT) and others to source candidates and ensure the development of a skilled, inclusive local workforce. 10-15 new permanent positfons will be created through the Beluga-Healy HVDC line for maintenance and operatfons of the new infrastructure. Benefit D3.1: The project intends to develop an overarching Memoranda of Agreement (MOA) with partfcipatfng Tribal Councils on the Railbelt to promote local hiring and creatfng meaningful engagement. D.5. Increases in energy democracy, including community ownership of project assets Benefit D5.1: All four electric utflitfes included in this project are member-owned cooperatfves; therefore, the electrical infrastructure for most of the communitfes affected by this project is already owned by the residents who live in those communitfes. One meaningful way this project will forward energy democracy goals is by designing a training-to- careers pipeline to recruit and train individuals to maintain the energy infrastructure on which their own communitfes rely. AEA believes that communitfes are strongest when they are meaningfully engaged in the maintenance and operatfons of their energy infrastructure, and the labor goals of this project are designed to train individuals—including Tribal members—to gain the skills necessary to maintain local electrical infrastructure and create a citfzenry who not only can repair and maintain their electrical infrastructure, but who are also sufficiently knowledgeable about that infrastructure that they are able to guide their communitfes in decisions about its future. D.6. Increased parity in clean energy technology access and adoption Benefit D6.1: The project seeks to build a resilient, clean, smart electrical grid in Alaska. Increased transfer capacity between regions will enable higher renewable energy integratfon and a reductfon in fossil fuel generatfon and associated emissions. A recent report from the Denver-based Natfonal Renewable Energy Laboratory said that getting to 75% renewable energy on the Railbelt by 2040 could be the lowest-cost energy optfon for Southcentral Alaska. The study estfmates that $100 million in annual savings could be realized if that 2040 target was met when compared to a scenario with no new renewable energy investment. That transitfon is only feasible with the transmission upgrades made possible through this project. The Beluga-Healy HVDC line is a critfcal link in bringing clean energy technology to the 242,407 individuals who live in the DACs and ANVSAs on the Railbelt. Page 14 of 21 D.7. An increase in energy resilience Benefit D7.1: The Railbelt region is home to some of the harshest conditfons on earth, making grid resilience a top priority. Past disasters include earthquakes, avalanches, forest fires, and landslides, which have left communitfes isolated and without power for days. 26% of Railbelt customers live in ANVSAs, many of which are in remote areas with energy infrastructure that is aging and partfcularly vulnerable to natural disaster. Increased grid resiliency is a primary goal of this project. The interregional transmission line that will be installed parallel to the line that currently tfes together the Railbelt’s Southern and Central regions will allow for contfnued energy transmission between regions in the event of a major natural disaster. Additfonal resilience benefits include right-of-way clearing, aerial inspectfons, and refurbishment of existfng lines and structures. D.8. Anticipated or potential negative environmental impacts There are potentfal viewshed impacts near Denali State Park and Denali Natfonal Park. A robust and early stakeholder engagement plan will assess both public and agency desires and tolerances. The project will build in contfngencies/optfons such as using innovatfve advanced conductors to minimize conductor size and spacing, potentfally undergrounding some portfons of the line, or routfng the line around the state and natfonal parks, to ensure that a cost-effectfve and publicly acceptable outcome is reached. D. Summary Table: Community Benefits Outcomes and Objectives Category and Commitment Existing or Planned Budget period 1 Budget period 2 Budget period 3 Budget period 4 Community and Labor Engagement Issue RFP and select contractor to assist with public partfcipatfon plan. Planned X Draft stakeholder engagement strategies and outreach media. Planned A focus group will be used to test the effectfveness of these materials on diverse populatfons. Launch RIR website with public meetfng schedule, project descriptfon, ArcGIS Online mapping tool, and public comment sectfon. Planned X Each (4) utflity provider and AEA hosts introductory public work session. Planned X Page 15 of 21 Conduct surveys to address data gaps identffied during introductory public work sessions. Planned X One-on-one work sessions with relevant organizatfons, including Tribes and DACs. Planned & Existfng Contact already made with: Alaska Federatfon of Natfves, Alaska Village Electric Cooperatfve, Alaska Black Caucus, Alaska Municipal League, IBEW Local 1547, Internatfonal Union of Operatfng Engineers (IUOE) Local 302, Alaska Operatfng Engineers Training Trust, Alaska Joint Electrical Apprentfceship & Training Trust, Fairbanks Chamber of Commerce, Alaska AFL-CIO, Anchorage Economic Development Corporatfon. Joint meetfng(s) with all relevant agencies re: viewshed and wildlife impacts from transmission line easement through Denali state and Natfonal Parks. Planned X “Going to the people” outreach conducted in more informal settings to recruit diverse group of stakeholders, including outreach event in Healy. Planned Outreach conducted at minimum of 3 public events designed to reach diverse/relevant audiences: (Alaska Federatfon of Natfves conventfon, Alaska Black Caucus Sunday Page 16 of 21 night Zoom meetfngs, Alaska State Fair, etc.) One event to be located in Healy. Each (4) utflity provider as well as Alaska Energy Authority hosts second public work session. Survey results shared as well as public comment themes to-date. Planned X RIR public partfcipatfon plan report published by AEA, along with memo in response, summarizing and responding to comments. Planned X Investing in Job Quality and Workforce Continuity Total Number of Permanent Operatfons Jobs: 659 Number of Constructfon phase jobs: 100 Number of new permanent positfons: 15 Retain high-quality jobs (the average wage of a journeyman lineman at these utflitfes ranges from $54.40 to $58.00 an hour) with employer-sponsored benefits (medical, dental, vision, life insurance, defined contributfon retfrement, 401(k), pension, short-term disability, long/short-term disability, tuitfon reimbursement, paid tfme off, and paid holidays) at all four Railbelt utflitfes by creatfng new infrastructure that will require operatfon and maintenance for the next 25 years. 659 existfng jobs under CBAs X X X X AEA will conduct work sessions with IBEW Local 1547 as part of public partfcipatfon plan. Planned X AEA will attempt to establish overarching MOA with Planned X X Page 17 of 21 partfcipatfng Railbelt Tribes and local governments to implement targeted recruitment strategies for RIR projects. Support for Worker Organizing/Collectfve Bargaining ☒ Pledge to remain neutral during any union organizing campaigns ☒ Intentfon to enter into binding arbitratfon to settle first contracts ☒ Pledge to allow union organizers access to appropriate onsite non-work spaces (e.g. lunch rooms) ☒ Pledge to refrain from holding captfve audience meetfngs X X X X Diversity, Equity, Inclusion, and Accessibility ☒ Local and/or targeted recruitment efforts ☒ Partner with quality pre- apprentfceship or apprentfceship readiness program AEA commitment that work performed with GRIP funding will be done in compliance with Alaska public contractfng law, which contains provisions for local hire preference, apprentfceship training, prevailing wages, and other forward-looking policies. Existfng X X X X Project is subject to the Office of Federal Contract Compliance Programs’ requirements for hiring and adhering to an Affirmatfve Actfon Plan. Existfng X X X X Affirmatfve actfon and antf-bias trainings for project hirers. Planned X X X Partnership with IBEW-NECA Alaska Joint Electrical Apprentfceship and Existfng X X X X Page 18 of 21 Training Trust and individual utflity training programs Work sessions with the Alaska Joint Electrical Apprentfceship & Training Trust (AJEATT) and others will assess how these apprentfceship programs serve workers facing systemic barriers to employment, and how to reduce those barriers through GMRP implementatfon. Findings to be included in public partfcipatfon report. Planned X X Collect data on workforce veteran status, ethnicity, gender, and disability status through GMRP implementatfon. Make data public on project website. Planned X X X Conduct work sessions with organizatfons representfng DACs affected by project, including tribal councils, Alaska Black Caucus, and Alaska Federatfon of Natfves, to understand desired benefits and reduced impacts. Minutes included in public partfcipatfon plan report. Planned X Develop MOAs with partfcipatfng, affected/on-Railbelt Tribes to ensure a clear framework for promotfng local hiring and creatfng meaningful engagement. Planned X X Justice40 Initiative AEA will offer to convene a joint meetfng with Alaska Department of Fish and Game, Natfonal Marine Fisheries Service, and Kenaitze and Knik Tribal Councils (to be invited – others may be included as well) to discuss how to minimize adverse environmental impacts re: placement of HVDC cable across Cook Inlet. Minutes included in public partfcipatfon plan report. Planned X Beluga-Healy HVDC Line will increase transfer capacity between the three Railbelt regions, paving the way for development of clean Projected Page 19 of 21 energy solutfons that will mitfgate environmental impacts from 3,218 natural-gas-produced GWh on Railbelt each year, resultfng in 1.61 billion kilograms of carbon dioxide equivalent. Beluga-Healy HVDC line, in conjunctfon with other grid upgrades, will result in decreased line losses and reduced reserves, due to increased transfer capability and improved economic dispatch leading to reduced thermal spending reductfons of 10-15%, representfng a non-cumulatfve decrease of over 200 million kilograms carbon dioxide equivalent per year. Projected Railbelt’s 260,000 residentfal utflity accounts serve 623,916 individuals, 242,407 (39%) of whom live in a DAC or on in ANVSAs. AEA engineers project RIR (including the Beluga-Healy HVDC line) overall fuel savings could result in a reductfon of 0.5 cents/kWh to 1.5 cents/kWh. The combined Railbelt utflitfes sold 4,408 GWh (Gigawatt- Hours) in 2020, suggestfng total savings of $44,080,000 for a 1 cent per kWh cost reductfon. Much of these $44 million in annual savings should pass through to member- owners. Projected In FY22 PCE served 188 communitfes, 154 (82%) of whom qualify as DACs or ANVSAs. Approximately 108,914,530 of PCE- eligible kWh were produced between residentfal and community facilitfes in those 154 DACs. At a one cent decrease in the average class rate, the increased credit amount that would be issued by AEA to PCE-enrolled DACs is $1,089,145. Projected 26% of Railbelt customers live in an Alaska Natfve Village Statfstfcal Planned x Page 20 of 21 Area (ANVSA), many of which are located in remote areas with energy infrastructure that is partfcularly vulnerable to natural disaster. Increased grid resiliency is a primary goal of this project, best embodied by the interregional transmission line that will be installed parallel to the line that currently tfes together the Railbelt’s Southern and Central regions, and which will allow for contfnued energy transmission between regions in the event of a major natural disaster. Build pipeline from apprentfceships and internships in remote communitfes into careers working on Railbelt grid. Beluga-Healy HVDC line will create high-paying jobs for members of DACs who live along the Railbelt by collaboratfng with IBEW-NECA Alaska Joint Electrical Apprentfceship and Training Trust, individual utflity training programs, and local colleges and potentfally the University of Alaska System. Planned Identffies benefits/impacts to disadvantaged communitfes ☒ Yes Including, Cantwell ANVSA, Chickaloon ANVSA, Chitfna ANVSA, Copper Center ANVSA, Eklutna ANVSA, Gakona ANVSA, Gulkana ANVSA, Kenaitze ANVSA, Knik ANVSA, Nanwalek ANVSA, Nenana ANVSA, Ninilchik ANVSA, Northway ANVSA, Port Graham ANVSA, Seldovia ANVSA, Tanacross ANVSA, Tazlina ANVSA) ☐ No Page 21 of 21 Reductfon in energy costs ☒ Yes ☐ No A decrease in environmental exposure and burdens ☒ Yes ☐ No An increase in quality job creatfon, the clean energy job pipeline, and job training for individuals ☒ Yes ☐ No X X X Increases in clean energy enterprise creatfon and contractfng (e.g., minority-owned or diverse business enterprises) ☐ Yes ☒ No An increase in energy resilience ☒ Yes ☐ No Resilience benefits include right of way clearing, aerial inspectfons, and refurbishment of existfng lines and structures. X X Award Number:Award Recipient:Alaska Energy Authority(May be award recipient or sub-recipient)Section A - Budget SummaryFederal Cost Share Total Costs Cost Share % Proposed Budget Period DatesBudget Period 1$40,098,443 $40,098,443 $80,196,886 50.00% 07/01/2024 - 06/30/2026Budget Period 2$91,198,443 $91,198,443 $182,396,887 50.00% 07/01/2026 - 06/30/2028Budget Period 3$125,100,000 $125,100,000 $250,200,000 50.00% 07/0/2028 - 06/30/2030Budget Period 4$108,421,795 $108,421,795 $216,843,591 50.00% 07/01/2030 - 06/30/2032Budget Period 5$0 $0 $0 0.00%Total$364,818,682 $364,818,682 $729,637,364 50.00%Section B - Budget CategoriesCATEGORY Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Total Costs % of Project Comments (as needed)a. Personnel$1,536,321 $1,597,774 $1,661,685 $1,728,152 $0 $6,523,932 0.89%b. Fringe Benefits$1,082,019 $1,125,300 $1,170,312 $1,217,124 $0 $4,594,756 0.63%c. Travel$75,600 $79,380 $83,349 $87,516 $0 $325,845 0.04% DNI Travel related to the CBPd. Equipment$80,000 $0 $80,000 $0 $0 $160,000 0.02%e. Supplies$80,000 $84,000 $88,200 $92,610 $0 $344,810 0.05%f. ContractualSub-recipient$0 $0 $0 $0 $0 $0 0.00%Contractor$2,798,000 $2,708,000 $2,558,000 $2,528,000 $0 $10,592,000 1.45%FFRDC$0 $0 $0 $0 $0 $0 0.00%Total Contractual $2,798,000 $2,708,000 $2,558,000 $2,528,000 $0 $10,592,000 1.45%g. Construction$72,770,283 $175,020,599 $242,787,102 $209,389,578 $0 $699,967,562 95.93%h. Other Direct Costs$0 $0 $0 $0 $0 $0 0.00%Total Direct Costs$78,422,223 $180,615,053 $248,428,648 $215,042,981 $0 $722,508,906 99.02%i. Indirect Charges$1,774,663 $1,781,834 $1,771,352 $1,800,609 $0 $7,128,458 0.98%Total Costs$80,196,886 $182,396,887 $250,200,000 $216,843,591 $0 $729,637,364 100.00%Benefit Budget $                156,410  $        729,793,774 1. If using this form for award application, negotiation, or budget revision, fill out the blank white cells in workbook tabs a. through j. with total project costs. 2. Blue colored cells contain instructions, headers, or summary calculations and should not be modified. Only blank white cells should be populated. 3. Enter detailed support for the project costs identified for each Category line item within each worksheet tab to autopopulate the summary tab. 4. The total budget presented on tabs a. through i. must include both Federal (DOE) and Non-Federal (cost share) portions.5. All costs incurred by the preparer's sub-recipients, contractors, and Federal Research and Development Centers (FFRDCs), should be entered only in section f. Contractual. All other sections are for the costs of the preparer only.6. Ensure all entered costs are allowable, allocable, and reasonable in accordance with the administrative requirements prescribed in 2 CFR 200, and the applicable cost principles for each entity type: FAR Part 31 for For-Profit entities; and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities. 7. Add rows as needed throughout tabs a. through j. If rows are added, formulas/calculations may need to be adjusted by the preparer. Do not add rows to the Instructions and Summary tab. If your project contains more than five budget periods, consult your DOE contact before adding additional budget period rows and columns.8. ALL budget period cost categories are rounded to the nearest dollar.BURDEN DISCLOSURE STATEMENTPublic reporting burden for this collection of information is estimated to average 24 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden, to Office of Information Resources Management Policy, Plans, and Oversight, AD-241-2 - GTN, Paperwork Reduction Project (1910-5162), U.S. Department of Energy 1000 Independence Avenue, S.W., Washington, DC 20585; and to the Office of Management and Budget, Paperwork Reduction Project (1910-5162), Washington, DC 20503.SUMMARY OF BUDGET CATEGORY COSTS PROPOSEDThe values in this summary table are from entries made in subsequent tabs, only blank white cells require data entryAdditional Explanation (as needed):Please read the instructions on each worksheet tab before starting. If you have any questions, please ask your DOE contact! Do not modify this template or any cells for formulas!Instructions and SummaryDate of Submission:Alaska Energy AuthorityForm submitted by: Personnel Cost using Loaded Rate:*apply 4% increase per budget period to account for merit based increases per state's salary schedule; increase in leave accrual based on longevity; and benefit cost increases.  Position Title % Hrs/yrBiannual HrsRate Period 1 Budget Period 1Rate Period 2 Budget Period 2Rate Period 3 Budget Period 3Rate Period 4 Budget Period 4 Total* 104.00% * 104.00% * 104.00%1 Contracting Officer 20% 390 780 89.88$    70,102.97$           93.47$    72,907.00$           97.21$    75,823.00$           101.10$  78,856.00$           297,688.97$             2 Executive Director 10% 195 390 183.59$  71,600.53$           190.93$  74,465.00$           198.57$  77,443.00$           206.52$  80,541.00$           304,049.53$             3 Communicaitons Director 20% 390 780 112.94$  88,096.22$           117.46$  91,620.00$           122.16$  95,285.00$           127.05$  99,096.00$           374,097.22$             4 GIS 15% 292.5 585 83.79$    49,014.57$           87.14$    50,975.00$           90.62$    53,014.00$           94.25$    55,135.00$           208,138.57$             5 Owned Assets Director 20% 390 780 165.94$  129,432.18$         172.58$  134,609.00$         179.48$  139,994.00$         186.66$  145,594.00$         549,629.18$             6 Senior Infrastructure Engineer 100% 1950 3900 111.09$  433,269.31$         115.54$  450,600.00$         120.16$  468,624.00$         124.97$  487,369.00$         1,839,862.31$         7 Infrastructure Engineer 20% 390 780 104.63$  81,607.83$           108.81$  84,872.00$           113.16$  88,267.00$           117.69$  91,798.00$           346,544.83$             8 Federal Project Manager 100% 1950 3900 152.99$  596,670.13$         159.11$  620,537.00$         165.48$  645,358.00$         172.10$  671,173.00$         2,533,738.13$         9 Environmental Engineer 80% 1560 3120 152.99$  477,336.10$         159.11$  496,430.00$         165.48$  516,287.00$         172.10$  536,938.00$         2,026,991.10$         10 Program Controls 100% 1950 3900 106.19$  414,140.35$         110.44$  430,706.00$         114.85$  447,934.00$         119.45$  465,852.00$         1,758,632.35$         11 Program Project Manager 50% 975 1950 106.19$  207,070.17$         110.44$  215,353.00$         114.85$  223,967.00$         119.45$  232,926.00$         879,316.17$             ‐$                         ‐$                        2,618,340.36$      2,723,074.00$      2,831,996.00$      2,945,278.00$      11,118,688.36$       11,118,688.36$        Base, Release Time, Benefits break out26 pp year 11 holiday; 7.5 hr day                      1,950 25.10% 6.13% 1.45% 0.68%Position Title Annual Salary  Leave Accrual PP ‐ hrs  Annual Leave ‐ Hrs  Annual Holiday ‐ Hrs   Net Billable Hrs  Hourly Rate Based on 1950 hrs Annual Leave HolidayRelease TimeHealth Ins (1,793 mo.)PERS RetirementSupplemental Benefits (in lieu of social security)MEDC WC BenefitsLoaded Labor RateContracting Officer 97,598.00       6.92              179.92          82.50            1,687.58         50.05           5.34            2.45            7.78         12.75      14.52         3.55 0.84 0.39 32.04 89.88          Executive Director 209,997.00     8.65              224.90          82.50            1,642.60         107.69        14.74          5.41            20.15      13.10      32.09         7.84 1.85 0.87 55.75 183.59       Communication Director 126,789.00     6.92              179.92          82.50            1,687.58         65.02           6.93            3.18            10.11      12.75      18.86         4.61 1.09 0.51 37.81 112.94       GIS 91,280.00       6.07              157.82          82.50            1,709.68         46.81           4.32            2.26            6.58         12.58      13.40         3.27 0.77 0.36 30.40 83.79          Owned Assets Director 182,657.00     10.38            269.88          82.50            1,597.62         93.67           15.82          4.84            20.66      13.47      28.70         7.01 1.66 0.78 51.61 165.94       Senior Infrastructure Engineer 124,449.00     6.92              179.92          82.50            1,687.58         63.82           6.80            3.12            9.92         12.75      18.51         4.52 1.07 0.50 37.35 111.09       Infrastructure Engineer 118,000.00     6.07              157.82          82.50            1,709.68         60.51           5.59            2.92            8.51         12.58      17.32         4.23 1.00 0.47 35.61 104.63       Federal Project Manager 180,000.00     6.07              157.82          82.50            1,709.68         92.31           8.52            4.45            12.98      12.58      26.43         6.45 1.53 0.72 47.71 152.99       Environmental Engineer 180,000.00     6.07              157.82          82.50            1,709.68         92.31           8.52            4.45            12.98      12.58      26.43         6.45 1.53 0.72 47.71 152.99       Program Project Manager 120,000.00     6.07              157.82          82.50            1,709.68         61.54           5.68            2.97            8.65         12.58      17.62         4.30 1.02 0.48 36.00 106.19       Program Project Manager 120,000.00     6.07              157.82          82.50            1,709.68         61.54           5.68            2.97            8.65         12.58      17.62         4.30 1.02 0.48 36.00 106.19       *apply 4% increase per budget period to account for merit based increases per state's salary schedule; increase in leave accrual based on longevity; and benefit cost increases.  Cost by Budget Period*: Bi‐Annual Hours  Bi‐Annual Salary  Leave + Holiday  Employer Paid Benefits  Total Budget Period 1  Total Budget Period 2  Total Budget Period 3  Total Budget Period 4 Contracting Officer 780      39,039.00    6,070.63       24,993.34    70,103            72,907        75,823        78,856        297,690  Executive Director 390      41,999.10    7,859.87       21,741.560  71,601            74,465        77,443        80,541        Communication Director 780      50,715.60    7,886.32       29,494.30    88,096            91,620        95,285        99,096        GIS 585      27,383.85    3,849.21       17,781.51    49,015            50,975        53,014        55,135        Owned Assets Director 780      73,062.60    16,115.14    40,254.44    129,432          134,609      139,994      145,594      Senior Infrastructure Engineer 3,900   248,898.00  38,703.83    145,667.48  433,269          450,600      468,624      487,369      Infrastructure Engineer 780      47,197.80    6,634.64       27,775.39    81,608            84,872        88,267        91,798        Federal Project Manager 3,900   360,009.00  50,603.15    186,057.98  596,670          620,537      645,358      671,173      Environmental Engineer 3,120   288,007.20  40,482.52    148,846.38  477,336          496,430      516,287      536,938      Program Controls 3,900   240,006.00  33,735.44    140,398.91  414,140          430,706      447,934      465,852      Program Project Manager 1,950   120,003.00  16,867.72    70,199.45    207,070          215,353      223,967      232,926      1,536,321    228,808        853,211        2,618,340      2,723,074   2,831,997  2,945,277  2,618,340            2,723,074        2,831,996       2,945,278       *apply 4% increase per budget period to account for merit based increases per state's salary sched‐                         (0.03)                0.93                (1.19)               Personnel Cost:  Budget Period 1  Budget Period 2  Budget Period 3  Budget Period 4  Total Contracting Officer 39,039            40,601          42,225          43,914          165,778          Executive Director 41,999            43,679          45,426          47,243          178,348          Communication Director 50,716            52,744          54,854          57,048          215,362          GIS 27,384            28,479          29,618          30,803          116,285          Owned Assets Director 73,063            75,985          79,025          82,185          310,258          Senior Infrastructure Engineer 248,898          258,854        269,208        279,976        1,056,936       Infrastructure Engineer 47,198            49,086          51,049          53,091          200,424          Federal Project Manager 360,009          374,409        389,386        404,961        1,528,765       Environmental Engineer 288,007          299,527        311,509        323,969        1,223,012       Program Controls 240,006          249,606        259,590        269,974        1,019,177       Program Project Manager 120,003          124,803        129,795        134,987        509,588          1,536,321       1,597,774    1,661,685    1,728,152    6,523,932      Fringe Benefit Cost:  Budget Period 1  Budget Period 2  Budget Period 3  Budget Period 4  Total Contracting Officer 31,064            32,307          33,599          34,943          131,912          Executive Director 29,601            30,785          32,017          33,298          125,701          Communication Director 37,381            38,876          40,431          42,048          158,735          GIS 21,631            22,496          23,396          24,332          91,854            Owned Assets Director 56,370            58,624          60,969          63,408          239,371          Senior Infrastructure Engineer 184,371          191,746        199,416        207,393        782,926          Infrastructure Engineer 34,410            35,786          37,218          38,707          146,121          Federal Project Manager 236,661          246,128        255,973        266,212        1,004,973       Environmental Engineer 189,329          196,902        204,778        212,969        803,978          Program Controls 174,134          181,100        188,344        195,877        739,455          Program Project Manager 87,067            90,550          94,172          97,939          369,728          1,082,019       1,125,300    1,170,312    1,217,124    4,594,756      2,618,340       2,723,074    2,831,997    2,945,277    11,118,688    x‐check2,618,340             2,723,074          2,831,996          2,945,278          11,118,688          ‐                         (0.03)                  0.93                   (1.19)                  (0.28)                     Personnel + Fringes Cost:  Budget Period 1  Budget Period 2  Budget Period 3  Budget Period 4  Total Contracting Officer 70,103            72,907          75,823          78,856          297,690          Executive Director 71,601            74,465          77,443          80,541          304,049          Communication Director 88,096            91,620          95,285          99,096          374,097          GIS 49,015            50,975          53,014          55,135          208,139          Owned Assets Director 129,432          134,609        139,994        145,594        549,629          Senior Infrastructure Engineer 433,269          450,600        468,624        487,369        1,839,863       Infrastructure Engineer 81,608            84,872          88,267          91,798          346,545          Federal Project Manager 596,670          620,537        645,358        671,173        2,533,738       Environmental Engineer 477,336          496,430        516,287        536,938        2,026,991       Program Controls 414,140          430,706        447,934        465,852        1,758,632       Program Project Manager 207,070          215,353        223,967        232,926        879,316          2,618,340       2,723,074    2,831,997    2,945,277    11,118,688    Source: pay rate roster Calculated based on Pay Rate Roster (Internal payroll data maintained my AIDEA) FY24 Rates Domestic Travel Depart From Destination No of Trips No. of DaysNo of TravelersTrips x TravelersLodging per Traveler per TripTrips x Travelers  x  LodgeFlight per Traveler (RT)Trips x Travelers x FlightsVehicle per TravelerVehicle * DaysPer Diem per TravelerTrips * travelers * days * Per Diem CostIn State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 40 250$        10,000$   1,100$        44,000$      100$        4,000$     58,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 40 250$        10,000$   500$           20,000$      100$        4,000$     34,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 1,000$     4,000$     1,500$        6,000$        500$        2,000$     12,000$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 1,000$     4,000$     1,500$        6,000$        400$        1,600$     500$        2,000$     13,600$        117,600$      Periods 4$                  470,400$      Domestic Travel Depart From Destination No of Trips No. of DaysNo of TravelersTrips x Travelers Lodging per Traveler Trips x Travelers  x Nights (D‐1) x LodgeFlight per Traveler (RT)Trips x Travelers x FlightsVehicle per TravelerVehicle * DaysPer Diem per TravelerTrips * travelers * days * Per Diem CostIn State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 20 250$        5,000$     1,100$        22,000$      100$        2,000$     29,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 20 250$        5,000$     500$           10,000$      100$        2,000$     17,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 400$        6,400$     1,500$        6,000$        500$        2,000$     14,400$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 350$        5,600$     1,500$        6,000$        400$        1,600$     500$        2,000$     15,200$        75,600$        100%Budget Period 1 75,600$        In State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 20 250$        5,000$     1,100$        22,000$      100$        2,000$     29,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 20 250$        5,000$     500$           10,000$      100$        2,000$     17,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 400$        6,400$     1,500$        6,000$        500$        2,000$     14,400$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 350$        5,600$     1,500$        6,000$        400$        1,600$     500$        2,000$     15,200$        75,600$        105% Budget Period 2 79,380$        In State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 20 250$        5,000$     1,100$        22,000$      100$        2,000$     29,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 20 250$        5,000$     500$           10,000$      100$        2,000$     17,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 400$        6,400$     1,500$        6,000$        500$        2,000$     14,400$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 350$        5,600$     1,500$        6,000$        400$        1,600$     500$        2,000$     15,200$        75,600$        110%Budget Period 3 83,349$        In State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 20 250$        5,000$     1,100$        22,000$      100$        2,000$     29,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 20 250$        5,000$     500$           10,000$      100$        2,000$     17,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 400$        6,400$     1,500$        6,000$        500$        2,000$     14,400$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 350$        5,600$     1,500$        6,000$        400$        1,600$     500$        2,000$     15,200$        75,600$        116%Budget Period 4 87,516$        Total Travel 325,845$       Equipment Item Qty Unit Cost Total Cost Revised Budget Period 1 Office Set‐up ‐ 8 new positions 8 10,000$        80,000$           Budget Period 20 Budget Period 3 Additional Equipment / replaceme 8 10,000          80,000             Budget Period 4 Note:  3 of 11 positions estimated to work on this project are existing PCNs.   ApplicationNo of Staff $/year $/Staff/YrYrs per Budget PeriodTotal Cost per Budget PeriodMisc Supplies 20 2,000$            40,000$          2$                    80,000$          Periods 4320,000$        Misc Supplies 20 2,000$            40,000$          2$                    80,000$          Budget Period 1105% 84,000$          Budget Period 2105% 88,200$          Budget Period 3105% 92,610$          Budget Period 4344,810$         Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 TotalBudget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 TotalLegal Services Competitive Bid or State of Alaska 425,000$               425,000$               425,000$               425,000$               1,700,000$           Public Relations Firm Competitive Bid 48,000$                 48,000$                 48,000$                 48,000$                 192,000$               Cultural Consoltation Competitive Bid 100,000$               100,000$               100,000$               100,000$               400,000$               Design & Engineering Consultant Competitive Bid 400,000$               400,000$               400,000$               400,000$               1,600,000$           Land Consultant Competitive Bid 400,000$               400,000$               400,000$               400,000$               1,600,000$           Labor/Govermental Consulting Competitive Bid 225,000$               225,000$               225,000$               225,000$               900,000$               Project Coordination Committee Competitive Bid 600,000$               600,000$               600,000$               600,000$               2,400,000$           Contractor Federal Projects Reporting Competitive Bid 150,000$               150,000$               150,000$               150,000$               600,000$               Accounting & Auditing Services Competitive Bid 150,000$               150,000$               150,000$               150,000$               600,000$               insurance Consultant Competitive Bid 100,000$               10,000$                 10,000$                 10,000$                 130,000$               NEPA Consultant Competitive Bid 200,000$               200,000$               30,000$                  ‐$                       430,000$               2,798,000$           2,708,000$           2,538,000$           2,508,000$           10,552,000$         Community Benefits Plan Quote‐$                        ‐$                       20,000$                 20,000$                 40,000$                 2,798,000$           2,708,000$           2,558,000$           2,528,000$            ‐$                       10,592,000$         10,592,000$      AEA GMRP Public Participation PlanTotalDec 2024- December 2026 hours rate hours rate hours rate hours rate hours rate hours rate ate$215 $165 $0 $155 $150 $145Task1. Project Administration10 $2,150 10 $1,650 0 $0 2 $310 15 $2,250 2 $290 $6,6502. Draft Public Participation plan8 $1,720 30 $4,950 4 $0 2 $310 30 $4,500 0 $0 $11,4803. Implement Public Participation PlanFacilitate five (5) introductory public work sessions, design/administer survey instrument, facilitate eight (8) one-on-one organizational work sessions, conduct informal outreach at three (3) events, facilitate five (5) secondary public work sessions, facilitate board leadership presentations.60 $12,900 100 $16,500 10 $0 45 $6,975 160 $24,000 35 $5,075 $65,4504. Public website designWebsite to include GIS tool for geocoded public comments. 4 $860 6 $990 16 $0 0 $0 12 $1,800 80 $11,600 $15,2505. OutreachRadio, social media, electric co-op mailers. (see "Advertising Expenses")0 $0 4 $660 12 $0 0 $0 30 $4,500 12 $1,740 $6,9006. Create reportAgnew::Beck will draft formal report of public participation plan findings.15 $3,225 40 $6,600 16 $0 5 $775 45 $6,750 8 $1,160 $18,5107. Public Review and Final Report Revisions4 $860 4 $660 20 $0 0 $0 4 $600 0 $0 $2,120Travel *$25,050Advertising Expenses **$5,000TOTAL*** 101 $21,715 194 $32,010 78 $0 54 $8,370 296 $44,400 137 $19,865 $156,410CHECKTravel Expense DetailTotal Lodging (2 nights/community meeting)$200 16 $200 16 $200 16 $9,600 Rental Car (2 days/meeting, shared)$150 16 $2,400 Meals ($75/day per diem)$75 18 $75 18 $75 18 $4,050Facility Rental ($800/meeting)$8,000Meeting Supplies ($50/meeting)$1,000TOTAL***$25,050$25,050EXCLUSIONS + TERMSThis estimate is good for 90 days from the date of the estimate.Principal Senior Manager Senior Associate* Travel - Roundtrip from Anchorage** Other Expenses - Include costs for phone and related equipment and services required in the normal performance of the contract. Costs for services required to produce informational, advertising or meeting materials are included in this budget; however, costs for printing, mailing or otherwise distributing these materials, or for paid advertising or other public notices are not included in this budget and would be paid for directly by client, as needed. Digital versions of all final materials will be submitted in an organized manner to the client for future editing, use and reproduction. Rights to final versions of all materials are transferred to the client upon conclusion of the project. A::B reserves the right to use any and all project materials for educational and marketing purposes. A::B reserves the rights to any draft or conceptual materials developed in the course of the project, or other Graphic/Web DesignerAPrincipal Senior Manager Senior Manager Senior Analyst Senior Associate SOPO Task #General Description Cost Basis of Cost Justification of needPreliminary Power Studies $4,500,000 Preliminary Estimate Studies to optimize designRoute Studies 4,500,000$ Based on similar work Preliminary inventory of soil, streams, etcCommunity Engagement $1,500,000 Consultant estimate Public EngagementNEPA Process $3,000,000 Preliminary estimate Begin environmental assessmentLong Lead Material Orders $59,270,283 Preliminary Estimate Begin ordering cable and towersBudget Period 1 Total$72,770,283Design & Engineering $7,000,000 Preliminary Estimate Perform detail engineering for transmissions & soilsNEPA Process $5,000,000 Preliminary Estimate Continue environmental/permitting processCommunity Engagement $2,000,000 Consultant Estimate Public EngagementROW and land acquisition and surface use agreements $10,000,000 Based on previous projects Land acquisiton and lease agreements for ROWLong Lead Material Orders $151,020,599 Continue ordering of materials Assure Delivery of materials meets consruction scheduleBudget Period 2 Total$175,020,599Long Lead Material Orders $10,200,000 Preliminary Estimate Purchase remaining materialsSite clearing and earthwork $38,000,000 Preliminary EstimateCommunity Engagement $2,000,000 Consultant Estimate Public EngagementConstruction $192,587,102 Preliminary EstimateBudget Period 3 Total$242,787,102Community Engagement $2,000,000 Consultant Estimate Public EngagementConstruction $190,389,578 Preliminary EstimateTesting and Commisioning $19,000,000 Preliminary EstimateBudget Period 4 Total$209,389,578Budget Period 5 Total$0 0PROJECT TOTAL $699,967,562Detailed Budget Justificationg. ConstructionPLEASE READ!!!1. Construction, for the purpose of budgeting, is defined as all types of work done on a particular building, including erecting, altering, or remodeling. Construction conducted by the award recipient is entered on this page. Any construction work that is performed by a vendor or subrecipient should be entered under f. Contractual.2. List all proposed construction below, providing a basis of cost such as engineering estimates, prior construction, etc., and briefly justify its need as it applies to the Statement of Project Objectives.3. Each budget period is rounded to the nearest dollar.Overall description of construction activities: Design and Construction of a 250 mile HVDC Overhead Transmission LineAdditional Explanation (as needed):Budget Period 1Budget Period 2Budget Period 5Budget Period 3Budget Period 4 Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Total CostRound 2Direct Costs:Personnel Cost 2,618,340$          2,723,074$            2,831,996$            2,945,278$          11,118,688$        Travel 75,600$                79,380$                 83,349$                 87,516$                325,845$              Supplies 80,000$                84,000$                 88,200$                 92,610$                344,810$              Contractual 2,798,000$          2,708,000$            2,558,000$            2,528,000$          10,592,000$          subtotal direct costs5,571,940$          5,594,454$            5,561,545$            5,653,404$          22,381,344$        Indirect Rate 31.85% 31.85% 31.85% 31.85%Indirect Costs 1,774,663.00       1,781,833.60         1,771,352.08         1,800,609.32       7,128,458$          Equipment (excluded from MTDC) 80,000$                 ‐$                        80,000$                  ‐$                      160,000$              Construction ( capital costs excluded from MTDC) 72,770,283$        175,020,599$       242,787,102$       209,389,578$      699,967,562$      Total 80,196,886$        182,396,887$       250,199,999$       216,843,592$      729,637,364$      Federal 40,098,443$        91,198,443$          125,100,000$       108,421,796$      364,818,682$      Cost Share 40,098,443$        91,198,443$          125,100,000$       108,421,796$      364,818,682$        Total 729,637,364$       Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Total CostRound 2Direct Costs:Personnel Cost 2,618,340$          2,723,074$            2,831,996$            2,945,278$          11,118,688$        Travel 75,600$                79,380$                 83,349$                 87,516$                325,845$              Supplies 80,000$                84,000$                 88,200$                 92,610$                344,810$              Contractual 2,798,000$          2,708,000$            2,558,000$            2,528,000$          10,592,000$          subtotal direct costs5,571,940$          5,594,454$            5,561,545$            5,653,404$          22,381,344$        Indirect Rate 31.85% 31.85% 31.85% 31.85%Indirect Costs 1,774,663.00       1,781,833.60         1,771,352.08         1,800,609.32       7,128,458$          Equipment (excluded from MTDC) 80,000$                 ‐$                        80,000$                  ‐$                      160,000$              Construction ( capital costs excluded from MTDC) 72,770,283$        175,020,599$       242,787,102$       209,389,578$      699,967,562$      Total 80,196,886$        182,396,887$       250,199,999$       216,843,592$      729,637,364$      Federal 40,098,443$        91,198,443$          125,100,000$       108,421,796$      364,818,682$      Cost Share 40,098,443$        91,198,443$          125,100,000$       108,421,796$      364,818,682$        Total 729,637,364$       Award Number:4/17/2024Award Recipient:AEA(May be award recipient or sub-recipient)Section A - Budget SummaryFederal Cost Share Total Costs Cost Share % Proposed Budget Period DatesBudget Period 1$78,205 $0 $78,205 0.00%Example!!! 01/01/2014 - 12/31/2014Budget Period 2$78,205 $0 $78,205 0.00%Budget Period 3$0 $0 $0 0.00%Budget Period 4$0 $0 $0 0.00%Budget Period 5$0 $0 $0 0.00%Total$156,410 $0 $156,410 0.00%Section B - Budget CategoriesCATEGORY Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Total Costs % of Project Comments (as needed)a. Personnel$0 $0 $0 $0 $0 $0 0.00%b. Fringe Benefits$0 $0 $0 $0 $0 $0 0.00%c. Travel$0 $0 $0 $0 $0 $0 0.00%d. Equipment$0 $0 $0 $0 $0 $0 0.00%e. Supplies$0 $0 $0 $0 $0 $0 0.00%f. ContractualSub-recipient$0 $0 $0 $0 $0 $0 0.00%Vendor$78,205 $78,205 $0 $0 $0 $156,410 100.00%FFRDC$0 $0 $0 $0 $0 $0 0.00%Total Contractual $78,205 $78,205 $0 $0 $0 $156,410 100.00%g. Construction$0 $0 $0 $0 $0 $0 0.00%h. Other Direct Costs$0 $0 $0 $0 $0 $0 0.00%Total Direct Costs$78,205 $78,205 $0 $0 $0 $156,410 100.00%i. Indirect Charges$0 $0 $0 $0 $0 $0 0.00%Total Costs$78,205 $78,205 $0 $0 $0 $156,410 100.00%Instructions and SummaryDate of Submission:SUMMARY OF BUDGET CATEGORY COSTS PROPOSEDThe values in this summary table are from entries made in subsequent tabs, only blank white cells require data entryAdditional Explanation (as needed):Form submitted by: Please read the instructions on each worksheet tab before starting. If you have any questions, please ask your DOE contact! 1. If using this form for award application, negotiation, or budget revision, fill out the blank white cells in workbook tabs a. through j. with total project costs. If using this form for invoice submission, fill out tabs a. through j. with total costs for just the proposed invoice and fill out tab k. per the instructions on that tab.2. Blue colored cells contain instructions, headers, or summary calculations and should not be modified. Only blank white cells should be populated. 3. Enter detailed support for the project costs identified for each Category line item within each worksheet tab to autopopulate the summary tab. 4. The total budget presented on tabs a. through i. must include both Federal (DOE) and Non-Federal (cost share) portions.5. All costs incurred by the preparer's sub-recipients, vendors, and Federal Research and Development Centers (FFRDCs), should be entered only in section f. Contractual. All other sections are for the costs of the preparer only.6. Ensure all entered costs are allowable, allocable, and reasonable in accordance with the administrative requirements prescribed in 2 CFR 200, and the applicable cost principles for each entity type: FAR Part 31 for For-Profit entities; and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities. 7. Add rows as needed throughout tabs a. through j. If rows are added, formulas/calculations may need to be adjusted by the preparer. Do not add rows to the Instructions and Summary tab. 8. ALL budget period cost categories are rounded to the nearest dollar.BURDEN DISCLOSURE STATEMENTPublic reporting burden for this collection of information is estimated to average 3 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden, to Office of Information Resources Management Policy, Plans, and Oversight, AD-241-2 - GTN, Paperwork Reduction Project (1910-5162), U.S. Department of Energy 1000 Independence Avenue, S.W., Washington, DC 20585; and to the Office of Management and Budget, Paperwork Reduction Project (1910-5162), Washington, DC 20503. Time (Hrs)Pay Rate($/Hr)Total Budget Period 1Time (Hrs)Pay Rate($/Hr)Total Budget Period 2Time (Hrs)Pay Rate($/Hr)Total Budget Period 3Time (Hrs)Pay Rate($/Hr)Total Budget Period 4Time (Hrs)Pay Rate($/Hr)Total Budget Period 51 Sr. Engineer (EXAMPLE!!!)2000 $85.00 $170,000 200 $50.00 $10,000 200 $50.00 $10,000 200 $50.00 $10,000 200 $50.00 $10,000 2400 $190,000 Actual Salary2 Technicians (2) 4000 $20.00 $80,000 0 $0.00 $0 0 $0.00 $0 0 $0.00 $0 0 $0.00 $0 4000 $80,000 Actual Salary$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0Total Personnel Costs0$00$00$00$00$00$0Additional Explanation (as needed):Position TitleINSTRUCTIONS - PLEASE READ!!!1. List project costs solely for employees of the entity completing this form. All personnel costs for subrecipients and vendors must be included under f. Contractual.2. All personnel should be identified by position title and not employee name. Enter the amount of time (e.g., hours or % of time) and the base pay rate and the total direct personnel compensation will automatically calculate. Rate basis (e.g., actual salary, labor distribution report, state civil service rates, etc.) must also be identified.3. If loaded labor rates are utilized, a description of the costs the loaded rate is comprised of must be included in the Additional Explanation section below. DOE must review all components of the loaded labor rate for reasonableness and unallowable costs (e.g. fee or profit). 4. If a position and hours are attributed to multiple employees (e.g. Technician working 4000 hours) the number of employees for that position title must be identified. 5. Each budget period is rounded to the nearest dollar.SOPO Task #Rate BasisProject Total DollarsBudget Period 4 Budget Period 5a. PersonnelProject Total HoursBudget Period 1 Budget Period 2 Budget Period 3Detailed Budget Justification Labor TypeTotal Project Personnel Costs Rate Total Personnel Costs Rate Total Personnel Costs Rate Total Personnel Costs Rate Total Personnel Costs Rate TotalEXAMPLE!!! Sr. Engineer$170,000 20% $34,000 $10,000 20% $2,000 $10,000 20% $2,000 $10,000 20% $2,000 $10,000 20% $2,000 $38,000$0 $0 $0 $0 $0 $0$0 $0 $0 $0 $0 $0$0 $0 $0 $0 $0 $0$0 $0 $0 $0 $0 $0$0 $0 $0 $0 $0 $0Total:$0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0Detailed Budget Justification b. Fringe BenefitsAdditional Explanation (as necessary): Please use this box (or an attachment) to list the elements that comprise your fringe benefits and how they are applied to your base (e.g. Personnel) to arrive at your fringe benefit rate.INSTRUCTIONS - PLEASE READ!!!1. Fill out the table below by position title. If all employees receive the same fringe benefits, you can show "Total Personnel" in the Labor Type column instead of listing out all position titles. 2. The rates and how they are applied should not be averaged to get one fringe cost percentage. Complex calculations should be described/provided in the Additional Explanation section below. 3. The fringe benefit rates should be applied to all positions, regardless of whether those funds will be supported by Federal Share or Recipient Cost Share.4. Each budget period is rounded to the nearest dollar.______ A fringe benefit rate has been negotiated with, or approved by, a federal government agency. A copy of the latest rate agreement is/was included with the project application.*______ There is not a current federally approved rate agreement negotiated and available.***Unless the organization has submitted an indirect rate proposal which encompasses the fringe pool of costs, please provide the organization’s benefit package and/or a list of the components/elements that comprise the fringe pool and the cost or percentage of each component/element allocated to the labor costs identified in the Budget Justification (Form EERE 335.1).**When this option is checked, the entity preparing this form shall submit an indirect rate proposal in the format provided in the Sample Rate Proposal at http://www1.eere.energy.gov/financing/resources.html, or a format that provides the same level of information and which will support the rates being proposed for use in the performance of the proposed project. A federally approved fringe benefit rate agreement, or a proposed rate supported and agreed upon by DOE for estimating purposes is required at the time of award negotiation if reimbursement for fringe benefits is requested. Please check (X) one of the options below and provide the requested information if not previously submitted.Budget Period 2 Budget Period 3Budget Period 1Budget Period 4 Budget Period 5 SOPO Task #Purpose of Travel Depart From DestinationNo. of DaysNo. of Travelers Lodging per Traveler Flight per Traveler Vehicle per Traveler Per Diem Per Traveler Cost per TripBasis for Estimating CostsDomestic Travel1EXAMPLE!!! Visit to PV manufacturer 2 2 $250 $500 $100 $160 $2,020 Current GSA rates$0$0$0$0International Travel$0Budget Period 1 Total$0Domestic Travel$0$0$0$0International Travel$0Budget Period 2 Total$0Domestic Travel$0$0$0$0International Travel$0Budget Period 3 Total$0Domestic Travel$0$0$0$0International Travel$0Budget Period 4 Total$0Domestic Travel$0$0$0$0International Travel$0Budget Period 5 Total$0PROJECT TOTAL$0INSTRUCTIONS - PLEASE READ!!1. Identify Foreign and Domestic Travel as separate items. Examples of Purpose of Travel are subrecipient site visits, DOE meetings, project mgmt. meetings, etc. Examples of Basis for Estimating Costs are past trips, travel quotes, GSA rates, etc. 2. All listed travel must be necessary for performance of the Statement of Project Objectives.3. Federal travel regulations are contained within the applicable cost principles for all entity types. Travel costs should remain consistent with travel costs incurred by an organization during normal business operations as a result of the organizations written travel policy. In absence of a written travel policy, organizations must follow the regulations prescribed by the General Services Administration. 4. Each budget period is rounded to the nearest dollar.Additional Explanation (as needed):c. TravelDetailed Budget Justification Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 SOPO Task #Equipment Item Qty Unit Cost Total Cost Basis of Cost Justification of need3,4,5EXAMPLE!!! Thermal shock chamber 2 $70,000 $140,000 Vendor Quote - Attached Reliability testing of PV modules- Task 4.3$0$0$0$0$0$0Budget Period 1 Total$0$0$0$0$0$0$0Budget Period 2 Total$0$0$0$0$0$0$0Budget Period 3 Total$0$0$0$0$0$0$0Budget Period 4 Total$0$0$0$0$0$0$0Budget Period 5 Total$0PROJECT TOTAL $0d. EquipmentDetailed Budget JustificationINSTRUCTIONS - PLEASE READ!!!1. Equipment is generally defined as an item with an acquisition cost greater than $5,000 and a useful life expectancy of more than one year. Please refer to the applicable Federal regulations in 2 CFR 200 for specific equipment definitions and treatment. 2. List all equipment below, providing a basis of cost (e.g. vendor quotes, catalog prices, prior invoices, etc.). Briefly justify items as they apply to the Statement of Project Objectives. If it is existing equipment, provide logical support for the estimated value shown. 3. During award negotiations, provide a vendor quote for all equipment items over $50,000 in price. If the vendor quote is not an exact price match, provide an explanation in the additional explanation section below. If a vendor quote is not practical, such as for a piece of equipment that is purpose-built, first of its kind, or otherwise not available off the shelf, provide a detailed engineering estimate for how the cost estimate was derived.4. Each budget period is rounded to the nearest dollar.Additional Explanation (as needed):Budget Period 3Budget Period 2Budget Period 1Budget Period 4Budget Period 5 SOPO Task #General Category of Supplies Qty Unit Cost Total Cost Basis of Cost Justification of need4,6EXAMPLE!!! Wireless DAS components10 $360.00 $3,600 Catalog price For Alpha prototype - Task 2.4$0$0$0$0$0$0$0Budget Period 1 Total $0$0$0$0$0$0$0$0$0Budget Period 2 Total$0$0$0$0$0$0$0$0$0Budget Period 3 Total$0$0$0$0$0$0$0$0$0Budget Period 4 Total$0$0$0$0$0$0$0$0$0Budget Period 5 Total$0PROJECT TOTAL$0Detailed Budget Justification INSTRUCTIONS - PLEASE READ!!!1. Supplies are generally defined as an item with an acquisition cost of $5,000 or less and a useful life expectancy of less than one year. Supplies are generally consumed during the project performance. Please refer to the applicable Federal regulations in 2 CFR 200 for specific supplies definitions and treatment. 2. List all proposed supplies below, providing a basis of costs (e.g. vendor quotes, catalog prices, prior invoices, etc.). Briefly justify the need for the Supplies as they apply to the Statement of Project Objectives. Note that Supply items must be direct costs to the project at this budget category, and not duplicative of supply costs included in the indirect pool that is the basis of the indirect rate applied for this project.3. Multiple supply items valued at $5,000 or less used to assemble an equipment item with a value greater than $5,000 with a useful life of more than one year should be included on the equipment tab. If supply items and costs are ambiguous in nature, contact your DOE representative for proper categorization. 4. Add rows as needed. If rows are added, formulas/calculations may need to be adjusted by the preparer. 5 Each budget period is rounded to the nearest dollarAdditional Explanation (as needed):Budget Period 1e. SuppliesBudget Period 2Budget Period 3Budget Period 4Budget Period 5 SOPO Task #Sub-RecipientName/OrganizationPurpose and Basis of CostBudget Period 1Budget Period 2Budget Period 3Budget Period 4Budget Period 5Project Total$0$0$0$0$0$0Sub-total $0 $0 $0 $0 $0 $0SOPO Task #Vendor Name/OrganizationPurpose and Basis of CostBudget Period 1Budget Period 2Budget Period 3Budget Period 4Budget Period 5Project TotalAgnew::Beck AEA GMRP Public Participation Plan $78,205 $78,205$156,410$0$0$0$0Sub-total $78,205 $78,205 $0 $0 $0 $156,410SOPO Task #FFRDCName/OrganizationPurpose and Basis of CostBudget Period 1Budget Period 2Budget Period 3Budget Period 4Budget Period 5Project Total$0$0Sub-total $0 $0 $0 $0 $0 $0Total Contractual$78,205 $78,205 $0 $0 $0 $156,410Detailed Budget Justification f. ContractualINSTRUCTIONS - PLEASE READ!!!1. The entity completing this form must provide all costs related to sub-recipients, vendors, and FFRDC partners in the applicable boxes below. 2. Sub-recipients (partners, sub-awardees): Subrecipients shall submit a Budget Justification describing all project costs and calculations when their total proposed budget exceeds either (1) $100,000 or (2) 25% of total award costs. These sub-recipient forms may be completed by either the sub-recipients themselves or by the preparer of this form. The budget totals on the sub-recipient's forms must match the sub-recipient entries below. A subrecipient is a legal entity to which a subaward is made, who has performance measured against whether the objectives of the Federal program are met, is responsible for programmatic decision making, must adhere to applicable Federal program compliance requirements, and uses the Federal funds to carry out a program of the organization. All characteristics may not be present and judgment must be used to determine subrecipient vs. vendor status. 3. Vendors (including contractors): List all vendors and contractors supplying commercial supplies or services used to support the project. For each Vendor cost with total project costs of $100,000 or more, a Vendor quote must be provided. A vendor is a legal entity contracted to provide goods and services within normal business operations, provides similar goods or services to many different purchasers, operates in a competitive environment, provides goods or services that are ancillary to the operation of the Federal program, and is not subject to compliance requirements of the Federal program. All characteristics may not be present and judgment must be used to determine subrecipient vs. vendor status. 4. Federal Funded Research and Development Centers (FFRDCs): FFRDCs must submit a signed Field Work Proposal during award application. The award recipient may allow the FFRDC to provide this information directly to DOE, however project costs must also be provided below.5. Each budget period is rounded to the nearest dollarAdditional Explanation (as needed): SOPO Task #General Description Cost Basis of Cost Justification of need3 EXAMPLE ONLY!!! Three days of excavation for platform site $28,000 Engineering estimate Site must be prepared for construction of platform.Budget Period 1 Total$0Budget Period 2 Total$0Budget Period 3 Total$0Budget Period 4 Total$0Budget Period 5 Total$0PROJECT TOTAL $0Detailed Budget Justificationg. ConstructionPLEASE READ!!!1. Construction, for the purpose of budgeting, is defined as all types of work done on a particular building, including erecting, altering, or remodeling. Construction conducted by the award recipient is entered on this page. Any construction work that is performed by a vendor or subrecipient should be entered under f. Contractual.2. List all proposed construction below, providing a basis of cost such as engineering estimates, prior construction, etc., and briefly justify its need as it applies to the Statement of Project Objectives.3. Each budget period is rounded to the nearest dollar.Overall description of construction activities: Example Only!!! - Build wind turbine platformAdditional Explanation (as needed):Budget Period 1Budget Period 2Budget Period 5Budget Period 3Budget Period 4 SOPO Task #General Description and SOPO Task # Cost Basis of Cost Justification of need5EXAMPLE!!! Grad student tuition - tasks 1-3$16,000 Established UCD costs Support of graduate students working on project Budget Period 1 Total$0Budget Period 2 Total$0Budget Period 3 Total$0Budget Period 4 Total$0Budget Period 5 Total$0PROJECT TOTAL $0Detailed Budget Justificationh. Other Direct CostsAdditional Explanation (as needed):INSTRUCTIONS - PLEASE READ!!!1. Other direct costs are direct cost items required for the project which do not fit clearly into other categories. These direct costs must not be included in the indirect costs (for which the indirect rate is being applied for this project). Examples are: tuition, printing costs, etc. which can be directly charged to the project and are not duplicated in indirect costs (overhead costs).2. Basis of cost are items such as vendor quotes, prior purchases of similar or like items, published price list, etc.3. Each budget period is rounded to the nearest dollar.Budget Period 1Budget Period 3Budget Period 2Budget Period 4Budget Period 5 Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 TotalProvide ONLY Applicable Rates:Overhead Rate 0.00% 0.00% 0.00% 0.00% 0.00%General & Administrative (G&A) 0.00% 0.00% 0.00% 0.00% 0.00%FCCM Rate, if applicable 0.00% 0.00% 0.00% 0.00% 0.00%OTHER Indirect Rate 0.00% 0.00% 0.00% 0.00% 0.00%Indirect Costs (As Applicable):Overhead Costs$0G&A Costs$0FCCM Costs, if applicable$0 OTHER Indirect Costs$0Total indirect costs requested: $0 $0 $0 $0 $0 $0Additional Explanation (as needed): *IMPORTANT: Please use this box (or an attachment) to further explain how your total indirect costs were calculated. If the total indirect costs are a cumulative amount of more than one calculation or rate application, the explanation and calculations should identify all rates used, along with the base they were applied to (and how the base was derived), and a total for each (along with grand total). Detailed Budget Justification You must provide an explanation (below or in a separate attachment) and show how your indirect cost rate was applied to this budget in order to come up with the indirect costs shown.A federally approved indirect rate agreement, or rate proposed (supported and agreed upon by DOE for estimating purposes) is required if reimbursement of indirect costs is requested. Please check (X) one of the options below and provide the requested information if it has not already been provided as requested, or has changed. ______ An indirect rate has been approved or negotiated with a federal government agency. A copy of the latest rate agreement is included with this application, and will be provided electronically to the Contracting Officer for this project.______ There is not a current, federally approved rate agreement negotiated and available*. *When this option is checked, the entity preparing this form shall submit an indirect rate proposal in the format provided by your DOE contact, or a format that provides the same level of information and which will support the rates being proposed for use in performance of the proposed project. Additionally, any non-Federal entity that has never received a negotiated indirect cost rate, except for those non-Federal entities described in Appendix VII to Part 200—States and Local Government and Indian Tribe Indirect Cost Proposals, paragraph D.1.b, may elect to charge a de minimis rate of 10% of modified total direct costs (MTDC) which may be used indefinitely.As described in §200.403 Factors affecting allowability of costs, costs must be consistently charged as either indirect or direct costs, but may not be double charged or inconsistently charged as both. If chosen, this methodology once elected must be used consistently for all Federal awards until such time as a non-Federal entity chooses to negotiate for a rate, which the non-Federal entity may apply to do at any time. i. Indirect CostsINSTRUCTIONS - PLEASE READ!!!1. Fill out the table below to indicate how your indirect costs are calculated. Use the box below to provide additional explanation regarding your indirect rate calculation. 2. The rates and how they are applied should not be averaged to get one indirect cost percentage. Complex calculations or rates that do not do not correspond to the below categories should be described/provided in the Additional Explanation section below. If questions exist, consult with your DOE contact before filling out this section. 3. The indirect rate should be applied to both the Federal Share and Recipient Cost Share.4. Each budget period is rounded to the nearest dollarExplanation of BASE Organization/Source Type (Cash or In Kind) Cost Share Item Budget Period 1Budget Period 2Budget Period 3Budget Period 4Budget Period 5Total Project Cost ShareABC CompanyEXAMPLE!!!Cash Project partner ABC Company will provide 20 PV modules for product development at the price of $680 per module$13,600$13,600$0$0$0$0$0$0$0$0$0$0Totals $0 $0 $0 $0 $0 $0$156,4100.0%Additional Explanation (as needed):Cost ShareDetailed Budget JustificationPLEASE READ!!!1. A detailed presentation of the cash or cash value of all cost share proposed must be provided in the table below. All items in the chart below must be identified within the applicable cost category tabs a. through i. in addition to the detailed presentation of the cash or cash value of all cost share proposed provided in the table below. Identify the source organization & amount of each cost share item proposed in the award. 2. Cash Cost Share - encompasses all contributions to the project made by the recipient, subrecipient, or third party (an entity that does not have a role in performing the scope of work) for costs incurred and paid for during the project. This includes when an organization pays for personnel, supplies, equipment, etc. for their own company with organizational resources. If the item or service is reimbursed for, it is cash cost share. All cost share items must be necessary to the performance of the project. Vendors may not provide cost share. Any partial donation of goods or services is considered a discount and is not allowable. 3. In Kind Cost Share - encompasses all contributions to the project made by the recipient, subrecipient, or third party (an entity that does not have a role in performing the scope of work) where a value of the contribution can be readily determined, verified and justified but where no actual cash is transacted in securing the good or service comprising the contribution. In Kind cost share items include volunteer personnel houthe donation of space or use of equipment, etc. The cash value and calculations thereof for all In Kind cost share items must be justified and explained in the Cost Share Item section below. All cost share items must be necessary to the performance of the project. If questions exist, consult your DOE contact before filling out In Kind cost share in this section. Vendors may not provide cost share. Any partial donation of goods or services is considered a discount and is not allowable. 4. Funds from other Federal sources MAY NOT be counted as cost share. This prohibition includes FFRDC sub-recipients. Non-Federal sources include any source not originally derived from Federal funds. Cost sharing commitment letters from subrecipients and third parties must be provided with the original application.5. Fee or profit, including foregone fee or profit, are not allowable as project costs (including cost share) under any resulting award. The project may only incur those costs that are allowable and allocable to the project (including cost share) as determined in accordance with the applicable cost principles prescribed in FAR Part 31 for For-Profit entities and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities.6. NOTE: A Recipient who elects to employ the 10% de minimis Indirect Cost rate cannot claim the resulting indirect costs as a Cost Share contribution. 7. NOTE: A Recipient cannot claim "unrecovered indirect costs" as a Cost Share contribution, without prior approval. 8. Each budget period is rounded to the nearest dollar. Cost Share Percent of Award:Total Project Cost: 813 W Northern Lights Blvd, Anchorage, AK 99503  Phone: (907) 771-3000  Fax: (907) 771-3044  Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG Environmental Questionnaire Attachment Control Number 3195-1942 Healy Beluga  Proposed HVDC Route OMB Number: 4040-0004 Expiration Date: 11/30/2025 Application for Federal Assistance SF-424 *1. Type of Submission: Preapplication Application Changed/Corrected Application *2. Type of Application New Continuation Revision * If Revision, select appropriate letter(s): * Other (Specify) *3. Date Received:4. Applicant Identifier: 5a. Federal Entity Identifier: *5b. Federal Award Identifier: State Use Only: 6.Date Received by State:7.State Application Identifier: 8. APPLICANT INFORMATION: *a. Legal Name: *b. Employer/Taxpayer Identification Number (EIN/TIN):*c. UEI: d. Address: *Street 1: Street 2: *City: County/Parish: *State: *Province: *Country: *Zip / Postal Code e. Organizational Unit: Department Name: Division Name: f. Name and contact information of person to be contacted on matters involving this application: Prefix: *First Name: Middle Name: *Last Name: Suffix: Title: Organizational Affiliation: *Telephone Number:Fax Number: *Email: Application for Federal Assistance SF-424 *9. Type of Applicant 1: Select Applicant Type: Type of Applicant 2: Select Applicant Type: Type of Applicant 3: Select Applicant Type: *Other (Specify) *10. Name of Federal Agency: 11. Catalog of Federal Domestic Assistance Number: CFDA Title: *12. Funding Opportunity Number: *Title: 13. Competition Identification Number: Title: 14. Areas Affected by Project (Cities, Counties, States, etc.): *15. Descriptive Title of Applicant’s Project: Attach supporting documents as specified in agency instructions. Application for Federal Assistance SF-424 16. Congressional Districts Of: *a. Applicant:*b. Program/Project: Attach an additional list of Program/Project Congressional Districts if needed. 17. Proposed Project: *a. Start Date:*b. End Date: 18. Estimated Funding ($): *a. Federal *b. Applicant *c. State *d. Local *e. Other *f. Program Income *g. TOTAL . *19. Is Application Subject to Review By State Under Executive Order 12372 Process? a.This application was made available to the State under the Executive Order 12372 Process for review on b.Program is subject to E.O. 12372 but has not been selected by the State for review. c.Program is not covered by E.O. 12372. *20. Is the Applicant Delinquent On Any Federal Debt? Yes No If “Yes”, explain: 21. *By signing this application, I certify (1) to the statements contained in the list of certifications** and (2) that the statements herein are true, complete and accurate to the best of my knowledge. I also provide the required assurances** and agree to comply with any resulting terms if I accept an award. I am aware that any false, fictitious, or fraudulent statements or claims may subject me to criminal, civil, or administrative penalties. (U. S. Code, Title 218, Section 1001) ** I AGREE ** The list of certifications and assurances, or an internet site where you may obtain this list, is contained in the announc ement or agency specific instructions. Authorized Representative: Prefix: *First Name: Middle Name: *Last Name: Suffix: *Title: *Telephone Number:Fax Number: * Email: *Signature of Authorized Representative:*Date Signed: CURTIS W. THAYER Executive Director Experience and Achievements Alaska Energy Authority 2019-Present The Alaska Energy Authority (AEA) is a public corporation of the State of Alaska governed by a board of directors with the mission to "reduce the cost of energy in Alaska." AEA is the state's energy office and lead agency for statewide energy policy and program development. Position: Executive Director • The Executive Director serves as the Chief Executive Officer of the Authority, responsible for all business and operations. I work closely with the Board as it sets Authority policies, goals, and objectives, and is responsible for the execution of Board directives. I have developed a close relationship with the Governor, Commissioners of principal State departments, the Legislature, business community, and the public to advance the mission of the Authority. Achievements: Increased the profile and developed a strategic action plan to advance the goal and objectives of the Authority • Worked with the Board to establish long-range vision, strategies, goals, policies, and plans; including leading the strategic planning process and working with the Board and Legislature to implement the strategy to achieve that vision. • Strengthening the working relationship with the five utilities is like shuttle diplomacy. A few of the key issues during the three years have included purchase of develop a strategy and bonding package for a $170 million upgrade for the transmission lines from Homer to Anchorage (closes 11/30/22), purchase SS/Q line ($17 million), Battle Creek diversion and construction delays and construction claims, ligation on the SQ line, and Governor's goal of reducing the cost of power. Managing expectations of the Board, Governor's Office, Legislature and our five utility partners has proved to be challenging (and rewarding). • Oversight responsibility of the Authority's rural energy programs, including energy system upgrades, loan programs, alternative/renewable energy, energy efficiency, and the Power Cost Equalization program. • Reviewed and analyzed legislation, laws, regulations, and other public policies that may affect the Authority's mission and programs and recommends changes when appropriate. • Developing and maintaining professional/cooperative relationships with local, state, and federal agencies, and Authority business partners. • Working with legislative or other government agencies regarding policies, programs, and budgets. Alaska State Chamber of Commerce 2015-2019 The Alaska Chamber is a non-profit, membership funded advocacy organization founded in 1953. The Chamber membership is comprised of companies, associations, and individuals from every business sector in Alaska. The Chamber's core mission is to make Alaska the best place to do business through its advocacy for and defense of sound business policies based on the principles of free enterprise, personal responsibility, and limited government. Position: President and CEO • As the President & Chief Executive Officer, I serve as the top administrative officer, principal spokesman, chief advocate in Juneau and Washington DC, chief finance officer and team leader. Achievements: Raised the profile of the Alaska Chamber • Coordinated and guided the work of staff, lobbyists, counsel, committee, and volunteers in marshaling and expressing the Chamber's business perspective on public policy issues which has increased the profile of the Alaska Chamber statewide through outreach and tackling tough legislative positions that benefit and promote business. • Lead efforts to develop and manage coalitions involving other business associations, advocacy groups, local chambers and the US Chamber to achieve Chamber goals. • Grew Chamber membership for the last three straight years. • Developed and implemented a financial plan that has increased Chamber reserves by 15 percent within three years. State of Alaska, Department of Administration 2012 - 2014 With 1, 100 employees and an annual budget of $350 million, DoA facilitates state government operations by providing policy leadership and management services in essential areas, including finance/accounting, payroll, human resources/retirement benefits, information technology, labor negotiations, legal services, procurement/facilities, and risk management. Positions: Commissioner & Deputy Commissioner • Served as the chief executive officer of DoA and as a member of Governor Sean Parnell's cabinet. Unanimously confirmed by the Alaska State Legislature. • Advised Governor on IT, pensions, healthcare, and labor relations with the Legislature and business community. • Responsible for development and implementation of all DOA policies and programs. Hired and managed two deputy commissioners and ten division directors. Achievements: Reducing the Cost of Government • Reformed PERS/TERS (state/local government pension programs) to reduce annual state contribution and ensure long-term solvency. Annual savings are more than $300 million. • Restructured AlaskaCare (state healthcare program) to reduce state contribution without reducing core benefits. Annual savings are more than $60 million. • Negotiated with the state's eleven public employee's unions to limit automatic merit increases, reduce leave accruals, and cap benefit cash-outs, all without work stoppages. Annual savings are more than $20 million. • Worked with Legislature to revamp state procurement statutes to increase transparency and competition. Applied new statutes and best practices to major telecom procurement, which reduced annual state expenses by 50%. Previous Experience • 2009-2012: Deputy Commissioner, State of Alaska, Department of Commerce, Community, and Economic Development • 2004-2009: Director, Corporate and External Affairs, ENSTAR Natural Gas Company • 2002-2004: President & CEO, Thayer & Associates (political and corporate communications consulting) • 2001-2002: External Affairs Advisor, Alaska Gas Producers Pipeline Team (BP, Phillips, Exxon) • 1997-2000: Special Assistant, U.S Congressman Don Young (R-Alaska) • 1993-1996: Professional Staff, U.S House Committee on Natural Resources • 1991-1992: Management Specialist, Federal Bureau of Investigation (FBI) Education • University of Alaska Fairbanks, Fairbanks, AK. Bachelor of Arts in Political Science and Business/Justice • National Renewable Energy Lab (NREL), Golden CO, Executive Energy Leadership Academy • University of Wisconsin, Institute of Organizational Management, U.S. Chamber • State of Alaska, Real Estate License Community Activities CURRENT • Alaska Board of Marine Pilots, Chair • Don Young Institute for Alaska, Chair • Alaska Leaders Archives, Treasurer PAST • Alaska Gas Line Development Corporation, Director • Alaska Housing Finance Corporation, Director • Alaska Retirement Management Board, Trustee • Alaska Royalty Oil and Gas Development Advisory Board, Director • Abused Women Aid in Crisis (AWAIC), Director and Treasurer • Committee of 100 Top Chamber Executives, U.S. Chamber • Council of State Chamber Executives • Selected as "Top 40 under 40" community leader Dan Bishop, PE PROFESSIONAL OBJECTIVE Use my understanding of policy trends and rapidly changing technologies in generation, energy storage, transmission & distribution, and information technology to drive projects that strategically benefit GVEA and the communities it serves without abandoning well-established, prudent utility practices. EMPLOYMENT HISTORY Golden Valley Electric Association, Inc. Director of Engineering Services, October 2022 - present Manager of Engineering Services, 2011–2022 • Participate in Railbelt utility organizations. • Work toward meeting GVEA strategic goals including reduction of carbon emissions. • Managing teams of engineers, electricians, land managers, and CAD/GIS technicians who: o Forecast future electrical loads o Build substations o Build transmission lines o Maintain substations o Perform Integrated Resource Planning o Prepare company-wide construction work plans for development of infrastructure o Facilitate connection of distributed generation o Analyze grid response to disturbances o Perform grid modeling as required for planning and operations o Participate in coordinated Railbelt planning of system improvements o Implement projects that use complex software systems to integrate business processes across software platforms o Apply new technology to improve cyber-security, mitigate environmental risk, reduce costs, and improve reliability. EDUCATION University of Alaska Fairbanks Master of Science in Electrical Engineering, 1990 Degree Emphasis: Control Systems & Instrumentation University of Alaska Fairbanks Bachelor of Science in Electrical Engineering, 1985 Degree Emphasis: Communications systems & Digital systems University of Alaska Fairbanks Power systems engineering classes, 1995 University of Wisconsin NRECA Management Internship Program, 2012 PROFESSIONAL REGISTRATION • AK Professional Electrical Engineer #8476 (received in 1993) Edward Jenkin P.O. Box 870234 Wasilla, Alaska 99687 Cell: 907-707-6385 edandjenjenkin@gmail.com A Professional Engineer in the state of Alaska with over 30 years of u�lity engineering and opera�ons experience, including over ten years in an execu�ve capacity. A past Chief Opera�ons Officer, presently overseeing a u�lity genera�on fleet transi�on as the Chief Energy Transforma�on Officer. A presenter at mul�ple conferences and workshops including events sponsored by the State of Alaska, Northwest Public Power Associa�on, and United States Energy Associa�on. MATANUSKA ELECTRIC ASSOCIATION (MEA) - JUNE 2014 TO PRESENT Presently, as Chief Energy Transformation Officer I am part of a team responsible for implementing key strategic goals for MEA. With direct oversight of Power Dispatch and Fuel Departments, I am responsible for various contracts and negotiation as MEA transitions to a generation portfolio with additional clean energy resources. As the regional utilities look to more regional approaches, I represent MEA on the region’s Electric Reliability Organization Board and am the technical representative for the regional utilities on the committee which sets up the organizational structure of a regional transmission organization. I was leader in developing a power pool with an adjacent utility and represent MEA on the Operating Committee. I represent MEA on the Technical Advisory Committee to the Alaska Energy Authority and other regional committees. I sit on the advisory committee for the University of Alaska, Anchorage’s Electrical Engineering Department. Prior to being the Chief Energy Transformation Officer, I was the Chief Operations Officer for MEA, where I participated in the Association’s strategic planning, financial planning, and resource planning. I presented to the Board of Directors various information and items for approval, being responsible for all aspects of delivering reliable power from MEA’s power plant and other distributed sources to the members’ facilities. Specifically, I oversaw Engineering, Operations, Technical Services, Power Dispatch, and Grid Modernization. I provided oversight on internal and regional resources and planning efforts. I participated in and led joint committees for the development of standards, including the present Reliability Standards jointly approved by all the Railbelt utilities. I was responsible for developing five-year capital work plans and multimillion dollar operational and capital budgets. Staffing plans and financial performance were reviewed as needed to ensure the Association’s performance is in line with service, reliability, and rate requirements. Professional Summary Work Experience CHUGACH ELECTRIC ASSOCIATION - MARCH 1989 TO JUNE 2014 At Chugach Electric, I progressed from the design, cost estimation, and inspection of projects associated with 12kV distribution and 35kV sub transmission facilities, to overall distribution and transmission system planning, including distribution system protection. I moved to the supervision of the Associ ation's Power Dispatch Center in 2000 and was responsible for overseeing generation scheduling (including sales and purchases) and overall system operations. As a Director and Executive at Chugach Electric from 2004 to 2014, I was responsible for all design, construction, and maintenance functions associated with the delivery of power from the power plants to the customer meter; directed the development of the Associati on's capital improvement plan and the division budget; participated in Board and executive level strategic planning and developed implementation plans, set goals, and reported on progress; approved represented and non-represented employee actions related to hiring and discipline; represented the Association at various levels, including to community, government, and legislative bodies; and sat on various regional committees. Master of Arts in Cross-Cultural Studies, Fuller Theological Seminary Pasadena, California; Graduated 1987 Bachelor of Science in Electrical Engineering, Power Op�on University of Alaska, Fairbanks; Graduated 1984 Educa�on Daniel Heckman P.O. Box 74434 ⚫Fairbanks, AK 99707 ⚫Phone: (907) 347-2844 ⚫E-Mail: dheckman22@gmail.com Experience Golden Valley Electric Association, Inc. (Fairbanks, AK)February 8, 2016 - Present Regulatory Manager (2022 - Present) Regulatory Analyst (2020 - 2022) Regulatory Specialist (2016 - 2020) ●Provide regulatory and compliance oversight to assure that financial and regulatory reporting is in compliance with Generally Accepted Accounting Principles (GAAP), USDA Rural Utilities Service (RUS), US Department of Energy (DOE), and Regulatory Commission of Alaska (RCA) policies and procedures, as well as any applicable Regulatory laws and to ensure GVEA’s regulatory practices and procedures are in line with industry standards. ●Serve as GVEA’s primary representative to regulatory agencies, including Regulatory Commission of Alaska (RCA), the Railbelt Reliability Council (RRC), and other federal/state agencies as applicable. ●Proactively research and monitor legislative and regulatory frameworks and activities on matters of importance to GVEA and the electric utility industry or before the RCA and timely advise management with recommendations on these activities. ●Lead with review of utilities regulatory reporting to ensure compliance with RCA orders, rules, regulations, and policies. ●Review the Cost of Power Adjustment (COPA) and the Simplified Rate Filing (SRF) models to forecast current and future conditions and provide responses to RCA’s questions concerning the COPA and SRF components. ●Lead senior management, consultants, and coordinate with tariff counsel in the tariff filing process and other adjudicatory matters before the RCA. ●Ensure the COPA, SRF, Annual FERC and RUS filings are submitted timely and in compliance with regulations. Assist with their computations and file their associated tariff sheets and filings with the RCA. Provide regulatory guidance on COPA and SRF related initiatives and inputs. ●Serve as internal resource to project managers and internal compliance officer to ensure grant reporting complies with the requirements of regulatory agencies as required. ●Provide oral and/or written comments on RCA utility, informational, and rulemaking dockets and various filings with the RCA of relevance to GVEA. ●Review and respond to member, utility personnel. and RCA staff inquiries about complaints relating to the proper application of GVEA’s tariffs. ●Timely respond to RCA staff inquiries on GVEA’s financial and regulatory reports and filings to ensure compliance with RCA orders, rules, regulations, and policies, and preferences. ●Serve as internal project manager and provide support to external legal counsel and consultants in preparing and presenting GVEA’s general rate case filings or other investigations before the RCA, including assembling support documents, draing prefiled direct and reply testimony, responding to data requests during discovery, preparing exhibits and participating in hearings before the RCA. ●Attend workshops and conferences as well as monitor regulatory proceedings to identify trends, issues or decisions which might affect GVEA’s regulatory objectives. ●Serve as GVEA representative on various groups and task forces, as requested, addressing matters related to energy and regulatory policy on a Railbelt-wide level. ●Responsible for employee training, hiring, promotion, and disciplinary actions, in consultation with Member Services Supervisors. ●Responsible for preparing and administering performance evaluations, establishing goals, monitoring performance, and developing employees. Page 1 of 2 Daniel Heckman P.O. Box 74434 ⚫Fairbanks, AK 99707 ⚫Phone: (907) 347-2844 ⚫E-Mail: dheckman22@gmail.com Doyon Utilities, LLC (Fairbanks, AK)July 1, 2013 - January 29, 2016 Contract Compliance/Regulatory Affairs Associate ●Assist in the computation, compilation, and filing of two rate cases for twelve separate certificated utilities before the RCA. Dratariff advice letters and pre-filed testimony, revise the Cost Allocation Manual, and respond to discovery requests. ●Review Defense Logistics Agency requests for proposals and contract modifications and proposed utility responses to ensure legal compliance with contract governing relationship between utility and the U.S. Government as well as RCA regulations. ●Develop and maintain a monthly spreadsheet detailing relevant filings before the RCA. Report on filings to the President/CEO, Vice-President of Administration, Director of Regulatory Affairs, and General Counsel. ●Perform legal, regulatory, and accounting research and dramemorandum for utility personnel as requested. ●Review dra capital projects plans to ensure legal and regulatory compliance. Education Gonzaga University School of Law (Spokane, WA) J.D., May 2013 ●Legal Fellow; Office of Senator Lisa Murkowski (Spring 2013, Washington DC) Southern Methodist University (Dallas, TX) B.A. Political Science; B.A. History, May 2010 Community Involvement ●Cold Climate Housing and Research Center o Member, Board of Directors (2023 - Present) ●United Way of the Tanana Valley o Member, Board of Directors (2019 - 2023) ●Midnight Sun Council, Boy Scouts of America o Member, Board of Directors (2014 - 2019) ●Golden Heart Rotary Club (2013 - 2020) Page 2 of 2 Julie Estey Julie Estey, Senior Director of External Affairs and Strategic Initiatives, MEA Julie Estey is the Senior Director where she manages the cooperative’s public and member facing activities along with the organization’s strategic plan and special projects. She serves as the organization’s representative, past Chair and founding member of the Railbelt Reliability Council, the recently certificated Electric Reliability Organization for the interconnected Railbelt grid. Before joining MEA, Ms. Estey was the Business Director for the Alaska Center for Energy and Power, an energy research group at the University of Alaska Fairbanks focused on improving how Alaskans generate and distribute power. She has experience managing public outreach and engagement for controversial transmission and generation capital projects as well as expertise bringing diverse groups of stakeholders together to develop common solutions. James W. Mendenhall, P.E. Program Manager jmendenhall@akenergyauthority.org 907-360-9390 PROFESSIONAL SUMMARY Jim Mendenhall has over 30 years working in senior leadership roles within the business environments of; Aviation, Construction, Mining and Alaska Native Enterprise initiatives. Jim knows what truly drives business strategy. His proven expertise; business development, operational project management, have provided his clients successes which reach solidly into the future, continuing to build on their business objectives. EXPERIENCE Alaska Energy Authority, Program Manager (2023-Present) Oversee various projects within AEA’s portfolio of projects including the Railbelt Innovation and Resiliency project. PAECO, LLC, Managing Member (2018-Present) MENDENHALL AND ASSOCIATES, Management Consultant (September 2014-2018) FAIRWEATHER AVIATION, Principal (January 2015-2018) Provide strategic and management advice to clients in the aviation and construction sectors. Examples: investor's representative to monitor and mentor aviation company performing specialized maintenance work on the North Slope; developed a business development plan for an electrical subcontractor; developed claim support strategy to justify a contract extension for a civil contractor and revised the project schedule in order to avoid termination by default; developed aviation solutions for the resource industry; made recommendations for an aviation shuttle to/from Alaska's North Slope; performed ice management surveys for arctic sealift, and developed an aerial solution for an electric utility to monitor tree & vegetation issues within the right-of-way, ASRC CONSTRUCTION HOLDING COMPANY President & CEO (January 2012-May 2014) Interim CEO (July 2011-December 2011) Chief Operating Officer (January 2011-June 2011) Executive leadership for five operating units' general managers, executing $150M in construction, O&M and design/build projects annually, with business unit teams maintaining backlog in tight market conditions. Directed business development for new initiatives including teaming arrangement with Fluor and two other ASRC subsidiaries to secure a $700M contract at DOE's Strategic Petroleum Reserve; advocated utilization of prefabricated modules for a Barrow hotel in order to save time and money; completed an acquisition that resulted in a business expansion; moved ACHC into the oil & gas sector to perform capital projects. Achieved aggressive Local/Shareholder hire goals each year. Improved safety culture, reducing incident rate from over 3.5 to 0.78. Restructured ACHC to increase efficiency and improve support to operating units. NANA DEVELOPMENT CORPORATION, Vice President (2006-2010) Managed NDC's operations at the Red Dog Mine. Built joint ventures and alliances, increasing portfolio of 10 companies' revenue 200% from 2006 to 2008. NDC corporate-wide: participated in M&A activities and created forum of NDC executives to meet and hear from guest speakers in order to pursue opportunities in the petroleum and mining industry. Responsible for Profit/Loss within Lynden, Crowley, Major American Drilling and PAA River Constructors partnerships, Negotiated NANA's initial multi-year contract to provide Red Dog with 19,500,000 gallons of fuel annually. Developed an apprentice program to train drillers during the winter season in New Mexico for employment at Red Dog during the summer season. NDC's lead for the initiative to bring the Red Dog lightering contract to NANA/Lynden. SECURITY AVIATION INC., Director of Business Development (2004-2006) Hired for a business development role, initiated and managed a complete review of operations, increasing profit margins three-and-a-half fold with minimal investment while converting underperforming assets into positive investment returns. Evaluated opportunities and developed proposals for new business. MENDENHALL AND ASSOCIATES, Management Consultant (2003-2004) Advised companies on the Small Business Administration Mentor-Protégé, 8(a) programs and certification processes. Participated in the creation of a rural Alaska fuel consortium funded by the Denali Commission. Worked with Canadian First Nations and the Alaska Highway Aboriginal Pipeline Group. Evaluated options for construction and operation of a small refinery/topping plant on the North Slope. ARCTIC SLOPE REGIONAL CORPORATION ASRC Constructors, President (2002) Converted dormant subsidiary into a qualified Small Business Administration 8(a) and secured key contracts with the Department of State for construction of a foreign embassy and DOE for Construction Management services. SKW-Eskimos, Inc., (1979-2001) Vice President of Marketing and Business Development (1999-2000) Business Development Manager (1992-1999) Accomplishments include: Maintained and guided Village Corporation relationships leading to over $250 million in JV contracts and diversified revenue by expanding business presence outside of Alaska. Advised Canadian First Nations on establishing for-profit economic entities. Secured an oil and gas development project for a Yukon First Nation's entity. Developed a Small Business Administration Mentor-Protégé Agreement. Refocused SKW's community contributions plan to increase return on investment. Successfully lobbied federal government for revisions to PL 93-638 (Indian Self Determination Act). Secured first fixed price construction ($4 million) '638' contract with Bureau of Indian Affairs for an Alaska Native corporation joint venture. Monitored Texas-based gas compression operation. Secured engineering and construction contracts for infrastructure development in Anadyr, Chukotka Autonomous Region (Russian Far East). Acquisition team member for Venezuelan fabrication facility and Texas based gas compression company. Conducted quarterly business reviews with the ASRC executive committee, delivered annual business unit financial plans and forecasts to the ASRC board. Served as a Trustee for the ASRC pension plan. Construction Administrator (1983-1992), Project Engineer (1979-1983) EDUCATION University of Alaska: 1979 Bachelor of Science - Civil Engineering, 1979 Associate of Arts - Science University of Washington: 1998- Accounting for Non-Financial Managers Levinson Leadership Institute: 1999 Alaska Humanities Forum: 2000 Leadership Anchorage Program FBI Citizens Academy PERSONAL & PROFESSIONAL AFFILIATIONS U.S. Chamber of Commerce - Director Prior board positions: Boy Scouts of Alaska, Associated Builders & Contractors-Alaska, Alaska Chamber of Commerce, University of Alaska Fairbanks College of Engineering & Mines Advisory Committee Race Across AMerica (RAAM) June 2000 member of Team Alaska Registered Professional Engineer — Alaska #7243 Have held Top Secret and Secret clearances Keriann Baker Chief Strategy Officer kbaker@homerelectric.com 907-235-3302 PROFESSIONAL SUMMARY Keriann is presently employed as the Chief Strategy Officer for Homer Electric Association, Inc. Keriann has served on numerous boards including local, and state chambers, state and national bar associations, and the South Peninsula Hospital, Inc. Board. Keriann received a Bachelor of Science from Utah Valley University and received a Juris Doctor Degree from Loyola Chicago School of Law. Keriann and her husband, Bryan, live in Homer and spend most of their free time chasing after their three school aged children and two dogs. Keriann enjoys fishing, hiking, camping, reading, and skiing. As an adult, Keriann formed a travel and adventure addiction. She has visited 44 of 50 states and visited 20 countries throughout Europe, South America, and the Caribbean. EXPERIENCE HOMER ELECTRIC ASSOCIATION, INC. (HEA) Chief Strategy Officer | 2021 - Present Oversees the cooperative’s strategic initiatives, public relations and external affairs efforts, and legislative affairs for HEA. REEVES AMODIO Attorney | April 2019 to April 2021 Representing clients in transactional matters, litigation and administrative proceedings including Representing developers before municipal entities and in legal proceedings for all manner of land use, environmental permitting, and zoning matters. Serving as corporate counsel. Representing Tribes in permitting, land use and transactional matters. Representing corporate clients engaged in business transactions with Tribes and tribally owned businesses. KC BAKER, P.A. / KC BAKER, LLC President | October 2013 to April 2019 Represented clients in transactional matters, litigation and administrative proceedings including Represented corporations, developers, and property owners before governmental bodies in matters relating to marine and coastal issues, environmental permitting, land use matters, zoning, and comprehensive planning. Served as corporate counsel for various companies. Provided of counsel services to various Alaska attorneys. Attended and argued motion and evidentiary hearings; developed discovery strategies, pleadings, motions, and legal memoranda; prepared for and attended trials. Represented corporate clients engaged in business with Native American Tribes and Tribal owned businesses. LEWIS, LONGMAN & WALKER, P.A. Attorney | June 2007 to October 2013 Represented clients in transactional matters, litigation and administrative proceedings including represented state and local governments and Tribes in land use and environmental matters. Advised financial institutions of environmental risks relating to property in foreclosure and pre-foreclosure. Represented tribes in putting land into trust with the Department of Interior and establishing delegated permitting agreements. Represented clients in environmental remediation matters. Litigated endangered species, energy and environmental lawsuits and administrative land use challenges. Represented airports in environmental permitting, land use and administrative matters. LIBOW & SHAHEEN LLP, BOCA RATON, FLORIDA Attorney | February 2006 to June 2007 CHRISTINE D. HANLEY & ASSOCIATES, P.A. Law Clerk and Attorney |July 2005 to February 2006 EDUCATION Loyola University Chicago School of Law: 2004 – Juris Doctor Utah Valley University: 2002 Bachelor of Science – Integrated Studies: Political Science, History and English PERSONAL & PROFESSIONAL AFFILIATIONS Alaska State Bar: Admitted 2018 Alaska Chamber of Commerce: Board Member 2018 –2020 South Peninsula Hospital, Inc., Homer, Alaska: Board Member 2018 to Present, Finance and Governance Committees, Chair Education Committee Homer Chamber of Commerce, Homer, Alaska: Board Member 2014 to Present, Vice President 2016- 2017, President 2017-2018, Past President 2018-2019 Executive, Bylaw and Legislative Affairs Committees South Peninsula Hospital Service Area Board: Board Member elected to three-year term from 2015 to 2018 Athena Award Finalist, Women Leaders Under 40, Palm Beach County Florida: The Athena Award is given to women nominated as rising stars and leaders in the community, 2013. Florida Rising Star in Environmental Law: Peer evaluation awarded to only 2.5% of Florida Lawyers, 2009, 2011 Florida State Bar: Admitted 2005, Florida Young Lawyers Division’s District Representative to the American Bar Association - Young Lawyers Division 2010-2012 Term, Student Loan Reform Committee 2010-2012; Council 2010-2012; Executive Council Membership Chair 2011-2012 American Bar Association - State & Local Government Section: Member 2007-2012, Council 2009- 2011, Environmental Committee Vice-Chair 2009-2011, Membership Committee 2009-2011, Electronics Committee 2009-2011 Leadership West Palm Beach: Graduate 2008 Class Florida Airports Council: Environmental and Legal Affairs Committees 2011- Present Marine Industries Association of Palm Beach County, Board Member 2011 - 2013, Boat Show Expansion Committee Friends of the Gumbo Limbo Nature Center, 2011- 2013, Board of Directors 2010-2012 Travis Million travismillion7@gmail.com | (907) 259-1100 | Fairbanks, Alaska linkedin.com/in/travis-million-8804b57a/ ELECTRIC COOPERATIVE CHIEF EXECUTIVE OFFICER Strong managerial background with over 10-years of executive level experience and a solid understanding of electric cooperative principles, operations, and finance. Dynamic leader who can develop cohesive teams, build positive rapport in the community, and has a proven track record. Strong communications skills to include public speaking at local, statewide, regional, and national events. WORK EXPERIENCE Golden Valley Electric Association Fairbanks, Alaska CHIEF OPERATING OFFICER September 2023 - Present Copper Valley Electric Association Glennallen, Alaska CHIEF EXECUTIVE OFFICER March 2020 – Aug 2023 Chief Operating Officer Jan 2016 – Feb 2020 Manager of Power Generation & Compliance June 2015 - Jan 2016 Manager of Power Generation Aug 2011 - June 2015 Duties: • Direct the day-to-day operations and activities of the cooperative • Generation, Transmission, & Distribution cooperative • $150M book assets (over $250M adjusted value) • $25M annual revenue • 44 full time employees • Participate in monthly board meetings • Develop and maintain positive relationships with Legislators on state and federal level • Develop and maintain positive relationships with personnel of multiple state and federal agencies • Active in various contract negotiations to include Union labor and special requirements contracts for industrial and large commercial members Chief Operating Officer • Oversee the following departments: Operations, Production, Engineering, Environmental & Regulatory Compliance, & Safety • CVEA Hydroelectric Facilities – Chief Dam Safety Engineer • Oversee operations of all CVEA generation facilities: Solomon Gulch Hydroelectric Plant (12MW), Allison Creek Hydroelectric Plant (6.7MW), Cogeneration Turbine Plant (5.3MW), Valdez Diesel Plant (9MW), Glennallen Diesel Plant (11MW) • Oversee operation of the 106 mile, 138kV transmission infrastructure and five associated substations • Oversee operation of over 500 miles of overhead and underground 25kV distribution system and associated substations • Oversee all regulatory and compliance for CVEA to include working with the following agencies: FERC, EPA, AKDEC, DOE, EIA, USACE, DNR, BLM • Proven project management with high rate of projects being completed under budget and on schedule • Set company safety records in lowest Workers’ Compensation Modification Factor, OSHA recordable, days away, incident rate, DART rate, and longest streak for no time loss accidents (1,200+ days) AREAS OF EXPERTISE Executive Leadership Strategic Planning Risk Management Member Focused Negotiations Electric Cooperative Expertise Exceptional Communicator Emergency Management Governance Policy Development Financial Planning Personnel Management Team Building Public Administration Value Engineering Technical Innovation Budget Development Project Management Lead Change AWARDS 2023 - NWPPA Safety Contest - First Place 2021 – APA Commitment to Continuous Safety Improvement 2020 – NWPPA Safety Contest – Second Place 2019 - ACEC - Allison Creek Hydroelectric Design-Build Project - Honor Award 2019 - NWPPA Safety Contest - First Place 2018 - NWPPA Safety Contest - First Place 2017 - Alaska Journal of Commerce - Top Forty Under 40 Marsh Creek LLC. / BAE Systems (HAARP) Gakona, Alaska HAARP Site Power Engineer / Feb 2005 - Aug 2011 Health, Safety, & Environmental Manager Schweitzer Engineering Laboratories, Inc. Pullman, Washington Hardware Design Engineering Technician Sept 1999 - Feb 2005 Field Service Engineering Technician Test Operator Assembler ACADEMIC QUALIFICATIONS Cooperative Financial Professional Certificate (CFPC) NRECA/CFC 2019 Dulles, VA MBA Certification University of St. Thomas 2018 Minneapolis, MN Robert I. Kabat NRECA Management Internship Program (MIP) University of Wisconsin 2013-2014 Madison, WI Cold Regions Engineering Short Course Certificate University of Washington 2009 Seattle, WA AAS Electrical Engineering ITT Technical Institute 2000 Spokane, WA COMMUNICATIONS • Alaska State Legislature Testimonies – Multiple • CVEA Annual Meetings • NRECA Safety Leadership Summit • Northwest Hydropower Association Annual Meeting • Northwest Public Power Association Alaska Utility Conference • Alaska Power Association Safety Summit • Alaska Power Association Annual Meetings • Allison Creek Commissioning Ceremony • Valdez City Council/Copper Basin Chamber of Commerce • CVEA social media – Video messaging (multiple) • Published Articles – Ruralite (multiple) • Facility tours for Alaska Governor, Senators, Representatives, Alaska State Chamber of Commerce • Guest lecturer and presenter at local schools ACCREDITATIONS • Incident Command System Training o ICS-100, ICS-200, MGT-345 • CFC KRTA Level 1 Certificate • FERC Division of Dam Safety and Inspections o Dam Safety 101 Workshop o Licensing and Compliance Workshop 201 • NRECA-RESAP Safety Observer Certified • OSHA 501 & 511 – General Industry Train the Trainer • OSHA – 10 Hour Construction Training • OSHA – 30 Hour General Industry Outreach Training • HAZWOPER Technician Level C Certification (40 hour) • 8 Hour HAZWOPER Supervisor Training • Delayed Care First Aid/CPR/AED Certification • NFPA 70E Certification • Method-9 Visible Emissions Testing Certification • EPTC Power Plant Operations Training • EMD 645 Series Technical/Practical Course Certified • ABB LV & MV Breaker Factory Service Certified • NRECA – Credentialed Cooperative Director VOLUNTEER WORK • Alaska Broadband Advisory Board (2023- present) • General Pacific (GENPAC) Board of Directors (2023-present) • Alaska Power Association (APA) Board of Directors (2020-2023) • APA Government Affairs Committee (2021-2023) o Chair (2021 – 2023) • APA Safety Committee (2016-2023) o Chair (2017-2020) o Vice Chair (2016) • NRECA Generation Advisory Committee (2022-present) • National Science Foundation FIREWALL advisory board (2021-2023) • Copper Valley Telecom Board of Directors (2015-2018) • Copper Valley Electric Board of Directors (2008-2011) o President (2010- 2011) o Vice President (2009) • Glennallen Community Chapel Board of Directors (2017-2023) o Chair (2020-2023) o Secretary (2018- 2020) • Copper River Local Emergency Planning Committee (2015-2023) o Vice Chair (2019- 2023) • Little Dribblers Basketball Coach (2007- 2012, 2015-2023) • Financial Peace University/Legacy Journey Coordinator Resume of Brian Hickey 1 Email:brian.hickey@mea.coop LinkedIn: linkedin.com/in/brianhickey01 Summary As a proven executive leader, I bring an extensive background in electric utility operations, encompassing transmission, hydroelectric, thermal generation, and telecommunications. My comprehensive understanding of the energy sector is evidenced by a track record of effectively planning, operating, acquiring, and integrating major utility assets, fostering inter-agency collaboration, and propelling strategic growth. My experience includes direct strategic planning and collaboration with the Boards and CEOs of prominent Railbelt electric utilities, along with proactive advocacy for federal and state funding. I have played a pivotal role in advancing state strategic initiatives related to clean energy standards and grid/transmission reforms, particularly in the development of governance models for ISO/RTO and ERO frameworks. During my tenure at Chugach Electric, my team and I accomplished many things from established a profitable long-haul telecommunications business unit, leveraging our comprehensive microwave and fiber assets to maximize returns for our members to successfully acquiring and merging the two largest utilities in the Railbelt. My capability to navigate complex regional issues has been marked by a consistent track record of maintaining strong relationships across various levels of federal and state government. I am deeply committed to community and social responsibility, ensuring safety, reliability, and efficiency in every initiative I undertake. Experience Executive Director, Railbelt Regional Coordination April 2022 – Present • Reports directly to the CEOs of the five Railbelt Utilities and the Director of the Alaska Energy Authority. • Leads cross-functional teams focusing on regional issues, including advocating for federal funding and strategic affairs related to state clean energy standards and reformation of transmission governance. • Completed successful concept papers and application for $530 million in federal funding. • Led the Railbelt team the recently received $206.5 million in federal funding through the Grid Resilience and Innovation Partnership (GRIP) Topic 3 funding opportunity announcement. When matched this grant will total $413M and fund construction of a second intertie from the Kenai peninsula to the Central region. • Led the Railbelt team that recently was selected to move forward with on a second application for DOE funding to construct a second line from the Central region to Healy. • Established and nurtured relationships with federal and state government officials at multiple tiers (DOE, USDA-RUS, federal delegations, state executive and legislative branches), indigenous groups, and key stakeholders. Resume of Brian Hickey 2 Chugach Electric Association Inc. 2012 - April 2022 Chief Operating Officer November 2018 - April 2022 • Successfully completed the acquisition and integration of Anchorage Municipal Light and Power (valued at ~$1B). • Managed over 300 employees with an O&M budget of approximately $100M. • Enhanced alignment between internal and external stakeholders. Sr. Vice President, System Opera tions July 2016 - November 2018 • Pioneered regional grid unification and strategic planning. • Managed operations for 120 personnel with a ~$30M budget. • Oversaw acquisition strategies and internal leadership development. Executive Manager, Grid Development June 2012 - December 2016 • Directed transmission system and regional grid integration. • Served as an expert witness in regulatory issues pertaining to wholesale customer contracts. • Key achievements: authorization of electric reliability organization in statute, acquisition strategies, and fuel supply planning. Senior Project Manager, Electric Power Systems Inc. August 2010 - June 2012 • Oversaw project phases from initiation to completion. • Highlighted projects: Fort Wainwright power plant refurbishment and Anchorage Regional Landfill gas generation project. Senior Project Manager, NANA-WorleyParsons February 2009 - August 2010 • Led notable projects including feasibility design for remote-site 675 MW gas-fired power plant and evaluations of fuel supply alternatives (Natural Gas, LNG import, coal gasification). Various other positions Chugach Electric Associa tion 1988 - January 2009 Roles included VP of Power Delivery, Director of Technical Services, Manager of Power Control Center, Manager of Substation Operations, and others. Oversaw power system and field operations, facilities, telecommunications, strategic planning, and asset management. Anchorage Municipal Light, and Power June 1984 - Sep 1988 Roles included T&D line design engineer, distribution dispatcher, and relay technician. Resume of Brian Hickey 3 Education • Bolea-Atwater-Applied Leadership Development 2018-19 • M.A., Global Finance & Business Admin, Alaska Pacific University, 2005-2007 • Master's Certificate in Project Management, ESI/George Washington University, 2003-2005 • MIP Certificate in Cooperative Management, NRECA Robert Kabal Program, 2001-2002 • B.Sc., Electrical Engineering, Montana State University, 1978-1984 Licenses Certifications & Memberships • Registered Professional Electrical Engineer (PE), Member IEEE • Pritchett-Certified in Merger & Acquisition Integration • Current member National Association of Corporate Directors and former Board Leadership Fellow • Current Member of Project Management Institute, and former Certified Project Management Professional (PMP) Publications • "Pelton turbine deflector control designs for Bradley Lake hydro units", IEEE American Control Conference, 2002 Volunteering • Denali Federal Credit Union: Supervisory Committee Chair (2008-2014), Board of Directors Member (2014-2018) • Nuvision Federal Credit Union: Board of Directors Member (2018-present) • Rotary Club of Anchorage: Former Member & Fundraising Volunteer • Boy Scouts of America: Former Pack Leader & Adult Leader • Big Brothers and Sisters: Former Big Brother References Available upon Request. Larry Jorgensen Chief Power Production Officer ljorgensen@homerelectric.com 907-335-6160 PROFESSIONAL SUMMARY Larry Jorgensen is a utility professional with over 40 years of operations and generating facility management experience with extensive experience in: managing personnel, budgets, forecasts, projects, outages, reporting, troubleshooting systems, implementation of technical applications to optimize plant performance, analysis of plant data, and training of plant personnel. EXPERIENCE HOMER ELECTRIC ASSOCIATION Chief Power Production Officer | 2016 – Present Ensures the safe and reliable management of generation, transmission, and fuel resources for Homer Electric Association, including the O&M contract to the State of Alaska for the Bradley Lake Hydroelectric Project. Develops and executes strategic long-term planning, reporting, modeling and forecasting of load and generation resources, maintaining compliance with reliability and cybersecurity standards, and multi-year budgeting. Nikiski Combined Cycle Plant Superintendent | 2013 – 2016 Managed an 80 MW combined cycle plant and generation dispatch for HEA’s load balancing area. Responsible for preparing budgets, daily operation and maintenance, long term planning, daily load and generation forecasts, daily gas nominations, and plant outages. Direct reports included an assistant superintendent and four shift supervisor/dispatchers. Served as the main point of contact for all power sales and purchases for HEA. Bradley Lake Hydroelectric Plant Superintendent | 2011 – 2013 Managed a 126 MW hydroelectric facility for HEA and Alaska Energy Authority. Responsible for preparing budgets, daily operation and maintenance, long term planning, and plant outages. Presented operational and maintenance status to the State and participating utilities monthly. Direct reports included five plant operators. DESERET POWER – BONANZA STATION Operations Superintendent | 2006 – 2011 Managed operations department of a 500 MW coal fired plant, which included plant operators, lab technicians, and heavy equipment operators. Responsible for preparing budgets, daily operations, limestone mine, long term planning, operation’s reports. Direct reports included eight supervisors with 49 total personnel in the department. Senior Shift Supervisor / Simulator Specialist | 1999 – 2006 Responsible for administering operations department training and advancement program. Managed high fidelity simulator and provided simulator training to plant operators. Coordinated operations personnel schedules and provided relief coverage for shift supervisors. Shift Supervisor | 1995 – 1999 Managed operations crew. Duties included unit operation, on shift training, reporting, troubleshooting, administering plant lockout/tagout system, and served as incident commander in plant emergencies. Crew consisted of control room operator, five plant operators, lab technician, and heavy equipment operator. Assistant Shift Supervisor, Senior Operator, Control Room Operator, Relief Operator, “A” Operator, Operator Trainee | 1983 – 1995 Advanced from operator trainee through assistant shift supervisor. Promoted to assist crew personnel management and training; provided coverage for control room operators and shift supervisors and performed system troubleshooting. EDUCATION Brigham Young University and Utah State University, 1978-1980 – Match & Computer Science Bismarck State College, 2015 – Associate of Applied Science – Power Plant Technology; 2017 Bachelor of Science – Energy Management, Phi Theta Kappa; April 10, 2024 Hon. Gene Rodrigues Assistant Secretary, Office of Electricity U.S. Department of Energy 1000 Independence Avenue, SW Washington, D.C. 20585 Assistant Secretary Rodrigues, We are writing in support of the application submitted by Alaska Energy Authority (AEA) for FY2024-FY2025 funding through Topic Area 3 of the Grid Resilience and Innovation Partnerships (GRIP) Program. The five Alaska Railbelt electric utilities and the St ate of Alaska’s AEA are working in unison to design, fund and implement a program of grid modernization that will directly benefit the 75 percent of the state’s population connected to the grid and indirectly benefit rural Alaskans who are geographically isolated from the Railbelt but are eligible for Alaska’s innovative rural electric subsidy Power Cost Equalization program. This is a once-in-a-generation opportunity for Alaskans to stabilize an aging grid by bringing it up to modern standards and enhancing resiliency in the face of unprecedented natural disasters, climate change and rugged geographic terrain. These improvements are critical to preparing Alaska for a fuel-diverse clean energy future and integrating new sources of energy along the grid, which spans a distance equivalent to the space between Atlanta, GA and Washington, D.C. The benefit of this work reaches far beyond our state. The Railbelt grid supplies energy to five U.S. military bases of vital strategic importance to national security. These critical assets contribute to the national defense from a broad range of perspectives including missile defense, global telecommunications downlink infrastructure, and F-22 high-speed intercept capability. The Railbelt grid serves the Don Young Port of Alaska, a federally designated strategic seaport which provides virtually all of the cargo, food, fuel and building materials to the majority of Alaskans. And finally, the Railbelt grid serves Ted Stevens Anchorage International Airport – the third busiest airport in the world in terms of cargo throughput. With the U.S. Department of Energy as a partner, Alaska’s utilities and the State of Alaska will be positioned to demonstrate grid revitalization and decarbonization on a scale that can be replicated. Consistent with all relevant rules, laws, and regulations, we respectfully request that all due consideration be given to this application and all other eligible Alaska-based applications. We also ask that you keep our offices appraised of the outcome. Thank you for your consideration. Sincerely, Lisa Murkowski United States Senator Dan Sullivan United States Senator Mary Sattler Peltola Representative for All Alaska Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0003195 RE: Alaska’s Railbelt Grid Modernization and Resiliency Plan To Whom It May Concern, The Alaska Municipal League (AML) is a voluntary, nonprofit, nonpartisan, statewide organization of 165 cities, boroughs, and unified municipalities, wherein over 97 percent of Alaskans reside. Since the passage of the Bipartisan Infrastructure Law, AML has focused its efforts to support strategic regional projects that address the long-standing inadequacy of Alaska’s infrastructure. As part of this effort, we are proud to support projects that improve the condition of communities and intersect with Alaska’s municipalities. We are excited to see the next phase of the Alaska Railbelt’s Grid Modernization and Resiliency Plan (GMRP) move forward. Working to decarbonize Alaska’s Railbelt grid is a particularly timely endeavor – state regulators have recently indicated that the natural gas supply that both power generation and other users rely on may not meet current demand within the next decade. This looming shortage puts economic activity throughout the state at risk by introducing long-term uncertainty to the key services that local governments and other organizations rely on from the Railbelt. With some of the highest energy prices in the country, solutions to control cost are a critical economic challenge facing Alaska’s communities and economic development. It’s important to note that in addressing costs on the Railbelt, these projects also stand to benefit communities across the state via the Power Cost Equalization program. The formula for this critical program ties subsidies for energy across the state to Railbelt prices – thus, if the cost of electricity on the Railbelt is lowered, it provides a greater subsidy to those communities who are experiencing high costs, and in effect lowering the cost to consumers. The GRMP is a strategic and collaborative effort that would go beyond the Railbelt to help make energy and the rural economies that depend on it more affordable and resilient. We fully support the GRMP and its associated projects. Sincerely, Nils Andreassen Executive Director Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0003195 RE: Alaska’s Railbelt Grid Modernization and Resiliency Plan To Whom It May Concern, The Alaska Municipal League (AML) is a voluntary, nonprofit, nonpartisan, statewide organization of 165 cities, boroughs, and unified municipalities, wherein over 97 percent of Alaskans reside. Since the passage of the Bipartisan Infrastructure Law, AML has focused its efforts to support strategic regional projects that address the long-standing inadequacy of Alaska’s infrastructure. As part of this effort, we are proud to support projects that improve the condition of communities and intersect with Alaska’s municipalities. We are excited to see the next phase of the Alaska Railbelt’s Grid Modernization and Resiliency Plan (GMRP) move forward. Working to decarbonize Alaska’s Railbelt grid is a particularly timely endeavor – state regulators have recently indicated that the natural gas supply that both power generation and other users rely on may not meet current demand within the next decade. This looming shortage puts economic activity throughout the state at risk by introducing long-term uncertainty to the key services that local governments and other organizations rely on from the Railbelt. With some of the highest energy prices in the country, solutions to control cost are a critical economic challenge facing Alaska’s communities and economic development. It’s important to note that in addressing costs on the Railbelt, these projects also stand to benefit communities across the state via the Power Cost Equalization program. The formula for this critical program ties subsidies for energy across the state to Railbelt prices – thus, if the cost of electricity on the Railbelt is lowered, it provides a greater subsidy to those communities who are experiencing high costs, and in effect lowering the cost to consumers. The GRMP is a strategic and collaborative effort that would go beyond the Railbelt to help make energy and the rural economies that depend on it more affordable and resilient. We fully support the GRMP and its associated projects. Sincerely, Nils Andreassen Executive Director MATANUSKA ELECTRIC ASSOCIATION, INC. • P.O. Box 2929 • Palmer, Alaska 99645 • t 907.745.3231 • f 907.761.9368 • www.mea.coop April 10, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3 Grid Innovation Program; Railbelt Innovative Resiliency Project Dear Application Review Committee, Matanuska Electric Association, Inc. (MEA) is pleased to team with the State of Alaska, d/b/a the Alaska Energy Authority, and the other Railbelt electric utilities1 to partner in the funding opportunity for Railbelt Innovative Resiliency Project (RIR) (DE-FOA-0003195). MEA is a not-for-profit, member owned, electric cooperative that serves almost 65,000 meters in the fastest-growing area of Alaska. We operate and maintain nearly 4700 miles of power lines, 26 substations and self-generate the majority of our power. MEA is interconnected to the other Railbelt electric utilities via a single transmission line, the majority of which is the Alaska Intertie – a 170 mile long, 345 kilovolt (kV) transmission line between Willow and Healy that operates at 138 kV. Together, MEA and the other Railbelt electric utilities comprise what is commonly referred to as the Alaska Railbelt Electric System and provides electric service to approximately 75% of Alaska’s population. MEA is supportive of the Railbelt Innovative Resiliency Project proposal and hopes that the proposal receives DOE approval. As a not-for-profit, member owned cooperative, MEA has a fiduciary responsibility to our member-consumers, to ensure that MEA’s resources are used wisely and prudently. As essential as the Railbelt Innovation Resiliency Project is to achieve meaningful, transformative, long-term benefits on the Railbelt Electric System, the cost of achieving those benefits cannot, from a practical perspective, be borne solely by our small number of Railbelt ratepayers. Financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically necessary. For that reason, MEA supports the cost allocation methodology outlined in this and other applications being submitted by this project team to the DOE’s Grid Resilience and Innovation Partnerships (GRIP) Program that prioritizes securing Federal IIJA/IRA funds with State of Alaska matching funds for the “non-federal cost share requirement.” If necessary, additional funding will also come from MEA and the other Railbelt electric utilities, subject to successful negotiation of the grant contract and receipt of any necessary Board of Directors, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered from the Railbelt’s member-consumers. MEA has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE IIJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. 1 Chugach Electric Association, Inc., Homer Electric Association, Inc., Golden Valley Electric Association, Inc., and the City of Seward d/b/a Seward Electric System. U.S. Department of Energy Letter of Commitment for Topic Area 3 April 10, 2024 Page 2 MEA fully supports the Railbelt Innovative Resiliency proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan that has and will be submitted to the DOE under separate applications. As the application reflects, there exists unprecedented alignment amongst the Railbelt utilities and the Alaska Energy Authority to materially transform the Railbelt electric system. We are committed to work collaboratively in order to strengthen and build a smart, clean electrical grid that ensures residents, communities, and the military bases served by the Railbelt electric utilities have access to clean, reliable, low-cost energy. Sincerely, Anthony M. Izzo Chief Executive Officer /. , c soc1a 10n PO Box 71249, Fairbanks, AK 99707-1249 • (907) 452-1151 • www.gvea.com April 10, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 Your Touchstone Energy• Cooperative � RE: Letter of Commitment for Topic Area 3: Grid Innovation Program -Railbelt Innovative Resiliency Project To the U.S. Department of Energy, Golden Valley Electric Association, Inc. (GVEA) is pleased to team with the State of Alaska, d/b/a the Alaska Energy Authority, and the other Railbelt electric utilities 1 to partner in the funding opportunity for the Railbelt Innovative Resiliency Project (RIR) (DE-FOA-003195). GVEA is a not-for-profit, member owned, electric cooperative that serves nearly 100,000 residents in Interior Alaska. We operate and maintain nearly 3,300 miles of power lines, 35 substations and nine generating facilities. GVEA's electric system is interconnected with, and has the ability to serve, four critical military installations -Fort Wainwright, Eielson AFB, Fort Greely, and Clear AFS. GVEA is also interconnected to the other Railbelt electric utilities via a single transmission line, the majority of which is the Alaska lntertie - a 170 mile long, 345 kilovolt (kV) transmission line between Willow and Healy that operates at 138 kV. Together GVEA and the other Railbelt electric utilities comprise what is commonly referred to as the Alaska Railbelt electric system and provide electric service to approximately 75% of Alaska's population. GVEA is supportive of the Railbelt Innovative Resiliency Project proposal and hopes that the proposal receives DOE approval. As a not-for-profit, member owned cooperative, GVEA has a fiduciary responsibility to our member-consumers, to ensure that GVEA's resources are used wisely and prudently. As essential as the RIR is to achieve meaningful, transformative, long-term benefits on the Railbelt electric system, the cost of achieving those benefits cannot, from a practical perspective, be borne solely by Railbelt Ratepayers. Financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically necessary. If necessary, additional funding will also come from GVEA and the other Railbelt electric utilities, subject to successful negotiation of the grant 1 Chugach Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., and the City of Seward d/b/a Seward Electric System. DOE Letter of Commitment (GVEA) DE-FOA-003195 Page 2 of 2 contract and receipt of Board of Directors, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered from the Railbelt's member-consumers. GVEA has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE I IJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. GVEA fully supports the Railbelt Innovative Resiliency Project, as well as other aspects of the broader Grid Modernization and Resiliency Plan as defined in the technical volume. There exists unprecedented alignment amongst the Railbelt utilities and the Alaska Energy Authority to materially transform the Railbelt electric system. We are committed to work collaboratively in order to strengthen and build a smart, clean electrical grid that ensures residents, communities, and the military bases served by the Railbelt electric utilities have access to clean, reliable, low-cost energy. 1ef Executive Officer Corporate Office Central Peninsula Service Center 3977 Lake Street 280 Airport Way Homer, Alaska 99603-7680 Kenai, Alaska 99611-5280 Phone (907) 235-8551 Phone (907) 283-5831 FAX (907) 235-3313 FAX (907) 283-2353 April 12, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3, Round 2: Grid Innovation Railbelt Innovative Resiliency (RIR) Project DE-FOA-0003195 Dear Grid Deployment Office: Homer Electric Association, Inc. (HEA) is pleased to submit this letter expressing its support for the funding proposal for improving grid resilience in the Alaska Railbelt. HEA is a not-for-profit, member- owned, electric cooperative that serves the residents, businesses, and industrial facilities on the Kenai Peninsula in the state of Alaska. HEA’s electric system is interconnected with the other Alaska Railbelt electric utilities via a single transmission line between the HEA and Chugach Electric systems. Together HEA and the other Railbelt electric utilities comprise what is commonly called the Alaska Railbelt Electric System and provide electric service to approximately 75 percent of Alaska’s population. HEA supports the RIR proposal and hopes it receives DOE approval. As a not-for-profit, member- owned cooperative, HEA has a fiduciary responsibility to its member-consumers, to ensure that HEA’s resources are used wisely and prudently. As essential as transmission improvements are to achieving, transformative, long-term benefits on the Railbelt Electric System, the cost to HEA’s members to secure those benefits must be understood before HEA can make a financial commitment to participate in funding the project. For that reason, HEA expects financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) to be critically necessary. Accordingly, HEA commits to working with the other utilities and the State of Alaska to develop a mechanism for funding the “non-federal cost share requirement” of the initiatives. HEA’s funding obligation in this regard will be subject to HEA’s final approval of the grant agreement terms and any necessary or appropriate Board of Directors, regulatory, and/or third-party approvals. HEA supports the RIR proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan. As the application reflects, there exists unprecedented alignment among the Railbelt utilities and the Alaska Energy Authority to create a resilient, reliable Railbelt electric system that would be on a par with the systems currently enjoyed by the rest of the country. HEA is committed to working collaboratively to achieve that end. Sincerely, Bradley P. Janorschke General Manager CITY OF SEWARD P.O. Box 167 410 Adams Street Seward, Alaska 99664-0167  Main Office (907) 224-4050  Police (907) 224-3338  Harbor (907) 224-3138  Fire (907) 224-3445  City Clerk (907) 224-4046  Community Development (907) 224-4049  Utilities (907) 224-4050  Electric (907) 224-4073 April 10, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3, Grid Innovation Dear Grid Deployement Office: Seward Electric System (SES), a small municipal power provider that serves approximately 3,000 residents in Southcentral Alaska, is pleased to submit this letter of support for the funding proposal for improving Grid Innovation. SES supports the Railbelt Innovating Resiliency Project (RIRP) proposal and is hopeful the proposal receives DOE approval. SES is the smallest of the Railbelt utilities, but our customers are directly impacted by the investments made to improve the Railbelt grid. Clearly, grid innovation is an initiative that will benefit the many consumers who depend on the Railbelt utilities for clean, reliable and affordable electricity. For the initiative to be successful, financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically important. If necessary, additional funding will also come from the Railbelt electric utilities, subject to successful negotiation of the grant contract and receipt of any necessary board/council, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered in consumer rates. SES has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE IIJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. As the application reflects, the Railbelt utilities are united and are working with the Alaska Energy Authority to materially transform the Railbelt electric system and ensure our members/customers have a secure energy future. Sincerely, Brian Hickey General Manager Seward Electric Systems Prime Applicant/ Team Member Address City StateNine Digit Zip Code (ZIP+4)Alaska Energy Authority 813 West Northern Lights Anchorage AK 99503-2407Mat-Su Borough 350 E. Dahlia Ave. Palmer AK 99645-6411Denali Borough P.O. Box 480 Healy AK 99743-0480Healy Alaska P.O. Box 480 Healy AK 99743-0480Matanuska Electric Association 163 Industrial Way Palmer AK 99645-6703Golden Valley Electric Assocation 758 Illinois Streer Fairbanks AK 99701-2919Homer Electric Association 3977 Lake Street Homer AK 99603-7652Chugach Electric Association 5601 Electron Drive Anchorage AK 99518-1074Seward Electric 238 5th Ave. Seward AK 99664-4400Control Number: 3195-1942Location(s) of Work DocumentationDE-FOA-00031954/16/20243195‐1942_AEA_LOW1 Corporate Office Central Peninsula Service Center 3977 Lake Street 280 Airport Way Homer, Alaska 99603-7680 Kenai, Alaska 99611-5280 Phone (907) 235-8551 Phone (907) 283-5831 FAX (907) 235-3313 FAX (907) 283-2353 April 12, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3, Round 2: Grid Innovation Railbelt Innovative Resiliency (RIR) Project DE-FOA-0003195 Dear Grid Deployment Office: Homer Electric Association, Inc. (HEA) is pleased to submit this letter expressing its support for the funding proposal for improving grid resilience in the Alaska Railbelt. HEA is a not-for-profit, member- owned, electric cooperative that serves the residents, businesses, and industrial facilities on the Kenai Peninsula in the state of Alaska. HEA’s electric system is interconnected with the other Alaska Railbelt electric utilities via a single transmission line between the HEA and Chugach Electric systems. Together HEA and the other Railbelt electric utilities comprise what is commonly called the Alaska Railbelt Electric System and provide electric service to approximately 75 percent of Alaska’s population. HEA supports the RIR proposal and hopes it receives DOE approval. As a not-for-profit, member- owned cooperative, HEA has a fiduciary responsibility to its member-consumers, to ensure that HEA’s resources are used wisely and prudently. As essential as transmission improvements are to achieving, transformative, long-term benefits on the Railbelt Electric System, the cost to HEA’s members to secure those benefits must be understood before HEA can make a financial commitment to participate in funding the project. For that reason, HEA expects financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) to be critically necessary. Accordingly, HEA commits to working with the other utilities and the State of Alaska to develop a mechanism for funding the “non-federal cost share requirement” of the initiatives. HEA’s funding obligation in this regard will be subject to HEA’s final approval of the grant agreement terms and any necessary or appropriate Board of Directors, regulatory, and/or third-party approvals. HEA supports the RIR proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan. As the application reflects, there exists unprecedented alignment among the Railbelt utilities and the Alaska Energy Authority to create a resilient, reliable Railbelt electric system that would be on a par with the systems currently enjoyed by the rest of the country. HEA is committed to working collaboratively to achieve that end. Sincerely, Bradley P. Janorschke General Manager MATANUSKA ELECTRIC ASSOCIATION, INC. • P.O. Box 2929 • Palmer, Alaska 99645 • t 907.745.3231 • f 907.761.9368 • www.mea.coop April 10, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3 Grid Innovation Program; Railbelt Innovative Resiliency Project Dear Application Review Committee, Matanuska Electric Association, Inc. (MEA) is pleased to team with the State of Alaska, d/b/a the Alaska Energy Authority, and the other Railbelt electric utilities1 to partner in the funding opportunity for Railbelt Innovative Resiliency Project (RIR) (DE-FOA-0003195). MEA is a not-for-profit, member owned, electric cooperative that serves almost 65,000 meters in the fastest-growing area of Alaska. We operate and maintain nearly 4700 miles of power lines, 26 substations and self-generate the majority of our power. MEA is interconnected to the other Railbelt electric utilities via a single transmission line, the majority of which is the Alaska Intertie – a 170 mile long, 345 kilovolt (kV) transmission line between Willow and Healy that operates at 138 kV. Together, MEA and the other Railbelt electric utilities comprise what is commonly referred to as the Alaska Railbelt Electric System and provides electric service to approximately 75% of Alaska’s population. MEA is supportive of the Railbelt Innovative Resiliency Project proposal and hopes that the proposal receives DOE approval. As a not-for-profit, member owned cooperative, MEA has a fiduciary responsibility to our member-consumers, to ensure that MEA’s resources are used wisely and prudently. As essential as the Railbelt Innovation Resiliency Project is to achieve meaningful, transformative, long-term benefits on the Railbelt Electric System, the cost of achieving those benefits cannot, from a practical perspective, be borne solely by our small number of Railbelt ratepayers. Financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically necessary. For that reason, MEA supports the cost allocation methodology outlined in this and other applications being submitted by this project team to the DOE’s Grid Resilience and Innovation Partnerships (GRIP) Program that prioritizes securing Federal IIJA/IRA funds with State of Alaska matching funds for the “non-federal cost share requirement.” If necessary, additional funding will also come from MEA and the other Railbelt electric utilities, subject to successful negotiation of the grant contract and receipt of any necessary Board of Directors, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered from the Railbelt’s member-consumers. MEA has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE IIJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. 1 Chugach Electric Association, Inc., Homer Electric Association, Inc., Golden Valley Electric Association, Inc., and the City of Seward d/b/a Seward Electric System. U.S. Department of Energy Letter of Commitment for Topic Area 3 April 10, 2024 Page 2 MEA fully supports the Railbelt Innovative Resiliency proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan that has and will be submitted to the DOE under separate applications. As the application reflects, there exists unprecedented alignment amongst the Railbelt utilities and the Alaska Energy Authority to materially transform the Railbelt electric system. We are committed to work collaboratively in order to strengthen and build a smart, clean electrical grid that ensures residents, communities, and the military bases served by the Railbelt electric utilities have access to clean, reliable, low-cost energy. Sincerely, Anthony M. Izzo Chief Executive Officer AEA Resolution No. 2024-04 Page 1 of 2 ALASKA ENERGY AUTHORITY RESOLUTION NO. 2024-04 RESOLUTION OF THE ALASKA ENERGY AUTHORITY APPROVING THE SUBMITTAL OF THE RAILBELT INNOVATIVE RESILIENCY PROJECT, GRIP 3, ROUND 2 WHEREAS, Resolution No. 2021-3 authorized the Executive Director of the Alaska Energy Authority to work collaboratively with the Railbelt Utilities to prepare a strategic plan including “transmission upgrades addressing capacity, reliability and redundancy” and to “pursue opportunities that will benefit ratepayers”; and WHEREAS, Alaska Energy Authority, in partnership with the Railbelt Utilities submitted a concept paper to the Department of Energy Funding Opportunity Announcement (DE-FOA- 003195) DOE Grid Resilience and Innovated Partnerships(GRIP), Topic 3, Round 2; and WHEREAS, upon review of the submitted concept paper, the Department of Energy notified the Alaska Energy Authority, as the applicant of the concept paper, the concept paper was selected to submit a full grant application; and WHEREAS, the Railbelt Utilities (Chugach Electric Association, Golden Valley Electric Association, Matanuska Electric Association, Homer Electric Association and Seward Electric System) approved authorizing funds for the costs associated with preparing, finalizing, and submitting GRIP 3, Round 2, grant application; and WHEREAS, the grant application proposes Phase 2 of the Railbelt Innovative Resiliency Project (RIR). Phase 2 will construct 250 miles of HVDC transmission line from Beluga in the Central Region near Anchorage to Healy in the Northern Region; and WHEREAS, submitting this application is solely an application for consideration by the Department of Energy and does not commit the Authority to acceptance of any award to expenditure of any funds for the project. WHEREAS, the Alaska Energy Authority has communicated to the Railbelt Utilities that submission of this application does not commit the Alaska Energy Authority or the State of Alaska to providing matching funds for Grant if received; and AEA Resolution No. 2024-04 Page 2 of 2 WHERAS, the Railbelt Utilities endorse the application and commit to exploring funding opportunities for the grant matching funds, if awarded. NOW, THEREFORE, BE IT RESOLVED, BY THE ALASKA ENERGY AUTHORITY AS FOLLOWS: Section 1. The Board authorizes Alaska Energy Authority, as applicant, in collaboration with the Railbelt Utilities, to submit the Railbelt Innovative Resiliency Project (RIR), GRIP 3, Round 2 application. Section 2. The Executive Director is authorized to execute and submit the Department of Energy Funding Opportunity Announcement (DE-FOA-003195) DOE Grid Resilience and Innovated Partnerships (GRIP), Topic 3, Round 2 grant application on behalf of the Authority to the Department of Energy. Section 3. This Resolution takes effect immediately. DATED at Anchorage, Alaska, this 17th day of April 2024. ALASKA ENERGY AUTHORITY _______________________________________ Chair _______________________________________ Secretary The Railbelt Central- Northern Region HVDC Interconnect Control Number:3195-1942 •Project Goal:Strengthen and modernize Alaska's Railbelt Grid to enhance resilience, reliability, and clean energy integration, serving over 75% of the state’s population five critical national defense installations, the third largest air cargo airport in the world, and one of the nation’s US TRANSCOM designated strategic seaports, . •Project Team: Alaska Energy Authority in association with Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, Seward Electric System, and the Regulatory Commission of Alaska. •Key Components:Construction of an HVDC line between The Central and Northern regions of the Railbelt. Wide area integration of the HVDC lines and regional BESS to improve grid stability, transfer capacity, and economic dispatch across Alaska's diverse territories. •Community Impact:Creation of high-quality jobs, reduction in energy costs, and improved energy access for disadvantaged and tribal communities. •Environmental Strategy:Compliance with NEPA to protect natural and cultural resources, ensuring sustainable project development. •Climate Strategy: Reduce dependence on carbon based thermal generation, enhance integration of clean energy •Innovation Highlight:First-of-its-kind wide are integration of HVDC and large-scale BESS technologies to optimize grid performance and energy distribution, paving the way for future renewable energy projects. •DOE Impact:Leveraging DOE funding to enhance infrastructure and enable significant state and private investments, promoting a cost-effective and fuel-diverse energy landscape. •Requested Funding: AEA is seeking $365 million for the $730 million project benefitting 75% of the Alaskan Population including 22 DACs and ANVSAs. Project Graphics Project Location Project Map Alaska in Comparison 3195-1942_AEA_Full Applica�on DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Summary/Abstract Railbelt Central-Northern Region HVDC Interconnect The Alaska Energy Authority (AEA) and the Railbelt u�li�es—including four member-owned coopera�ves and a municipal u�lity—in partnership with the private sector and the federal government under the Bipar�san Infrastructure Law’s Grid Resilience and the Department of Energy’s Innova�ve Partnerships (GRIP) program, aim to transform Alaska’s Railbelt Grid. This ini�a�ve aims to bolster grid resiliency and support a transi�on to a low-carbon economy through innova�ve electrical infrastructure projects. The Railbelt Grid, which serves over 75% of Alaska’s popula�on, hosts five cri�cal na�onal defense installa�ons, the third largest air cargo airport in the world, and one of the na�on’s US TRANSCOM designated strategic seaports, is crucial for the state’s social, economic, and environmental well-being and is cri�cal to na�onal defense. Current limita�ons in grid resiliency hinder Alaska's resilient clean energy future, mo�va�ng this significant upgrade. The AEA is seeking $365 million toward the $730 million project. Project Components: This project involves construc�ng new High Voltage Direct Current (HVDC) transmission lines and integra�ng planned large-capacity Batery Energy Storage Systems (BESS) across mul�ple regions. This setup aims to enhance the interregional transfer capacity, op�mize economic dispatch, and stabilize the grid through advanced control systems. This “first of its kind” project leverages unique collabora�ve efforts among local u�li�es and is poised to set a precedent in grid moderniza�on. Community and Environmental Impact: The project promises substan�al benefits, including increased employment, enhanced community resiliency, and reduced energy costs, par�cularly benefi�ng indigenous people and disadvantaged communi�es. The strategic inclusion of local workforce training programs aims to ensure long-term economic and social benefits. Environmental considera�ons are thoroughly integrated, adhering to NEPA guidelines to mi�gate impacts on natural and cultural resources. Innova�on and Future Outlook: By addressing cri�cal gaps in the exis�ng infrastructure and introducing cu�ng-edge technology, the project sets the stage for a scalable clean energy future. It supports state and na�onal goals for a resilient and sustainable energy framework, significantly reducing dependency on fossil fuels and promo�ng economic growth through enhanced grid capabili�es. Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 1 STATEMENT OF OBJECTIVES (SOPO) Railbelt Central Northern Region HVDC Interconnect A. OBJECTIVE The Railbelt Innovation Resiliency Program (RIR) aims to enhance resiliency and transfer capability among the three regions of the Railbelt. The Railbelt has experienced decreasing frequency regulation, slowed disturbance response, and increased magnitude natural frequency oscillations. The current configuration of the Railbelt system restricts the adoption of clean energy, diversification of the fuel supply, and Alaska’s preparation for a sustainable carbon-free future. A key priority to achieve this objective is to reinforce interconnections between the primary regions of the Railbelt by adding parallel lines and implementing Battery Energy Storage Systems (BESS) to resolve long-standing frequency control and instability issues. Alongside the High Voltage Direct Current (HVDC) submarine cable between Kenai and Beluga (funded in cycle 1) this includes an HVDC line paralleling the existing AKNG pipeline ROW between Beluga and Healy, these additions will alleviate transmission congestion and maximize interregional transfer capability. The project's innovative solutions hold the promise of curbing escalating energy prices, which currently rank among the highest in the nation, while providing rural residents and disadvantaged communities with an opportunity to enhance community viability. Sharing these solutions with other communities will support collective efforts toward achieving clean, reliable, and affordable energy for all. B. SCOPE OF WORK The RIR encompasses three primary components designed to achieve its objectives. The Current RIR Project involves interconnecting the AC Transmission systems of the Central and Northern regions through a DC Bipolar High Voltage Direct Current (HVDC) system. The HVDC system is comprised of a Bipolar HVDC overhead line between Beluga and Healy, connecting the Central region’s existing 230kV AC System to the Northern regions 230kV system. The coordinated interregional control and operation of this line and the other BESS and HVDC assets in the Railbelt will resiliently integrate the three Railbelt regions, enhancing stability and increasing Railbelt-wide resiliency and increasing transfer capacity 2-3 times current capability. The first project, which included the HVDC link from Beluga to Kenai and the regional BESS, received funding from the DOE in its first GRIP funding cycle, totaling a maximum grant of $206.5 million. The objective for Topic 3 in funding cycle 2 is to complement the first project by constructing an HVDC overhead line from Beluga to Healy. This project will finalize the parallel interconnection of all three Railbelt Grid regions. As noted, the new parallel interconnection between Central and Northern regions will not only improve resiliency and reliability but will increase energy transfer capability between the Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 2 regions by 2-3 times. Providing a parallel path assures that all energy will continue to flow if the alternative path is lost. Major load swings between regions are also avoided by increasing system stability and allowing the lines to carry additional capacity, reducing congestion. C. TASKS TO BE PERFORMED Task 1.0: Project Management and Planning (PMP): Subtask 1.1 – Project Management Plan (PMP): Within 30 days of award, the Recipient shall provide the Project Management Plan (PMP) to the designated Federal Project Officer (FPO). The Recipient shall not proceed beyond Task 1.0 until the PMP has been accepted by the FPO. The PMP shall be revised and resubmitted as often as necessary, during the project, to capture any major/significant changes to the planned approach, budget, key personnel, major resources, etc. The Recipient shall manage and direct the project in accordance with the accepted PMP to meet all technical, schedule and budget objectives and requirements. The Recipient will coordinate activities to effectively accomplish the work. The Recipient will ensure that project plans, results, and decisions are appropriately documented, and that project reporting and briefing requirements are satisfied. Subtask 1.2 Community Benefits Plan Within 30 days of award, the Recipient shall revise the Community Benefits Plan (CBP) and submit to the designated Federal Project Officer (FPO). The Recipient shall not proceed beyond Task 1.0 until the CBP has been accepted by the FPO. The CBP shall be revised and resubmitted as often as necessary, during the project execution, to capture any major/significant changes to the CBP with regard to the four priority goals; Community and Labor Engagement; Investing in the American Workforce; Diversity, Equity, Inclusion, and Accessibility; and Justice 40 Initiative. The Recipient will coordinate activities to effectively implement the CBP goals. The Recipient will ensure that metrics, SMART community benefits plan commitments, and outcomes are appropriately documented, and that reporting and briefing requirements to stakeholders are satisfied.” Subtask 1.3: National Environmental Policy Act (NEPA) Compliance Sub Task 1.3.1: Permitting – Undertake EIS and apply for permits from appropriate agencies. Subtask 1.3.1.1 – Notice of Intent to Prepare EIS Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 3 Subtask 1.3.1.2 – Scoping process –DOE names lead agency; Federal agency begins the scoping process by publishing a Notice of Intent (NOI). The NOI describes the project and provides background on potential impacts. The public provides comments on the proposed project, proposed alternatives, and environmental impacts. Applicant holds public meetings to obtain comments. Meetings beyond the scope of those traditionally required in the EIS process may be required by the project’s CBP. Subtask 1.3.1.4 – Notice of Availability of Draft EIS – the Draft EIS presents, analyzes, and compares potential environmental impacts and proposed actions for mitigation. Subtask 1.3.1.5 – Notice of Availability of Final EIS – EIS prepared and distributed including comments from Draft EIS. Subtask 1.3.3 – Record of Decision – Notice of decision and rationale for decision giving factors such as cost, technical feasibility, agency and national objectives, and environmental impacts of any actions. The Applicant will undertake an Environmental Impact Study (EIS) with a lead agency (DOE) to identify and analyze possible adverse environmental impacts and investigate reasonable alternatives as appropriate. As required, the Recipient shall provide the documentation necessary for NEPA compliance. Subtask 1.4: Cybersecurity Plan (CSP) The Applicant will focus its efforts on protecting the Federal systems and its networks from cyber threats. The plan will incorporate processes to identify, investigate and mitigate threats from targeted phishing, denial of service attacks, and the introduction of malware into the system. A coordinated effort with the State, the utilities, and DOE will be undertaken to implement the tools necessary to provide continuous diagnostics and mitigation. The plan will be compliant with AKCIP standards. A full cybersecurity plan will be submitted during award negotiations and prior to receiving project funding. The CSP shall be revised and resubmitted as often as necessary, during the course of the project, to capture any major/significant changes. Subtask 1.5: Continuation Briefing(s): A continuation briefing will be done on an annual basis to explain the plans, progress, and results of the technical effort. Task 2.0: Design, Permitting and Siting – Design criteria for transmission lines, substations, cables, and converter stations. Subtask 2.1 – Risk Evaluation – Evaluate transmission components. Subtask 2.1.1 – Evaluate new transmission corridor for known events such as CBP input, avalanche, seismic, wildfire, heavy snow and ice loading. Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 4 Subtask 2.1.2 – Evaluate potential ROW or cable routing particularly around Denali State and National parks. This effort is broken into five phases based on primary land ownership or responsible agencies. Subtask 2.1.3– Evaluate potential uses of the parallel AKLNG Pipeline Right of Way as a buffer for natural conditions and obstacles (such as uphill tree impingement, river ice or drift snow accumulation) No impact or impingement on the AKLNG ROW is intended or implied in this analysis without prior approval of the Alaska Gasline Development Corporation Subtask 2.2 – Design Criteria – Develop tailored and innovative design criteria to mitigate input and risks identified in 2.1. Evaluate alternative routing alignment as necessary. Subtask 2.3 – Preliminary Design – Engineer for lines, converter stations, potential cable sections, foundations, anchors, guys, structure type, span length, conductor size, design, and sag. Evaluate potential right-of-way alignment, land ownership and permit requirements. Task 3.0: Public Notice – Consistent with the CBP provide public notice of intent to construct, provide data, seek input, and provide feedback. Adjust design and routing as necessary to secure permits. Task 4.0: Final Design & Engineering – Prepare final design documents for permitting and construction. Task 6.0: Procurement – Secure long-term materials such as insulators strings, inverters, converters, transformers, steel structures, and specialized equipment. Task 7.0: Construction – Undertake construction process Subtask 7.1 – Solicitation – prepare construction documents and evaluate most cost- effective method to seek bids. Subtask 7.2 – Award – Award contracts for construction Subtask 7.3 – Construction Management – Initiate project management office Subtask 7.4 – Construction Close Out Process Task 8.0: Testing & Commissioning – Undertake final inspection, energization, and system coordination testing with regional BESS and Southern-Central HVDC system, cutovers as necessary. D. DELIVERABLES I. Management Reporting a. Progress Report b. Project Management Plan (PMP)and updates c. NEEPA Compliance Environmental Impact Statement (ROD) Grid Resilience and Innovation Partnership (GRIP) U.S. Department of Energy DE-FOA-0002740 Control Number 3195-1942 5 d. Community Benefit Plan and updates e. Cybersecurity Plan and updates f. Continuation Briefings g. Final study results and system benchmarking on the impact of inverter-based resources on grid voltage stability and short circuit current ratio at variable generation penetration present at commissioning. II. Financial Reporting III. Closeout Reporting E. BREIFINGS/TECHNICAL PRESENTATIONS Briefings and technical presentations will be prepared as requested by the Federal project Officer which will include at a minimum those listed below. Kickoff Briefing - Not more than 60 days after submission of the Project Management Plan, the Recipient shall prepare and present a project summary briefing as part of a Project Kickoff Meeting. Pre-Continuation Briefing - Not less than 90 days prior to the completion of approximately twelve (12) calendar months (no more than eighteen (18) months) of project execution, the Recipient shall brief the DOE on the performance relative to project success criteria, milestones, Go/No-Go Decision point metrics that are documented in the Project Management Plan (PMP), and their plans for the subsequent periods of work. The Go/No-Go Final Project Briefing - Not less than 30 days prior to the end of the project, the Recipient shall prepare and present a Final Project Briefing on the results and accomplishments of the entire project. Other Briefings – The Recipient shall prepare, and present technical, financial, and/or administrative briefings as requested by the DOE. A project technical review briefing will be conducted no less than annually. Additionally, the DOE may require Recipients to make technical presentations at national and/or industry conferences.” 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 1 April 17, 2024 Cover Page Topic Area 3: Grid Innovatfon Title: Railbelt Central-Northern Region HVDC Interconnect Applicant: The Alaska Energy Authority representfng the State of Alaska Business Point of Contact: Curtfs Thayer, Executfve Director, Alaska Energy Authority Technical Point of Contact: Jim Mendenhall, Program Manager, Alaska Energy Authority The Alaska Energy Authority and Railbelt utflitfes are partners on this project, representfng all the primary transmission owners and operators of Alaska’s largest electrical grid (the Railbelt) as collaboratfve decision-makers. The project partners include: 1. The Alaska Energy Authority (AEA), Executive Director: Curtis Thayer 2. Chugach Electric Association, Inc., (CEA), Central Region Cooperative; CEO: Arthur Miller 3. Golden Valley Electric Association, Inc., (GVEA), Northern Region Cooperative; John Burns: CEO 4. Homer Electric Association, Inc., (HEA), Southern Region Cooperative; CEO: Brad Janorschke 5. Matanuska Electric Association, Inc., (MEA), Central Region Cooperative: CEO: Tony Izzo 6. The City of Seward, Alaska, dba Seward Electric System, Southern Region Municipal Utility (SES); Brian Hickey, General Manager 7. The Regulatory Commission of Alaska (RCA) is participating as a team member in an advisory and regulatory role, as permitted by statutory authority) Chairman: Bob Doyle Project Location: All three regions (Northern, Central, and Southern) of the Alaska Railbelt electrical grid. Figure 1 The Railbelt Region and Scale 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 2 April 17, 2024 Table of Contents Cover Page .................................................................................................................................. 1 Project Overview ......................................................................................................................... 3 Project Goal: ............................................................................................................................ 6 DOE Impact ............................................................................................................................. 7 Community Benefits Plan: Job Quality and Equity ..................................................................... 8 Constraints on Resources ........................................................................................................ 9 Climate Strategy ...................................................................................................................... 9 Climate Resilience Strategies for Electricity: ........................................................................... 9 Technical Descriptfon, Innovatfon, and Impact ........................................................................... 9 Relevance and Outcomes ........................................................................................................ 9 Feasibility .............................................................................................................................. 10 Innovatfon and Impacts ........................................................................................................ 14 F.6 Topic Area 3: Grid Innovatfon Program ....................................................................... 14 Workplan ................................................................................................................................... 15 Project Objectfves ................................................................................................................. 15 Technical Scope Summary ..................................................................................................... 16 Work Breakdown Structure (WBS) and Task Descriptfon Summary ..................................... 18 Go/No-Go Decision Points (See Sectfon VI.B.xv. for more informatfon on the Go/No-Go Review) .................................................................................................................................. 21 End of Project Goal ............................................................................................................... 21 Project Schedule (Gantt or similar) ....................................................................................... 22 Project Management ............................................................................................................ 22 Technical Qualificatfons and Resources (Approximately 20% of the Technical Volume) .. 24 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 3 April 17, 2024 Project Overview Through the Bipartfsan Infrastructure Law’s (BIL) Grid Resilience and Innovatfve Partnerships program (GRIP), the Alaskan Energy Authority (AEA) and its four small-utflity, member-owned cooperatfves are seeking funding for this once-in-a-generatfon opportunity to build resiliency and develop a fuel-diverse, low-carbon economy by investfng in essentfal electrical infrastructure. Alaska’s largest—but electrically islanded—grid serves over 75 percent of the state’s populatfon. Termed the Railbelt grid, it includes 17 Alaskan Natfve Village Statfstfcal Areas (ANVSAs) as well as 22 census tracts in Disadvantaged Communitfes (DACs), primary commerce and shipping centers, critfcal-operatfon military bases, and access areas for key mineral deposits. The Railbelt plays a vital role in shaping the social, economic, cultural, and environmental landscape of Alaska, serving as a gateway to the state’s vast and diverse territories. Its significance extends beyond regional boundaries, as it influences the trajectory of the state’s development and identfty. Deficiencies in this grid’s resiliency undermine the state’s ability to usher in a clean energy future. The collectfve mission of the State of Alaska and the interconnected Railbelt utflitfes is to build a resilient, clean, smart, and low-cost electrical grid. This grid must support a fuel-diverse energy landscape that drives reliable and sustainable economic development in Alaska and ensures a cost-effectfve delivery of energy to Railbelt consumers, including defense infrastructure and more. As part of the broader Grid Modernizatfon and Resiliency Plan (GMRP), the Railbelt Innovatfve Resiliency Program (RIR) will construct new high-voltage direct current (HVDC) transmission lines parallel to the existfng single regional tfes. The HVDC system will be comprised of Project 1 a submarine circuit and overhead HVDC interconnects between the Kenai Peninsula and Beluga, and Project 2 a HVDC overhead line between Beluga and the town of Healy. Project 1 also integrates three large-capacity (40-70 MW; 2-hour) Battery Energy Storage Systems (BESS), one in each region. The HVDC -BESS system Figure 2 The Grid Modernization and Resiliency Plan (GMRP) Current project Railbelt Innovative Resilience (RIR)project in yellow 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 4 April 17, 2024 will feature wide area integrated and coordinated inter-regional control and operatfon of the three regional BESS and two HVDC lines to maximize transfer capacity and optf mize economic dispatch. This system will be technologically innovatfve—the first of its kind based in part on the unique collaboratfon of these entftfes. The purpose of the GMRP is to create programs that will significantly increase resiliency and transfer capability of the inter-regional transmission system, thus facilitatfng diverse clean-energy optfons for the future of Alaska. The GMRP is broken into two programs whose purpose is to reconstruct the Railbelt’s existfng lines: the Railbelt Backbone Reconstructfon Program (RBR) and the Railbelt Innovatfve Resiliency Program (RIR), which constructs innovatfve parallel interconnects with Battery Energy Storage Systems (BESS) between regions. The RIR specifically and the broader GMRP allow small electric- utflity providers from Fairbanks to Homer and Valdez to partfcipate, with the goal of driving down consumer costs via economies of scale; to utflize modern technologies such as energy storage to stabilize grid resiliency; and to integrate renewable energy seamlessly into the Railbelt grid. The RIR is broken into three projects: The first (Project 1) was DOE-funded during funding cycle 1 (F- 1). The project referred to in this applicatfon constftutes Project 2. Project 1 includes the HVDC link from Kenai Peninsula to Beluga and the regional BESS. As noted, Project 1 received funding from the DOE in its first F-1 funding cycle, with a maximum grant of $206.5 million. Project 2 is the HVDC interconnect between the Central and Northern regions. Project 2 is estfmated to cost $730M, with our request for a DOE grant of $365M. Project 3 is a long-term vision of an interconnectfon from the Central region through Glenallen to Fort Greely. Background The Railbelt electric grid is unique in North America as it is technically a fully functfoning, long- distance electrical grid designed on a very small scale. It encompasses three load-generatfon regions with four load-balancing areas. These are the Northern region (Fairbanks-Delta Junctfon), the Central region (Anchorage-Matanuska-Sustfna-or Mat-Su-Valley), and Southern region (the Kenai Peninsula); they are tfed together with two long transmission lines operatfng variously at 115kV and 138KV. The grid provides electricity to approximately 75 percent of the state's residents and generates 80 percent of the electricity in Alaska. It extends over 700 miles from the Bradley Lake Project located at the head of Kachemak Bay near Homer in the Southern region, to Delta Junctfon in Interior Alaska—roughly the distance from Washington, DC, to Atlanta. The grid transverses inhospitable, subarctfc, mountain terrain, along with the Cook Inlet, with its tremendous tfdes and currents. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 5 April 17, 2024 Climate change is dramatfcally affectfng Alaska. The state is laced with highly actfve seismic zones and is subject to volcanic eruptfons, droughts, forest fires, flooding, landslides, tsunamis and fierce annual winter storms. The Railbelt grid's assets vary from high-voltage (138 kV and 230 kV) submarine cable crossings in Cook Inlet1 to remote helicopter/riverboat-access-only river crossings and numerous transmission structures located in subarctfc climates that are well above 2,000 feet in elevatfon with the tree-line oflen well below 2,000 feet and extraordinarily harsh conditfons. Unlike numerous areas in the contfguous 48 states, the Railbelt received minimal federal investment in grid development prior to the GRIP F-1 award. The Eklutna Hydroelectric Project, initfally constructed in the 1950s, was the last major federal project in the Railbelt that included a transmission-line component. This project was rebuilt by the Bureau of Reclamatfon's Alaska Power Administratfon following an earthquake in 1964 and sold by the federal government to Central region utflitfes in the early 1990s. 1 Cook Inlet is a silt laden 180-mile inlet reaching from Knik Arm to the Gulf of Alaska. The Inlet has the fourth highest tidal range in the world at 35 feet and contains an endangered subspecies of the beluga whale. Railbelt Grid Figure 3: Alaska’s Relative Size 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 6 April 17, 2024 Due to the high cost of transmission lines, the regions are moderately interconnected, primarily at 69kV, 115kV, 138KV, 230kV. A tfght power pool2 operates in the Central region, and an actfve economy-energy market exists between regions but is severely limited by transmission constraints. There is no formal interconnectfon queue. A reserve-sharing pool exists between all three regions, but historically, the regions have planned for capacity separately due to weak interconnectfons. The Railbelt grid is technically characterized as "transient stability limited," with machines under dynamic stress swinging power-output against other machines within the region and with regions swinging against each other across light inter-regional interconnectfons. These power swings resolve in mechanical forces which stress, and sometfmes over-stress, generator windings, rotors, stators and other mechanical equipment. The grid is also susceptfble to and has experienced large-scale,3 small-signal instability oscillatfons, which lead to outages and damage power equipment. Voltage stability, which varies from marginal to good depending on the specific area, has been improved with the additfon of six statfc VAR compensators at critfcal locatfons. The Railbelt grid operates under a subset of North American Electric Reliability Corporatfon (NERC) standards modified to account for the scale and nature of the interconnectfon (the grid's system bias is variable and ranges from 3-10 MW/.1 hertz). The grid has a sophistfcated under-frequency load-shed scheme which sheds load to match generatfon in four stages, with varying tfme delays and, in some cases, considering frequency rate-of-change. Traditfonal day-ahead and real-tfme security-constrained economic dispatch is run in each of the Load Balancing Areas (LBA) with net interchange, and frequency monitored and managed to NERC Control Performance Standards 1 and 2. Dynamic events on the grid occur and resolve very quickly (in 2 to 10 seconds) when compared with the much larger North American grids which resolve in tens of minutes. The grid's peak demand is roughly 750 MW compared to that of Texas’s ERCOT system, which has a peak demand of 85,000 MW. The grid's annual energy consumptfon is approximately 4,500 GWH compared with ERCOT’s 339,000 GWH. Project Goal: This improved grid must support diversified energy landscape that drives sustainable economic development in Alaska and ensures a cost-effective delivery of energy to Railbelt consumers 2 Tight Power Pool is a term of art indicating the commitment required by the parties within a power pool. Loose pools are generally economy energy contracts, and tight pools generally require a single dispatch and a single Load Balancing Area. 3 Oscillations have been measured with a peak of 220 MW, a 1.1 second period and sustained for over 90 seconds on a grid with a summer valley peak load of approximately 500MW. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 7 April 17, 2024 and beyond. As noted, the Railbelt utflitfes and the state of Alaska share a vision: a collaboratfve future in the Railbelt in which our communitfes come together and share resources to strengthen and build a smart, clean electrical grid that promises our residents, our natfonal defense infrastructure, and communitfes adjacent to the Railbelt access to clean, low-cost energy from any source. Other goals include reducing reliance on fossil fuels; documentfng lessons learned, partfcularly relatfng to penetratfon of inverter-based resources and voltage stability; and the development of innovatfve rate-making strategies on which to incentfvize prudent transmission development. DOE Impact DOE investment is critical to mobilizing additional state and utility capital. Accomplishing a project of this magnitude in a 10-to-15-year tfme frame is beyond the financial capabilitfes of the Railbelt utflitfes without significant rate increases. The burden of such rate increases falls on all ratepayers, but disproportfonately on the disadvantaged and underserved. With the completfon of this project, fuel burn (which represents about 40 percent of an average consumer’s bill) may be reduced 10 to 15 percent, exclusive of increased clean-energy development. The requested $365 million in DOE funding has the potentfal to unlock an additfonal $700 million to $1 billion in non-federal and utflity funding, significantly enhancing the Railbelt transmission system and boostfng clean-energy productfon in the region. In combinatfon with the GRIP F-1 project, this will be the largest grid-infrastructure project undertaken in the Railbelt since the interconnectfon of the Central and Northern regions in 1984. The benefits will be significant and comparable to the recent economic benefit derived from convertfng the Railbelt generatfon fleet from GE Frame units to aero -derivatfve units—a conversion that reduced fuel burn (carbon emissions) by nearly 30 percent. The benefits of the RIR will include improved fuel-efficiency, reduced carbon emissions, increased variable- generatfon penetratfon, increased private capital investment from IPPs in energy development, and reduced O&M. Another benefit will be extended transitfon tfme for moving away from Cook Inlet natural gas4. Finally, the project will promote coordinated energy- and capacity-planning across the Railbelt. 4 The Cook Inlet Field provides heat to 140,000 homes and businesses in the Central region and is used to generate 70 percent of the electricity in the Railbelt. In early 2021, the field’s only remaining large-scale producer notified utilities (both gas and electric) that they would not extend existing gas contracts, most of which expire in 2028. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 8 April 17, 2024 Community Benefits Plan: Job Quality and Equity Through Alaska’s unique Power Cost Equalizatfon (“PCE”) program, improvements in Railbelt transfer capability, reliability, and resiliency will stabilize long-term power costs for the numerous tribal and disadvantaged communitfes on the Railbelt as well as rural villages outside the Railbelt. The Alaskan IBEW (Internatfonal Brotherhood of Electrical Workers) leadership has identffied this as an opportunity to train a new generatfon of linemen and wiremen, reinvigoratfng this sector of Alaska’s technical workforce. The broad and inclusive outreach program envisioned in our CBP will ensure that maximum benefit flows to diverse and disadvantaged communitfes on the Railbelt. The Beluga-Healy HVDC Line project will directly benefit people within Alaska Natfve Village Statfstfcal Areas (ANVSAs) and DACs in Alaska’s Railbelt region. The project will construct 250 miles of HVDC transmission line from Beluga, near Anchorage in the Central Region, to Healy in the Northern Region. This HVDC line will enable Railbelt utflitfes to transfer low-cost and reliable power to where it is most needed. Beluga-Healy HVDC Line community benefits outcomes and objectfves include:  A robust public participation plan followed by a public AEA memo responding to stakeholder feedback  Increased transfer capacity between regions to enable higher renewable-energy integration and a reduction in fossil fuel generation and associated emissions  Improved long-term air quality in communities near fuel-based power generation, including ANSVAs and DACs  Energy-access resiliency and reliability improvements for ANVSAs and DACs on the Railbelt  Retention of over 650 highly paid union jobs with competitive, employer-sponsored benefits  Creation of over a thousand high-value construction and support jobs  Creation of numerous ongoing positions at utilities  Creation of apprenticeship and internship programs to reinvigorate Alaska’s energy workforce, including local-hiring preference  Decreased Railbelt community energy burdens from reduced line loss and thermal spending. A one cent per kWh reduction in the average cost of Railbelt power saves $44,080,000 annually.  The same reduction in the average cost of Railbelt energy will result in decreased off-Railbelt community energy burdens via increased Power Cost Equalization (PCE) with potential consumer PCE credit increases of $1.5M annually The project team will coordinate with partfcipatfng tribal councils on the Railbelt to promote local hiring and open dialogue with this key stakeholder group. Procurement will comply with Alaska public-contractfng law, which contains provisions for local hiring, apprentfceship training, prevailing wages, and other forward-looking policies. The project will partner with the IBEW-NECA, the Alaska Joint Electrical Apprentfceship and Training Trust (AJEATT), the Alaska Natfve Science & Engineering Program (ANSEP) and the Alaska Operatfng Engineers/Employers Training Trust 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 9 April 17, 2024 (AOEETT) to source apprentfceship candidates and ensure the development of a skilled, inclusive local workforce. Constraints on Resources An evaluatfon per NEPA EIS process will be completed to identffy any areas of sensitfvity to the environment or to Tribal cultural resources. This is a critfcal step, as the line will extend through state and natfonal park systems as well as through or in close proximity to ANSVAs identffied in the project area. All best-practfce protocols identffied will be incorporated into the project executfon. Climate Strategy As previously discussed, the Railbelt region of Alaska spans a distance further than that of Washington DC to Atlanta. The climate challenges and extreme weather patterns the region encounters—or is at risk of encountering—include frequent thunderstorms, heavy and sustained precipitatfon, earthquakes, volcanic actfvity, avalanches, flooding, changes in permafrost conditfons, high winds, coastal erosion, landslides, droughts, wildfires, tsunami potentfal, and sea-ice dynamics. Climate Resilience Strategies for Electricity: Upgrade grid to allow for high clean energy and variable renewables penetratfon: The Railbelt grid is an interconnected electrical transmission system reaching from Homer to Fairbanks and then on to Delta Junctfon, approximately 700 miles further. It supplies electricity throughout this region. The network consists of various utflitfes, the state, and Independent Power Producers (IPPs) that allow sharing to meet demand fluctuatfons and ensure system reliability. Upgrading the infrastructure will better integrate this power (partfcularly variable resources like wind and solar) into the Railbelt, ensuring better system reliability and fewer and shorter power outages. Reducing greenhouse gas emissions and improving access to power: Promotfng energy diversificatfon and minimizing the use of traditfonal fossil fuel-based generators will reduce harmful greenhouse. Reductfon of carbon emissions supports forest and stream health, strengthening community well-being through subsistence and other traditfonal uses of the land. Technical Description, Innovation, and Impact Relevance and Outcomes This project aligns perfectly with the FOA goals; transforming community, inter-regional and natfonal resiliency including consideratfon of future shifls in generatfon and load; catalyzing and leveraging state and private-sector spending for impactiul technology and infrastructure development; and advancing community benefits especially to disadvantaged and tribal communitfes. Further, the project will provide training and job opportunitfes for the next 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 10 April 17, 2024 generatfon of power system line workers, electricians, equipment operators, technicians, and engineers. The project consists of an HVDC overhead line (with potentfal cable sectfons where resiliency, NEPA, or other requirements deem it prudent) and Voltage Source Converter (VSC) statfons at Beluga and Healy interconnectfng the HVDC with the existfng transmission system. The line will likely be a 150 kV /200 MW bipolar line for enhanced transfer capability and increased resiliency; however, these specificatfons will be finalized in final design. The project will complete a parallel transmission path between the Northern and Central regions, immediately enhancing reliability and improving resiliency and economic dispatch between the two regions by reducing the dispatch of thermal generatfon and thereby reducing carbon emissions. These enhancements in turn will provide more resilient and reliable grid power to the five critfcal military installatfons served by the Railbelt strengthening our natfonal defense posture. Once the project is fully integrated into the southern-central HVDC interconnectfon and the regional BESS, these benefits will increase significantly. The project will ensure grid reliability by increasing inter-regional transfer capability, allowing for diversificatfon of fuel supply, acceleratfng the adoptfon of variable renewable generatfon, reducing carbon emissions, improving frequency regulatfon, and aiding in eliminatfng potentfally catastrophic small signal instability oscillatfons. This project was identffied as a key requirement for a cost-effectfve, fuel- diverse, clean-energy future in the Alaska’s Energy Security Plan, published in December 2023.5 Feasibility The Railbelt is transmission-constrained, meaning the grid is only able to move 10 percent or less of its peak load between regions. These constraints, caused by transient stability limitatfons and small signal instability, limit the grid’s ability to cost-effectfvely deploy large-scale, renewable projects. Further, Railbelt utflity engineers have observed several concerning trends on the Railbelt over the past decade. These 5 Alaska Energy Security Task Force. (2023, December 1). Alaska Energy Security Task Force Report, p. 36. Figure 4 Distribution of Railbelt Frequency Readings over time 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 11 April 17, 2024 challenges include the degradatfon of frequency regulatfon; decreasing system-frequency response to generatfon trip disturbances; and increasing magnitude and duratfon of natural- frequency power oscillatfons and occasional large power swings, which impact the entfre Railbelt (see figures 4, above, and 5, below). The displacement of thermal generatfon with renewable generatfon such as wind or PV will further decrease inertfa in each region and may negatfvely impact stability across single inter-regional transmission lines. These phenomena are thoroughly described, and their solutfons are explored in detail in studies referenced below6. The completfon of the HVDC line stretching from Beluga to Healy will serve as a crucial and significant element of this solutfon. The Railbelt’s Northern region is interconnected to the Central region by a single, 200-mile-long transmission line. The Northern region, with the highest energy costs in the Railbelt, desires to import as much energy from the Southern and Central regions as is technically and reliably feasible. The existfng transmission line has a stability limit of 65-84 MW, approximately a third of the line’s thermal limit. Currently, the line has to be de- energized for several weeks at a tfme due to severe icing or structural damage at one of the many river crossings; these events can occur multfple tfmes per year depending on weather. Due to the single contfngency line, the Northern system is limited in the amount of variable renewable generatfon it can import from the Central and Southern regions into its system, which does not have base-load hydro-generatfon on-line to provide grid strength as measured by Short Circuit Ratfo (SCR) following the loss of the tfe to the Central region. The extremely low SCR following the loss of the single line puts the system with its large motors, and the existfng SVCs and BESS, at risk. 6 Bansal A, Anantharaman A, Donlagic T, Feltes T, Orikhi Z, Rachinger S, Silva D, Grande -Moran C; Alaska Railbelt Power System Oscillation Anchorage Bess unit Impact Analysis; 10-20-20; SPTI P# 620T-001718 6List B, Amrein J, Heimann A, Furtner N, Keck H, Dorfler P, Hickey B, Stead D, Bradley Lake Deflector Divider Model Tests; 9-10-2004 VA TCH Hydro 6Cote J, Burlingame D, Lai D; Railbelt Oscillation Investigation and Mitigation study; 3-1-22; Electric Power Systems Inc. Figure 5 System Oscillations Resulting from Trip of the Existing Central-Northern Region Intertie 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 12 April 17, 2024 The proposed Beluga–Healy line is projected to enhance transfer capabilitfes between regions by two to three tfmes. The plan is to evaluate the impact of integratfng inverter-based HVDC/BESS— along with wind and solar generatfon—on voltage stability and the short circuit ratfo in order to provide real-world data. This data will be scalable and valuable for planning within larger grids, both in the U.S. and globally. The new line will allow Northern region wind and PV resources to be totally developed as part of the integrated grid instead of in isolatfon. Regulatfon will be performed over multfple regions, significantly reducing integratfon costs for renewable resources. The geographical diversity of wind resources will reduce the overall variability of wind and solar resources, reducing the financial impact of the regulatfons that are required by the use of thermal resources. The Beluga-Healy line will allow the Northern region to operate without thermal generatfon during much of the year, but it will be available when system conditfons or climate events warrant it, or when renewables are unavailable. Further, the proposed routfng of the line along the existfng AKLNG pipeline will open access to new wind resources that are currently unavailable in that geographic area. The combinatfon of the Beluga – Healy line with the Kenai – Beluga line and regional BESS will virtually eliminate transmission constraints on clean-energy development in the Railbelt. Additfonal lines and upgrades may be needed to establish specific renewable projects. However, the bulk of the benefits to the Railbelt are realized with these two transmission lines. To understand the project’s technical contributfon and feasibility, please refer to Figure 6 and Figure 6A. These figures provide a mechanical analog representatfon of transient stability between two regions, namely the Central/Southern and Northern regions. In AC power system transmission, two key concepts are critfcal: First, generatfon and load must always maintain near-perfect balance; second, real power transfer across a transmission line is achieved by increasing the voltage phase angle difference at the sending end relatfve to the receiving end. Figure 6 uses the analogy of drums and a spring to represent the transmission line between two areas, where the weight symbolizes the power transferred, and the spring stfffness reflects the line's interconnectfon strength. As power transfer increases, symbolized by the weight, the arms— held only by the spring—begin to separate. This separatfon angle, denoted as δ, represents the power-transfer angle between the sending- and receiving-end voltages. An excessive power transfer can lead to the arms falling below horizontal, illustratfng a system collapse or an “out-of-step” Figure 6 Mechanical Analog of AC transmission 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 13 April 17, 2024 conditfon. Oscillatfons in the arms, stfmulated by pulling and releasing the weight, mimic the grid's response to rapid load or generatfon changes or faults, (disturbances) which can lead to out-of-step conditfons if uncontrolled. These disturbances to the generatfon -load balance are caused by physical events such as trees inadvertently contactfng lines, generators tripping oftfine, equipment failures or rapid loss of wind or solar resources due to meteorological changes. In contrast, DC systems, partfcularly those utflizing VSC technology, offer greater control. Here, DC voltage adjustments at the sending and receiving ends manage power transfer, akin to controlling system frequency and phase angle in AC systems. DC voltage management is performed by the VSC-Insulated Gate Bipolar Junctfon Transistor (VSC-IGBT) based converter statfon analogous to the high-speed controller in figure 6A. Installing an HVDC line between the Central/Southern and Northern regions introduces a shock absorber—adjustable in real-tfme for length and stfffness—in parallel with the mechanical spring. This additfon enhances the system's capacity to handle increased power transfers and dampen oscillatfons. When integrated with Battery Energy Storage Systems (BESS) and the Southern HVDC, this combined setup acts as a four-quadrant actfve device able to deliver and absorb both real and reactfve power. It injects energy to counteract oscillatfons and regulate frequency, thereby amplifying the stabilizing effect throughout the grid. Integratfng these geographically diverse resources in real-tfme represents a truly innovatfve solutfon for managing grid flows and is likely a first-of-its-kind implementatfon. Railbelt engineers' and operators' deep experience with stability and its effects on power flows makes them uniquely positfoned to successfully integrate and implement such a solutfon. Learnings gleaned from this solutfon will have applicatfons through the U.S. and globally. Beyond stabilizing large-scale oscillatfons and alleviatfng stability constraints, a new transmission line can remove barriers to developing new clean-energy sources in both the Central and Northern regions. Without the resilient and unconstrained access facilitated by a new line, the potentfal for renewable resource development in each region remains limited, contfngent on their ability to manage single-contfngency events. As noted, HVDC/BESS control will play an integral part in stability control of the entfre Railbelt grid. The controller will work in concert with BESS and HVDC controllers in the Northern, Central and Southern regions to control transient frequencies in each of the islands , increasing stability limits across each of the existfng AC transmission interconnectfons. The HVDC controller will help coordinate the system-wide regulatfon of clean-energy resources. will be integral to the ability to black-start either the Northern or Central region following a catastrophic event such as a repeat of the 1964 earthquake, the November 2018 earthquake, or the tremendous windstorm of 2022. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 14 April 17, 2024 Innovatfon and Impacts We know of no other single transmission line that has the capability to consolidate multfple planning areas into a single inter-regional planning area. The project will improve the grid's overall stability by establishing a parallel path between the Northern region and the Central/Southern regions. Enabling high-speed control of power flows will lower spinning-reserve requirements, thus diminishing reliance on Cook Inlet natural gas and decreasing carbon emissions. This control, coupled with the reductfon of impedance between the regions, will elevate transient stability limits and therefore increase transfer capacity. When operated in a coordinated fashion, the BESS and southern HVDC system will increase transfer capability, resiliency, and reliability, even more significantly by performing three functfons, all of which contribute to frequency stabilizatfon. The first functfon is to increase transfer capability. The second is to improve frequency regulatfon. And the third is address small-signal instability on the grid. The HVDC controllers and three BESS installatfons in three different regions of the system will operate in a coordinated manner to increase transfer limits across the interconnectfng transmission lines. Following completfon of the Beluga–Healy sectfon, the BESS and Southern/Central system controls will be modified to optfmize system security across all three regions. Such control will allow real-tfme optfmizatfon of grid operatfons in the face of events that result in d ecreased inertfa and other generatfon contfngencies. This enhanced grid performance will increase the ability to accept renewables into the system by aiding in the performance of regulatfon and reserve optfmizatfon. Further, the increase of inter-regional transfer capacity from approximately 75MW to over 200MW will allow the generatfon with the highest costs and emissions on the Railbelt to run only during rare contfngencies. It will also allow large-scale wind projects of approximately 200MW capacity to be located as needed to take full advantage of geographic diversity in wind resources, minimizing the amount of fossil-fuel generatfon required to regulate the output of the Railbelt’s future wind generatfon portiolio. As noted above, we believe this to be an innovatfve, first-of-its- kind solutfon. Knowledge gleaned from this project’s unique integratfon of multfple BESS and HVDC will be useful throughout the country and world as BESS and HVDC systems are installed to facilitate increased, variable, clean-energy project integratfon. Further, analysis of real-world experience with high penetratfon of inverter-based resources will provide valuable knowledge that can be scaled and applied to larger grids in other parts of the US and wor ldwide. F.6 Topic Area 3: Grid Innovation Program Strengthening the fragile connectfon between three service regions of the Central and Northern regions of the Railbelt will provide significant benefits to all five interconnected service areas 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 15 April 17, 2024 represented in this proposal, CEA, GVEA, HEA, MEA, and SES. The new HVDC line will eliminate the single-contfngency islanding conditfon that is created when the existfng intertfe is out of service (scheduled or non-scheduled). The HVDC line will also eliminate the small-signal instability events that occur on the loss of the existfng intertfe during high central regional exports in the summer valley season. The completfon of this project will increase transfer capability between the Central and Northern regions by two or three tfmes the current transfer capacity. Further, real-tfme control of transmission line flows will improve dynamic performance and enhance operatfonal flexibility related to disturbance response regulatfon and reserves. This project enhances and accelerates the Railbelt’s ability to integrate intermittent renewable resources such as wind and solar directly into the grid. To facilitate transmission constructfon, the Regulatory Commission of Alaska (RCA) has agreed to join our project team within their statutory limits. Recognizing the unique structure of Railbelt's electric cooperatfves, the RCA is prepared to initfate an investfgatfve docket to explore innovatfve funding mechanisms for transmission-investment-cost recovery. Larger-scale projects drive the price per unit of electricity down and make the benefit-cost hurdle lower and more achievable, driving greater private sector investment in the Railbelt energy field. Workplan Project Objectfves The project aims to achieve the following objectfves, each with specific measures of success to gauge progress and impact: 1. Create a reliable and resilient grid capable of supportfng a diverse mix of clean energy, reduced carbon emissions, enhanced stability and increased transfer capacity between regions at two to three tfmes current capability. This infrastructure is crucial for the Railbelt and Alaska’s future quality of life and economic growth. Success in this area will be measured by:  The reductfon in the number of grid-instability events over tfme  A decrease in transmission and generatfon outages due to weather, wildfires, and other disruptfve events  The improvement in transfer capability, assessed by comparison of sending- versus receiving-end phase angles  The megawatt-hours (MWh) of additfonal clean energy integrated into the grid over tfme 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 16 April 17, 2024 2. Successful constructfon and integratfon of an HVDC overhead line from Beluga to Healy, linking it with the BESS and Southern HVDC systems using innovatfve technical solutfons to enhance resiliency in extreme environments. This goal's achievement will be evaluated through:  Completfon of the project within the set schedule and budget  Improved heat rates in the Northern region and the overall system due to enhanced operatfng flexibility  Reduced islanding events between regions 3. Promotfon of economic growth by creatfng thousands of well-paid jobs and opportunitfes for Alaskans, ensuring that at least 40 percent of these benefits reach those residents in the Railbelt living in disadvantaged communitfes (DACs) or in Alaska Natfve Statfstfcal Areas (ANSAs). The success of this objectfve will be monitored by:  The total number of constructfon and long-term jobs created, as verified by certffied payrolls  The proportfon of these positfons filled by indigenous people or residents from Railbelt's disadvantaged communitfes  The number of journeyman craflsmen trained by the building trades during the project, compared to historical averages Technical Scope Summary Steps 1-a through 1-e is a 250-mile 150 kV/200 MW, HVDC bipolar transmission link between Beluga in the Central region and Healy in the Northern region. Permitting and routfng this segment will undergo a NEPA process expected to take three years. The transmission line uses a 230kV bay at the Beluga 230kV yard to interconnect to the existfng Central region 230kV AC system via a VSC-IGBT converter assembly. A similar configuratfon interconnects the line at Healy. The transmission route is designed to follow the AKLNG right-of-way (ROW) to Healy. Where practfcal, the AKLNG ROW will serve as a buffer to reinforce and harden the HVDC line against natural disasters, including the impacts of seismic actfvity and extreme weather events. This project will be sourced with American bought products in compliance with the Buy America program. The line will be constructed with ROW and towers designed to support a second circuit. Given the limitatfons of modifying a DC line for multf-terminal operatfons, should future opportunitfes for additfonal renewable generatfon or loads emerge along the HVDC line’s route, a second AC circuit can be added to integrate these resources into the grid. A NEPA route selectfon study will be completed to reach a final determinatfon on routfng. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 17 April 17, 2024 Special consideratfons for outreach and flexibility in constructfon techniques may be necessary and are expected as the line transitfons Denali Natfonal Park and state parks. Substatfon constructfon will include steel structures, foundatfons, conduit, cables, VSC-IGBT converter statfons, two 230kV/138kV power transformers, and associated breakers and switches with SCADA, communicatfons, protectfon and control devices. Line constructfon is envisioned using a combinatfon of steel H structures; angle and dead-end structures with all the associated guys, anchors, and overhead; and potentfally underground or advanced design conductors. Should the passage through Denali Natfonal Park necessitate it, the consideratfon of experiment al, tfght- bundled superconductors may be employed. A fiber-optfc cable will be included in the Optfcal Ground Wire (OPGW) for communicatfons. Due to the scale of the project (250-mile length), it will be broken into five sectfons for constructfon purposes, with multfple contractors working concurrent schedules to meet the constructfon tfmeline of just two years. The line's segmentatfon has been strategically designed to maximize the use of common constructfon techniques, considering the varying requirements for agency permits. Preliminary efforts to secure right-of-way access through easements, special permits, or land acquisitfon will start with Denali Natfonal Park. The acquisitfon process will be segmented into five phases, mirroring the line constructfon stages. Once final permits are secured, easements will be finalized. Land is available at both end points (Beluga and Healy) for converters and substatfons. Therefore, permits should be minimal to accommodate local design criteria. Transmission constructfon will start with right-of-way clearing followed by material delivery and installatfon of structures and anchors. Following erectfon, down guys are installed to support the structures, and conductors are strung using specialized pulling equipment. The conductor is then sagged and pulled to proper tension. Following installatfon, conductors are clipped (attached to tangent and angle structures) or dead-ended (attached to end structures), and jumpers are installed to carry current from one side of the dead-end structure to the other. To expedite constructfon and minimize environmental impacts, helicopter constructfon is recommended in inaccessibly remote locatfons. The use of helicopters to set structures and pull sock line (stringing lines or rope) can reduce labor costs and increase productfvity. Helicopters can also be used to deliver material to staged locatfons along the transmission path. The constructfon will entail the additfon of a 230kV bay at Beluga and a line sectfon extending to the converter statfon. This sectfon is to include terminatfon structures for the line as well as the necessary infrastructure for switches and breakers. It will enable interconnectfon with the existfng 230kV AC system in the Central region via a bi-pole HVDC statfon that employs an HVDC converter. At the project’s northern terminus, the Healy substatfon will act as a terminatfon point, a 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 18 April 17, 2024 switching statfon, and a transitfon point from the HVDC to the Northern region’s 230kV AC system, facilitated again by a bi-pole HVDC statfon using an HVDC converter. The interconnectfons will be equipped with relaying protectfon and communicatfon systems to ensure the transmission line sectfons leading to the converter statfons operate safely. The procurement and testfng of the integrated control system's soflware and hardware will occur concurrently with line constructfon, ensuring it is ready and in place for commissioning as the final sectfons of the line are installed. The commissioning of the integrated control system will proceed afler the HVDC system has been commissioned and checked out in standalone mode. The Beluga-Healy HVDC line will provide improved energy-transfer grid stability and resilience between the Central and North regions of the Railbelt. The existfng 138kV AC transmission line traverses some of Alaska's most challenging landscapes, encompassing numerous river crossings, areas prone to snow and ice-loading, mountainous topography, and terrain that is constantly changing due to permafrost degradatfon and processes like solifluctfon and creep. Additfonally, the existfng line’s proximity to areas where lightning strikes are prevalent increases the risk of fire danger; implementfng an alternatfve path will enhance the resiliency and reliability of the transmission network, thereby reducing instances of transmission downtfme and improving the capacity to transfer power throughout the Railbelt. This additfonal line will also unlock acces s to previously inaccessible renewable-energy sources, including wind, hydroelectric, and photovoltaic (PV) opportunitfes. Work Breakdown Structure (WBS) and Task Descriptfon Summary The overall approach for the project workplan follows accepted project-management techniques identffied more completely in the Project Management Body of Knowledge (PMBOK). The project will engage stakeholders through the comprehensive process, which is more fully defined in our Community Benefit Plan; execute analysis and permitting in compliance with NEPA requirements; and engineer, design, procure and construct a 150kV/200 MW Bipolar HVDC line from the Central region to the Northern region of Alaska’s Railbelt. This HVDC system will be fully integrated into the HVDC/BESS system from F-1. The integratfon will be the first-of-its-kind, real-tfme integratfon of multfple large-scale BESS and HVDC systems. The WBS of Figure 7 is summary task roll -up of the 92 task WBS and Gantt chart developed for the project. Additfonal WBS details are available upon request but were summarized here to meet page-count requirements. Milestone Summary 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 19 April 17, 2024 Work Breakdown Structure 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 20 April 17, 2024 Figure 7 Summary Work Breakdown Structure for the Railbelt’s Beluga-Healy HVDC line. Outline Number Task Name Duration Start Finish 1 Project Management and Planning 2087 days?Thu 5/15/25 Fri 5/13/33 1.1 Project management Plan (PMP) 22 days Thu 5/15/25 Fri 6/13/25 1.2 Community Benefit Plan (CBP) Early Stakeholder Engagement determination and meetings 2087 days?Thu 5/15/25 Fri 5/13/33 1.3 National Environmental Policy Act (NEPA) Process - EIS Required Conceptual Desgn and Environmental Impact 784 days Thu 5/15/25 Tue 5/16/28 1.3.1 Permitting Undertake EIS and apply for permits 487 days Thu 5/15/25 Fri 3/26/27 1.3.1.1 NOI to prepare EIS -HVDC interconnect Central Region and the Northern Region-Environmental and Permitting 1 day Thu 5/15/25 Thu 5/15/25 1.3.1.2 Scoping and Project alternative analysis 487 days Thu 5/15/25 Fri 3/26/27 1.3.2 NEPA Revisions & Identification long-termconstraints on comm. Access to res. & to tribal cultural resources 296 days Fri 3/26/27 Fri 5/12/28 1.3.3 Record of Decsion Approval Milestone 0 days Mon 5/15/28 Mon 5/15/28 1.3.4 EIS Record of Decision Go/No Go 1 day Tue 5/16/28 Tue 5/16/28 1.4 Cyber Security Plan (CSP)2087 days?Thu 5/15/25 Fri 5/13/33 1.4.1 Develop Cyber Security Plan 43 days Thu 5/15/25 Mon 7/14/25 1.4.2 Cybersecurity Plan Milestone 0 days Tue 7/15/25 Tue 7/15/25 1.4.3 Cyber security Go/No Go 1 day Wed 7/16/25 Wed 7/16/25 1.4.4 Ongoing Cyber Security monitoring and iterative updates 2043 days Wed 7/16/25 Fri 5/13/33 1.5 Continuation Briefing(s)1763 days Fri 8/15/25 Tue 5/18/32 2 SOPO Phase 1 Design Permitting and Siting 1828 days Thu 5/15/25 Mon 5/17/32 2.1 Risk Evaluation (ongoing)1828 days Thu 5/15/25 Mon 5/17/32 2.1.1 Intital Risk Probability Impact and Mitigation Matrix (Focus on CBP, natural hazards,preliminary 2.1.2 & 2.1.3 Topics)10 days Thu 5/15/25 Wed 5/28/25 2.1.2 Formal Review 1 (Focus on routing through Denali National and State Parks)2 days Thu 5/29/25 Fri 5/30/25 2.1.3 Formal Review 2 (Focus on potential uses of AKLNG ROW as mitigation buffer)2 days Fri 5/15/26 Mon 5/18/26 2.1.4 Formal Review 3 2 days Sat 5/15/27 Mon 5/17/27 2.1.5 Formal Review 4 2 days Mon 5/15/28 Tue 5/16/28 2.1.6 Formal Review 5 2 days Tue 5/15/29 Wed 5/16/29 2.1.7 Formal Review 6 2 days Wed 5/15/30 Thu 5/16/30 2.1.8 Formal Review 7 2 days Thu 5/15/31 Fri 5/16/31 2.1.9 Formal Review 8 2 days Sat 5/15/32 Mon 5/17/32 2.2 Design Criteria 308 days Thu 5/15/25 Mon 7/20/26 2.3 Prelimnary design 308 days Thu 5/15/25 Mon 7/20/26 3 Public Notice per CBP 5 days Tue 4/15/25 Mon 4/21/25 4 Final Design and Engineering 1416 days Mon 9/15/25 Mon 2/17/31 5 Permitting 418 days Fri 3/26/27 Tue 10/31/28 5.1 Permits complete and valid GO/ No Go 0 days Fri 3/26/27 Fri 3/26/27 5.2 ROW and land Acquisition 262 days Fri 3/26/27 Sun 3/26/28 5.3 Land Acquisition 122 days Mon 5/15/28 Tue 10/31/28 6 SOPO Phase 2 Procurement and Acquisition (Materials and Services)-Long-lead Equipment Purchase 644 days Tue 5/16/28 Sat 11/2/30 7 SOPO Phase 3 Construction and Deployment 1156 days Wed 7/12/28 Wed 12/15/32 8 SOPO Phase 4 Testing and Commissioning 1216 days Fri 9/15/28 Sun 5/15/33 9 Project Completion Milestone 0 days Sun 5/15/33 Sun 5/15/33 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 21 April 17, 2024 Go/No-Go Decision Points (See Sectfon VI.B.xv. for more informatfon on the Go/No-Go Review) End of Project Goal Create reliable and resilient grid capable of supportfng a diverse mix of clean energy, reduced carbon emissions, enhanced stability, and increased transfer capacity between regions two to three tfmes current capability. This infrastructure is crucial for the Railbelt and Alaska ’s future quality of life and economic growth. Successful constructfon and integratfon of an HVDC overhead line from Beluga to Healy, linking it with the BESS and Southern HVDC systems using innovatfve technical solutfons to enhance resiliency in extreme environments. Promote economic growth by creatfng well-paid jobs and opportunitfes for Alaskans, ensuring that at least 40 percent of these benefits reach those residents in the Railbelt living in DACs or ANVSAs. Outline Number Task Name Duration Start Finish 1.3.4 EIS Record of Decision Go/No Go 1 day Tue 5/16/28 Tue 5/16/28 1.4.3 Cyber security Go/No Go 1 day Wed 7/16/25 Wed 7/16/25 1.5.2 Kickoff Go/ No Go 1 day Wed 8/20/25 Wed 8/20/25 1.5.4 Risk Briefing 2 Go/ No Go 1 day Wed 5/20/26 Wed 5/20/26 1.5.6 Risk Briefing 3 Go/ No Go 1 day Wed 5/19/27 Wed 5/19/27 1.5.8 Risk Briefing 4 Go/ No Go 1 day Thu 5/18/28 Thu 5/18/28 1.5.10 Risk Briefing 5 Go/ No Go 1 day Fri 5/18/29 Fri 5/18/29 1.5.12 Risk Briefing 6 Go/ No Go 1 day Mon 5/20/30 Mon 5/20/30 1.5.14 Risk Briefing 7 Go/ No Go 1 day Tue 5/20/31 Tue 5/20/31 2.3.3 Preliminary Design StudyWorks Go/ No Go 1 day Mon 7/20/26 Mon 7/20/26 4.11 Design and Engineering Completion Go/No Go 1 day Mon 2/17/31 Mon 2/17/31 5.2 Permits Complete and Valid GO/ No Go 1 day Tue 10/31/28 Tue 10/31/28 5.4.6 Right of Way and Land Acquisition Go/No Go 1 day Tue 10/31/28 Tue 10/31/28 6.6 Equipment Procurement Go/No Go 1 day Sat 11/2/30 Sat 11/2/30 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 22 April 17, 2024 Project Schedule (Gantt or similar) Project Management Overall Approach The project-management approach will follow the key tenets of the PMBOK’s successful project- management guidelines. This approach is structured around the concept of process groups and knowledge areas. Process Groups: PMBOK organizes project management into five process groups that represent the stages of a project's lifecycle:  Initiating: Defining and authorizing the project or a project phase.  Planning: Establishing the scope, objectives, and procedures necessary for accomplishing the project.  Executing: Performing the work defined in the project-management plan to achieve the project's objectives.  Monitoring and Controlling: Tracking, reviewing, and regulating the progress and performance of the project; identifying any areas in which changes to the plan are required.  Closing: Finalizing activities across all process groups to formally close the project or phase. Knowledge Areas: PMBOK also delineates 10 knowledge areas that are key to successful project executfon. These areas encompass the core technical subject matters necessary for effectfve project management:  Stakeholder Management: managing stakeholders' expectations and engagement. 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 23 April 17, 2024  Risk Management: identifying, analyzing, and responding to project risks.  Communication Management: ensuring timely and appropriate planning, collection, creation, distribution, storage, retrieval, management, control, monitoring, and ultimate disposition of project information.  Procurement Management: managing procurement of goods and services from outside the project team.  Integration Management: ensuring that project processes are properly coordinated.  Scope Management: managing the project's scope.  Schedule Management: managing the project schedule.  Cost Management: managing the project budget.  Quality Management: Ensuring the project will satisfy the stated or implied needs for which it was undertaken.  Resource Management: managing project resources, including human resources and materials. As noted above, the project will use traditfonal project management techniques and controls such as change management, budget and cost control, and scope management as identffied in the PMBOK. A comprehensive risk log will be maintained by the project manager. At a minimum, all risk and mitfgatfon strategies will be updated at each milestone. The project will be managed by an overall project lead under the guidance of a team comprised of Railbelt utflity engineers, system operators, and managers. Actfng as the project steering committee, the team will guide the project lead’s efforts and provide access to resources and data. The team and DOE will validate and verify the performance of the systems at each milestone and go/no -go point. Role Descriptfon Project Lead Manages overall project Engineering Liaison Evaluates process to secure needed design & engineering expertfse Lands Liaison Evaluates process to secure land acquisitfon, easements, and permits Constructfon Liaison Evaluates the best method to secure constructfon contracts Labor Liaison Works with labor unions, workforce development organizatfons, universitfes, and trade schools to arrange for needed labor Project Management Lead Manages overall schedule and coordinates individual projects Finance & Grant Management Lead Coordinates work with AEA, utflitfes, DOE, RUS, and private lenders Government Relatfons Lead Communicates project details with local, state, and federal entftfes Purchasing & Materials Lead Assures key materials are available and monitors and works with vendors on unforeseen Buy America goals 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 24 April 17, 2024 Public Relatfons Lead Communicates with key stakeholders and the general public, and executes the Community Benefit Plan outreach Legal & Contracts Lead Develops contracts and provides guidance with appropriate terms and conditfons Accountfng and Closeout Coordinator Coordinates with project leads, assuring all proper documentatfon is secured to tfmely close out projects; coordinates with Finance and Grant Management Lead Project Value and Change Management Projects will be competftfvely bid. Traditfonal project change control methods will be used. Quality Assurance/Control QA/QC Performed by the project management team; strict check-out and commissioning procedures will be developed in the Factory Acceptance (FAT)and Site Acceptance test (SAT) plans. Project Communicatfon Project initfatfon documents, and Project Management Plan (PMP) will contain a project communicatfons plan detailing chain of command and appropriate communicatfon meetfng cadence and tempo. Technical Qualifications and Resources (Approximately 20% of the Technical Volume) The team has a combined 200 years of Railbelt system operatfons, constructfon, and engineering experience. Members are experienced and well-versed in executfng complex transmission-line and substatfon projects in Alaska’s challenging environment. The Railbelt utflitfes have skilled engineers and designers, and the local work force includes IBEW journeymen, technicians, and linemen who have built the electrical system we have today. Engineering and design firms, who routfnely propose projects as envisioned in the applicatfon, are available locally and in the Pacific Northwest. Alaska has multfple highly skilled electrical contractors through the Natfonal Electrical Contractor Associatfon (NECA), which employs workers from IBEW local 1547. They are versed both in high- voltage transmission and substatfon constructfon. The IBEW has out-of-state traveler availability and a state-of-the-art apprentfceship school that can ramp up to meet demand. The NECA contractors have specialized tools and equipment to undertake remote, off-road transmission constructfon. These specialized techniques have expedited constructfon and minimized environmental damage in the past. Unique Qualifications and Expertise The project team is unique in that it includes all relevant decision-makers in the Railbelt. The team has decades of experience in constructfng transmission lines and installing , operatfng, and maintaining high-voltage (34.5kV, 69kV, 115kV, 138 kV and 230kV Alternatfng Current (AC)) submarine cables in Cook Inlet. In additfon, they have decades of experience with BESS systems. The existfng BESS in Fairbanks at 46MW—5 minutes was the largest BESS in the world at the tfme of its installatfon in 2003, and the Southern region BESS (46.5MW—2hours) was commissioned and installed in 2022. Further, with six Statfc VAR Compensators (SVCs) on the Railbelt, the team 3195-1942_BPMC_Full Applicatfon DOE Grid Resilience and Innovated Partnerships Topic 3 FOA Number: DE-FOA-003195 Page 25 April 17, 2024 is very familiar with installatfon, commissioning, and operatfng high-powered electronics like those used in HVDC converters. The team is currently rebuilding the 39-mile Sterling-to-Quarts Creek line to 230 kV. The team has also collaborated on a number of other projects, including the constructfon of the $350M Bradley Lake hydroelectric facility in 1991; the $47M Battle Creek diversion at Bradley Lake in 2020; and $10M controls replacement on the Northern SVCS. Team members have also done significant transmission-line constructfon individually. Existing Equipment and Facilities The team works with state-of-the-art SCADA/EMS systems with an inter-regional ICCP link for data transfer: a complex network of ringed SONET-compatfble digital microwave and fiber assets and hardened statfons for high-speed communicatfons. The microwave and fiber systems are currently used for SEL high speed mirrored-bit communicatfons to enable high-speed transfer tripping. As noted above, there are several high-voltage AC submarine cables, BESS systems and SVCs, as well as the equipment and technical know-how to work on them. Relevant, Previous Work Efforts, Demonstrated Innovations Numerous complex systems have been studied and successfully placed in the Railbelt by project team members. These include the Northern region BESS in 2003, the Southern region BESS in 2022, and the Central region BESS, which is currently under constructfon. High-voltage AC submarine cables have been installed, the earliest at 138kV in 1973. Statfc Var Compensators have been added, the earliest of which was in 1985, and more recently, the control systems on all the Alaska Intertfe and Bradley Lake SVCs have been completely replaced. Installatfon of SCADA and EMS systems at all five utflitfes; installatfon of inter-regional digital-microwave and fiber-optfc systems; installatfon of high-speed, communicatfon-assisted transfer trip- and line-current differentfal protectfon on all Railbelt transmission lines; eigenvector/value analysis that defined and mitfgated the small-signal instability points between the weak Summer Valley Railbelt grid and the Bradley Lake hydroelectric project. The study of development and installatfon of the Railbelt’s multf-stage, multf-delayed under-frequency load shed schemes is another example of a complex real-tfme control system developed and installed by members of the project team. Key Team Members’ Time Commitment Key members will be assigned to this project as necessary to ensure successful completfon. Page 1 of 21 REQUIRED USE -- Community Benefits Plan Template for Funding Opportunity Announcement (FOA) Number: DE-FOA-0003195 Bipartisan Infrastructure Law (BIL) – Grid Resilience and Innovative Partnerships (GRIP) Alaska Energy Authority Topic Area 3 – Railbelt Central-Northern Region HVDC Interconnect General Project Informatfon 1. High-level description of the CBP and project The Beluga-Healy HVDC Line project will benefit Tribes in Alaskan Natfve Village Statfstfcal Areas (“ANVSAs") and disadvantaged communitfes (“DACs”) in Alaska’s Railbelt region. The project will construct 240 miles of HVDC transmission line from Beluga in the Central Region near Anchorage to Healy in the Northern Region near Fairbanks. By increasing operatfng voltages, this HVDC line will enable Railbelt utflitfes to transfer low-cost and reliable power to where it is most needed. Beluga-Healy HVDC Line Community Benefits outcomes and objectfves include:  Robust public partfcipatfon plan followed by public AEA (Alaska Energy Authority) memo responding to stakeholder feedback.  Increased transfer capacity between regions to enable higher renewable energy integratfon and a reductfon in fossil fuel generatfon and associated emissions.  Energy access resilience and reliability improvements for Tribal communitfes in ANVSAs and DACs on the Railbelt.  Retentfon of over 650 highly paid union jobs with competftfve employer-sponsored benefits.  Creatfon of 1,000s of temporary constructfon jobs.  Creatfon of 10-15 new positfons at four partfcipatfng utflity cooperatfves.  Improvement and growth of apprentfceship and internship programs that include recruitment focused in ANVSAs and DACs.  Decrease in energy burdens from reduced line loss in Railbelt communitfes.  Decreased community energy burdens for remote communitfes (outside of Railbelt) via increased Power Cost Equalizatfon (PCE) with potentfal consumer PCE credit increases of $1.5M annually based on FY22 PCE Community Report.pdf (akenergyauthority.org). The project team plans to pursue an overarching Memoranda of Agreement with interested Tribal Councils on the Railbelt to encourage local partfcipatfon and open dialogue with this key stakeholder group. AEA will promote and commit to local hiring where possible, barrier reductfon for entry into apprentfceship and internship programs, contracts that pay above prevailing wages, and other forward looking policies. The project will partner with the Internatfonal Brotherhood of Electrical Workers- Natfonal Electrical Contractors Associatfon (IBEW-NECA) and Alaska Joint Electrical Apprentfceship and Training Trust (AJEATT) to source apprentfce candidates and ensure the development of a skilled, inclusive local workforce. Page 2 of 21 2. Construction Information AEA will develop and maintain a risk register complete with ongoing mitfgatfon strategies. At this point we antfcipate the primary risks to be (1) staffing (2) procurement, cost, and supply chain management and (3) permitting the sectfon near Denali State Park and Denali Natfonal Park. Mitfgatfon strategies for each are outlined in the following paragraphs. Staffing Shortages. To address the natfonal shortage of electrical workers, the Project Team will contfnue ongoing discussions with the IBEW 1547, NECA, and their AJEATT to inform them of project tfming and staffing needs and to reinforce AEA’s desire to hire local workers. For additfonal staffing needs, workers will be sourced from the Lower 48 states through IBEW. The Project Team is also working to develop training opportunitfes for Alaskan Natfve workers in a proposed partnership between the utflitfes, IBEW/NECA, and local Natfve village and regional corporatfons. Procurement. The engineering and project management plan will include periodic evaluatfons of the supply chain for major equipment. The schedule is flexible with modular engineering and constructfon plans to navigate around supply chain challenges while maintaining productfvity: procurement of scarce items can be delayed minimizing supply chain and inflatfonary cost impacts without derailing the schedule. Permitting. A two-pronged approach has been developed to address antfcipated permitting challenges. First, a robust and early stakeholder engagement plan is intended to bolster support and advocacy for the project by transparently identffying and attemptfng to resolve any issues that stakeholders have. Second, the project will build in contfngencies/optfons such as using innovatfve advanced conductors to minimize conductor size and spacing, potentfally undergrounding some portfons of the line, or routfng the line around the state and natfonal parks. It should be noted that an Alaska Department of Transportatfon & Public Facilitfes (AKDOT-PF)-managed ROW exists through both Denali State Park and Denali Natfonal Park, and Alaska Gasline Development Corporatfon (AGDC) previously obtained permits in both parks. Existfng partnerships with these agencies could pave the way for better permitting outcomes. 3. Locations and Communities Affected The new HVDC transmission line will run 240 miles from Beluga to Healy. Importantly, this route will be entfrely in remote locatfons untfl it connects in Healy. Beluga is located in Kenai Peninsula Borough (#02122000100), populatfon 526. This tract is considered disadvantaged because it meets more than 1 burden threshold and the associated socioeconomic threshold. The one ANVSA in this tract is also considered disadvantaged. From there the line travels through Matanuska-Susitna Borough (#02170000101), populatfon also 526. This tract is considered disadvantaged because it meets more than 1 burden threshold and the associated socioeconomic threshold. From there the line will travel through Denali Borough (#02068000100), populatfon 2,246, to its terminatfon point in Healy, which already houses a significant power generatfon plant and grid infrastructure. Denali Borough is considered disadvantaged because it meets more than 1 burden threshold and the associated socioeconomic threshold.1 The one ANVSA in this tract is also considered disadvantaged. Every single mile of transmission line that will be installed through this project will be installed on DAC lands. These DACs 1 https://screeningtool.geoplatiorm.gov/en/ Page 3 of 21 and ANVSAs are antfcipated to capture the majority of project benefits, partfcularly local hiring preference. There is no demolitfon of any lines or facilitfes included in the project; minimal waste materials are antfcipated to be generated. There are no DACs antfcipated to be adversely affected by the project, since the project occurs almost entfrely in remote locatfons. All communitfes where constructfon occurs will have multfple opportunitfes to engage on preliminary and final design through the project’s public partfcipatfon plan. Sacred tribal lands will be identffied through the Environmental Impact Assessment study prior to deployment of constructfon and through public engagement with Tribal Councils and leaders in the service areas. A. Community and Labor Engagement 1. Community and Labor Stakeholders Engaged to Date Alaska Federatfon of Natfves, Alaska Village Electric Cooperatfve, Alaska Black Caucus, Alaska Municipal League, IBEW Local 1547, Internatfonal Union of Operatfng Engineers (IUOE) Local 302, Alaska Operatfng Engineers Training Trust, Alaska Joint Electrical Apprentfceship & Training Trust, Fairbanks Chamber of Commerce, Alaska AFL-CIO, Anchorage Economic Development Corporatfon. Type of Engagement: Preliminary meetfngs and phone calls to alert organizatfons to existence of project and desire for partnership if funded. No known oppositfon to the project has been expressed by any of these organizatfons to date. Date of Engagement: Between February 2023 – April 2024. Outcome of Engagement Ongoing discussion. 2. Community and Labor Stakeholders to be Engaged. Beluga-Healy HVDC Line Public Partfcipatfon Plan: Phase 1: Draft public participation plan 1. Select public engagement firm to assist with public participation plan (cost estimate for scope of work included in this section = $156,410). 2. Select environmental consultant to complete EIS and field related stakeholder questions. 3. Meet with and draft overarching MOA with representatives from receptive Railbelt Tribal Councils to ensure robust public participation and local hiring preference. 4. Draft outreach media. Include strategies designed to ensure participation from minority groups and disadvantaged communities affected by project. A focus group will be used to test effectiveness of materials on diverse populations. 5. Launch website with public meeting schedule, project description, public comment section, and ArcGIS Online mapping tool with public comments geocoded by location, allowing identification of site-specific issues, needs, and themes. Phase 2: Implement Public Participation Plan Alaska Energy Authority (AEA), representfng the State of Alaska, is the lead applicant for this project. They are accustomed to engaging with local governments and tribal entftfes regarding permitting Page 4 of 21 and regulatory processes for capital projects. As noted in B.1. many of these conversatfons have already begun and will contfnue to inform project development. AEA believes that local governments and Tribal entftfes are uniquely situated to identffy actfons the project can take to advance progressive workforce, DEIA, and environmental justfce outcomes at both the community and regional levels. AEA will work closely with each utflity provider to determine the appropriate tfme and setting for community meetfngs to avoid conflicts with other events. The core team will devote special attentfon to ensuring diverse demographic partfcipatfon at all meetfngs, including hostfng meetfngs at a range of tfmes, including outside of typical working hours. Task 1: Introductory Work Sessions Each of the four utility providers involved in the project and AEA will host an introductory public work session. These work sessions will be advertised at least two weeks in advance via social media, public postings, utility cooperative mailers, and the project website ($5,000 in marketing/outreach materials is estimated). Topics will include: Task 2: Data Collection 1. Conduct surveys to address data gaps identified by public during introductory public work sessions. Surveys will be distributed electronically and/or made available at key community locations. AEA does not expect to get a statistically valid sample of the entire Railbelt population, but enough feedback to assess community perspectives from a cross -section of stakeholders. Task 3: Organizational Work Sessions and “Going to the People” 1. Review the Beluga-Healy HVDC Line (and other ongoing Railbelt grid-modernization projects). Communicate what it encompasses, costs, projected timeline, and potential impacts. Identify stakeholders affected and their various value propositions. 2. Communicate how the public can learn more, track project progress, and how their feedback will be used. 3. Share success stories as well as lessons learned from other electrical infrastructure upgrades conducted on the Railbelt. 4. Present benefits and constraints of Alaska public contracting law. Solicit feedback on DEIA goals and commitments to workers. 5. Identify areas where stakeholders wish they had more data or information via questions like: “What should AEA consider that we haven't covered today?” “What information would you like to see at a future meeting?” “What additional questions do you have?” 6. Meeting minutes will be made public on the project website. Page 5 of 21 Task 4: Follow-up Work Sessions A second round of public meetfngs will be hosted by the four utflitfes as well as Alaska Energy Authority. Topics will include: Task 5: Public Participation Plan report (September-November 2024) Workforce and Community Agreements Agreement A: Overarching Memorandum of Agreement with participating Tribal Councils for ANVSAs on the Railbelt 1. Work sessions with relevant organizations will be conducted, including those organizations listed in B1 with whom preliminary contact has already been made. Engagement with these groups will guide project design and implementation. Discussion topics to include: environmental impacts (particularly around transmission line easements through Denali State Park and Denali National Park), viewshed impacts, subsistence impacts, state and federal land management, Power Cost Equalization, workforce development (including apprenticeships), support for minority business enterprises, DEIA recruitment, DEIA workplace policies, and state legislation. 2. Additional AEA outreach will be conducted at existing meetings in each project area, such as: Tribal Council meetings, City Council meetings, and Chamber of Commerce lunches. AEA outreach will also be conducted in more informal settings to recruit a more diverse group o f stakeholders. AEA refers to this process as “G2P” or “going to the people.” Examples of events suitable for G2P include, but are not limited to: Alaska Federation of Natives convention, Alaska Black Caucus Sunday night Zoom meetings, Alaska State Fair, community farmers’ markets, Juneteenth programming, Alaska Federation of Filipino Americans programming, Sportsman shows, music festivals, and more. Events may vary from community to community. At least one informal event will be hosted/attended in Healy, the northern terminus of the line. 1. Recap project purpose, goals, and timeline. 2. Themes and key takeaways from intro work sessions, one -on-one organizational meetings, G2P events, and survey results. 3. Have stations set up around different topics: people can walk from station to station to learn about different elements of the project (DEIA goals, labor commitments, environmental impacts, employment opportunities, homeowner impacts, etc.), and ask questions of project staff about specific areas they are interested in. 4. Request for additional feedback or concerns not captured thus far. 5. Minutes from this meeting will be posted to the project website. 1. Public Participation Plan Report published by AEA, along with memo in response, summarizing and responding to comments. Page 6 of 21 Agreement Summary: This single MOA, ratified by multiple Tribal councils, will outline criteria for a robust public engagement process as well as targeted recruiting of Alaskan Native people for apprenticeship and internship opportunities in clean energy. This includes apprenticeships for construction work and access to “job pipelines” for long-term employment maintaining local electrical infrastructure. Scope: A single overarching MOA will be established with participating Tribal councils. These can include but are not limited to: Cantwell ANVSA, Chickaloon ANVSA, Chitfna ANVSA, Copper Center ANVSA, Eklutna ANVSA, Gakona ANVSA, Gulkana ANVSA, Kenaitze ANVSA, Knik ANVSA, Nanwalek ANVSA, Nenana ANVSA, Ninilchik ANVSA, Northway ANVSA, Port Graham ANVSA, Seldovia ANVSA, Tanacross ANVSA, Tazlina ANVSA. Budget Period to be completed: Budget period 1. Milestones with timelines: Milestones include one on one organizational meetings with select Tribal Councils to draft a Tribal MOA for the project, this MOA appearing on Tribal Council agendas, and being ratified (with revisions as needed) by various Tribal Councils within the first budget period of the project. Agreement B: Collective Bargaining Agreements with Utilities Agreement Summary: The four utilities included in this project currently maintain collective bargaining agreements (CBA) with 659 of 1,071 (62%) total employees. Alaska is not a Right to Work state; utflity employees whose positfons are covered by bargaining unit agreements are required to join unions consistent with those agreements. The Railbelt utflitfes have used project labor agreements in the past for projects of this scale, such as constructfon of the Alaska Intertfe. Each of the utflitfes has CBAs with IBEW 1547, among other unions. AEA and the four utflitfes in this project intend to engage labor partners early to initfate discussions around labor agreements, local and targeted hiring goals, card-check neutrality, and programs to attract, train, and retain new workers. HR directors at these utflitfes confirmed that their organizatfons have plans in place that minimize the risk of labor disputes via contracts with “appropriate grievance resolutfon stfpulatfons”2 and a staffed positfon of “Labor Relatfons Program Manager.”3 Melinda Taylor, Communicatfons Director at IBEW 1547, wrote: “we would generally consider our relatfonship with each utflity to be positfve. We work well with each of these utflitfes and understand that the success of our membership is tfed to the success of each utflity. Because we have separate collectfve bargaining agreements with each utflity (some of these utflitfes have multfple CBAs), the applicable work rules and expectatfons are much clearer than if there were no CBA in place. For these reasons, we believe that the IBEW is well-positfoned to 2 Email correspondence between Reagan M. Russell, RMRussel@gvea.com, Human Resources at Golden Valley Electric Associatfon, and Clare Boersma, clareboersma@northerncompassgroup.com, Monday, March 6, 2023, 10:39 AM. 3 Email correspondence between Justfn Patterson, justfn.patterson@mea.coop, Human Resources at Matanuska Electric Associatfon, and Clare Boersma, clareboersma@northerncompassgroup.com, Monday, March 9, 2023, 3:27 PM. Page 7 of 21 maintain strong labor relatfons with our partner utflitfes throughout any Railbelt grid modernizatfon and revitalizatfon projects.”4 AEA and Railbelt utflitfes intend to maintain these CBAs for existfng employees throughout the project lifespan. Scope: 659 employees at GVEA, MEA, CEA, and HEA covered under CBAs. Budget Period to be completed: Budget period 1, 2, 3, and 4. Milestones with timelines: Existing. Agreement C: Alaska Public Contracting Law Agreement Summary: Alaska Public Contracting Law contains provisions for preference in hiring Alaskan-owned corporatfons, reductfon in barriers to Natfve Alaskans seeking apprentfceship training, local hiring preference, prevailing wages, and other forward-looking policies. Scope: AEA commits to completing all work done with GRIP funds in compliance with Federal Laws and Alaska Public Contracting Law. Budget Period to be completed: Budget period 1, 2. Milestones with timelines: RFP in alignment with all federal laws and Alaska Public Contracting Law issued for contractor to complete project scope of work in Budget Period 2. RFP in alignment with Alaska Public Contracting Law awarded for contractor to complete project scope of work. 3. Other Community and Labor Engagement Goals, Commitments, and Milestones The contractor hired to complete the Public Partfcipatfon Plan included in this Community Benefits Plan will issue a Public Partfcipatfon Plan report to AEA that summarizes key themes and concerns related to the project, as well as meetfng minutes from all public meetfngs and one-on-one organizatfonal meetfngs. This report will be made public on the project website alongside a public memo responding to the report from AEA. The memo will respond to themes and concerns surfaced during the engagement process and detail what changes to the project will be made to improve project outcomes and stakeholder contentment (in alignment with the awarded grant agreement). The transparency of this process ensures that AEA is accountable for responding to and addressing any significant concerns over project implementatfon. B. Investing in Job Quality and Workforce Continuity This project will retain high-quality jobs at all four Railbelt utflitfes by creatfng new infrastructure that will require operatfon and maintenance for the next 25 years. The average wage of a journeyman lineman at these utflitfes ranges from $54.40 to $58.00 an hour and includes employer-sponsored benefits (medical, 4 Email correspondence between Melinda Taylor, mtaylor@ibew1547.org, Communicatfons Director IBEW 1547, and Clare Boersma, clareboersma@northerncompassgroup.com, Tuesday, March 7, 2023, 6:00 PM. Page 8 of 21 dental, vision, life insurance, defined contributfon retfrement, 401(k), pension, short-term disability, long/short-term disability, tuitfon reimbursement, paid tfme off, and paid holidays). Project employees will be dispatched by organized labor and benefit from registered apprentfceship programs represented by the Alaska Apprentfceship Training Coordinators Associatfon (AATCA). AEA will conduct work sessions with IBEW 1547 as part of the public partfcipatfon plan. AEA will attempt to establish an overarching MOA with partfcipatfng Tribal councils on the Railbelt and local governments to implement targeted recruitment of Alaskan Natfve workers, local preference policies for project constructfon and establish job pipelines to enable local workers to maintain this infrastructure critfcal to their communitfes. Support for Worker Organizing/Collective Bargaining 1. Worker Organizing and Collective Bargaining Commitment C1.1: The AEA commits to contfnue to engage labor partners early to initfate discussions around future contracts, local and targeted hiring goals, and programs to attract, train, and retain a skilled workforce. Commitment C1.2: AEA pledges to remain neutral during union organizing campaigns. Commitment C1.3: AEA seeks to enter into binding arbitratfon to settle contracts. Commitment C1.4: AEA pledges to allow union organizers access to appropriate onsite non-work spaces. Commitment C1.5: AEA pledges to refrain from holding captfve audience meetfngs Commitment C1.6: Other commitments or pledges: Each of the four utflitfes in this project pledges to maintain a collectfve bargaining agreement with their employees. 2. Union support IBEW 1547 and NECA have demonstrated support for this project. They have expressed their willingness to collaborate around workforce development opportunitfes and partfcipate in the public engagement process. 3. Job Quality and Workforce Continuity a. Ongoing Operations and Production Jobs Commitment C3a.1: The four utflitfes associated with this project will retain high-quality jobs at all four Railbelt utflitfes by creatfng new infrastructure that will require operatfon and maintenance for the next 25 years. The average wage of a journeyman lineman at these utflitfes ranges from $54.40 to $58.00 an hour with employer-sponsored benefits (medical, dental, vision, life insurance, defined contributfon retfrement, 401(k), pension, short-term disability, long/short-term disability, tuitfon reimbursement, paid tfme off, and paid holidays). Commitment C3a.2: AEA will provide workforce educatfon and training for project operators through existfng utflity training programs and partfcipatfon with programs offered through Alaska Apprentfceship Page 9 of 21 Training Coordinators Associatfon (AATCA). AATCA, composed of 16 different constructfon trades, is a member of the Alaska Works Partnership, a non-profit organizatfon focused solely on getting Alaskans into careers in the constructfon industry. Alaska Works is jointly funded by the U.S. Department of Labor, the Alaska Department of Labor and Workforce Development, the Alaska Department of Transportatfon & Public Facilitfes, and the North American Building Trades Unions. Commitment C3a.3: AEA will ensure workers are engaged in the design and implementatfon of workplace safety and health plans. The existfng collectfve bargaining agreements establish Safety Committees at each of the utflitfes; contracted employees will have the same access to safety protocols on all work sites in additfon to local dispatch protocols. Employees who join the committee will be paid their normal hourly rate for their partfcipatfon on the committee. Committee members will be enrolled in mandatory worksite safety analysis, hazard preventfon and control, safety and health training, antf- harassment and by-stander interventfon training to give them an understanding of best practfces to inform their recommendatfons as further described in CBAs. b. Construction Jobs Commitment C3b.1 This project is projected to create approximately 100 new constructfon jobs. These jobs will receive competftfve wage and benefit rates benchmarked against local Davis Bacon prevailing wages. Commitment C3b.2 AEA will provide workforce educatfon and training for project constructfon employees through partfcipatfon with AATCA. By engaging registered apprentfces in this project, AEA is assured of accessing the resources brought to bear by the Alaska Works Partnership in support of local hire, veteran hire, and as diverse a workforce as Alaska has to offer. The utflizatfon of registered apprentfces will constftute approximately 15 percent of total project labor hours as prescribed in the Alaska Public Contractfng Law. Commitment C3b.3: Recipient will ensure the highest standards of constructfon site health and safety, including a site free of harassment and discriminatfon, are met. This committee includes mandatory trainings in worksite analysis, hazard preventfon and control, safety and health training, and antf- harassment training. C. Diversity, Equity, Inclusion, and Accessibility Alaska Energy Authority plans to incorporate DEIA objectfves into the project through the following means: 1. Work performed with GRIP funding will be done in compliance with Alaska Public Contractfng Law, which contains provisions for preference of local hire, apprentfceship training, prevailing wages, and other forward-looking policies. 2. Project is subject to the Office of Federal Contract Compliance Programs’ requirements for hiring and adheres to an Affirmatfve Actfon Plan. 3. Affirmatfve actfon and antf-bias training for project hires and project Health and Safety Committee members. 4. Partnership with IBEW-NECA Alaska Joint Electrical Apprentfceship and Training Trust (AJEATT) and individual utflity training programs for apprentfceship and internship programs. Page 10 of 21 5. Work sessions with the AJEATT will assess how apprentfceship programs serve workers facing systemic barriers to employment, and how to reduce those barriers through project implementatfon. Findings to be included in public partfcipatfon report. 6. Collect and monitor data on workforce veteran status, ethnicity, gender, and disability status through project implementatfon to ensure a diverse and inclusive workforce. This data will be made public on the project webpage. 7. Conduct one-on-one work sessions with organizatfons representfng ANVSAs and DACs potentfally affected by the project. Commitment C1. AEA commits to leveraging local hiring preference in Alaska public contractfng law to hire a local workforce that is as diverse as possible. Per state statute, work completed by AEA must be done in compliance with Alaska public contractfng law. Alaska public contractfng law does not allow for hiring preference specifically for economically disadvantaged minority residents, however it does include provisions for local hiring preference which may be utflized in project areas proximate to ANVSAs to create a more diverse workforce. Commitment C1.2 Per sectfon 36.10.040 of Alaska Public Contractfng law, AEA commits to adhere to all federal statutes giving preference to veterans or prohibitfng other preferences or discriminatfons among Alaskan Natfve people and United States citfzens. Commitment C1.3 AEA commits to leveraging local hiring preference in Alaska public contractfng law to hire a local workforce that is as sexually equitable as possible. Commitment C2 AEA commits to conductfng work sessions with the Alaska Joint Electrical Apprentfceship & Training Trust (AJEATT) to assess how apprentfceship programs serve workers facing systemic barriers to employment, and how to reduce those barriers through project implementatfon. The minutes from these meetfngs will be made public on the project website. Commitment C2.1 The project team will pursue a single overarching Memoranda of Agreement (MOA) with partfcipatfng Tribal governments in ANVSAs on the Railbelt to promote local hiring and create meaningful engagement. Commitment C2.3 The public partfcipatfon plan outreach materials will be piloted with focus groups composed of diverse partfcipants to evaluate their effectfveness in recruitfng diverse stakeholders to partfcipate in the Public Partfcipatfon Plan. Commitment C2.4 The Public Partfcipatfon Plan will include a “G2P” or “Going to the People” outreach component focused on recruitfng diverse populatfons to partfcipate in the engagement process. Project representatfves will staff informatfonal booths at public events such as Juneteenth programming, Alaska Federatfon of Natfves Conventfon, the Alaska State Fair, and more. Project partners will help identffy events that will reach a diversity of audiences from across the project area. These events will—when possible—focus on high-impact project areas, such as Healy, where the line will be terminated. D. Justice40 Initiative D.1. A decrease in energy burden (energy costs for low-income households) Page 11 of 21 The Beluga-Healy HVDC line, which is a part of the Railbelt’s larger Grid Modernizatfon and Resiliency Plan (GMRP), is antfcipated to provide significant benefits to Alaskan DACs both on and off the Railbelt. There are 22 census tracts that qualify as disadvantaged5 on the Railbelt, with a combined populatfon of 81,921.6 There are 17 ANVSAs on the Railbelt,7 with a combined populatfon of 160,486. All of these communitfes will receive direct benefits from the Beluga-Healy HVDC Line via long-term reductfon of their energy cost burdens. Railbelt engineers believe Beluga-Healy HVDC line, in conjunctfon with other grid upgrades, will result in decreased line losses and reduced reserves, due to increased transfer capability and improved economic dispatch leading to reduced thermal spending of 10-15%.8 Because the utflitfes are member-owned, these savings will translate to reduced consumer costs. The Railbelt’s 260,0009 residentfal utflity accounts serve 623,916 individuals,10 242,407 (39%) of whom live in a DAC or ANVSA. AEA engineers project that GMRP’s overall fuel savings could result in a reductfon of 0.5 cents/kWh to 1.5 cents/kWh for users. The combined Railbelt utflitfes sold 4,408 GWh (Gigawatt-Hours) in 2020,11 suggestfng total savings of $44,080,000 for a one cent per kWh cost reductfon. Much of this antfcipated $44 million in annual savings will be passed through to member- owners; as a percentage of populatfon served, 39% of these savings will flow to those who live in a DAC or ANVSA. A unique feature of the Beluga-Healy HVDC line as a component of the GMRP is that it will also have significant economic impacts outside of the Railbelt due to Alaska’s Power Cost Equalizatfon program (PCE). The PCE program was established in 1985 to provide economic assistance to residents and community facilitfes in rural Alaska, where electricity rates can be two to five tfmes higher than in more populated areas. The primary beneficiaries of PCE are residentfal customers, who are eligible for subsidy of actual consumptfon up to 750 kWh. If a household uses more than 750 kWh of electricity in a given month, the amount used above 750 kWh is not subsidized. Community facilitfes are also eligible for actual consumptfon up to 70 kWh per month per community resident. AEA administers the PCE program by making payments directly to individual utflitfes enrolled in the program who then pass the benefits on to qualified customers. The PCE program is funded by earnings of the PCE Endowment Fund. Alaska Statute 42.45.085 provides that five percent of the PCE Endowment Fund’s three-year monthly average market value may be appropriated to the PCE Program. In recent years, the five percent draw on the endowment has been sufficient to fully fund PCE payments. By decreasing (or incrementally reducing over the long-term) electricity rates in Anchorage and Fairbanks, PCE credit for eligible communitfes and residents will increase compared to baseline. In FY22 PCE served 188 communitfes, 15412 (82%) of whom qualify as DACs or ANVSAs. Approximately 108,914,53013 of PCE-eligible kWh were produced between 5 DOE Disadvantaged Communitfes Reporter 6 American Community Survey 2021 5 Year Populatfon Estfmates 7 2020 U.S. Census, DOE Disadvantaged Communitfes Reporter 8 Brian Hickey, Project Lead, P.E., PMP., Brian.Hickey@mea.coop, Zoom, 8:00-8:30 am, March 1st, 2023. 9 Summed from: Homer Electric Associatfon, Golden Valley Electric Associatfon, Chugach Electric Associatfon Inc., Matanuska Electric Associatfon, Inc. 10 Alaska Department of Labor and Workforce Development, Research and Analysis Sectfon. 11 U.S. Energy Informatfon Administratfon, 2020 12 https://www.energy.gov/diversity/justfce40-initfatfve 13 FY22 PCE Community Report.pdf (akenergyauthority.org) Page 12 of 21 residentfal and community facilitfes in those 154 DACs. At a one cent decrease in the average class rate, the increased credit amount that would be issued by AEA to PCE-enrolled DACs is $1,089,145.14 In sum: GMRP and the Beluga-Healy HVDC Line’s projected one cent/kWh reductfon in energy costs for users is calculated to result in $44,080,000 in reduced energy burdens for on-Railbelt electricity users, 39% of whom belong to DACs or live in ANVSAs. Through AEA’s power-cost-equalizatfon program, that same one cent/kWh reductfon in on-Railbelt energy costs is antfcipated to result in an additfonal $1,329,60615 in PCE subsidies to off-Railbelt communitfes, 82% of which will flow to DACs or ANVSAs. Taken together, this reduced energy burden for on-Railbelt residents and increased PCE subsidy for off- Railbelt residents represents cumulatfve annual benefits to DACs or ANVSAs of $18,215,330, or slightly over 40% of a calculated $45,409,606 in total annual benefits. Benefit D1.1: Increased PCE credit for 154 off-Railbelt DACs  154 DACs and/or ANVSAs will benefit from increased PCE credits.  The benefit will be delivered via off-Railbelt utflitfes, including Alaska Village Electric Cooperatfve.  When benefit will be delivered: Benefits will be delivered after project completfon in year 2034.  Milestones toward benefit delivery: Project close out.  Metrics to track and report on benefits: AEA Power Cost Equalizatfon Program annual report allows for the calculatfon of the delta in PCE credits to DACs pre-and-post project completfon.  Unantfcipated barriers and strategies to address barriers: These projectfons rely on reduced thermal spending and line loss cost reductfons being passed through from utflity operatfons to electric co-operatfve member-owners in the form of reduced rates. Rate setting for public utflitfes is complicated and includes many factors other than thermal spending; exact cost savings are therefore difficult to predict, but the project is, at the very least, antfcipated to keep Railbelt electricity rates lower for longer, and increase PCE credits versus baseline.  Community-based organizatfon(s) involved in identffying or negotfatfng benefit or developing plan for benefit delivery: Power Cost Equalizatfon is stfpulated by Alaska Statute 44.83.940. D.2. A decrease in environmental exposure and burdens Benefit D2.1: This work is projected to result in long-term increased integratfon of renewables in the Railbelt grid by improving economy of scale. Such integratfon would reduce emissions from power generatfon from coal and natural gas. Although woodstoves result in the majority of PM2.5 partfculate contaminatfon throughout interior Alaska, this project’s projected reduced thermal spending via increased renewables can be reasonably assumed to have air quality benefits, especially for the community of Healy (located 14 Actual savings would be less than this, since Juneau, which is outside the Railbelt, is included in the “Average Class Rate”, and their rates would not be affected by thermal spending reductfons from GMRP. It should also be noted that PCE payments received by a partfcular utflity are not uniformly distributed and will vary from year-to- year based on the utflitfes’ energy cost reportfng. 15 FY22 PCE Community Report.pdf (akenergyauthority.org) Page 13 of 21 within Denali Borough—a DAC), which is home to a coal power plant with a peak generatfon capacity of 92.8 MW. D.3. An increase in quality job creation, the clean energy job pipeline, and job training for individuals All procurement will comply with Alaska public contractfng law, which contains provisions for local hire, apprentfceship training, prevailing wages, and other forward-looking policies. The project will partner with IBEW-NECA Alaska Joint Electrical Apprentfceship and Training Trust (AJEATT) and others to source candidates and ensure the development of a skilled, inclusive local workforce. 10-15 new permanent positfons will be created through the Beluga-Healy HVDC line for maintenance and operatfons of the new infrastructure. Benefit D3.1: The project intends to develop an overarching Memoranda of Agreement (MOA) with partfcipatfng Tribal Councils on the Railbelt to promote local hiring and creatfng meaningful engagement. D.5. Increases in energy democracy, including community ownership of project assets Benefit D5.1: All four electric utflitfes included in this project are member-owned cooperatfves; therefore, the electrical infrastructure for most of the communitfes affected by this project is already owned by the residents who live in those communitfes. One meaningful way this project will forward energy democracy goals is by designing a training-to- careers pipeline to recruit and train individuals to maintain the energy infrastructure on which their own communitfes rely. AEA believes that communitfes are strongest when they are meaningfully engaged in the maintenance and operatfons of their energy infrastructure, and the labor goals of this project are designed to train individuals—including Tribal members—to gain the skills necessary to maintain local electrical infrastructure and create a citfzenry who not only can repair and maintain their electrical infrastructure, but who are also sufficiently knowledgeable about that infrastructure that they are able to guide their communitfes in decisions about its future. D.6. Increased parity in clean energy technology access and adoption Benefit D6.1: The project seeks to build a resilient, clean, smart electrical grid in Alaska. Increased transfer capacity between regions will enable higher renewable energy integratfon and a reductfon in fossil fuel generatfon and associated emissions. A recent report from the Denver-based Natfonal Renewable Energy Laboratory said that getting to 75% renewable energy on the Railbelt by 2040 could be the lowest-cost energy optfon for Southcentral Alaska. The study estfmates that $100 million in annual savings could be realized if that 2040 target was met when compared to a scenario with no new renewable energy investment. That transitfon is only feasible with the transmission upgrades made possible through this project. The Beluga-Healy HVDC line is a critfcal link in bringing clean energy technology to the 242,407 individuals who live in the DACs and ANVSAs on the Railbelt. Page 14 of 21 D.7. An increase in energy resilience Benefit D7.1: The Railbelt region is home to some of the harshest conditfons on earth, making grid resilience a top priority. Past disasters include earthquakes, avalanches, forest fires, and landslides, which have left communitfes isolated and without power for days. 26% of Railbelt customers live in ANVSAs, many of which are in remote areas with energy infrastructure that is aging and partfcularly vulnerable to natural disaster. Increased grid resiliency is a primary goal of this project. The interregional transmission line that will be installed parallel to the line that currently tfes together the Railbelt’s Southern and Central regions will allow for contfnued energy transmission between regions in the event of a major natural disaster. Additfonal resilience benefits include right-of-way clearing, aerial inspectfons, and refurbishment of existfng lines and structures. D.8. Anticipated or potential negative environmental impacts There are potentfal viewshed impacts near Denali State Park and Denali Natfonal Park. A robust and early stakeholder engagement plan will assess both public and agency desires and tolerances. The project will build in contfngencies/optfons such as using innovatfve advanced conductors to minimize conductor size and spacing, potentfally undergrounding some portfons of the line, or routfng the line around the state and natfonal parks, to ensure that a cost-effectfve and publicly acceptable outcome is reached. D. Summary Table: Community Benefits Outcomes and Objectives Category and Commitment Existing or Planned Budget period 1 Budget period 2 Budget period 3 Budget period 4 Community and Labor Engagement Issue RFP and select contractor to assist with public partfcipatfon plan. Planned X Draft stakeholder engagement strategies and outreach media. Planned A focus group will be used to test the effectfveness of these materials on diverse populatfons. Launch RIR website with public meetfng schedule, project descriptfon, ArcGIS Online mapping tool, and public comment sectfon. Planned X Each (4) utflity provider and AEA hosts introductory public work session. Planned X Page 15 of 21 Conduct surveys to address data gaps identffied during introductory public work sessions. Planned X One-on-one work sessions with relevant organizatfons, including Tribes and DACs. Planned & Existfng Contact already made with: Alaska Federatfon of Natfves, Alaska Village Electric Cooperatfve, Alaska Black Caucus, Alaska Municipal League, IBEW Local 1547, Internatfonal Union of Operatfng Engineers (IUOE) Local 302, Alaska Operatfng Engineers Training Trust, Alaska Joint Electrical Apprentfceship & Training Trust, Fairbanks Chamber of Commerce, Alaska AFL-CIO, Anchorage Economic Development Corporatfon. Joint meetfng(s) with all relevant agencies re: viewshed and wildlife impacts from transmission line easement through Denali state and Natfonal Parks. Planned X “Going to the people” outreach conducted in more informal settings to recruit diverse group of stakeholders, including outreach event in Healy. Planned Outreach conducted at minimum of 3 public events designed to reach diverse/relevant audiences: (Alaska Federatfon of Natfves conventfon, Alaska Black Caucus Sunday Page 16 of 21 night Zoom meetfngs, Alaska State Fair, etc.) One event to be located in Healy. Each (4) utflity provider as well as Alaska Energy Authority hosts second public work session. Survey results shared as well as public comment themes to-date. Planned X RIR public partfcipatfon plan report published by AEA, along with memo in response, summarizing and responding to comments. Planned X Investing in Job Quality and Workforce Continuity Total Number of Permanent Operatfons Jobs: 659 Number of Constructfon phase jobs: 100 Number of new permanent positfons: 15 Retain high-quality jobs (the average wage of a journeyman lineman at these utflitfes ranges from $54.40 to $58.00 an hour) with employer-sponsored benefits (medical, dental, vision, life insurance, defined contributfon retfrement, 401(k), pension, short-term disability, long/short-term disability, tuitfon reimbursement, paid tfme off, and paid holidays) at all four Railbelt utflitfes by creatfng new infrastructure that will require operatfon and maintenance for the next 25 years. 659 existfng jobs under CBAs X X X X AEA will conduct work sessions with IBEW Local 1547 as part of public partfcipatfon plan. Planned X AEA will attempt to establish overarching MOA with Planned X X Page 17 of 21 partfcipatfng Railbelt Tribes and local governments to implement targeted recruitment strategies for RIR projects. Support for Worker Organizing/Collectfve Bargaining ☒ Pledge to remain neutral during any union organizing campaigns ☒ Intentfon to enter into binding arbitratfon to settle first contracts ☒ Pledge to allow union organizers access to appropriate onsite non-work spaces (e.g. lunch rooms) ☒ Pledge to refrain from holding captfve audience meetfngs X X X X Diversity, Equity, Inclusion, and Accessibility ☒ Local and/or targeted recruitment efforts ☒ Partner with quality pre- apprentfceship or apprentfceship readiness program AEA commitment that work performed with GRIP funding will be done in compliance with Alaska public contractfng law, which contains provisions for local hire preference, apprentfceship training, prevailing wages, and other forward-looking policies. Existfng X X X X Project is subject to the Office of Federal Contract Compliance Programs’ requirements for hiring and adhering to an Affirmatfve Actfon Plan. Existfng X X X X Affirmatfve actfon and antf-bias trainings for project hirers. Planned X X X Partnership with IBEW-NECA Alaska Joint Electrical Apprentfceship and Existfng X X X X Page 18 of 21 Training Trust and individual utflity training programs Work sessions with the Alaska Joint Electrical Apprentfceship & Training Trust (AJEATT) and others will assess how these apprentfceship programs serve workers facing systemic barriers to employment, and how to reduce those barriers through GMRP implementatfon. Findings to be included in public partfcipatfon report. Planned X X Collect data on workforce veteran status, ethnicity, gender, and disability status through GMRP implementatfon. Make data public on project website. Planned X X X Conduct work sessions with organizatfons representfng DACs affected by project, including tribal councils, Alaska Black Caucus, and Alaska Federatfon of Natfves, to understand desired benefits and reduced impacts. Minutes included in public partfcipatfon plan report. Planned X Develop MOAs with partfcipatfng, affected/on-Railbelt Tribes to ensure a clear framework for promotfng local hiring and creatfng meaningful engagement. Planned X X Justice40 Initiative AEA will offer to convene a joint meetfng with Alaska Department of Fish and Game, Natfonal Marine Fisheries Service, and Kenaitze and Knik Tribal Councils (to be invited – others may be included as well) to discuss how to minimize adverse environmental impacts re: placement of HVDC cable across Cook Inlet. Minutes included in public partfcipatfon plan report. Planned X Beluga-Healy HVDC Line will increase transfer capacity between the three Railbelt regions, paving the way for development of clean Projected Page 19 of 21 energy solutfons that will mitfgate environmental impacts from 3,218 natural-gas-produced GWh on Railbelt each year, resultfng in 1.61 billion kilograms of carbon dioxide equivalent. Beluga-Healy HVDC line, in conjunctfon with other grid upgrades, will result in decreased line losses and reduced reserves, due to increased transfer capability and improved economic dispatch leading to reduced thermal spending reductfons of 10-15%, representfng a non-cumulatfve decrease of over 200 million kilograms carbon dioxide equivalent per year. Projected Railbelt’s 260,000 residentfal utflity accounts serve 623,916 individuals, 242,407 (39%) of whom live in a DAC or on in ANVSAs. AEA engineers project RIR (including the Beluga-Healy HVDC line) overall fuel savings could result in a reductfon of 0.5 cents/kWh to 1.5 cents/kWh. The combined Railbelt utflitfes sold 4,408 GWh (Gigawatt- Hours) in 2020, suggestfng total savings of $44,080,000 for a 1 cent per kWh cost reductfon. Much of these $44 million in annual savings should pass through to member- owners. Projected In FY22 PCE served 188 communitfes, 154 (82%) of whom qualify as DACs or ANVSAs. Approximately 108,914,530 of PCE- eligible kWh were produced between residentfal and community facilitfes in those 154 DACs. At a one cent decrease in the average class rate, the increased credit amount that would be issued by AEA to PCE-enrolled DACs is $1,089,145. Projected 26% of Railbelt customers live in an Alaska Natfve Village Statfstfcal Planned x Page 20 of 21 Area (ANVSA), many of which are located in remote areas with energy infrastructure that is partfcularly vulnerable to natural disaster. Increased grid resiliency is a primary goal of this project, best embodied by the interregional transmission line that will be installed parallel to the line that currently tfes together the Railbelt’s Southern and Central regions, and which will allow for contfnued energy transmission between regions in the event of a major natural disaster. Build pipeline from apprentfceships and internships in remote communitfes into careers working on Railbelt grid. Beluga-Healy HVDC line will create high-paying jobs for members of DACs who live along the Railbelt by collaboratfng with IBEW-NECA Alaska Joint Electrical Apprentfceship and Training Trust, individual utflity training programs, and local colleges and potentfally the University of Alaska System. Planned Identffies benefits/impacts to disadvantaged communitfes ☒ Yes Including, Cantwell ANVSA, Chickaloon ANVSA, Chitfna ANVSA, Copper Center ANVSA, Eklutna ANVSA, Gakona ANVSA, Gulkana ANVSA, Kenaitze ANVSA, Knik ANVSA, Nanwalek ANVSA, Nenana ANVSA, Ninilchik ANVSA, Northway ANVSA, Port Graham ANVSA, Seldovia ANVSA, Tanacross ANVSA, Tazlina ANVSA) ☐ No Page 21 of 21 Reductfon in energy costs ☒ Yes ☐ No A decrease in environmental exposure and burdens ☒ Yes ☐ No An increase in quality job creatfon, the clean energy job pipeline, and job training for individuals ☒ Yes ☐ No X X X Increases in clean energy enterprise creatfon and contractfng (e.g., minority-owned or diverse business enterprises) ☐ Yes ☒ No An increase in energy resilience ☒ Yes ☐ No Resilience benefits include right of way clearing, aerial inspectfons, and refurbishment of existfng lines and structures. X X Award Number:Award Recipient:Alaska Energy Authority(May be award recipient or sub-recipient)Section A - Budget SummaryFederal Cost Share Total Costs Cost Share % Proposed Budget Period DatesBudget Period 1$40,098,443 $40,098,443 $80,196,886 50.00% 07/01/2024 - 06/30/2026Budget Period 2$91,198,443 $91,198,443 $182,396,887 50.00% 07/01/2026 - 06/30/2028Budget Period 3$125,100,000 $125,100,000 $250,200,000 50.00% 07/0/2028 - 06/30/2030Budget Period 4$108,421,795 $108,421,795 $216,843,591 50.00% 07/01/2030 - 06/30/2032Budget Period 5$0 $0 $0 0.00%Total$364,818,682 $364,818,682 $729,637,364 50.00%Section B - Budget CategoriesCATEGORY Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Total Costs % of Project Comments (as needed)a. Personnel$1,536,321 $1,597,774 $1,661,685 $1,728,152 $0 $6,523,932 0.89%b. Fringe Benefits$1,082,019 $1,125,300 $1,170,312 $1,217,124 $0 $4,594,756 0.63%c. Travel$75,600 $79,380 $83,349 $87,516 $0 $325,845 0.04% DNI Travel related to the CBPd. Equipment$80,000 $0 $80,000 $0 $0 $160,000 0.02%e. Supplies$80,000 $84,000 $88,200 $92,610 $0 $344,810 0.05%f. ContractualSub-recipient$0 $0 $0 $0 $0 $0 0.00%Contractor$2,798,000 $2,708,000 $2,558,000 $2,528,000 $0 $10,592,000 1.45%FFRDC$0 $0 $0 $0 $0 $0 0.00%Total Contractual $2,798,000 $2,708,000 $2,558,000 $2,528,000 $0 $10,592,000 1.45%g. Construction$72,770,283 $175,020,599 $242,787,102 $209,389,578 $0 $699,967,562 95.93%h. Other Direct Costs$0 $0 $0 $0 $0 $0 0.00%Total Direct Costs$78,422,223 $180,615,053 $248,428,648 $215,042,981 $0 $722,508,906 99.02%i. Indirect Charges$1,774,663 $1,781,834 $1,771,352 $1,800,609 $0 $7,128,458 0.98%Total Costs$80,196,886 $182,396,887 $250,200,000 $216,843,591 $0 $729,637,364 100.00%Benefit Budget $                156,410  $        729,793,774 1. If using this form for award application, negotiation, or budget revision, fill out the blank white cells in workbook tabs a. through j. with total project costs. 2. Blue colored cells contain instructions, headers, or summary calculations and should not be modified. Only blank white cells should be populated. 3. Enter detailed support for the project costs identified for each Category line item within each worksheet tab to autopopulate the summary tab. 4. The total budget presented on tabs a. through i. must include both Federal (DOE) and Non-Federal (cost share) portions.5. All costs incurred by the preparer's sub-recipients, contractors, and Federal Research and Development Centers (FFRDCs), should be entered only in section f. Contractual. All other sections are for the costs of the preparer only.6. Ensure all entered costs are allowable, allocable, and reasonable in accordance with the administrative requirements prescribed in 2 CFR 200, and the applicable cost principles for each entity type: FAR Part 31 for For-Profit entities; and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities. 7. Add rows as needed throughout tabs a. through j. If rows are added, formulas/calculations may need to be adjusted by the preparer. Do not add rows to the Instructions and Summary tab. If your project contains more than five budget periods, consult your DOE contact before adding additional budget period rows and columns.8. ALL budget period cost categories are rounded to the nearest dollar.BURDEN DISCLOSURE STATEMENTPublic reporting burden for this collection of information is estimated to average 24 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden, to Office of Information Resources Management Policy, Plans, and Oversight, AD-241-2 - GTN, Paperwork Reduction Project (1910-5162), U.S. Department of Energy 1000 Independence Avenue, S.W., Washington, DC 20585; and to the Office of Management and Budget, Paperwork Reduction Project (1910-5162), Washington, DC 20503.SUMMARY OF BUDGET CATEGORY COSTS PROPOSEDThe values in this summary table are from entries made in subsequent tabs, only blank white cells require data entryAdditional Explanation (as needed):Please read the instructions on each worksheet tab before starting. If you have any questions, please ask your DOE contact! Do not modify this template or any cells for formulas!Instructions and SummaryDate of Submission:Alaska Energy AuthorityForm submitted by: Personnel Cost using Loaded Rate:*apply 4% increase per budget period to account for merit based increases per state's salary schedule; increase in leave accrual based on longevity; and benefit cost increases.  Position Title % Hrs/yrBiannual HrsRate Period 1 Budget Period 1Rate Period 2 Budget Period 2Rate Period 3 Budget Period 3Rate Period 4 Budget Period 4 Total* 104.00% * 104.00% * 104.00%1 Contracting Officer 20% 390 780 89.88$    70,102.97$           93.47$    72,907.00$           97.21$    75,823.00$           101.10$  78,856.00$           297,688.97$             2 Executive Director 10% 195 390 183.59$  71,600.53$           190.93$  74,465.00$           198.57$  77,443.00$           206.52$  80,541.00$           304,049.53$             3 Communicaitons Director 20% 390 780 112.94$  88,096.22$           117.46$  91,620.00$           122.16$  95,285.00$           127.05$  99,096.00$           374,097.22$             4 GIS 15% 292.5 585 83.79$    49,014.57$           87.14$    50,975.00$           90.62$    53,014.00$           94.25$    55,135.00$           208,138.57$             5 Owned Assets Director 20% 390 780 165.94$  129,432.18$         172.58$  134,609.00$         179.48$  139,994.00$         186.66$  145,594.00$         549,629.18$             6 Senior Infrastructure Engineer 100% 1950 3900 111.09$  433,269.31$         115.54$  450,600.00$         120.16$  468,624.00$         124.97$  487,369.00$         1,839,862.31$         7 Infrastructure Engineer 20% 390 780 104.63$  81,607.83$           108.81$  84,872.00$           113.16$  88,267.00$           117.69$  91,798.00$           346,544.83$             8 Federal Project Manager 100% 1950 3900 152.99$  596,670.13$         159.11$  620,537.00$         165.48$  645,358.00$         172.10$  671,173.00$         2,533,738.13$         9 Environmental Engineer 80% 1560 3120 152.99$  477,336.10$         159.11$  496,430.00$         165.48$  516,287.00$         172.10$  536,938.00$         2,026,991.10$         10 Program Controls 100% 1950 3900 106.19$  414,140.35$         110.44$  430,706.00$         114.85$  447,934.00$         119.45$  465,852.00$         1,758,632.35$         11 Program Project Manager 50% 975 1950 106.19$  207,070.17$         110.44$  215,353.00$         114.85$  223,967.00$         119.45$  232,926.00$         879,316.17$             ‐$                         ‐$                        2,618,340.36$      2,723,074.00$      2,831,996.00$      2,945,278.00$      11,118,688.36$       11,118,688.36$        Base, Release Time, Benefits break out26 pp year 11 holiday; 7.5 hr day                      1,950 25.10% 6.13% 1.45% 0.68%Position Title Annual Salary  Leave Accrual PP ‐ hrs  Annual Leave ‐ Hrs  Annual Holiday ‐ Hrs   Net Billable Hrs  Hourly Rate Based on 1950 hrs Annual Leave HolidayRelease TimeHealth Ins (1,793 mo.)PERS RetirementSupplemental Benefits (in lieu of social security)MEDC WC BenefitsLoaded Labor RateContracting Officer 97,598.00       6.92              179.92          82.50            1,687.58         50.05           5.34            2.45            7.78         12.75      14.52         3.55 0.84 0.39 32.04 89.88          Executive Director 209,997.00     8.65              224.90          82.50            1,642.60         107.69        14.74          5.41            20.15      13.10      32.09         7.84 1.85 0.87 55.75 183.59       Communication Director 126,789.00     6.92              179.92          82.50            1,687.58         65.02           6.93            3.18            10.11      12.75      18.86         4.61 1.09 0.51 37.81 112.94       GIS 91,280.00       6.07              157.82          82.50            1,709.68         46.81           4.32            2.26            6.58         12.58      13.40         3.27 0.77 0.36 30.40 83.79          Owned Assets Director 182,657.00     10.38            269.88          82.50            1,597.62         93.67           15.82          4.84            20.66      13.47      28.70         7.01 1.66 0.78 51.61 165.94       Senior Infrastructure Engineer 124,449.00     6.92              179.92          82.50            1,687.58         63.82           6.80            3.12            9.92         12.75      18.51         4.52 1.07 0.50 37.35 111.09       Infrastructure Engineer 118,000.00     6.07              157.82          82.50            1,709.68         60.51           5.59            2.92            8.51         12.58      17.32         4.23 1.00 0.47 35.61 104.63       Federal Project Manager 180,000.00     6.07              157.82          82.50            1,709.68         92.31           8.52            4.45            12.98      12.58      26.43         6.45 1.53 0.72 47.71 152.99       Environmental Engineer 180,000.00     6.07              157.82          82.50            1,709.68         92.31           8.52            4.45            12.98      12.58      26.43         6.45 1.53 0.72 47.71 152.99       Program Project Manager 120,000.00     6.07              157.82          82.50            1,709.68         61.54           5.68            2.97            8.65         12.58      17.62         4.30 1.02 0.48 36.00 106.19       Program Project Manager 120,000.00     6.07              157.82          82.50            1,709.68         61.54           5.68            2.97            8.65         12.58      17.62         4.30 1.02 0.48 36.00 106.19       *apply 4% increase per budget period to account for merit based increases per state's salary schedule; increase in leave accrual based on longevity; and benefit cost increases.  Cost by Budget Period*: Bi‐Annual Hours  Bi‐Annual Salary  Leave + Holiday  Employer Paid Benefits  Total Budget Period 1  Total Budget Period 2  Total Budget Period 3  Total Budget Period 4 Contracting Officer 780      39,039.00    6,070.63       24,993.34    70,103            72,907        75,823        78,856        297,690  Executive Director 390      41,999.10    7,859.87       21,741.560  71,601            74,465        77,443        80,541        Communication Director 780      50,715.60    7,886.32       29,494.30    88,096            91,620        95,285        99,096        GIS 585      27,383.85    3,849.21       17,781.51    49,015            50,975        53,014        55,135        Owned Assets Director 780      73,062.60    16,115.14    40,254.44    129,432          134,609      139,994      145,594      Senior Infrastructure Engineer 3,900   248,898.00  38,703.83    145,667.48  433,269          450,600      468,624      487,369      Infrastructure Engineer 780      47,197.80    6,634.64       27,775.39    81,608            84,872        88,267        91,798        Federal Project Manager 3,900   360,009.00  50,603.15    186,057.98  596,670          620,537      645,358      671,173      Environmental Engineer 3,120   288,007.20  40,482.52    148,846.38  477,336          496,430      516,287      536,938      Program Controls 3,900   240,006.00  33,735.44    140,398.91  414,140          430,706      447,934      465,852      Program Project Manager 1,950   120,003.00  16,867.72    70,199.45    207,070          215,353      223,967      232,926      1,536,321    228,808        853,211        2,618,340      2,723,074   2,831,997  2,945,277  2,618,340            2,723,074        2,831,996       2,945,278       *apply 4% increase per budget period to account for merit based increases per state's salary sched‐                         (0.03)                0.93                (1.19)               Personnel Cost:  Budget Period 1  Budget Period 2  Budget Period 3  Budget Period 4  Total Contracting Officer 39,039            40,601          42,225          43,914          165,778          Executive Director 41,999            43,679          45,426          47,243          178,348          Communication Director 50,716            52,744          54,854          57,048          215,362          GIS 27,384            28,479          29,618          30,803          116,285          Owned Assets Director 73,063            75,985          79,025          82,185          310,258          Senior Infrastructure Engineer 248,898          258,854        269,208        279,976        1,056,936       Infrastructure Engineer 47,198            49,086          51,049          53,091          200,424          Federal Project Manager 360,009          374,409        389,386        404,961        1,528,765       Environmental Engineer 288,007          299,527        311,509        323,969        1,223,012       Program Controls 240,006          249,606        259,590        269,974        1,019,177       Program Project Manager 120,003          124,803        129,795        134,987        509,588          1,536,321       1,597,774    1,661,685    1,728,152    6,523,932      Fringe Benefit Cost:  Budget Period 1  Budget Period 2  Budget Period 3  Budget Period 4  Total Contracting Officer 31,064            32,307          33,599          34,943          131,912          Executive Director 29,601            30,785          32,017          33,298          125,701          Communication Director 37,381            38,876          40,431          42,048          158,735          GIS 21,631            22,496          23,396          24,332          91,854            Owned Assets Director 56,370            58,624          60,969          63,408          239,371          Senior Infrastructure Engineer 184,371          191,746        199,416        207,393        782,926          Infrastructure Engineer 34,410            35,786          37,218          38,707          146,121          Federal Project Manager 236,661          246,128        255,973        266,212        1,004,973       Environmental Engineer 189,329          196,902        204,778        212,969        803,978          Program Controls 174,134          181,100        188,344        195,877        739,455          Program Project Manager 87,067            90,550          94,172          97,939          369,728          1,082,019       1,125,300    1,170,312    1,217,124    4,594,756      2,618,340       2,723,074    2,831,997    2,945,277    11,118,688    x‐check2,618,340             2,723,074          2,831,996          2,945,278          11,118,688          ‐                         (0.03)                  0.93                   (1.19)                  (0.28)                     Personnel + Fringes Cost:  Budget Period 1  Budget Period 2  Budget Period 3  Budget Period 4  Total Contracting Officer 70,103            72,907          75,823          78,856          297,690          Executive Director 71,601            74,465          77,443          80,541          304,049          Communication Director 88,096            91,620          95,285          99,096          374,097          GIS 49,015            50,975          53,014          55,135          208,139          Owned Assets Director 129,432          134,609        139,994        145,594        549,629          Senior Infrastructure Engineer 433,269          450,600        468,624        487,369        1,839,863       Infrastructure Engineer 81,608            84,872          88,267          91,798          346,545          Federal Project Manager 596,670          620,537        645,358        671,173        2,533,738       Environmental Engineer 477,336          496,430        516,287        536,938        2,026,991       Program Controls 414,140          430,706        447,934        465,852        1,758,632       Program Project Manager 207,070          215,353        223,967        232,926        879,316          2,618,340       2,723,074    2,831,997    2,945,277    11,118,688    Source: pay rate roster Calculated based on Pay Rate Roster (Internal payroll data maintained my AIDEA) FY24 Rates Domestic Travel Depart From Destination No of Trips No. of DaysNo of TravelersTrips x TravelersLodging per Traveler per TripTrips x Travelers  x  LodgeFlight per Traveler (RT)Trips x Travelers x FlightsVehicle per TravelerVehicle * DaysPer Diem per TravelerTrips * travelers * days * Per Diem CostIn State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 40 250$        10,000$   1,100$        44,000$      100$        4,000$     58,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 40 250$        10,000$   500$           20,000$      100$        4,000$     34,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 1,000$     4,000$     1,500$        6,000$        500$        2,000$     12,000$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 1,000$     4,000$     1,500$        6,000$        400$        1,600$     500$        2,000$     13,600$        117,600$      Periods 4$                  470,400$      Domestic Travel Depart From Destination No of Trips No. of DaysNo of TravelersTrips x Travelers Lodging per Traveler Trips x Travelers  x Nights (D‐1) x LodgeFlight per Traveler (RT)Trips x Travelers x FlightsVehicle per TravelerVehicle * DaysPer Diem per TravelerTrips * travelers * days * Per Diem CostIn State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 20 250$        5,000$     1,100$        22,000$      100$        2,000$     29,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 20 250$        5,000$     500$           10,000$      100$        2,000$     17,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 400$        6,400$     1,500$        6,000$        500$        2,000$     14,400$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 350$        5,600$     1,500$        6,000$        400$        1,600$     500$        2,000$     15,200$        75,600$        100%Budget Period 1 75,600$        In State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 20 250$        5,000$     1,100$        22,000$      100$        2,000$     29,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 20 250$        5,000$     500$           10,000$      100$        2,000$     17,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 400$        6,400$     1,500$        6,000$        500$        2,000$     14,400$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 350$        5,600$     1,500$        6,000$        400$        1,600$     500$        2,000$     15,200$        75,600$        105% Budget Period 2 79,380$        In State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 20 250$        5,000$     1,100$        22,000$      100$        2,000$     29,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 20 250$        5,000$     500$           10,000$      100$        2,000$     17,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 400$        6,400$     1,500$        6,000$        500$        2,000$     14,400$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 350$        5,600$     1,500$        6,000$        400$        1,600$     500$        2,000$     15,200$        75,600$        110%Budget Period 3 83,349$        In State Trips ‐ Nothern Sites ‐ 10 Trips per yearANC Northern Alaska 10 2 2 20 250$        5,000$     1,100$        22,000$      100$        2,000$     29,000$        In State Trips ‐ Southern Sites ‐ 10 Trips per yearANC Southern Alaska 10 2 2 20 250$        5,000$     500$           10,000$      100$        2,000$     17,000$        Out of State Trip ‐ DCANC Out of State 2 5 2 4 400$        6,400$     1,500$        6,000$        500$        2,000$     14,400$        Out of State Trip ‐ Conference or TrainingANC Out of State 2 5 2 4 350$        5,600$     1,500$        6,000$        400$        1,600$     500$        2,000$     15,200$        75,600$        116%Budget Period 4 87,516$        Total Travel 325,845$       Equipment Item Qty Unit Cost Total Cost Revised Budget Period 1 Office Set‐up ‐ 8 new positions 8 10,000$        80,000$           Budget Period 20 Budget Period 3 Additional Equipment / replaceme 8 10,000          80,000             Budget Period 4 Note:  3 of 11 positions estimated to work on this project are existing PCNs.   ApplicationNo of Staff $/year $/Staff/YrYrs per Budget PeriodTotal Cost per Budget PeriodMisc Supplies 20 2,000$            40,000$          2$                    80,000$          Periods 4320,000$        Misc Supplies 20 2,000$            40,000$          2$                    80,000$          Budget Period 1105% 84,000$          Budget Period 2105% 88,200$          Budget Period 3105% 92,610$          Budget Period 4344,810$         Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 TotalBudget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 TotalLegal Services Competitive Bid or State of Alaska 425,000$               425,000$               425,000$               425,000$               1,700,000$           Public Relations Firm Competitive Bid 48,000$                 48,000$                 48,000$                 48,000$                 192,000$               Cultural Consoltation Competitive Bid 100,000$               100,000$               100,000$               100,000$               400,000$               Design & Engineering Consultant Competitive Bid 400,000$               400,000$               400,000$               400,000$               1,600,000$           Land Consultant Competitive Bid 400,000$               400,000$               400,000$               400,000$               1,600,000$           Labor/Govermental Consulting Competitive Bid 225,000$               225,000$               225,000$               225,000$               900,000$               Project Coordination Committee Competitive Bid 600,000$               600,000$               600,000$               600,000$               2,400,000$           Contractor Federal Projects Reporting Competitive Bid 150,000$               150,000$               150,000$               150,000$               600,000$               Accounting & Auditing Services Competitive Bid 150,000$               150,000$               150,000$               150,000$               600,000$               insurance Consultant Competitive Bid 100,000$               10,000$                 10,000$                 10,000$                 130,000$               NEPA Consultant Competitive Bid 200,000$               200,000$               30,000$                  ‐$                       430,000$               2,798,000$           2,708,000$           2,538,000$           2,508,000$           10,552,000$         Community Benefits Plan Quote‐$                        ‐$                       20,000$                 20,000$                 40,000$                 2,798,000$           2,708,000$           2,558,000$           2,528,000$            ‐$                       10,592,000$         10,592,000$      AEA GMRP Public Participation PlanTotalDec 2024- December 2026 hours rate hours rate hours rate hours rate hours rate hours rate ate$215 $165 $0 $155 $150 $145Task1. Project Administration10 $2,150 10 $1,650 0 $0 2 $310 15 $2,250 2 $290 $6,6502. Draft Public Participation plan8 $1,720 30 $4,950 4 $0 2 $310 30 $4,500 0 $0 $11,4803. Implement Public Participation PlanFacilitate five (5) introductory public work sessions, design/administer survey instrument, facilitate eight (8) one-on-one organizational work sessions, conduct informal outreach at three (3) events, facilitate five (5) secondary public work sessions, facilitate board leadership presentations.60 $12,900 100 $16,500 10 $0 45 $6,975 160 $24,000 35 $5,075 $65,4504. Public website designWebsite to include GIS tool for geocoded public comments. 4 $860 6 $990 16 $0 0 $0 12 $1,800 80 $11,600 $15,2505. OutreachRadio, social media, electric co-op mailers. (see "Advertising Expenses")0 $0 4 $660 12 $0 0 $0 30 $4,500 12 $1,740 $6,9006. Create reportAgnew::Beck will draft formal report of public participation plan findings.15 $3,225 40 $6,600 16 $0 5 $775 45 $6,750 8 $1,160 $18,5107. Public Review and Final Report Revisions4 $860 4 $660 20 $0 0 $0 4 $600 0 $0 $2,120Travel *$25,050Advertising Expenses **$5,000TOTAL*** 101 $21,715 194 $32,010 78 $0 54 $8,370 296 $44,400 137 $19,865 $156,410CHECKTravel Expense DetailTotal Lodging (2 nights/community meeting)$200 16 $200 16 $200 16 $9,600 Rental Car (2 days/meeting, shared)$150 16 $2,400 Meals ($75/day per diem)$75 18 $75 18 $75 18 $4,050Facility Rental ($800/meeting)$8,000Meeting Supplies ($50/meeting)$1,000TOTAL***$25,050$25,050EXCLUSIONS + TERMSThis estimate is good for 90 days from the date of the estimate.Principal Senior Manager Senior Associate* Travel - Roundtrip from Anchorage** Other Expenses - Include costs for phone and related equipment and services required in the normal performance of the contract. Costs for services required to produce informational, advertising or meeting materials are included in this budget; however, costs for printing, mailing or otherwise distributing these materials, or for paid advertising or other public notices are not included in this budget and would be paid for directly by client, as needed. Digital versions of all final materials will be submitted in an organized manner to the client for future editing, use and reproduction. Rights to final versions of all materials are transferred to the client upon conclusion of the project. A::B reserves the right to use any and all project materials for educational and marketing purposes. A::B reserves the rights to any draft or conceptual materials developed in the course of the project, or other Graphic/Web DesignerAPrincipal Senior Manager Senior Manager Senior Analyst Senior Associate SOPO Task #General Description Cost Basis of Cost Justification of needPreliminary Power Studies $4,500,000 Preliminary Estimate Studies to optimize designRoute Studies 4,500,000$ Based on similar work Preliminary inventory of soil, streams, etcCommunity Engagement $1,500,000 Consultant estimate Public EngagementNEPA Process $3,000,000 Preliminary estimate Begin environmental assessmentLong Lead Material Orders $59,270,283 Preliminary Estimate Begin ordering cable and towersBudget Period 1 Total$72,770,283Design & Engineering $7,000,000 Preliminary Estimate Perform detail engineering for transmissions & soilsNEPA Process $5,000,000 Preliminary Estimate Continue environmental/permitting processCommunity Engagement $2,000,000 Consultant Estimate Public EngagementROW and land acquisition and surface use agreements $10,000,000 Based on previous projects Land acquisiton and lease agreements for ROWLong Lead Material Orders $151,020,599 Continue ordering of materials Assure Delivery of materials meets consruction scheduleBudget Period 2 Total$175,020,599Long Lead Material Orders $10,200,000 Preliminary Estimate Purchase remaining materialsSite clearing and earthwork $38,000,000 Preliminary EstimateCommunity Engagement $2,000,000 Consultant Estimate Public EngagementConstruction $192,587,102 Preliminary EstimateBudget Period 3 Total$242,787,102Community Engagement $2,000,000 Consultant Estimate Public EngagementConstruction $190,389,578 Preliminary EstimateTesting and Commisioning $19,000,000 Preliminary EstimateBudget Period 4 Total$209,389,578Budget Period 5 Total$0 0PROJECT TOTAL $699,967,562Detailed Budget Justificationg. ConstructionPLEASE READ!!!1. Construction, for the purpose of budgeting, is defined as all types of work done on a particular building, including erecting, altering, or remodeling. Construction conducted by the award recipient is entered on this page. Any construction work that is performed by a vendor or subrecipient should be entered under f. Contractual.2. List all proposed construction below, providing a basis of cost such as engineering estimates, prior construction, etc., and briefly justify its need as it applies to the Statement of Project Objectives.3. Each budget period is rounded to the nearest dollar.Overall description of construction activities: Design and Construction of a 250 mile HVDC Overhead Transmission LineAdditional Explanation (as needed):Budget Period 1Budget Period 2Budget Period 5Budget Period 3Budget Period 4 Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Total CostRound 2Direct Costs:Personnel Cost 2,618,340$          2,723,074$            2,831,996$            2,945,278$          11,118,688$        Travel 75,600$                79,380$                 83,349$                 87,516$                325,845$              Supplies 80,000$                84,000$                 88,200$                 92,610$                344,810$              Contractual 2,798,000$          2,708,000$            2,558,000$            2,528,000$          10,592,000$          subtotal direct costs5,571,940$          5,594,454$            5,561,545$            5,653,404$          22,381,344$        Indirect Rate 31.85% 31.85% 31.85% 31.85%Indirect Costs 1,774,663.00       1,781,833.60         1,771,352.08         1,800,609.32       7,128,458$          Equipment (excluded from MTDC) 80,000$                 ‐$                        80,000$                  ‐$                      160,000$              Construction ( capital costs excluded from MTDC) 72,770,283$        175,020,599$       242,787,102$       209,389,578$      699,967,562$      Total 80,196,886$        182,396,887$       250,199,999$       216,843,592$      729,637,364$      Federal 40,098,443$        91,198,443$          125,100,000$       108,421,796$      364,818,682$      Cost Share 40,098,443$        91,198,443$          125,100,000$       108,421,796$      364,818,682$        Total 729,637,364$       Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Total CostRound 2Direct Costs:Personnel Cost 2,618,340$          2,723,074$            2,831,996$            2,945,278$          11,118,688$        Travel 75,600$                79,380$                 83,349$                 87,516$                325,845$              Supplies 80,000$                84,000$                 88,200$                 92,610$                344,810$              Contractual 2,798,000$          2,708,000$            2,558,000$            2,528,000$          10,592,000$          subtotal direct costs5,571,940$          5,594,454$            5,561,545$            5,653,404$          22,381,344$        Indirect Rate 31.85% 31.85% 31.85% 31.85%Indirect Costs 1,774,663.00       1,781,833.60         1,771,352.08         1,800,609.32       7,128,458$          Equipment (excluded from MTDC) 80,000$                 ‐$                        80,000$                  ‐$                      160,000$              Construction ( capital costs excluded from MTDC) 72,770,283$        175,020,599$       242,787,102$       209,389,578$      699,967,562$      Total 80,196,886$        182,396,887$       250,199,999$       216,843,592$      729,637,364$      Federal 40,098,443$        91,198,443$          125,100,000$       108,421,796$      364,818,682$      Cost Share 40,098,443$        91,198,443$          125,100,000$       108,421,796$      364,818,682$        Total 729,637,364$       Award Number:4/17/2024Award Recipient:AEA(May be award recipient or sub-recipient)Section A - Budget SummaryFederal Cost Share Total Costs Cost Share % Proposed Budget Period DatesBudget Period 1$78,205 $0 $78,205 0.00%Example!!! 01/01/2014 - 12/31/2014Budget Period 2$78,205 $0 $78,205 0.00%Budget Period 3$0 $0 $0 0.00%Budget Period 4$0 $0 $0 0.00%Budget Period 5$0 $0 $0 0.00%Total$156,410 $0 $156,410 0.00%Section B - Budget CategoriesCATEGORY Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Total Costs % of Project Comments (as needed)a. Personnel$0 $0 $0 $0 $0 $0 0.00%b. Fringe Benefits$0 $0 $0 $0 $0 $0 0.00%c. Travel$0 $0 $0 $0 $0 $0 0.00%d. Equipment$0 $0 $0 $0 $0 $0 0.00%e. Supplies$0 $0 $0 $0 $0 $0 0.00%f. ContractualSub-recipient$0 $0 $0 $0 $0 $0 0.00%Vendor$78,205 $78,205 $0 $0 $0 $156,410 100.00%FFRDC$0 $0 $0 $0 $0 $0 0.00%Total Contractual $78,205 $78,205 $0 $0 $0 $156,410 100.00%g. Construction$0 $0 $0 $0 $0 $0 0.00%h. Other Direct Costs$0 $0 $0 $0 $0 $0 0.00%Total Direct Costs$78,205 $78,205 $0 $0 $0 $156,410 100.00%i. Indirect Charges$0 $0 $0 $0 $0 $0 0.00%Total Costs$78,205 $78,205 $0 $0 $0 $156,410 100.00%Instructions and SummaryDate of Submission:SUMMARY OF BUDGET CATEGORY COSTS PROPOSEDThe values in this summary table are from entries made in subsequent tabs, only blank white cells require data entryAdditional Explanation (as needed):Form submitted by: Please read the instructions on each worksheet tab before starting. If you have any questions, please ask your DOE contact! 1. If using this form for award application, negotiation, or budget revision, fill out the blank white cells in workbook tabs a. through j. with total project costs. If using this form for invoice submission, fill out tabs a. through j. with total costs for just the proposed invoice and fill out tab k. per the instructions on that tab.2. Blue colored cells contain instructions, headers, or summary calculations and should not be modified. Only blank white cells should be populated. 3. Enter detailed support for the project costs identified for each Category line item within each worksheet tab to autopopulate the summary tab. 4. The total budget presented on tabs a. through i. must include both Federal (DOE) and Non-Federal (cost share) portions.5. All costs incurred by the preparer's sub-recipients, vendors, and Federal Research and Development Centers (FFRDCs), should be entered only in section f. Contractual. All other sections are for the costs of the preparer only.6. Ensure all entered costs are allowable, allocable, and reasonable in accordance with the administrative requirements prescribed in 2 CFR 200, and the applicable cost principles for each entity type: FAR Part 31 for For-Profit entities; and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities. 7. Add rows as needed throughout tabs a. through j. If rows are added, formulas/calculations may need to be adjusted by the preparer. Do not add rows to the Instructions and Summary tab. 8. ALL budget period cost categories are rounded to the nearest dollar.BURDEN DISCLOSURE STATEMENTPublic reporting burden for this collection of information is estimated to average 3 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden, to Office of Information Resources Management Policy, Plans, and Oversight, AD-241-2 - GTN, Paperwork Reduction Project (1910-5162), U.S. Department of Energy 1000 Independence Avenue, S.W., Washington, DC 20585; and to the Office of Management and Budget, Paperwork Reduction Project (1910-5162), Washington, DC 20503. Time (Hrs)Pay Rate($/Hr)Total Budget Period 1Time (Hrs)Pay Rate($/Hr)Total Budget Period 2Time (Hrs)Pay Rate($/Hr)Total Budget Period 3Time (Hrs)Pay Rate($/Hr)Total Budget Period 4Time (Hrs)Pay Rate($/Hr)Total Budget Period 51 Sr. Engineer (EXAMPLE!!!)2000 $85.00 $170,000 200 $50.00 $10,000 200 $50.00 $10,000 200 $50.00 $10,000 200 $50.00 $10,000 2400 $190,000 Actual Salary2 Technicians (2) 4000 $20.00 $80,000 0 $0.00 $0 0 $0.00 $0 0 $0.00 $0 0 $0.00 $0 4000 $80,000 Actual Salary$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0$0 $0 $0 $0 $0 0 $0Total Personnel Costs0$00$00$00$00$00$0Additional Explanation (as needed):Position TitleINSTRUCTIONS - PLEASE READ!!!1. List project costs solely for employees of the entity completing this form. All personnel costs for subrecipients and vendors must be included under f. Contractual.2. All personnel should be identified by position title and not employee name. Enter the amount of time (e.g., hours or % of time) and the base pay rate and the total direct personnel compensation will automatically calculate. Rate basis (e.g., actual salary, labor distribution report, state civil service rates, etc.) must also be identified.3. If loaded labor rates are utilized, a description of the costs the loaded rate is comprised of must be included in the Additional Explanation section below. DOE must review all components of the loaded labor rate for reasonableness and unallowable costs (e.g. fee or profit). 4. If a position and hours are attributed to multiple employees (e.g. Technician working 4000 hours) the number of employees for that position title must be identified. 5. Each budget period is rounded to the nearest dollar.SOPO Task #Rate BasisProject Total DollarsBudget Period 4 Budget Period 5a. PersonnelProject Total HoursBudget Period 1 Budget Period 2 Budget Period 3Detailed Budget Justification Labor TypeTotal Project Personnel Costs Rate Total Personnel Costs Rate Total Personnel Costs Rate Total Personnel Costs Rate Total Personnel Costs Rate TotalEXAMPLE!!! Sr. Engineer$170,000 20% $34,000 $10,000 20% $2,000 $10,000 20% $2,000 $10,000 20% $2,000 $10,000 20% $2,000 $38,000$0 $0 $0 $0 $0 $0$0 $0 $0 $0 $0 $0$0 $0 $0 $0 $0 $0$0 $0 $0 $0 $0 $0$0 $0 $0 $0 $0 $0Total:$0 $0 $0 $0 $0 $0 $0 $0 $0 $0$0Detailed Budget Justification b. Fringe BenefitsAdditional Explanation (as necessary): Please use this box (or an attachment) to list the elements that comprise your fringe benefits and how they are applied to your base (e.g. Personnel) to arrive at your fringe benefit rate.INSTRUCTIONS - PLEASE READ!!!1. Fill out the table below by position title. If all employees receive the same fringe benefits, you can show "Total Personnel" in the Labor Type column instead of listing out all position titles. 2. The rates and how they are applied should not be averaged to get one fringe cost percentage. Complex calculations should be described/provided in the Additional Explanation section below. 3. The fringe benefit rates should be applied to all positions, regardless of whether those funds will be supported by Federal Share or Recipient Cost Share.4. Each budget period is rounded to the nearest dollar.______ A fringe benefit rate has been negotiated with, or approved by, a federal government agency. A copy of the latest rate agreement is/was included with the project application.*______ There is not a current federally approved rate agreement negotiated and available.***Unless the organization has submitted an indirect rate proposal which encompasses the fringe pool of costs, please provide the organization’s benefit package and/or a list of the components/elements that comprise the fringe pool and the cost or percentage of each component/element allocated to the labor costs identified in the Budget Justification (Form EERE 335.1).**When this option is checked, the entity preparing this form shall submit an indirect rate proposal in the format provided in the Sample Rate Proposal at http://www1.eere.energy.gov/financing/resources.html, or a format that provides the same level of information and which will support the rates being proposed for use in the performance of the proposed project. A federally approved fringe benefit rate agreement, or a proposed rate supported and agreed upon by DOE for estimating purposes is required at the time of award negotiation if reimbursement for fringe benefits is requested. Please check (X) one of the options below and provide the requested information if not previously submitted.Budget Period 2 Budget Period 3Budget Period 1Budget Period 4 Budget Period 5 SOPO Task #Purpose of Travel Depart From DestinationNo. of DaysNo. of Travelers Lodging per Traveler Flight per Traveler Vehicle per Traveler Per Diem Per Traveler Cost per TripBasis for Estimating CostsDomestic Travel1EXAMPLE!!! Visit to PV manufacturer 2 2 $250 $500 $100 $160 $2,020 Current GSA rates$0$0$0$0International Travel$0Budget Period 1 Total$0Domestic Travel$0$0$0$0International Travel$0Budget Period 2 Total$0Domestic Travel$0$0$0$0International Travel$0Budget Period 3 Total$0Domestic Travel$0$0$0$0International Travel$0Budget Period 4 Total$0Domestic Travel$0$0$0$0International Travel$0Budget Period 5 Total$0PROJECT TOTAL$0INSTRUCTIONS - PLEASE READ!!1. Identify Foreign and Domestic Travel as separate items. Examples of Purpose of Travel are subrecipient site visits, DOE meetings, project mgmt. meetings, etc. Examples of Basis for Estimating Costs are past trips, travel quotes, GSA rates, etc. 2. All listed travel must be necessary for performance of the Statement of Project Objectives.3. Federal travel regulations are contained within the applicable cost principles for all entity types. Travel costs should remain consistent with travel costs incurred by an organization during normal business operations as a result of the organizations written travel policy. In absence of a written travel policy, organizations must follow the regulations prescribed by the General Services Administration. 4. Each budget period is rounded to the nearest dollar.Additional Explanation (as needed):c. TravelDetailed Budget Justification Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 SOPO Task #Equipment Item Qty Unit Cost Total Cost Basis of Cost Justification of need3,4,5EXAMPLE!!! Thermal shock chamber 2 $70,000 $140,000 Vendor Quote - Attached Reliability testing of PV modules- Task 4.3$0$0$0$0$0$0Budget Period 1 Total$0$0$0$0$0$0$0Budget Period 2 Total$0$0$0$0$0$0$0Budget Period 3 Total$0$0$0$0$0$0$0Budget Period 4 Total$0$0$0$0$0$0$0Budget Period 5 Total$0PROJECT TOTAL $0d. EquipmentDetailed Budget JustificationINSTRUCTIONS - PLEASE READ!!!1. Equipment is generally defined as an item with an acquisition cost greater than $5,000 and a useful life expectancy of more than one year. Please refer to the applicable Federal regulations in 2 CFR 200 for specific equipment definitions and treatment. 2. List all equipment below, providing a basis of cost (e.g. vendor quotes, catalog prices, prior invoices, etc.). Briefly justify items as they apply to the Statement of Project Objectives. If it is existing equipment, provide logical support for the estimated value shown. 3. During award negotiations, provide a vendor quote for all equipment items over $50,000 in price. If the vendor quote is not an exact price match, provide an explanation in the additional explanation section below. If a vendor quote is not practical, such as for a piece of equipment that is purpose-built, first of its kind, or otherwise not available off the shelf, provide a detailed engineering estimate for how the cost estimate was derived.4. Each budget period is rounded to the nearest dollar.Additional Explanation (as needed):Budget Period 3Budget Period 2Budget Period 1Budget Period 4Budget Period 5 SOPO Task #General Category of Supplies Qty Unit Cost Total Cost Basis of Cost Justification of need4,6EXAMPLE!!! Wireless DAS components10 $360.00 $3,600 Catalog price For Alpha prototype - Task 2.4$0$0$0$0$0$0$0Budget Period 1 Total $0$0$0$0$0$0$0$0$0Budget Period 2 Total$0$0$0$0$0$0$0$0$0Budget Period 3 Total$0$0$0$0$0$0$0$0$0Budget Period 4 Total$0$0$0$0$0$0$0$0$0Budget Period 5 Total$0PROJECT TOTAL$0Detailed Budget Justification INSTRUCTIONS - PLEASE READ!!!1. Supplies are generally defined as an item with an acquisition cost of $5,000 or less and a useful life expectancy of less than one year. Supplies are generally consumed during the project performance. Please refer to the applicable Federal regulations in 2 CFR 200 for specific supplies definitions and treatment. 2. List all proposed supplies below, providing a basis of costs (e.g. vendor quotes, catalog prices, prior invoices, etc.). Briefly justify the need for the Supplies as they apply to the Statement of Project Objectives. Note that Supply items must be direct costs to the project at this budget category, and not duplicative of supply costs included in the indirect pool that is the basis of the indirect rate applied for this project.3. Multiple supply items valued at $5,000 or less used to assemble an equipment item with a value greater than $5,000 with a useful life of more than one year should be included on the equipment tab. If supply items and costs are ambiguous in nature, contact your DOE representative for proper categorization. 4. Add rows as needed. If rows are added, formulas/calculations may need to be adjusted by the preparer. 5 Each budget period is rounded to the nearest dollarAdditional Explanation (as needed):Budget Period 1e. SuppliesBudget Period 2Budget Period 3Budget Period 4Budget Period 5 SOPO Task #Sub-RecipientName/OrganizationPurpose and Basis of CostBudget Period 1Budget Period 2Budget Period 3Budget Period 4Budget Period 5Project Total$0$0$0$0$0$0Sub-total $0 $0 $0 $0 $0 $0SOPO Task #Vendor Name/OrganizationPurpose and Basis of CostBudget Period 1Budget Period 2Budget Period 3Budget Period 4Budget Period 5Project TotalAgnew::Beck AEA GMRP Public Participation Plan $78,205 $78,205$156,410$0$0$0$0Sub-total $78,205 $78,205 $0 $0 $0 $156,410SOPO Task #FFRDCName/OrganizationPurpose and Basis of CostBudget Period 1Budget Period 2Budget Period 3Budget Period 4Budget Period 5Project Total$0$0Sub-total $0 $0 $0 $0 $0 $0Total Contractual$78,205 $78,205 $0 $0 $0 $156,410Detailed Budget Justification f. ContractualINSTRUCTIONS - PLEASE READ!!!1. The entity completing this form must provide all costs related to sub-recipients, vendors, and FFRDC partners in the applicable boxes below. 2. Sub-recipients (partners, sub-awardees): Subrecipients shall submit a Budget Justification describing all project costs and calculations when their total proposed budget exceeds either (1) $100,000 or (2) 25% of total award costs. These sub-recipient forms may be completed by either the sub-recipients themselves or by the preparer of this form. The budget totals on the sub-recipient's forms must match the sub-recipient entries below. A subrecipient is a legal entity to which a subaward is made, who has performance measured against whether the objectives of the Federal program are met, is responsible for programmatic decision making, must adhere to applicable Federal program compliance requirements, and uses the Federal funds to carry out a program of the organization. All characteristics may not be present and judgment must be used to determine subrecipient vs. vendor status. 3. Vendors (including contractors): List all vendors and contractors supplying commercial supplies or services used to support the project. For each Vendor cost with total project costs of $100,000 or more, a Vendor quote must be provided. A vendor is a legal entity contracted to provide goods and services within normal business operations, provides similar goods or services to many different purchasers, operates in a competitive environment, provides goods or services that are ancillary to the operation of the Federal program, and is not subject to compliance requirements of the Federal program. All characteristics may not be present and judgment must be used to determine subrecipient vs. vendor status. 4. Federal Funded Research and Development Centers (FFRDCs): FFRDCs must submit a signed Field Work Proposal during award application. The award recipient may allow the FFRDC to provide this information directly to DOE, however project costs must also be provided below.5. Each budget period is rounded to the nearest dollarAdditional Explanation (as needed): SOPO Task #General Description Cost Basis of Cost Justification of need3 EXAMPLE ONLY!!! Three days of excavation for platform site $28,000 Engineering estimate Site must be prepared for construction of platform.Budget Period 1 Total$0Budget Period 2 Total$0Budget Period 3 Total$0Budget Period 4 Total$0Budget Period 5 Total$0PROJECT TOTAL $0Detailed Budget Justificationg. ConstructionPLEASE READ!!!1. Construction, for the purpose of budgeting, is defined as all types of work done on a particular building, including erecting, altering, or remodeling. Construction conducted by the award recipient is entered on this page. Any construction work that is performed by a vendor or subrecipient should be entered under f. Contractual.2. List all proposed construction below, providing a basis of cost such as engineering estimates, prior construction, etc., and briefly justify its need as it applies to the Statement of Project Objectives.3. Each budget period is rounded to the nearest dollar.Overall description of construction activities: Example Only!!! - Build wind turbine platformAdditional Explanation (as needed):Budget Period 1Budget Period 2Budget Period 5Budget Period 3Budget Period 4 SOPO Task #General Description and SOPO Task # Cost Basis of Cost Justification of need5EXAMPLE!!! Grad student tuition - tasks 1-3$16,000 Established UCD costs Support of graduate students working on project Budget Period 1 Total$0Budget Period 2 Total$0Budget Period 3 Total$0Budget Period 4 Total$0Budget Period 5 Total$0PROJECT TOTAL $0Detailed Budget Justificationh. Other Direct CostsAdditional Explanation (as needed):INSTRUCTIONS - PLEASE READ!!!1. Other direct costs are direct cost items required for the project which do not fit clearly into other categories. These direct costs must not be included in the indirect costs (for which the indirect rate is being applied for this project). Examples are: tuition, printing costs, etc. which can be directly charged to the project and are not duplicated in indirect costs (overhead costs).2. Basis of cost are items such as vendor quotes, prior purchases of similar or like items, published price list, etc.3. Each budget period is rounded to the nearest dollar.Budget Period 1Budget Period 3Budget Period 2Budget Period 4Budget Period 5 Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 TotalProvide ONLY Applicable Rates:Overhead Rate 0.00% 0.00% 0.00% 0.00% 0.00%General & Administrative (G&A) 0.00% 0.00% 0.00% 0.00% 0.00%FCCM Rate, if applicable 0.00% 0.00% 0.00% 0.00% 0.00%OTHER Indirect Rate 0.00% 0.00% 0.00% 0.00% 0.00%Indirect Costs (As Applicable):Overhead Costs$0G&A Costs$0FCCM Costs, if applicable$0 OTHER Indirect Costs$0Total indirect costs requested: $0 $0 $0 $0 $0 $0Additional Explanation (as needed): *IMPORTANT: Please use this box (or an attachment) to further explain how your total indirect costs were calculated. If the total indirect costs are a cumulative amount of more than one calculation or rate application, the explanation and calculations should identify all rates used, along with the base they were applied to (and how the base was derived), and a total for each (along with grand total). Detailed Budget Justification You must provide an explanation (below or in a separate attachment) and show how your indirect cost rate was applied to this budget in order to come up with the indirect costs shown.A federally approved indirect rate agreement, or rate proposed (supported and agreed upon by DOE for estimating purposes) is required if reimbursement of indirect costs is requested. Please check (X) one of the options below and provide the requested information if it has not already been provided as requested, or has changed. ______ An indirect rate has been approved or negotiated with a federal government agency. A copy of the latest rate agreement is included with this application, and will be provided electronically to the Contracting Officer for this project.______ There is not a current, federally approved rate agreement negotiated and available*. *When this option is checked, the entity preparing this form shall submit an indirect rate proposal in the format provided by your DOE contact, or a format that provides the same level of information and which will support the rates being proposed for use in performance of the proposed project. Additionally, any non-Federal entity that has never received a negotiated indirect cost rate, except for those non-Federal entities described in Appendix VII to Part 200—States and Local Government and Indian Tribe Indirect Cost Proposals, paragraph D.1.b, may elect to charge a de minimis rate of 10% of modified total direct costs (MTDC) which may be used indefinitely.As described in §200.403 Factors affecting allowability of costs, costs must be consistently charged as either indirect or direct costs, but may not be double charged or inconsistently charged as both. If chosen, this methodology once elected must be used consistently for all Federal awards until such time as a non-Federal entity chooses to negotiate for a rate, which the non-Federal entity may apply to do at any time. i. Indirect CostsINSTRUCTIONS - PLEASE READ!!!1. Fill out the table below to indicate how your indirect costs are calculated. Use the box below to provide additional explanation regarding your indirect rate calculation. 2. The rates and how they are applied should not be averaged to get one indirect cost percentage. Complex calculations or rates that do not do not correspond to the below categories should be described/provided in the Additional Explanation section below. If questions exist, consult with your DOE contact before filling out this section. 3. The indirect rate should be applied to both the Federal Share and Recipient Cost Share.4. Each budget period is rounded to the nearest dollarExplanation of BASE Organization/Source Type (Cash or In Kind) Cost Share Item Budget Period 1Budget Period 2Budget Period 3Budget Period 4Budget Period 5Total Project Cost ShareABC CompanyEXAMPLE!!!Cash Project partner ABC Company will provide 20 PV modules for product development at the price of $680 per module$13,600$13,600$0$0$0$0$0$0$0$0$0$0Totals $0 $0 $0 $0 $0 $0$156,4100.0%Additional Explanation (as needed):Cost ShareDetailed Budget JustificationPLEASE READ!!!1. A detailed presentation of the cash or cash value of all cost share proposed must be provided in the table below. All items in the chart below must be identified within the applicable cost category tabs a. through i. in addition to the detailed presentation of the cash or cash value of all cost share proposed provided in the table below. Identify the source organization & amount of each cost share item proposed in the award. 2. Cash Cost Share - encompasses all contributions to the project made by the recipient, subrecipient, or third party (an entity that does not have a role in performing the scope of work) for costs incurred and paid for during the project. This includes when an organization pays for personnel, supplies, equipment, etc. for their own company with organizational resources. If the item or service is reimbursed for, it is cash cost share. All cost share items must be necessary to the performance of the project. Vendors may not provide cost share. Any partial donation of goods or services is considered a discount and is not allowable. 3. In Kind Cost Share - encompasses all contributions to the project made by the recipient, subrecipient, or third party (an entity that does not have a role in performing the scope of work) where a value of the contribution can be readily determined, verified and justified but where no actual cash is transacted in securing the good or service comprising the contribution. In Kind cost share items include volunteer personnel houthe donation of space or use of equipment, etc. The cash value and calculations thereof for all In Kind cost share items must be justified and explained in the Cost Share Item section below. All cost share items must be necessary to the performance of the project. If questions exist, consult your DOE contact before filling out In Kind cost share in this section. Vendors may not provide cost share. Any partial donation of goods or services is considered a discount and is not allowable. 4. Funds from other Federal sources MAY NOT be counted as cost share. This prohibition includes FFRDC sub-recipients. Non-Federal sources include any source not originally derived from Federal funds. Cost sharing commitment letters from subrecipients and third parties must be provided with the original application.5. Fee or profit, including foregone fee or profit, are not allowable as project costs (including cost share) under any resulting award. The project may only incur those costs that are allowable and allocable to the project (including cost share) as determined in accordance with the applicable cost principles prescribed in FAR Part 31 for For-Profit entities and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities.6. NOTE: A Recipient who elects to employ the 10% de minimis Indirect Cost rate cannot claim the resulting indirect costs as a Cost Share contribution. 7. NOTE: A Recipient cannot claim "unrecovered indirect costs" as a Cost Share contribution, without prior approval. 8. Each budget period is rounded to the nearest dollar. Cost Share Percent of Award:Total Project Cost: 813 W Northern Lights Blvd, Anchorage, AK 99503  Phone: (907) 771-3000  Fax: (907) 771-3044  Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG Environmental Questionnaire Attachment Control Number 3195-1942 Healy Beluga  Proposed HVDC Route OMB Number: 4040-0004 Expiration Date: 11/30/2025 Application for Federal Assistance SF-424 *1. Type of Submission: Preapplication Application Changed/Corrected Application *2. Type of Application New Continuation Revision * If Revision, select appropriate letter(s): * Other (Specify) *3. Date Received:4. Applicant Identifier: 5a. Federal Entity Identifier: *5b. Federal Award Identifier: State Use Only: 6.Date Received by State:7.State Application Identifier: 8. APPLICANT INFORMATION: *a. Legal Name: *b. Employer/Taxpayer Identification Number (EIN/TIN):*c. UEI: d. Address: *Street 1: Street 2: *City: County/Parish: *State: *Province: *Country: *Zip / Postal Code e. Organizational Unit: Department Name: Division Name: f. Name and contact information of person to be contacted on matters involving this application: Prefix: *First Name: Middle Name: *Last Name: Suffix: Title: Organizational Affiliation: *Telephone Number:Fax Number: *Email: Application for Federal Assistance SF-424 *9. Type of Applicant 1: Select Applicant Type: Type of Applicant 2: Select Applicant Type: Type of Applicant 3: Select Applicant Type: *Other (Specify) *10. Name of Federal Agency: 11. Catalog of Federal Domestic Assistance Number: CFDA Title: *12. Funding Opportunity Number: *Title: 13. Competition Identification Number: Title: 14. Areas Affected by Project (Cities, Counties, States, etc.): *15. Descriptive Title of Applicant’s Project: Attach supporting documents as specified in agency instructions. Application for Federal Assistance SF-424 16. Congressional Districts Of: *a. Applicant:*b. Program/Project: Attach an additional list of Program/Project Congressional Districts if needed. 17. Proposed Project: *a. Start Date:*b. End Date: 18. Estimated Funding ($): *a. Federal *b. Applicant *c. State *d. Local *e. Other *f. Program Income *g. TOTAL . *19. Is Application Subject to Review By State Under Executive Order 12372 Process? a.This application was made available to the State under the Executive Order 12372 Process for review on b.Program is subject to E.O. 12372 but has not been selected by the State for review. c.Program is not covered by E.O. 12372. *20. Is the Applicant Delinquent On Any Federal Debt? Yes No If “Yes”, explain: 21. *By signing this application, I certify (1) to the statements contained in the list of certifications** and (2) that the statements herein are true, complete and accurate to the best of my knowledge. I also provide the required assurances** and agree to comply with any resulting terms if I accept an award. I am aware that any false, fictitious, or fraudulent statements or claims may subject me to criminal, civil, or administrative penalties. (U. S. Code, Title 218, Section 1001) ** I AGREE ** The list of certifications and assurances, or an internet site where you may obtain this list, is contained in the announc ement or agency specific instructions. Authorized Representative: Prefix: *First Name: Middle Name: *Last Name: Suffix: *Title: *Telephone Number:Fax Number: * Email: *Signature of Authorized Representative:*Date Signed: CURTIS W. THAYER Executive Director Experience and Achievements Alaska Energy Authority 2019-Present The Alaska Energy Authority (AEA) is a public corporation of the State of Alaska governed by a board of directors with the mission to "reduce the cost of energy in Alaska." AEA is the state's energy office and lead agency for statewide energy policy and program development. Position: Executive Director • The Executive Director serves as the Chief Executive Officer of the Authority, responsible for all business and operations. I work closely with the Board as it sets Authority policies, goals, and objectives, and is responsible for the execution of Board directives. I have developed a close relationship with the Governor, Commissioners of principal State departments, the Legislature, business community, and the public to advance the mission of the Authority. Achievements: Increased the profile and developed a strategic action plan to advance the goal and objectives of the Authority • Worked with the Board to establish long-range vision, strategies, goals, policies, and plans; including leading the strategic planning process and working with the Board and Legislature to implement the strategy to achieve that vision. • Strengthening the working relationship with the five utilities is like shuttle diplomacy. A few of the key issues during the three years have included purchase of develop a strategy and bonding package for a $170 million upgrade for the transmission lines from Homer to Anchorage (closes 11/30/22), purchase SS/Q line ($17 million), Battle Creek diversion and construction delays and construction claims, ligation on the SQ line, and Governor's goal of reducing the cost of power. Managing expectations of the Board, Governor's Office, Legislature and our five utility partners has proved to be challenging (and rewarding). • Oversight responsibility of the Authority's rural energy programs, including energy system upgrades, loan programs, alternative/renewable energy, energy efficiency, and the Power Cost Equalization program. • Reviewed and analyzed legislation, laws, regulations, and other public policies that may affect the Authority's mission and programs and recommends changes when appropriate. • Developing and maintaining professional/cooperative relationships with local, state, and federal agencies, and Authority business partners. • Working with legislative or other government agencies regarding policies, programs, and budgets. Alaska State Chamber of Commerce 2015-2019 The Alaska Chamber is a non-profit, membership funded advocacy organization founded in 1953. The Chamber membership is comprised of companies, associations, and individuals from every business sector in Alaska. The Chamber's core mission is to make Alaska the best place to do business through its advocacy for and defense of sound business policies based on the principles of free enterprise, personal responsibility, and limited government. Position: President and CEO • As the President & Chief Executive Officer, I serve as the top administrative officer, principal spokesman, chief advocate in Juneau and Washington DC, chief finance officer and team leader. Achievements: Raised the profile of the Alaska Chamber • Coordinated and guided the work of staff, lobbyists, counsel, committee, and volunteers in marshaling and expressing the Chamber's business perspective on public policy issues which has increased the profile of the Alaska Chamber statewide through outreach and tackling tough legislative positions that benefit and promote business. • Lead efforts to develop and manage coalitions involving other business associations, advocacy groups, local chambers and the US Chamber to achieve Chamber goals. • Grew Chamber membership for the last three straight years. • Developed and implemented a financial plan that has increased Chamber reserves by 15 percent within three years. State of Alaska, Department of Administration 2012 - 2014 With 1, 100 employees and an annual budget of $350 million, DoA facilitates state government operations by providing policy leadership and management services in essential areas, including finance/accounting, payroll, human resources/retirement benefits, information technology, labor negotiations, legal services, procurement/facilities, and risk management. Positions: Commissioner & Deputy Commissioner • Served as the chief executive officer of DoA and as a member of Governor Sean Parnell's cabinet. Unanimously confirmed by the Alaska State Legislature. • Advised Governor on IT, pensions, healthcare, and labor relations with the Legislature and business community. • Responsible for development and implementation of all DOA policies and programs. Hired and managed two deputy commissioners and ten division directors. Achievements: Reducing the Cost of Government • Reformed PERS/TERS (state/local government pension programs) to reduce annual state contribution and ensure long-term solvency. Annual savings are more than $300 million. • Restructured AlaskaCare (state healthcare program) to reduce state contribution without reducing core benefits. Annual savings are more than $60 million. • Negotiated with the state's eleven public employee's unions to limit automatic merit increases, reduce leave accruals, and cap benefit cash-outs, all without work stoppages. Annual savings are more than $20 million. • Worked with Legislature to revamp state procurement statutes to increase transparency and competition. Applied new statutes and best practices to major telecom procurement, which reduced annual state expenses by 50%. Previous Experience • 2009-2012: Deputy Commissioner, State of Alaska, Department of Commerce, Community, and Economic Development • 2004-2009: Director, Corporate and External Affairs, ENSTAR Natural Gas Company • 2002-2004: President & CEO, Thayer & Associates (political and corporate communications consulting) • 2001-2002: External Affairs Advisor, Alaska Gas Producers Pipeline Team (BP, Phillips, Exxon) • 1997-2000: Special Assistant, U.S Congressman Don Young (R-Alaska) • 1993-1996: Professional Staff, U.S House Committee on Natural Resources • 1991-1992: Management Specialist, Federal Bureau of Investigation (FBI) Education • University of Alaska Fairbanks, Fairbanks, AK. Bachelor of Arts in Political Science and Business/Justice • National Renewable Energy Lab (NREL), Golden CO, Executive Energy Leadership Academy • University of Wisconsin, Institute of Organizational Management, U.S. Chamber • State of Alaska, Real Estate License Community Activities CURRENT • Alaska Board of Marine Pilots, Chair • Don Young Institute for Alaska, Chair • Alaska Leaders Archives, Treasurer PAST • Alaska Gas Line Development Corporation, Director • Alaska Housing Finance Corporation, Director • Alaska Retirement Management Board, Trustee • Alaska Royalty Oil and Gas Development Advisory Board, Director • Abused Women Aid in Crisis (AWAIC), Director and Treasurer • Committee of 100 Top Chamber Executives, U.S. Chamber • Council of State Chamber Executives • Selected as "Top 40 under 40" community leader Dan Bishop, PE PROFESSIONAL OBJECTIVE Use my understanding of policy trends and rapidly changing technologies in generation, energy storage, transmission & distribution, and information technology to drive projects that strategically benefit GVEA and the communities it serves without abandoning well-established, prudent utility practices. EMPLOYMENT HISTORY Golden Valley Electric Association, Inc. Director of Engineering Services, October 2022 - present Manager of Engineering Services, 2011–2022 • Participate in Railbelt utility organizations. • Work toward meeting GVEA strategic goals including reduction of carbon emissions. • Managing teams of engineers, electricians, land managers, and CAD/GIS technicians who: o Forecast future electrical loads o Build substations o Build transmission lines o Maintain substations o Perform Integrated Resource Planning o Prepare company-wide construction work plans for development of infrastructure o Facilitate connection of distributed generation o Analyze grid response to disturbances o Perform grid modeling as required for planning and operations o Participate in coordinated Railbelt planning of system improvements o Implement projects that use complex software systems to integrate business processes across software platforms o Apply new technology to improve cyber-security, mitigate environmental risk, reduce costs, and improve reliability. EDUCATION University of Alaska Fairbanks Master of Science in Electrical Engineering, 1990 Degree Emphasis: Control Systems & Instrumentation University of Alaska Fairbanks Bachelor of Science in Electrical Engineering, 1985 Degree Emphasis: Communications systems & Digital systems University of Alaska Fairbanks Power systems engineering classes, 1995 University of Wisconsin NRECA Management Internship Program, 2012 PROFESSIONAL REGISTRATION • AK Professional Electrical Engineer #8476 (received in 1993) Edward Jenkin P.O. Box 870234 Wasilla, Alaska 99687 Cell: 907-707-6385 edandjenjenkin@gmail.com A Professional Engineer in the state of Alaska with over 30 years of u�lity engineering and opera�ons experience, including over ten years in an execu�ve capacity. A past Chief Opera�ons Officer, presently overseeing a u�lity genera�on fleet transi�on as the Chief Energy Transforma�on Officer. A presenter at mul�ple conferences and workshops including events sponsored by the State of Alaska, Northwest Public Power Associa�on, and United States Energy Associa�on. MATANUSKA ELECTRIC ASSOCIATION (MEA) - JUNE 2014 TO PRESENT Presently, as Chief Energy Transformation Officer I am part of a team responsible for implementing key strategic goals for MEA. With direct oversight of Power Dispatch and Fuel Departments, I am responsible for various contracts and negotiation as MEA transitions to a generation portfolio with additional clean energy resources. As the regional utilities look to more regional approaches, I represent MEA on the region’s Electric Reliability Organization Board and am the technical representative for the regional utilities on the committee which sets up the organizational structure of a regional transmission organization. I was leader in developing a power pool with an adjacent utility and represent MEA on the Operating Committee. I represent MEA on the Technical Advisory Committee to the Alaska Energy Authority and other regional committees. I sit on the advisory committee for the University of Alaska, Anchorage’s Electrical Engineering Department. Prior to being the Chief Energy Transformation Officer, I was the Chief Operations Officer for MEA, where I participated in the Association’s strategic planning, financial planning, and resource planning. I presented to the Board of Directors various information and items for approval, being responsible for all aspects of delivering reliable power from MEA’s power plant and other distributed sources to the members’ facilities. Specifically, I oversaw Engineering, Operations, Technical Services, Power Dispatch, and Grid Modernization. I provided oversight on internal and regional resources and planning efforts. I participated in and led joint committees for the development of standards, including the present Reliability Standards jointly approved by all the Railbelt utilities. I was responsible for developing five-year capital work plans and multimillion dollar operational and capital budgets. Staffing plans and financial performance were reviewed as needed to ensure the Association’s performance is in line with service, reliability, and rate requirements. Professional Summary Work Experience CHUGACH ELECTRIC ASSOCIATION - MARCH 1989 TO JUNE 2014 At Chugach Electric, I progressed from the design, cost estimation, and inspection of projects associated with 12kV distribution and 35kV sub transmission facilities, to overall distribution and transmission system planning, including distribution system protection. I moved to the supervision of the Associ ation's Power Dispatch Center in 2000 and was responsible for overseeing generation scheduling (including sales and purchases) and overall system operations. As a Director and Executive at Chugach Electric from 2004 to 2014, I was responsible for all design, construction, and maintenance functions associated with the delivery of power from the power plants to the customer meter; directed the development of the Associati on's capital improvement plan and the division budget; participated in Board and executive level strategic planning and developed implementation plans, set goals, and reported on progress; approved represented and non-represented employee actions related to hiring and discipline; represented the Association at various levels, including to community, government, and legislative bodies; and sat on various regional committees. Master of Arts in Cross-Cultural Studies, Fuller Theological Seminary Pasadena, California; Graduated 1987 Bachelor of Science in Electrical Engineering, Power Op�on University of Alaska, Fairbanks; Graduated 1984 Educa�on Daniel Heckman P.O. Box 74434 ⚫Fairbanks, AK 99707 ⚫Phone: (907) 347-2844 ⚫E-Mail: dheckman22@gmail.com Experience Golden Valley Electric Association, Inc. (Fairbanks, AK)February 8, 2016 - Present Regulatory Manager (2022 - Present) Regulatory Analyst (2020 - 2022) Regulatory Specialist (2016 - 2020) ●Provide regulatory and compliance oversight to assure that financial and regulatory reporting is in compliance with Generally Accepted Accounting Principles (GAAP), USDA Rural Utilities Service (RUS), US Department of Energy (DOE), and Regulatory Commission of Alaska (RCA) policies and procedures, as well as any applicable Regulatory laws and to ensure GVEA’s regulatory practices and procedures are in line with industry standards. ●Serve as GVEA’s primary representative to regulatory agencies, including Regulatory Commission of Alaska (RCA), the Railbelt Reliability Council (RRC), and other federal/state agencies as applicable. ●Proactively research and monitor legislative and regulatory frameworks and activities on matters of importance to GVEA and the electric utility industry or before the RCA and timely advise management with recommendations on these activities. ●Lead with review of utilities regulatory reporting to ensure compliance with RCA orders, rules, regulations, and policies. ●Review the Cost of Power Adjustment (COPA) and the Simplified Rate Filing (SRF) models to forecast current and future conditions and provide responses to RCA’s questions concerning the COPA and SRF components. ●Lead senior management, consultants, and coordinate with tariff counsel in the tariff filing process and other adjudicatory matters before the RCA. ●Ensure the COPA, SRF, Annual FERC and RUS filings are submitted timely and in compliance with regulations. Assist with their computations and file their associated tariff sheets and filings with the RCA. Provide regulatory guidance on COPA and SRF related initiatives and inputs. ●Serve as internal resource to project managers and internal compliance officer to ensure grant reporting complies with the requirements of regulatory agencies as required. ●Provide oral and/or written comments on RCA utility, informational, and rulemaking dockets and various filings with the RCA of relevance to GVEA. ●Review and respond to member, utility personnel. and RCA staff inquiries about complaints relating to the proper application of GVEA’s tariffs. ●Timely respond to RCA staff inquiries on GVEA’s financial and regulatory reports and filings to ensure compliance with RCA orders, rules, regulations, and policies, and preferences. ●Serve as internal project manager and provide support to external legal counsel and consultants in preparing and presenting GVEA’s general rate case filings or other investigations before the RCA, including assembling support documents, draing prefiled direct and reply testimony, responding to data requests during discovery, preparing exhibits and participating in hearings before the RCA. ●Attend workshops and conferences as well as monitor regulatory proceedings to identify trends, issues or decisions which might affect GVEA’s regulatory objectives. ●Serve as GVEA representative on various groups and task forces, as requested, addressing matters related to energy and regulatory policy on a Railbelt-wide level. ●Responsible for employee training, hiring, promotion, and disciplinary actions, in consultation with Member Services Supervisors. ●Responsible for preparing and administering performance evaluations, establishing goals, monitoring performance, and developing employees. Page 1 of 2 Daniel Heckman P.O. Box 74434 ⚫Fairbanks, AK 99707 ⚫Phone: (907) 347-2844 ⚫E-Mail: dheckman22@gmail.com Doyon Utilities, LLC (Fairbanks, AK)July 1, 2013 - January 29, 2016 Contract Compliance/Regulatory Affairs Associate ●Assist in the computation, compilation, and filing of two rate cases for twelve separate certificated utilities before the RCA. Dratariff advice letters and pre-filed testimony, revise the Cost Allocation Manual, and respond to discovery requests. ●Review Defense Logistics Agency requests for proposals and contract modifications and proposed utility responses to ensure legal compliance with contract governing relationship between utility and the U.S. Government as well as RCA regulations. ●Develop and maintain a monthly spreadsheet detailing relevant filings before the RCA. Report on filings to the President/CEO, Vice-President of Administration, Director of Regulatory Affairs, and General Counsel. ●Perform legal, regulatory, and accounting research and dramemorandum for utility personnel as requested. ●Review dra capital projects plans to ensure legal and regulatory compliance. Education Gonzaga University School of Law (Spokane, WA) J.D., May 2013 ●Legal Fellow; Office of Senator Lisa Murkowski (Spring 2013, Washington DC) Southern Methodist University (Dallas, TX) B.A. Political Science; B.A. History, May 2010 Community Involvement ●Cold Climate Housing and Research Center o Member, Board of Directors (2023 - Present) ●United Way of the Tanana Valley o Member, Board of Directors (2019 - 2023) ●Midnight Sun Council, Boy Scouts of America o Member, Board of Directors (2014 - 2019) ●Golden Heart Rotary Club (2013 - 2020) Page 2 of 2 Julie Estey Julie Estey, Senior Director of External Affairs and Strategic Initiatives, MEA Julie Estey is the Senior Director where she manages the cooperative’s public and member facing activities along with the organization’s strategic plan and special projects. She serves as the organization’s representative, past Chair and founding member of the Railbelt Reliability Council, the recently certificated Electric Reliability Organization for the interconnected Railbelt grid. Before joining MEA, Ms. Estey was the Business Director for the Alaska Center for Energy and Power, an energy research group at the University of Alaska Fairbanks focused on improving how Alaskans generate and distribute power. She has experience managing public outreach and engagement for controversial transmission and generation capital projects as well as expertise bringing diverse groups of stakeholders together to develop common solutions. James W. Mendenhall, P.E. Program Manager jmendenhall@akenergyauthority.org 907-360-9390 PROFESSIONAL SUMMARY Jim Mendenhall has over 30 years working in senior leadership roles within the business environments of; Aviation, Construction, Mining and Alaska Native Enterprise initiatives. Jim knows what truly drives business strategy. His proven expertise; business development, operational project management, have provided his clients successes which reach solidly into the future, continuing to build on their business objectives. EXPERIENCE Alaska Energy Authority, Program Manager (2023-Present) Oversee various projects within AEA’s portfolio of projects including the Railbelt Innovation and Resiliency project. PAECO, LLC, Managing Member (2018-Present) MENDENHALL AND ASSOCIATES, Management Consultant (September 2014-2018) FAIRWEATHER AVIATION, Principal (January 2015-2018) Provide strategic and management advice to clients in the aviation and construction sectors. Examples: investor's representative to monitor and mentor aviation company performing specialized maintenance work on the North Slope; developed a business development plan for an electrical subcontractor; developed claim support strategy to justify a contract extension for a civil contractor and revised the project schedule in order to avoid termination by default; developed aviation solutions for the resource industry; made recommendations for an aviation shuttle to/from Alaska's North Slope; performed ice management surveys for arctic sealift, and developed an aerial solution for an electric utility to monitor tree & vegetation issues within the right-of-way, ASRC CONSTRUCTION HOLDING COMPANY President & CEO (January 2012-May 2014) Interim CEO (July 2011-December 2011) Chief Operating Officer (January 2011-June 2011) Executive leadership for five operating units' general managers, executing $150M in construction, O&M and design/build projects annually, with business unit teams maintaining backlog in tight market conditions. Directed business development for new initiatives including teaming arrangement with Fluor and two other ASRC subsidiaries to secure a $700M contract at DOE's Strategic Petroleum Reserve; advocated utilization of prefabricated modules for a Barrow hotel in order to save time and money; completed an acquisition that resulted in a business expansion; moved ACHC into the oil & gas sector to perform capital projects. Achieved aggressive Local/Shareholder hire goals each year. Improved safety culture, reducing incident rate from over 3.5 to 0.78. Restructured ACHC to increase efficiency and improve support to operating units. NANA DEVELOPMENT CORPORATION, Vice President (2006-2010) Managed NDC's operations at the Red Dog Mine. Built joint ventures and alliances, increasing portfolio of 10 companies' revenue 200% from 2006 to 2008. NDC corporate-wide: participated in M&A activities and created forum of NDC executives to meet and hear from guest speakers in order to pursue opportunities in the petroleum and mining industry. Responsible for Profit/Loss within Lynden, Crowley, Major American Drilling and PAA River Constructors partnerships, Negotiated NANA's initial multi-year contract to provide Red Dog with 19,500,000 gallons of fuel annually. Developed an apprentice program to train drillers during the winter season in New Mexico for employment at Red Dog during the summer season. NDC's lead for the initiative to bring the Red Dog lightering contract to NANA/Lynden. SECURITY AVIATION INC., Director of Business Development (2004-2006) Hired for a business development role, initiated and managed a complete review of operations, increasing profit margins three-and-a-half fold with minimal investment while converting underperforming assets into positive investment returns. Evaluated opportunities and developed proposals for new business. MENDENHALL AND ASSOCIATES, Management Consultant (2003-2004) Advised companies on the Small Business Administration Mentor-Protégé, 8(a) programs and certification processes. Participated in the creation of a rural Alaska fuel consortium funded by the Denali Commission. Worked with Canadian First Nations and the Alaska Highway Aboriginal Pipeline Group. Evaluated options for construction and operation of a small refinery/topping plant on the North Slope. ARCTIC SLOPE REGIONAL CORPORATION ASRC Constructors, President (2002) Converted dormant subsidiary into a qualified Small Business Administration 8(a) and secured key contracts with the Department of State for construction of a foreign embassy and DOE for Construction Management services. SKW-Eskimos, Inc., (1979-2001) Vice President of Marketing and Business Development (1999-2000) Business Development Manager (1992-1999) Accomplishments include: Maintained and guided Village Corporation relationships leading to over $250 million in JV contracts and diversified revenue by expanding business presence outside of Alaska. Advised Canadian First Nations on establishing for-profit economic entities. Secured an oil and gas development project for a Yukon First Nation's entity. Developed a Small Business Administration Mentor-Protégé Agreement. Refocused SKW's community contributions plan to increase return on investment. Successfully lobbied federal government for revisions to PL 93-638 (Indian Self Determination Act). Secured first fixed price construction ($4 million) '638' contract with Bureau of Indian Affairs for an Alaska Native corporation joint venture. Monitored Texas-based gas compression operation. Secured engineering and construction contracts for infrastructure development in Anadyr, Chukotka Autonomous Region (Russian Far East). Acquisition team member for Venezuelan fabrication facility and Texas based gas compression company. Conducted quarterly business reviews with the ASRC executive committee, delivered annual business unit financial plans and forecasts to the ASRC board. Served as a Trustee for the ASRC pension plan. Construction Administrator (1983-1992), Project Engineer (1979-1983) EDUCATION University of Alaska: 1979 Bachelor of Science - Civil Engineering, 1979 Associate of Arts - Science University of Washington: 1998- Accounting for Non-Financial Managers Levinson Leadership Institute: 1999 Alaska Humanities Forum: 2000 Leadership Anchorage Program FBI Citizens Academy PERSONAL & PROFESSIONAL AFFILIATIONS U.S. Chamber of Commerce - Director Prior board positions: Boy Scouts of Alaska, Associated Builders & Contractors-Alaska, Alaska Chamber of Commerce, University of Alaska Fairbanks College of Engineering & Mines Advisory Committee Race Across AMerica (RAAM) June 2000 member of Team Alaska Registered Professional Engineer — Alaska #7243 Have held Top Secret and Secret clearances Keriann Baker Chief Strategy Officer kbaker@homerelectric.com 907-235-3302 PROFESSIONAL SUMMARY Keriann is presently employed as the Chief Strategy Officer for Homer Electric Association, Inc. Keriann has served on numerous boards including local, and state chambers, state and national bar associations, and the South Peninsula Hospital, Inc. Board. Keriann received a Bachelor of Science from Utah Valley University and received a Juris Doctor Degree from Loyola Chicago School of Law. Keriann and her husband, Bryan, live in Homer and spend most of their free time chasing after their three school aged children and two dogs. Keriann enjoys fishing, hiking, camping, reading, and skiing. As an adult, Keriann formed a travel and adventure addiction. She has visited 44 of 50 states and visited 20 countries throughout Europe, South America, and the Caribbean. EXPERIENCE HOMER ELECTRIC ASSOCIATION, INC. (HEA) Chief Strategy Officer | 2021 - Present Oversees the cooperative’s strategic initiatives, public relations and external affairs efforts, and legislative affairs for HEA. REEVES AMODIO Attorney | April 2019 to April 2021 Representing clients in transactional matters, litigation and administrative proceedings including Representing developers before municipal entities and in legal proceedings for all manner of land use, environmental permitting, and zoning matters. Serving as corporate counsel. Representing Tribes in permitting, land use and transactional matters. Representing corporate clients engaged in business transactions with Tribes and tribally owned businesses. KC BAKER, P.A. / KC BAKER, LLC President | October 2013 to April 2019 Represented clients in transactional matters, litigation and administrative proceedings including Represented corporations, developers, and property owners before governmental bodies in matters relating to marine and coastal issues, environmental permitting, land use matters, zoning, and comprehensive planning. Served as corporate counsel for various companies. Provided of counsel services to various Alaska attorneys. Attended and argued motion and evidentiary hearings; developed discovery strategies, pleadings, motions, and legal memoranda; prepared for and attended trials. Represented corporate clients engaged in business with Native American Tribes and Tribal owned businesses. LEWIS, LONGMAN & WALKER, P.A. Attorney | June 2007 to October 2013 Represented clients in transactional matters, litigation and administrative proceedings including represented state and local governments and Tribes in land use and environmental matters. Advised financial institutions of environmental risks relating to property in foreclosure and pre-foreclosure. Represented tribes in putting land into trust with the Department of Interior and establishing delegated permitting agreements. Represented clients in environmental remediation matters. Litigated endangered species, energy and environmental lawsuits and administrative land use challenges. Represented airports in environmental permitting, land use and administrative matters. LIBOW & SHAHEEN LLP, BOCA RATON, FLORIDA Attorney | February 2006 to June 2007 CHRISTINE D. HANLEY & ASSOCIATES, P.A. Law Clerk and Attorney |July 2005 to February 2006 EDUCATION Loyola University Chicago School of Law: 2004 – Juris Doctor Utah Valley University: 2002 Bachelor of Science – Integrated Studies: Political Science, History and English PERSONAL & PROFESSIONAL AFFILIATIONS Alaska State Bar: Admitted 2018 Alaska Chamber of Commerce: Board Member 2018 –2020 South Peninsula Hospital, Inc., Homer, Alaska: Board Member 2018 to Present, Finance and Governance Committees, Chair Education Committee Homer Chamber of Commerce, Homer, Alaska: Board Member 2014 to Present, Vice President 2016- 2017, President 2017-2018, Past President 2018-2019 Executive, Bylaw and Legislative Affairs Committees South Peninsula Hospital Service Area Board: Board Member elected to three-year term from 2015 to 2018 Athena Award Finalist, Women Leaders Under 40, Palm Beach County Florida: The Athena Award is given to women nominated as rising stars and leaders in the community, 2013. Florida Rising Star in Environmental Law: Peer evaluation awarded to only 2.5% of Florida Lawyers, 2009, 2011 Florida State Bar: Admitted 2005, Florida Young Lawyers Division’s District Representative to the American Bar Association - Young Lawyers Division 2010-2012 Term, Student Loan Reform Committee 2010-2012; Council 2010-2012; Executive Council Membership Chair 2011-2012 American Bar Association - State & Local Government Section: Member 2007-2012, Council 2009- 2011, Environmental Committee Vice-Chair 2009-2011, Membership Committee 2009-2011, Electronics Committee 2009-2011 Leadership West Palm Beach: Graduate 2008 Class Florida Airports Council: Environmental and Legal Affairs Committees 2011- Present Marine Industries Association of Palm Beach County, Board Member 2011 - 2013, Boat Show Expansion Committee Friends of the Gumbo Limbo Nature Center, 2011- 2013, Board of Directors 2010-2012 Travis Million travismillion7@gmail.com | (907) 259-1100 | Fairbanks, Alaska linkedin.com/in/travis-million-8804b57a/ ELECTRIC COOPERATIVE CHIEF EXECUTIVE OFFICER Strong managerial background with over 10-years of executive level experience and a solid understanding of electric cooperative principles, operations, and finance. Dynamic leader who can develop cohesive teams, build positive rapport in the community, and has a proven track record. Strong communications skills to include public speaking at local, statewide, regional, and national events. WORK EXPERIENCE Golden Valley Electric Association Fairbanks, Alaska CHIEF OPERATING OFFICER September 2023 - Present Copper Valley Electric Association Glennallen, Alaska CHIEF EXECUTIVE OFFICER March 2020 – Aug 2023 Chief Operating Officer Jan 2016 – Feb 2020 Manager of Power Generation & Compliance June 2015 - Jan 2016 Manager of Power Generation Aug 2011 - June 2015 Duties: • Direct the day-to-day operations and activities of the cooperative • Generation, Transmission, & Distribution cooperative • $150M book assets (over $250M adjusted value) • $25M annual revenue • 44 full time employees • Participate in monthly board meetings • Develop and maintain positive relationships with Legislators on state and federal level • Develop and maintain positive relationships with personnel of multiple state and federal agencies • Active in various contract negotiations to include Union labor and special requirements contracts for industrial and large commercial members Chief Operating Officer • Oversee the following departments: Operations, Production, Engineering, Environmental & Regulatory Compliance, & Safety • CVEA Hydroelectric Facilities – Chief Dam Safety Engineer • Oversee operations of all CVEA generation facilities: Solomon Gulch Hydroelectric Plant (12MW), Allison Creek Hydroelectric Plant (6.7MW), Cogeneration Turbine Plant (5.3MW), Valdez Diesel Plant (9MW), Glennallen Diesel Plant (11MW) • Oversee operation of the 106 mile, 138kV transmission infrastructure and five associated substations • Oversee operation of over 500 miles of overhead and underground 25kV distribution system and associated substations • Oversee all regulatory and compliance for CVEA to include working with the following agencies: FERC, EPA, AKDEC, DOE, EIA, USACE, DNR, BLM • Proven project management with high rate of projects being completed under budget and on schedule • Set company safety records in lowest Workers’ Compensation Modification Factor, OSHA recordable, days away, incident rate, DART rate, and longest streak for no time loss accidents (1,200+ days) AREAS OF EXPERTISE Executive Leadership Strategic Planning Risk Management Member Focused Negotiations Electric Cooperative Expertise Exceptional Communicator Emergency Management Governance Policy Development Financial Planning Personnel Management Team Building Public Administration Value Engineering Technical Innovation Budget Development Project Management Lead Change AWARDS 2023 - NWPPA Safety Contest - First Place 2021 – APA Commitment to Continuous Safety Improvement 2020 – NWPPA Safety Contest – Second Place 2019 - ACEC - Allison Creek Hydroelectric Design-Build Project - Honor Award 2019 - NWPPA Safety Contest - First Place 2018 - NWPPA Safety Contest - First Place 2017 - Alaska Journal of Commerce - Top Forty Under 40 Marsh Creek LLC. / BAE Systems (HAARP) Gakona, Alaska HAARP Site Power Engineer / Feb 2005 - Aug 2011 Health, Safety, & Environmental Manager Schweitzer Engineering Laboratories, Inc. Pullman, Washington Hardware Design Engineering Technician Sept 1999 - Feb 2005 Field Service Engineering Technician Test Operator Assembler ACADEMIC QUALIFICATIONS Cooperative Financial Professional Certificate (CFPC) NRECA/CFC 2019 Dulles, VA MBA Certification University of St. Thomas 2018 Minneapolis, MN Robert I. Kabat NRECA Management Internship Program (MIP) University of Wisconsin 2013-2014 Madison, WI Cold Regions Engineering Short Course Certificate University of Washington 2009 Seattle, WA AAS Electrical Engineering ITT Technical Institute 2000 Spokane, WA COMMUNICATIONS • Alaska State Legislature Testimonies – Multiple • CVEA Annual Meetings • NRECA Safety Leadership Summit • Northwest Hydropower Association Annual Meeting • Northwest Public Power Association Alaska Utility Conference • Alaska Power Association Safety Summit • Alaska Power Association Annual Meetings • Allison Creek Commissioning Ceremony • Valdez City Council/Copper Basin Chamber of Commerce • CVEA social media – Video messaging (multiple) • Published Articles – Ruralite (multiple) • Facility tours for Alaska Governor, Senators, Representatives, Alaska State Chamber of Commerce • Guest lecturer and presenter at local schools ACCREDITATIONS • Incident Command System Training o ICS-100, ICS-200, MGT-345 • CFC KRTA Level 1 Certificate • FERC Division of Dam Safety and Inspections o Dam Safety 101 Workshop o Licensing and Compliance Workshop 201 • NRECA-RESAP Safety Observer Certified • OSHA 501 & 511 – General Industry Train the Trainer • OSHA – 10 Hour Construction Training • OSHA – 30 Hour General Industry Outreach Training • HAZWOPER Technician Level C Certification (40 hour) • 8 Hour HAZWOPER Supervisor Training • Delayed Care First Aid/CPR/AED Certification • NFPA 70E Certification • Method-9 Visible Emissions Testing Certification • EPTC Power Plant Operations Training • EMD 645 Series Technical/Practical Course Certified • ABB LV & MV Breaker Factory Service Certified • NRECA – Credentialed Cooperative Director VOLUNTEER WORK • Alaska Broadband Advisory Board (2023- present) • General Pacific (GENPAC) Board of Directors (2023-present) • Alaska Power Association (APA) Board of Directors (2020-2023) • APA Government Affairs Committee (2021-2023) o Chair (2021 – 2023) • APA Safety Committee (2016-2023) o Chair (2017-2020) o Vice Chair (2016) • NRECA Generation Advisory Committee (2022-present) • National Science Foundation FIREWALL advisory board (2021-2023) • Copper Valley Telecom Board of Directors (2015-2018) • Copper Valley Electric Board of Directors (2008-2011) o President (2010- 2011) o Vice President (2009) • Glennallen Community Chapel Board of Directors (2017-2023) o Chair (2020-2023) o Secretary (2018- 2020) • Copper River Local Emergency Planning Committee (2015-2023) o Vice Chair (2019- 2023) • Little Dribblers Basketball Coach (2007- 2012, 2015-2023) • Financial Peace University/Legacy Journey Coordinator Resume of Brian Hickey 1 Email:brian.hickey@mea.coop LinkedIn: linkedin.com/in/brianhickey01 Summary As a proven executive leader, I bring an extensive background in electric utility operations, encompassing transmission, hydroelectric, thermal generation, and telecommunications. My comprehensive understanding of the energy sector is evidenced by a track record of effectively planning, operating, acquiring, and integrating major utility assets, fostering inter-agency collaboration, and propelling strategic growth. My experience includes direct strategic planning and collaboration with the Boards and CEOs of prominent Railbelt electric utilities, along with proactive advocacy for federal and state funding. I have played a pivotal role in advancing state strategic initiatives related to clean energy standards and grid/transmission reforms, particularly in the development of governance models for ISO/RTO and ERO frameworks. During my tenure at Chugach Electric, my team and I accomplished many things from established a profitable long-haul telecommunications business unit, leveraging our comprehensive microwave and fiber assets to maximize returns for our members to successfully acquiring and merging the two largest utilities in the Railbelt. My capability to navigate complex regional issues has been marked by a consistent track record of maintaining strong relationships across various levels of federal and state government. I am deeply committed to community and social responsibility, ensuring safety, reliability, and efficiency in every initiative I undertake. Experience Executive Director, Railbelt Regional Coordination April 2022 – Present • Reports directly to the CEOs of the five Railbelt Utilities and the Director of the Alaska Energy Authority. • Leads cross-functional teams focusing on regional issues, including advocating for federal funding and strategic affairs related to state clean energy standards and reformation of transmission governance. • Completed successful concept papers and application for $530 million in federal funding. • Led the Railbelt team the recently received $206.5 million in federal funding through the Grid Resilience and Innovation Partnership (GRIP) Topic 3 funding opportunity announcement. When matched this grant will total $413M and fund construction of a second intertie from the Kenai peninsula to the Central region. • Led the Railbelt team that recently was selected to move forward with on a second application for DOE funding to construct a second line from the Central region to Healy. • Established and nurtured relationships with federal and state government officials at multiple tiers (DOE, USDA-RUS, federal delegations, state executive and legislative branches), indigenous groups, and key stakeholders. Resume of Brian Hickey 2 Chugach Electric Association Inc. 2012 - April 2022 Chief Operating Officer November 2018 - April 2022 • Successfully completed the acquisition and integration of Anchorage Municipal Light and Power (valued at ~$1B). • Managed over 300 employees with an O&M budget of approximately $100M. • Enhanced alignment between internal and external stakeholders. Sr. Vice President, System Opera tions July 2016 - November 2018 • Pioneered regional grid unification and strategic planning. • Managed operations for 120 personnel with a ~$30M budget. • Oversaw acquisition strategies and internal leadership development. Executive Manager, Grid Development June 2012 - December 2016 • Directed transmission system and regional grid integration. • Served as an expert witness in regulatory issues pertaining to wholesale customer contracts. • Key achievements: authorization of electric reliability organization in statute, acquisition strategies, and fuel supply planning. Senior Project Manager, Electric Power Systems Inc. August 2010 - June 2012 • Oversaw project phases from initiation to completion. • Highlighted projects: Fort Wainwright power plant refurbishment and Anchorage Regional Landfill gas generation project. Senior Project Manager, NANA-WorleyParsons February 2009 - August 2010 • Led notable projects including feasibility design for remote-site 675 MW gas-fired power plant and evaluations of fuel supply alternatives (Natural Gas, LNG import, coal gasification). Various other positions Chugach Electric Associa tion 1988 - January 2009 Roles included VP of Power Delivery, Director of Technical Services, Manager of Power Control Center, Manager of Substation Operations, and others. Oversaw power system and field operations, facilities, telecommunications, strategic planning, and asset management. Anchorage Municipal Light, and Power June 1984 - Sep 1988 Roles included T&D line design engineer, distribution dispatcher, and relay technician. Resume of Brian Hickey 3 Education • Bolea-Atwater-Applied Leadership Development 2018-19 • M.A., Global Finance & Business Admin, Alaska Pacific University, 2005-2007 • Master's Certificate in Project Management, ESI/George Washington University, 2003-2005 • MIP Certificate in Cooperative Management, NRECA Robert Kabal Program, 2001-2002 • B.Sc., Electrical Engineering, Montana State University, 1978-1984 Licenses Certifications & Memberships • Registered Professional Electrical Engineer (PE), Member IEEE • Pritchett-Certified in Merger & Acquisition Integration • Current member National Association of Corporate Directors and former Board Leadership Fellow • Current Member of Project Management Institute, and former Certified Project Management Professional (PMP) Publications • "Pelton turbine deflector control designs for Bradley Lake hydro units", IEEE American Control Conference, 2002 Volunteering • Denali Federal Credit Union: Supervisory Committee Chair (2008-2014), Board of Directors Member (2014-2018) • Nuvision Federal Credit Union: Board of Directors Member (2018-present) • Rotary Club of Anchorage: Former Member & Fundraising Volunteer • Boy Scouts of America: Former Pack Leader & Adult Leader • Big Brothers and Sisters: Former Big Brother References Available upon Request. Larry Jorgensen Chief Power Production Officer ljorgensen@homerelectric.com 907-335-6160 PROFESSIONAL SUMMARY Larry Jorgensen is a utility professional with over 40 years of operations and generating facility management experience with extensive experience in: managing personnel, budgets, forecasts, projects, outages, reporting, troubleshooting systems, implementation of technical applications to optimize plant performance, analysis of plant data, and training of plant personnel. EXPERIENCE HOMER ELECTRIC ASSOCIATION Chief Power Production Officer | 2016 – Present Ensures the safe and reliable management of generation, transmission, and fuel resources for Homer Electric Association, including the O&M contract to the State of Alaska for the Bradley Lake Hydroelectric Project. Develops and executes strategic long-term planning, reporting, modeling and forecasting of load and generation resources, maintaining compliance with reliability and cybersecurity standards, and multi-year budgeting. Nikiski Combined Cycle Plant Superintendent | 2013 – 2016 Managed an 80 MW combined cycle plant and generation dispatch for HEA’s load balancing area. Responsible for preparing budgets, daily operation and maintenance, long term planning, daily load and generation forecasts, daily gas nominations, and plant outages. Direct reports included an assistant superintendent and four shift supervisor/dispatchers. Served as the main point of contact for all power sales and purchases for HEA. Bradley Lake Hydroelectric Plant Superintendent | 2011 – 2013 Managed a 126 MW hydroelectric facility for HEA and Alaska Energy Authority. Responsible for preparing budgets, daily operation and maintenance, long term planning, and plant outages. Presented operational and maintenance status to the State and participating utilities monthly. Direct reports included five plant operators. DESERET POWER – BONANZA STATION Operations Superintendent | 2006 – 2011 Managed operations department of a 500 MW coal fired plant, which included plant operators, lab technicians, and heavy equipment operators. Responsible for preparing budgets, daily operations, limestone mine, long term planning, operation’s reports. Direct reports included eight supervisors with 49 total personnel in the department. Senior Shift Supervisor / Simulator Specialist | 1999 – 2006 Responsible for administering operations department training and advancement program. Managed high fidelity simulator and provided simulator training to plant operators. Coordinated operations personnel schedules and provided relief coverage for shift supervisors. Shift Supervisor | 1995 – 1999 Managed operations crew. Duties included unit operation, on shift training, reporting, troubleshooting, administering plant lockout/tagout system, and served as incident commander in plant emergencies. Crew consisted of control room operator, five plant operators, lab technician, and heavy equipment operator. Assistant Shift Supervisor, Senior Operator, Control Room Operator, Relief Operator, “A” Operator, Operator Trainee | 1983 – 1995 Advanced from operator trainee through assistant shift supervisor. Promoted to assist crew personnel management and training; provided coverage for control room operators and shift supervisors and performed system troubleshooting. EDUCATION Brigham Young University and Utah State University, 1978-1980 – Match & Computer Science Bismarck State College, 2015 – Associate of Applied Science – Power Plant Technology; 2017 Bachelor of Science – Energy Management, Phi Theta Kappa; April 10, 2024 Hon. Gene Rodrigues Assistant Secretary, Office of Electricity U.S. Department of Energy 1000 Independence Avenue, SW Washington, D.C. 20585 Assistant Secretary Rodrigues, We are writing in support of the application submitted by Alaska Energy Authority (AEA) for FY2024-FY2025 funding through Topic Area 3 of the Grid Resilience and Innovation Partnerships (GRIP) Program. The five Alaska Railbelt electric utilities and the St ate of Alaska’s AEA are working in unison to design, fund and implement a program of grid modernization that will directly benefit the 75 percent of the state’s population connected to the grid and indirectly benefit rural Alaskans who are geographically isolated from the Railbelt but are eligible for Alaska’s innovative rural electric subsidy Power Cost Equalization program. This is a once-in-a-generation opportunity for Alaskans to stabilize an aging grid by bringing it up to modern standards and enhancing resiliency in the face of unprecedented natural disasters, climate change and rugged geographic terrain. These improvements are critical to preparing Alaska for a fuel-diverse clean energy future and integrating new sources of energy along the grid, which spans a distance equivalent to the space between Atlanta, GA and Washington, D.C. The benefit of this work reaches far beyond our state. The Railbelt grid supplies energy to five U.S. military bases of vital strategic importance to national security. These critical assets contribute to the national defense from a broad range of perspectives including missile defense, global telecommunications downlink infrastructure, and F-22 high-speed intercept capability. The Railbelt grid serves the Don Young Port of Alaska, a federally designated strategic seaport which provides virtually all of the cargo, food, fuel and building materials to the majority of Alaskans. And finally, the Railbelt grid serves Ted Stevens Anchorage International Airport – the third busiest airport in the world in terms of cargo throughput. With the U.S. Department of Energy as a partner, Alaska’s utilities and the State of Alaska will be positioned to demonstrate grid revitalization and decarbonization on a scale that can be replicated. Consistent with all relevant rules, laws, and regulations, we respectfully request that all due consideration be given to this application and all other eligible Alaska-based applications. We also ask that you keep our offices appraised of the outcome. Thank you for your consideration. Sincerely, Lisa Murkowski United States Senator Dan Sullivan United States Senator Mary Sattler Peltola Representative for All Alaska Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0003195 RE: Alaska’s Railbelt Grid Modernization and Resiliency Plan To Whom It May Concern, The Alaska Municipal League (AML) is a voluntary, nonprofit, nonpartisan, statewide organization of 165 cities, boroughs, and unified municipalities, wherein over 97 percent of Alaskans reside. Since the passage of the Bipartisan Infrastructure Law, AML has focused its efforts to support strategic regional projects that address the long-standing inadequacy of Alaska’s infrastructure. As part of this effort, we are proud to support projects that improve the condition of communities and intersect with Alaska’s municipalities. We are excited to see the next phase of the Alaska Railbelt’s Grid Modernization and Resiliency Plan (GMRP) move forward. Working to decarbonize Alaska’s Railbelt grid is a particularly timely endeavor – state regulators have recently indicated that the natural gas supply that both power generation and other users rely on may not meet current demand within the next decade. This looming shortage puts economic activity throughout the state at risk by introducing long-term uncertainty to the key services that local governments and other organizations rely on from the Railbelt. With some of the highest energy prices in the country, solutions to control cost are a critical economic challenge facing Alaska’s communities and economic development. It’s important to note that in addressing costs on the Railbelt, these projects also stand to benefit communities across the state via the Power Cost Equalization program. The formula for this critical program ties subsidies for energy across the state to Railbelt prices – thus, if the cost of electricity on the Railbelt is lowered, it provides a greater subsidy to those communities who are experiencing high costs, and in effect lowering the cost to consumers. The GRMP is a strategic and collaborative effort that would go beyond the Railbelt to help make energy and the rural economies that depend on it more affordable and resilient. We fully support the GRMP and its associated projects. Sincerely, Nils Andreassen Executive Director Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0003195 RE: Alaska’s Railbelt Grid Modernization and Resiliency Plan To Whom It May Concern, The Alaska Municipal League (AML) is a voluntary, nonprofit, nonpartisan, statewide organization of 165 cities, boroughs, and unified municipalities, wherein over 97 percent of Alaskans reside. Since the passage of the Bipartisan Infrastructure Law, AML has focused its efforts to support strategic regional projects that address the long-standing inadequacy of Alaska’s infrastructure. As part of this effort, we are proud to support projects that improve the condition of communities and intersect with Alaska’s municipalities. We are excited to see the next phase of the Alaska Railbelt’s Grid Modernization and Resiliency Plan (GMRP) move forward. Working to decarbonize Alaska’s Railbelt grid is a particularly timely endeavor – state regulators have recently indicated that the natural gas supply that both power generation and other users rely on may not meet current demand within the next decade. This looming shortage puts economic activity throughout the state at risk by introducing long-term uncertainty to the key services that local governments and other organizations rely on from the Railbelt. With some of the highest energy prices in the country, solutions to control cost are a critical economic challenge facing Alaska’s communities and economic development. It’s important to note that in addressing costs on the Railbelt, these projects also stand to benefit communities across the state via the Power Cost Equalization program. The formula for this critical program ties subsidies for energy across the state to Railbelt prices – thus, if the cost of electricity on the Railbelt is lowered, it provides a greater subsidy to those communities who are experiencing high costs, and in effect lowering the cost to consumers. The GRMP is a strategic and collaborative effort that would go beyond the Railbelt to help make energy and the rural economies that depend on it more affordable and resilient. We fully support the GRMP and its associated projects. Sincerely, Nils Andreassen Executive Director MATANUSKA ELECTRIC ASSOCIATION, INC. • P.O. Box 2929 • Palmer, Alaska 99645 • t 907.745.3231 • f 907.761.9368 • www.mea.coop April 10, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3 Grid Innovation Program; Railbelt Innovative Resiliency Project Dear Application Review Committee, Matanuska Electric Association, Inc. (MEA) is pleased to team with the State of Alaska, d/b/a the Alaska Energy Authority, and the other Railbelt electric utilities1 to partner in the funding opportunity for Railbelt Innovative Resiliency Project (RIR) (DE-FOA-0003195). MEA is a not-for-profit, member owned, electric cooperative that serves almost 65,000 meters in the fastest-growing area of Alaska. We operate and maintain nearly 4700 miles of power lines, 26 substations and self-generate the majority of our power. MEA is interconnected to the other Railbelt electric utilities via a single transmission line, the majority of which is the Alaska Intertie – a 170 mile long, 345 kilovolt (kV) transmission line between Willow and Healy that operates at 138 kV. Together, MEA and the other Railbelt electric utilities comprise what is commonly referred to as the Alaska Railbelt Electric System and provides electric service to approximately 75% of Alaska’s population. MEA is supportive of the Railbelt Innovative Resiliency Project proposal and hopes that the proposal receives DOE approval. As a not-for-profit, member owned cooperative, MEA has a fiduciary responsibility to our member-consumers, to ensure that MEA’s resources are used wisely and prudently. As essential as the Railbelt Innovation Resiliency Project is to achieve meaningful, transformative, long-term benefits on the Railbelt Electric System, the cost of achieving those benefits cannot, from a practical perspective, be borne solely by our small number of Railbelt ratepayers. Financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically necessary. For that reason, MEA supports the cost allocation methodology outlined in this and other applications being submitted by this project team to the DOE’s Grid Resilience and Innovation Partnerships (GRIP) Program that prioritizes securing Federal IIJA/IRA funds with State of Alaska matching funds for the “non-federal cost share requirement.” If necessary, additional funding will also come from MEA and the other Railbelt electric utilities, subject to successful negotiation of the grant contract and receipt of any necessary Board of Directors, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered from the Railbelt’s member-consumers. MEA has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE IIJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. 1 Chugach Electric Association, Inc., Homer Electric Association, Inc., Golden Valley Electric Association, Inc., and the City of Seward d/b/a Seward Electric System. U.S. Department of Energy Letter of Commitment for Topic Area 3 April 10, 2024 Page 2 MEA fully supports the Railbelt Innovative Resiliency proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan that has and will be submitted to the DOE under separate applications. As the application reflects, there exists unprecedented alignment amongst the Railbelt utilities and the Alaska Energy Authority to materially transform the Railbelt electric system. We are committed to work collaboratively in order to strengthen and build a smart, clean electrical grid that ensures residents, communities, and the military bases served by the Railbelt electric utilities have access to clean, reliable, low-cost energy. Sincerely, Anthony M. Izzo Chief Executive Officer /. , c soc1a 10n PO Box 71249, Fairbanks, AK 99707-1249 • (907) 452-1151 • www.gvea.com April 10, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 Your Touchstone Energy• Cooperative � RE: Letter of Commitment for Topic Area 3: Grid Innovation Program -Railbelt Innovative Resiliency Project To the U.S. Department of Energy, Golden Valley Electric Association, Inc. (GVEA) is pleased to team with the State of Alaska, d/b/a the Alaska Energy Authority, and the other Railbelt electric utilities 1 to partner in the funding opportunity for the Railbelt Innovative Resiliency Project (RIR) (DE-FOA-003195). GVEA is a not-for-profit, member owned, electric cooperative that serves nearly 100,000 residents in Interior Alaska. We operate and maintain nearly 3,300 miles of power lines, 35 substations and nine generating facilities. GVEA's electric system is interconnected with, and has the ability to serve, four critical military installations -Fort Wainwright, Eielson AFB, Fort Greely, and Clear AFS. GVEA is also interconnected to the other Railbelt electric utilities via a single transmission line, the majority of which is the Alaska lntertie - a 170 mile long, 345 kilovolt (kV) transmission line between Willow and Healy that operates at 138 kV. Together GVEA and the other Railbelt electric utilities comprise what is commonly referred to as the Alaska Railbelt electric system and provide electric service to approximately 75% of Alaska's population. GVEA is supportive of the Railbelt Innovative Resiliency Project proposal and hopes that the proposal receives DOE approval. As a not-for-profit, member owned cooperative, GVEA has a fiduciary responsibility to our member-consumers, to ensure that GVEA's resources are used wisely and prudently. As essential as the RIR is to achieve meaningful, transformative, long-term benefits on the Railbelt electric system, the cost of achieving those benefits cannot, from a practical perspective, be borne solely by Railbelt Ratepayers. Financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically necessary. If necessary, additional funding will also come from GVEA and the other Railbelt electric utilities, subject to successful negotiation of the grant 1 Chugach Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., and the City of Seward d/b/a Seward Electric System. DOE Letter of Commitment (GVEA) DE-FOA-003195 Page 2 of 2 contract and receipt of Board of Directors, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered from the Railbelt's member-consumers. GVEA has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE I IJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. GVEA fully supports the Railbelt Innovative Resiliency Project, as well as other aspects of the broader Grid Modernization and Resiliency Plan as defined in the technical volume. There exists unprecedented alignment amongst the Railbelt utilities and the Alaska Energy Authority to materially transform the Railbelt electric system. We are committed to work collaboratively in order to strengthen and build a smart, clean electrical grid that ensures residents, communities, and the military bases served by the Railbelt electric utilities have access to clean, reliable, low-cost energy. 1ef Executive Officer Corporate Office Central Peninsula Service Center 3977 Lake Street 280 Airport Way Homer, Alaska 99603-7680 Kenai, Alaska 99611-5280 Phone (907) 235-8551 Phone (907) 283-5831 FAX (907) 235-3313 FAX (907) 283-2353 April 12, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3, Round 2: Grid Innovation Railbelt Innovative Resiliency (RIR) Project DE-FOA-0003195 Dear Grid Deployment Office: Homer Electric Association, Inc. (HEA) is pleased to submit this letter expressing its support for the funding proposal for improving grid resilience in the Alaska Railbelt. HEA is a not-for-profit, member- owned, electric cooperative that serves the residents, businesses, and industrial facilities on the Kenai Peninsula in the state of Alaska. HEA’s electric system is interconnected with the other Alaska Railbelt electric utilities via a single transmission line between the HEA and Chugach Electric systems. Together HEA and the other Railbelt electric utilities comprise what is commonly called the Alaska Railbelt Electric System and provide electric service to approximately 75 percent of Alaska’s population. HEA supports the RIR proposal and hopes it receives DOE approval. As a not-for-profit, member- owned cooperative, HEA has a fiduciary responsibility to its member-consumers, to ensure that HEA’s resources are used wisely and prudently. As essential as transmission improvements are to achieving, transformative, long-term benefits on the Railbelt Electric System, the cost to HEA’s members to secure those benefits must be understood before HEA can make a financial commitment to participate in funding the project. For that reason, HEA expects financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) to be critically necessary. Accordingly, HEA commits to working with the other utilities and the State of Alaska to develop a mechanism for funding the “non-federal cost share requirement” of the initiatives. HEA’s funding obligation in this regard will be subject to HEA’s final approval of the grant agreement terms and any necessary or appropriate Board of Directors, regulatory, and/or third-party approvals. HEA supports the RIR proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan. As the application reflects, there exists unprecedented alignment among the Railbelt utilities and the Alaska Energy Authority to create a resilient, reliable Railbelt electric system that would be on a par with the systems currently enjoyed by the rest of the country. HEA is committed to working collaboratively to achieve that end. Sincerely, Bradley P. Janorschke General Manager CITY OF SEWARD P.O. Box 167 410 Adams Street Seward, Alaska 99664-0167  Main Office (907) 224-4050  Police (907) 224-3338  Harbor (907) 224-3138  Fire (907) 224-3445  City Clerk (907) 224-4046  Community Development (907) 224-4049  Utilities (907) 224-4050  Electric (907) 224-4073 April 10, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3, Grid Innovation Dear Grid Deployement Office: Seward Electric System (SES), a small municipal power provider that serves approximately 3,000 residents in Southcentral Alaska, is pleased to submit this letter of support for the funding proposal for improving Grid Innovation. SES supports the Railbelt Innovating Resiliency Project (RIRP) proposal and is hopeful the proposal receives DOE approval. SES is the smallest of the Railbelt utilities, but our customers are directly impacted by the investments made to improve the Railbelt grid. Clearly, grid innovation is an initiative that will benefit the many consumers who depend on the Railbelt utilities for clean, reliable and affordable electricity. For the initiative to be successful, financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically important. If necessary, additional funding will also come from the Railbelt electric utilities, subject to successful negotiation of the grant contract and receipt of any necessary board/council, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered in consumer rates. SES has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE IIJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. As the application reflects, the Railbelt utilities are united and are working with the Alaska Energy Authority to materially transform the Railbelt electric system and ensure our members/customers have a secure energy future. Sincerely, Brian Hickey General Manager Seward Electric Systems Prime Applicant/ Team Member Address City StateNine Digit Zip Code (ZIP+4)Alaska Energy Authority 813 West Northern Lights Anchorage AK 99503-2407Mat-Su Borough 350 E. Dahlia Ave. Palmer AK 99645-6411Denali Borough P.O. Box 480 Healy AK 99743-0480Healy Alaska P.O. Box 480 Healy AK 99743-0480Matanuska Electric Association 163 Industrial Way Palmer AK 99645-6703Golden Valley Electric Assocation 758 Illinois Streer Fairbanks AK 99701-2919Homer Electric Association 3977 Lake Street Homer AK 99603-7652Chugach Electric Association 5601 Electron Drive Anchorage AK 99518-1074Seward Electric 238 5th Ave. Seward AK 99664-4400Control Number: 3195-1942Location(s) of Work DocumentationDE-FOA-00031954/16/20243195‐1942_AEA_LOW1 Corporate Office Central Peninsula Service Center 3977 Lake Street 280 Airport Way Homer, Alaska 99603-7680 Kenai, Alaska 99611-5280 Phone (907) 235-8551 Phone (907) 283-5831 FAX (907) 235-3313 FAX (907) 283-2353 April 12, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3, Round 2: Grid Innovation Railbelt Innovative Resiliency (RIR) Project DE-FOA-0003195 Dear Grid Deployment Office: Homer Electric Association, Inc. (HEA) is pleased to submit this letter expressing its support for the funding proposal for improving grid resilience in the Alaska Railbelt. HEA is a not-for-profit, member- owned, electric cooperative that serves the residents, businesses, and industrial facilities on the Kenai Peninsula in the state of Alaska. HEA’s electric system is interconnected with the other Alaska Railbelt electric utilities via a single transmission line between the HEA and Chugach Electric systems. Together HEA and the other Railbelt electric utilities comprise what is commonly called the Alaska Railbelt Electric System and provide electric service to approximately 75 percent of Alaska’s population. HEA supports the RIR proposal and hopes it receives DOE approval. As a not-for-profit, member- owned cooperative, HEA has a fiduciary responsibility to its member-consumers, to ensure that HEA’s resources are used wisely and prudently. As essential as transmission improvements are to achieving, transformative, long-term benefits on the Railbelt Electric System, the cost to HEA’s members to secure those benefits must be understood before HEA can make a financial commitment to participate in funding the project. For that reason, HEA expects financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) to be critically necessary. Accordingly, HEA commits to working with the other utilities and the State of Alaska to develop a mechanism for funding the “non-federal cost share requirement” of the initiatives. HEA’s funding obligation in this regard will be subject to HEA’s final approval of the grant agreement terms and any necessary or appropriate Board of Directors, regulatory, and/or third-party approvals. HEA supports the RIR proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan. As the application reflects, there exists unprecedented alignment among the Railbelt utilities and the Alaska Energy Authority to create a resilient, reliable Railbelt electric system that would be on a par with the systems currently enjoyed by the rest of the country. HEA is committed to working collaboratively to achieve that end. Sincerely, Bradley P. Janorschke General Manager MATANUSKA ELECTRIC ASSOCIATION, INC. • P.O. Box 2929 • Palmer, Alaska 99645 • t 907.745.3231 • f 907.761.9368 • www.mea.coop April 10, 2024 U.S. Department of Energy Grid Deployment Office 1000 Independence Ave. SW Washington D.C. 20585 RE: Letter of Commitment for Topic Area 3 Grid Innovation Program; Railbelt Innovative Resiliency Project Dear Application Review Committee, Matanuska Electric Association, Inc. (MEA) is pleased to team with the State of Alaska, d/b/a the Alaska Energy Authority, and the other Railbelt electric utilities1 to partner in the funding opportunity for Railbelt Innovative Resiliency Project (RIR) (DE-FOA-0003195). MEA is a not-for-profit, member owned, electric cooperative that serves almost 65,000 meters in the fastest-growing area of Alaska. We operate and maintain nearly 4700 miles of power lines, 26 substations and self-generate the majority of our power. MEA is interconnected to the other Railbelt electric utilities via a single transmission line, the majority of which is the Alaska Intertie – a 170 mile long, 345 kilovolt (kV) transmission line between Willow and Healy that operates at 138 kV. Together, MEA and the other Railbelt electric utilities comprise what is commonly referred to as the Alaska Railbelt Electric System and provides electric service to approximately 75% of Alaska’s population. MEA is supportive of the Railbelt Innovative Resiliency Project proposal and hopes that the proposal receives DOE approval. As a not-for-profit, member owned cooperative, MEA has a fiduciary responsibility to our member-consumers, to ensure that MEA’s resources are used wisely and prudently. As essential as the Railbelt Innovation Resiliency Project is to achieve meaningful, transformative, long-term benefits on the Railbelt Electric System, the cost of achieving those benefits cannot, from a practical perspective, be borne solely by our small number of Railbelt ratepayers. Financial support in the form of Department of Energy funding via the Infrastructure Investment and Jobs Act (IIJA) and the Inflation Reduction Act (IRA) is critically necessary. For that reason, MEA supports the cost allocation methodology outlined in this and other applications being submitted by this project team to the DOE’s Grid Resilience and Innovation Partnerships (GRIP) Program that prioritizes securing Federal IIJA/IRA funds with State of Alaska matching funds for the “non-federal cost share requirement.” If necessary, additional funding will also come from MEA and the other Railbelt electric utilities, subject to successful negotiation of the grant contract and receipt of any necessary Board of Directors, regulatory, and/or third-party approvals required to ensure that costs incurred by the utilities can appropriately be recovered from the Railbelt’s member-consumers. MEA has been diligently working with the other Railbelt electric utilities and with the Alaska Energy Authority to ensure that the opportunities afforded by the DOE IIJA and IRA funding grants, once received, will meaningfully and positively transform the Alaska Railbelt electric system. 1 Chugach Electric Association, Inc., Homer Electric Association, Inc., Golden Valley Electric Association, Inc., and the City of Seward d/b/a Seward Electric System. U.S. Department of Energy Letter of Commitment for Topic Area 3 April 10, 2024 Page 2 MEA fully supports the Railbelt Innovative Resiliency proposal, as well as other aspects of the broader Grid Modernization and Resiliency Plan that has and will be submitted to the DOE under separate applications. As the application reflects, there exists unprecedented alignment amongst the Railbelt utilities and the Alaska Energy Authority to materially transform the Railbelt electric system. We are committed to work collaboratively in order to strengthen and build a smart, clean electrical grid that ensures residents, communities, and the military bases served by the Railbelt electric utilities have access to clean, reliable, low-cost energy. Sincerely, Anthony M. Izzo Chief Executive Officer FY24 58,120,700$ FY25 Gov Amend 60,541,800$ Federal State Other Total FY23 41,024,363$ 38,583,158$ 400,000$ 80,007,521$ FY24 143,715,793$ 49,568,579$ 193,284,372$ FY25 (Gov Amend) & FY24 Supp 284,676,588$ 25,596,279$ 310,272,867$ SSQ Upgrades HVDC GRIP BESS Total FY25 90,000,000$ 20,000,000$ 56,000,000$ 166,000,000$ Alaska Energy Authority Operating Budget Alaska Energy Authority - Capital Budget Alaska Energy Authority - Transmission/BESS Bonds 4/5/2024 24/5/2024 34/5/2024 ALASKA ENERGY AUTHORITY Capital Budget Gov Request- FY2025 4/4/24 1:40 PM Project Name Federal Receipt (Gov) Federal Receipt (Gov Amd) State Funding (Gov) State Funding (Gov Amd) Total Fund Code Grid Resilience and Innovation Partnership Topic 3 - Railbelt Utilities $ 206,500,000 $ 12,700,000 $ 219,200,000 1002 - Fed Receipts /1003 G/F Match IIJA Efficiency Revolving Loan Fund Capitalization - Formula FY2025 $ 252,700 $ - $ 252,700 1002 - Fed Receipts IIJA - Statewide Grid Resilience and Reliability $ 12,110,523 $ 17,627,018 $ 1,816,579 $ 1,816,579 $ 19,443,597 1002 - Fed Receipts / 1003 G/F Match IRA Sec. 60103: Green House Gas Reduction Fund (Solar for All) $ 20,000,000 $ 20,000,000 $ - $ - $ 20,000,000 1002 Fed Receipts IRA Sec. 50123: State Based Energy Efficiency Contractor $ 1,296,870 $ 1,296,870 $ - $ - $ 1,296,870 1002 Fed Receipts Total IIJA/IRA/GRIP Capital Requests: $ 33,407,393 $ 245,676,588 $ 1,816,579 $ 14,516,579 $ 260,193,167 Reapprop Alaska-British Colombia Intertie to Dixon Diversion - Bradley Lake Hydro Power $ 1,379,700 $ 1,379,700 1012 - Railbelt energy Fund UGF Bulk Fuel Upgrades (state dollars are matching funds) $ 11,000,000 $ 11,000,000 $ 2,000,000 $ 2,000,000 $ 13,000,000 1002 - Fed Receipts / 1003 G/F Match Electrical Emergency Response $ - $ - $ 200,000 $ 200,000 $ 200,000 1004 - General Fund Renewable Energy Grant Fund - Round 16 $ - $ - $ 5,000,000 $ 5,000,000 $ 5,000,000 1004 - UGF Rural Power Systems Upgrades (state dollars are matching funds) $ 25,000,000 $ 25,000,000 $ 2,500,000 $ 2,500,000 $ 27,500,000 1002 - Fed Receipts /1003 G/F Match Total $ 69,407,393 $ 281,676,588 $ 11,516,579 $ 25,596,279 $ 307,272,867 * Note: Univerity of AK - $1M for Alaska Energy Data Storage and Revitalization Program p11 FY2024 Supplemental - Request Project Name Federal Receipt Authority (Gov) Federal Receipt (Gov Amd) State Funding (Gov) State Funding (Gov Amd) Total Fund Code Defense Community Infrastructure Pilot Program - Black Rapids Training Site $ - $ 3,000,000 $ - $ - $ 3,000,000 1002 Fed Receipts Total $ - $ 3,000,000 $ - $ - $ 3,000,000 AEA has been selected for a $206.5 million grant from the DOE for a Railbelt Innovative Resiliency Project. A 100% cost share of $206.5 million is required. AEA, the Railbelt utilities, and the RCA are partners in this project as collaborative decision makers representing all primary transmission owners and operators of the Railbelt. A once-in-a-generation opportunity to build resiliency and develop a fuel-diverse, low-carbon economy, by investing in essential electric infrastructure. $20M for Bradley Lake required project work funded by $166M of bonds. Additional request of $252,700 for Federal Receipt Authority necessary to fully fund the project under the SEP program requirements to begin using capitalization grant not more than 180 days after the date on which the grant is received. Request for fund capitalization to REF program for Round 16 of REF projects. FY25 Capital Budget - Request Brief Summary IIJA - Section 40101 (d) - formula grant program to strengthen and modernize America's power grid against wildfire, extreme weather, and other natural disasters. Improve resilience of the electric grid against disruptive events. Funding over five years to total over $60M. IIJA - Competitive application to be submitted September 2023. This project will enable AEA and AHFC to develop programs and deploy rooftop solar panels and community solar arrays to benefit low-income Training for energy audits of commercial and residential buildings. AEA will RSA with AHFC. Bulk fuel tank farm upgrades. Replaces aging tanks that may be leaking. Adds capacity to meet community needs. Meets code compliance standards improving life, health, and safety of community. Critical to rural communities - provides technical support when an electrical utility has lost, or will lose the ability to generate or transmit power. AS42.45.900 Electric utility systems are part of the basic infrastructure of rural communities. New power systems are designed to meet accepted utility standards for safety, reliability, and environmental protections. Brief Summary Extension of an electric power line to the Black Rapids Training Site. AEA partnership with GVEA. No state match is required. GVEA has committed funds to complete the project. Estimates for the preliminary studies for the Dixon Diversion are $12 million. These studies were partially funded by a $5 million appropriation in FY2024. This appropriation will enable engineering and environmental studies to continue during the upcoming field season. 44/5/2024 IIJA, $260,193,167 Dixon Diversion, $1,379,700 Bulk Fuel, $13,000,000 Electrical Emergency Response , $200,000 Renewable Energy Grant Fund Program, $5,000,000 Defense Community Infrastructure Pilot Program, $3,000,000 Rural Power Systems Upgrades , $27,500,000 Alaska Energy Authority FY25 Gov Amend & FY24 Supp Capital Budget - $310,272,867 54/5/2024 FY21 , 12,500,000 FY22 , 25,000,000 FY23 , 41,024,363 FY24 , 143,715,793 FY25 , 284,676,588 FY21 , 5,000,000 FY22 , 15,450,973 FY23 , 38,583,158 FY24 , 49,568,579 FY25 , 25,596,279 - 50,000,000 100,000,000 150,000,000 200,000,000 250,000,000 300,000,000 350,000,000 FY21 FY22 FY23 FY24 FY25 Alaska Energy Authority Total Capital Appropriations FY21 - FY25 Federal State FY21-FY22 increased 131% FY22-FY23 increased 97% FY23-FY24 increased 143% FY24-FY25 increased 61% FY21-FY25 increased 1673% FY25 , 166,000,000 - 50,000,000 100,000,000 150,000,000 200,000,000 250,000,000 300,000,000 350,000,000 FY25 Alaska Energy Authority Transmission/BESS Bonds FY25 RPW Bond FY21-FY25 w/ RPW Bond, increased 2622% 4/5/2024 813 W Northern Lights Blvd, Anchorage, AK 99503  Phone: (907) 771-3000  Fax: (907) 771-3044  Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG TO: Board of Directors, Alaska Energy Authority FROM: Curtis Thayer, Executive Director DATE: April 8, 2024 RE: Negotiated Indirect Cost Rate Agreement for the Alaska Energy Authority On April 4, 2024, the Alaska Energy Authority signed a Negotiated Indirect Cost Rate Agreement (NICRA) between AEA and the federal cognizant agency, Denali Commission, negotiated by the U.S. Department of Interior. A NICRA is a formal written agreement between an organization and its cognizant federal agency. This agreement outlines how the organization will calculate indirect costs. The provisional negotiated indirect cost rate for FY2024 and FY2025 is 31.85%. See attached signed agreement. This is a very significant milestone for AEA and is the first NICRA for the authority. AEA is allowed to recover indirect costs from all of its federal funding agencies at a rate that when applied consistently and in accordance with the agreement will allow for full recovery of federal indirect costs associated with managing and administering federal awards. In the past, AEA utilized a 10% De Minimis rate, allowed for in the absence of an approved negotiated federal indirect cost rate. This resulted in an under recovery of federal reimbursement for indirect costs. As result, AEA’s state operating and capital appropriations funded the majority of AEA’s indirect costs. As an example, AEA’s indirect costs for the fiscal year 2023 were approximately $3 million. The federal recovery during FY2023 was approximately $221,000. The new rate will be negotiated with all future federal applications. This is significant given the amount of federal funding anticipated by AEA through the Infrastructure and Investment Jobs Act, and other large federal opportunities. AEA’s finance team is currently in the process of implementing the provisions of this agreement into accounting policy and procedure. Railbelt Opportunities April 8, 2024 BATTERY ENERGY STORAGE SYSTEMS Enhancing Railbelt Capacity and Resilience Status: Railbelt Region: Southern (Kenai Peninsula) - Completed in 2022 Central (Anchorage)* - Completed in October 2024 Northern (Fairbanks)* - To Be Determined *Potential option for GRIP funding PROJECT SUMMARY Benefits Opportunities ƒImproved oscillation damping ƒEnhanced disturbance response rate ƒIncreased transfer capability between regions ƒLess constrained economic dispatch The Railbelt is transmission constrained so we can only move 10 percent or less of our peak load between regions. Further, Railbelt utility engineers have observed several increasingly concerning trends on the Railbelt over the past decade. These challenges include degradation of frequency regulation, decreasing system frequency response to generation trip disturbances, increasing the magnitude and duration of natural frequency power oscillations, and occasional large power swings impacting the entire Railbelt. Based on studies performed by Railbelt utilities, three regional battery energy storage systems (BESS) units were proposed in each of the Southern, Northern, and Central regions. These units in the three regions would provide significant reliability and economic benefit to the Railbelt transmission system. Additionally, studies found that BESS would help stabilize non-dispatchable renewables’ output by smoothing energy fluctuations and controlling their release to the grid. (Continued on back) PROJECT OVERVIEW ƒReduced fuel burn ƒLower carbon emissions ƒGreater ability to integrate variable generation such as wind and solar power into the grid DRAFT April 8, 2024 813 W Northern Lights Blvd. Anchorage, AK 99503 www.akenergyauthority.org info@akenergyauthority.org T: (907) 771-3000 F: (907) 771-3000 A BESS can successfully fulfill the required energy response to a loss of generation in as quickly as less than one second, improving system frequency. Furthermore, the study showed that a BESS could participate in balancing generation and load, thereby improving frequency regulation. After careful analysis, it has been determined that a BESS and a high-voltage direct current line can significantly enhance system performance and reduce operational limitations in power systems. The proposed integrated BESS will bring benefits to the Railbelt grid. Homer Electric Association in the Southern region has installed a BESS. Chugach Electric Association and Matanuska Electric Association in the Central region are in the process of installing a BESS. Golden Valley Electric Association in Fairbanks is planning a BESS installation. The combined BESS system will be a valuable addition to the Railbelt grid’s power infrastructure. PROJECT OVERVIEW (CONT) BESS CAPACITY 47 MWhs Southern (Kenai Peninsula) 40 MWhs Central (Anchorage) TBD MWhs Northern (Fairbanks) FUNDING PLAN ($MILLIONS) LOCATION AEA BONDS (EXISTING) FUNDING SOURCE TBD Southern (Kenai Peninsula) BESS 7.41 33.00 Central (Anchorage) BESS 39.96 45.00 Northern (Fairbanks) BESS 9.63 33.00 Subtotals 57.00 111.00 Total 168.00 Total Project Cost: Estimate $168 million Secured Sources of Funding Match: $57 million AEA bonds (existing) Potential Sources of Funding: GRIP 3 Round 1 funding if available after HVDC line, Railbelt utilities, tax credits for BESS depending on timing Please note project costs are estimates and are subject to change. BELUGA TO HEALY OVERHEAD HVDC Enhancing Railbelt Reliability and Resilience Status: AEA and Railbelt Utilities were encouraged to apply for DOE’s second round GRIP program. Applications due April 17, 2024. Capacity: 230kV Length: 240 miles Right of Way: Adjacent to the existing AKLNG Right of Way Construction: 6-8 years Cost: $730 Million PROJECT SUMMARY The Railbelt Innovative Resiliency (RIR) Project, Phase 2 is a crucial initiative to build a clean, smart, and affordable grid in Alaska. This project consists of constructing a 240-mile high-voltage direct current (HVDC) overhead transmission line from Beluga (west of Cook Inlet) to Healy. Coupled with the RIR Phase 1 project (Subsea cable from the Kenai Peninsula to Beluga) this will provide a redundant connection between the Bradley Lake Dam and Fairbanks. The Beluga to Healy overhead line will allow northern region customers on the Railbelt to experience the benefits of expanded renewable energy in southcentral Alaska and the southern region to receive power from renewable resources from the northern region. This HVDC line will add critical resilience and redundancy to the Railbelt. Currently, there is only one transmission line, the Alaska Intertie, which transmits power north and south along the Railbelt. The Alaska Intertie is capacity-limited. This HVDC line will provide an alternate route if the Alaska Intertie energy is interrupted by maintenance or failure. (Continued on back) Benefits Opportunities ƒIncreased resilience and redundancy of the Alaska Intertie ƒAdditional conduit for power to transmit between regions ƒReduced line losses ƒAllow additional energy to be delivered to consumers ƒIncreased capacity to bring on utility-scale renewable projects ƒDevelopment of renewable resources in an area of the state that were previously uneconomical due to lack of proximity to transmission PROJECT OVERVIEW DRAFT April 8, 2024 FUNDING PLAN ($MILLIONS) FISCAL YEAR POTENTIAL FEDERAL SHARE SOURCE TBD 2025 9.50 9.50 2026 34.50 34.50 2027 36.50 36.50 2028 74.50 74.50 2029 82.00 82.00 2030 102.00 102.00 2031 26.00 26.00 Subtotals 365.00 365.00 Total 730.00 Total Project Cost: $730 Secured Funding Sources: None Potential Sources of Funding: DOE grant for up to 50 percent of the project cost, Railbelt utilities, state appropriations, revenue bonds AEA is submitting grant application to DOE GRIP 3 Round 2 for $365 million federal share that would require a $365 million match Please note expenditure estimates are preliminary and subject to change. 813 W Northern Lights Blvd. Anchorage, AK 99503 www.akenergyauthority.org info@akenergyauthority.org T: (907) 771-3000 F: (907) 771-3000 PROJECT OVERVIEW (CONT) 2025-2026 Initial Design, Permitting 2026-2027 Engineering, NEPA Process 2027-2031 Construction SCHEDULE PROJECT STATUS In January 2024, AEA and the Railbelt Utilities submitted a concept paper to the Department of Energy (DOE) for the project. In late February, we were encouraged to submit a full application; 50 percent of the concept papers were advanced to the full application phase. The full application is due on April 17, 2024, and we expect notification in early third quarter of this year. The Beluga to Healy Overhead HVDC line is proposed to run along the Alaska Gasline Right of Way, west of the current Alaska Intertie. One of the primary objectives of the RIR is to address various challenges facing the Railbelt grid, which serves 75 percent of Alaska’s population. These challenges include decreasing system frequency regulation, slowing frequency response to disturbances, and increasing natural frequency oscillations. To overcome these challenges, the project emphasizes the need for BESS and new transmission lines between the northern, central and southern regions of the Railbelt. DIXON DIVERSION PROJECT Expanding Alaska’s Largest Hydropower Project Status: Preliminary studies and engineering Dam Modification: 14 ft raise Tunnel: 4.7 miles, 14 ft diameter Annual Energy: 190,800 MWh Natural gas offset: 1.5 to 1.6 bcf/yr Cost: $342 Million PROJECT SUMMARY Benefits Opportunities ƒReduction in Cook Inlet Natural gas demand by 1.5 bcf/yr ƒ190,800 MWh/yr of additional energy (increase Bradley Lake by 50 percent) ƒAdditional stored energy to regulate non-firm renewables ƒPower Sharing Agreements with Railbelt Utilities provide stable long- term returns via revenue stability and market risk mitigation ƒLower long-term energy costs The Dixon Diversion project is a significant expansion of the Alaska Energy Authority (AEA)-owned Bradley Lake Hydroelectric Project (Bradley Lake). The project will convey water from the toe of the Dixon Glacier via a diversion dam and a 4.7-mile- long tunnel into Bradley Lake. Diverted water will flow through the existing hydroelectric power plant connected to the Railbelt. This project also includes modifications to the Bradley Lake Dam to raise the full pool height by 14 feet. The combination of additional water diverted from the Dixon Glacier Basin and additional storage capacity in Bradley Lake will lead to an increase in energy of 190,800 megawatt hours (MWh) annually (over a baseline of ~400,000 MWh/yr). (Continued on back) PROJECT OVERVIEW ƒStorage hydro is dispatchable year- round, allowing utilities to regulate additional renewable resources ƒUtilizing existing Bradley infrastructure allows for development of a huge resource on an extremely small footprint ƒRevenue Bonds ƒClimate Pollution Reduction Grants Funding Options DRAFT April 8, 2024 FISCAL YEAR FUNDING SOURCE TBD 2024 7.00 2025 7.00 2026 14.00 2027 305.00 2028 3.00 2029 3.00 2030 3.00 Total 342.00 813 W Northern Lights Blvd. Anchorage, AK 99503 PROJECT STATUS AEA continues to assess the Dixon Diversion project, which would fortify Alaska’s energy security by increasing overall renewable generation and mitigating exposure to fuel price volatility and supply-side disruptions. The project could be operational by the end of the decade and will offset the equivalent of approximately 1.5 to 1.6 billion cubic feet (bcf) per year of natural gas consumed for electricity production. An offset of this magnitude is equal to about 7.5 percent of the Railbelt’s unmet natural gas demand projected for 2030. Hydroelectric power is cheap and reliable energy that will lower the cost of electricity for all Railbelt consumers (75 percent of Alaska’s population), and indirectly lower the cost of energy for Power Cost Equalization (PCE) recipients. The storage component of this project allows Railbelt utilities to reliably dispatch renewable power year-round. www.akenergyauthority.org info@akenergyauthority.org T: (907) 771-3000 F: (907) 771-3000 This would equate to an approximately 50 percent increase in energy from Bradley Lake , which currently supplies ~10 percent of the Railbelt’s electric demand. By utilizing existing infrastructure, this large renewable resource can be developed with a very small footprint. The Dixon Diversion project will construct only one mile of new road, utilize less than five acres for the diversion dam, convey water through an underground tunnel, and inundate less than 200 acres of land from higher lake levels. 2024-2025 Studies 2026-2027 Licensing 2027-2030 Construction SCHEDULE PROJECT OVERVIEW (CONT) FUNDING PLAN ($MILLIONS) Total Project Cost: $342 million Potential Sources of Funding: United States Environmental Protection Agency Climate Pollution Reduction Grant (award selections expected July 2024), Revenue bonds, Railbelt utilities, tax credits depending on timing and eligibility April 8, 2024 DRAFT ROADBELT INTERTIE PROJECT Enhancing Railbelt Reliability and Resilience Status: Conceptual Capacity: 230kV Length: 388 miles Right of Way: Near existing roads Construction: 6-8 years Cost: $566 Million (2020$) PROJECT SUMMARY The Roadbelt Intertie Project would construct a new 230 kilovolt (kV) transmission line from Sutton to Glennallen (135 miles) to Tok (142 miles) to Delta Junction (111 miles), interconnecting island road system power utilities and creating a parallel path between the two most populated roadbelt areas. Alternative utility interconnection configurations with 230 kV lines between Glennallen and Delta Junction and a smaller 138 kV radial line to Tok from either Glennallen or Delta Junction are possible. Eastern interior has undeveloped hydroelectric, wind, and solar resources that could be developed if a larger market (Railbelt region) was interconnected. The Roadbelt Intertie Project line would provide a conduit of at least 75 megawatts firm power from the Central load region of Anchorage and the Matanuska Valley to the eastern interior communities and the Northern load center of Fairbanks. The Roadbelt Intertie allows additional communities to share the benefits of expanded hydroelectric, wind, and solar renewable energy in Southern, Central, and Northern Regions. (Continued on back) Benefits Opportunities ƒIncreased resilience and redundancy of the Alaska Intertie ƒAdditional conduit for power to transmit between regions ƒReduced line losses ƒAllow additional energy to be delivered to consumers ƒIncreased capacity to bring on utility-scale renewable projects ƒDevelopment of renewable resources in an area of the state that were previously uneconomical due to lack of proximity to transmission PROJECT OVERVIEW 2024-TBD 813 W Northern Lights Blvd. Anchorage, AK 99503 www.akenergyauthority.org info@akenergyauthority.org T: (907) 771-3000 F: (907) 771-3000 PROJECT OVERVIEW (CONT) AEA provides energy solutions to meet the unique needs of Alaska’s rural and urban communities. Established by the Alaska Legislature in 1976, its mission is to reduce the cost of energy throughout Alaska. As Alaska’s lead agency for statewide energy policy and program development, AEA collaborates with utilities, private companies, legislators, local governments, and Alaskan energy innovators to diversify the state’s energy portfolio increasing resiliency, reliability, and redundancy. AEA OVERVIEW BUDGET Natural gas energy will replace diesel energy during periods of low renewable energy. This line will add critical resilience and redundancy to Railbelt transmission. There is only one transmission line, the Alaska Intertie, which transmits power north and south along the Railbelt. The Roadbelt Intertie is capacity-limited. This line would provide an alternate route if Intertie energy is interrupted by maintenance or failure. PROJECT STATUS The Roadbelt Intertie Project is conceptually designed and cost estimated. SSQ TRANSMISSION UPGRADE Enhancing Railbelt Capacity and Resilience Ownership: AEA Owned Status: Constuction Capacity: 230kV (Currently operating at 115kV) Length: 54 miles Right of Way (ROW): Utilizing existing SSQ ROW Construction: 2024-2028 Cost: $90 Million PROJECT SUMMARY The Soldotna Substation to Quartz Creek (SSQ) Substation transmission line plays a vital role in Alaska’s Railbelt electric grid, which serves over 75 percent of the state’s population. About 87 percent of the energy from Bradley Lake Hydroelectric Project (Bradley Lake) crosses this section going to the central and northern utilities. The 115 kilovolt (kV) transmission line is 50 years old and will require replacement as many of the support structures are approaching the end of their useful life. This section represents some of the highest line loss per mile of Bradley Lake energy. The upgrade will size the conductor, insulators, and poles/towers to 230 kV standards. A fiber-optic communication line will also be installed along the route. (Continued on back) PROJECT OVERVIEW Benefits Opportunities ƒReduced line losses ƒGreater secure communication and control of system ƒIncreased resilience to wildfires and other unplanned events ƒAllows for development of new renewable energy projects on the Kenai Peninsula by eliminating capacity constraints along Railbelt ƒAdditional capacity for increasing energy during peak periods DRAFT April 8, 2024 FISCAL YEAR FUNDING SOURCE 2024 25.00 2025 2.00 2026 30.00 2027 30.00 2028 3.00 Total 90.00 FUNDING PLAN ($MILLIONS) Total Project Cost: $90 million (secured) Secured Sources of Funding: $90 million AEA bonds (existing) Once all transmission lines have been upgraded from Anchorage to Soldotna then transformers will be upgraded to 230 kV and the line will operate at 230 kV. Because of constraints on how long the transmission line can be out-of- service and the various land ownerships the line crosses, the effort has been divided into four projects, each with an independent utility. The projects are as follows: ƒProject 1: Sterling Substation to Kenai National Wildlife Refuge (8 miles) ƒProject 2: Kenai National Wildlife Refuge (17 miles) ƒProject 3: Kenai National Wildlife Refuge and Chugach National Forest to Cooper Creek (9 miles) ƒProject 4: Cooper Creek to Quartz Creek Substation (5 miles) The project schedule is based on outage constraints, permitting, and seasonal construction. The project’s schedule is subject to change based the above criteria. The majority of work is over wetlands and can only occur during the late winter months. Outages cannot occur concurrently with other transmission projects because that would island communities from power and prevent Bradley power from moving north during critical periods. Projects 1 through 4 are shown above from left to right. 813 W Northern Lights Blvd. Anchorage, AK 99503 Project 1 Q1 2025 PROJECT OVERVIEW (CONT) www.akenergyauthority.org info@akenergyauthority.org T: (907) 771-3000 F: (907) 771-3000 Project 2 Q1 2027 Project 3 Q1 2028 SCHEDULE Project 4 Q1 2025 SUBMARINE HVDC LINE & BESS* Improving Railbelt Resiliency and Transfer Capacity Status: In grant negotiations with DOE; anticipated award Q2 2024. Scope: Subsea HVDC Line between the Kenai Peninsula and Beluga with AC/DC converters. 2 BESS Units: Central (Anchorage & Mat-Su) and Northern (Fairbanks) Cost: $413 Million *BESS, if feasible, after HVDC. PROJECT SUMMARY The Alaska Energy Authority (AEA), in collaboration with the Railbelt utilities, has been selected for a $206.5 million grant from the Department of Energy (DOE) through the Grid Resilience and Innovation Partnerships (GRIP) Program. The grant requires a dollar-for-dollar match and will fund the construction of a high-voltage direct current (HVDC) subsea line across Cook Inlet from the Kenai Peninsula to the Beluga substation to connect the converter station with Soldotna. Two converter stations will be constructed at the terminal ends of the HVDC line, to convert alternating current to direct current, and vice versa at the other end. In addition, if feasible, build a battery energy storage system (BESS) in Fairbanks and expand the Anchorage BESS. Benefits Opportunities ƒAdds redundancy along the Railbelt by creating an alternate path for generation to flow north and south along Railbelt ƒDecreased line loss will contribute to lower energy prices ƒIncreases resilience of the grid (BESS able to support load for a couple hours) ƒReduction of natural gas generators spinning ƒPotential for development of renewable resources in an area of the state that were previously uneconomical due to lack of proximity to transmission ƒBESS will enhance resiliency and eliminate small signal instability events and increase frequency control ƒIncreases effectiveness of additional renewable resources PROJECT OVERVIEW DRAFT April 8, 2024 2025 $64 Million 2026 $63 Million DRAFT BUDGET 2027 $18 Million 2028 $54 Million 2029 $120 Million 2030 $62 Million 2031 $32 Million Total $413 Million 813 W Northern Lights Blvd. Anchorage, AK 99503 This project is expected to take eight years to complete (including design, permitting, and construction) and will provide an alternative path between the Central and Southern regions of the Railbelt, increasing transfer capability and improving resilience along the Railbelt. The addition of an alternative path of electricity will also relieve the burden of the existing capacity-constrained transmission lines which enables the construction of additional renewable resources on the Kenai Peninsula and reduces the occurrence of transmission disruptions during maintenance or construction activities on the existing line. As Alaska’s grid brings on more renewable resources, the incorporation of BESSs are vital for utilities to regulate and manage the energy load. Many renewable resources, such as solar and wind, are non-firm (unpredictable) sources of energy that may not provide power to the grid when required. BESS’s increase resiliency and allow utilities to store renewable energy and deploy at a later time to follow the natural demands of the grid. PROJECT STATUS www.akenergyauthority.org info@akenergyauthority.org T: (907) 771-3000 F: (907) 771-3000 FUNDING PLAN ($MILLIONS) FISCAL YEAR FEDERAL SHARE STATE FUNDS OR SOURCE TBD EXISTING AEA REVENUE BONDS 2025 32.70 12.70 20.00 2026 31.50 6.50 25.00 2027 8.80 8.80 - 2028 26.80 21.80 5.00 2029 60.00 60.00 - 2030 30.95 30.95 - 2031 15.75 15.75 - Subtotals 206.50 156.50 50.00 Total 413.00 Total Project Cost: $413 million ($206.5 million federal share and $206.5 million match) Secured Sources for Match: $20 million AEA bonds (existing) and $12.7 million FY2025 appropriation *Other Sources for Match: Potentially $30 million from AEA bonds (existing) for BESS depending on timing, Railbelt utilities, additional state appropriations, tax credits, and bond convenants * * AEA Infrastructure Funding Opportunities Note: New information is in bold font in cells highlighted yellow Page 1 of 2 last updated 4/3/2024 %$ Awarded Defense Community Infrastructure Pilot - National Defense Authorization Act Black Rapids Training Site $ 12,602,648 0%$0 AEA partnered with GVEA for Black Rapids Training Site. Requesting additional $3M in federal receipt authority in FY24 supplemental budget for a total of $15.6M. Awarded Energy Efficiency and Conservation Block Grant - IIJA 40552b $ 1,627,450 0%$0 Solicitation for RE-VEEP subawards Round 1 closed 2/27/24. Round 2 closes 5/28/24. Awarded High Energy Cost Grants - USDA RUS $ 2,000,000 0%$0 AEA awarded grant for Manokotak. Awarded National Electric Vehicle Infrastructure Program (NEVI) FFY 22-24 - IIJA 11401 $ 30,086,630 20%$6,017,326 AEA partnered with DOT, DOT responsible for receipt authority. Total funding expected is $52M. Awarded Preventing Outages and Enhancing the Resilience of the Electric Grid, Formula Grants to States and Indian Tribes FFY 2022-2023 - IIJA 40101d $ 24,221,046 15%$3,633,157 Additional formula funding expected over the next 3 years, listed as conditional award. AEA has receipt authority for $24.2M federal award and $5.4M match. Solicitation for subawards closed 2/16/24. Awarded State Energy Program Funding - IIJA 40109 $ 3,661,930 0%$0 AEA applicant. Funding split 70% AEA and 30% AHFC. Awarded Vehicle Technology Office FFY 2022 $ 1,670,000 20%$417,500 Match to be provided by site partners. $85,937,687 $ 75,869,704 $10,067,983 Conditional Award Defense Community Infrastructure Pilot - National Defense Authorization Act - Black Rapids Training Site additional $3 million $ 3,000,000 0%$0 AEA lead applicant partnered with GVEA. Requesting additional $3M in federal receipt authority in FY24 supplemental budget for a total of $15.6M. Conditional Award Energy Efficiency Revolving Loan Capitalization Program - IIJA 40502 $ 4,782,480 0%$0 AEA resubmitted application 11/1/23. Requested additional $240k in federal receipt authority in FY24 supplemental budget. AEA and AHFC are partners. Conditional Award Energy Future Grant $ 496,725 0%$0 AEA partnered with AML for proposal to evaluate energy permitting in 45 municipalities. Application was selected for award pending negotiations. Conditional Award Grid Resilience and Innovation Partnerships Program Topic 3 - IIJA 40103b $ 206,500,000 100%$206,500,000 AEA notified by DOE for negotiation of financial assistance award in the amount of $206.5M. 100% match required or $206.5M, funding source unknown. Conditional Award Home Efficiency Rebates (formula funding) - IRA 50121 $ 37,368,480 0%$0 AEA applicant as State Energy Office. AHFC administer the program. Application due 1/31/25. Conditional Award Home Electrification and Appliance Rebates (formula funding) - IRA 50122 $ 37,150,940 0%$0 AEA applicant as State Energy Office. AHFC administer the program. Application due 1/31/25. Conditional Award National Electric Vehicle Infrastructure Program (NEVI) FFY 25-26 - IIJA 11401 $ 22,328,390 20%$4,465,678 Program is formula funding that DOT will apply for as the allocation for each fiscal year is released. Conditional Award Preventing Outages and Enhancing the Resilience of the Electric Grid, Formula Grants to States and Indian Tribes FFY 2024-2026 - IIJA 40101d (formula funding) $ 41,848,064 15%$6,277,210 Formula funding that AEA will apply for as the allocation for each year is released. AEA has receipt authority for $5.4M of match and needs authority for remaining match of $4.2. FFY24 application deadline is 4/17/24, State allocation for FFY24 is $17,627,018. Conditional Award Training for Residential Energy Contractors (TREC) (formula funding) - IRA 50123 (Previously known as Energy Auditor Contractor Training Program) $ 1,293,870 0%$0 AEA applicant as State Energy Office. AHFC to administer the program. AEA submitted the application on 1/30/24. $572,011,837 $ 354,768,949 $ 217,242,888 AK Funding Award / Request Comments Required Match Status GO Federal Receipt Authority Grant Program Name Total Awarded: Total Conditional Award: AEA Infrastructure Funding Opportunities Note: New information is in bold font in cells highlighted yellow Page 2 of 2 last updated 4/3/2024 %$ AK Funding Award / Request Comments Required Match Status GO Federal Receipt Authority Grant Program Name Pending Clean Energy Innovator Fellowship Program NA NA NA AEA submitted 2 host applications on 3/1/24. Pending Climate Pollution Reduction Grants Competition - Dixon Diversion Measure - IRA 60114 $ 348,415,151 0%$0 AEA submitted application March 29, 2024. Pending Climate Pollution Reduction Grants Competition - Rural Energy Programs- IRA 60114 $ 49,986,112 0%$0 AEA submitted application March 29, 2024. AEA lead applicant of coalition with Northwest Arctic Borough and Tanana Chiefs Conference. Pending Energy Auditor Training Program - IIJA 40503 $ 2,000,000 0%$0 AEA will submit 2 concept papers by due date of 4/12/24. AEA would administer commercial program and AHFC would administer residential program. Pending Greenhouse Gas Reduction Fund - Solar For All Competition - IRA 134a $ 100,000,000 0%$0 AEA/AHFC partners. Application Submitted 10/11/2023. Pending Grid Resilience and Innovation Partnerships Program Topic 3 - IIJA 40103b $ 365,000,000 100% $ 365,000,000 AEA will submit applicant before deadline of April 17, 2024. Pending Waste to Energy Technical Assistance for State, Local Governments and Tribal Governments NA 0% NA Application due 4/15/24. AEA will submit an application for 40 hours of technical assistance. Pending Wood Innovations Grant Program FFY 2024 - IRA 23002 $ 500,000 100%$500,000 Application submitted. $1,231,401,263 $ 865,901,263 $ 365,500,000 Considering Clean Heavy Duty Vehicles - IRA 60101 NA TBD TBD Funding opportunity not issued at this time. Considering Clean Ports Program - IRA 60102 NA 0-20%TBD Application due May 28, 2024. Considering Defense Community Infrastructure Pilot - National Defense Authorization Act NA TBD TBD Application deadline June 17, 2024. AEA considering re- submitting application for Eielson upgrades with partner GVEA, $10.2 million grant request. Considering Energy Improvements in Remote and Rural Areas FY24-FY26 - IIJA 40103c NA TBD TBD Funding for FY 2024 - 2026 not open at this time. Considering MARAD Port Infrastructure Development Grant - IIJA Title VIII NA 20%TBD AEA interested in partnering with DOT to apply for barge landing and fuel header in Scammon Bay. Application due May 10, 2024. Considering Transmission Siting & Economic Development Grants Program - IRA 50152 NA 5- 100%TBD AEA and AML submitted a concept as partners for economic development in Round 1 but need to confirm HVDC line eligibility. AEA will resubmit for Round 2 deadline expected in August 2024. Considering Watersmart Grants: Water and Energy Efficiency Grants for FY2024 & 2025 Bureau of Reclamation Opportunity No. R24AS00052 NA 100%TBD Application Period 2 deadline 10/30/24. AEA may apply for part of Dixon Diversion Project. NA TBDTotal Considering: Total Pending: 813 W Northern Lights Blvd, Anchorage, AK 99503  Phone: (907) 771-3000  Fax: (907) 771-3044  Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG RAILBELT INNOVATIVE RESILIENCY PROJECT HVDC Submarine Cable and BESS April 17, 2024 813 W Northern Lights Blvd, Anchorage, AK 99503  Phone: (907) 771-3000  Fax: (907) 771-3044  Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG RGYAUTHORITY.ORG MEMORANDUM DATE: April 8, 2024 TO: Curtis Thayer, Executive Director FROM: James Mendenhall, Program Manager SUBJECT: Railbelt Innovation and Resiliency Project, Phase 1 - Dates and Milestones HVDC Subsea Cable and Battery Energy Storage Systems Project: Target Completion: Action: Week of April 8, 2024 AEA submits Statement of Project Objective (SOPO) and Budget Justification to Department of Energy (DOE) April 30, 2024 Finish negotiations with DOE (i.e. finalize SOPO, Budget, National Environmental Policy Act (NEPA) Compliance, Intellectual Property (IP)) Week of May 13, 2024 Final Technical Package and program approvals. Week of June 3, 2024 Procurement finishes DRAFT Award package July 26, 2024 (no later than) AEA completes:  Internal review and approval  AEA Board review and approval (Special Meeting)  Notification of Office of Management and Budget  Notification of Congressional Delegation September 30, 2024 (no later than) Project Award complete. 813 W Northern Lights Blvd, Anchorage, AK 99503  Phone: (907) 771-3000  Fax: (907) 771-3044  Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG RAILBELT INNOVATIVE RESILIENCY PROJECT HVDC Submarine Cable and BESS Table of Contents Page 1. Grid Resilience Innovation Partnership ...................................................................................................... 1 2. Funding Opportunity Announcement ........................................................................................................ 7 3. Railbelt Innovation Resiliency Project (CONCEPT PAPER) ............................................................. 149 4. DOE Notification of Selection of Concept Paper .............................................................................. 171 5. Application ...................................................................................................................................................... 173 6. DOE Notification of Selection of Application ..................................................................................... 299 7. AEA Questions for Department of Energy ......................................................................................... 305 8. Contract Terms and Conditions (SAMPLE ONLY) ............................................................................. 309 9. Alaska Energy Authority Budget Justification (BUDGET PERIOD 1) ........................................... 345 10. Project Schedule (Preliminary) ................................................................................................................. 361 11. Project Management Plan Template ..................................................................................................... 363 12. Statement of Project Objectives (DRAFT) ............................................................................................ 383 13. Community Benefits Outcomes and Objectives (DRAFT) .............................................................. 391 14. National Environmental Policy Act (DRAFT) ....................................................................................... 399 15. Cybersecurity Plan December 2024 (CONFIDENTIAL) .................................................................... 401 16. Project Funding Plan .................................................................................................................................... 405 17. Future Initial Award Notice (in progress) 18. Contract Terms and Conditions (in progress) 19. Project Budget (in progress) 20. Project Schedule (in progress) Grid Resilience Innovation Partnership  Task and Purpose AcƟon Item: Support State investment in the Grid Resilience Innovation Partnership (GRIP) Project.  Background: The Railbelt electric transmission system is an electric transmission system comprised of interconnected transmission infrastructure assets owned by four independent member- owned electric cooperatives1; one municipal electric utility2; and the State-owned Alaska Intertie and Bradley Lake Hydroelectric Project (“Bradley Lake”) transmission assets. This transmission system serves over 75 percent of Alaska’s population and spans a distance of over 700 miles from the Bradley Lake near Homer, Alaska at its southernmost point, to Delta Junction in interior Alaska at its northernmost point.  At present, the Railbelt transmission system is in effect, a single transmission line. The costs of such a lack in reliability and redundancy was evidenced with the Swan Lake Fire in 2019. This event caused prevented load centers north of the incident (Anchorage, Matanuska Susitna Valley, and Fairbanks area) from drawing on low-cost hydroelectric power from the Bradley Lake Hydroelectric facility. A future event could prevent Anchorage area sharing energy with Fairbanks or Kenai areas. Ability to share energy between areas are especially important during the winter months.  In 2023, AEA, representing the State of Alaska, in association with the Regulatory Commission of Alaska (RCA), and five electric utilities that make up the Railbelt electric grid assembled a team that applied for and were successful in securing a highly competitive $206.5 million grant from the U.S. Department of Energy to assist in financing a sub-sea high-voltage direct-current (“HVDC”) transmission line which would serve to provide a redundant pathway for the transmission of energy off the Kenai Peninsula to the Central region, and the procurement and installation of multiple battery energy storage systems (“BESS”). The total cost of the project is expected to be $413 million.  Value ProposiƟon: Provides for redundancy between the southern and central regions. HVDC transmission line will significantly increase the ability to share power between the South, Central, and North load centers. The most economic power can be used at all times. Expanded capacity will enable new renewable energy projects to be constructed and deliver power to other load centers. BESS assets will provide for increased efficiency of existing and future intermittent low-cost renewable energy generation units with their ability to store renewable 1 The four member‐owned electric cooperaƟves are: Chugach Electric AssociaƟon, Inc.; Golden Valley Electric  AssociaƟon, Inc.; Homer Electric AssociaƟon, Inc.; and Matanuska Electric AssociaƟon, Inc.  2 Municipal UƟlity: City of Seward d.b.a. Seward Electric System   1 energy and transmit such energy for times when it would be needed, optimizing economic energy generation.  BESS will reduce generation and operational costs for the Railbelt utilities, by reducing the need (and fuel) to provide spinning reserve. Long term lower energy costs on the Railbelt and lower rural energy costs through Power Cost EqualizaƟon (PCE). How we get there (Roadmap): AEA is currently performing due diligence of a potential award from the Department of Energy (DOE).   AEA is providing various required documents to DOE.  Once commitment of the State provided then  AEA will receive the award.    The term for  the project is eight years from the time of the award which is not very much time.  Thus,  AEA is working on lining up engineering and environmental contractors to assist in the design and  permitting of the project.  The main project components include:  Sub-sea HVDC transmission cable from the Kenai Peninsula under Cook Inlet to Beluga Power Plant. BESS Central region BESS Northern region Project Schedule 2024‐2025 – Preliminary Design, revised cost estimate, and outreach. 2025‐2027 – Design and permitting Licensing o Outreach o An Environmental Analysis (EA) or Environmental Impact Statement (EIS) will need to be prepared. o Order long lead items. o Acquire site control. 2028‐2031 – Construction o Many items will need to be ordered several years prior to construction. Project Economics: Total  cost: $413 million Indirect benefits are substanƟal such as sharing of lowest cost energy, sharing of energy during shortages, allowing new generaƟon to connect to the grid. Future gas cost increases will only enhance project economics. 2 Benefit of sharing of energy between regions in winter to prevent power outages in sub‐ zero weather are substanƟal but hard to quanƟfy. Project Funding  Funds requested from the Alaska Legislature in FY25 to provide commitment to DOE and fund engineering and environmental contractors to start design and permitting. See Funding Plan. 33 4 5 6 Page 1 of 142 FINANCIAL ASSISTANCE FUNDING OPPORTUNITY ANNOUNCEMENT Department of Energy (DOE) Grid Deployment Office (GDO) Office of Clean Energy Demonstrations (OCED) BIL – Grid Resilience and Innovation Partnerships (GRIP) Funding Opportunity Announcement (FOA) Number: DE-FOA-0002740 FOA Type: Amendment 000007 Assistance Listing Number: 81.254 FOA Amendment 000007 Issue Date:04/11/2023 1st Informational Webinar:11/29/2022 2:00pm ET 2nd Informational Webinar:02/08/2023 2:00pm ET 3rd Informational Webinar 02/27/2023 1:00pm ET 4th Informational Webinar 02/28/2023 1:00pm ET Additional Webinars To Be Announced* Submission Deadline for Concept Papers (Topic Area 1):12/16/2022 5:00pm ET Submission Deadline for Concept Papers (Topic Area 2):12/16/2022 5:00pm ET Submission Deadline for Concept Papers (Topic Area 3):01/13/2023 5:00pm ET Submission Deadline for Full Applications (Topic Area 1):04/06/2023 5:00pm ET Submission Deadline for Full Applications (Topic Area 2):03/17/2023 5:00pm ET Submission Deadline for Full Applications (Topic Area 3):05/19/2023 5:00pm ET Expected Date for DOE Selection Notifications (Topic Area 1):Summer 2023 Expected Date for DOE Selection Notifications (Topic Area 2):Summer 2023 Expected Date for DOE Selection Notifications (Topic Area 3):Fall 2023 Expected Timeframe for Award Negotiations (Topic Area 1):Fall 2023 Expected Timeframe for Award Negotiations (Topic Area 2):Fall 2023 Expected Timeframe for Award Negotiations (Topic Area 3):Winter 2023 7 Page 2 of 142 Applicants must submit a Concept Paper by 5:00pm ET on the due date listed above to be eligible to submit a Full Application. *See Section VIII.P for more information on additional webinar(s). To apply to this FOA, applicants must register with and submit application materials through Grants.gov at https://www.grants.gov/. Applicants must designate primary and backup points-of-contact with whom DOE will communicate to conduct award negotiations. If an application is selected for award negotiations, it is not a commitment to issue an award. It is imperative that the applicant/selectee be responsive during award negotiations and meet negotiation deadlines. Failure to do so may result in cancelation of further award negotiations and rescission of the selection. 8 Page 3 of 142 Registration Requirements There are several one-time actions that must be completed before submitting an application in response to this Funding Opportunity Announcement (FOA) (e.g., register with the System for Award Management (SAM), obtain a Unique Entity Identifier (UEI) number, register with Grants.gov, and register with FedConnect.net to submit questions). It is vital that applicants address these items as soon as possible. Some may take several weeks, and failure to complete them could interfere with an applicant’s ability to apply to this FOA. SAM – Applicants must register with SAM at https://www.sam.gov/ prior to submitting an application in response to this FOA. Designating an Electronic Business Point of Contact (EBiz POC) and obtaining a special password called an MPIN are important steps in SAM registration. Failure to register with SAM will prevent your organization from applying through Grants.gov. The applicant must maintain an active SAM registration with current information at all times during which it has an active Federal award or application under consideration. More information about SAM registration for applicants is found at: https://www.fsd.gov/gsafsd_sp?id=gsafsd_kb_articles&sys_id=650d493e1bab7c105465 eaccac4bcbcb . NOTE: If clicking the SAM links do not work, please copy and paste the link into your browser. Due to the high demand of SAM registrations and UEI requests, entity legal business name and address validations are taking longer than expected to process. Entities should start the SAM and UEI registration process as soon as possible. If entities have technical difficulties with the SAM registration or UEI validation process they should utilize the HELP feature on SAM.gov. SAM.gov will work entity service tickets in the order in which they are received and asks that entities not create multiple service tickets for the same request or technical issue. Additional entity validation resources can be found here: GSAFSD Tier 0 Knowledge Base - Validating your Entity. UEI – Applicants must obtain an UEI from the SAM to uniquely identify the entity. The UEI is available in the SAM entity registration record. NOTE: Subawardees/subrecipients at all tiers must also obtain an UEI from the SAM and provide the UEI to the Prime Recipient before the subaward can be issued. Grants.gov – Applicants must register with Grants.gov and set up your WorkSpace. You cannot submit an application through Grants.gov unless you are registered. Please read the registration requirements carefully and start the process immediately. 1) The Authorized Organizational Representative (AOR) must register at: https://apply07.grants.gov/apply/OrcRegister . 9 Page 4 of 142 2) An email is sent to the E-Business (E-Biz) POC listed in SAM. The E-Biz POC must approve the AOR registration using their MPIN from their SAM registration. More information about the registration steps for Grants.gov is provided at: https://www.grants.gov/web/grants/applicants/registration.html. In addition: o Add a Profile to a Grants.gov Account: A profile in Grants.gov corresponds to a single applicant organization the user represents (i.e., an applicant) or an individual applicant. If you work for or consult with multiple organizations and have a profile for each, you may log in to one Grants.gov account to access all of your grant applications. To add an organizational profile to your Grants.gov account, enter the UEI for the organization in the UEI field while adding a profile. For more detailed instructions about creating a profile on Grants.gov, refer to: https://www.grants.gov/web/grants/applicants/registration/add-profile.html . o EBiz POC Authorized Profile Roles: After you register with Grants.gov and create an Organization Applicant Profile, the organization applicant's request for Grants.gov roles and access is sent to the EBiz POC. The EBiz POC will then log in to Grants.gov and authorize the appropriate roles, which may include the AOR role, thereby giving you permission to complete and submit applications on behalf of the organization. You will be able to submit your application online any time after you have been assigned the AOR role. NOTE: When applications are submitted through Grants.gov, the name of the organization applicant with the AOR role that submitted the application is inserted into the signature line of the application, serving as the electronic signature. The EBiz POC must authorize people who are able to make legally binding commitments on behalf of the organization as a user with the AOR role; this step is often missed and it is crucial for valid and timely submissions. For more detailed instructions about creating a profile on Grants.gov, refer to: https://www.grants.gov/web/grants/applicants/registration/authorize- roles.html . To track your role request, refer to: https://www.grants.gov/web/grants/applicants/registration/track-role- status.html . Questions relating to the registration process, system requirements, or how an application form works must be directed to Grants.gov at 1-800-518-4726 or support@grants.gov. 10 Page 5 of 142 FedConnect.net – Applicants must register with FedConnect to submit questions. FedConnect website: https://www.fedconnect.net/ All questions and answers related to this FOA will be posted on the FedConnect portal at: https://www.FedConnect.net and on the Grid Resilience and Innovation Partnerships (GRIP) Program web page at: Grid Resilience Innovation Partnership Programs | Department of Energy. See Section IV for Application and Submission Information (including how to create a WorkSpace). 11 Page 6 of 142 Amendments Amend. No.Date Description of Amendment 000001 11/18/2022 This Amendment is to issue the initial version of the FOA. This version (Amendment 00001) supersedes the previous draft version that was released for public comment (the Draft). The Draft version is now obsolete. Applicants are advised to use Amendment 00001 to prepare the concept paper and full application. 000002 11/29/2022 This Amendment is to revise Section IV.D.xvi to replace the hyperlink to the Community Benefits Plan Scoring Rubric; to remove a reference to program-specific Community Benefits Plan Guidance; and to move the instructions for submitting the Community Benefits Plan to the end of the section. Text that is revised or newly incorporated with this amendment is highlighted in yellow. 000003 12/13/2022 This Amendment revises the following sections: the Registration Requirements section and Section VII to include the GRIP web page as an additional resource for Applicants to view FOA questions and answers. Section I.B.ii to include the GRIP web page as an additional resource for Applicants to view the Teaming Partner List and any updates to it. Section II.A.ii to include additional funding information, including plans for issuing the second competitive funding opportunity for GRIP in Fiscal Year 2024. Section IV.A. and IV.C. to clarify concept paper submission information. Text that is revised or newly incorporated with this amendment is highlighted in yellow. 000004 02/06/2023 The Amendment revises the following: The FOA Cover Page and Section VIII.P to notify applicants that additional informational webinars are planned. Please see Section VIII.P for additional webinar information. Section I.B and I.C to reflect that for Topic Area 1, new distribution lines below 69 kV, reconductoring, undergrounding and other upgrades to existing transmission infrastructure are considered eligible; and applications that include new transmission lines at or 12 Page 7 of 142 above 69 kV are not of interest. A correction to Footnote 40 was also made in this section. Section IV.D.xvi to remove the hyperlink to the Community Benefits Plan Scoring Rubric. The Community Benefits Plan Scoring Rubric will no longer be available. Section IV.D.xx to correctly reflect the reference to the Project Description and Assurances Document Template (PDAD) template as Appendix F. Text that is revised or newly incorporated with this amendment is highlighted in yellow. 000005 02/23/2023 The Amendment revises the following: The FOA Cover Page and Section VIII.P to notify applicants that additional informational webinars are scheduled. Please see Section VIII.P for additional webinar information. Section II.A.ii to correct the anticipated length of the period of performance. Section IV.D.xx to add the text of the “Locations of Work” full application content requirement. The Locations of Work template is now available as an attachment to this announcement for use. Text that is revised or newly incorporated with this amendment is highlighted in yellow. 000006 03/20/2023 The purpose of this Amendment is to re-open the FOA to accommodate the submission of full applications to Topic Area 1 and Topic Area 3 only. See the FOA Cover Page for Application Due Dates and Times. Please note, the application period for Topic Area 2 is closed. There are no changes being made to the FOA document as a result of this amendment. 000007 04/11/2023 The purpose of this Amendment is to re-open the FOA to accommodate the submission of full applications to Topic Area 3 only. See the FOA Cover Page for Application Due Dates and Times. Please note, the application period is now closed for Topic Area 1 and Topic Area 2. This amendment also revises Section VII to increase the number of days for which questions and comments concerning this FOA shall be submitted, from 3 business days to not later than 5 13 Page 8 of 142 business days, prior to the application due date for Topic Area 3. Text that is revised or newly incorporated with this amendment is highlighted in yellow. 14 Page 9 of 142 Table of Contents Table of Contents.................................................................................................................................................8 I. Funding Opportunity Description...............................................................................................................12 A. Background and Context...............................................................................................................................12 i. Program Purpose......................................................................................................................................13 ii. Strategic Goals..........................................................................................................................................15 iii. Community Benefits Plan: Job Quality and Equity...................................................................................17 B. Topic Areas....................................................................................................................................................20 i. Topic Areas...............................................................................................................................................20 ii. Teaming Partner List.................................................................................................................................36 C. Applications Specifically Not of Interest .......................................................................................................37 D. Authorizing Statutes......................................................................................................................................37 E. Notice of Bipartisan Infrastructure Law-Specific Requirements...................................................................37 II. Award Information....................................................................................................................................38 A. Award Overview............................................................................................................................................38 i. Estimated Funding....................................................................................................................................38 ii. Period of Performance.............................................................................................................................40 iii. New Applications Only .............................................................................................................................40 B. DOE Funding Agreements.............................................................................................................................40 i. Cooperative Agreements (applies to Topic Area 3 ONLY)........................................................................40 ii. Grants (applies to Topic Area 1 and 2 ONLY) ...........................................................................................40 III. Eligibility Information................................................................................................................................41 A. Eligible Applicants.........................................................................................................................................41 i. Topic Area 1 (Section 40101(c)) ...............................................................................................................41 ii. Topic Area 2 (Section 40107)....................................................................................................................41 iii. Topic Area 3 (40103(b))...........................................................................................................................41 iv. General Requirements for Eligible Applicants For Topic Areas 1, 2, and 3 ............................................41 v. Restricted Eligibility (applies to Topic Area 1 and Topic Area 3 ONLY).....................................................43 B. Cost Sharing ..................................................................................................................................................43 i. Legal Responsibility..................................................................................................................................44 ii. Cost Share Allocation ...............................................................................................................................44 iii. Cost Share Types and Allowability............................................................................................................44 iv. Cost Share Verification.............................................................................................................................45 v. Cost Share Payment .................................................................................................................................46 C. Compliance Criteria.......................................................................................................................................46 i. Concept Papers.........................................................................................................................................46 D. Responsiveness Criteria ................................................................................................................................47 E. Other Eligibility Requirements (Reserved)....................................................................................................47 F. Limitation on Number of Concept Papers and Full Applications Eligible for Review....................................47 G. Questions Regarding Eligibility......................................................................................................................47 IV. Application and Submission Information ...................................................................................................47 A. Application Process.......................................................................................................................................47 B. Application Forms.........................................................................................................................................48 C. Content and Form of the Concept Paper......................................................................................................49 D. Content and Form of the Full Application.....................................................................................................51 i. Full Application Content Requirements ...................................................................................................51 15 Page 10 of 142 ii. SF-424: Application for Federal Assistance ..............................................................................................52 iii. Project/Performance Site Location(s) ......................................................................................................53 iv. Technical Volume.....................................................................................................................................53 v. Resumes...................................................................................................................................................59 vi. Letters of Commitment............................................................................................................................59 vii. Community Partnership Documentation .................................................................................................59 viii. Statement of Project Objectives (SOPO)..................................................................................................60 ix. Budget Justification Workbook ................................................................................................................60 x. Summary/Abstract for Public Release......................................................................................................60 xi. Summary Slide..........................................................................................................................................61 xii. Subrecipient Budget Justification (if applicable)......................................................................................61 xiii. Environmental Questionnaire..................................................................................................................61 xiv. SF-LLL: Disclosure of Lobbying Activities (required).................................................................................62 xv. Waiver Requests (if applicable)................................................................................................................62 xvi. Community Benefits Plan: Job Quality and Equity (Community Benefits Plan).......................................63 xvii. Requirement to Report Potentially Duplicative Funding..........................................................................68 xviii. Report on Resilience Investments (Topic Area 1 ONLY)...........................................................................69 xix. EIA 861 Report (Topic Area 1, small utilities ONLY)..................................................................................69 xx. Locations of Work.....................................................................................................................................69 xxi. Project Description and Assurances Document (PDAD)...........................................................................70 E. Post Selection Information Requests............................................................................................................70 F. Unique Entity Identifier (UEI) and System for Award Management (SAM)..................................................70 G. Submission Dates and Times.........................................................................................................................71 H. Intergovernmental Review............................................................................................................................71 I. Funding Restrictions......................................................................................................................................71 i. Allowable Costs........................................................................................................................................71 ii. Pre-Award Costs.......................................................................................................................................71 iii. Performance of Work in the United States (Foreign Work Waiver).........................................................72 iv. Construction.............................................................................................................................................73 v. Foreign Travel...........................................................................................................................................73 vi. Equipment and Supplies...........................................................................................................................73 vii. Buy America Requirements for Infrastructure Projects...........................................................................73 viii. Davis-Bacon Act Requirements................................................................................................................74 ix. Lobbying...................................................................................................................................................76 x. Risk Assessment .......................................................................................................................................77 xi. Invoice Review and Approval...................................................................................................................78 xii. Prohibition related to Foreign Government-Sponsored Talent Recruitment Programs..........................78 xiii. Affirmative Action and Pay Transparency Requirements.........................................................................79 V. Application Review Information ................................................................................................................80 A. Technical Review Criteria..............................................................................................................................80 i. Concept Papers.........................................................................................................................................80 ii. Full Applications.......................................................................................................................................81 B. Standards for Application Evaluation............................................................................................................93 C. Other Selection Factors.................................................................................................................................93 i. Program Policy Factors.............................................................................................................................93 D. Evaluation and Selection Process..................................................................................................................95 i. Overview ..................................................................................................................................................95 ii. Pre-Selection Interviews...........................................................................................................................95 iii. Pre-Selection Clarification........................................................................................................................96 iv. Recipient Integrity and Performance Matters..........................................................................................96 v. Selection...................................................................................................................................................97 E. Anticipated Notice of Selection and Award Negotiation Dates....................................................................97 16 Page 11 of 142 VI. Award Administration Information............................................................................................................97 A. Award Notices...............................................................................................................................................97 i. Ineligible Submissions ..............................................................................................................................97 ii. Concept Paper Notifications.....................................................................................................................97 iii. Full Application Notifications ...................................................................................................................98 iv. Successful Applicants ...............................................................................................................................98 v. Alternate Selection Determinations.........................................................................................................98 vi. Unsuccessful Applicants...........................................................................................................................98 B. Administrative and National Policy Requirements .......................................................................................99 i. Registration Requirements.......................................................................................................................99 ii. Award Administrative Requirements.......................................................................................................99 iii. Foreign National Participation (September 2021)....................................................................................99 iv. Subaward and Executive Reporting........................................................................................................100 v. National Policy Requirements................................................................................................................100 vi. Environmental Review in Accordance with National Environmental Policy Act (NEPA)........................100 vii. Flood Resilience......................................................................................................................................101 viii. Applicant Representations and Certifications........................................................................................101 ix. Statement of Federal Stewardship.........................................................................................................103 x. Statement of Substantial Involvement (Applies to Topic Area 3 ONLY).................................................103 xi. Intellectual Property Management Plan (IPMP).....................................................................................104 xii. Intellectual Property Provisions .............................................................................................................104 xiii. Reporting................................................................................................................................................104 xiv. Go/No-Go Review...................................................................................................................................105 xv. Conference Spending .............................................................................................................................106 xvi. Uniform Commercial Code (UCC) Financing Statements .......................................................................107 xvii. Implementation of Executive Order 13798, Promoting Free Speech and Religious Liberty..................107 xviii. Participants and Collaborating Organizations........................................................................................107 xix. Requirement to Report Potentially Duplicative Funding........................................................................107 xx. Interim Conflict of Interest Policy for Financial Assistance....................................................................108 xxi. Fraud, Waste and Abuse ........................................................................................................................109 xxii. Human Subjects Research......................................................................................................................109 xxiii. Cybersecurity Plan (Applies to Topic Areas 2 & 3 ONLY)........................................................................110 xxiv. Domestic Content Commitments...........................................................................................................111 xxv. Real Property and Equipment ................................................................................................................111 VII. Questions/Agency Contacts.....................................................................................................................112 VIII. Other Information ...................................................................................................................................112 A. FOA Modifications.......................................................................................................................................112 B. Government Right to Reject or Negotiate ..................................................................................................113 C. Commitment of Public Funds......................................................................................................................113 D. Treatment of Application Information........................................................................................................113 E. Evaluation and Administration by Non-Federal Personnel.........................................................................114 F. Notice Regarding Eligible/Ineligible Activities.............................................................................................114 G. Notice of Right to Conduct a Review of Financial Capability ......................................................................115 H. Requirement for Full and Complete Disclosure..........................................................................................115 I. Retention of Submissions............................................................................................................................115 J. Rights in Technical Data..............................................................................................................................115 K. Copyright.....................................................................................................................................................116 L. Export Control.............................................................................................................................................116 M. Prohibition on Certain Telecommunications and Video Surveillance Services or Equipment....................116 N. Personally Identifiable Information (PII).....................................................................................................117 O. Annual Independent Audits ........................................................................................................................117 17 Page 12 of 142 P. Informational Webinars..............................................................................................................................118 Appendix A – Cost Share Information ...............................................................................................................119 Appendix B – Waiver Requests For: Foreign Entity Participation; and Foreign Work .........................................125 Waiver Criteria .................................................................................................................................................125 Appendix C – Required Use of Iron, Steel, Manufactured Products, and Construction Materials Produced in the United States....................................................................................................................................................128 Buy America Requirements for infrastructure projects .....................................................................................128 Appendix D – Statement of Project Objectives..................................................................................................132 Appendix E – Cybersecurity Plan.......................................................................................................................136 Appendix F – Project Description And Assurances Document Template (PDAD)................................................138 18 Page 13 of 142 I.Funding Opportunity Description A. Background and Context The Grid Deployment Office (GDO), in conjunction with the Office of Clean Energy Demonstrations (OCED), is issuing this Funding Opportunity Announcement (FOA). Awards made under this FOA will be funded, in whole or in part, with funds appropriated by the Infrastructure Investment and Jobs Act1 (IIJA), also more commonly known as the Bipartisan Infrastructure Law (BIL). The BIL is a once-in-a-generation investment in infrastructure, designed to modernize and upgrade American infrastructure to enhance U.S. competitiveness, driving the creation of good-paying union jobs, tackling the climate crisis, and ensuring stronger access to economic, environmental, and other benefits for disadvantaged communities (DACs). The BIL appropriates more than $62 billion to the Department of Energy (DOE)2 including funding to support investments to build a clean and equitable energy economy that achieves pollution free electricity by 2035 and puts the United States on a path to achieve net-zero emissions economy- wide by no later than 2050“3 to benefit all Americans. As new load and generation come online as the market moves in line with these goals, deploying the projects that will support a more resilient and reliable grid will be critical. At present, aging grid infrastructure leaves the grid increasingly vulnerable to attacks.4 The increasing frequency of extreme weather events is leading to energy supply disruptions that threaten the economy, put public health and safety at risk, and can devastate affected communities all over the country. Among other programs DOE has to support the grid, three BIL programs covered by this FOA – each with specific statutory requirements– will invest approximately $10.5 billion for the five-year period encompassing FY22 through FY26 to deploy technologies to increase grid reliability and resilience. The activities to be funded under this FOA support three BIL sections including 40101(c), 40107 and 40103(b).5 Together DOE refers to these programs as the Grid Resilience and Innovation Partnerships (GRIP) program. 1 Infrastructure Investment and Jobs Act, Public Law 117-58 (November 15, 2021). https://www.congress.gov/bill/117th-congress/house-bill/3684. This FOA uses the more common name “Bipartisan Infrastructure Law”. 2 U.S. Department of Energy. November 2021. “DOE Fact Sheet: The Bipartisan Infrastructure Deal Will Deliver For American Workers, Families and Usher in the Clean Energy Future.” https://www.energy.gov/articles/doe-fact- sheet-bipartisan-infrastructure-deal-will-deliver-american-workers-families-and-0 3 Executive Order (EO) 14008, “Tackling the Climate Crisis at Home and Abroad,” January 27, 2021. 4 See ICF International, Electric Grid Security and Resilience: Establishing a Baseline for Adversarial Threats, at 26 (June 2016) 5 42 USC §18711(c); 42 USC §18712(b); 42 USC §17386 19 Page 14 of 142 Principles of equity, justice, and advancing accessible good-paying jobs with the free and fair choice to join a union will guide implementation of this program, in alignment with the Administration’s Justice40 Initiative and commitment to American workers. The Department commits to robust engagement and collaboration with States, U.S. Territories, and Indian Tribes, as well as with other interested stakeholders, including industry, unions, and local communities, for successful implementation of the GRIP program. These BIL sections that make up the GRIP program are: Section 40101(c): Grid Resilience Grants Section 40107: Smart Grid Grants Section 40103(b): Grid Innovation Program i. Program Purpose Climate change is increasing the threats to our power system infrastructure. Disruptive weather events are more intense in terms of temperature extremes and precipitation and are becoming broader in scope and affecting larger areas at a time. Other climate impacts like droughts are long-lasting, compounding the potential impact of disruptive events and increasing other threats such as wildfires, floods, and mudslides. Previous methods and approaches to prepare for disruptions are no longer sufficient to meet the increasing threats to the power system due to climate change. Increasing interdependencies between critical infrastructure systems will continue to impact our power system. With these trends in mind, building a more resilient and reliable grid is critical. Studies indicate a more resilient and reliable grid must inherently have the following characteristics: increased grid reliability and flexibility, the ability to easily interconnect new clean energy to enhance generation mix diversity, and improved system cost-effectiveness.6 There is currently insufficient development of projects that will support these characteristics that are critical to reliability and resilience of the grid, particularly in projects that would achieve the following outcomes: 1) increasing transfer capacity between regions, 2) addressing the most consequential system needs and challenges that cause or contribute to the problematic and increasing interconnection queue time for clean energy, and 3) increasing supply of a geographically and technologically diverse sets of location-constrained energy resources to enhance resource adequacy and reduce correlated generation outages.7 Therefore, DOE is eager to leverage federal dollars under the GRIP program to bring together state, Tribal, 6 National Renewable Energy Laboratory (NREL). Interconnections Seam Study. October 2020. https://www.nrel.gov/analysis/seams.html 7 Lawrence Berkeley National Laboratory (LBNL). “Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection.” April 2022. https://emp.lbl.gov/queues 20 Page 15 of 142 community, and industry stakeholders to support these outcomes and others of equal or greater public benefit to build the grid that America needs. Additionally, as the need for grid investment that can enhance reliability and resilience grows, historical trends show that investments by major U.S. electric utilities—representing about 70% of total U.S. electric load—into the distribution system has been more than double that into the transmission system.8,9 DOE is looking to leverage funding to unlock transformative projects that would not be built and deployed without the federal funding under the GRIP program across the transmission system, distribution system, and combination system approaches – including catalyzing and unlocking increased investment into the transmission system to support greater overall grid resilience and reliability at the greatest scale. With the funding provided by the BIL across these three programs there is an opportunity to not only invest in power system infrastructure that addresses critical national, interregional, and regional needs, but also a unique chance to build partnerships between states, local governments, Tribes, and power system operators that align industry objectives with broader regional, interregional, and national goals to enhance reliability, all- hazards resilience, and efficiency of the electric grid. A comprehensive approach that considers all the opportunities available within the BIL can result in more coordinated efforts across relevant stakeholders that can ultimately guide investment strategies for improving resilience beyond what the BIL can support directly. Concurrently, infrastructure investments in power system resilience offer the opportunity to include a diverse set of populations, including underserved and disadvantaged communities, in the development of resilience strategies that focus on communities, and equitable access to opportunities and the benefits that derive from them. DOE believes there are significant benefits to be realized by coordinating the implementation of the three BIL programs focused on power sector infrastructure, grid reliability and resilience. As part of the whole-of-government approach to advance equity and encourage worker organizing and collective bargaining10,11,12 and in alignment with BIL sections 40101(c), 40107, and 40103(b), this FOA and any related activities will seek to encourage meaningful engagement and participation of labor unions and 8 Energy Information Administration (EIA). “Utilities continue to increase spending on transmission infrastructure.” February 9, 2018. https://www.eia.gov/todayinenergy/detail.php?id=34892 9 EIA. “Major utilities continue to increase spending on U.S. electric distribution systems.” July 20, 2018. https://www.eia.gov/todayinenergy/detail.php?id=36675 10 EO 13985, “Advancing Racial Equity and Support for Underserved Communities Through the Federal Government” (Jan. 20, 2021). 11 EO 14025, “Worker Organizing and Empowerment,” April 26, 2021. 12 EO 14052, “Implementation of the Infrastructure Investment and Jobs Act,” November 18, 2021. 21 Page 16 of 142 underserved communities and underrepresented groups, including consultation with Tribal Nations13,14. Consistent with Executive Order 14008, this FOA is designed to help meet the goal that 40% of the overall benefits of certain federal investments flow to disadvantaged communities and drive the creation of accessible good-paying jobs with the free and fair chance for workers to join a union. ii. Strategic Goals This FOA seeks applications to address these three goals: 1. Transform community, regional, interregional, and national resilience, including in consideration of future shifts in generation and load 2. Catalyze and leverage private sector and non-federal public capital for impactful technology and infrastructure deployment 3. Advance community benefits 1.Transform community, regional, interregional, and national resilience, including in consideration of future shifts in generation and load As explained in DOE’s Building a Better Grid Initiative Notice of Intent, modernizing, hardening, and expanding the grid will enhance the resilience of our entire electric system, and ensure that electricity is available to customers when it is needed most.15 Projects funded by the GRIP program should be designed to enable significant national, regional, or community resilience improvements, consistent with grid needs that will manifest as a result of aging grid infrastructure, increasing climate change-related or other hazards to reliability, and the clean energy transition. An important objective of community and regional resilience and transformation is improving the electric grid’s ability to avoid, mitigate and recover from major disruptions and plan for future disruptions across all hazards. Grid investments can enhance resilience by, among other things: i.increasing regional and interregional electricity transfer capacity, ii.addressing the most consequential system needs and challenges that cause or contribute to the problematic and increasing interconnection queue time for clean energy, 13 EO 13175, November 6, 2000 “Consultation and Coordination With Indian Tribal Governments”, charges all executive departments and agencies with engaging in regular, meaningful, and robust consultation with Tribal officials in the development of Federal policies that have Tribal implications. 14 Presidential Memorandum on Tribal Consultation and Strengthening Nation-to-Nation Relationships. January 26, 2021. https://www.whitehouse.gov/briefing-room/presidential-actions/2021/01/26/memorandum-on-tribal- consultation-and-strengthening-nation-to-nation-relationships/ 15 Building a Better Grid Initiative To Upgrade and Expand the Nation's Electric Transmission Grid To Support Resilience, Reliability, and Decarbonization. 87 FR 2769 22 Page 17 of 142 iii.facilitating clean energy deployment, generation mix diversity, and other system benefits. A systemic approach can consider all aspects of physical infrastructure and the ability of power system owners and operators to mitigate outages and restore power to communities as well as the ability of communities to work towards recovery. Therefore, alignment with state, regional, and national energy planning is important to understand threats, mitigation approaches, and system needs, and to help with the prioritization of funding. BIL investments can leverage these plans as well as industry and other investments to assist in community transformation. Applications may consider emphasis on a specific threat, such as wildfire or flooding, and how an approach can transform a region or community resulting in a significant resilience and other economic benefits, with an emphasis on equity. 2.Catalyze and leveraging private sector and non-federal public capital for impactful technology and infrastructure deployment Investments should prioritize driving innovative approaches to achieving grid infrastructure deployment at-scale where significant economic benefits to mitigate threats and impacts of disruptive events to communities can be attained. DOE is looking for applications that will leverage private sector and non-federal public capital to advance deployment goals. These efforts will be aligned with state, regional, or other planning activities and goals. As state resilience plans continue to be updated annually and evaluate future risks, DOE is interested in how Federal funds will leverage industry investments towards hardening their system and/or advancing innovative solutions to enhance system resilience. DOE is also interested in leveraging Federal infrastructure funding to maximize grid infrastructure deployment at-scale. Successful projects will demonstrate how federal investments under the GRIP program can lead to additional future investments by industry, communities, venture capital, and other private debt and equity capital. Investments should prioritize grid improvements especially in cases where GRIP investments can overcome institutional barriers, perceived risk, and the like so as to both deliver beneficial grid outcomes and demonstrate an approach suitable for replication. 3.Advance Community Benefits Increasing grid reliability and resilience provides notable benefits such as reducing outages resulting from extreme events and/or other causes, by 23 Page 18 of 142 reducing restoration times from such outages, or by reducing risks to health and safety for the affected community. In keeping with the Administration’s goals, and as an agency whose mission includes strengthening our country’s energy prosperity, DOE seeks projects that should not only contribute to the country’s energy technology and climate goals, but also meet the following four priority goals (1) support meaningful community and labor engagement; (2) invest in the American workforce; (3) advance diversity, equity, inclusion, and accessibility; and (4) contribute to the goal that 40% of the overall benefits of certain federal investments flow to disadvantaged communities (the Justice40 Initiative). iii. Community Benefits Plan: Job Quality and Equity To support the goal of building a clean and equitable energy economy, the BIL- funded projects are expected to (1) support meaningful community and labor engagement; (2) invest in America’s workforce; (3) advance diversity, equity, inclusion, and accessibility; and (4) contribute to the President’s goal that 40% of the overall benefits of certain federal investments flow to disadvantaged communities (the Justice40 Initiative). To ensure these goals are met, applications must include a Community Benefits Plan that describes how the proposed project would incorporate the four objectives stated above. Applicants are encouraged to submit Community and Labor Partnership Documentation from established labor and community-based organizations that demonstrate the applicant’s ability to achieve the above goals as outlined in the Community Benefits Plan. Within the Community Benefits Plan, the applicant is encouraged to provide specific detail on how to ensure the delivery of measurable community and jobs benefits, ideally through the use of negotiated agreements between the applicant and the community, and/or the applicant and labor unions referred to collectively here as “Workforce and Community Agreements.” These include good neighbor agreements, community benefits agreements, community workforce agreements, project labor agreements, and other collective bargaining agreements. See Section IV.D.xv for the Community Benefits Plan content requirements. a. Community and Labor Engagement The project planning should include engagement with an inclusive collection of local labor unions, governments Tribal entities, and other stakeholders -- such as, residents and businesses, entities that carry out workforce development programs, and community-based organizations that support or work with disadvantaged communities. Considering the importance of the four priorities listed above and the financial investment in the projects to be funded under this FOA, stakeholder engagement is a relatively small cost that delivers high value. 24 Page 19 of 142 Proactive and meaningful engagement with stakeholders ensures stakeholders’ perspectives can be incorporated into the project plan, allows for transparency, and helps reduce or eliminate certain risks associated with the project. b. Quality Jobs In keeping with the Administration’s goals, and to ensure the agency’s energy projects contribute to overall economic prosperity, the DOE strongly supports investments that expand accessible good-paying jobs, with assurances that workers will have a free and fair chance to join a union; promote worker power for marginalized workers and in hard-to-organize and changing industries; improve job quality through the adoption of strong labor standards; support responsible employers; and foster safe, healthy, and inclusive workplaces and communities free from harassment and discrimination, and support strategies that develop a skilled and inclusive local workforce to build and maintain the country’s energy infrastructure and grow domestic manufacturing. c. Diversity, Equity, Inclusion, and Accessibility Advancing equity, civil rights, racial justice, and equal opportunity is a key priority of the Biden Administration. The term “equity” means the consistent and systematic fair, just, and impartial treatment of all individuals, including individuals who belong to underserved communities that have been denied such treatment, such as Black, Latino, and Indigenous and Native American persons, Asian Americans and Pacific Islanders and other persons of color; members of religious minorities; lesbian, gay, bisexual, transgender, and queer (LGBTQ+) persons; persons with disabilities; persons who live in rural areas; and persons otherwise adversely affected by persistent poverty or inequality.16 As part of a whole of government approach to advancing equity, this FOA seeks to encourage the participation of underserved communities17 and underrepresented groups, ensure equitable access to business opportunities, good-paying jobs, career-track training, and other economic opportunities. Partnerships with community-based organizations, comprehensive support services to reduce barriers to access to opportunities and ensuring business and employment opportunities for members of DACs are key tools. Applicants are 16 Executive Order 13985, “Advancing Racial Equity and Support for Underserved Communities Through the Federal Government” (Jan. 20, 2021). 17 The term “underserved communities” refers to populations sharing a particular characteristic, as well as geographic communities, that have been systematically denied a full opportunity to participate in aspects of economic, social, and civic life, as exemplified by the list of in the definition of “equity.” E.O. 13985. For purposes of this FOA, communities identified as disadvantaged or underserved communities by their respective States; communities identified on the Index of Deep Disadvantage referenced at https://news.umich.edu/new-index- ranks-americas-100-most-disadvantaged-communities/, and communities that otherwise meet the definition of “underserved communities” stated above. 25 Page 20 of 142 required to describe how diversity, equity, inclusion, and accessibility objectives will be incorporated in the project. Further, Applicants are highly encouraged to include individuals from groups historically underrepresented18,19 in science, technology, engineering and math (STEM) fields on their project teams. Minority Serving Institutions20, Minority Business Enterprises, Minority Owned Businesses, Woman Owned Businesses, Veteran Owned Businesses, Tribal Colleges and Universities, or entities located in an underserved community that meet the eligibility requirements (See Section III) are encouraged to apply as the prime applicant or participate on an application as a proposed partner to the prime applicant. The Selection Official may consider the inclusion of these types of entities as part of the selection decision (See Section V.C.i. Program Policy Factors). d. Justice40 Initiative In addition to the Federal government’s initiative to achieve greater participation from underserved communities and underrepresented groups, this FOA supports DOE’s commitment to the Justice40 Initiative.21 Benefits include (but are not 18 According to the National Science Foundation’s 2019 report titled, “Women, Minorities and Persons with Disabilities in Science and Engineering”, women, persons with disabilities, and underrepresented minority groups—blacks or African Americans, Hispanics or Latinos, and American Indians or Alaska Natives—are vastly underrepresented in the STEM (science, technology, engineering and math) fields that drive the energy sector. That is, their representation in STEM education and STEM employment is smaller than their representation in the U.S. population. https://ncses.nsf.gov/pubs/nsf19304/digest/about-this-report For example, in the U.S., Hispanics, African Americans and American Indians or Alaska Natives make up 24 percent of the overall workforce, yet only account for 9 percent of the country’s science and engineering workforce. DOE seeks to inspire underrepresented Americans to pursue careers in energy and support their advancement into leadership positions. https://www.energy.gov/articles/introducing-minorities-energy-initiative 19 See also. Note that Congress recognized in Section 305 of the American Innovation and Competitiveness Act of 2017, Public Law 114-329: (1) [I]t is critical to our Nation’s economic leadership and global competitiveness that the United States educate, train, and retain more scientists, engineers, and computer scientists; (2) there is currently a disconnect between the availability of and growing demand for STEM-skilled workers; (3) historically, underrepresented populations are the largest untapped STEM talent pools in the United States; and (4) given the shifting demographic landscape, the United States should encourage full participation of individuals from underrepresented populations in STEM fields. 20 Minority Serving Institutions refers to universities and colleges that serve a significant percentage of students from minority groups, including Historically Black Colleges and Universities/Other Minority Institutions as educational entities recognized by the Office of Civil Rights (OCR), U.S. Department of Education, and identified on the OCR's Department of Education U.S. accredited postsecondary minorities’ institution list. See https://www2.ed.gov/about/offices/list/ocr/edlite-minorityinst.html. 21 The Justice40 initiative, created by E.O. 14008, establishes a goal that 40% of the overall benefits of certain federal investments flow to disadvantaged communities. The Justice40 Interim Guidance provides a broad 26 Page 21 of 142 limited to) measurable direct or indirect investments or positive project outcomes that achieve or contribute to the following in DACs: (1) a decrease in energy burden; (2) a decrease in environmental exposure and burdens; (3) an increase in access to low-cost capital; (4) an increase in high-quality job creation, the clean energy job pipeline, and job training for individuals; (5) increases in clean energy enterprise creation and contracting (e.g., minority-owned or disadvantaged business enterprises); (6) increases in energy democracy, including community ownership; (7) increased parity in clean energy technology access and adoption; and (8) an increase in energy resilience. B. Topic Areas i. Topic Areas The proposed objectives, eligibility, and the technical approach for each of the three programs within the GRIP program are outlined below. DOE will be requesting and reviewing concept papers as part of the application process. Based on DOE’s review of the concept papers, DOE will encourage a subset of applicants to submit Full Applications. Topic Area 1: Grid Resilience Grants (BIL section 40101(c)) Topic Area 2: Smart Grid Grants (BIL section 4010722) Topic Area 3: Grid Innovation Program (BIL section 40103(b)) Topic Area 1: Grid Resilience Grants (40101(c)) Objectives: This program supports activities that reduce the likelihood and consequence of impacts to the electric grid due to extreme weather, wildfire, and natural disaster. The statutory language requires prioritization of projects that will generate the greatest regional or community benefit (whether rural or urban) in reducing the likelihood and consequences of disruptive events.23 definition of disadvantaged communities (Page 2): https://www.whitehouse.gov/wp-content/uploads/2021/07/M- 21-28.pdf. The DOE, Office of Management and Budget, and/or the Federal Council on Environmental Quality (CEQ) may issue additional and subsequent guidance regarding the designation of disadvantaged communities and recognized benefits under the Justice40 Initiative. DOE will also recognize disadvantaged communities as defined and identified by the White House Council on Environmental Quality’s Climate and Economic Justice Screening Tool (CEJST), which can be located at https://screeningtool.geoplatform.gov/ 22 Topic Area 2 is authorized under section 1306 of the Energy Independence and Security Act of 2007, which was later amended by section 40107 of the BIL. The authority is codified at 42 USC §17386. 23 42 USC §18711(c)(4) 27 Page 22 of 142 DOE is seeking projects that address comprehensive transformational transmission and distribution technology solutions that will mitigate one or multiple hazards across a region or within a community, including but not limited to wildfires, floods, hurricanes, extreme heat, extreme cold, storms, and any other event that can cause a disruption to the power system. Consistent with the broader overall objectives of the GRIP programs, projects in this area should demonstrate that they will provide significant economic and justice benefits to communities, can leverage capital investment, and lead to repeatable solutions for other entities. Technical approaches of interest include (but are not limited to) the following: Grants under this program are for projects and activities that increase the ability of applicants to reduce the likelihood and consequences of impacts to the electric grid due to extreme weather, wildfire, natural disaster and other disruptive events. Applicants will demonstrate a transformational, comprehensive approach to mitigating one or more hazards across a region or within a community. Concurrently, DOE encourages applicants to align proposed grid resilience and grid hardening investments with broader State, Tribal, or regional resilience or energy security plans. DOE is particularly interested in applications for adaptive storage deployment, microgrid deployment, and the undergrounding of existing distribution and transmission lines – in addition to other eligible projects and solutions that provide significant benefit. In the selection process, DOE will prioritize applications that address community transformation or the ability to leverage capital investments. For Topic Area 1, there are a broad range of activities, technologies, equipment, and hardening measures to reduce the likelihood and consequences of disruptive events that are eligible for funding24, which include: (A) weatherization technologies and equipment; (B) fire-resistant technologies and fire prevention systems; (C) monitoring and control technologies; (D) the undergrounding of electrical equipment; (E) utility pole management; (F) the relocation of power lines or the reconductoring of power lines with low- sag, advanced conductors; 24 See BIL section 40101(e)(1)(A)-(L), as codified at 42 USC 18711(e)(1)(A)-(L). 28 Page 23 of 142 (G) vegetation and fuel-load management; (H) the use or construction of distributed energy resources for enhancing system adaptive capacity during disruptive events, including— a. microgrids; and b. battery-storage subcomponents; (I) adaptive protection technologies; (J) advanced modeling technologies; (K) hardening of power lines, facilities, substations, of other systems; (L) the replacement of old overhead conductors and underground cables; and (M)new distribution lines below 69 kV, reconductoring, undergrounding and other upgrades to existing transmission infrastructure. The following activities are NOT eligible25 for funding under Topic Area 1: construction of a new— (I) electric generating facility; or (II) large-scale battery- storage facility that is not used for enhancing system adaptive capacity during disruptive events; (III) transmission lines at or above 69 kV; nor cybersecurity. Topic Area 1 Requirements Small utility set-aside. Thirty percent (30%) of the total funding available for Topic Area 1 will be set aside for small utilities, which are defined as entities that sell no more than 4,000,000 MWh of electricity per year.26 Entities applying for this set aside must demonstrate their eligibility by submitting their total retail electricity sales to ultimate customers as reported to the Energy Information Administration (EIA) on Form 861 for the last reporting year. In addition to submission of the Form 861, applications to Topic Area 1 must include a Project Description and Assurances Document (PDAD) certifying the applicant is a Small Utility (sells no more than 4,000,000 MWh of electricity per year). The PDAD template is provided as Appendix F. Report on Resilience Investments. An applicant must submit as part of their application, a report detailing past, current, and future efforts by the eligible entity to reduce the likelihood and consequences of disruptive events.27 The report must summarize any program and related approved funding that the applicant’s organization has implemented over the past 3 years to reduce the likelihood of events in which operations of the electric grid are disrupted, preventively shut off, or cannot operate safely due to extreme weather, wildfire, or a natural disaster. The report must also summarize current and 25 See BIL section 40101(e)(2), as codified at 42 USC 18711(e)(2). 26 42 USC §18711(c)(5) 27 42 USC §18711(c)(2)(B) 29 Page 24 of 142 future efforts planned over at least the next 3 years to reduce the likelihood and consequences of disruptive events. In addition to submission of the report, applications to Topic Area 1 must include a PDAD that confirms the total amount (USD) of qualifying resilience investments that have been spent for the previous 3 years and the time period utilized for calculation of the reported amount by completing and certifying the PDAD. The PDAD template is provided as Appendix F. Funding supplemental to existing efforts. Grants under this program are in general intended to be supplemental to existing hardening efforts of applicants for any given year.28 The applicant should describe in a narrative how the grant funding provided by this program would result in proposed activities that are additional to efforts that would have been undertaken but- for the funding and will generate the greatest community or regional resilience benefit in reducing the likelihood and consequences of disruptive events. This may include the acceleration or expansion of planned activities that would not be accelerated or expanded but-for the funding. The narrative should reference the Report on Resilience Investments to demonstrate how the proposed activities would be additional to existing planned investments. Biennial Report to Congress. Every two years DOE will submit a report to Congress covering data on the cost of projects, the types of activities funded, and the extent to which the ability of the power grid to withstand disruptive events has increased.29 Awardees will be required to track and report this data to DOE. Section 40101(d), ALRD 2736. Per BIL section 40101(e)(2) (C) APPLICATION LIMITATIONS.—An eligible entity may not submit an application for a grant provided by the Secretary under subsection (c) and a grant provided by a State or Indian Tribe pursuant to subsection (d) during the same application cycle. If the applicant is a subaward/subcontract recipient for an application submitted under IIJA Section 40101(d), ALRD 2736, the applicant must describe the differences between the GRIP FOA 2740 application [40101(c)] and the ALRD 2736 [40101(d)] application in the PDAD. The PDAD template is provided as Appendix F. Topic Area 1 Teaming Arrangements Eligible applicants include electric grid operators; electricity generators; electricity storage operators; transmission owners or operators; distribution 28 42 USC §18711(c)(1)(A) 29 42 USC §18711(i) 30 Page 25 of 142 providers; and fuel suppliers.30 Applicants must certify that the prime applicant is an eligible entity type as listed above via completion and submission of the PDAD. The PDAD template is provided as Appendix F. As appropriate, ensuring that the state, Indian Tribe or territory is engaged in the approach is important. The expectation of the Department is that regulatory stakeholders will be engaged in this process to ensure cost recovery of the concepts are achieved. Topic Area 2: Smart Grid Grants (40107) Objectives Topic Area 2 seeks to deploy and catalyze technology solutions that increase the flexibility, efficiency, reliability, and resilience of the electric power system, with particular focus on enhancing the system’s capabilities to meet the following objectives: increase the capacity of transmission facilities or the capability of the transmission system to reliably transfer increased amounts of electric energy; prevent faults that may lead to wildfires or other system disturbances; integrate variable renewable energy resources at the transmission and distribution levels; and, facilitate the aggregation and integration (edge-computing) of electric vehicles and other grid-edge devices or electrified loads. According to a 2018 DOE report, the sum of real-time congestion cost for 2016 among major system operators— specifically, the California Independent System Operator (CAISO), the Electricity Reliability Council of Texas (ERCOT), Independent System Operator New England (ISO-NE), Midcontinent Independent System Operator (MISO), New York Independent System Operator (NYISO), and PJM — was $4.8 billion.31 Another study from DOE found that grid- enhancing technologies (GETs) have significant potential to modernize the grid to increase capacity to reduce clean energy curtailment, unlock additional clean energy generation, and enable more resilient grid operation.32 Complimentary modeling of the impact of deploying three specific types of GETs – Advanced Power Flow Control, Dynamic Line Ratings and Topology Optimization – at a national scale could deliver $5 billion in yearly energy production cost savings, with upfront investment paid back in just 6 months, and double the amount of renewables that can be integrated into the electricity grid prior to building new 30 42 USC §18711(a)(2) 31 U.S. Department of Energy. "Annual U.S. transmission data review." 2018. 32 U.S. Department of Energy. “Grid-Enhancing Technologies: A Case Study on Ratepayer Impact.” February 2022. 31 Page 26 of 142 large-scale transmission lines. A more granular assessment conducted under the same study looked at the Southwest Power Pool system and found that deploying the same three types of GETs could enable 2 adjoining states, to integrate 5,200 MW of wind and solar generation currently in interconnection queues by 2025 without any new large-scale transmission buildout, more than double the development possible without the technologies.33 DOE is interested in applications that deploy GETs to modernize the grid and unlock significant public benefit, and therefore demonstrate the suggested benefit shown by various studies. DOE is also interested in other eligible types of applications that deploy scalable solutions that deliver significant public benefit. Applicants are encouraged to coordinate with and support broader State, local, Tribal, and regional strategies on resilience, energy security, energy & environmental justice, and decarbonization. In addition, smart grid technologies funded and deployed at-scale under this program should have a pathway to wider market adoption such that the funding significantly encourages and facilitates the development of a smart grid.34 Aggregation of smart grid technologies is encouraged to accelerate deployment. Technical approaches of interest include (but are not limited to) the following: A broad set of eligible smart grid investments and capabilities is allowed under statute,35 and any combination of smart grid investments and functions that support the objectives are eligible. DOE will require that projects support data standards (e.g., Green Button Connect36), interoperability, and non- discriminatory data access on a real-time basis. Priority investments in Topic Area 2 include the following: Increasing transmission capacity and operational transfer capacity through grid enhancing technologies such as dynamic line rating, flow control devices, advanced conductors, and network topology optimization, to improve system efficiency and reliability. Improving the visibility of the electrical system to grid operators, to help quickly rebalance the electrical system with autonomous controls, through data analytics, software, and sensors. 33 The Brattle Group. “Unlocking the Queue with Grid-Enhancing Technologies.” February 1, 2021. 34 42 USC §17386(e)(1)(C) 35 42 USC §17386(b) and (d) 36 Green Button Connect is the energy industry standard enabling easy access to, and secure sharing of, utility- customer energy-usage data. 32 Page 27 of 142 Enhance secure communication and data flow between distribution components, through investments in optical ground wire, dark fiber, operational fiber, and wireless broadband communications networks. Aggregation and integration of distributed energy resources and other “grid- edge” devices to provide system benefits, such as renewable energy resources, electric vehicle charging infrastructure, vehicle-to-grid technologies and capabilities, and smart building technologies. Enhancing interoperability and data architecture of systems that support two-way flow of both electric power and localized analytics to provide information between electricity system operators and consumers. Anticipate and mitigate the impacts of extreme weather or natural disaster on grid resiliency, including investments to increase the ability to redirect or shut of power to minimize blackouts, prevent wildfires, and avoid further damage. Complete list of qualifying investments under Topic Area 237 includes: 1. In the case of appliances covered for purposes of establishing energy conservation standards under part B of title III of the Energy Policy and Conservation Act of 1975,38 the documented expenditures incurred by a manufacturer of such appliances associated with purchasing or designing, creating the ability to manufacture, and manufacturing and installing for one calendar year, internal devices that allow the appliance to engage in Smart Grid functions. 2. In the case of specialized electricity-using equipment, including motors and drivers, installed in industrial or commercial applications, the documented expenditures incurred by its owner or its manufacturer of installing devices or modifying that equipment to engage in Smart Grid functions. 3. In the case of transmission and distribution equipment fitted with monitoring and communications devices to enable smart grid functions, the documented expenditures incurred by the electric utility to purchase and install such monitoring and communications devices. 4. In the case of metering devices, sensors, control devices, and other devices integrated with and attached to an electric utility system or retail distributor or marketer of electricity that are capable of engaging in Smart 37 42 USC §17386(b) 38 42 USC §6291 33 Page 28 of 142 Grid functions, the documented expenditures incurred by the electric utility, distributor, or marketer and its customers to purchase and install such devices. 5. In the case of software that enables devices or computers to engage in Smart Grid functions, the documented purchase costs of the software. 6. In the case of entities that operate or coordinate operations of regional electric grids, the documented expenditures for purchasing and installing such equipment that allows Smart Grid functions to operate and be combined or coordinated among multiple electric utilities and between that region and other regions. 7. In the case of persons or entities other than electric utilities owning and operating a distributed electricity generator, the documented expenditures of enabling that generator to be monitored, controlled, or otherwise integrated into grid operations and electricity flows on the grid utilizing Smart Grid functions. 8. In the case of electric or hybrid-electric vehicles, the documented expenses for devices that allow the vehicle to engage in Smart Grid functions (but not the costs of electricity storage for the vehicle). 9. In the case of data analytics that enable software to engage in Smart Grid functions, the documented purchase costs of the data analytics. 10. In the case of buildings, the documented expenses for devices and software, including for installation, that allow buildings to engage in demand flexibility or Smart Grid functions. 11. In the case of utility communications, the documented expenditures incurred by the electric utility to purchase and install operational fiber and wireless broadband communications networks to enable data flow between distribution system components. 12. In the case of advanced transmission technologies such as dynamic line rating, flow control devices, advanced conductors, network topology optimization, or other hardware, software, and associated protocols applied to existing transmission facilities that increase the operational transfer capacity of a transmission network, the documented expenditures to purchase and install those advanced transmission technologies. 13. In the case of extreme weather or natural disasters, the documented expenses for monitoring, control devices and other equipment that enable 34 Page 29 of 142 the ability to redirect or shut off power to minimize blackouts and avoid further damage. The following expenditures and investments are not eligible for Smart Grid grant funding under Topic Area 239: 1. Investments or expenditures for Smart Grid technologies, devices, or equipment that utilize specific tax credits or deductions under the Internal Revenue Code, as amended. 2. Expenditures for electricity generation, transmission, or distribution infrastructure or equipment not directly related to enabling Smart Grid functions. 3. After the final date for State consideration of the Smart Grid Information Standard under section 2621(d)(17) of title 16, an investment that is not in compliance with such standard. 4. After the development and publication by the Institute22 of protocols and model standards for interoperability of smart grid devices and technologies, an investment that fails to incorporate any of such protocols or model standards. 5. Expenditures for physical interconnection of generators or other devices to the grid except those that are directly related to enabling Smart Grid functions. 6. Expenditures for ongoing salaries, benefits, or personnel costs not incurred in the initial installation, training, or startup of smart grid functions. 7. Expenditures for travel, lodging, meals or other personal costs. 8. Ongoing or routine operation, billing, customer relations, security, and maintenance expenditures. Teaming Arrangements DOE encourages applicant teams to include a broad set of stakeholders, including but not limited to, electric grid operator or owners, technology vendors, system integrators, subject matter experts, local energy and environmental justice organizations, and community leaders. In addition, State, 39 42 USC §17386(c) 35 Page 30 of 142 Tribal, territory, or regulatory stakeholders should be engaged in the approach as appropriate. Topic Area 3: Grid Innovation Program (40103(b)) DOE is interested in both technical and non-technical approaches that improve grid reliability and resilience on a local, regional, and interregional scale. Innovative approaches can include advanced technologies, innovative partnerships, financial arrangements, deployment of projects identified by innovative planning and cost allocation approaches, and environmental siting and permitting strategies. Applications may address the transmission system, the distribution system, or both, and may include elements such as: distributed generation assets; load point flexibility enhancements; energy storage systems and other flexibility enhancements; technologies to increase the capacity of the transmission and distribution system; grid-edge technologies; sensing, communications, and control technologies and approaches; grid-forming power electronics; integrated system designs; projects with innovative financing and permitting solutions; projects with uncommon or innovative regulatory structures, projects that are a product of innovative planning, modeling, or cost- allocation approaches, and other similar projects. There is currently insufficient development of projects that are critical to reliability and resilience of the grid, particularly in projects that would achieve the following outcomes for the transmission system: 1) increasing transfer capacity between regions, 2) addressing the most consequential system needs and challenges that cause or contribute to long and increasing interconnection queue time for clean energy, and 3) increasing supply of a geographically and technologically diverse sets of location-constrained energy resources to enhance resource adequacy and reduce correlated generation outages. DOE is particularly interested in applications that demonstrate innovative models, methods, technologies, or other ways to achieve these outcomes that enable grid resilience and reliability. DOE is also interested in all other eligible grid projects that support similar or greater public resilience and reliability benefit. Applications combining multiple approaches are encouraged, and all applications should demonstrate how the proposed new, innovative approaches interact with each other and any existing infrastructure to increase overall system resiliency. Hardening of assets and infrastructure may be included but must show a clear contribution to overall system resiliency. Project results should enable asset owners and operators to effectively articulate within local, state, and Federal decision-making frameworks the economic, technical, and societal benefits of new innovative approaches that improve system reliability and resilience. Applications that invest in America’s workforce; advance energy and environmental justice and support the goals of the Justice40 Initiative; engage in 36 Page 31 of 142 meaningful community and stakeholder engagement; and advance diversity, equity, inclusion and accessibility are of particular importance in this topic area. Entities who are eligible to apply to Topic Area 3 include States, local governments, Tribes, and public utility commissions. Applicants must certify that the prime applicant is an eligible entity via completion and submission of the PDAD. The PDAD template is provided as Appendix F. Objectives This program seeks to provide financial assistance to eligible entities (States, local governments, Tribes, public utility commissions) to facilitate coordination, and collaboration with electric sector owners and operators to: demonstrate innovative approaches to transmission, storage, and distribution infrastructure to harden and enhance resilience and reliability; and demonstrate new approaches to enhance regional grid resilience, implemented through States by public and rural electric cooperative entities on a cost-shared basis.40 DOE is soliciting projects that contribute significantly to one or more of the following primary objectives: Ensuring reliable grid operations by reducing the frequency, scale, and/or duration of disruptions, reducing capacity interconnection time, increasing regional and interregional transfer capacity, or reducing costs associated with increased reliability. Improving overall grid resilience in terms of avoiding, withstanding, responding to, and recovering from disruptions, including deliberate attacks, accidents, the growing threats of extreme weather events and climate change, and other naturally occurring threats or incidents. Projects may demonstrate: o Individual technologies and solutions (or multiple technologies and solutions working as a system) that address resilience in one part of the power system (e.g., transmission system). o Technologies and solutions that address resilience across the traditional boundaries in the power system (e.g., between transmission and distribution). Enhancing collaboration between and among eligible entities and private and public sector owners and operators on grid resilience, including in alignment with regional resilience strategies and plans. This includes collaboration across state and other territorial boundaries such as grid operators or other balancing authorities, with a particular focus on innovating planning processes, 40 42 USC 18712: Electric grid reliability and resilience research, development, and demonstration (house.gov) 37 Page 32 of 142 modeling, cost allocation, permitting, reduction of interconnection queue waiting time, inter-regional projects and other activities aided by collaborative approaches. Contributing to the decarbonization of the electricity and broader energy system in a way that supports system resilience, reliability, and affordability by improving access to technologically and geographically diverse energy resources, including distributed energy resources and electrification opportunities. Providing enhanced system value, improving current and future system cost- effectiveness, and delivering economic benefits to community members, underrepresented regions, or other stakeholders. Applications should clearly identify their value proposition for each individual stakeholder group. Project results should enable asset owners and operators to effectively articulate within local, state, regional and federal decision-making frameworks the economic, technical, and societal benefits of deploying new innovative technologies that improve system reliability and resilience. Technical Approaches of interest include (but are not limited to) the following: Applications to this topic area may address the transmission system, the distribution system, storage, or a combination. Applications combining multiple approaches are encouraged, and all applications should demonstrate how proposed innovative approaches interact with each other and any existing infrastructure to increase overall system resilience. Innovative approaches can include advanced technologies; innovative partnerships; new financial arrangements; deployment of projects identified by innovative planning, modeling, or cost allocation approaches; and/or innovative environmental siting, permitting strategies, or community engagement practices. Hardening of assets and infrastructure may be included but must show a clear contribution to overall system resilience. DOE has identified the three areas of interest for this program spanning the transmission system, distribution system, and combination system approaches. These are not exhaustive, nor intended to be fully independent. Applications that address more than one area of interest, or that present alternative approaches to accomplish the key objectives outside of the specified areas of interest, are encouraged. Area of Interest 1: Transmission system applications The transmission system in operation today is the backbone of the electricity delivery system that connects all grid resources and acts as the path for electricity to flow from generation to demand. Transmission capacity constraints and 38 Page 33 of 142 congestion can prevent delivery of clean, cost-effective electricity to consumers, harming overall system reliability. Advanced transmission technologies, coupled with advanced computational and advanced dynamic situational awareness, are a suite of tools that can help address transmission challenges, improve the efficiency and effectiveness of electricity delivery, and increase the reliability and resilience of the system. Innovative project approaches, including those leveraging advanced transmission technologies can reduce or remove the existing technical, economic, and/or regulatory barrier(s) necessary to accelerate widescale transmission expansion and renewable energy interconnection. Proposed solutions should demonstrate enhanced transmission system operational flexibility or capacity while enhancing reliability. Applications in this area could include technologies, solutions, and advanced functionalities such as: Investments and strategies that accelerate interconnection of clean energy generation and/or storage; Interregional or cross-ISO/RTO projects that address key grid reliability, flexibility, and/or resilience challenges; Projects addressing grid access challenges for remote, stranded, or novel low-carbon resources; Planning, modeling, cost allocation, or other approaches that enable a transition to innovative financial and/or regulatory constructs that accelerate transmission expansion; Underground or underwater HVDC systems in challenging environments; Capacity enhancing approaches such as advanced conductors or dynamic line rating systems; Congestion management techniques including energy storage and integrated controls; Transmission-scale reactive power devices; Flexible alternating current transmission system (FACTS) devices; Solid state transformers; Power flow controllers for AC or High Voltage Direct Current (HVDC) systems. Area of Interest 2: Distribution system applications The distribution system serves as a highly interconnected system providing reliable electricity to consumers. The integration of variable distributed energy sources such wind and solar power, new loads such as electric vehicle charging, and energy storage into these networks is creating new challenges and opportunities for power system control and operation. Solutions should demonstrate improved cost-value characteristics relative to alternative approaches, managing distribution grid integration costs and traditional asset 39 Page 34 of 142 upgrade costs while maintaining or enhancing system reliability and service provision. In addition, extreme weather events have led to an increase in the frequency and duration of de-energization events. These occurrences, along with other experienced or potential disruptions of the distribution grid highlight the importance of improved system resilience. Solutions should demonstrate improved system resilience in response to disruptions and/or recovery from these events with an emphasis on community transformation. Applications in this area could include demonstration of technologies, solutions, and advanced functionalities such as: Adaptive microgrid formation, reliable islanded operations, and service provision during grid-tied operations; Demonstration of reliable and resilient system operations utilizing high levels of distributed renewable generation and energy storage, or increased levels of non-emitting, non-electric distributed energy resources (e.g., renewable heating or cooling); Black-start capable systems and control approaches to minimize negative impacts during power grid disruptions; Provision of grid services from distributed, advanced grid-forming inverter- based systems at sufficient scale and system complexity; Behind the meter asset operations, aggregation, and coordination to provide demand response and grid services, including building systems, distributed generation, energy storage, electric vehicle fleets and others. Area of Interest 3: Combination systems applications While there is a clear differentiation between transmission and distribution systems in the current electrical grid, they both function within the same overall systems. Area of Interest 3 is intended to highlight opportunities to improve joint resilience and functionality across both grid sectors. This could involve using assets in one sector to provide services to the other in a manner that reduces upgrade or expansion requirements, or efforts to improve visibility and communication across sectors to allow for more complete optimization of grid operations. Applications in this area could include demonstration of technologies, solutions, and advanced functionalities such as: Utilization of distribution grid assets to provide backup power and reduce transmission requirements; 40 Page 35 of 142 Utilization of distribution grid dispatchable loads, distributed generation, and energy storage to manage transmission congestion and limit required upgrades; Optimized integrated management of transmission and distribution systems; Monitoring and control technologies, that can provide improved resilience and extend grid visibility & situational awareness across the entire electric delivery system by providing real-time situational awareness across the system. Requirements Topic Area 3 will prioritize large scale and complex system projects that demonstrate innovative approaches while offering the greatest public benefit with a clear path to replication, scale, and ability to impact decarbonization objectives; projects that provide equitable access to innovative technologies and business models; and demonstrations that involve multiple communities and diverse asset compositions including electrical, thermal, building and transportation solutions. Successful applications in this Topic Area 3 will clearly explain: The scale of the proposed project and the differentiated value that this scale will bring to the project and the subject area. The replicability, extensibility, and scalability of the method, model, financing, planning, regulatory approach, technology, or other solution given the system in which it will be demonstrated. Estimated costs and value propositions for the proposed project including contribution to system cost effectiveness, as well as a relative value comparison to alternative approaches. How quantitative, measurable metrics relating to the intended improvements in grid outcomes will be utilized to evaluate success. The readiness, viability, and expected timing of the deployment strategy, including key milestones relating to critical financial, development, and implementation stages of the project. The project management strategy, including use of project funds to secure subrecipient or vendor expertise to support prime recipients on project management, accounting, environmental justice community engagement, federal reporting, and technical oversight. 41 Page 36 of 142 o Note: this approach has been identified as a potential path forward to address resource limitations at recipient organizations. It is not required that external expertise and groups be included, but use of project funds to support these functions will be allowed in accordance with applicable federal cost principles (Section I.i Allowable Costs) How federal funding to address the risks identified in the application will increase the likelihood of securing additional public and/or private investment. How the project will invest in America’s workforce, meaningfully engage communities and stakeholders, advance energy and environmental justice, and ensure diversity, equity, inclusion, and accessibility. Teaming Arrangements This topic area seeks to support demonstrations at sufficient scale and within a system of sufficient complexity to establish confidence in the value proposition of the proposed approach. Applicants are encouraged to assemble diverse and multi-functional project teams capable of receiving and managing federal and matching funds, executing on technology deployments and upgrades, conducting operational testing and validation, analyzing resultant data and performance, and clearly communicating and disseminating findings to key stakeholders and decision makers. The team must designate one team member to serve as the prime recipient and that team member must qualify as an eligible applicant. See Section III. In addition, all teams should clearly articulate their strategy to enable wide- scale adoption of their proposed solutions following a successful demonstration and their intended commitment to utilize these or resultant solutions within their own systems and jurisdictions. Projects selected under this topic area will attempt to resolve technical and commercial adoption barriers by increasing stakeholder confidence in the performance, cost, and value characteristics of their proposed system. In order to ensure maximum impact following these demonstrations, a clear plan to disseminate findings, replicate successes, incorporate the outcomes of the demonstrations into investment decision- making frameworks, and activate additional public and private capital is crucial. These plans should consider which stakeholders and decision makers must be informed as to the demonstration results, what types and quality of information would lead to concrete investment decisions, and how to integrate with local, Tribal, state, and regional energy strategies and transition plans to amplify overall impact and rate of adoption. Initial strategies should be presented in the 42 Page 37 of 142 application, but it is expected that these plans will be developed more fully over the course of the project. All work for projects selected under this FOA must be performed in the United States. See Section IV.I.iii. and Appendix B. Project Management Plan: Successful applicants under all topic areas will be required to prepare a Project Management Plan (PMP). The initial PMP is due 30 days after award. The PMP shall be revised and resubmitted as often as necessary, during the course of the project, to capture any major/significant changes to the planned approach, budget, key personnel, major resources, etc. A sample PMP is available at: BIL-GRIP Application Forms and Templates | netl.doe.gov. ii. Teaming Partner List DOE is compiling a “Teaming Partner List” to facilitate the formation of new project teams for this FOA. The Teaming Partner List allows organizations who may wish to participate on an application to express their interest to other applicants and to explore potential partnerships. Updates to the Teaming Partner List will be available in the FedConnect (https://www.fedconnect.net/) website and on the Grid Resilience and Innovation Partnerships (GRIP) Program web page: Grid Resilience Innovation Partnership Programs | Department of Energy. The Teaming Partner List will be regularly updated to reflect new teaming partners who provide their organization’s information. Applicants must register with FedConnect to have access to the Teaming Partner List (and any updates to it) in FedConnect. SUBMISSION INSTRUCTIONS: Any organization that would like to be included on this list should submit the following information: Organization Name, Contact Name, Contact Address, Contact Email, Contact Phone, Organization Type, Area of Technical Expertise, Brief Description of Capabilities, and Topic Area(s) of Interest. Interested parties should complete the Excel file titled DOE-FOA- 0002740 Teaming Partner List provided as an attachment to this announcement and email it to GDOFOA@hq.doe.gov with the subject line “Teaming Partner Information.” DISCLAIMER: By submitting a request to be included on the Teaming Partner List, the requesting organization consents to the publication of the above-referenced information. By facilitating the Teaming Partner List, DOE is not endorsing, sponsoring, or otherwise evaluating the qualifications of the individuals and organizations that are self-identifying themselves for placement on this Teaming Partner List. DOE will not pay for the provision of any information, nor will it 43 Page 38 of 142 compensate any applicants or requesting organizations for the development of such information. C. Applications Specifically Not of Interest The following types of applications will be deemed nonresponsive and will not be reviewed or considered (See Section III.D. of the FOA): Applications that fall outside the technical parameters specified in Sections I.A. and I.B. of the FOA. Applications for proposed technologies that are not based on sound scientific principles (e.g., violates the laws of thermodynamics). Topic Area 1: Applications that propose the construction of a new—(I) electric generating facility; or (II) large-scale battery-storage facility that is not used for enhancing system adaptive capacity during disruptive events; (III) transmission lines at or above 69 kV; nor cybersecurity. Topic Area 2: See full list of investments not included in section I.B. D. Authorizing Statutes The programmatic authorizing statute is as follows: • Infrastructure Investment and Jobs Act (IIJA), also known as the Bipartisan Infrastructure Law (BIL): o Section 40101(c) – 42 USC §18711(c); o Section 40107 – 42 USC §17386; o Section 40103(b) – 42 USC §18712(b). • Public Law (PL) 95-91, DOE Organization Act; • PL 109-58, Energy Policy Act 2005; • PL 110-140 Energy Independence and Security Act of 2007. Awards made under this announcement will fall under the purview of 2 Code of Federal Regulation (CFR) Part 200 as amended by 2 CFR Part 910. E. Notice of Bipartisan Infrastructure Law-Specific Requirements Be advised that special terms and conditions apply to projects funded by the BIL relating to: Reporting, tracking and segregation of incurred costs; Reporting on job creation and preservation; Publication of information on the Internet; Access to records by Inspectors General and the Government Accountability Office; 44 Page 39 of 142 Requiring all of the iron, steel, manufactured goods, and construction materials used in the infrastructure activities of applicable projects are produced in the United States; Ensuring laborers and mechanics employed by contractors or subcontractors on BIL-funded projects are paid wages equivalent to prevailing wages on similar projects in the area; Protecting whistleblowers and requiring prompt referral of evidence of a false claim to an appropriate inspector general; and Certification and Registration. Recipients of funding appropriated by the BIL must comply with requirements of all applicable Federal, State, and local laws, regulations, DOE policy and guidance, and instructions in this FOA. Recipients must flow down the requirements to subrecipients to ensure the recipient’s compliance with the requirements. II.Award Information A. Award Overview i. Estimated Funding Under BIL sections 40101(c), 40107, and 40103(b), the BIL appropriated approximately $10.5 billion for the five-year period encompassing FY22 through FY26, via annual release of competitive FOAs. This FOA will include both fiscal years 2022 and 2023, totaling approximately $3.9 Billion of federal funding that DOE expects to make available for new awards under this FOA, subject to the availability of appropriated funds. DOE anticipates making approximately 40-100 awards under this FOA. DOE may issue one, multiple, or no awards. Individual award amounts vary by topic area, see details below. Please note, the second competitive funding opportunity is expected to be issued in the first quarter of Fiscal Year 2024 and will include approximately $2 Billion in federal funding for FY 2024, subject to the availability of appropriated funds, along with any unspent funds from the current FY22-23 funding cycle. DOE may issue awards in one, multiple, or none of the following topic areas: Topic Area Number Topic Area Title Anticipated Number of Awards Anticipated Minimum Award Size for Any One Individual Anticipated Maximum Award Size for Any One Individual Approximate Total Federal Funding Anticipated Period of Performance (months) 45 Page 40 of 142 Award (Fed Share) Award (Fed Share) Available for All Awards 1 Grid Resilience Grants (40101(c)) 10*N/A Either the total of the applicant’s last three years of resilience investments or $100 million, whichever is lower** $918 Million 60 months 2 Smart Grid Grants (40107) 25-40 N/A $50 Million $1,080 Million 60 months 3 Grid Innovation Program (40103(b)) 4-40 N/A $250 Million (Increased award size of $1 Billion per award for interregional transmission projects only) $1,820 Million 60-96 months *Approximately 3 of the anticipated number of awards will be made to small utilities. Thirty percent (30%) of the total funding available will be set aside for small utilities, which are defined as entities that sell no more than 4,000,000 MWh of electricity per year.41 **DOE may not award a grant to an eligible entity in an amount that is greater than “the total amount that the eligible entity has spent in the previous 3 years on efforts to reduce the likelihood and consequences of disruptive events”. 42 DOE is including an additional discretionary limit of $100 million in federal funds per award. DOE will interpret “efforts to reduce the likelihood and consequences of disruptive events” as those activities, technologies, equipment, and hardening measures that are eligible for grants under this provision.43 DOE may establish more than one budget period for each award and fund only the initial budget period(s). Funding for all budget periods, including the initial budget period, is not guaranteed. 41 42 USC §18711(c)(5) 42 42 USC §18711(c)(3) 43 42 USC §18711(e)1 46 Page 41 of 142 ii. Period of Performance DOE anticipates making awards that will run from 60 months to 96 months in length (see table below), comprised of one or more budget periods. Project continuation will be contingent upon several elements, including satisfactory performance and DOE’s Go/No-Go decision. For a complete list and more information on the Go/No-Go review, see Section VI.B.xv. iii. New Applications Only DOE will accept only new applications under this FOA. DOE will not consider applications for renewals of existing DOE-funded awards through this FOA. B. DOE Funding Agreements Through cooperative agreements and other similar agreements, DOE provides financial and other support to projects that have the potential to realize the FOA objectives. DOE does not use such agreements to acquire property or services for the direct benefit or use of the United States government. i. Cooperative Agreements (applies to Topic Area 3 ONLY) DOE anticipates funding projects selected under Topic Area 3 through cooperative agreements. In the event funding is awarded to another federal agency, the funding may be provided directly to the agency through an interagency agreement. Through cooperative agreements, DOE provides financial or other support to accomplish a public purpose of support or stimulation authorized by federal statute. Under cooperative agreements, the government and prime recipients share responsibility for the direction of projects. DOE has substantial involvement in all projects funded via cooperative agreement. See Section VI.B.x of the FOA for more information on what substantial involvement may involve. ii. Grants (applies to Topic Area 1 and 2 ONLY) DOE anticipates funding projects selected under Topic Areas 1 and 2 through grants. In the event funding is awarded to another federal agency, the funding may be provided directly to the agency through an interagency agreement. Topic Area Period of Performance 1 60 months 2 60 months 3 60 - 96 months 47 Page 42 of 142 III.Eligibility Information To be considered for substantive evaluation, an applicant’s submission must meet the criteria set forth below. If the application does not meet these eligibility requirements, it will be considered ineligible and removed from further evaluation. A. Eligible Applicants i. Topic Area 1 (Section 40101(c)) The following domestic entities are eligible to apply: electric grid operator; electricity storage operator; electricity generator; transmission owner or operator; distribution provider; and fuel supplier. ii. Topic Area 2 (Section 40107) The following domestic entities are eligible to apply: Institutions of higher education; For-profit entities; Non-profit entities; and State and local governmental entities, and tribal nations. iii. Topic Area 3 (40103(b)) The following domestic entities are eligible to apply: a State; a combination of 2 or more States; an Indian Tribe; a unit of local government; and a public utility commission. iv. General Requirements for Eligible Applicants For Topic Areas 1, 2, and 3 a. Domestic Entities Under this FOA, to qualify as a domestic entity, an entity other than a State or Indian Tribe must be organized, chartered or incorporated (or otherwise formed) under the laws of the United States or of a particular state or territory of the United States and have a physical place of business in the United States. Both 48 Page 43 of 142 recipients and subrecipients must be domestic entities absent an approved waiver. b. Foreign Entities In limited circumstances, DOE may approve a waiver to allow a foreign entity to participate as a prime recipient or subrecipient. A foreign entity may submit a Full Application to this FOA, but the Full Application must be accompanied by an explicit written waiver request. Likewise, if the applicant seeks to include a foreign entity as a subrecipient, the applicant must submit a separate explicit written waiver request in the Full Application for each proposed foreign subrecipient. Appendix B lists the information that must be included in a foreign entity waiver request. The applicant does not have the right to appeal DOE’s decision concerning a waiver request. c. National Laboratories/FFRDCs National Laboratories and Federal Funded Research and Development Centers (FFRDCs) are not eligible to apply for funding as a prime recipient and may not be proposed as a subrecipient on another entity’s application. This restriction is applicable to both DOE/NNSA and non-DOE/NNSA National Laboratories and FFRDCs. The National Energy Technology Laboratory (NETL) is not eligible for award under this announcement and may not be proposed as a subrecipient on another entity’s application. An application that includes NETL as a prime recipient or subrecipient will be considered non-responsive. d. Federal agencies Federal agencies, instrumentalities, and corporations (other than DOE) are eligible to participate as a subrecipient if the agency, instrumentality, or corporation satisfies the statutory requirements, but are not eligible to apply as a prime recipient; except for the Tennessee Valley Authority (under Topic Area 1), who is eligible to participate as a prime recipient and as a subrecipient. e. Teaming Arrangements The project team must designate one team member to serve as the prime recipient and that team member must qualify as an eligible entity. If the project team will operate as an incorporated or unincorporated consortium, DOE may request the applicant to provide additional information, such as any collaboration agreement, that describes management structure and the rights and responsibilities of each consortium member. f. Additional Restrictions 49 Page 44 of 142 Entities banned from doing business with the U.S. government such as entities debarred, suspended, or otherwise excluded from or ineligible for participating in Federal programs are not eligible. Nonprofit organizations described in section 501(c)(4) of the Internal Revenue Code of 1986 that engaged in lobbying activities after December 31, 1995 are not eligible to apply for funding. Nonprofit organizations described in section 501(c)5 of the Internal Revenue Code are eligible to apply for funding. v. Restricted Eligibility (applies to Topic Area 1 and Topic Area 3 ONLY) In accordance with 2 CFR 910.126, DOE restricted eligibility for Topic Area 1 and Topic Area 3 to incorporate the eligibility requirements set forth in sections 40101(c) and 40103(b) of the BIL, as codified at 42 USC 18711 and 42 USC 18712(c), respectively. B. Cost Sharing Applicants are bound by the cost share proposed in their Full Applications if selected for award negotiations. Topic Area Topic Area Title Cost Match/Share Requirement 1 Section 40101(c) – “Grants to Eligible Entities on Preventing Outages and Enhancing the Resilience of the Electric Grid (Grid Resilience Grants)” An eligible entity that receives a grant under this section shall be required to match 100% of the amount of the grant (at least 50% of the Federal funds only, rather than the Total Project Cost). Exception for small utilities: An eligible entity that sells not more than 4,000,000 megawatt hours of electricity per year shall be required to match 1/3 of the grant.* 2 Section 40107 – “Deployment of Technologies to Enhance Grid Flexibility (Smart Grid Grants)” The cost share must be at least 50% of the total project costs. The cost share must come from non-federal sources unless otherwise allowed by law. 3 Section 40103 (b) – “Program Upgrading Our Electric Grid and Ensuring Reliability and Section 988 of the Energy Policy Act of 2005 (42 U.S.C. 16352) shall apply. The cost share must be at least 50% of the total project costs.44,45 The 44 Total project costs is the sum of the government share, , and the recipient share of project costs. 45 Energy Policy Act of 2005, Pub.L. 109-58, sec. 988. Also see 2 CFR 200.306 and 2 CFR 910.130 for additional cost sharing requirements. 50 Page 45 of 142 Resiliency (Grid Innovation Program)” cost share must come from non-federal sources unless otherwise allowed by law. *Cost matching: “Cost matching” for the non-federal share is calculated as a percentage of the Federal funds only, rather than the Total Project Cost. To assist applicants in calculating proper cost match/share amounts, DOE has included a cost share information sheet and sample cost share calculation as Appendix A to this FOA. i. Legal Responsibility Although the cost share requirement applies to the project as a whole, including work performed by members of the project team other than the prime recipient, the prime recipient is legally responsible for paying the entire cost share. If the funding agreement is terminated prior to the end of the project period, the prime recipient is required to contribute at least the cost share percentage of total expenditures incurred through the date of termination. The prime recipient is solely responsible for managing cost share contributions by the project team and enforcing cost share obligation assumed by project team members in subawards or related agreements. ii. Cost Share Allocation Each project team is free to determine how best to allocate the cost share requirement among the team members. The amount contributed by individual project team members may vary, as long as the cost share requirement for the project as a whole is met. iii. Cost Share Types and Allowability Every cost share contribution must be allowable under the applicable federal cost principles, as described in Section IV.I.i. of the FOA. In addition, cost share must be verifiable upon submission of the Full Application. Project teams may provide cost share in the form of cash or in-kind contributions. Cost share may be provided by the prime recipient, subrecipients, or third parties (entities that do not have a role in performing the scope of work). Vendors/contractors may not provide cost share. Any partial donation of goods or services is considered a discount and is not allowable. Cash contributions include, but are not limited to: personnel costs, fringe costs, supply and equipment costs, indirect costs and other direct costs. In-kind contributions are those where a value of the contribution can be readily determined, verified and justified but where no actual cash is transacted in 51 Page 46 of 142 securing the good or service comprising the contribution. Allowable in-kind contributions include, but are not limited to: the donation of volunteer time or the donation of space or use of equipment. Project teams may use funding or property received from state or local governments to meet the cost share requirement, so long as the funding was not provided to the state or local government by the Federal government. The prime recipient may not use the following sources to meet its cost share obligations including, but not limited to: Revenues or royalties from the prospective operation of an activity beyond the project period; Proceeds from the prospective sale of an asset of an activity; Federal funding or property (e.g., federal grants, equipment owned by the federal government); or Expenditures that were reimbursed under a separate federal program. Project teams may not use the same cash or in-kind contributions to meet cost share requirements for more than one project or program. Cost share contributions must be specified in the project budget, verifiable from the prime recipient’s records, and necessary and reasonable for proper and efficient accomplishment of the project. As all sources of cost share are considered part of total project cost, the cost share dollars will be scrutinized under the same federal regulations as federal dollars to the project. Every cost share contribution must be reviewed and approved in advance by the Contracting Officer and incorporated into the project budget before the expenditures are incurred. Applicants are encouraged to refer to 2 CFR 200.306 and 2 CFR 910.130 for additional cost sharing requirements. iv. Cost Share Verification Applicants are required to provide written assurance of their proposed cost share contributions in their Full Applications. Upon selection for award negotiations, applicants are required to provide additional information and documentation regarding their cost share contributions. Please refer to Appendix A of the FOA. 52 Page 47 of 142 v. Cost Share Payment DOE requires prime recipients to contribute the cost share amount incrementally over the life of the award. Specifically, the prime recipient’s cost share for each billing period must always reflect the overall cost share ratio negotiated by the parties (i.e., the total amount of cost sharing on each invoice when considered cumulatively with previous invoices must reflect, at a minimum, the cost sharing percentage negotiated). In limited circumstances, and where it is in the government’s interest, the DOE Contracting Officer may approve a request by the prime recipient to meet its cost share requirements on a less frequent basis, such as monthly or quarterly. Regardless of the interval requested, the prime recipient must be up-to-date on cost share at each interval. Such requests must be sent to the Contracting Officer during award negotiations and include the following information: (1) a detailed justification for the request; (2) a proposed schedule of payments, including amounts and dates; (3) a written commitment to meet that schedule; and (4) such evidence as necessary to demonstrate that the prime recipient has complied with its cost share obligations to date. The Contracting Officer must approve all such requests before they go into effect. C. Compliance Criteria Concept Papers and Full Applications must meet all compliance criteria listed below or they will be considered noncompliant. DOE will not review or consider noncompliant submissions, including Concept Papers and Full Applications that were: submitted through means other than specifically stated in the FOA; submitted after the applicable deadline; and/or submitted incomplete. DOE will not extend the submission deadline for applicants that fail to submit required information by the applicable deadline due to server/connection congestion. i. Concept Papers Concept Papers are deemed compliant if: The Concept Paper complies with the content and form requirements in Section IV.C. of the FOA; and The applicant successfully emailed all required documents to FOA2740@netl.doe.gov by the deadline stated in this FOA. ii. Full Applications Full Applications are deemed compliant if: The Full Application complies with the content and form requirements in Section IV.D. of the FOA; and 53 Page 48 of 142 The applicant successfully uploaded all required documents and clicked the “Submit” button in Grants.gov by the deadline stated in the FOA. D. Responsiveness Criteria All “Applications Specifically Not of Interest,” as described in Section I.C. of the FOA, are deemed nonresponsive and are not reviewed or considered. E. Other Eligibility Requirements (Reserved) F. Limitation on Number of Concept Papers and Full Applications Eligible for Review An entity may submit more than one Concept Paper and Full Application to this FOA, provided that each application describes a unique, scientifically distinct project and provided that an eligible Concept Paper was submitted for each Full Application. G. Questions Regarding Eligibility DOE will not make eligibility determinations for potential applicants prior to the date on which applications to this FOA must be submitted. The decision whether to submit an application in response to this FOA lies solely with the applicant. IV.Application and Submission Information A. Application Process The application process will include two phases: a Concept Paper phase and a Full Application phase. Only applicants who have submitted an eligible Concept Paper will be eligible to submit a Full Application. At each phase, DOE performs an initial eligibility review of the applicant submissions to determine whether they meet the eligibility requirements of Section III of the FOA. DOE will not review or consider submissions that do not meet the eligibility requirements of Section III. All submissions must conform to the following form and content requirements, including maximum page lengths (described below). Concept papers must be emailed to FOA2740@netl.doe.gov, and full applications must be submitted via Grants.gov at https://www.grants.gov/. DOE will not review or consider submissions submitted through means other than specifically stated in the FOA, submissions submitted after the applicable deadline, or incomplete 54 Page 49 of 142 submissions. DOE will not extend deadlines for applicants who fail to submit required information and documents due to server/connection congestion. The Concept Paper and Full Application must conform to the following requirements: Each must be submitted in Adobe PDF format unless stated otherwise; Each must be written in English; All pages must be formatted to fit on 8.5 x 11-inch paper with margins not less than one inch on every side. Use Calibri typeface, a black font color, and a font size of 12 point or larger (except in figures or tables, which may be 10-point font). A symbol font may be used to insert Greek letters or special characters, but the font size requirement still applies. References must be included as footnotes or endnotes in a font size of 10 or larger. Footnotes and endnotes are counted toward the maximum page requirement; and Each submission must not exceed the specified maximum page limit, including cover page, charts, graphs, maps, and photographs when printed using the formatting requirements set forth above and single spaced. If applicants exceed the maximum page lengths indicated below, DOE will review only the authorized number of pages and disregard any additional pages. Applicants are responsible for meeting each submission deadline. Applicants are strongly encouraged to submit their Concept Papers and Full Applications at least 48 hours in advance of the submission deadline. Under normal conditions (i.e., at least 48 hours in advance of the submission deadline), applicants should allow at least 1 hour to submit a Concept Paper and Full Application. Once the Concept Paper and Full Application is submitted as specifically stated in the FOA, applicants may revise or update that submission until the expiration of the applicable deadline. If changes are made to any of these documents, the applicant must resubmit the Concept Paper and Full Application before the applicable deadline. DOE urges applicants to carefully review their Concept Paper and Full Application to allow sufficient time for the submission of required information and documents. Full Applications that pass the initial eligibility review will undergo comprehensive technical merit review according to the criteria identified in Section V of the FOA. B. Application Forms The application forms and instructions are available on Grants.gov at https://www.grants.gov/. 55 Page 50 of 142 Note: The maximum file size that can be uploaded to the Grants.gov website is 10MB. Files in excess of 10MB cannot be uploaded, and hence cannot be submitted for review. If a file exceeds 10MB but is still within the maximum page limit specified in the FOA, it must be broken into parts and denoted to that effect. For example: TechnicalVolume_Part_1 TechnicalVolume_Part_2 DOE will not accept late submissions that resulted from technical difficulties due to uploading files that exceed 10MB. C. Content and Form of the Concept Paper Each Concept Paper must be limited to a single Topic Area. Do not consolidate multiple Topic Areas into a single Concept Paper. The Concept Paper must conform to the following content and form requirements and must not exceed the stated page limits. If applicants exceed the maximum page lengths indicated below, DOE will review only the authorized number of pages and disregard any additional pages. Applicants are encouraged to include the following information in the subject line of the email that includes the concept paper submission: Applicant Name – Topic Area X (insert topic area number to which you are applying for the X) – Concept Paper. Section Page Limit*Description Cover Page 1 page maximum The cover page should include the project title, the specific announcement Topic Area being addressed, entity type of the applicant organization (e.g., electric grid operator, State, etc.), both the technical and business points of contact, names of all team member organizations, the project location(s), and any statements regarding confidentiality. Project and/or Technology Description 12 pages maximum Applicants are required to describe succinctly: How the project addresses the topic area’s eligible uses and technical approaches. How the project supports State, local, Tribal, community and regional resilience, in reducing the likelihood and consequences of disruptive events, decarbonization, or other energy strategies and plans. The grid-benefitting outcomes to be delivered by the project. 56 Page 51 of 142 The impact of the project to reduce innovative technology risk; achieve further deployment at- scale; and lead to additional private sector investments. The impact that DOE funding would have on the proposed project. The readiness, viability, and expected timing of the project. Community Benefits Plan 5 Pages maximum Applicants are required to describe succinctly the approach to be taken with the Community Benefits Plan, addressing the four core elements: community and labor engagement leading to negotiated agreements; investing in job quality and workforce continuity; advancing diversity, equity, inclusion, and accessibility; and contributing to the Justice40 Initiative goal that 40% of the overall benefits of certain climate and clean energy investments flow to disadvantaged communities. Addendum A 5 pages maximum Applicants are required to describe succinctly the qualifications, experience, and capabilities of the proposed Project Team, including: Whether the Project Manager and Project Team have the skill and expertise needed to successfully execute the project plan; Whether the applicant has prior experience that demonstrates an ability to perform tasks of similar risk and complexity; Whether the applicant has worked together with its teaming partners on prior projects or programs; and Whether the applicant has adequate access to equipment and facilities necessary to accomplish the effort and/or clearly explain how it intends to obtain access to the necessary equipment and facilities. Applicants may provide graphs, charts, or other data to supplement their Project and/or Technology Description. Addendum B Topic Area 1 ONLY, if applicable** N/A Applicants who are small utilities applying to Topic Area 1 must submit the EIA Form 861 for the last reporting year showing the total retail electricity sales to ultimate customers to ensure status as a small utility. *Applicants are encouraged to include page numbers in the footer of every page. **Small utilities ONLY: 30% of the total funding available will be set aside for small utilities, which are defined as entities that sell no more than 4,000,000 MWh of electricity per year.46 46 42 USC §18711(c)(5) 57 Page 52 of 142 DOE makes an independent assessment of each Concept Paper based on the criteria in Section V of the FOA. DOE will encourage a subset of applicants to submit Full Applications. Other applicants will be discouraged from submitting a Full Application. An applicant who receives a “discouraged” notification may still submit a Full Application. DOE will review all eligible Full Applications. However, by discouraging the submission of a Full Application, DOE intends to convey its lack of programmatic interest in the proposed project in an effort to save the applicant the time and expense of preparing an application that is unlikely to be selected for award negotiations. DOE may include general comments provided from reviewers on an applicant’s Concept Paper in the encourage/discourage notification sent via email at the close of that phase. D. Content and Form of the Full Application Applicants must submit a Full Application by the specified due date and time to be considered for funding under this FOA. Applicants must complete the following application forms found on the Grants.gov website at https://www.grants.gov/ in accordance with the instructions. Applicants should reference the date and time stated on the FOA cover page to plan for the number of days from receipt of the Concept Paper Encourage/Discourage notification to preparing and submitting a Full Application. Regardless of the date the applicant receives the Encourage/Discourage notification, the submission deadline for the Full Application remains the date and time stated on the FOA cover page. i. Full Application Content Requirements Each Full Application must be limited to a single concept or technology. Do not consolidate unrelated concepts and technologies in a single Full Application. Full Applications must conform to the following content and form requirements and must not exceed the stated page limits. If applicants exceed the maximum page lengths indicated below, DOE will review only the authorized number of pages and disregard any additional pages. Component File Format Page Limit File Name SF-424 Form N/A N/A Project/Performance Site Location(s) Form N/A N/A Technical Volume PDF 25 TechnicalVolume.pdf 58 Page 53 of 142 Resumes PDF 2 pages each Resumes.pdf Letters of Commitment PDF 1 page each LOC.pdf Community Partnership Documentation PDF 1 page each LeadOrganization_Partner.pdf Statement of Project Objectives MS Word 5 SOPO.doc or docx Budget Justification Workbook MS Excel N/A Budget_Justification.xls or xlsx Summary/Abstract for Public Release PDF 1 Summary.pdf Summary Slide MS PowerPoint Up to 3 Slide.ppt or pptx Subrecipient Budget Justification MS Excel N/A Subrecipient_Budget_Justification.xls or xlsx Environmental Questionnaire PDF N/A Env.pdf SF-LLL Disclosure of Lobbying Activities Form N/A N/A Foreign Entity Waiver Requests and Foreign Work Waiver Requests PDF N/A FN_Waiver.pdf Buy America Requirements for Infrastructure Projects Waiver Requests PDF N/A BAWaiver.pdf Community Benefits Plan: Job Quality and Equity PDF 12 CBenefits.pdf Potentially Duplicative Funding Notice (if applicable) PDF N/A PDFN.pdf Report on Resilience Investments Topic Area 1 ONLY PDF 10 ResilienceInvestments.pdf EIA 861 Topic Area 1 ONLY, if applicable* PDF N/A EIA861.pdf Locations of Work MS Excel N/A LOW.xls or xlsx Project Description and Assurances Document (PDAD) PDF N/A PDAD.pdf *Small utilities ONLY: 30% of the total funding available will be set aside for small utilities, which are defined as entities that sell no more than 4,000,000 MWh of electricity per year.47 DOE provides detailed guidance on the content and form of each component below. ii. SF-424: Application for Federal Assistance Complete the SF 424 form first to populate data in other forms. Complete all required fields in accordance with the instructions on the form. The list of certifications and assurances in Field 21 can be found at https://www.energy.gov/management/financial-assistance-forms-and- 47 42 USC §18711(c)(5) 59 Page 54 of 142 information-applicants-and-recipients, under Certifications and Assurances. Note: The dates and dollar amounts on the SF-424 are for the complete project period of performance and not just the first project year, first phase or other subset of the project period of performance. iii. Project/Performance Site Location(s) Indicate the primary site where the work will be performed. If a portion of the project will be performed at any other site(s), identify the site location(s) in the blocks provided. Note that the Project/Performance Site Congressional District is entered in the format of the 2-digit state code followed by a dash and a 3-digit Congressional district code, for example VA-001. Hover over this field for additional instructions. Use the Next Site button to expand the form to add additional Project/Performance Site Locations. iv. Technical Volume The Technical Volume must be submitted in PDF format. The Technical Volume must conform to the following content and form requirements, including maximum page lengths. This volume must address the technical review criteria as discussed in Section V of the FOA. Save the Technical Volume in a single PDF file using the following convention for the title “TechnicalVolume.pdf” and click on "Add Mandatory Other Attachment" to attach. Note: If a file exceeds 10 MB but is still within the maximum page limit specified in the FOA, it must be broken into parts and denoted to that effect. For example: TechnicalVolume_Part_1 TechnicalVolume_Part_2 Applicants must provide sufficient citations and references to the primary research literature to justify the claims and approaches made in the Technical Volume. However, DOE and reviewers are under no obligation to review cited sources. The Technical Volume to the Full Application may not be more than 25 pages, including the cover page, table of contents, and all citations, charts, graphs, maps, photos, or other graphics, and must include all of the information in the table below. The applicant should consider the weighting of each of the technical review criterion (see Section V of the FOA) when preparing the Technical Volume. 60 Page 55 of 142 The Technical Volume should clearly describe and expand upon information provided in the Concept Paper. The Technical Volume must conform to the following content requirements: Technical Volume Content Requirements SECTION/PAGE LIMIT DESCRIPTION Cover Page The cover page should include the project title, the specific FOA Topic Area being addressed, both the technical and business points of contact, names of all team member organizations, names of the senior/key personnel and their organizations, the project location(s), and any statements regarding confidentiality. Project Overview (Approximately 10% of the Technical Volume) The Project Overview should contain the following information: Background: The applicant should discuss the background of their organization, including the history, successes, and current project development status (i.e., the development baseline) relevant to the technical topic being addressed in the Full Application. Project Goal: The applicant should explicitly identify the targeted improvements to the baseline infrastructure, practices and regulatory framework, and/or technology and the critical success factors in achieving that goal, including the ways in which the proposed project location and related infrastructure, skilled workforce, community benefits, etc. will contribute to the success of the overall project. DOE Impact: The applicant should discuss the impact that DOE funding would have on the proposed project. Applicants should specifically explain how DOE funding, relative to prior, current, or anticipated funding from other public and private sources, is necessary to enable the project to progress, and to achieve its intended objectives. Community Benefits Plan: Job Quality and Equity – The applicant should summarize the overall anticipated benefits that will accrue to the local community and DACs (including, but not limited to, decreased duration, frequency, or impact of power disruption; increased access to clean power; and the support of minority business enterprises). The applicant should summarize a plan to attract, train, and retain a skilled labor force with strong labor standards, ensure workers’ free and fair chance to join a union, and identify potential partners they are working with to support these objectives. The applicant should articulate a strategy for sharing and maximizing the project’s benefits across disadvantaged communities and include a discussion of how resident and community leadership will be engaged throughout the project’s duration. DOE encourages efforts to reach historically underserved populations, racial minorities, and women. These strategies should create the connectivity and conditions for growth where they may not exist, such as in rural, underserved, and disadvantaged communities. 61 Page 56 of 142 Identify any potential long-term constraints the project will have on the community’s access to natural resources (e.g., water) and Tribal cultural resources. If applicable, describe a long-term cleanup strategy that ensures communities and neighborhoods remain healthy and safe and not burdened with cleanup costs and waste. The applicant should outline a climate resilience strategy that accounts for climate impacts and extreme weather patterns such as high winds (tornadoes and hurricanes), heat and freezing temperatures, drought, wildfire, and floods. Technical Description, Innovation, and Impact (Approximately 30% of the Technical Volume) The Technical Description should contain the following information: Relevance and Outcomes: The applicant should provide a detailed description of the project, including grid outcomes, the technology used, and other principles and objectives that will be pursued during the project. This section should describe the relevance of the proposed project to the goals and objectives of the FOA, including the potential for the deployment of the project to meet specific desired grid outcomes and other relevant performance targets. The applicant should clearly specify the expected outcomes of the project. Feasibility: The applicant should demonstrate the technical feasibility of the proposed technology and capability of achieving the anticipated performance targets, including a description of previous work done and prior results. This section should also address the project’s access to necessary infrastructure (e.g., transportation, water, electric transmission), including any use of existing infrastructure, as well as to a skilled workforce. Innovation and Impacts: The applicant should describe the current standard practice and/or state-of-the-art technology in the applicable field, the specific innovation (which can include advanced technologies; innovative partnerships; new financial arrangements; deployment of projects identified by innovative planning, modeling, or cost allocation approaches; and/or innovative environmental siting, permitting strategies, or community engagement practices) of the proposed technology, the advantages of proposed technology over current and emerging technologies, and the overall impact on advancing the state-of- the-art/technical baseline if the project is successful. The applicant should describe how the project supports State, local, Tribal, regional and national resilience, decarbonization, or other energy goals, strategies and plans. The applicant should address the potential impact of the project to reduce perceived risk for project deployment; achieve further deployment at-scale to; and lead to additional private sector investments. Topic Area 1 (Grid Resilience Grants) applications must: o Address how the proposed project will generate the greatest community, regional, or interregional resilience benefit in reducing the likelihood and consequences of disruptive events. 62 Page 57 of 142 o Address how the project (1) comprehensively mitigates one or more hazards faced by community or region; (2) comprehensively mitigates the potential for equipment to cause a wildfire in a community or region; (3) fully addresses the consequences of an outage caused by a natural hazard; or (4) mitigates economic risk as derived from outage duration or outage frequency. o Address how the grant funding provided by this program would result in proposed activities that go beyond and are additional to efforts that would have been undertaken but-for the funding and will generate the greatest community or regional resilience benefit in reducing the likelihood and consequences of disruptive events. The narrative should reference the Report on Resilience Investments to demonstrate how the proposed activities would be additional to existing planned investments. Topic Area 2 (Smart Grid Grants) applications must: o Describe how the project will have a significant effect in encouraging and facilitating the development of smart grid functions identified as priority focus areas in 1.B.Topic Area 2 o Describe how the project would enhance the system flexibility to meet program objectives. Topic Area 3 (Grid Innovation Program) applications must: o Describe how the project will address innovative approaches and deployment goals across transmission systems, distribution, or both as identified as priority focus areas in 1.B.Topic Area 3. o Describe how federal funding to address the risks identified in the application will increase the likelihood of securing additional public and/or private investment or otherwise enable the project to proceed. o Include how the concept will provide economic benefit to communities or regions that mitigate impacts from extreme events and disruptions. o Describe how the project has the potential to deliver near-term impact, with appropriate quantitative metrics o Describe project’s readiness, viability, and expected timing. Workplan (Approximately 40% of the Technical Volume) The Workplan should include a summary of the Project Objectives, Technical Scope, Work Breakdown Structure (WBS), Milestones, Go/No-Go Decision Points, and Project Schedule. A detailed SOPO is separately requested. The Workplan should contain the following information: Project Objectives: The applicant should provide a clear and concise (high-level) statement of the goals and objectives of the project as well as the expected outcomes. 63 Page 58 of 142 Technical Scope Summary: The applicant should provide a summary description of the overall work scope and approach to achieve the objective(s). The overall work scope is to be divided by performance periods that are separated by discrete, approximately annual decision points (see below for more information on Go/No-Go decision points). The applicant should describe the specific expected end result of each performance period, including milestones detailed in the Community Benefits Plan. WBS and Task Description Summary: The Workplan should describe the work to be accomplished and how the applicant will achieve the milestones, will accomplish the final project goal(s), and will produce all deliverables. The Workplan is to be structured with a hierarchy of performance period (approximately annual), task and subtasks, which is typical of a standard WBS for any project. The Workplan shall contain a concise description of the specific activities to be conducted over the life of the project. The description shall be a full explanation and disclosure of the project being proposed (i.e., a statement such as “we will then complete a proprietary process” is unacceptable). It is the applicant’s responsibility to prepare an adequately detailed task plan to describe the proposed project and the plan for addressing the objectives of this FOA. The summary provided should be consistent with the SOPO. The SOPO will contain a more detailed description of the WBS and tasks. Milestone Summary: The applicant should provide a summary of appropriate milestones throughout the project to demonstrate success. A milestone may be either a progress measure (which can be activity based) or a SMART technical milestone. SMART milestones should be Specific, Measurable, Achievable, Relevant, and Timely, and must demonstrate a technical achievement rather than simply completing a task. Unless otherwise specified in the FOA, the minimum requirement is that each project must have at least one milestone per quarter for the duration of the project with at least one SMART technical milestone per year (depending on the project, more milestones may be necessary to comprehensively demonstrate progress). The applicant should also provide the means by which the milestone will be verified. Go/No-Go Decision Points (See Section VI.B.xv for more information on the Go/No-Go Review): provide a summary of project-wide Go/No-Go decision points at appropriate points in the Workplan. At a minimum, each project must have at least one project-wide Go/No-Go decision point for each budget period (12 to 18-month period) of the project. The applicant should also provide the specific objective criteria to be used to evaluate the project at the Go/No-Go decision point. The summary provided should be consistent with the SOPO. Go/No-Go decision points are considered “SMART” and can fulfill the requirement for an annual SMART milestone. End of Project Goal: The applicant should provide a summary of the end of project goal(s). At a minimum, each project must have one SMART end 64 Page 59 of 142 of project goal. The summary provided should be consistent with the SOPO. Project Schedule (Gantt Chart or similar): The applicant should provide a schedule for the entire project, including task and subtask durations, milestones, and Go/No-Go decision points. Buy America Requirements for Infrastructure Projects: Within the first 2 pages of the Workplan or project description, include a short statement on whether the project will involve the construction, alteration, maintenance and/or repair of public infrastructure in the United States. See Appendix C for applicable definitions and other information regarding Infrastructure Projects and the Buy America Requirement. Project Management: The applicant should discuss the team’s proposed management plan, including the following: o The overall approach to and organization for managing the work o The roles of each project team member o Any critical handoffs/interdependencies among project team members o The technical and management aspects of the management plan, including systems and practices, such as financial and project management practices o The approach to project risk management, including a plan for securing a qualified workforce and mitigating risks to project performance including but not limited to community or labor disputes. o A description of how project changes will be handled o If applicable, the approach to Quality Assurance/Control o How communications will be maintained among project team members Technical Qualifications and Resources (Approximately 20% of the Technical Volume) The Technical Qualifications and Resources should contain the following information: Describe the project team’s unique qualifications and expertise, including those of key subrecipients. Describe the project team’s existing equipment and facilities, or equipment or facilities already in place on the proposed project site, that will facilitate the successful completion of the proposed project; include a justification of any new equipment or facilities requested as part of the project. This section should also include relevant, previous work efforts, demonstrated innovations, and how these enable the applicant to achieve the project objectives. Describe the time commitment of the key team members to support the project. 65 Page 60 of 142 Describe the technical services to be provided by DOE/NNSA FFRDCs, if applicable. v. Resumes A resume provides information that can be used by reviewers to evaluate the individual’s skills and experience of the key project personnel. Applicants are required to submit two-page resumes for each project manager and key personnel that include the following: 1. Contact Information; 2. Education: Include all academic institutions attended, major/area, degree; 3. Training: (e.g.,) certification or credential from a Registered Apprenticeship or Labor Management Partnership 4. Professional Experience: Beginning with the current position, list professional/academic positions in chronological order with a brief description; 5. List all current academic, professional, or institutional appointments, foreign or domestic, at the applicant institution or elsewhere, whether or not remuneration is received, and, whether full-time, part-time, or voluntary; and 6. There should be no lapses in time over the past ten years or since age 18, which ever time period is shorter. Save the resumes in a single PDF file using the following convention for the title “Resumes.pdf” and click on "Add Optional Other Attachment" to attach. vi. Letters of Commitment Submit letters of commitment from all subrecipient and third-party cost share providers. If applicable, also include any letters of commitment from suppliers/partners/end users/future customers/labor unions/community-based organizations (one-page maximum per letter). Save the letters of commitment in a single PDF file using the following convention for the title “LOC.pdf” and click on "Add Optional Other Attachment" to attach. Letters of support or endorsement for the project from entities that do not have a substantive role in the project are not required nor desired. vii. Community Partnership Documentation In support of the Community Benefits Plan, applicants may submit documentation to demonstrate existing or planned partnerships with community entities, such as, organizations that work with local stakeholders most vulnerable to or affected by the project, such as organizations that carry out workforce development programs, labor unions, Tribal organizations, and 66 Page 61 of 142 community-based organizations that work with disadvantaged communities. The partnership documentation could be in the form of a letter on the partner’s letterhead outlining the planned partnership signed by an officer of the entity, a Memorandum of Understanding, or other similar agreement. Such letters must state the specific nature of the partnership and must not be general letters of support. If the applicant intends to enter into Workforce and Community Agreements as part of the Community Benefits Plan, please include letters from proposed partners as appropriate. Each letter must not exceed 1 page. In total, the partnership documentation must not exceed 10 pages. Save the partnership documentation in a single PDF file using the following convention for the title “LeadOrganization_Partner.pdf”. viii. Statement of Project Objectives (SOPO) Applicants are required to complete a SOPO. A SOPO template is available as Appendix D of the FOA. The SOPO, including the Milestone Table, must not exceed 5 pages when printed using standard 8.5 x 11 paper with 1” margins (top, bottom, left, and right) with font not smaller than 12-point (except in figures or tables, which may be 10-point font). Save the SOPO in a single Microsoft Word file using the following convention for the title “SOPO.doc or docx” and click on "Add Optional Other Attachment" to attach. ix. Budget Justification Workbook Applicants are required to complete the Budget Justification Workbook. This workbook is included as an attachment to this announcement for use and to describe the level of detail required in the budget justification. Although the data requested is mandatory, the use of the budget justification workbook is not. Prime recipients must complete each tab of the Budget Justification Workbook for the project as a whole, including all work to be performed by the prime recipient and its subrecipients and contractors. Applicants should include costs associated with required annual audits and incurred cost proposals in their proposed budget documents. The “Instructions and Summary” included with the Budget Justification Workbook will auto-populate as the applicant enters information into the Workbook. Applicants must carefully read the “Instructions and Summary” tab provided within the Budget Justification Workbook. Save the Budget Justification Workbook in a single Microsoft Excel file using the following convention for the title “Recipient_Budget_Justification.xls or xlsx” and click on “Add Optional Other Attachment” to attach. x. Summary/Abstract for Public Release Applicants are required to submit a one-page summary/abstract of their project. The project summary/abstract must contain a summary of the proposed activity suitable for dissemination to the public. It should be a self-contained document that identifies the name of the applicant, the project manager, the project title, 67 Page 62 of 142 the objectives of the project, a description of the project, including methods to be employed, the potential impact of the project (e.g., benefits, outcomes), and major participants (for collaborative projects). This document must not include any proprietary or sensitive business information as DOE may make it available to the public after selections are made. The project summary must not exceed 1 page when printed using standard 8.5 x 11 paper with 1” margins (top, bottom, left, and right) with font not smaller than 12-point. Save the Summary for Public Release in a single PDF file using the following convention for the title “Summary.pdf” and click on “Add Optional Other Attachment” to attach. xi. Summary Slide Applicants are required to provide up to 3 slides summarizing the proposed project. This slide is used during the evaluation process. The Summary Slide template requires the following information: A technology summary; A description of the technology’s impact; Proposed project goals; Any key graphics (illustrations, charts and/or tables); The project’s key idea/takeaway; Project title, prime recipient, project manager and key personnel information; and Requested DOE funds and proposed applicant cost share. Save the Summary Slide in a single Microsoft PowerPoint file using the following convention for the title “Slide.ppt or pptx” and click on “Add Optional Other Attachment” to attach. xii. Subrecipient Budget Justification (if applicable) Applicants must provide a separate budget justification for each subrecipient that is expected to perform work estimated to be more than $250,000 or 25 percent of the total work effort (whichever is less). The budget justification must include the same justification information described in the “Budget Justification” section above. Save each subrecipient budget justification in a Microsoft Excel file using the following convention for the title “Subrecipient_Budget_Justification.xls or xlsx” and click on “Add Optional Other Attachment” to attach. xiii. Environmental Questionnaire The Applicant must submit an environmental questionnaire providing for the work of the entire project. The Applicant is also responsible for submitting a separate environmental questionnaire for each proposed subrecipient performing at a different location. The environmental questionnaire is available 68 Page 63 of 142 at http://www.netl.doe.gov/File%20Library/Business/forms/451_1-1-3.pdf. Save the questionnaire in a single file named "Env.pdf" (or “Env-FILL IN TEAM MEMBER.pdf” if more than questionnaire is submitted) and click on "Add Optional Other Attachment” to attach. NOTE: If selected for award and if a subrecipient’s location is not known at the time of application, a subsequent environmental questionnaire will be needed prior to them beginning work at an alternate location. xiv. SF-LLL: Disclosure of Lobbying Activities (required) Prime recipients and subrecipients may not use any federal funds to influence or attempt to influence, directly or indirectly, congressional action on any legislative or appropriation matters. Prime recipients and subrecipients are required to complete and submit SF-LLL, “Disclosure of Lobbying Activities” to ensure that non-federal funds have not been paid and will not be paid to any person for influencing or attempting to influence any of the following in connection with the application: An officer or employee of any federal agency; A Member of Congress; xv. Waiver Requests (if applicable) i.Foreign Entity Participation For projects selected under this FOA, as set forth in Section III, all prime recipients and subrecipients must qualify as domestic entities. To request a waiver of this requirement, the applicant must submit an explicit waiver request in the Full Application. Appendix B lists the information that must be included in a waiver request. ii.Performance of Work in the United States (Foreign Work Waiver) As set forth in Section IV.I.iii., all work for projects selected under this FOA must be performed in the United States. To request a waiver of this requirement, the applicant must submit an explicit waiver request in the Full Application. Appendix B lists the information that must be included in a foreign work waiver request. Save the Waivers in a single PDF file using the following convention for the title “FN_Waiver.pdf” and click on “Add Optional Other Attachment” to attach. iii.Waiver of the Buy America Requirement for Infrastructure Projects 69 Page 64 of 142 As set forth in Section IV.I.vii., federally assisted projects which involve infrastructure work, undertaken by applicable recipient types, require that: all iron, steel, and manufactured products used in the infrastructure work are produced in the United States; and all construction materials used in the infrastructure work are manufactured in the United States. The award agreement for funding between DOE and the awardee will require each recipient: (1) to fulfill the commitments made in its application regarding the procurement of U.S.-produced products, subject to a waiver process by DOE assessing the availability and cost (increasing the cost of the overall project by >25%), and (2) to fulfill the commitments made in its application regarding the procurement of other key component metals and manufactured products domestically that are deemed available in sufficient and reasonably available quantities or of a satisfactory quality at the time of award negotiation, again subject to a DOE waiver process. In limited circumstances, DOE may grant a waiver of this requirement. Appendix C to this FOA provides guidance on how “infrastructure work” is defined, explains the applicable justifications under which a waiver may be granted, and lists the information that must be included in the waiver request. Save the Waivers in a single PDF file using the following convention for the title “BAWaiver.pdf” and click on “Add Optional Other Attachment” to attach. xvi. Community Benefits Plan: Job Quality and Equity (Community Benefits Plan) When Community Benefits Plan: Job Quality and Equity (Community Benefits Plan or Plan) must set forth the applicant’s framework to ensure that federal investments in the power sector advance the following four priorities: (1) community and labor engagement; (2) investing in the American workforce; (3) advancing diversity, equity, inclusion, and accessibility (DEIA); and (4) the Justice40 Initiative. The below sections set forth the Plan requirements in each of the foregoing areas. At this stage of the application process, the Community Benefits Plan should indicate the applicant’s intention to engage meaningfully with labor and community stakeholders on these goals, including the potential of entering into formal Workforce and Community Agreements. Given project complexity and sensitivities, applicants should consider pursuing multiple agreements. 70 Page 65 of 142 Applicants should complete each portion of the initial Community Benefits Plan to the greatest extent possible. In cases where information is incomplete, applicants should clearly explain the reason for missing information and provide plans to address those gaps during the project. If the applicant has prior or ongoing efforts to advance energy and environmental justice, DEIA, community and labor engagement, or quality jobs, the application should discuss how they are incorporating lessons learned and building on these prior/ongoing efforts. At this stage of the application process, the Community Benefits Plan should indicate the applicant’s intention to engage meaningfully with community and labor stakeholders on these goals, including the potential of entering into a formal Workforce and Community Agreement. DOE expects the information contained in the Community Benefits Plan to deepen and evolve during each phase. The applicant’s Community Benefits Plan must include at least one SMART (Specific, Measurable, Assignable, Realistic and Time-Related) milestone per budget period supported by metrics to measure the success of the proposed actions. Each of the four sections should also include information about the resources intended to implement the Community Benefits Plan, including staff time and budget to convene public meetings to engage and negotiate agreements with relevant labor unions, communities, and other stakeholders. The initial Community Benefits Plan should provide the most details regarding actions the applicant would take during the initial stages of project development but should also describe in a higher-level summary what goals, deliverables, outcomes, and implementation strategies the applicant would pursue as the project moves through the development, construction, and operational stages. The Community Benefits Plan will be evaluated as part of the technical review process. If the project is selected, DOE will incorporate relevant elements of the Community Benefits Plan, including any proposed Workforce and Community Agreement(s), into the award as part of the project requirements. During the life of the DOE award, DOE will evaluate the recipient’s progress in formatting and implementing this Plan. For additional information, see Community Benefits Plan Frequently Asked Questions (FAQs) | Department of Energy. 1. Community and Labor Engagement: The Community Benefits Plan must set forth the applicant’s prior actions and future plans to engage with labor unions, local governments and Tribal entities, and an inclusive collection of local stakeholders, including community-based organizations that support or work with disadvantaged communities. By facilitating community input and social buy-in and strengthening accountability, such agreements substantially reduce 71 Page 66 of 142 or eliminate certain risks associated with the project. These agreements ideally lay the groundwork for the eventual negotiation of Workforce and Community Agreements, which could take the form of one or more kinds of negotiated agreements with communities, labor unions, or, ideally, both. Registered apprenticeship programs, labor-management training partnerships, quality pre- apprenticeship programs, card check neutrality, and local and targeted hiring goals are all examples of provisions that Workforce and Community Agreements could cover that would increase the success of a DOE-funded project. Applicants should also provide Community and Labor Partnership Documentation from representative organizations reflecting substantive engagement and feedback on applicant’s approach to community benefits including job quality and workforce continuity; diversity, equity, inclusion, and accessibility; and the Justice40 Initiative detailed below. If selected for funding, applicants will be expected to execute on any proposed Workforce and Community Agreements that identify how community and labor concerns, vulnerabilities, and benefits will be addressed. 2. Investing in the American Workforce: A well-qualified, skilled, and trained workforce is necessary to ensure project stability, continuity, and success, and to meet program goals. High-quality jobs are critical to attracting and retaining the qualified workforce required. The Community Benefits Plan must provide an approach to the creation and retention of quality jobs.48 The Plan is an opportunity for the applicant to detail their approach to investing in the American workforce. Successful applicants will be required to provide more detail and identify SMART milestones to ensure accountability with plan implementation. Letters of support may bolster, but not replace, the descriptions requested below. Specific components of the plan must include: 1) Summarize the applicant’s plan to attract, train, and retain a skilled and well qualified workforce for both (a) construction and (b) ongoing operations/production activities. An available workforce is necessary to ensure project stability, continuity, and success. A collective bargaining 48 A “quality job” is defined as a job that (1) exceeds the local prevailing wage for an industry in the region, includes basic benefits (e.g., paid leave, health insurance, retirement/savings plan), and/or is unionized, and (2) helps the employee develop the skills and experiences necessary to advance along a career path. See Economic Development Administration, ARPA Good Jobs Challenge NOFO, EDAHDQ-ARPGJ-2021-2006964, at n. 1, available at https://www.grants.gov/web/grants/viewopportunity.html?oppId=334720. 72 Page 67 of 142 agreement, labor-management partnership, or other such agreement would provide evidence of such a plan. Alternatively, applicants may describe: i. Wages, benefits, and other worker supports provided ii. Commitments to support workforce education and training, including which reduces employee turnover costs for employers, increases productivity from a committed and engaged workforce, and promotes a nimble, resilient, and stable workforce for the project. iii. Efforts to engage employees in the design and execution of a workplace safety and health plan to safeguard worker health and well-being. NOTE: Because Project Labor Agreements (PLAs) have been shown to reduce project costs, avoid work delays, and improve efficiency, they are preferred on construction projects of all sizes and may be required for large construction projects (above $35M or possibly lower, on a case-by-case basis). Assessment of applicability will be conducted on a case-by-case basis and in consultation with recipients to ensure project feasibility. 2) Please disclose any violations found within the past two years under the National Labor Relations Act, Fair Labor Standards Act, Occupational Safety and Health Act, Service Contract Act, Davis-Bacon Act, or Title VII of the Civil Rights Act and any steps taken to improve your workforce practices following this violation. Describe whether workers can form and join unions of their choosing, exercising collective voice. Employees’ ability to organize, bargain collectively, and participate through labor organizations of their choosing in decisions which affect them, helps build meaningful economic power, safeguard the public interest, contribute to the effective conduct of business, and facilitate amicable settlements of disputes between employees and their employers, thus providing assurances of project efficiency, continuity, and multiple public benefits. 3) Describe the job retention and/or transition and other workforce development opportunities associated with the project noting efforts to create or retain jobs. 3. DEIA: The Community Benefits Plan must include a section describing how DEIA objectives will be incorporated into the project. The section should detail how the applicant will partner with underrepresented businesses, training organizations serving workers facing system barriers to access quality jobs, and other project partners to help address DEIA. The plan should include at least one SMART milestone per Budget Period supported by metrics to measure the success of the proposed actions and will be incorporated into the award if selected. 73 Page 68 of 142 The following is a non-exhaustive list of potential DEIA actions that can serve as examples of ways the proposed project could incorporate DEIA elements. These examples should not be considered either comprehensive or prescriptive. Applicants may include appropriate actions not covered by these examples and should include a comprehensive set of specific DEIA actions anticipated in connection with the project. a. Commit to supplier diversity and identify Minority Business Enterprises, Minority Owned Businesses, Woman Owned Businesses, and Veteran Owned Businesses to solicit as vendors and sub-contractors for bids on supplies, services and equipment; b. Identify and partner with workforce training organizations serving under- represented individuals and those facing barriers to quality employment such as those with disabilities, returning citizens, opportunity youth, and veterans; c. Offer anti-bias training and education to ensure hiring professionals can recognize unconscious bias and can learn how to reduce discriminatory barriers; d. Support for quality apprenticeship-readiness and/or pre-apprenticeship programs in the local community that are integrated with registered apprenticeship, including cyber apprenticeship-readiness programs and cyber-registered apprenticeship programs; e. Provide funding for or partner with organization that can provide comprehensive support services such as training stipends, mental health supports, transportation assistance, and access to child care to improve access to career-track training and quality jobs for underrepresented and disadvantaged workers; f. Describe Local and/or Economic Hire efforts (e.g., recruitment preferences for economically disadvantaged populations 4. Justice40 Initiative: Applicants must provide an overview of benefits that can be supported by measurable metrics and describe the benefits to DACs. Such benefits framework shall include appropriate milestones for benefit delivery and will be incorporated into the award. Specifically, the Justice40 Initiative section must include: 1. Identification of applicable disadvantaged communities to which the anticipated project benefits will flow. 2. Identification of applicable benefits that are quantifiable, measurable, and trackable. a. Benefits include (but are not limited to) measurable direct or indirect investments or positive project outcomes that achieve or contribute to the following in disadvantaged communities: (1) a decrease in 74 Page 69 of 142 energy burden; (2) a decrease in environmental exposure and burdens; (3) an increase in access to low-cost capital; (4) an increase in high-quality job creation, the clean energy job pipeline, and job training for individuals; (5) increases in clean energy enterprise creation and contracting (e.g., minority-owned or disadvantaged business enterprises); (6) increases in energy democracy, including community ownership; (7) increased parity in clean energy technology access and adoption; and (8) an increase in energy resilience including reduced outage frequency and/or duration. In addition, applicants, should also discuss how the project will maximize all of the benefits listed herein. 3. A Discussion of Anticipated Negative and Cumulative Environmental Impacts on disadvantaged communities. For example, what are the anticipated environmental impacts associated with the project, and how will the applicant mitigate such impacts? Within the context of cumulative impacts created by the project, applicants should use Environmental Protection Agency EJSCREEN49 tool to quantitatively discuss existing environmental impacts in the project area. 4. A Description of How and when Anticipated Benefits Are Expected to Flow to disadvantaged communities. For example, will the benefits be provided directly within the disadvantaged communities identified in the Justice40 Initiative Plan, or are the benefits expected to flow in another way? Further, will the benefits flow during project development or after project completion, and how will applicant track benefits delivered? For projects funded under this FOA, DOE will provide specific reporting guidance for a subset of the eight policy priorities described above; however, recipients must also report how project benefits flow to applicable disadvantaged communities, in furtherance of the advancement of the policy priorities outlined above. For example, a recipient can describe how a project will increase access to clean energy and decrease harmful emissions in disadvantaged communities and provide methods for tracking the progress of these outcomes. Save the Community Benefits Plan in a single PDF file using the following convention for the title “CBenefits.pdf” and click on “Add Optional Other Attachment” to attach. xvii. Requirement to Report Potentially Duplicative Funding If the applicant or project team member has other active awards of federal funds, the applicant must determine whether the activities of those awards potentially overlap with the activities set forth in its application to this FOA. If 49 Environmental Justice (EJ) Screening and Mapping Tool from the Environmental Protection Agency https://www.epa.gov/ejscreen 75 Page 70 of 142 there is a potential overlap, the applicant must notify DOE in writing of the potential overlap and state how it will ensure any project funds (i.e., recipient cost share and federal funds) will not be used for identical cost items under multiple awards. Likewise, for projects that receive funding under this FOA, if a recipient or project team member receives any other award of federal funds for activities that potentially overlap with the activities funded under the DOE award, the recipient must promptly notify DOE in writing of the potential overlap and state whether project funds from any of those other federal awards have been, are being, or are to be used (in whole or in part) for one or more of the identical cost items under the DOE award. If there are identical cost items, the recipient must promptly notify the DOE Contracting Officer in writing of the potential duplication and eliminate any inappropriate duplication of funding. Save the Potential Duplicative Funding Notice in a single PDF file using the following convention for the title “PDFN.pdf” and click on “Add Optional Other Attachment” to attach. xviii. Report on Resilience Investments (Topic Area 1 ONLY) Applicants must submit a report detailing past, current, and future efforts by the eligible entity to reduce the likelihood and consequences of disruptive events. The report must summarize any programs and related approved funding that your organization has implemented over the past 3 years to reduce the likelihood of events in which operations of the electric grid are disrupted, preventively shut off, or cannot operate safely due to extreme weather, wildfire, or a natural disaster. The report must also summarize current and future efforts planned over at least the next 3 years to reduce the likelihood and consequences of disruptive events. Save the Report on Resilience Investments in a single PDF file using the following convention for the title “ResilienceInvestments.pdf”. xix. EIA 861 Report (Topic Area 1, small utilities ONLY) Applicants who are small utilities applying to Topic Area 1 must submit the EIA Form 861 for the last reporting year showing the total retail electricity sales to ultimate customers to ensure status as a small utility. Save the EIA 861 Report in a single PDF file using the following convention for the title “EIA861.pdf”. xx. Locations of Work The applicant must complete the supplied template by listing the city, state, and zip code + 4 for each location where project work will be performed by the prime recipient or subrecipient(s). This template is included as an attachment to this announcement for use. Save the Location of Work in a single Microsoft Excel file 76 Page 71 of 142 using the following naming convention for the title “LOW.xls or xlsx” and click on “Add Optional Other Attachment” to attach xxi. Project Description and Assurances Document (PDAD) Applicants for all three topic areas must complete and submit the PDAD. Note that there are requirements specific to Topic Area 1 and Topic Area 3, for which the applicant will respond and certify responses via the PDAD, as described in Section I.B. Applicants shall prepare the PDAD in the format provided in Appendix F of the FOA. The PDAD must be signed by the Authorized Organizational Representative (AOR) on behalf of the organization and be submitted in PDF format. Save the PDAD in a single PDF file using the following convention for the title “PDAD.pdf”. E. Post Selection Information Requests If selected for award, DOE reserves the right to request additional or clarifying information regarding the following (non-exhaustive list): Personnel proposed to work on the project and collaborating organizations (See Section VI.B.xix. Participants and Collaborating Organizations); An Intellectual Property Management Plan (if applicable) describing how the project team/consortia members will handle intellectual property rights and issues between themselves while ensuring compliance with federal intellectual property laws, regulations, and policies in accordance with VI.B.xi Intellectual Property Management Plan; Indirect cost information; Other budget information; Commitment Letters from Third Parties Contributing to Cost Share, if applicable; Name and phone number of the Designated Responsible Employee for complying with national policies prohibiting discrimination (See 10 CFR 1040.5); Representation of Limited Rights Data and Restricted Software, if applicable; Information related to Davis-Bacon Act Requirements; Information related to Community Benefits Agreements, as defined above in “Community Benefits Plan: Jobs Quality and Equity,” that applicants may have made with the relevant community; Updated Environmental Questionnaire(s). F. Unique Entity Identifier (UEI) and System for Award Management (SAM) Each applicant (unless the applicant is an individual or federal awarding agency that is excepted from those requirements under 2 CFR 25.110(b) or (c), or has an 77 Page 72 of 142 exception approved by the federal awarding agency under 2 CFR 25.110(d)) is required to: (1) Be registered in the SAM at https://www.sam.gov before submitting its application; (2) provide a valid UEI number in its application; and (3) continue to maintain an active SAM registration with current information at all times during which it has an active federal award or an application or plan under consideration by a federal awarding agency. DOE may not make a federal award to an applicant until the applicant has complied with all applicable UEI and SAM requirements and, if an applicant has not fully complied with the requirements by the time DOE is ready to make a federal award, the DOE will determine that the applicant is not qualified to receive a federal award and use that determination as a basis for making a federal award to another applicant. G. Submission Dates and Times All required submissions must be submitted as specifically stated in the announcement no later than 5 p.m. ET on the dates provided on the cover page of this FOA. H. Intergovernmental Review This FOA is not subject to Executive Order 12372 – Intergovernmental Review of Federal Programs. I.Funding Restrictions i. Allowable Costs All expenditures must be allowable, allocable, and reasonable in accordance with the applicable federal cost principles. Pursuant to 2 CFR 910.352, the cost principles in the Federal Acquisition Regulations (48 CFR Part 31.2) apply to for- profit entities. The cost principles contained in 2 CFR Part 200, Subpart E apply to all entities other than for-profits. Costs to support or oppose union organizing, whether directly or as an offset for other funds, are unallowable. ii. Pre-Award Costs Applicants selected for award negotiations (selectee) must request prior written approval to charge pre-award costs. Pre-award costs are those incurred prior to the effective date of the federal award directly pursuant to the negotiation and in anticipation of the federal award where such costs are necessary for efficient and timely performance of the scope of work. Such costs are allowable only to the extent that they would have been allowable if incurred after the date of the federal award and only with the written approval of the federal awarding agency, through the DOE Contracting Officer. Pre-award costs cannot be incurred prior to the Selection Official signing the Selection Statement and Analysis. 78 Page 73 of 142 Pre-award expenditures are made at the selectee’s risk. DOE is not obligated to reimburse costs: (1) in the absence of appropriations; (2) if an award is not made; or (3) if an award is made for a lesser amount than the selectee anticipated. 1. National Environmental Policy Act (NEPA) Requirements Related to Pre-Award Costs DOE’s decision whether and how to distribute federal funds under this FOA is subject to NEPA. Applicants should carefully consider and should seek legal counsel or other expert advice before taking any action related to the proposed project that would have an adverse effect on the environment or limit the choice of reasonable alternatives prior to DOE completing the NEPA review process. DOE does not guarantee or assume any obligation to reimburse pre- award costs incurred prior to receiving written authorization from the Contracting Officer. If the applicant elects to undertake activities that DOE determines may have an adverse effect on the environment or limit the choice of reasonable alternatives prior to receiving such written authorization from the Contracting Officer, the applicant is doing so at risk of not receiving federal funding for their project and such costs may not be recognized as allowable cost share. Nothing contained in the pre-award cost reimbursement regulations or any pre- award costs approval letter from the Contracting Officer override the requirement to obtain the written authorization from the Contracting Officer prior to taking any action that may have an adverse effect on the environment or limit the choice of reasonable alternatives. Likewise, if an application is selected for negotiation of award, and the prime recipient elects to undertake activities that are not authorized for federal funding by the Contracting Officer in advance of DOE completing a NEPA review, the prime recipient is doing so at risk of not receiving federal funding and such costs may not be recognized as allowable cost share. iii. Performance of Work in the United States (Foreign Work Waiver) 1. Requirement All work performed under DOE awards issued under this FOA must be performed in the United States. The prime recipient must flow down this requirement to its subrecipients. 2. Failure to Comply 79 Page 74 of 142 If the prime recipient fails to comply with the Performance of Work in the United States requirement, DOE may deny reimbursement for the work conducted outside the United States and such costs may not be recognized as allowable recipient cost share. The prime recipient is responsible should any work under this award be performed outside the United States, absent a waiver, regardless of whether the work is performed by the prime recipient, subrecipients, contractors or other project partners. 3. Waiver To seek a foreign work waiver, the applicant must submit a written waiver request to DOE. Appendix B lists the information that must be included in a request for a foreign work waiver. Save the waiver request(s) in a single PDF file. The applicant does not have the right to appeal DOE’s decision concerning a waiver request. iv. Construction Recipients are required to obtain written authorization from the Contracting Officer before incurring any major construction costs. v. Foreign Travel Foreign travel costs are not allowable under this FOA. vi. Equipment and Supplies Property disposition may be required at the end of a project if the current fair market value of property exceeds $5,000. For-profit entity disposition requirements are set forth at 2 CFR 910.360. Property disposition requirements for other non-federal entities are set forth in 2 CFR 200.310 – 200.316. vii. Buy America Requirements for Infrastructure Projects Awards funded through this FOA that are for, or contain, construction, alteration, maintenance or repair of public infrastructure in the United States, undertaken by applicable recipient types, require that:     All iron, steel, and manufactured products used in the infrastructure project are produced in the United States; and   All construction materials used in the infrastructure project are manufactured in the United States.     In general, whether a given project must apply this requirement is dependent on several factors, such as the recipient’s entity type, whether the work involves “infrastructure,” as that term is defined in Section 70914 of the BIL (discussed in more detail in Appendix C), based in part on whether the infrastructure in question is publicly owned or serves a public function. For this FOA specifically, 80 Page 75 of 142 all projects subject to this FOA are considered “infrastructure” within the Buy America provision of BIL, based on implementation guidance from Office of Management and Budget (OMB) Memorandum M-22-11 issued on April 18, 2022. Moreover, based on M-22-11, the Buy America requirements of the BIL do not apply to DOE projects in which the prime recipient is a for-profit entity; the requirements only apply to projects whose prime recipient is a “non-Federal entity,” e.g., a State, local government, Indian Tribe, Institution of Higher Education, or nonprofit organization. Subawards should conform to the terms of the prime award from which they flow; in other words, for-profit prime recipients are not required to flow down these Buy America requirements to subrecipients, even if those subrecipients are non-Federal entities as defined above. Conversely, prime recipients which are non-Federal entities must flow the Buy America requirements down to all subrecipients, even if those subrecipients are for-profit entities. Finally, for all applicants—both non-Federal entities and for-profit entities—DOE is including a Program Policy Factor that the Selection Official may consider in determining which Full Applications to select for award negotiations that considers whether the applicant has made a commitment to procure U.S. iron, steel, manufactured products, and construction materials in its project. The Cooperative Agreement between DOE and the awardee will require each recipient: (1) to fulfill the commitments made in its application regarding the procurement of U.S.-produced products, and (2) to fulfill the commitments made in its application regarding the procurement of other key component metals and manufactured products domestically that are deemed available in sufficient and reasonably available quantities or of a satisfactory quality at the time of award negotiation. Applicants may seek waivers of these requirements in very limited circumstances and for good cause shown. Further details on requesting a waiver can be found in Appendix C and the terms and conditions of the applicant’s award. Applicants are strongly encouraged to consult Appendix C for more information. viii. Davis-Bacon Act Requirements Projects awarded under this FOA will be funded under Division D of the Bipartisan Infrastructure Law. Accordingly, per section 41101 of that law, all laborers and mechanics employed by the applicant, subrecipients, contractors or subcontractors in the performance of construction, alteration, or repair work funded in whole or in part under this FOA shall be paid wages at rates not less than those prevailing on similar projects in the locality, as determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40, United States Code commonly referred to as the “Davis-Bacon Act” (DBA). 81 Page 76 of 142 Applicants shall provide written assurance acknowledging the DBA requirements above, and confirming that the laborers and mechanics performing construction, alteration, or repair work on projects funded in whole or in part by awards made as a result of this FOA are paid or will be paid wages at rates not less than those prevailing on projects of a character similar in the locality as determined by subchapter IV of Chapter 31 of Title 40, United States Code (Davis-Bacon Act). Applicants acknowledge that they will comply with all of the Davis-Bacon Act requirements, including but not limited to: (1) ensuring that the wage determination(s) and appropriate Davis-Bacon clauses and requirements are flowed down to and incorporated into any applicable subcontracts or subrecipient awards. (2) ensuring that if wage determination(s) and appropriate Davis-Bacon clauses and requirements are improperly omitted from contracts and subrecipient awards, the applicable wage determination(s) and clauses are retroactively incorporated to the start of performance. (3) being responsible for compliance by any subcontractor or subrecipient with the Davis-Bacon labor standards. (4) receiving and reviewing certified weekly payrolls submitted by all subcontractors and subrecipients for accuracy and to identify potential compliance issues. (5) maintaining original certified weekly payrolls for 3 years after the completion of the project and must make those payrolls available to the DOE or the Department of Labor upon request, as required by 29 CFR 5.6(a)(2). (6) conducting payroll and job-site reviews for construction work, including interviews with employees, with such frequency as may be necessary to assure compliance by its subcontractors and subrecipients and as requested or directed by the DOE. (7) cooperating with any authorized representative of the Department of Labor in their inspection of records, interviews with employees, and other actions undertaken as part of a Department of Labor investigation. (8) posting in a prominent and accessible place the wage determination(s) and Department of Labor Publication: WH-1321, Notice to Employees Working on Federal or Federally Assisted Construction Projects. 82 Page 77 of 142 (9) notifying the Contracting Officer of all labor standards issues, including all complaints regarding incorrect payment of prevailing wages and/or fringe benefits, received from the recipient, subrecipient, contractor, or subcontractor employees; significant labor standards violations, as defined in 29 CFR 5.7; disputes concerning labor standards pursuant to 29 CFR parts 4, 6, and 8 and as defined in FAR 52.222-14; disputed labor standards determinations; Department of Labor investigations; or legal or judicial proceedings related to the labor standards under this Contract, a subcontract, or subrecipient award. (10) preparing and submitting to the Contracting Officer, the Office of Management and Budget Control Number 1910-5165, Davis Bacon Semi- Annual Labor Compliance Report, by April 21 and October 21 of each year. Form submittal will be administered through the iBenefits system (https://doeibenefits2.energy.gov) or its successor system. Recipients of funding under this FOA will also be required to undergo Davis- Bacon Act compliance training and to maintain competency in Davis-Bacon Act compliance. The Contracting Officer will notify the recipient of any DOE sponsored Davis-Bacon Act compliance trainings. The U.S. Department of Labor (“DOL”) offers free Prevailing Wage Seminars several times a year that meet this requirement, at https://www.dol.gov/agencies/whd/government- contracts/construction/seminars/events. For additional guidance on how to comply with the Davis-Bacon provisions and clauses, see https://www.dol.gov/agencies/whd/government- contracts/construction and https://www.dol.gov/agencies/whd/government- contracts/protections-for-workers-in-construction . DOE anticipates contracting with a third party for a Davis-Bacon Act electronic payroll compliance software application. Recipients of funding under this FOA must ensure the timely electronic submission of weekly certified payrolls through this software as part of its compliance with the Davis-Bacon Act unless a waiver is granted to a particular contractor or subcontractor because they are unable or limited in their ability to use or access. Applicants should indicate if a waiver will be sought. ix. Lobbying Recipients and subrecipients may not use any federal funds to influence or attempt to influence, directly or indirectly, congressional action on any legislative or appropriation matters. 83 Page 78 of 142 Recipients and subrecipients are required to complete and submit SF-LLL, “Disclosure of Lobbying Activities” (https://www.grants.gov/web/grants/forms/sf-424-individual-family.html) to ensure that non-federal funds have not been paid and will not be paid to any person for influencing or attempting to influence any of the following in connection with the application: An officer or employee of any federal agency; A Member of Congress; An officer or employee of Congress; or An employee of a Member of Congress. x. Risk Assessment Pursuant to 2 CFR 200.206, DOE will conduct an additional review of the risk posed by applicants submitted under this FOA. Such risk assessment will consider: 1. Financial stability; 2. Quality of management systems and ability to meet the management standards prescribed in 2 CFR 200 as amended and adopted by 2 CFR 910; 3. History of performance; 4. Audit reports and findings; and 5. The applicant’s ability to effectively implement statutory, regulatory, or other requirements imposed on non-federal entities. DOE may make use of other publicly available information and the history of an applicant’s performance under DOE or other federal agency awards. Depending on the severity of the findings and whether the findings were resolved, DOE may elect not to fund the applicant. In addition to this review, DOE must comply with the guidelines on government- wide suspension and debarment in 2 CFR 180 and must require non-federal entities to comply with these provisions. These provisions restrict federal awards, subawards and contracts with certain parties that are debarred, suspended or otherwise excluded from or ineligible for participation in federal programs or activities. Further, as DOE funds critical and emerging technology areas, DOE also considers possible vectors of undue foreign influence in evaluating risk. If high risks are identified and cannot be sufficiently mitigated, DOE may elect to not fund the applicant. 84 Page 79 of 142 xi. Invoice Review and Approval DOE employs a risk-based approach to determine the level of supporting documentation required for approving invoice payments. Recipients may be required to provide some or all of the following items with their requests for reimbursement: Summary of costs by cost categories; Timesheets or personnel hours report; Proof of compliance with Davis-Bacon and electronic submittals of certified payroll reports; Disclosure of any citations related to NLRA, FLSA, OSH, SCA, or DBA, or Title VII; Invoices/receipts for all travel, equipment, supplies, contractual, and other costs; UCC filing proof for equipment acquired with project funds by for-profit recipients and subrecipients; Explanation of cost share for invoicing period; Analogous information for some subrecipients; and Other items as required by DOE. xii. Prohibition related to Foreign Government-Sponsored Talent Recruitment Programs a. Prohibition Persons participating in a Foreign Government-Sponsored Talent Recruitment Program of a Foreign Country of Risk are prohibited from participating in projects selected for federal funding under this FOA. Should an award result from this FOA, the recipient must exercise ongoing due diligence to reasonably ensure that no individuals participating on the DOE-funded project are participating in a Foreign Government-Sponsored Talent Recruitment Program of a Foreign Country of Risk. Consequences for violations of this prohibition will be determined according to applicable law, regulations, and policy. Further, the recipient must notify DOE within five (5) business days upon learning that an individual on the project team is or is believed to be participating in a foreign government talent recruitment program of a foreign country of risk. DOE may modify and add requirements related to this prohibition to the extent required by law. b. Definitions 1. Foreign Government-Sponsored Talent Recruitment Program. An effort directly or indirectly organized, managed, or funded by a foreign government, or a foreign government instrumentality or entity, to recruit science and technology professionals or students (regardless of citizenship or national origin, or whether having a full-time or part-time 85 Page 80 of 142 position). Some foreign government-sponsored talent recruitment programs operate with the intent to import or otherwise acquire from abroad, sometimes through illicit means, proprietary technology or software, unpublished data and methods, and intellectual property to further the military modernization goals and/or economic goals of a foreign government. Many, but not all, programs aim to incentivize the targeted individual to relocate physically to the foreign state for the above purpose. Some programs allow for or encourage continued employment at U.S. research facilities or receipt of Federal research funds while concurrently working at and/or receiving compensation from a foreign institution, and some direct participants not to disclose their participation to U.S. entities. Compensation could take many forms including cash, research funding, complimentary foreign travel, honorific titles, career advancement opportunities, promised future compensation, or other types of remuneration or consideration, including in-kind compensation. 2. Foreign Country of Risk. DOE has designated the following countries as foreign countries of risk: Iran, North Korea, Russia, and China. This list is subject to change. xiii. Affirmative Action and Pay Transparency Requirements All f federally assisted construction contracts exceeding $10,000 annually will be subject to the requirements of Executive Order 11246: (1) Recipients, subrecipients, contractors and subcontractors are prohibited from discriminating in employment decisions on the basis of race, color, religion, sex, sexual orientation, gender identity or national origin. (2)Recipients and Contractors are required to take affirmative action to ensure that equal opportunity is provided in all aspects of their employment. This includes flowing down the appropriate language to all subrecipients, contractors and subcontractors. (3)Recipients, subrecipients, contractors and subcontractors are prohibited from taking adverse employment actions against applicants and employees for asking about, discussing, or sharing information about their pay or, under certain circumstances, the pay of their co-workers. The Department of Labor’s (DOL) Office of Federal Contractor Compliance Programs (OFCCP) uses a neutral process to schedule contractors for 86 Page 81 of 142 compliance evaluations. OFCCP’s Technical Assistance Guide50 should be consulted to gain an understanding of the requirements and possible actions the recipients, subrecipients, contractors and subcontractors must take. Additionally, for construction projects valued at $35 million or more and lasting more than one year, the recipients, subrecipients, contractors and subcontractors may be assigned by OFCCP as a mega construction project and may be neutrally selected for a compliance evaluation by OFCCP.51 V.Application Review Information A. Technical Review Criteria i. Concept Papers Concept Papers are evaluated based on consideration the following factors. All sub-criteria are of equal weight. Applicable to All Topic Areas Concept Paper Criterion: Overall FOA Responsiveness and Viability of the Project (Weight: 100%) This criterion involves consideration of the following factors: The proposed work, if successfully accomplished, would clearly meet the objectives as stated in the FOA for the specific topic area. The proposed work aligns with and supports State, local, Tribal, regional resilience, decarbonization, or other energy strategies and plans. The applicant has identified risks and challenges, including possible mitigation strategies, and has shown the impact that DOE funding and the proposed project would have on the relevant field and application. The applicant has proposed strategies to ensure meaningful community and labor engagement; quality jobs and workforce development; EEJ and the Justice40 Initiative; and diversity, inclusion, accessibility—including methods to ensure accountability. The applicant has the qualifications, experience, capabilities and other resources necessary to complete the proposed project. 50 See OFCCP’s Technical Assistance Guide at: https://www.dol.gov/sites/dolgov/files/ofccp/Construction/files/ConstructionTAG.pdf?msclkid=9e397d68c4b111e c9d8e6fecb6c710ec Also see the National Policy Assurances http://www.nsf.gov/awards/managing/rtc.jsp 51 For more information regarding this program, see https://www.dol.gov/agencies/ofccp/construction/mega- program. 87 Page 82 of 142 ii. Full Applications Applications will be evaluated against the technical review criteria shown below. All sub-criteria are of equal weight. Criterion 1 for Topic Area 1: Impact, Transformation, and Technical Merit (50%): This criterion involves consideration of the following factors: Extent to which the project supports the Topic Area 1 objectives and desired outcomes. The magnitude of the community or regional resilience benefit that the project will generate by reducing the likelihood and consequences of disruptive events. The extent to which the has application specifically and convincingly demonstrates the applicant’s technical ability to: o comprehensively mitigate one or more hazards faced by community or region o fully mitigate the potential for equipment to cause a wildfire in a community or region o minimize the consequences of an outage caused by a natural hazard o minimize economic impact resulting from outage duration or outage frequency. Extent to which project supports and works in tandem with State, local, Tribal, regional resilience, decarbonization, or other energy strategies and plans. Extent to which the project aligns with and is additive to the current resilience investments described by the applicant outlined in the Report on Resilience Investments. Sufficiency of technical detail to demonstrate that the proposed project is technically feasible and would likely result in the described community or regional resilience benefits. The potential impact of the project to lead to catalyze additional private sector investments and/or non-federal public or regulated capital. Criterion 2 for Topic Area 1: Project Plan and Project Financial Feasibility (20%) This criterion involves consideration of the following factors: Project Approach, Workplan, and Statement of Project Objectives (SOPO) Degree to which the approach and critical path have been clearly described and thoughtfully considered. 88 Page 83 of 142 Degree to which the task descriptions are clear, detailed, timely, and reasonable, resulting in a high likelihood that the proposed Workplan and SOPO will succeed in meeting the project goals. Identification of Risks Discussion and demonstrated understanding of the key anticipated risks (e.g. technical, financial, market, environmental, regulatory) involved in the proposed work and the quality of the mitigation strategies to address them. Baseline, Metrics, and Deliverables The level of clarity in the definition of the baseline, metrics, and milestones. Relative to a clearly defined baseline, the strength of the quantifiable metrics, milestones, and mid-point deliverables defined in the application, such that meaningful interim progress will be made. Project Financial Feasibility The reasonableness of the budget and spend plan for the proposed project and objectives. Soundness of proposed cost share; level of dedication as demonstrated by letter(s) of commitment that clearly identify type and amount of proposed cost share. Proposed cost share meets requirements outlined in the FOA. The degree to which the proposed project yields additive benefit(s) from the federal funding to undertake additional efforts that would not be taken but-for the funding or to accelerate or expand planned activities that would not be accelerated or expanded but-for the funding. The degree to which the applicant justifies the project’s economic viability. The degree to which the project provides enhanced system value and/or provides improved current and future system cost-effectiveness and delivers economic benefit. Criterion 3 for Topic Area 1: Management Team and Project Partners (10%) This criterion involves consideration of the following factors: Project Management Clarity and appropriateness of the roles and responsibilities of the project management organization and the project team, including relevant and critical subrecipients and vendors. 89 Page 84 of 142 The capability of the Project Manager(s) and the proposed team to manage and address all aspects of the proposed work with a high probability of success. The qualifications, relevant expertise, and time commitment of the individuals on the team. The level of participation by project participants as evidenced by letter(s) of commitment and how well they are integrated into the Project Plan/Workplan. The degree to which the applicant has defined and described a project management structure that addresses interfaces with DOE. Partners Degree to which the applicant includes partnerships with critical entities that will help ensure project success, as well as any partnerships with entities (including other states) outside of the applicant’s jurisdiction, who will commit to encourage asset operators (e.g., utilities, merchant developers) to replicate the proposed approaches, technologies or solutions, as applicable. Criterion 4 for Topic Area 1: Community Benefits Plan (20%) Every BIL-funded project is expected to contribute to the country’s energy infrastructure modernization goals, energy technology demonstration and deployment goals, and climate goals, and also to (1) support meaningful community and labor engagement; (2) support quality jobs and ensure workforce continuity; (3) advance diversity, equity, inclusion, and accessibility; and (4) contribute to the Justice40 Initiative’s goal that 40% of the overall project benefits flow to disadvantaged communities. To ensure these goals are met, applications must include a Community Benefits Plan that illustrates how the proposed project plans to incorporate the four goals stated above and are encouraged to submit Community Partnership Documentation from established labor unions, Tribal entities, and community-based organizations that demonstrate the applicant’s ability to achieve the above goals as outlined in the Community Benefits Plan. This criterion involves consideration of the following factors: Community and Labor Engagement Extent to which the applicant demonstrates community and labor engagement to date that results in support for the proposed project. Extent to which the applicant has a clear and appropriately robust plan to engage—ideally through a clear commitment to negotiate an enforceable Workforce & Community Agreements--with labor unions, Tribal entities, 90 Page 85 of 142 and community-based organizations that support or work with disadvantaged communities and other affected stakeholders. Extent to which the applicant has considered accountability to affected workers and community stakeholders, including those most vulnerable to project activities with a plan to publicly share SMART community benefits plan commitments. Extent to which the applicant demonstrates that community and labor engagement will lead to the delivery of high-quality jobs, minimal environmental impact, and allocation of project benefits to disadvantaged communities. Quality Jobs Quality and manner in which the proposed project will create and/or retain high quality, good-paying jobs with employer-sponsored benefits for all classifications and phases of work. Extent to which the project provides employees with the ability to organize, bargain collectively, and participate, through labor. organizations of their choosing, in decisions that affect them and that contribute to the effective conduct of business and facilitates amicable settlements of any potential disputes between employees and employers, providing assurances of project efficiency, continuity, and multiple public benefits. Extent to which applicant demonstrates that they are a responsible employer, with ready access to a sufficient supply of appropriately skilled labor, and an effective plan to minimize the risk of labor disputes or disruptions. Diversity, Equity, Inclusion, and Accessibility (DEIA) The quality and manner in which the proposed project incorporates and measures diversity, equity, inclusion and accessibility goals in the project, as reflected in the applicant’s Community Benefits Plan. Extent to which the project supports the development or demonstration in disadvantaged communities, supports existing minority business enterprises (MBEs) or promotes the creation of MBEs and underrepresented businesses in disadvantaged communities. Quality of any partnerships and agreements with apprenticeship readiness programs, or community-based workforce training and support organizations serving workers facing systematic barriers to employment to facilitate participation in the project’s construction and operations. Extent of engagement of organizations that represent underserved communities as core element of their mission to include Minority Serving Institutions (MSIs), MBEs, associations, and non-profit organizations. 91 Page 86 of 142 Extent to which the project illustrates the ability to meet or exceed the objectives of the Justice40 initiative, including the extent to which the project benefits disadvantaged, underserved communities or partners with Tribal Nations. Justice40 Initiative Extent to which the Community Benefits Plan identifies: specific, measurable benefits for disadvantaged communities, how the benefits will flow to disadvantaged communities, and how negative environmental impacts affecting disadvantaged communities would be mitigated. Extent to which the project would contribute to meeting the objective that 40% of the benefits of climate and clean energy investments flow to disadvantaged communities. Criterion 1 Topic Area 2: Impact, Transformation, and Technical Merit (50%): This criterion involves consideration of the following factors: Extent to which the project supports the Topic Area 2 objectives and desired outcomes. Extent to which the project deploys technology solutions that address Topic Area 2 priority investments. Extent to which the project deploys technology solutions that increase the flexibility, efficiency, reliability and resilience of the electric power system. Extent to which the project supports State, local, Tribal, regional resilience, decarbonization, or other energy strategies and plans. Extent to which the application provides sufficient technical detail to demonstrate that the proposed project is technically feasible and would likely result in the described smart grid benefits. The potential impact of the project to reduce risk for deployment of innovative technologies or solutions and lead to further deployment at- scale. The potential impact of the project to catalyze additional private sector investments and/or non-federal public or regulated capital. Criterion 2 for Topic Area 2: Project Plan and Project Financial Feasibility (20%) This criterion involves consideration of the following factors: Project Approach, Workplan, and Statement of Project Objectives (SOPO) 92 Page 87 of 142 Degree to which the approach and critical path have been clearly described and thoughtfully considered. Degree to which the task descriptions are clear, detailed, timely, and reasonable, resulting in a high likelihood that the proposed Workplan and SOPO will succeed in meeting the project goals. Identification of Risks Discussion and demonstrated understanding of the key anticipated risks (e.g., technical, financial, market, environmental, regulatory) involved in the proposed work and the quality of the mitigation strategies to address them. Baseline, Metrics, and Deliverables The level of clarity in the definition of the baseline, metrics, and milestones. Relative to a clearly defined baseline, the strength of the quantifiable metrics, milestones, and mid-point deliverables defined in the application, such that meaningful interim progress will be made. Project Financial Feasibility The reasonableness of the budget and spend plan for the proposed project and objectives. Soundness of proposed cost share; level of dedication as demonstrated by letter(s) of commitment that clearly identify type and amount of proposed cost share. Proposed cost share meets requirements outlined in the FOA. The degree to which the proposed project yields additive benefit(s) from the federal funding to undertake additional efforts that would not be taken but-for the funding or to accelerate or expand planned activities that would not be accelerated or expanded but-for the funding. The degree to which the applicant justifies the project’s economic viability. The degree to which the project provides enhanced system value and/or provides improved current and future system cost-effectiveness and delivers economic benefit. Criterion 3 for Topic Area 2: Management Team and Project Partners (10%) This criterion involves consideration of the following factors: Project Management Clarity and appropriateness of the roles and responsibilities of the project management organization and the project team, including relevant and critical subrecipients and vendors. 93 Page 88 of 142 The capability of the Project Manager(s) and the proposed team to manage and address all aspects of the proposed work with a high probability of success. The qualifications, relevant expertise, and time commitment of the key individuals on the team. The level of participation by project participants as evidenced by letter(s) of commitment and how well they are integrated into the Project Plan/Workplan. The degree to which the applicant has defined and described a project management structure that addresses interfaces with DOE. Partners Degree to which the applicant includes partnerships with critical entities that will help ensure project success, as well as any partnerships with entities (including other states) outside of the applicant’s jurisdiction, who will commit to encourage asset operators (e.g., utilities, merchant developers) to replicate the proposed approaches, technologies or solutions, as applicable. Criterion 4 for Topic Area 2: Community Benefits Plan (20%) Every BIL-funded project is expected to contribute to the country’s energy infrastructure modernization goals, energy technology demonstration and deployment goals, and climate goals, and also to (1) support meaningful community and labor engagement; (2) support quality jobs and ensure workforce continuity; (3) advance diversity, equity, inclusion, and accessibility; and (4) contribute to the Justice40 Initiative’s goal that 40% of the overall project benefits flow to disadvantaged communities. To ensure these goals are met, applications must include a Community Benefits Plan that illustrates how the proposed project plans to incorporate the four goals stated above and are encouraged to submit Community Partnership Documentation from established labor unions, Tribal entities, and community-based organizations that demonstrate the applicant’s ability to achieve the above goals as outlined in the Community Benefits Plan. This criterion involves consideration of the following factors: Community and Labor Engagement Extent to which the applicant demonstrates community and labor engagement to date that results in support for the proposed project. Extent to which the applicant has a clear and appropriately robust plan to engage—ideally through a clear commitment to negotiate an enforceable Workforce & Community Agreements--with labor unions, Tribal entities, 94 Page 89 of 142 and community-based organizations that support or work with disadvantaged communities and other affected stakeholders. Extent to which the applicant has considered accountability to affected workers and community stakeholders, including those most vulnerable to project activities with a plan to publicly share SMART community benefits plan commitments. Extent to which the applicant demonstrates that community and labor engagement will lead to the delivery of high-quality jobs, minimal environmental impact, and allocation of project benefits to disadvantaged communities. Quality Jobs Quality and manner in which the proposed project will create and/or retain high quality, good-paying jobs with employer-sponsored benefits for all classifications and phases of work. Extent to which the project provides employees with the ability to organize, bargain collectively, and participate, through labor organizations of their choosing, in decisions that affect them and that contribute to the effective conduct of business and facilitates amicable settlements of any potential disputes between employees and employers, providing assurances of project efficiency, continuity, and multiple public benefits. Extent to which applicant demonstrates that they are a responsible employer, with ready access to a sufficient supply of appropriately skilled labor, and an effective plan to minimize the risk of labor disputes or disruptions. Diversity, Equity, Inclusion, and Accessibility (DEIA) The quality and manner in which the proposed project incorporates and measures diversity, equity, inclusion and accessibility goals in the project, as reflected in the applicant’s Community Benefits Plan. Extent to which the project supports the development or demonstration in disadvantaged communities, supports existing minority business enterprises (MBEs) or promotes the creation of MBEs and underrepresented businesses in disadvantaged communities. Quality of any partnerships and agreements with apprenticeship readiness programs, or community-based workforce training and support organizations serving workers facing systematic barriers to employment to facilitate participation in the project’s construction and operations. Extent of engagement of organizations that represent underserved communities as core element of their mission to include Minority Serving Institutions (MSIs), MBEs, associations, and non-profit organizations. 95 Page 90 of 142 Extent to which the project illustrates the ability to meet or exceed the objectives of the Justice40 initiative, including the extent to which the project benefits disadvantaged, underserved communities or partners with Tribal Nations. Justice40 Initiative Extent to which the Community Benefits Plan identifies: specific, measurable benefits for disadvantaged communities, how the benefits will flow to disadvantaged communities, and how negative environmental impacts affecting disadvantaged communities would be mitigated. Extent to which the project would contribute to meeting the objective that 40% of the benefits of climate and clean energy investments flow to disadvantaged communities. Criterion 1 for Topic Area 3: Impact and Market Viability (50%) This criterion involves consideration of the following factors: Extent to which the project supports Topic Area 3 objectives and will deliver the desired Topic Area 3 outcomes. Extent to which the project demonstrates innovative approaches to support deployment goals across transmission system, distribution system, storage or a combination to achieve Topic Area 3 primary objectives. Extent to which the project clearly enhances collaboration between eligible entities and owners/operators to meet Topic Area 3 objectives. Extent to which the project offers the greatest public benefit with a clear path to replication, scale and ability to ensure electricity system reliability and/or resilience, provide enhanced system value and economic benefit, and contribute to the decarbonization of the electricity and broader energy systems. Extent that the project has the potential to deliver near-term impact. Extent to which project supports State, local, Tribal, and regional resilience, decarbonization, or other energy strategies and plans. The potential impact of the project to increase adoption of innovative approach(es), for example to lead to more widespread deployment of advanced technologies; innovative partnerships; new financial arrangements; increased non-Federal investment; deployment of projects identified by innovative planning, modeling, or cost allocation approaches; and/or innovative environmental siting, permitting strategies, or community engagement practices. 96 Page 91 of 142 Criterion 2 for Topic Area 3: Project Plan and Project Financial Feasibility (20%) This criterion involves consideration of the following factors. Project Approach, Workplan, and Statement of Project Objectives (SOPO) Degree to which the approach and critical path have been clearly described and thoughtfully considered. Degree to which the task descriptions are clear, detailed, timely, and reasonable, resulting in a high likelihood that the proposed Workplan and SOPO will succeed in meeting the project goals. Identification of Risks Discussion and demonstrated understanding of the key anticipated risks (e.g., technical, financial, market, environmental, regulatory) involved in the proposed work and the quality of the mitigation strategies to address them. Baseline, Metrics, and Deliverables The level of clarity in the definition of the baseline, metrics, and milestones. Relative to a clearly defined baseline, the strength of the quantifiable metrics, milestones, and mid-point deliverables defined in the application, such that meaningful interim progress will be made. Project Financial Feasibility The reasonableness of the budget and spend plan for the proposed project and objectives. Soundness of proposed cost share; level of dedication as demonstrated by letter(s) of commitment that clearly identify type and amount of proposed cost share. Proposed cost share meets requirements outlined in the FOA. The degree to which the proposed project yields additive benefit(s) from the federal funding to undertake additional efforts that would not be taken but-for the funding or to accelerate or expand planned activities that would not be accelerated or expanded but-for the funding. The degree to which the applicant justifies the project’s economic viability. The degree to which the project provides enhanced system value and/or provides improved current and future system cost-effectiveness and delivers economic benefit. Project Viability, Readiness, and Timing 97 Page 92 of 142 Evidence to support the state of project planning, development, including depth, stage and degree of completeness of engineering design; status of critical agreements and permits; customer expressions of interest; and financial commitments beyond the support sought under this FOA. Criterion 3 for Topic Area 3: Management Team and Project Partners (10%) This criterion involves consideration of the following factors: Project Management Clarity and appropriateness of the roles and responsibilities of the project management organization and the project team, including relevant and critical subrecipients and vendors. The capability of the Project Manager(s) and the proposed team to manage and address all aspects of the proposed work with a high probability of success. The qualifications, relevant expertise, and time commitment of the key individuals on project team. The level of participation by project participants as evidenced by letter(s) of commitment and how well they are integrated into the Project Plan/Workplan. The degree to which the applicant has defined and described a project management structure that addresses interfaces with DOE. Partners Degree to which the applicant includes partnerships with critical entities that will help ensure project success, as well as any partnerships with entities (including other states) outside of the applicant’s jurisdiction, who will commit to encourage asset operators (e.g., utilities, merchant developers) to replicate the proposed approaches, technologies or solutions, as applicable. Criterion 4 for Topic Area 3: Community Benefits Plan (20%) Every BIL-funded project is expected to contribute to the country’s energy infrastructure modernization goals, energy technology demonstration and deployment goals, and climate goals, and also to (1) support meaningful community and labor engagement; (2) support quality jobs and ensure workforce continuity; (3) advance diversity, equity, inclusion, and accessibility; and (4) contribute to the Justice40 Initiative’s goal that 40% of the overall project benefits flow to disadvantaged communities. 98 Page 93 of 142 To ensure these goals are met, applications must include a Community Benefits Plan that illustrates how the proposed project plans to incorporate the four goals stated above and are encouraged to submit Community Partnership Documentation from established labor unions, Tribal entities, and community-based organizations that demonstrate the applicant’s ability to achieve the above goals as outlined in the Community Benefits Plan. This criterion involves consideration of the following factors: Community and Labor Engagement Extent to which the applicant demonstrates community and labor engagement to date that results in support for the proposed project. Extent to which the applicant has a clear and appropriately robust plan to engage—ideally through a clear commitment to negotiate an enforceable Workforce & Community Agreements--with labor unions, Tribal entities, and community-based organizations that support or work with disadvantaged communities and other affected stakeholders. Extent to which the applicant has considered accountability to affected workers and community stakeholders, including those most vulnerable to project activities with a plan to publicly share SMART community benefits plan commitments. Extent to which the applicant demonstrates that community and labor engagement will lead to the delivery of high-quality jobs, minimal environmental impact, and allocation of project benefits to disadvantaged communities. Quality Jobs Quality and manner in which the proposed project will create and/or retain high quality, good-paying jobs with employer-sponsored benefits for all classifications and phases of work. Extent to which the project provides employees with the ability to organize, bargain collectively, and participate, through labor organizations of their choosing, in decisions that affect them and that contribute to the effective conduct of business and facilitates amicable settlements of any potential disputes between employees and employers, providing assurances of project efficiency, continuity, and multiple public benefits. Extent to which applicant demonstrates that they are a responsible employer, with ready access to a sufficient supply of appropriately skilled labor, and an effective plan to minimize the risk of labor disputes or disruptions. Diversity, Equity, Inclusion, and Accessibility (DEIA) 99 Page 94 of 142 The quality and manner in which the proposed project incorporates and measures diversity, equity, inclusion and accessibility goals in the project, as reflected in the applicant’s Community Benefits Plan. Extent to which the project supports the development or demonstration in disadvantaged communities, supports existing minority business enterprises (MBEs) or promotes the creation of MBEs and underrepresented businesses in disadvantaged communities. Quality of any partnerships and agreements with apprenticeship readiness programs, or community-based workforce training and support organizations serving workers facing systematic barriers to employment to facilitate participation in the project’s construction and operations. Extent of engagement of organizations that represent underserved communities as core element of their mission to include Minority Serving Institutions (MSIs), MBEs, associations, and non-profit organizations. Extent to which the project illustrates the ability to meet or exceed the objectives of the Justice40 initiative, including the extent to which the project benefits disadvantaged, underserved communities or partners with Tribal Nations. Justice40 Initiative Extent to which the Community Benefits Plan identifies: specific, measurable benefits for disadvantaged communities, how the benefits will flow to disadvantaged communities, and how negative environmental impacts affecting disadvantaged communities would be mitigated. Extent to which the project would contribute to meeting the objective that 40% of the benefits of climate and clean energy investments flow to disadvantaged communities. B. Standards for Application Evaluation Applications that are determined to be eligible will be evaluated in accordance with this FOA and the guidance provided in the “DOE Merit Review Guide for Financial Assistance,” effective September 2020, which is available at: https://energy.gov/management/downloads/merit-review-guide-financial- assistance-and-unsolicited-proposals-current. C. Other Selection Factors i. Program Policy Factors In addition to the above criteria, the Selection Official may consider the following program policy factors in determining which Full Applications to select for award negotiations: 100 Page 95 of 142 The degree to which the proposed project exhibits technological diversity when compared to the existing DOE project portfolio and other projects selected from the subject FOA; The degree to which the proposed project, including proposed cost share, optimizes the use of available DOE funding to achieve programmatic objectives; The degree to which the proposed project will deliver the greatest benefits for less Federal cost share; The level of industry involvement and demonstrated ability to accelerate commercialization and overcome key market barriers; For Topic Area 1, the degree to which the applicant supports the availability of information before during and after resilience events through participation in the Outage Data Initiative Nationwide (ODIN),52 a voluntary program to promote increasing standardization of outage data, accessible and achievable by any size utility; The degree to which the proposed project is likely to lead to increased high- quality employment and manufacturing in the United States; The degree to which the proposed project will accelerate transformational technological advances in areas that industry by itself is not likely to undertake because of technical and financial uncertainty; The degree to which the proposed project, or group of projects, represent a desired geographic distribution (considering past awards and current applications), including whether the project is in a community facing job loss in the energy transition; The degree to which the proposed project incorporates diversity, equity, and inclusion elements, including, but not limited to, applicant or team members from Minority Serving Institutions (e.g. Historically Black Colleges and Universities (HBCUs)/Other Minority Institutions), Minority Business Enterprises, Minority Owned Businesses, Woman Owned Businesses, Veteran Owned Businesses, Tribal Nations, or members within underserved communities; The degree to which the proposed project maximizes benefits to disadvantaged communities; The degree to which the proposed project minimizes environmental impacts to disadvantaged communities; The degree to which the project’s solution or strategy will maximize deployment or replication; The degree to which the proposed project leverages existing infrastructure, facilities, and/or workforce skills; The degree to which the proposed project will employ procurement of U.S. iron, steel, manufactured products, and construction materials; 52 More information is available at odin.ornl.gov 101 Page 96 of 142 The degree to which the proposed project, when compared to the existing DOE project portfolio and other projects to be selected from the subject FOA, contributes to the total portfolio meeting the goals reflected in the Community Benefits Plan criteria; The degree to which the proposed project avoids duplication/overlap with other publicly or privately funded work. D. Evaluation and Selection Process i. Overview The evaluation process consists of multiple phases; each includes an initial eligibility review and a thorough technical merit review. Rigorous technical merit reviews of eligible submissions are conducted by reviewers that are experts in the subject matter of the FOA. Ultimately, the Selection Official considers the recommendations of the reviewers, along with other considerations such as program policy factors, in determining which applications to select. ii. Pre-Selection Interviews As part of the evaluation and selection process, DOE may invite one or more applicants to participate in Pre-Selection Interviews. Pre-Selection Interviews are distinct from and more formal than pre-selection clarifications (See Section V.D.ii. of the FOA). The invited applicant(s) will meet with DOE representatives to provide clarification on the contents of the Full Applications and to provide DOE an opportunity to ask questions regarding the proposed project. The information provided by applicants to DOE through Pre-Selection Interviews contributes to DOE’s selection decisions. DOE will arrange to meet with the invited applicants in person at DOE’s offices or a mutually agreed upon location. DOE may also arrange site visits at certain applicants’ facilities. In the alternative, DOE may invite certain applicants to participate in a one-on-one conference with DOE via webinar, videoconference, or conference call. DOE will not reimburse applicants for travel and other expenses relating to the Pre-Selection Interviews, nor will these costs be eligible for reimbursement as pre-award costs. DOE may obtain additional information through Pre-Selection Interviews that will be used to make a final selection determination. DOE may select applications for funding and make awards without Pre-Selection Interviews. Participation in Pre-Selection Interviews with DOE does not signify that applicants have been selected for award negotiations. 102 Page 97 of 142 iii. Pre-Selection Clarification DOE may determine that pre-selection clarifications are necessary from one or more applicants. Pre-selection clarifications are distinct from and less formal than pre-selection interviews. These pre-selection clarifications will solely be for the purposes of clarifying the application. The pre-selection clarifications may occur before, during or after the merit review evaluation process. Information provided by an applicant that is not necessary to address the pre-selection clarification question will not be reviewed or considered. Typically, a pre- selection clarification will be carried out through either written responses to DOE’s written clarification questions or video or conference calls with DOE representatives. The information provided by applicants to DOE through pre-selection clarifications is incorporated in their applications and contributes to the merit review evaluation and DOE’s selection decisions. If DOE contacts an applicant for pre-selection clarification purposes, it does not signify that the applicant has been selected for negotiation of award or that the applicant is among the top ranked applications. DOE will not reimburse applicants for expenses relating to the pre-selection clarifications, nor will these costs be eligible for reimbursement as pre-award costs. iv. Recipient Integrity and Performance Matters DOE, prior to making a federal award with a total amount of federal share greater than the simplified acquisition threshold, is required to review and consider any information about the applicant that is in the designated integrity and performance system accessible through SAM (currently FAPIIS) (see 41 U.S.C. 2313). The applicant, at its option, may review information in the designated integrity and performance systems accessible through SAM and comment on any information about itself that a federal awarding agency previously entered and is currently in the designated integrity and performance system accessible through SAM. DOE will consider any written comments by the applicant, in addition to the other information in the designated integrity and performance system, in making a judgment about the applicant's integrity, business ethics, and record of performance under federal awards when completing the review of risk posed by applicants as described in 2 CFR 200.206. 103 Page 98 of 142 v. Selection The Selection Official may consider the technical merit, the Federal Consensus Board’s recommendations, program policy factors, and the amount of funds available in arriving at selections for this FOA. E. Anticipated Notice of Selection and Award Negotiation Dates DOE anticipates notifying applicants selected for negotiation of award and negotiating awards by the dates provided on the cover page of this FOA. VI.Award Administration Information A. Award Notices i. Ineligible Submissions Ineligible Concept Papers and Full Applications will not be further reviewed or considered for award. The Contracting Officer will send a notification letter by email to the technical and administrative points of contact designated by the applicant The notification letter will state the basis upon which the Concept Paper or the Full Application is ineligible and not considered for further review. ii. Concept Paper Notifications DOE will notify applicants of its determination to encourage or discourage the submission of a Full Application. DOE will send a notification letter by email to the technical and administrative points of contact designated by the applicant in on the Concept Paper cover page. Applicants may submit a Full Application even if they receive a notification discouraging them from doing so. By discouraging the submission of a Full Application, DOE intends to convey its lack of programmatic interest in the proposed project. Such assessments do not necessarily reflect judgments on the merits of the proposed project. The purpose of the Concept Paper phase is to save applicants the considerable time and expense of preparing a Full Application that is unlikely to be selected for award negotiations. A notification encouraging the submission of a Full Application does not authorize the applicant to commence performance of the project. Please refer to Section IV.I.ii. of the FOA for guidance on pre-award costs. 104 Page 99 of 142 iii. Full Application Notifications DOE will notify applicants of its determination via a notification letter by email to the technical and administrative points of contact designated by the applicant in Grants.gov. The notification letter will inform the applicant whether or not its Full Application was selected for award negotiations. Alternatively, DOE may notify one or more applicants that a final selection determination on particular Full Applications will be made at a later date, subject to the availability of funds or other factors. iv. Successful Applicants Receipt of a notification letter selecting a Full Application for award negotiations does not authorize the applicant to commence performance of the project. If an application is selected for award negotiations, it is not a commitment by DOE to issue an award. Applicants do not receive an award until award negotiations are complete and the Contracting Officer executes the funding agreement, accessible by the prime recipient in FedConnect. The award negotiation process will take approximately 60 days. Applicants must designate a primary and a backup point-of-contact in Grants.gov with whom DOE will communicate to conduct award negotiations. The applicant must be responsive during award negotiations (i.e., provide requested documentation) and meet the negotiation deadlines. If the applicant fails to do so or if award negotiations are otherwise unsuccessful, DOE will cancel the award negotiations and rescind the Selection. DOE reserves the right to terminate award negotiations at any time for any reason. Please refer to Section IV.I.ii. of the FOA for guidance on pre-award costs. v. Alternate Selection Determinations In some instances, an applicant may receive a notification that its application was not selected for award and DOE designated the application to be an alternate. As an alternate, DOE may consider the Full Application for federal funding in the future. A notification letter stating the Full Application is designated as an alternate does not authorize the applicant to commence performance of the project. DOE may ultimately determine to select or not select the Full Application for award negotiations. vi. Unsuccessful Applicants DOE shall promptly notify in writing each applicant whose application has not been selected for award or whose application cannot be funded because of the unavailability of appropriated funds. 105 Page 100 of 142 B. Administrative and National Policy Requirements i. Registration Requirements There are several one-time actions before submitting an application in response to this FOA, and it is vital that applicants address these items as soon as possible. Some may take several weeks, and failure to complete them could interfere with an applicant’s ability to apply to this FOA, or to meet the negotiation deadlines and receive an award if the application is selected. These requirements are as follows: 1. System for Award Management Register with the SAM at https://www.sam.gov. Designating an Electronic Business Point of Contact (EBiz POC) and obtaining a special password called a Marketing Partner ID Number (MPIN) are important steps in SAM registration. Please update your SAM registration annually. 2. FedConnect Register in FedConnect at https://www.fedconnect.net. To create an organization account, your organization’s SAM MPIN is required. For more information about the SAM MPIN or other registration requirements, review the FedConnect Ready, Set, Go! Guide at https://www.fedconnect.net/FedConnect/Marketing/Documents/FedConnec t_Ready_Set_Go.pdf. 3. Grants.gov Register in Grants.gov (https://www.grants.gov/)) to receive automatic updates when Amendments to this FOA are posted. However, please note that Concept Papers will not be accepted through Grants.gov. 4. Electronic Authorization of Applications and Award Documents Submission of an application and supplemental information under this FOA through electronic systems used by the DOE, including Grants.gov and FedConnect.net, constitutes the authorized representative’s approval and electronic signature. ii. Award Administrative Requirements The administrative requirements for DOE grants and cooperative agreements are contained in 2 CFR Part 200 as amended by 2 CFR Part 910. iii. Foreign National Participation (September 2021) All applicants selected for an award under this FOA and project participants (including subrecipients and contractors) who anticipate involving foreign nationals in the performance of an award, will be required to provide DOE with 106 Page 101 of 142 specific information about each foreign national to satisfy requirements for foreign national participation. A “foreign national” is defined as any person who is not a United States citizen by birth or naturalization. The volume and type of information collected may depend on various factors associated with the award. DOE concurrence may be required before a foreign national can participate in the performance of any work under an award. Approval for foreign nationals from countries identified on the U.S. Department of State’s list of State Sponsors of Terrorism must be obtained from DOE before they can participate in the performance of any work under an award. iv. Subaward and Executive Reporting Additional administrative requirements necessary for DOE grants and cooperative agreements to comply with the Federal Funding and Transparency Act of 2006 (FFATA) are contained in 2 CFR Part 170. Prime recipients must register with the new FFATA Subaward Reporting System database and report the required data on their first tier subrecipients. Prime recipients must report the executive compensation for their own executives as part of their registration profile in SAM. v. National Policy Requirements The National Policy Assurances that are incorporated as a term and condition of award are located at: http://www.nsf.gov/awards/managing/rtc.jsp. vi. Environmental Review in Accordance with National Environmental Policy Act (NEPA) DOE’s decision whether and how to distribute federal funds under this FOA is subject to NEPA (42 U.S.C. 4321, et seq.). NEPA requires federal agencies to integrate environmental values into their decision-making processes by considering the potential environmental impacts of their proposed actions. For additional background on NEPA, please see DOE’s NEPA website, at https://www.energy.gov/nepa. While NEPA compliance is a federal agency responsibility and the ultimate decisions remain with the federal agency, all recipients selected for an award will be required to assist in the timely and effective completion of the NEPA process in the manner most pertinent to their proposed project. If DOE determines certain records must be prepared to complete the NEPA review process (e.g., biological evaluations or environmental assessments), the recipient may be required to prepare the records and the costs to prepare the necessary records may be included as part of the project costs. 107 Page 102 of 142 vii. Flood Resilience Applications should indicate whether the proposed project location(s) is within a floodplain, how the floodplain was defined, and how future flooding will factor into the project’s design. The base floodplain long used for planning has been the 100-year floodplain, that is, a floodplain with a 1.0 percent chance of flooding in any given year. As directed by Executive Order 13690, Establishing a Federal Flood Risk Management Standard and a Process for Further Soliciting and Considering Stakeholder Input (2015), Federal agencies, including DOE, continue to avoid development in a floodplain to the extent possible. When doing so is not possible, Federal agencies are directed to “expand management from the current base flood level to a higher vertical elevation and corresponding horizontal floodplain to address current and future flood risk and ensure that projects funded with taxpayer dollars last as long as intended.” The higher flood elevation is based on one of three approaches: climate-informed science (preferred), freeboard value, or 0.2 percent annual flood change (500- year floodplain). EO 13690 and related information is available at https://www.energy.gov/nepa/articles/eo-13690-establishing-federal-flood-risk- management-standard-and-process-further. viii. Applicant Representations and Certifications 1. Lobbying Restrictions By accepting funds under this award, the prime recipient agrees that none of the funds obligated on the award shall be expended, directly or indirectly, to influence Congressional action on any legislation or appropriation matters pending before Congress, other than to communicate to Members of Congress as described in 18 U.S.C. § 1913. This restriction is in addition to those prescribed elsewhere in statute and regulation. 2. Corporate Felony Conviction and Federal Tax Liability Representations In submitting an application in response to this FOA, the applicant represents that: a.It is not a corporation that has been convicted of a felony criminal violation under any federal law within the preceding 24 months; and b.It is not a corporation that has any unpaid federal tax liability that has been assessed, for which all judicial and administrative remedies have been exhausted or have lapsed, and that is not being paid in a timely manner pursuant to an agreement with the authority responsible for collecting the tax liability. For purposes of these representations the following definitions apply: 108 Page 103 of 142 A Corporation includes any entity that has filed articles of incorporation in any of the 50 states, the District of Columbia, or the various territories of the United States [but not foreign corporations]. It includes both for- profit and non-profit organizations. 3. Nondisclosure and Confidentiality Agreements Representations In submitting an application in response to this FOA the applicant represents that: a.It does not and will not require its employees or contractors to sign internal nondisclosure or confidentiality agreements or statements prohibiting or otherwise restricting its employees or contactors from lawfully reporting waste, fraud, or abuse to a designated investigative or law enforcement representative of a federal department or agency authorized to receive such information. b.It does not and will not use any federal funds to implement or enforce any nondisclosure and/or confidentiality policy, form, or agreement it uses unless it contains the following provisions: (1)‘‘These provisions are consistent with and do not supersede, conflict with, or otherwise alter the employee obligations, rights, or liabilities created by existing statute or Executive Order relating to (1) classified information, (2) communications to Congress, (3) the reporting to an Inspector General of a violation of any law, rule, or regulation, or mismanagement, a gross waste of funds, an abuse of authority, or a substantial and specific danger to public health or safety, or (4) any other whistleblower protection. The definitions, requirements, obligations, rights, sanctions, and liabilities created by controlling Executive Orders and statutory provisions are incorporated into this agreement and are controlling.’’ (2)The limitation above shall not contravene requirements applicable to Standard Form 312 Classified Information Nondisclosure Agreement (https://fas.org/sgp/othergov/sf312.pdf), Form 4414 Sensitive Compartmented Information Disclosure Agreement (https://fas.org/sgp/othergov/intel/sf4414.pdf), or any other form issued by a federal department or agency governing the nondisclosure of classified information. (3)Notwithstanding the provision listed in paragraph (a), a nondisclosure or confidentiality policy form or agreement that is to be executed by 109 Page 104 of 142 a person connected with the conduct of an intelligence or intelligence-related activity, other than an employee or officer of the United States government, may contain provisions appropriate to the particular activity for which such document is to be used. Such form or agreement shall, at a minimum, require that the person will not disclose any classified information received in the course of such activity unless specifically authorized to do so by the United States government. Such nondisclosure or confidentiality forms shall also make it clear that they do not bar disclosures to Congress, or to an authorized official of an executive agency or the Department of Justice, that are essential to reporting a substantial violation of law. ix. Statement of Federal Stewardship DOE will exercise normal federal stewardship in overseeing the project activities performed under DOE awards. Stewardship Activities include, but are not limited to, conducting site visits; reviewing performance and financial reports; providing assistance and/or temporary intervention in unusual circumstances to correct deficiencies that develop during the project; assuring compliance with terms and conditions; and reviewing technical performance after project completion to ensure that the project objectives have been accomplished. x. Statement of Substantial Involvement (Applies to Topic Area 3 ONLY) DOE has substantial involvement in work performed under awards made as a result of this FOA. DOE does not limit its involvement to the administrative requirements of the award. Instead, DOE has substantial involvement in the direction and redirection of the technical aspects of the project as a whole. Substantial involvement includes, but is not limited to, the following: 1.DOE shares responsibility with the recipient for the management, control, direction, and performance of the project. 2.DOE may intervene in the conduct or performance of work under this award for programmatic reasons. Intervention includes the interruption or modification of the conduct or performance of project activities. 3.DOE may redirect or discontinue funding the project based on the outcome of DOE’s evaluation of the project at the Go/No-Go decision point(s) as identified in the Project Management Plan. 4.Reviewing and concurring with ongoing technical performance to ensure that adequate progress has been obtained within the current Budget Period authorized by DOE before work can commence on subsequent Budget Periods. 110 Page 105 of 142 5.DOE participates in major project decision-making processes. xi. Intellectual Property Management Plan (IPMP) As a quarter 1 milestone if selected for award, applicants must submit an executed IPMP between the members of the consortia or team. The award will set forth the treatment of and obligations related to intellectual property rights between DOE and the individual members. The IPMP should describe how the members will handle intellectual property rights and issues between themselves while ensuring compliance with federal intellectual property laws, regulations, and policies (see Sections VIII.J.-VIII.N. of this FOA for more details on applicable federal intellectual property laws and regulations). Guidance regarding the contents of IPMP is available from DOE upon request. The following is a non-exhaustive list of examples of items that the IPMP may cover: The treatment of confidential information between members (e.g., the use of NDAs); The treatment of background intellectual property (e.g., any requirements for identifying it or making it available); The treatment of inventions made under the award (e.g., any requirements for disclosing to the other members on an application, filing patent applications, paying for patent prosecution, and cross-licensing or other licensing arrangements between the members); The treatment of data produced, including software, under the award (e.g., any publication process or other dissemination strategies, copyrighting strategy or arrangement between members); Any technology transfer and commercialization requirements or arrangements between the members; The treatment of any intellectual property issues that may arise due to a change in membership of the consortia or team; and The handling of disputes related to intellectual property between the members. xii. Intellectual Property Provisions The standard DOE financial assistance intellectual property provisions applicable to the various types of recipients are located at http://energy.gov/gc/standard- intellectual-property-ip-provisions-financial-assistance-awards. xiii. Reporting Reporting requirements are identified on the Federal Assistance Reporting Checklist and Instructions, DOE F 4600.2, attached to the award agreement. A 111 Page 106 of 142 sample checklist is available at: BIL-GRIP Application Forms and Templates | netl.doe.gov. Additional reporting requirements apply to projects funded by BIL. As part of tracking progress toward key departmental goals – ensuring justice and equity, investing in the American workforce, boosting domestic manufacturing, reducing greenhouse gas emissions, and advancing a pathway to private sector deployment – DOE may require specific data collection. Examples of data that may be collected include: New manufacturing production, and recycling capacity Jobs data including Number and types of training jobs provided, wages and benefits paid Demographics of workforce including local hires Efforts to minimize risks of labor disputes and disruptions Contributions to training; certificates and training credentials received by employees; ratio of apprentice-to-journey level workers employed Justice and Equity data, including o Minority Business Enterprises, Minority Owned Businesses, Woman Owned Businesses and Veteran Owned Businesses acting as vendors and sub-contractors for bids on supplies, services and equipment. o Value, number, and type of partnerships with MSIs o Stakeholder engagement events, consent-based siting activities o Other relevant indicators from the Community Benefits Plan Number and type of energy efficient and clean energy equipment installed Funding leveraged, follow-on-funding, Intellectual Property (IP) Generation and IP Utilization Biennial Report to Congress - (Applies to Topic Area 1 ONLY), See Section I.B. for more information. xiv. Go/No-Go Review Each project selected under this FOA will be subject to a periodic project evaluation referred to as a Go/No-Go Review. A Go/No-Go Review is a risk management tool and a project management best practice to ensure that, for the current phase or period of performance, technical success is definitively achieved and potential for success in future phases or periods of performance is evaluated, prior to actually beginning the execution of future phases. At the Go/No-Go decision points, DOE will evaluate project performance, project schedule adherence, the extent milestone objectives are met, compliance with 112 Page 107 of 142 reporting requirements, and overall contribution to the program goals and objectives. Federal funding beyond the Go/No-Go decision point (continuation funding) is contingent upon (1) availability of federal funds appropriated by Congress for the purpose of this program; (2) the availability of future-year budget authority; (3) recipient’s technical progress as compared to the technical milestones, success criteria, and go/no-go decision point as described in the Project Management Plan; (4) recipient’s submittal of required reports; (5) recipient’s compliance with the terms and conditions of the award; (6) the recipient’s submission of a continuation application53; and (7) written approval of the continuation application by the Contracting Officer. As a result of the Go/No-Go Review, DOE may, at its discretion, authorize the following actions: (1) continue to fund the project, contingent upon the availability of funds appropriated by Congress for the purpose of this program and the availability of future-year budget authority; (2) recommend redirection of work under the project; (3) place a hold on federal funding for the project, pending further supporting data or funding; or (4) discontinue funding the project because of insufficient progress, change in strategic direction, or lack of funding. The Go/No-Go decision is distinct from a non-compliance determination. In the event a recipient fails to comply with the requirements of an award, DOE may take appropriate action, including but not limited to, redirecting, suspending or terminating the award. xv. Conference Spending The recipient shall not expend any funds on a conference not directly and programmatically related to the purpose for which the grant or cooperative agreement was awarded that would defray the cost to the United States government of a conference held by any Executive branch department, agency, board, commission, or office for which the cost to the United States government would otherwise exceed $20,000, thereby circumventing the required 53 A continuation application is a non-competitive application for an additional budget period within a previously approved project period. At least ninety (90) days before the end of each budget period, the recipient must submit its continuation application, which includes the following information: i. A progress report on the project objectives, including significant findings, conclusions, or developments, and an estimate of any unobligated balances remaining at the end of the budget period. If the remaining unobligated balance is estimated to exceed 20 percent of the funds available for the budget period, explain why the excess funds have not been obligated and how they will be used in the next budget period. ii. A detailed budget and supporting justification if there are changes to the negotiated budget, or a budget for the upcoming budget period was not approved at the time of award. iii. A description of any planned changes from the SOPO and/or Milestone Summary Table. 113 Page 108 of 142 notification by the head of any such Executive Branch department, agency, board, commission, or office to the Inspector General (or senior ethics official for any entity without an Inspector General), of the date, location, and number of employees attending such conference. xvi. Uniform Commercial Code (UCC) Financing Statements Per 2 CFR 910.360 (Real Property and Equipment) when a piece of equipment is purchased by a for-profit recipient or subrecipient with federal funds, and when the federal share of the financial assistance agreement is more than $1,000,000, the recipient or subrecipient must: Properly record, and consent to the Department's ability to properly record if the recipient fails to do so, UCC financing statement(s) for all equipment in excess of $5,000 purchased with project funds. These financing statement(s) must be approved in writing by the Contracting Officer prior to the recording, and they shall provide notice that the recipient's title to all equipment (not real property) purchased with federal funds under the financial assistance agreement is conditional pursuant to the terms of this section, and that the government retains an undivided reversionary interest in the equipment. The UCC financing statement(s) must be filed before the Contracting Officer may reimburse the recipient for the federal share of the equipment unless otherwise provided for in the relevant financial assistance agreement. The recipient shall further make any amendments to the financing statements or additional recordings, including appropriate continuation statements, as necessary or as the Contracting Officer may direct. xvii. Implementation of Executive Order 13798, Promoting Free Speech and Religious Liberty States, local governments, or other public entities may not condition sub-awards in a manner that would discriminate, or disadvantage sub-recipients based on their religious character. xviii. Participants and Collaborating Organizations If selected for award negotiations, the selected applicant must submit a list of personnel who are proposed to work on the project, both at the recipient and subrecipient level and a list of collaborating organizations within 30 days after the applicant is notified of the selection. Recipients will have an ongoing responsibility to notify DOE of changes to the personnel and collaborating organizations and submit updated information during the life of the award. xix. Requirement to Report Potentially Duplicative Funding If a recipient or project team member receives any other award of federal funds for activities that potentially overlap with the activities funded under the DOE 114 Page 109 of 142 award, the recipient must promptly notify DOE in writing of the potential overlap and state whether project funds from any of those other federal awards have been, are being, or are to be used (in whole or in part) for one or more of the identical cost items under the DOE award. If there are identical cost items, the recipient must promptly notify the DOE Contracting Officer in writing of the potential duplication and eliminate any inappropriate duplication of funding. Also See Section IV.D.xvi. xx. Interim Conflict of Interest Policy for Financial Assistance The DOE interim Conflict of Interest Policy for Financial Assistance (COI Policy)54 is applicable to all non-Federal entities applying for, or that receive, DOE funding by means of a financial assistance award (e.g., a grant, cooperative agreement, or technology investment agreement) and, through the implementation of this policy by the entity, to each senior/key personnel55 who is planning to participate in, or is participating in, the project funded wholly or in part under the DOE financial assistance award. The term “senior/key personnel” means the Program/Project Manager and any other person, regardless of title or position, who is responsible for the purpose, design, conduct, or reporting of a project funded by DOE or proposed for funding by DOE. Recipients must flow down the requirements of the interim COI Policy to any subrecipient non-Federal entities. Further, for DOE funded projects, the recipient must include all financial conflicts of interest (FCOI) (i.e., managed and unmanaged/ unmanageable) in their initial and ongoing FCOI reports. It is understood that non-Federal entities and individuals receiving DOE financial assistance awards will need sufficient time to come into full compliance with DOE’s interim COI Policy. To provide some flexibility, DOE allows for a staggered implementation. Specifically, prior to award, applicants selected for award negotiations must: ensure all senior/key personnel complete their significant financial disclosures; review the disclosures; determine whether a FCOI exists; develop and implement a management plan for FCOIs; and provide DOE with an initial FCOI report that includes all FCOIs (i.e., managed and unmanaged/ unmanageable). Recipients will have 180 days from the date of the award to come into full compliance with the other requirements set forth in DOE’s interim COI Policy. Prior to award, the applicant must certify that it is, or will be within 180 days of the award, compliant with all requirements in the COI Policy. 54 DOE’s interim COI Policy can be found at PF 2022-17 FAL 2022-02 Department of Energy Interim Conflict of Interest Policy Requirements for Financial Assistance. 55 For purposes of this subsection of the FOA, the term “senior/key personnel” has the same meaning as “Investigator” as defined in the DOE interim COI Policy. 115 Page 110 of 142 xxi. Fraud, Waste and Abuse The mission of the DOE Office of Inspector General (OIG) is to strengthen the integrity, economy and efficiency of the Department’s programs and operations including deterring and detecting fraud, waste, abuse and mismanagement. The OIG accomplishes this mission primarily through investigations, audits, and inspections of DOE activities to include grants, cooperative agreements, loans, and contracts. The OIG maintains a Hotline for reporting allegations of fraud, waste, abuse, or mismanagement. To report such allegations, please visit https://www.energy.gov/ig/ig-hotline. Additionally, recipients of DOE awards must be cognizant of the requirements of 2 CFR 200.113 Mandatory disclosures, which states: The non-Federal entity or applicant for a Federal award must disclose, in a timely manner, in writing to the Federal awarding agency or pass-through entity all violations of Federal criminal law involving fraud, bribery, or gratuity violations potentially affecting the Federal award. Non-Federal entities that have received a Federal award including the term and condition outlined in appendix XII of 2 CFR Part 200 are required to report certain civil, criminal, or administrative proceedings to SAM (currently FAPIIS). Failure to make required disclosures can result in any of the remedies described in 2 CFR 200.339. (See also 2 CFR part 180, 31 U.S.C. 3321, and 41 U.S.C. 2313.) [85 FR 49539, Aug. 13, 2020] xxii. Human Subjects Research Research involving human subjects, biospecimens, or identifiable private information conducted with DOE funding is subject to the requirements of DOE Order 443.1C, Protection of Human Research Subjects, 45 CFR Part 46, Protection of Human Subjects (subpart A which is referred to as the “Common Rule”), and 10 CFR Part 745, Protection of Human Subjects. Federal regulation and the DOE Order require review by an Institutional Review Board (IRB) of all proposed human subjects research projects. The IRB is an interdisciplinary ethics board responsible for ensuring that the proposed research is sound and justifies the use of human subjects or their data; the potential risks to human subjects have been minimized; participation is voluntary; and clear and accurate information about the study, the benefits and risks of participating, and how individuals’ data/specimens will be protected/used, is provided to potential participants for their use in determining whether or not to participate. 116 Page 111 of 142 The recipient shall provide the Federal Wide Assurance number identified in item 1) below and the certification identified in item 2) below to DOE prior to initiation of any project that will involve interactions with humans in some way (e.g., through surveys); analysis of their identifiable data (e.g., demographic data and energy use over time); asking individuals to test devices, products, or materials developed through research; and/or testing of commercially available devices in buildings/homes in which humans will be present. Note: This list of examples is illustrative and not all inclusive. No DOE funded research activity involving human subjects, biospecimens, or identifiable private information shall be conducted without: 1) A registration and a Federal Wide Assurance of compliance accepted by the Office of Human Research Protection (OHRP) in the Department of Health and Human Services; and 2) Certification that the research has been reviewed and approved by an Institutional Review Board (IRB) provided for in the assurance. IRB review may be accomplished by the awardee’s institutional IRB; by the Central DOE IRB; or if collaborating with one of the DOE national laboratories, by the DOE national laboratory IRB. The recipient is responsible for ensuring all subrecipients comply and for reporting information on the project annually to the DOE Human Subjects Research Database (HSRD) at https://science.osti.gov/HumanSubjects/Human- Subjects-Database/home. Note: If a DOE IRB is used, no end of year reporting will be needed. Additional information on the DOE Human Subjects Research Program can be found at: HUMAN SUBJECTS Human Subjects Pr... | U.S. DOE Office of Science (SC) (osti.gov). xxiii. Cybersecurity Plan (Applies to Topic Areas 2 & 3 ONLY) Be advised that under Section 40126 of the BIL, the Secretary of Energy has determined that this FOA requires an applicant to submit a Cybersecurity Plan to the DOE prior to the issuance of an award. Each applicant whose Full Application is selected for award negotiations must submit a Cybersecurity Plan during the award negotiations phase. A Cybersecurity Plan explains how basic cybersecurity practices throughout the life of the proposed the project will be maintained. See Appendix E. 117 Page 112 of 142 xxiv. Domestic Content Commitments Be advised that the grant agreement or cooperative agreement for funding between DOE and the awardee will require each recipient: (1) to fulfill the commitments made in its application regarding the procurement of U.S.- produced products, subject to a waiver process by DOE and (2) to fulfill the commitments made in its application regarding the procurement of other key component metals and manufactured products domestically that are deemed available in sufficient and reasonably available quantities or of a satisfactory quality at the time of award negotiation, again subject to a DOE waiver process. xxv. Real Property and Equipment Property disposition will be required at the end of a project if the current fair market value of property exceeds $5,000. For-profit entity disposition requirements are set forth at 2 CFR 910.360. Property disposition requirements for other non-federal entities are set forth in 2 CFR 200.310 – 200.316. Real property and equipment purchased with project funds (federal share and recipient cost share) are subject to the requirements at 2 CFR 200.310, 200.311, 200.313, and 200.316 (non-Federal entities, except for-profit entities) and 2 CFR 910.360 (for-profit entities). For projects selected for award under this FOA, the recipient may take disposition action on the real property and equipment or continue to use the real property and equipment after the conclusion of the award period of performance. Recipients may continue to use the real property and equipment so long as the recipient: a.continues to use the property for the authorized project purposes; b.complies with the applicable reporting requirements and regulatory property standards; and c.requests continued use of the property with its final SF-428 Tangible Personal Property Report and/or SF-429 Real Property Status Report submission during award closeout. The recipient’s written Request for Continued Use must identify the real property and equipment and include: a summary of how the property will be used (must align with the authorized project purposes); a proposed use period, (e.g., perpetuity, until fully depreciated, or a calendar date where the recipient expects to submit disposition instructions); acknowledgement that the that the recipient shall not sell or encumber the property or permit any encumbrance without prior written DOE approval; current fair market value of the property; and an Estimated Useful Life or depreciation schedule for equipment. When the property is no longer needed for authorized project purposes, the recipient must request disposition instructions from DOE. For-profit entity 118 Page 113 of 142 disposition requirements are set forth at 2 CFR 910.360. Property disposition requirements for other non-federal entities are set forth in 2 CFR 200.310 – 200.316. VII.Questions/Agency Contacts Upon the issuance of a FOA, DOE personnel are prohibited from communicating (in writing or otherwise) with applicants regarding the FOA except through the established question and answer process as described below. Specifically, questions regarding this FOA must be submitted through the FedConnect portal. You must register with FedConnect to respond as an interested party to submit questions. It is recommended that you register as soon after release of the FOA as possible to have the benefit of all responses. Applicants are encouraged to review previously issued Questions and Answers prior to the submission of questions. Questions and comments concerning this FOA shall be submitted not later than 5 business days prior to the application due date. Please note, feedback on individual concepts will not be provided through Q&A. All questions and answers related to this FOA will be posted on the FedConnect portal at: https://www.FedConnect.net and on the Grid Resilience and Innovation Partnerships (GRIP) Program web page at: Grid Resilience Innovation Partnership Programs | Department of Energy. DOE will attempt to respond to a question within 3 business days unless a similar question and answer has already been posted on the website. Questions relating to the registration process, system requirements, how an application form works, or the submittal process must be directed to Grants.gov at 1-800-518-4726 or support@grants.gov. DOE/NNSA cannot answer these questions. VIII.Other Information A. FOA Modifications Amendments to this FOA will be posted on the Grants.gov system and the FedConnect portal. However, you will only receive an email when an amendment or a FOA is posted on these sites by registering with FedConnect as an interested party for this FOA. DOE recommends that you register as soon 119 Page 114 of 142 after the release of the FOA as possible to ensure you receive timely notice of any amendments or other FOAs. B. Government Right to Reject or Negotiate DOE reserves the right, without qualification, to reject any or all applications received in response to this FOA and to select any application, in whole or in part, as a basis for negotiation and/or award. C. Commitment of Public Funds The Contracting Officer is the only individual who can make awards or commit the government to the expenditure of public funds. A commitment by anyone other than the Contracting Officer, either express or implied, is invalid. D. Treatment of Application Information Applicants should not include business sensitive (e.g., commercial or financial information that is privileged or confidential), trade secrets, proprietary, or otherwise confidential in their application unless such information is necessary to convey an understanding of the proposed project or to comply with a requirement in the FOA. Applicants are advised to not include any critically sensitive proprietary detail. If an application includes business sensitive, trade secrets, proprietary, or otherwise confidential information, it is furnished to the Federal Government (Government) in confidence with the understanding that the information shall be used or disclosed only for evaluation of the application. Such information will be withheld from public disclosure to the extent permitted by law, including the Freedom of Information Act. Without assuming any liability for inadvertent disclosure, DOE will seek to limit disclosure of such information to its employees and to outside reviewers when necessary for merit review of the application or as otherwise authorized by law. This restriction does not limit the Government’s right to use the information if it is obtained from another source. If an applicant chooses to submit business sensitive, trade secrets, proprietary, or otherwise confidential information, the applicant must provide two copies of the submission (e.g., Concept Paper, Full Application). The first copy should be marked, “non-confidential” with the information believed to be confidential deleted. The second copy should be marked “confidential” and must clearly and conspicuously identify the business sensitive, trade secrets, proprietary, or otherwise confidential information and must be marked as described below. Failure to comply with these marking requirements may result in the disclosure of the unmarked information under the Freedom of Information Act or otherwise. The Government is not liable for the disclosure or use of unmarked information and may use or disclose such information for any purpose. 120 Page 115 of 142 The cover sheet of the Full Application, and other submission must be marked as follows and identify the specific pages business sensitive, trade secrets, proprietary, or otherwise confidential information: Notice of Restriction on Disclosure and Use of Data: Pages [list applicable pages] of this document may contain business sensitive, trade secrets, proprietary, or otherwise confidential information that is exempt from public disclosure. Such information shall be used or disclosed only for evaluation purposes or in accordance with a financial assistance agreement between the submitter and the Government. The Government may use or disclose any information that is not appropriately marked or otherwise restricted, regardless of source. [End of Notice] In addition, (1) the header and footer of every page that contains business sensitive, trade secrets, proprietary, or otherwise confidential information must be marked as follows: “Contains Business Sensitive, Trade Secrets, Proprietary, or Otherwise Confidential Information Exempt from Public Disclosure,” and (2) every line or paragraph containing such information must be clearly marked with double brackets or highlighting. DOE will make its own determination about the confidential status of the information and treat it according to its determination. E. Evaluation and Administration by Non-Federal Personnel In conducting the technical merit review evaluation, the Go/No-Go Reviews and Peer Reviews, the government may seek the advice of qualified non-federal personnel as reviewers. The government may also use non-federal personnel to conduct routine, nondiscretionary administrative activities, including DOE contractors. The applicant, by submitting its application, consents to the use of non-federal reviewers/administrators. Non-federal reviewers must sign conflict of interest (COI) and non-disclosure acknowledgements (NDA) prior to reviewing an application. Non-federal personnel conducting administrative activities must sign an NDA.-federal personnel conducting administrative activities must sign an NDA. F. Notice Regarding Eligible/Ineligible Activities Eligible activities under this FOA include those which describe and promote the understanding of scientific and technical aspects of specific energy technologies, but not those which encourage or support political activities such as the collection and dissemination of information related to potential, planned or pending legislation. 121 Page 116 of 142 G. Notice of Right to Conduct a Review of Financial Capability DOE reserves the right to conduct an independent third-party review of financial capability for applicants that are selected for negotiation of award (including personal credit information of principal(s) of a small business if there is insufficient information to determine financial capability of the organization).). H. Requirement for Full and Complete Disclosure Applicants are required to make a full and complete disclosure of all information requested. Any failure to make a full and complete disclosure of the requested information may result in: The termination of award negotiations; The modification, suspension, and/or termination of a funding agreement; The initiation of debarment proceedings, debarment, and/or a declaration of ineligibility for receipt of federal contracts, subcontracts, and financial assistance and benefits; and Civil and/or criminal penalties. I.Retention of Submissions DOE expects to retain copies of all Full Applications and other submissions. No submissions will be returned. By applying to DOE for funding, applicants consent to DOE’s retention of their submissions. J.Rights in Technical Data Data rights differ based on whether data is first produced under an award or instead was developed at private expense outside the award. “Limited Rights Data”: The U.S. government will not normally require delivery of confidential or trade secret-type technical data developed solely at private expense prior to issuance of an award, except as necessary to monitor technical progress and evaluate the potential of proposed technologies to reach specific technical and cost metrics. Government Rights in Technical Data Produced Under Awards: The U.S. government normally retains unlimited rights in technical data produced under government financial assistance awards, including the right to distribute to the public. However, pursuant to special statutory authority, certain categories of data generated under DOE awards may be protected from public disclosure for up to five years after the data is generated (“Protected Data”). For awards permitting Protected Data, the protected data must be marked as set forth in the award’s intellectual property terms and conditions and a listing of unlimited rights data (i.e., non-protected data) must be inserted into the data clause in the 122 Page 117 of 142 award. In addition, invention disclosures may be protected from public disclosure for a reasonable time in order to allow for filing a patent application. For this FOA, selectees and recipients may request an extended period of protection (more than five years and not to exceed thirty years) if reasonably required for commercialization for specific categories of data for all Topic Areas first produced under the resulting awards in accordance with 15 U.S.C. § 3710a(c)(7)(B)(ii) and the Energy Policy Acts of 1992 and 2005. Further direction will be provided during the negotiation process upon request. K. Copyright The prime recipient and subrecipients may assert copyright in copyrightable works, such as software, first produced under the award without DOE approval. When copyright is asserted, the government retains a paid-up nonexclusive, irrevocable worldwide license to reproduce, prepare derivative works, distribute copies to the public, and to perform publicly and display publicly the copyrighted work. This license extends to contractors and others doing work on behalf of the government. L. Export Control The U.S. government regulates the transfer of information, commodities, technology, and software considered to be strategically important to the U.S. to protect national security, foreign policy, and economic interests without imposing undue regulatory burdens on legitimate international trade. There is a network of federal agencies and regulations that govern exports that are collectively referred to as “Export Controls”. All recipients and subrecipients are responsible for ensuring compliance with all applicable U.S. Export Control laws and regulations relating to any work performed under a resulting award. The recipient must immediately report to DOE any export control violations related to the project funded under the DOE award, at the recipient or subrecipient level, and provide the corrective action(s) to prevent future violations. M. Prohibition on Certain Telecommunications and Video Surveillance Services or Equipment As set forth in 2 CFR 200.216, recipients and subrecipients are prohibited from obligating or expending project funds (federal funds and recipient cost share) to: (1) Procure or obtain; (2) Extend or renew a contract to procure or obtain; or 123 Page 118 of 142 (3) Enter into a contract (or extend or renew a contract) to procure or obtain equipment, services, or systems that uses covered telecommunications equipment or services as a substantial or essential component of any system, or as critical technology as part of any system. As described in Public Law 115-232, section 889, covered telecommunications equipment is telecommunications equipment produced by Huawei Technologies Company or ZTE Corporation (or any subsidiary or affiliate of such entities). See Public Law 115-232, section 889, and 2 CFR 200.471 for additional information. N. Personally Identifiable Information (PII) All information provided by the applicant must to the greatest extent possible exclude PII. The term “PII” refers to information which can be used to distinguish or trace an individual's identity, such as their name, social security number, biometric records, alone, or when combined with other personal or identifying information which is linked or linkable to a specific individual, such as date and place of birth, mother’s maiden name. (See OMB Memorandum M-07-16 dated May 22, 2007, found at: M-07-16 (whitehouse.gov). By way of example, applicants must screen resumes to ensure that they do not contain PII such as personal addresses, personal landline/cell phone numbers, and personal emails. Under no circumstances should Social Security Numbers (SSNs) be included in the application. Federal agencies are prohibited from the collecting, using, and displaying unnecessary SSNs. (See, the Federal Information Security Modernization Act of 2014 (Pub. L. No. 113-283, Dec 18, 2014; 44 U.S.C. § 3551). O. Annual Independent Audits If a for-profit entity is a prime recipient and has expended $750,000 or more of DOE awards during the entity's fiscal year, an annual compliance audit performed by an independent auditor is required. For additional information, please refer to 2 CFR 910.501 and Subpart F. If an educational institution, non-profit organization, or state/local government is a prime recipient or subrecipient and has expended $750,000 or more of federal awards during the non-federal entity's fiscal year, then a Single or Program-Specific Audit is required. For additional information, please refer to 2 CFR 200.501 and Subpart F. Applicants and subrecipients (if applicable) should propose sufficient costs in the project budget to cover the costs associated with the audit. DOE will share in the cost of the audit at its applicable cost share ratio. 124 Page 119 of 142 P. Informational Webinars Initial Webinar DOE will conduct one informational webinar at the date and time listed in the table on the FOA cover page prior to concept paper submission due dates. The purpose of this webinar is to give applicants a chance to ask questions about the FOA process generally. As the webinar will be open to all Applicants who wish to participate, Applicants should refrain from asking questions or communicating information that would reveal confidential and/or proprietary information specific to their project. Additional Webinars Additional webinars are scheduled. See below for schedule and agenda information. Webinar registration information will be provided on the Grid Resilience and Innovation Partnerships (GRIP) Program web page at: Grid Resilience Innovation Partnership Programs | Department of Energy. Questions will not be taken as part of these webinars. February 27 | 1-2 PM EST Agenda This webinar will cover information such as community and labor engagement, advancing Diversity Equity Inclusion and Accessibility, and the Justice40 initiative. As a prospective applicant to the FY 2022/2023 GRIP program, applicants will learn best practices for proposing meaningful Community Benefits Plans with tangible objectives to ensure the best community outcomes as part of these applications. February 28 | 1-3 PM EST Agenda This webinar will provide industry stakeholders with cybersecurity planning to help prospective applicants enhance current efforts to improve the reliability, resiliency, and security of the U.S. power grid. Topics covered will include security risk evaluation, mitigation measures , and other security best practices from early development stages to implementation. The session will be conducted by our expert security team from DOE National Labs and provide training on cybersecurity planning and security best practices. Attendance is not mandatory for the webinars and will not positively or negatively impact the overall review of any applicant submissions. Recordings of the webinars will be made available on the GRIP Program web page at: Grid Resilience Innovation Partnership Programs | Department of Energy. 125 Page 120 of 142 APPENDIX A – COST SHARE INFORMATION Cost Sharing or Cost Matching The terms “cost sharing” and “cost matching” are often used synonymously. Even the DOE Financial Assistance Regulations, 2 CFR 200.306, use both of the terms in the titles specific to regulations applicable to cost sharing. The difference between the two terms is the calculation used to determine the non-federal amount. “Cost sharing” for the non-federal share is calculated as a percentage of the Total Project Cost. “Cost matching” for the non-federal share is calculated as a percentage of the federal funds only, rather than the Total Project Cost. How Cost Sharing Is Calculated As stated above, cost sharing is calculated as a percentage of the Total Project Cost. The following is an example of how to calculate cost sharing amounts for a project with $1,000,000 in federal funds with a minimum 20% non-federal cost sharing requirement: Formula A: Federal share ($) divided by federal share (%) = Total Project Cost ($) Example: $1,000,000 divided by 80% = $1,250,000 Formula B: Total Project Cost ($) minus federal share ($) = Non-federal share ($) Example: $1,250,000 minus $1,000,000 = $250,000 Formula C: Non-federal share ($) divided by Total Project Cost ($) = Non-federal share (%) Example: $250,000 divided by $1,250,000 = 20% How Cost Matching Is Calculated “Cost matching” for the non-federal share is calculated as a percentage of the Federal funds only, rather than the Total Project Cost. The following are examples of how to calculate cost matching amounts for a project with $1,000,000 in federal funds with a minimum 20% non- federal cost matching requirement: Formula D: Federal share ($) multiplied by non-federal share (%) = Non-federal match ($) Example: $1,000,000 multiplied by 20% = $200,000 Formula E: Federal Share ($) plus Non-Federal Match ($) = Total Project Cost ($) Example: $1,000,000 plus $200,000 = $1,200,000 Formula F: Total Project Cost ($) minus federal share ($) = Non-federal match ($) Example: $1,200,000 minus $1,000,000 = $200,000 126 Page 121 of 142 Formula G: Federal share ($) divided by Total Project Cost ($) = Calculated Federal Share of Total Project Cost (%) Example: $1,000,000 divided by $1,200,000 = 83.33% Formula C: Non-Federal share ($) divided by Total Project Cost ($) = Calculated Non- Federal Share of Total Project Cost (%) Example: $200,000 divided by $1,200,000 = 16.67% The tables below provide additional examples of calculation results for the cost match (Topic Area 1) and cost share (Topic Areas 2 and 3) for the three BIL Topic Areas: Maximum Federal Share ($)Entity Type Non-Federal Minimum Match Required (%) Calculated Non- Federal Mininum Match ($)D Total Project Cost ($)E Calculated Federal Share of Total Project Costs (%)G Calculated Non-Federal Share of Total Project Costs (%)c $100,000,000 Eligible Entity (except for Small Utilities)100 $100,000,000 $200,000,000 50 50 $100,000,000 Small Utility 33.33 $33,330,000 $133,330,000 75 25 Topic Area 1: Section 40101 ( c) Grid Resilience Grants ($100M Maximum Grant (Federal Share $). An eligible entity shall be required to match 100% of the amount of the grant (except for Small Utilities must match 1/3 of the grant). Maximum Federal Share ($)Entity Type Non-Federal Cost Share Minimum % of Total Project Costs (%) Calculated Non- Federal Mininum Share ($)B Total Project Cost ($)A Calculated Non- Federal Mininum Share (%)C $50,000,000 Eligible Entity 50 $50,000,000 $100,000,000 50 Topic Area 2: Section 40107 Smart Grid Grants ($50M Maximum Grant (Federal Share $). The non-federal cost share must be at least 50% of the Total Project Costs. 127 Page 122 of 142 What Qualifies For Cost Sharing? While it is not possible to explain what specifically qualifies for cost sharing in one or even a couple of sentences, in general, if a cost is allowable under the cost principles applicable to the organization incurring the cost and is eligible for reimbursement under a DOE grant or cooperative agreement, then it is allowable as cost share. Conversely, if the cost is not allowable under the cost principles and not eligible for reimbursement, then it is not allowable as cost share. In addition, costs may not be counted as cost share if they are paid by the federal government under another award unless authorized by federal statute to be used for cost sharing. The rules associated with what is allowable as cost share are specific to the type of organization that is receiving funds under the grant or cooperative agreement, though are generally the same for all types of entities. The specific rules applicable to: FAR Part 31 for For-Profit entities, (48 CFR Part 31); and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities. In addition to the regulations referenced above, other factors may also come into play such as timing of donations and length of the project period. For example, the value of ten years of donated maintenance on a project that has a project period of five years would not be fully allowable as cost share. Only the value for the five years of donated maintenance that corresponds to the project period is allowable and may be counted as cost share. Additionally, DOE generally does not allow pre-award costs for either cost share or reimbursement when these costs precede the signing of the appropriation bill that funds the award. In the case of a competitive award, DOE generally does not allow pre-award costs prior to the signing of the Selection Statement by the DOE Selection Official. General Cost Sharing Rules on a DOE Award Federal Share ($) Entity Type Non-Federal Cost Share Minimum % of Total Project Costs (%) Calculated Non- Federal Mininum Share ($)B Total Project Cost ($)A Calculated Non- Federal Mininum Share (%)C $250,000,000 Eligible Entity 50 $250,000,000 $500,000,000 50 $1,000,000,000 Eligible Entity 50 $1,000,000,000 $2,000,000,000 50 Topic Area 3: SECTION 40103 (b) Innovative Grid Resilience Program Example breakdown for $250M and $1B maximum Grant (Federal Share $) The non-federal cost share must be at least 50% of the Total Project Costs. 128 Page 123 of 142 1.Cash Cost Share – encompasses all contributions to the project made by the recipient or subrecipient(s), for costs incurred and paid for during the project. This includes when an organization pays for personnel, supplies, equipment for their own company with organizational resources. If the item or service is reimbursed for, it is cash cost share. All cost share items must be necessary to the performance of the project. 2.In-Kind Cost Share – encompasses all contributions to the project made by the recipient or subrecipient(s) that do not involve a payment or reimbursement and represent donated items or services. In-Kind cost share items include volunteer personnel hours, donated existing equipment, donated existing supplies. The cash value and calculations thereof for all In-Kind cost share items must be justified and explained in the Cost Share section of the project Budget Justification. All cost share items must be necessary to the performance of the project. If questions exist, consult your DOE contact before filling out the In-Kind cost share section of the Budget Justification. 3.Funds from other federal sources MAY NOT be counted as cost share. Non-federal sources include any source not originally derived from federal funds. Cost sharing commitment letters from subrecipients must be provided with the original application. 4.Fee or profit, including foregone fee or profit, are not allowable as project costs (including cost share) under any resulting award. The project may only incur those costs that are allowable and allocable to the project (including cost share) as determined in accordance with the applicable cost principles prescribed in FAR Part 31 for For-Profit entities and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities. DOE Financial Assistance Rules 2 CFR Part 200 as amended by 2 CFR Part 910 As stated above, the rules associated with what is allowable cost share are generally the same for all types of organizations. Following are the rules found to be common, but again, the specifics are contained in the regulations and cost principles specific to the type of entity: (A)Acceptable contributions. All contributions, including cash contributions and third-party in-kind contributions, must be accepted as part of the prime recipient's cost sharing if such contributions meet all of the following criteria: (1)They are verifiable from the recipient's records. (2)They are not included as contributions for any other federally-assisted project or program. (3)They are necessary and reasonable for the proper and efficient accomplishment of project or program objectives. 129 Page 124 of 142 (4)They are allowable under the cost principles applicable to the type of entity incurring the cost as follows: a.For-profit organizations. Allowability of costs incurred by for-profit organizations and those nonprofit organizations listed in Attachment C to OMB Circular A–122 is determined in accordance with the for-profit cost principles in 48 CFR Part 31 in the FAR, except that patent prosecution costs are not allowable unless specifically authorized in the award document. (v) Commercial Organizations. FAR Subpart 31.2—Contracts with Commercial Organizations; and b.Other types of organizations. For all other non-federal entities, allowability of costs is determined in accordance with 2 CFR Part 200 Subpart E. (5)They are not paid by the federal government under another award unless authorized by federal statute to be used for cost sharing or matching. (6)They are provided for in the approved budget. (B)Valuing and documenting contributions (1)Valuing recipient's property or services of recipient's employees. Values are established in accordance with the applicable cost principles, which mean that amounts chargeable to the project are determined on the basis of costs incurred. For real property or equipment used on the project, the cost principles authorize depreciation or use charges. The full value of the item may be applied when the item will be consumed in the performance of the award or fully depreciated by the end of the award. In cases where the full value of a donated capital asset is to be applied as cost sharing or matching, that full value must be the lesser or the following: a.The certified value of the remaining life of the property recorded in the recipient's accounting records at the time of donation; or b.The current fair market value. If there is sufficient justification, the Contracting Officer may approve the use of the current fair market value of the donated property, even if it exceeds the certified value at the time of donation to the project. The Contracting Officer may accept the use of any reasonable basis for determining the fair market value of the property. (2)Valuing services of others' employees. If an employer other than the recipient furnishes the services of an employee, those services are valued at the employee's regular rate of pay, provided these services are for the same skill level for which the employee is normally paid. (3)Valuing volunteer services. Volunteer services furnished by professional and technical personnel, consultants, and other skilled and unskilled labor may be 130 Page 125 of 142 counted as cost sharing or matching if the service is an integral and necessary part of an approved project or program. Rates for volunteer services must be consistent with those paid for similar work in the recipient's organization. In those markets in which the required skills are not found in the recipient organization, rates must be consistent with those paid for similar work in the labor market in which the recipient competes for the kind of services involved. In either case, paid fringe benefits that are reasonable, allowable, and allocable may be included in the valuation. (4)Valuing property donated by third parties. a.Donated supplies may include such items as office supplies or laboratory supplies. Value assessed to donated supplies included in the cost sharing or matching share must be reasonable and must not exceed the fair market value of the property at the time of the donation. b.Normally only depreciation or use charges for equipment and buildings may be applied. However, the fair rental charges for land and the full value of equipment or other capital assets may be allowed, when they will be consumed in the performance of the award or fully depreciated by the end of the award, provided that the Contracting Officer has approved the charges. When use charges are applied, values must be determined in accordance with the usual accounting policies of the recipient, with the following qualifications: i.The value of donated space must not exceed the fair rental value of comparable space as established by an independent appraisal of comparable space and facilities in a privately-owned building in the same locality. ii.The value of loaned equipment must not exceed its fair rental value. (5)Documentation. The following requirements pertain to the recipient's supporting records for in-kind contributions from third parties: a.Volunteer services must be documented and, to the extent feasible, supported by the same methods used by the recipient for its own employees. b.The basis for determining the valuation for personal services and property must be documented. 131 Page 126 of 142 APPENDIX B – WAIVER REQUESTS FOR: FOREIGN ENTITY PARTICIPATION; AND FOREIGN WORK Waiver for Foreign Entity Participation For projects selected under this FOA, all recipients and subrecipients must be organized, chartered or incorporated (or otherwise formed) under the laws of a state or territory of the United States and have a physical location for business operations in the United States. To request a waiver of this requirement, an applicant must submit an explicit waiver request in the Full Application. WAIVER CRITERIA Foreign entities seeking to participate in a project funded under this FOA must demonstrate to the satisfaction of DOE that: a.Its participation is in the best interest of the U.S. industry and U.S. economic development; b. The project team has appropriate measures in place to control sensitive information and protect against unauthorized transfer of scientific and technical information; c. Adequate protocols exist between the U.S. subsidiary and its foreign parent organization to comply with export control laws and any obligations to protect proprietary information from the foreign parent organization; d. The work is conducted within the U.S. and the entity acknowledges and demonstrates that it has the intent and ability to comply with the U.S. Competitiveness Provision; and e. The foreign entity will satisfy other conditions that may be deemed necessary by DOE to protect U.S. government interests. Content for Waiver Request A Foreign Entity waiver request must include the following: a. Information about the entity: name, point of contact, and proposed type of involvement with the Institute; b. Country of incorporation, the extent of the ownership/level control by foreign entities, whether the entity is state owned or controlled, a summary of the ownership breakdown of the foreign entity and the percentage of ownership/control by foreign entities, foreign shareholders, foreign state or foreign individuals; c. The rationale for proposing a foreign entity participate (must address criteria above); d. A description of the project’s anticipated contributions to the U.S. economy; 132 Page 127 of 142 How the project will benefit the U.S., including manufacturing, contributions to employment in the U.S. and growth in new markets and jobs in the U.S.; How the project will promote domestic American manufacturing of products and/or services; e. A description of how the foreign entity’s participation is essential to the project; f. A description of the likelihood of Intellectual Property (IP) being created from the work and the treatment of any such IP; and g. Countries where the work will be performed (Note: if any work is proposed to be conducted outside the U.S., the applicant must also complete a separate request foreign work waiver). DOE may also require: A risk assessment with respect to IP and data protection protocols that includes the export control risk based on the data protection protocols, the technology being developed and the foreign entity and country. These submissions could be prepared by the project lead, but the prime recipient must make a representation to DOE as to whether it believes the data protection protocols are adequate and make a representation of the risk assessment – high, medium or low risk of data leakage to a foreign entity. Additional language be added to any agreement or subagreement to protect IP, mitigate risk or other related purposes. DOE may require additional information before considering the waiver request. The applicant does not have the right to appeal DOE’s decision concerning a waiver request. Waiver for Performance of Work in the United States (Foreign Work Waiver) As set forth in Section IV.I.iii., all work under funding under this FOA must be performed in the United States. To seek a waiver of the Performance of Work in the United States requirement, the applicant must submit an explicit waiver request in the Full Application. A separate waiver request must be submitted for each entity proposing performance of work outside of the United States. Overall, a waiver request must demonstrate to the satisfaction of DOE that it would further the purposes of this FOA and is otherwise in the economic interests of the United States to perform work outside of the United States. A request for a foreign work waiver must include the following: The rationale for performing the work outside the U.S. (“foreign work”); A description of the work proposed to be performed outside the U.S.; 133 Page 128 of 142 An explanation as to how the foreign work is essential to the project; A description of the anticipated benefits to be realized by the proposed foreign work and the anticipated contributions to the US economy; The associated benefits to be realized and the contribution to the project from the foreign work; How the foreign work will benefit the U.S., including manufacturing, contributions to employment in the U.S. and growth in new markets and jobs in the U.S.; How the foreign work will promote domestic American manufacturing of products and/or services; A description of the likelihood of Intellectual Property (IP) being created from the foreign work and the treatment of any such IP; The total estimated cost (DOE and recipient cost share) of the proposed foreign work; The countries in which the foreign work is proposed to be performed; and The name of the entity that would perform the foreign work. DOE may require additional information before considering the waiver request. The applicant does not have the right to appeal DOE’s decision concerning a waiver request. 134 Page 129 of 142 APPENDIX C – REQUIRED USE OF IRON, STEEL, MANUFACTURED PRODUCTS, AND CONSTRUCTION MATERIALS PRODUCED IN THE UNITED STATES BUY AMERICA REQUIREMENTS FOR INFRASTRUCTURE PROJECTS A. Definitions For purposes of the Buy America requirements, the following definitions apply: Construction materials includes an article, material, or supply—other than an item of primarily iron or steel; a manufactured product; cement and cementitious materials; aggregates such as stone, sand, or gravel; or aggregate binding agents or additives56 —that is or consists primarily of: • non-ferrous metals; • plastic and polymer-based products (including polyvinylchloride, composite building materials, and polymers used in fiber optic cables); • glass (including optic glass); • lumber; or • drywall. Applicants may also seek a DOE waiver of domestic procurement requirements based on applicable public interest factors, such as relating to minor components, international trade obligations, or other considerations. Infrastructure includes, at a minimum, the structures, facilities, and equipment for, in the United States, Roads, highways, and bridges; public transportation; Dams, ports, harbors, and other maritime facilities; InterCity passenger and freight railroads; Freight and intermodal facilities; airports; Water systems, including drinking water and wastewater systems; Electrical transmission facilities and systems; utilities; broadband infrastructure; and buildings and real property. Infrastructure includes facilities that generate, transport, and distribute energy. In addition to the above, the infrastructure in question must be publicly-owned or must serve a public function; privately owned infrastructure that is solely utilized for private use is not considered “infrastructure” for purposes of Buy America applicability. The Agency, not the applicant, will have the final say as to whether a given project includes infrastructure, as defined herein. 56 BIL, § 70917(c)(1). 135 Page 130 of 142 For this FOA specifically, all projects subject to this FOA are considered “infrastructure” within the Buy America provision of BIL. Project means the construction, alteration, maintenance, or repair of infrastructure in the United States. B. Buy America Requirements for Infrastructure Projects (“Buy America” requirements) In accordance with section 70914 of the BIL, none of the project funds (includes federal share and recipient cost share) may be used for a project for infrastructure unless: (1) all iron and steel used in the project are produced in the United States--This means all manufacturing processes, from the initial melting stage through the application of coatings, occurred in the United States; (2) all manufactured products used in the project are produced in the United States— this means the manufactured product was manufactured in the United States; and the cost of the components of the manufactured product that are mined, produced, or manufactured in the United States is greater than 55 percent of the total cost of all components of the manufactured product, unless another standard for determining the minimum amount of domestic content of the manufactured product has been established under applicable law or regulation; and (3) all construction materials57 are manufactured in the United States—this means that all manufacturing processes for the construction material occurred in the United States. The Buy America requirements only apply to articles, materials, and supplies that are consumed in, incorporated into, or affixed to an infrastructure project. As such, it does not apply to tools, equipment, and supplies, such as temporary scaffolding, brought to the construction site and removed at or before the completion of the infrastructure project. Nor does the Buy America requirements apply to equipment and furnishings, such as movable chairs, desks, and portable computer equipment, that are used at or within the finished infrastructure project, but are not an integral part of the structure or permanently affixed to the infrastructure project. These requirements must flow down to all sub-awards, all contracts, subcontracts and purchase orders for work performed under the proposed project, except where the prime recipient is a for-profit entity. Based on guidance from Office of Management and Budget (OMB) Memorandum M-22-11, the Buy America requirements of the BIL do not apply to DOE projects in which the prime recipient is a for-profit entity; the requirements only apply to projects whose prime recipient is a State, local government, Indian tribe, Institution of Higher Education, or nonprofit organization. 57 Excludes cement and cementitious materials, aggregates such as stone, sand, or gravel, or aggregate binding agents or additives. 136 Page 131 of 142 For additional information related to the application and implementation of these Buy America requirements, please see OMB Memorandum M-22-11, issued April 18, 2022: https://www.whitehouse.gov/wp-content/uploads/2022/04/M-22-11.pdf Note that for all applicants—both non-Federal entities and for-profit entities—DOE is including a Program Policy Factor that the Selection Official may consider in determining which Full Applications to select for award negotiations that considers whether the applicant has made a commitment to procure U.S. iron, steel, manufactured products, and construction materials in its project. C. DOE Submission Requirements for Full Application Within the first two pages of the workplan, applicants must provide a short statement on whether the project will involve the construction, alteration, and/or repair of infrastructure in the United States. The ultimate determination about whether a project includes infrastructure remains with DOE, but the applicant’s statement will assist project planning and integration of domestic preference requirements, which may impact the project’s proposed budget. D. Waivers In limited circumstances, DOE may waive the application of the Buy America requirements where DOE determines that: (1) applying the Buy America requirements would be inconsistent with the public interest; (2) the types of iron, steel, manufactured products, or construction materials are not produced in the United States in sufficient and reasonably available quantities or of a satisfactory quality; or (3) the inclusion of iron, steel, manufactured products, or construction materials produced in the United States will increase the cost of the overall project by more than 25 percent. If an applicant is seeking a waiver of the Buy America requirements, it must include a written waiver request with the Full Application. A waiver request must include: A detailed justification for the use of “non-domestic” iron, steel, manufactured products, or construction materials to include an explanation as to how the non- domestic item(s) is essential to the project A certification that the applicant or recipient made a good faith effort to solicit bids for domestic products supported by terms included in requests for proposals, contracts, and nonproprietary communications with potential suppliers; Applicant /Recipient name and Unique Entity Identifier (UEI) Total estimated project cost, DOE and cost-share amounts 137 Page 132 of 142 Project description and location (to the extent known) List and description of iron or steel item(s), manufactured goods, and construction material(s) the applicant or recipient seeks to waive from Domestic Content Procurement Preference requirement, including name, cost, country(ies) of origin (if known), and relevant PSC and NAICS code for each. Waiver justification including due diligence performed (e.g., market research, industry outreach) by the applicant or recipient Anticipated impact if no waiver is issued DOE may require additional information before considering the waiver request. Waiver requests are subject to public comment periods of no less than 15 days and must be reviewed by the Made in America Office. There may be instances where an award qualifies, in whole or in part, for an existing waiver described at https://www.madeinamerica.gov/financial- assistance/. The applicant does not have the right to appeal DOE’s decision concerning a waiver request. 138 Page 133 of 142 APPENDIX D – STATEMENT OF PROJECT OBJECTIVES Background/Instructions: Prospective recipients of awards funded from Funding Opportunity Announcement DE-FOA-0002740 (FOA 2740) must prepare/submit a detailed statement of project objectives (SOPO) that addresses how the project objectives will be met. The SOPO must contain a clear, concise description of all activities that will be completed during project performance and follow the structure/format outlined below. Since the SOPO may be released (in whole or in part) to the public by the Department of Energy (DOE) after award, it shall not contain proprietary or confidential business information. The SOPO generally consists of less than five (5) pages to describe the proposed work. Prospective recipients of FOA 2740 funding (FOA 2740 Recipient) shall prepare the SOPO according to the format provided in the SOPO template and in accordance with the application content and form requirements identified in Section IV Of the FOA. This Background/Instructions section as well as italicized text in the SOPO template is intended to be instructional, is provided as guidance, and should be removed by the FOA 2740 recipient when preparing their SOPO. All other text (shown as normal font within the SOPO template) is to be included in the proposed SOPO. In writing the Statement of Project Objectives (SOPO), avoid: 1) the use of proper nouns to minimize SOPO modifications in the event of changes to the project team, facilities, etc.; 2) figures and equations; 3) references to other documents and publications; and 4) details about past work and discussion of technical background (which should be covered elsewhere in the application narrative). [*****BEGININNING OF SOPO TEMPLATE*****] STATEMENT OF PROJECT OBJECTIVES (SOPO) Title of Project (Insert the title of the work to be performed. Be concise and descriptive) A. OBJECTIVES Clearly and concisely describe the objective(s) of the project. If the project includes multiple phases of work, describe the objective(s) for each phase. This section should not exceed one-half page. B. SCOPE OF WORK 139 Page 134 of 142 Summarize the planned effort and approach to achieve the proposed overall project objectives. For projects that involve multiple phases of work, specific scope statement(s) should be defined for each phase. This section should not exceed one-half page. C. TASKS TO BE PERFORMED Unless otherwise stated, all SOPOs will include tasks for Project Management Plan, National Environmental Policy Act (NEPA) Compliance, and Cybersecurity Plan (CSP) as instructed below. Further, the applicant should include clear and concise descriptions of their planned tasks (and subtasks if needed). Tasks are to be organized in a logical sequence and grouped into corresponding phases, if applicable. Task 1.0: Project Management and Planning Subtask 1.1 – Project Management Plan (PMP): Within 30 days of award, the Recipient shall submit a Project Management Plan (PMP) to the designated Federal Project Officer (FPO). The Recipient shall not proceed beyond Task 1.0 until the PMP has been accepted by the FPO. The PMP shall be revised and resubmitted as often as necessary, during the course of the project, to capture any major/significant changes to the planned approach, budget, key personnel, major resources, etc. The Recipient shall manage and direct the project in accordance with the accepted PMP to meet all technical, schedule and budget objectives and requirements. The Recipient will coordinate activities to effectively accomplish the work. The Recipient will ensure that project plans, results, and decisions are appropriately documented, and that project reporting and briefing requirements are satisfied. Subtask 1.2: National Environmental Policy Act (NEPA) Compliance As required, the Recipient shall provide the documentation necessary for NEPA compliance. Subtask 1.3: Cybersecurity Plan (CSP)* The CSP shall be revised and resubmitted as often as necessary, during the course of the project, to capture any major/significant changes. *Applicable to Topic Area 2 [Smart Grid Investments (40107)] and Topic Area 3 (Innovative Grid Resilience Program (40103(b)) only Subtask 1.4: Continuation Briefing(s): 140 Page 135 of 142 The Recipient will brief DOE on roughly an annual basis to explain the plans, progress and results of the technical effort. The briefing shall also describe performance relative to project success criteria, milestones, and the Go/No-Go Decision point that are documented in the Project Management Plan (PMP). Include additional tasks and subtasks as appropriate using the following format. For projects that involve multiple phases of work, label the start of each phase (such as “Phase 1”, etc.), state the title, and provide a brief narrative describing the objective(s) and scope for the phase. Task 2.0 - (State title of task and provide description) Subtask 2.1 - (State title of subtask and provide description) Task 3.0 - (State title of task and provide description) Subtask 3.1 - (State title of subtask and provide description) Task 4.0 - (State title of task and provide description Subtask 4.1 - (State title of subtask and provide description) D. DELIVERABLES The Recipient shall include a list of deliverables that will be submitted during the project. Subtask 1.1: Project Management Plan Subtask 1.3 – Cybersecurity Plan (*if applicable) Subtask 1.4 – Pre-Continuation Briefing Document(s) List additional deliverables as appropriate including any documents that will be delivered to DOE. In addition to the deliverables listed above, the Recipient shall submit all periodic, topical, final, and other reports in accordance with the Federal Assistance Reporting Checklist and accompanying instructions. E. BRIEFINGS/TECHNICAL PRESENTATIONS The Recipient shall prepare, and present periodic briefings, technical presentations and demonstrations as requested by the Federal Project Officer, which may be held at a DOE or the Recipient’s facility, other mutually agreeable location, or via webinar. Such meetings may include all or a combination of the following: 141 Page 136 of 142 Kickoff Briefing - Not more than 30 days after submission of the Project Management Plan, the Recipient shall prepare and present a project summary briefing as part of a Project Kickoff Meeting. Pre-Continuation Briefing - Not less than 90 days prior to the planned start of a budget period, the Recipient shall brief the DOE on the results to date, and their plans for the subsequent periods of work. The DOE will consider the information from this briefing, as well as the content of deliverables submitted to date, prior to authorizing continuing the project. Final Project Briefing - Not less than 30 days prior to the end of the project, the Recipient shall prepare and present a Final Project Briefing on the results and accomplishments of the entire project. Other Briefings – The Recipient shall prepare and present technical, financial, and/or administrative briefings as requested by the DOE. Additionally, the DOE may require Recipients to make technical presentations at national and/or industry conferences. [*****END OF SOPO TEMPLATE*****] 142 Page 137 of 142 APPENDIX E – CYBERSECURITY PLAN In accordance with BIL Section 40126, DOE requires Topic Area 2 and Topic Area 3 awardees to submit a cybersecurity plan during award negotiations and prior to receiving funding.58 These plans are intended to foster a cybersecurity-by-design approach59 for BIL efforts. The Department will also use these plans to ensure effective integration and coordination across its research, development, and demonstration programs. The Department recommends using open guidance and standards such as the National Institute of Standards and Technology's (NIST) Cybersecurity Framework (CSF), the DOE Cybersecurity Capability Maturity Model (C2M2), and the Cybersecurity and Infrastructure Security Agency (CISA) cybersecurity performance goals for critical infrastructure and control systems.60 The cybersecurity plan created pursuant to Section 40126 should document any deviation from open standards, as well as the utilization of proprietary standards where the awardee determines that such deviation is necessary. Cybersecurity plans should be commensurate to the threats and vulnerabilities associated with the proposed efforts and demonstrate the cybersecurity maturity of the project. Cybersecurity plans may cover a range of topics relevant to the proposed project, e.g., software development lifecycle, third-party risks, and incident reporting. At a minimum, the Cybersecurity Plan should address questions noted in IIJA section 40126 (b) ‘Contents of Cybersecurity Plan’.61 o (1) plans to maintain cybersecurity between networks, systems, devices, applications, or components- (A) within the proposed solution of the project; and (B) at the necessary external interfaces at the proposed solution boundaries; 58 42 USC §18725 59 Security must be baked into the development process, not bolted on. Security risk evaluation and mitigation measures should be an active component in a project (or product) lifecycle – from early development stages to implementation. 60 NERC critical infrastructure protection (CIP) standards for entities responsible for the availability and reliability of the bulk electric system. NIST IR 7628: 2 Smart grid cyber security strategy and requirements. NIST SP800-53, Recommended Security Controls for Federal Information Systems and Organizations: Catalog of security controls in 18 categories, along with profiles for low-, moderate-, and high-impact systems. NIST SP800-82, Guide to Industrial Control Systems (ICS) Security. NIST SP800-39, Integrated Enterprise-Wide Risk Management: Organization, mission, and information system view. AMI System Security Requirements: Security requirements for advanced metering infrastructure. ISO (International Organization for Standardization) 27001, Information Security Management Systems: Guidance on establishing governance and control over security activities (this document must be purchased). IEEE (Institute of Electrical and Electronics Engineers) 1686-2007, Standard for Substation Intelligent Electronic Devices (IEDs) Cyber Security Capabilities (this document must be purchased). DOE Cybersecurity Capability Maturity Model (C2M2). CISA cybersecurity performance goals for critical infrastructure and control systems directed by the National Security Presidential Memorandum on Improving Cybersecurity for Critical Infrastructure Control Systems, found at https://www.cisa.gov/cpgs 61 42 USC §18725 143 Page 138 of 142 o (2) will perform ongoing evaluation of cybersecurity risks to address issues as the issues arise throughout the life of the proposed solution; o (3) will report known or suspected network or system compromises of the project to DOE; and o (4) will leverage applicable cybersecurity programs of the Department, including cyber vulnerability testing and security engineering evaluations. Projects receiving funding under this program must utilize open protocols and standards (including Internet-based protocols and standards) if available and appropriate.62 62 42 USC §17386(e)(1)(B) 144 Page 139 of 142 APPENDIX F – PROJECT DESCRIPTION AND ASSURANCES DOCUMENT TEMPLATE (PDAD) Project title: Applicant Name: Applicant Address: Names of all team member organizations (if applicable): Principal Investigator (Name, Address if different than Applicant’s, Phone Number, E-mail): Business Point of Contact (Name, Address if different than Applicant’s, Phone Number, E-mail): Include any statements regarding confidentiality. Federal Share: Cost Share: Total Estimated Project Cost: Item 1: Specify (mark with “X”)” the FOA Topic Area and as applicable the Area of Interest (AOI): ________Topic Area 1: Grid Resilience Grants (BIL section 40101(c)) ________Topic Area 2: Smart Grid Grants (BIL section 40107) ________Topic Area 3: Grid Innovation Program (BIL section 40103(b)) – Area of Interest 1 (Transmission System Applications) ________Topic Area 3: Grid Innovation Program (BIL section 40103(b)) – Area of Interest 2 (Distribution System Applications) ________Topic Area 3: Grid Innovation Program (BIL section 40103(b)) – Area of Interest 3 (Combination System Applications) TOPIC AREA 1 Specific Items: Item 2: Specify (mark with “X”)” the entity type of the applicant organization: ________electric grid operator ________electricity storage operator ________electricity generator 145 Page 140 of 142 ________transmission owner or operator ________distribution provider ________fuel supplier If further description is needed for the specified entity type, please provide below: Item 3: Please provide the total amount (USD) of qualifying resilience investments (as outlined in DE-FOA-00002740) that has been spent for the previous 3 years. Please also provide the time period utilized for calculation of this amount. Total Amount: Time Period for Resilience Investments: Note: Topic Area 1 applicants must submit as part of their application, a report detailing past, current, and future efforts by the eligible entity to reduce the likelihood and consequences of disruptive events. This report should include efforts over at least the previous 3 years and at least the next 3 years and any broader resilience strategy used by the applicant. Item 4: Is the eligible entity a Small Utility as defined in DE-FOA-0002740 (sells no more than 4,000,000 MWh of electricity per year)? If NO is selected, skip to Item 7. ________Yes ________No Note: If YES, applicant must provide their Form 861 for the last reporting year submitted to the Energy Information Administration (EIA). Item 5: Per BIL section 40101(e)(2) (C) APPLICATION LIMITATIONS.—An eligible entity may not submit an application for a grant provided by the Secretary under subsection (c) and a grant provided by a State or Indian Tribe pursuant to subsection (d) during the same application cycle. Therefore, is the eligible entity a Subaward/Subcontract recipient for an application submitted under IIJA Section 40101(d), ALRD 2736? If “YES”, please describe the differences between the GRIP FOA 2740 application [40101(c)] and the ALRD 2736 [40101(d)] applications in the box below: ________Yes 146 Page 141 of 142 ________No TOPIC AREA 2 Specific No items TOPIC AREA 3 Specific Item 6: Specify (mark with “X”)” the entity type of the applicant organization: ________a State ________a combination of 2 or more States ________an Indian Tribe ________a unit of local government ________a public utility commission If further description is needed for the specified entity type, please provide below: Item 7: Authorized Organizational Representative (AOR): please provide name, address, phone number and e- mail address for the authorized agent to bind the entity 147 Page 142 of 142 Authorized Organizational Representative (AOR): Name: Address: Phone: E-mail: Item 8: Signature of Authorized Organizational Representative (AOR) ____________________________________- 148 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Concept Paper Railbelt Innovation Resiliency Project (RIR) Topic Area 3: Grid Innovation Applicant: The Alaska Energy Authority (AEA) representing the State of Alaska Technical Point of Contact: Bryan Carey, Director of Owned Assets, AEA Business Point of Contact: Curtis Thayer, Executive Director, AEA The AEA and Railbelt electric utilities are partners in this project as collaborative decision makers representing all the primary transmission owners and operators of Alaska’s largest electrical grid (the Railbelt). The project team consists of: 1.AEA 2.Chugach Electric Association Inc. (CEA), a Central Region cooperative 3.Golden Valley Electric Association Inc. (GVEA), a Northern Region cooperative 4.Homer Electric Association Inc. (HEA), a Southern Region cooperative 5.Matanuska Electric Association Inc. (MEA), a Central Region cooperative (MEA) 6.The City of Seward, Alaska dba Seward Electric System (SES), a Southern Region municipal utility 7.The Regulatory Commission of Alaska (RCA) is participating as a team member in an advisory and regulatory role, as permitted by their statutory authority Project Location: All three regions (Northern, Central, and Southern) of the Alaska Railbelt electrical grid and the Eastern Region1. 1 Copper Valley Electric Association (CVEA) serves the Eastern Region and is a stakeholder knowledgeable about this application but is not a project team member. Area served by the Railbelt grid Area served by Copper Valley Electric Association 149 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 1 Project and Technical Description Alaska and the nation are at a crossroads of the need to develop a fuel-diverse, low-carbon economy, and a once-in-a-generation opportunity to invest in infrastructure. At this intersection, the collective mission of the Railbelt utilities and the State of Alaska is to build a resilient, clean, smart, and low-cost electrical grid. This grid must support a fuel-diverse energy landscape that drives sustainable economic development in Alaska and ensures the cost- effective delivery of energy to Railbelt consumers and beyond. The Railbelt utilities and State share a vision: a collaborative future in the Railbelt in which our communities come together and share resources to strengthen and build a smart, clean electrical grid that promises our residents, our national defense infrastructure, and communities adjacent to the Railbelt access to clean, low-cost energy from any source. The Railbelt Innovation Resiliency project (RIR or Project), the subject of this GRIP Topic 3 Concept Paper, is one of a series of projects that constitute the Railbelt’s Grid Modernization and Resiliency Plan (GMRP or Plan)2. The RIR effort proposed in this Topic 3 funding cycle will construct an interregional transmission line (including a high voltage direct current (HVDC) submarine cable) parallel to the single line that currently ties the Southern and Central regions together. The project includes two Battery Energy Storage Systems (BESS), one each in the Central and Northern regions, to augment the existing 46 MW, 2-hour battery in the Southern Region. The HVDC line and batteries will be operated and controlled simultaneously in real time to maximize transfer capability between regions and minimize spinning reserve requirements, improving resiliency and allowing the transfer of renewable energy. Discussion on how this project fulfills the GRIP FOA eligibility requirements begins on page 10 of this document. The team assembled for this project includes stakeholder outreach experts, engineers, project managers, and the executive-level decision makers for the Railbelt utilities and AEA. The team will work diligently to integrate other regional stakeholders into the process, as described in the Community Benefits Plan section. The project team intends to apply in subsequent cycles for funding to complete the transmission line between the Southern and Northern regions by extending the transmission line in this funding request from the Central Region to Healy in the Northern Region. In the final funding cycle, the project team will submit the completion of RIR Phase 2, constructing a transmission line integrating the Copper Valley in the Eastern Region into the Railbelt grid and providing an alternate path to feed the Ground-based Midcourse Defense (GMD) system and Black Rapids Arctic Warfare Training Center at Fort Greely in the Northern Region. 2 The GMRP consists of interregional transmission interconnection improvements and a coordinated energy storage/HVDC system: More specifically these are: 1) upgrades to the Railbelt Backbone, the Railbelt’s existing transmission system (the Railbelt Backbone Rebuild) 2) a second interregional tie between the Southern, Central, and Northern regions, 3) battery energy storage systems (BESS) in each region operating in real-time coordination with an HVDC system to maximize transfer capability and minimize spinning reserve requirements, and 4) an interregional tie between the Central and Northern regions integrating the Copper River Valley (currently a stand- alone system) into the Railbelt grid and providing a second feed into the U.S. Department of Defense GMD system at Fort Greely. 150 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 2 Fort Greely is currently served by a single radial transmission line from Fairbanks. These subsequent projects would complete the full GMRP. Grip Topic 3 is coordinated with but distinct from the project team’s requests in GRIP Topics 1 and 2. In GRIP Topic 1 the team is seeking federal assistance for the reconstruction of the antiquated and end of useful life transmission assets that comprise the existing transmission system backbone. In GRIP Topic 2, the Railbelt utilities and AEA are seeking federal assistance for design and procurement of the interregional battery-HVDC control and monitoring system, which would provide simultaneous interregional control. In Grip Topic 3, this concept paper, the project team is seeking assistance in constructing the actual HVDC line and BESSs. Although the GMRP in total provides the greatest benefit to Alaska and the strongest opportunity to advance federal policy interests, each of its components provide value in their own right. The team will seek funding to complete the entire GMRP; however, as noted below, without significant federal and state assistance the GMRP will take many decades to complete. Through the GMRP, there exists an opportunity for a transformational series of transmission infrastructure improvements estimated to cost ~$2.87 B. Successful and accelerated implementation of the GMRP will prepare the Railbelt grid in terms of resiliency and reliability necessary for the development of a more fuel diverse low carbon future in Alaska that can serve as a model for the rest of the United States and the world. Given the nature of the Railbelt and the disparate socioeconomic status and vast diversity of its communities as described below, learnings from this undertaking will be broadly applicable to the larger grids of the contiguous lower forty-eight states and North America. As described in this concept paper, the Railbelt grid is an isolated3, long-distance, fully functioning electric grid built on a relatively small scale that serves nearly three quarters of Alaska’s population. Yet, the grid’s aging infrastructure is inadequate by traditional industry standards. For example, although Alaska is not regulated by the North American Electric Reliability Corporation (NERC), NERC standards would require the construction of the GMRP projects to meet its reliability and resiliency standards. The GRIP provides an opportunity to successfully modernize the Railbelt grid to support the state’s isolated population core and to facilitate decarbonization of the broader Alaska economy. The AEA and the Railbelt utilities are investigating large-scale, known-resource wind projects in the Northern Region near Fairbanks; in the Central Region on the east and west sides of Cook Inlet; and in the Southern Region north of Kachemak Bay and the upper Gulf of Alaska near the mouth of Cook Inlet. Additionally, AEA and the Railbelt utilities are investigating hydroelectric resources in the Southern Region, solar farms in the Central and Southern regions, and potential hydroelectric resources in the Eastern Region. The economics of integrating any of these projects into the Railbelt grid will require the participation of all five Railbelt electric utilities, the State, and in the case of the Eastern Region, CVEA, a stand-alone, islanded electric utility. For these utilities to participate in any of these renewable or low carbon energy projects, firm transmission access to generation resources must be assured. Firm transmission access will 3 The Railbelt is a stand-alone grid not interconnected with any other electric system. 151 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 3 require completion of the GMRP. Thus, GMRP completion is the key to decarbonizing the Railbelt grid. Due to the population diversity within the Railbelt and scale of the infrastructure, the federal government has an opportunity to utilize the Railbelt grid as a model to demonstrate both the objectives and vision of the bipartisan Infrastructure Investment and Jobs Act (IIJA) and other initiatives. The lessons learned from this demonstration will have broad applicability to the larger grids of the contiguous lower forty-eight states. The project team looks forward to collaborating with the national labs to ensure such learnings are transferred to national stakeholders. As discussed more fully in the Community Benefits Plan section, the Railbelt region is home to numerous federally recognized tribes and disadvantaged and underserved communities. There are over 200 federally recognized tribes in Alaska, many in the Railbelt region, and based on the 2010 census Anchorage is home to the three most culturally diverse census tracts in the U.S. (followed closely by Queens, New York)4. One hundred and ten languages are spoken in the Anchorage School District alone.5 With this socially and economically diverse makeup, the Railbelt is the ideal area for the federal government to demonstrate how the benefits of the IIJA can be maximized. The Railbelt serves five military bases, as depicted in Figure 1, each with a vital strategic importance to U.S. national security. These critical bases contribute to the national defense through airborne infantry, military intelligence, mid-course missile defense, global telecommunications downlink infrastructure, Long Range Discrimination Radar (LRDR), F-16, F-22, and F-35 high-speed intercept capability, and Coast Guard, among other ways. As noted in the White House’s Indo-Pacific Strategy (February 2022), these defense capabilities are vital to our national security and prosperity. The GMRP will support the transition of Alaska-based U.S. Department of Defense assets to a low-carbon future and improve resiliency by building a redundant transmission line to serve the GMD system near Ft. Greely. The Railbelt is essential to the broader state economy. The Port of Alaska, a federally designated Strategic Seaport in Anchorage, serves as the primary point of entry for virtually all cargo, building material, fuel, and food for most of the state’s population. Additionally, the Ted 4 https://www.cnn.com/2015/06/12/us/most-diverse-place-in-america/index.html 5 https://www.asdk12.org/aboutasd/ Railbelt Military Bases Figure 1: Military Bases Served by the Railbelt Grid 152 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 4 Stevens Anchorage International Airport is the fourth largest international airport in the world in terms of cargo throughput (approximately 50% of the air cargo between North America and Asia), making its decarbonization of global importance. Alaska is home to significant mining operations including for rare earth metals critical to national security and other strategic imperatives. These assets are vital to the economy and security of both Alaska and the nation. The RIR will deliver broad and substantial benefits to the Railbelt and the state. Those benefits include improved regional and interregional reliability, resiliency and transfer capacity, increased ability to integrate renewable and other low carbon energy projects, reduction in carbon emissions and transmission system losses, increasing geographic and technological diversity of the Railbelt grid generation portfolio, facilitation of decarbonized beneficial electrification, and the eventual decarbonization of the electric grid. More significantly, over time this project and the broader GMRP will help stabilize electric rates throughout the state. Alaskans pay some of the highest electric rates in the country6, which disproportionately impact the disadvantaged and underserved. Stabilizing Railbelt rates will in turn help address the even higher cost of energy in rural Alaska not served by the Railbelt, with close to 30% of the state’s population. The state’s innovative, equity-sharing Power Cost Equalization (PCE) program7 mitigates rural costs using a formula based in part on the price of Railbelt electricity. This program spreads benefits realized by investment in the Railbelt to virtually every village in Alaska, most of which are Disadvantaged Communities. The GRIP program objectives are met and complimented by the State’s and utilities’ goal of a resilient, clean, and low-cost electrical network that supports sustainable economic development in the region, decarbonization, and cost-effective energy delivery. All the Railbelt electric utilities are either electric cooperatives or, in the case of the City of Seward Electric System (SES), municipally owned8. Thus, virtually all benefits from this grid modernization effort flow directly to the member-owners, the residents, businesses, and communities of the Railbelt, and indirectly to the rest of the State through PCE. The Railbelt is effectively a proving ground where the Department of Energy (DOE) and other federal agencies can evaluate and successfully demonstrate transmission resiliency improvements in preparation for electric decarbonization, both technically and on a community basis. Notably, this can be achieved at a relatively low cost in the Railbelt grid. The RIR project will have the full support and cooperation of the State and utility project team. This team consists of representatives of the State of Alaska and each of the five Railbelt electric utilities9, and of the 6 Energy Information Administration (EIA) form EIA-826. 7 The Community Benefits Plan section beginning on Page 13 provides additional discussion on Power Cost Equalization. 8 The City of Seward, a municipal, public power utility at ~1% of total Railbelt electricity demand. 9 The five Railbelt Electric Utilities consist of Golden Valley Electric Association Inc. in the Northern Region, Matanuska Electric Association Inc., and Chugach Electric Association Inc. in the Central Region, and Seward Electric System and Homer Electric System Inc. in the Southern Region. 153 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 5 RCA, the state’s utility regulator10. The team members are committed to the GMRP, subject to governance board approvals and vetting through the National Environmental Policy Act (NEPA) process. The State and the Railbelt utilities are committed to upgrading the regional and interregional transmission system. On December 2, 2022, AEA closed on a bond package for $166M, 65% of which will be dedicated to transmission line reconstruction and 35% to the three regional grid stabilization BESSs. The Railbelt utilities will pay the debt service on this bond package. In later funding cycles, other segments of the RIR will be constructed as study work is completed and regional and interregional approval is obtained. State funding assistance11 to help close the gap between utility funding and federal assistance is being pursued. The team plans to apply for all applicable IIJA and Inflation Reduction Act (IRA) federal assistance for GMRP projects. In addition, the team is seeking State appropriations to augment federal funds. The GMRP upgraded grid will create an unrestricted electron freeway and allow the Railbelt to optimize the use of cost-effective, low-carbon technologies by eliminating current technical and geographic constraints of the transmission system. Background The Railbelt Grid The Railbelt electric grid is unique in North America as it is a fully functioning, long-distance electrical grid with a relatively small load. The Railbelt is characterized by three load-generation regions. These load- generation concentrations are known as the Northern Region (Fairbanks-Delta Junction), the Central Region (Anchorage- Matanuska-Susitna Valleys, and Southern Region (the Kenai Peninsula). The Southern and Central regions are joined by a single, 140 mile long 115 kV transmission line through many avalanche areas. The Central and Northern regions are connected by a 169-mile, 138 kV line through mountainous 10 On January 4, 2023, the RCA unanimously passed the following motion “I [Commissioner Pickett] will make a motion that the RCA be considered as a [Alaska Railbelt GRIP] team member subject to any legal restrictions we may have and to consider probably in the format of an I docket, uncommon or innovative regulatory structures [to incentivize transmission investment].” 11The October 26,2022 letter from Railbelt utility managers to Governor Michael Dunleavy is available for review. Railbelt Grid Figure 2: Alaska’s Relative Size 154 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 6 terrain accessible only by helicopter. The grid provides electricity to approximately 70% of the state's population and generates 80% of the electricity in Alaska. It extends over 700 miles from the Bradley Lake Project, located at the head of Kachemak Bay near Homer, Alaska, in the Southern Region, to Delta Junction in the Northern Region, roughly the distance from Washington, DC, to Atlanta, Georgia, as depicted in Figure 2. The grid traverses inhospitable, mountainous, subarctic terrain. The region is laced with highly active seismic zones and is subject to volcanic eruptions, forest fires, flooding, and fierce annual winter storms. The grid's assets vary from high voltage (138 kV and 230 kV) submarine cable crossings in Cook Inlet12 to remote helicopter/riverboat -access-only river crossings and numerous transmission structures at high elevations in this subarctic environment. Unlike numerous areas in the contiguous lower forty-eight states, the Railbelt has received minimal federal investment in grid development over Alaska’s history. The Eklutna Hydroelectric Project, initially constructed in the 1950s, was the last major federal project in the Railbelt that included a transmission line component. A portion of this project was rebuilt by the Bureau of Reclamation's Alaska Power Administration after the 1964 Good Friday Earthquake and sold by the federal government to the Railbelt’s Central Region utilities in the early 1990s. The Railbelt’s Northern Region is loosely interconnected, primarily at 69 kV and 138 kV. The Central Region is moderately well interconnected with multiple 230, 138, and 115 kV lines. The Southern Region is interconnected at 115 kV but includes a radial feed to the SES system. A tight power pool operates in the Central Region and an active economy energy market exists between regions but is severely limited by transmission constraints and a lack of transmission lines. A generation contingency reserve-sharing pool exists between all three regions. Because the transmission interconnections are vulnerable to single contingencies, each region is responsible for its own operating and off-line reserves. Due to the relatively feeble regional interconnections, the Railbelt grid is technically characterized as "transient stability limited," with machines under dynamic stress swinging against other machines within the region, and with regions swinging against each other across the light interregional interconnections. The grid is susceptible to transient stability and large-scale, small-signal instability oscillations. Voltage stability, which varies from marginal to good depending on the specific area, has been improved with the addition of six static volt-amps-reactive (VAR) compensators at critical locations. The grid operates under a subset of NERC standards modified to account for the scale, nature, and economic limitations of the interconnection (the grid's system bias is variable and ranges from 3-10 MW/.1 hertz). In 2024 these standards will become mandatory and enforceable under a recently certificated electric reliability organization, the Railbelt Reliability Council. The grid has a sophisticated under-frequency load shed scheme which sheds load to match generation in four stages with varying time delays and includes frequency rate of change relays. Traditional day-ahead and real-time security constrained economic dispatch are run in 12 Cook Inlet is a silt laden 180-mile inlet reaching from Knik Arm to the Gulf of Alaska. The inlet has the fourth highest tidal range in the world at 30.3 feet and contains an endangered subspecies of the beluga whale. 155 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 7 each Load Balancing Area (LBA) with net interchange, and frequency monitored and managed to Alaska Standard AK BAL-001 which incorporates NERC CPS 1 and 2. Dynamic events on the grid occur and resolve very quickly (2-10 seconds) when compared with the much larger North American grids (the Eastern Interconnection, the Western Interconnection, and ERCOT), which resolve in tens of minutes. The grid's peak demand is roughly 750 MW compared to ERCOT's 13 peak demand of 85,000 MW. The grid's annual energy consumption is approximately 4,800 GWH compared to ERCOT’s at 339,000 GWH. The Railbelt Grid Modernization and Resiliency Plan Today, the broader energy landscape in Alaska and across the world is being reshaped by multiple change drivers. Geopolitical shifts are dramatically altering global energy markets. Decarbonization policies and technological advancements shaped by increasingly dramatic climate change are both the result of and contributing to a shift in popular sentiment about energy and the environment. Regionally, uncertainty around declining Cook Inlet natural gas 14 and broader fuel supply issues for the utilities is a critical – and shared – challenge looming on the near-term horizon. In response to this shared challenge, the State and Railbelt utilities have come together to develop a broad-based, long- term plan to ensure the future energy viability of the Railbelt from a social, economic, and technical perspective. The technical aspect of that plan is the GMRP, of which the RIR (the focus of this funding request) is a component. We intend to submit the GMRP as the Railbelt’s contribution to Alaska’s broader State Energy Security Plan as that document is developed in the coming months. Figure 3 is a graphic representation of the current Railbelt grid with the GMRP components overlaid. The GMRP components that comprise the RIR 2022-23 funding cycle project costs are highlighted in yellow. A more detailed geographic GMRP map with component projects and estimated costs is available upon request. 13 ERCOT is by far the smallest of the North American interconnections. 14 Natural gas is used to generate 80% of the electricity in the Railbelt and is also the primary source of energy for home heating in the Central and Southern regions. Figure 3: RIR Components in Current Funding Cycle 156 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 8 In the 2022-23 GRIP Topic 3 funding cycle, the State and utilities are requesting $298,600,000, representing 50% of the 2022-23 RIR project costs. The same team will seek federal assistance for the remaining project costs in subsequent Topic 3 funding cycles. Figure 4 is a graphic representation of the Railbelt system with an overlay of the GMRP. The entire RIR project (topic of this concept paper) is highlighted in yellow. The Railbelt Backbone Reconstruction is highlighted in red, and the BESS-HVDC control project (at locations highlighted with the blue “C”) comprise the remainder of the GMRP15. The estimated total cost for the GMRP is $2.87B over 15 years. Given the Railbelt’s small population, without significant federal and state investment the GMRP and its RIR component would take many decades to finance and construct. The costs are too high for the limited number of Railbelt customers to absorb. This delay will in turn hinder the Railbelt’s ability to decarbonize both the grid and the broader economy. The project team intends to apply for federal funding for specific GMRP components in each of the five funding periods of the GRIP and IRA, and also USDA Rural Utility Services (RUS) loan programs. In addition to these federal requests, the team is seeking state funding with the remainder of plan costs to be funded by Railbelt utilities. The utilities have requested, and the RCA has agreed, to evaluate innovative ratemaking strategies to promote the completion of the GMRP, e.g., accelerated application of costs to rate base or forward funding of project costs, among others.16 15 Subjects of the project team’s Topics 1 and 2 concept papers. 16 The RCA is the statutorily authorized regulator of the Railbelt electric utilities. The RCA discussion to evaluate innovative ratemaking strategies can be found in the minutes of the RCA’s January 4, 2023, special public meeting at https://rca.alaska.gov/RCAWeb/MeetingDetails/CommissionMeetingDetails.aspx?id=f44c5897-045b-4d7c-a59b- d650bdb52a2e Railbelt Innovation and Resiliency Project Cost 2022-2023 2024-27 Southern Region to Central Region HVDC Cable and Regional Battery Energy Storage $597,100,000 $870,400,000 Figure 4: RIR, RBR and BESS-HVDC Projects Comprising the Railbelt Grid Modernization and Resiliency Plan (GMRP) 157 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 9 The priority improvements required to allow diversification of the Railbelt fuel supply and decarbonization of the Railbelt grid must be providing frequency stability and decongesting the transmission system. These improvements are required irrespective of the nature of fuel supply diversity and decarbonization solutions. In 2010, the Railbelt's frequency was equal to 60 Hz. approximately 44 % of the time. By 2021, the grid operated at 60 Hz about 17% of the time. The primary causes of this deterioration of frequency control are the introduction of lighter, more efficient aero-derivative turbines, efficiency-driven (as opposed to response-driven) plant control systems, and the introduction of non-dispatchable renewables in the form of solar and wind generators. Stabilizing frequency and decongesting the grid will require upgrading existing transmission lines and building a new transmission interconnection from the Southern Region to the Central Region and on to Healy in the Northern Region, and development of a regional BESS-HVDC real-time control and optimization scheme. These steps are the core of the GMRP. A subsequent phase will include a transmission interconnection from Wasilla in the Central Region to Glenallen in the Eastern Region, and north to interconnect with the GVEA system at Fort Greely and the GMD System in the Northern Region. The following table estimates the high-level GMRP timeline and associated estimated costs. The priority and timing of projects may vary given the outcome of funding opportunities17, NEPA processes, the evolving nature of low carbon generation development, and Cook Inlet fuel supply changes. The Railbelt Innovation Resiliency Project The subject of this concept paper is the RIR, which is: • Construction of transmission lines and an HVDC submarine cable paralleling the existing single transmission line between the Southern and Central regions • Construction of two large-scale BESSs, one in the Northern Region and one in the Central Region, which will augment the existing 46 MW, 2-hour battery in the Southern Region These three batteries and the HVDC line will be operated in a coordinated, simultaneous fashion, in real-time, to maximize transfer capability and minimize spinning reserve requirements. The need for constructing a resilient transmission grid with multiple interregional interconnections was established in studies beginning with the development of the Bradley Lake Project in the late 1980s and confirmed as recently as 2017 in AEA’s Railbelt Regional 17 Full funding of requests in GRIP Topics 1, 2, and 3 may accelerate the 2023-2027 effort, pushing it above the estimated $934,000,000. Grid Modernization and Resiliency Plan (GMRP) Decarbonization and Fuel Diversity Transmission Build-Out 2023-2027 2028-2032 2035-2037 Southern Region (Kenai Peninsula) to Central Region (Anchorage Mat-Su) + Energy Storage $934,000,000 Central Region to Northern Region (Fairbanks-Delta Junction) Phase 1 $981,000,000 Central Region to Northern Region Phase 2 and Roadbelt (Wasilla-Glenallen-Delta Junction)$958,000,000 Total Fifteen Year Transmission Spend $2,873,000,000 158 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 10 Integrated Resource Transmission Plan. The RIR components addressed in this concept paper have historically received broad support within the Railbelt. This support will aid in moving the projects more quickly to design, permitting and construction. Project Eligibility and Area of Interest The RIR project meets the DOE’s objectives as expressed in the Topic 3, Area of Interest 1: Transmission System Applications18, as detailed below: 1. Investments and strategies that accelerate interconnection of clean energy generation and/or storage: Railbelt grid frequency stabilization and transmission system decongestion will allow development of large-scale interregional wind and solar projects by improving their economic and technical viability. With a reinforced transmission system, the geographical diversity of wind and solar will contribute to reduced storage requirements. The more robust transmission system will also allow interregional planning and dispatching stored resources, which will reduce storage resources required in individual regions. These improvements will also enable beneficial electrification on a large-scale, e.g., electric vehicles and space heating. 2. Interregional or cross-ISO/RTO projects that address key grid reliability, flexibility, and/or resilience challenges: The three Railbelt regions (Southern, Central, and Northern) are joined by single transient stability limited interconnections. The RIR project will remove single contingency constraints and increase interregional transfer capacity. 3. Projects addressing grid access challenges for remote, stranded, or novel low-carbon resources: The improved interregional grid (in terms of resilience and improved transfer capability) will increase the economic viability of and thus increase utility participation in geographically diverse wind and solar projects by enabling greater scale and driving per- unit costs down. From a technical perspective, stabilizing grid frequency and maximizing or eliminating transient stability limits and small-signal instability susceptibility will allow a larger scale integration of non-dispatchable renewables. Railbelt-wide coordination of BESS/HVDC resources will increase the amount of renewables sustainable in the Railbelt without increasing the amount of BESS resources. 4. Planning, modeling, cost allocation, or other approaches that enable a transition to innovative financial and/or regulatory constructs that accelerate transmission expansion: RCA participation in the RIR and broader GMRP efforts will likely create an innovative regulatory framework that allows the utilities to maximize their financial participation in this project and others, e.g., early inclusion of transmission construction costs in rates or forward funding of portions of these costs, thereby minimizing carrying costs. 5. Underground or underwater HVDC systems in challenging environments: The Nikiski to Beluga HVDC submarine cable will cross Cook Inlet, a challenging marine environment. 18 Funding Opportunity Announcement (FOA) Number: DE-FOA-0002740 pp 31-32 159 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 11 Cook Inlet is laden with glacial silt corrosive to armored cables19; has some of the highest tides in the world, peaking at 30 feet; is home to an endangered subspecies of beluga whale; and hosts numerous subsea petroleum and natural gas pipelines. 6. Capacity enhancing approaches such as advanced conductors, dynamic line rating systems: The geographically disparate combined BESS-HVDC system will be controlled in a real-time, coordinated fashion that provides real-time, dynamic maximization of transfer capability and minimization of spinning reserves. 7. Congestion management techniques including energy storage and integrated controls: See 6 above. 8. Transmission-scale reactive power devices: The BESSs are four-quadrant devices providing both real and reactive support, controlled and tuned to operate in dynamic synchronism with the six existing static VAR compensators. 9. Power flow controllers for AC or High voltage Direct Current (HVDC) systems: See 6 above. Project Grid Benefits The RIR project will simultaneously increase transfer capability and resiliency between the three Railbelt regions. Currently, transfers are vulnerable to interruption due to the lack of resiliency and reliability that will be resolved via the RIR by second ties between the regions. Increased transfer capability reduces security constrained economic dispatch (SCED) constraints, resulting in more efficient generation dispatch. More efficient SCED will reduce overall fuel burn and reduce carbon emissions, saving money and advancing climate goals. Further, firm transmission capability and increased transfer capability will allow geographically diverse utilities to participate economically in renewables, by increasing economies of scale and reducing per-unit costs of renewables. Energy resiliency will be greatly improved by allowing energy sources in all three regions to participate in electricity restoration as opposed to limiting resiliency measures to three individual areas. Ultimately the RIR project, as a component of the larger GMRP, will improve resiliency, reliability, and efficiency, and facilitate the integration of additional renewables and variable generation whether in the Southern, Central, or Northern regions. Improving transmission security between the three areas will extend to all regions the benefits of geographically diverse renewables. With completion of the RIR effort contemplated under this funding cycle, the benefits noted above will extend in full to the Southern Region and in part to the Central Region. Completion of the broader GMRP (which requires the RIR as an initial component) will accrue the full value of these benefits to the entire Railbelt and Copper Valley. 19 An evaluation by CEA in the mid-1990s showed that of ten 138 kV AC oil-filled undersea cables installed between 1970 and 1990, the average cable life was approximately 15 years versus an industry expectation of 50 years. 160 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 12 Project Risk Reduction DOE investment in the RIR will provide valuable insights for contiguous lower forty-eight states’ grid planners and developers specifically with respect to long-distance, coordinated, real-time control of BESS and HVDC systems from real and reactive power perspectives. Applications of this technology will be particularly useful in isolated pockets of the larger contiguous lower forty-eight states where transient or small-signal instability present a challenge. There are several know project risks which we will address proactively; for example, the beluga whale endangered species challenge will be mitigated by early engagement with stakeholders, appropriate whale watch protocols, and bubble acoustic sound deadening construction techniques. Early bathymetry development and engagement with pipeline owners and state permitting will optimize circuit routing and minimize conflicts, e.g., cathodic protection. The abrasive nature of Cook Inlet silt will be mitigated by double armoring the cable, a solution that has proven effective on the most recently installed 138 kV submarine cable. Project DOE Funding to Leverage Outcomes DOE investment in the RIR will unlock state20 and local electric utility funding for this project and subsequent GMRP components. AEA and the utilities also look forward to collaborating with the national labs to integrate opportunities for additional innovation in the Railbelt effort. By advancing the GMRP’s cumulative broader impact, this RIR investment will transform the Railbelt transmission grid. This transformation will provide adequate transmission capability for broad regional participation in renewable and low-carbon generation projects. Broad participation will drive economies of scale and improve the cost profile of such projects, effectively easing the rate burden of the Green Premium21 that falls disproportionately on low income and underserved communities. Thus, the RIR and GMRP will facilitate the integration of renewable and low-carbon generation technologies from Homer to Fairbanks through an unrestricted electron freeway. Project Readiness, Viability, and Expected Timing As noted above, the RIR project can be accelerated through design, permitting, and construction stages due to the maturity of the existing study work of the proposed RIR segments. 20 See October 26, 2022, letter from the Railbelt electric utility managers to Alaska Governor Michael Dunleavy. 21 https://breakthroughenergy.org/our-approach/the-green-premium 161 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 13 Community Benefits Plan The Railbelt Innovation Resiliency project presents a unique opportunity to increase reliability, provide clean energy options, and reduce electricity rates for a 700-mile-long stretch of Alaska that serves as the state’s economic backbone and is home to approximately two-thirds of the state’s population. The same Railbelt region includes multiple disadvantaged communities (DACs), extensive veteran, Pacific Islander, and Alaska Native populations, and some of the most diverse neighborhoods in the nation. Importantly, the benefits of federal investment in the Railbelt are not limited to those directly connected to the Railbelt grid. The State of Alaska’s Power Cost Equalization (PCE) program extends the financial benefits of lower Railbelt electric rates to positively impact hundreds of remote communities statewide; even populations not connected to the Railbelt’s electric network benefit from reduced Railbelt rates. Most of these remote areas are DACs with extremely high power costs; PCE reduces costs in these communities based on a formula tied to Railbelt rates. This innovative, built-in transfer mechanism demonstrates Alaska’s prioritization of equitable benefits sharing and provides a time-tested means to ensure benefits from federal investment in the Railbelt extend to compounded communities targeted by Justice40. Having missed out on the federal government’s transformational infrastructure investments before Alaska statehood, residents of Alaska have long borne outsized infrastructure costs spread across relatively few homes, businesses, and industries. Alaskans have experienced a lack of redundancy and infrastructure that would be considered unacceptable in other parts of the U.S. Alaska residents and businesses have been underserved in comparison to the federal investment in electrical infrastructure and energy in the contiguous lower forty-eight states. Federal support would be a step closer to providing parity to Alaskans, including numerous DACs, tribal entities, and rural communities. The project team intends to identify project benefits, the anticipated recipients, and metrics to track and measure the benefits in its Community Benefits Plan (CBP) to meet the federal government’s four target goals (outlined below). The project team’s approach to this plan will be stakeholder driven, involving communities and entities anticipated to become partners through the project planning, execution, and operations stages. CBP development will benefit from early engagement with potential partners and stakeholders in order to define measurable project benefits, set workforce goals, and advance formal partnerships for inclusion in the CBP. Individuals in impacted communities and local institutions can provide invaluable insight into potential project benefits and outcomes that will inform the project development and execution. This stakeholder participation is critical up-front to ensure the project delivers expected benefits that reach the intended communities, while reducing possible adverse impacts. Defining the affected stakeholders early, establishing clear, durable communication channels, receiving concerns, and crafting measures to address those concerns are critical to managing project risks and ensuring desired objectives. Clear communication and collaboration during 162 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 14 development of the project application and the CBP will set a foundation for implementing the CBP during project development, construction, and operations. This engagement should be a continuous loop through the project design and execution. Given that the project team is made up of cooperatives, a municipal utility, and the State of Alaska, stakeholder engagement is central to the team’s regular businesses. The project team believes this extensive experience will provide key support in CBP development and execution. Early engagement with stakeholders is also expected to further the ability of communities, individuals, local governments, and tribal entities to unlock additional funding opportunities tied to the project. To that end, the project team will develop a robust CBP around the four FOA elements as detailed below. Across all elements, the project approach is founded on the belief that direct, early communication and meaningful exchange with other entities and communities will inform CBP development. Element 1: Community and labor engagement leading to negotiated agreements The project team members have established, long-term, and mutually valued relationships with the organized labor community in Alaska. The Railbelt utilities have used project labor agreements in the past for projects of this scale, e.g., construction of the Alaska Intertie. Each of the Railbelt utilities has collective bargaining agreements with the International Brotherhood of Electrical Workers, among other unions. The project approach to the CBP will be to engage its labor partners early to initiate discussions toward labor agreements. The CBP would establish a timeline and milestones for negotiations with organized labor, including discussions on local and targeted hiring goals, card-check neutrality, and possible provisions advancing programs to attract, train, and retain new workers. As the project applicant, the Alaska Energy Authority works with the Railbelt utilities as partners in several transmission organizations. The utilities and AEA have a successful record partnering both as owner/partners in shared capital projects and in advancing state energy goals and priorities. With state support affirmed in this way, the CBP would prioritize establishing and formalizing relationships with tribal entities, local governments, and other State of Alaska departments with a focus on workforce and related issues. Early engagement with these core stakeholders will also help ensure the project is cognizant of and in support of local energy plans and goals. The project team members individually are accustomed to engaging with local governments and tribal entities through permitting and regulatory processes for capital projects. The CBP for this project would establish milestones urging earlier dialogue with local governments and tribal entities. These conversations should begin sufficiently early to inform project development in response to local communities’ needs and concerns and to guide iterations of the CBP. Local governments and tribal entities are uniquely situated to help identify the most effective actions the project can take toward partnerships that advance workforce issues; diversity, equity, inclusion, and accessibility; and the flow of project benefits to disadvantaged communities. 163 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 15 AEA and its partner utilities have extensive experience engaging with local residents and businesses in town halls and similar formats; AEA is a state entity with obligations to the public interest, and the electric utilities are member-owned cooperatives (one is municipal with direct responsibilities to the city’s residents). The CBP will articulate a plan and schedule for these engagements to ensure individuals and businesses are aware of the project, including potential economic and clean energy opportunities the project could enable, and to receive and incorporate concerns and input into project development plans. Element 2: Investing in job quality and workforce continuity Given Alaska’s relative isolation and general need for living wage jobs, the project team members firmly support the development of workforce training institutions. The stakeholder engagement articulated above is expected to further inform the project team of workforce issues and opportunities, including opportunities to partner with existing programs and institutions to ensure a skilled and inclusive local workforce. Such opportunities would be evaluated for incorporation into the CBP. Alaska is not a right-to-work state. The Railbelt utilities’ employees who are covered by bargaining unit agreements are required to join unions consistent with the terms and conditions of the various utility bargaining unit agreements. Further, the utilities maintain strict policies fostering safe, healthy, inclusive workplaces free of discrimination and harassment. The utilities currently support continual development of a skilled, inclusive local workforce, specifically the IBEW-NECA Alaska Joint Electrical Apprenticeship and Training Trust, individual utility training programs, the University of Alaska System and other technical training programs. This track record of investment in the Alaskan and American workforce will be reflected in the CBP. The project team members will also continue support of STEM and energy literacy programs throughout the state as an investment in the future pipeline of critical energy-related jobs. Element 3: Advancing diversity, equity, inclusion, and accessibility The CBP will identify and evaluate potential actions to advance diversity, equity, inclusion, and accessibility in relation to the project. Alaska offers significant opportunities to engage underserved populations, including Alaska Native, Pacific Islander, and veteran residents. Stakeholder consultation, including with organized labor, is expected to identify potential workforce partnerships to encourage participation of these and similar communities in the project. Element 4: Contributing to the Justice40 Initiative goal that 40% of the overall benefits of certain climate and clean energy investments flow to disadvantaged communities 164 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 16 As discussed in the beginning of this section, the team believes its project presents a unique opportunity to extend benefits to much of Alaska, including DACs. The initial approach to this CBP element would be identifying potential partners and establishing relationships to assist in the plan development. Potential partners may include impacted DACs; state entities such as Department of Environmental Conservation, Department of Commerce, and Department of Labor and Workforce Development; academic or public policy/research institutions such as the University of Alaska, Alaska Center for Energy and Power, and the Institute for Social and Economic Research (ISER); and tribal and non-governmental entities, many of whom have prioritized affordable, clean energy as strategic goals. The project team intends to work with partners, stakeholders, and project technical teams to identify measurable, trackable benefits and determine which benefits are most meaningful to impacted communities. Engagement with institutional partners will help define disadvantaged communities within and proximate to the project area, and within the projected reach of the defined outcomes. Formulation of a stakeholder engagement plan and further consultation with DACs and other partners could help establish mechanisms to measure and track the investments and outcomes. The project team believes significant benefits can be realized in energy resiliency, reduction of energy and pollution poverty, and increased clean energy opportunities throughout the region and state, and would coordinate with partners and stakeholders to quantify these broader benefits within the CBP. Communities in the project region currently face potentially severe health, safety, and economic consequences resulting from grid threats such as earthquakes, severe cold weather events, and large-scale forest fires, often in remote areas. The project is also anticipated to increase clean energy options throughout the region, including for DACs and other rural communities, many of which are currently powered through coal or diesel-fired generation. The project is expected to reduce the potential consequences posed by these risks. The CBP should also capture the potential benefits of increased opportunities for tying new, clean- energy projects to the grid, especially smaller-scale projects. Project benefits are anticipated to include improvements to air quality across the project regions, especially in the Northern Region and other locations where particulate matter (PM2.5) pollution has risen to non- attainment levels high enough to trigger remediation efforts through the EPA and is adversely impacting the economy and health. 165 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 17 Addendum A The Railbelt utilities and AEA have worked together for over 30 years, from constructing the Bradley Lake Hydroelectric Project (BLHP), which was commissioned in 1992 at a cost of approximately $350M in 1990 dollars, to the most recent addition to the BLHP of the Sterling to Quartz 115 kV line. The BLHP added the West Fork Upper Battle Creek Diversion in 2020, a $45M diversion structure that increased the lake’s energy capacity water by approximately 10 percent. On December 1, 2022, AEA closed on a $166M bond package which will be used to begin the RIR project by upgrading the Sterling to Quartz section of the 115 kV Southern Region to Central Region transmission line (the Anchorage to Kenai 115kV line). Thirty-five percent of the bond issue will be used to fund three regional grid stabilization batteries, one of which has been constructed by HEA and is operational. The AEA and Railbelt utilities’ stakeholder outreach, engineering, and project management teams have many decades of stakeholder outreach, transmission, and generation engineering, construction, and operations experience. Many of the engineers are registered professional engineers (PE) and several are also registered project management professionals (PMP). Combined this group has successfully constructed and commissioned billions of dollars of grid infrastructure, as noted in their qualifications and expertise below. Alaska Energy Authority (AEA) AEA’s mission is to reduce the cost of energy in Alaska. As Alaska’s lead agency for statewide energy policy and program development, AEA collaborates with utilities, private companies, legislators, local governments, and Alaskan energy innovators to diversify the state’s energy portfolio. On the Railbelt, AEA owns the 120-megawatt Bradley Lake Hydroelectric Project, the largest in Alaska. AEA recently oversaw the West Fork Upper Battle Creek Diversion construction, which diverts glacial water from West Fork Upper Battle Creek into Bradley Lake increasing energy by 10%. In rural Alaska, AEA constructs bulk fuel tank farms, diesel powerhouses, and electrical distribution grids, and provides technical/community assistance to rural Alaskans. AEA’s dedicated team of engineers, economists, project managers, loan officers, and planners help Alaska’s cities, boroughs, utilities, tribal entities, schools, and private businesses move energy projects forward successfully. Curtis Thayer, Executive Director, AEA Since 2019, Curtis W. Thayer has served as executive director of AEA, the state's energy office and lead agency for statewide energy policy and program development. Before joining AEA, Thayer served as president and chief executive officer of the Alaska Chamber, the largest state trade association. Previously, he was the commissioner for the Department of Administration and cabinet member for Governor Sean Parnell, responsible for 1,100 public employees and an annual budget of $350 million. As part of his public service, he served as the deputy commissioner of the Department of Commerce, Community, and Economic Development, and worked in Washington, D.C., with Alaska’s Congressional Delegation. 166 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 18 Formerly, he was on the management team of ENSTAR Natural Gas Company and the Alaska Gas Producers Pipeline Team. Thayer has served on boards at Alaska Housing Finance Corporation, Alaska Gasline Development Corporation, Alaska Retirement Management Board, Alaska Royalty Oil and Gas Development Advisory Board, and United States Chambers’ Committee of 100, and currently chairs Alaska’s Board of Marine Pilots. A graduate of the United States Department of Energy’s National Renewable Energy Laboratory Executive Energy Leadership Institute program, Thayer has gained a comprehensive understanding of advanced energy technologies that has helped him guide his organizations in making energy-related decisions. He is also an alumnus of the United States Chamber of Commerce Foundation's Institute for Organization Management, which recognizes graduates as leaders in their industries and organizations. Thayer earned his bachelor’s degree from the University of Alaska Fairbanks with a major in political science and a minor in business. Bryan Carey, Director of Owned Assets, AEA Bryan Carey has worked more than 20 years on energy projects for AEA. During that time, he has been the project manager for the Bradley Lake Hydroelectric Project, Bradley Lake transmission assets, project engineer for the Susitna-Watana Hydroelectric Project, Alaska Industrial Development Export Authority’s (AIDEA) owned Snettisham Hydroelectric Project, and substantially participated in Railbelt Integrated Resource Planning. In addition, he has been the project manager for many rural Alaska energy projects including bulk fuel facilities, power plants, and small hydroelectric/wind projects. Recently, he managed the studies, licensing, and construction of the West Fork Upper Battle Creek Diversion Project ($47m) to increase energy output of Bradley Lake by 37,000 MWh a year. Mr. Carey received a Bachelor of Science in engineering from the University of Alaska Fairbanks and a Master of Business Administration from University of Alaska Anchorage. He is a registered Professional Engineer in Alaska. Railbelt Electric Utilities Seward Electric Systems, Golden Valley Electric Association Inc., Matanuska Electric Association Inc., and Homer Electric Association are all vertically integrated generation, transmission, and distribution utilities with many decades of planning, design, construction, and operation of power systems. The Railbelt is, and has been, an early adopter of technology over may decades; for example, virtually all protective relays in the Railbelt grid were converted to microprocessor-based technologies by the early 1990s, and currently most critical busses in the Railbelt have real-time synchro phaser capability. In the last decade the combined utilities have constructed nearly $1B dollars in generation22, a 46MW two-hour battery, and many miles of transmission. The utility members of the project team are highly qualified in the execution of projects proposed under the Grid Resiliency and Innovation Partnership funding opportunity. Seward Electric System 22 Conversion to the new generation portfolio reduced carbon emissions by nearly 30% over the last decade. 167 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 19 Rob Montgomery, General Manager, Seward Electric System Rob Montgomery is the General Manager of Seward Electric System, a municipal electric organization serving 3,000 meters in the City of Seward and surrounding communities. In this role, he is responsible for overall operations of the city’s electric utility. Mr. Montgomery has over 20 years of professional experience in the electric utility industry, including 15 years with South Carolina Electric & Gas Company (SCE&G) and six years with Tennessee Valley Authority (TVA). At SCE&G, Mr. Montgomery was responsible for all strategic communications and media relations. In this position, he directed efforts to create a pipeline safety communications plan to meet compliance requirements of the 2002 Pipeline Safety Improvement Act; led public outreach related to the construction of a $275-million, federally mandated back-up dam on Lake Murray in Columbia, S.C.; and managed communications and conducted public workshops when communities were impacted by new federal laws for clearing and maintaining rights of way near high-voltage transmission lines. At TVA, he was responsible for strategic communications and served as a primary liaison with the Tennessee Valley Public Power Association. Mr. Montgomery is a graduate of the University of South Carolina with a degree in journalism and holds a certificate from Duke University’s Executive Leadership Program. Golden Valley Electric Association (GVEA) Dan Bishop, Director of Engineering Services, GVEA Dan Bishop has been responsible for the design and construction of electric transmission lines and substations throughout Alaska. His experience includes drafting, structural design, electrical design, project management, quality control during construction, leading teams of engineers and technicians, planning studies, budgeting, and executive management. He received his Bachelor of Science and Master of Science in Electrical Engineering from the University of Alaska Fairbanks and has been a registered professional engineer since 1993. Mr. Bishop has been with GVEA since 1997. Daniel Heckman, Regulatory Manager, GVEA Daniel Heckman serves as the primary liaison between GVEA and federal and state regulatory agencies, primarily the Regulatory Commission of Alaska (RCA), as well as regulatory stakeholders statewide. In addition to his regulatory and compliance oversight responsibilities, he serves as GVEA’s primary representative on the Railbelt Reliability Council and as GVEA’s representative on the BPMC project team described in this application. He received bachelor’s degrees in political science and history from Southern Methodist University in 2010 and his juris doctor from the Gonzaga University School of Law in 2013. Combined with his prior experience at an investor-owned utility, Mr. Heckman has 10 years of experience in regulatory affairs. Chugach Electric Association, Inc. (CEA) Bruce Aspray, Manager of Transmission & Substation Engineering & Planning, CEA Bruce Aspray is a professional with experience in the industrial power and electrical utility industries. Mr. Aspray has specified, built, commissioned, and operated a combined cycle power plant as well as open air and GIS substations. He is a degreed and licensed Professional 168 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 20 electrical engineer in the State of Alaska. He is experienced in project management and construction of utility grade facilities including generation, transmission, substations, distribution, and renewables. Andrew Laughlin, Chief Operating Officer, CEA Andrew Laughlin is a professional with a diverse background in the power industry, specifically, power delivery project development, design, procurement, project management and construction. He is a licensed Professional electrical engineer with experience that includes construction of transmission and substation infrastructure as well as upgrading Static VAR Compensation, boiler controls and steam turbine generation systems. Mr. Laughlin has developed project teams for large and small complicated projects. Dustin Highers, Vice President Corporate Programs, CEA Dustin Highers is an electric utility professional with a background in power plant operations, maintenance, construction, commissioning, and engineering support. Mr. Highers’ industry experience includes 30 years in various industries including maritime, oil and gas, power plant construction and commissioning, gas turbine field engineering, and electric utility engineering and management. He is the leader of small and large teams in the execution of enterprise level projects to achieve corporate goals and objectives. Mr. Highers has demonstrated skill in complex program and project management for power generator maintenance and large generation construction projects. Matanuska Electric Association (MEA) Ed Jenkin, Chief Operations Officer, MEA Ed Jenkin is a licensed professional electrical engineer in the State of Alaska with more than 30 years of experience in the utility industry. He is presently the Chief Operations Officer for MEA. In this role he has oversight of MEA’s system planning, engineering, operations, technical services, and power system dispatch functions. Within the interconnected Alaska electric utility system Mr. Jenkin has led or worked on multiple collaborative efforts, including Railbelt electric reliability and cybersecurity standards development, joint asset management and operations, power pool formation between MEA and CEA, electric reliability organization legislation, and regulations on net-metering, regional planning, and standards enforcement. Mr. Jenkin graduated with a Bachelor of Science in Electrical Engineering from the University of Alaska, Fairbanks in 1984. He also has a Master of Arts in cross-cultural studies. Julie Estey, Senior Director of External Affairs and Strategic Initiatives, MEA Julie Estey is Senior Director at MEA, where she manages the cooperative’s public and member- facing activities along with strategic plans and special projects. She serves as MEA’s representative, past chair, and founding member of the Railbelt Reliability Council, the recently certificated electric reliability organization for the interconnected Railbelt grid. Before joining MEA, Ms. Estey was the Business Director for the Alaska Center for Energy and Power, an energy research group at the University of Alaska Fairbanks focused on improving how Alaskans generate and distribute power. She has experience managing public outreach and engagement 169 Grid Resilience and Innovation Partnerships (GRIP) U.S. Department of Energy DE-FOA-0002740 Railbelt Innovation and Resiliency 21 for controversial transmission and generation capital projects as well as expertise bringing diverse groups of stakeholders together to develop common solutions. Brian Hickey, Executive Director, Railbelt Regional Coordination Brian Hickey is the Executive Director of Railbelt Regional Coordination, working for the CEOs of the five Railbelt electric utilities. He has more than 40 years of experience in electric power systems and telecommunications. His experience includes executive leadership and management, strategic business planning, economic alternative analysis, engineering, design, project management, and maintenance process development and implementation. Mr. Hickey has managed numerous generation, transmission, and process development and improvement projects in his career. He holds a Bachelor of Science in Electrical Engineering from Montana State University, a master’s certificate in Project Management from ESI/George Washington University, and a master’s degree in Global Finance from Alaska Pacific University. He is a licensed Professional Electrical Engineer and PMI Certified Project Management Professional. Homer Electric Association, Inc. (HEA) Keriann Baker, Director of Member Relations, HEA Keriann Baker, Director of Member Relations, oversees the utility’s customer service programs, public relations efforts, and legislative affairs. Ms. Baker practiced law with Reeves Amodio in Anchorage and Lewis, Longman & Walker in Palm Beach County, Florida, prior to joining HEA. She serves as vice chair of the South Peninsula Hospital, Inc., board and previously has served on numerous boards including several local/state chambers of commerce as well as state and national bar associations. Ms. Baker received a Bachelor of Science from Utah Valley University in Orem, Utah, and her juris doctorate from Loyola Chicago School of Law, in Chicago, IL. Larry Jorgensen, Director of Power, Fuels, & Dispatch, HEA Larry Jorgensen, Director of Power, Fuels & Dispatch, manages the operation and maintenance of HEA’s generation facilities, and generation dispatch. His skills include project design and management, advanced control systems, simulation and modeling, plant commissioning and startup, personnel training and advancement, and standards development. Mr. Jorgensen received an Associate in Applied Science in Power Plant Technology and Bachelor of Science in Energy Management, both from Bismarck State College in Bismarck, North Dakota. He has been with HEA since 2011. 170 March 3, 2023 SENT VIA ELECTRONIC MAIL The Alaska Energy Authority (AEA) Curtis Thayer cthayer@akenergyauthority.org SUBJECT: Funding Opportunity Announcement (FOA) no. DE-FOA-0002740, titled “BIL – Grid Resilience and Innovation Partnerships (GRIP)” – Concept Paper review results. Concept Paper Identification Code: TA3-015-E Dear Curtis Thayer: Thank you for submitting a Concept Paper in response to the subject FOA. The Concept Paper for proposed project titled "Rural Alaska Microgrid Transformation“ was carefully reviewed in accordance with the evaluation criteria in the FOA. Based on the results of the Concept Paper review, you (your organization) are (is) hereby encouraged to submit a full application in accordance with the instructions and requirements contained within the FOA by the due date/time specified on the FOA cover page. Please be advised that receiving a letter of encouragement does not guarantee that an application will be selected for negotiations leading to award. The Department of Energy (DOE) has identified potential area(s) for improvement based on the concept paper merit review criteria identified in the FOA (see below). DOE will not provide any additional feedback or guidance beyond what is provided below. X The Concept Paper did not propose or thoroughly describe how the proposed work, if successfully accomplished, would clearly meet the objectives as stated in the FOA for the specific topic area. The Concept Paper does not clearly describe how the proposed work aligns with and supports State, local, Tribal, regional resilience, decarbonization, or other energy strategies and plans. The Concept Paper does not adequately identify risks and challenges, including possible mitigation strategies, and/or has not adequately shown the impact that the DOE funding and the proposed project would have on the relevant field and application. X The Concept Paper does not adequately identify strategies to ensure meaningful community and labor engagement; quality jobs and workforce development; energy and environmental justice and the Justice40 Initiative; and diversity, inclusion, accessibility— including methods to ensure accountability. The proposed project team does not appear to have adequate qualifications, experience, capabilities, and other resources necessary to complete the proposed project. 171 If your organization chooses to submit a full application, please include the concept paper identification code identified above in your full application, preferably in the file name and on the cover page of the technical volume. The code is specific to this concept paper submission. Please also ensure you have carefully read the Registrations Requirements located in the FOA document. There are several one-time actions that must be completed before submitting an application in response to this FOA (e.g., register with the System for Award Management (SAM), obtain a Unique Entity Identifier (UEI) number, register with Grants.gov, and register with FedConnect.net to submit questions). It is vital that applicants address these items as soon as possible. Some may take several weeks, and failure to complete them could interfere with an applicant’s ability to apply to this FOA. The DOE did not make an applicant eligibility determination as part of the concept paper review. Applicant eligibility determinations will be considered at the full application stage of the FOA process. To be considered for substantive evaluation, an applicant’s submission must meet the criteria set forth in Section III.A of the FOA (Eligible Applicants). If the full application does not meet the eligibility requirements, it will be considered ineligible and removed from further evaluation. The DOE recognizes the significant effort your organization expended to prepare a concept paper in response to this FOA. On behalf of the DOE, the FOA team would like to express our appreciation for your interest in the Grid Deployment Office and this FOA. Sincerely, DE-FOA-0002740 Team Email CC: rgarrett@akenergyauthority.org 172 173 174 175 176 177 178 179 180 181 182 183 184 185 186 187 188 189 190 191 192 193 194 195 196 197 198 199 200 201 202 203 204 205 206 207 208 209 210 211 212 213 214 215 216 217 218 219 220 221 222 223 224 225 226 227 228 229 230 231 232 233 234 235 236 237 238 239 240 241 242 243 244 245 246 247 248 249 250 251 252 253 254 255 256 257 258 259 260 261 262 263 264 265 266 267 268 269 270 271 272 273 274 275 276 277 278 279 280 281 282 283 284 285 286 287 288 289 290 291 292 293 294 295 296 297 298 October 17, 2023 SENT VIA ELECTRONIC MAIL Curtis Thayer Alaska Energy Authority 813 W. Northern Lights Blvd., Anchorage, AK 99503-2407 cthayer@akenergyauthority.org SUBJECT: Selection of Application for Negotiation Under Funding Opportunity Announcement Number DE-FOA-0002740, BIL – Grid Resilience and Innovation Partnerships (GRIP), Topic Area 3 Dear Curtis Thayer: We are pleased to provide this update on your application. The Grid Deployment Office (GDO) within the Department of Energy (DOE) has completed its evaluation of your application submitted in response to the subject Funding Opportunity Announcement (FOA). The application below has been recommended by the GDO for negotiation of a financial award (Note: This notification does not guarantee Federal Government funding, as funding will only be obligated upon completion of successful negotiations.): Application/Project Title: Railbelt Innovative Resiliency Project (RIR); Principal Investigator: Bryan Carey; Grants.Gov Application Number: GRANT13888581. Your application was conditionally selected. Selection is conditioned upon your organization’s agreement to propose, for DOE’s consideration, a reduction in scope that eliminates the 2 overhead AC transmission lines and prioritizes (first) underwater HVDC and (second, if feasible) one or both BESS, at a federal funding amount of no greater than $121.6M. DOE may also consider a reduction in scope that eliminates the 2 overhead AC transmission lines and prioritizes (first) underwater HVDC and (second, if feasible) one or both BESS at a federal funding amount of no greater than $206.5M. The non-federal cost share must be at least 50% of the total project costs, consistent with the statutory requirement. The conditions must be resolved to the satisfaction of the DOE. Following your organization’s initial review of the condition set forth above, DOE would like to set up a meeting with your principal project officials. The purpose of the meeting is to address any questions you may have regarding the condition set forth above. The condition must be resolved no later than two weeks from receipt of this letter for award negotiations to commence. 299 PLEASE NOTE: The DOE is planning to issue a formal media release regarding this, and other GRIP financial assistance awards, in the near future. Accordingly, the GDO requests that selectees do not make any public announcements before this DOE announcement. The GDO communications team will provide a promotional toolkit to support you in amplifying your award status, should you choose to do so once the public announcement is made and a link to the DOE press release is available. If you have any questions about this, please reach out to: GDO_Comms@hq.doe.gov. Receipt of this letter does not authorize you to commence with performance of the project. DOE makes no commitment to issue an award and assumes no financial obligation with the issuance of this letter. Applicants do not receive an award until award negotiations are complete and the Contracting Officer executes the funding agreement. Only an award document signed by the Contracting Officer obligates DOE to support a project. The usual award negotiation process can take approximately 120 days. You must be responsive during award negotiations (i.e., provide requested documentation) and meet the stated negotiation deadlines. Failure to submit the requested information and forms by the stated due date, or any failure to conduct award negotiations in a timely and responsive manner, may cause DOE to cancel award negotiations and rescind this selection. DOE reserves the right to terminate award negotiations at any time for any reason. Please complete the following items in accordance with the instructions below and submit to the DOE Project Manager and Specialist identified in this letter, unless otherwise instructed. Requirement Instructions Business Days Due (from Receipt of Letter) Pre-Award Information Sheet (and all information requested within the document). Prepare and submit. Available at https://www.netl.doe.gov/business/business- forms/financial-assistance). 10 Indirect Rate Agreement(s) for the Awardee and all Subrecipients Submit, if applicable. 10 Davis Bacon Assurances (if applicable) For all projects that include construction, submit Assurances (see FOA Section IV.I.viii). 10 Participants and Collaborating Organizations Prepare and submit (see FOA Section VI.B.xviii). 30 Cybersecurity Plan In accordance with Section VI.B.xxiii and Appendix E of the subject FOA, a Cybersecurity Plan must be submitted during award negotiations. 45 300 Cybersecurity Plan Template: You can obtain the Cybersecurity Plan Template at https://www.energy.gov/ceser/bipartisan- infrastructure-law-implementation under the provision titled, CYBERSECURITY PLAN (SEC 40126). Please select the High Risk Cybersecurity Plan Template, which applies to the majority of projects selected under Topic Areas 2 & 3 of the subject FOA. Though unlikely, if the low or medium risk Cybersecurity Plan Template applies to your project, your DOE Project Manager will inform you in follow up correspondence. Webinars: Two webinars will be held to assist you with the preparation of your Cybersecurity Plan. Both webinars will provide the same information, so you will only need to attend one. Once available, webinar registration information will be provided on the Grid Resilience and Innovation Partnerships (GRIP) Program web page at: https://www.energy.gov/gdo/grid-resilience- innovation-partnership-programs. Webinar Agenda: • Welcome and Introductions • FOA Cybersecurity Plan Requirements • Submission and Review Process • Review of the Cybersecurity Plan Template o walk-thru of each of the ten sections within the templates o discussion of lessons learned from plans submitted to other FOAs • Cybersecurity Resources and Technical Assistance • Questions and Answers Submittal: Applicants will submit the final completed Cybersecurity Plan to the DOE Project Manager and to the following email address: CR- IIJACybersecurityplans@hq.doe.gov. Submission of the Cybersecurity Plan is required prior to award. 301 If your organization, including any subrecipient or contractor, anticipates involving foreign nationals (FNs) in the performance of the award, your organization is required to provide a list of all FNs planned to participate on the award along with basic information about each. You must download and complete the “Foreign National Participation Document” located at https://www.netl.doe.gov/business/business-forms/financial-assistance under Post Selection Forms/Information and submit the completed document to basicinfo@netl.doe.gov with a courtesy copy to the assigned Project Manager (PM) and Specialist. Upon receipt of the completed “Foreign National Participation Document,” we will create a secured file sharing drop box folder(s) for FNs in Principal Investigator (PI)/Co-PI roles, for FNs from countries of risk (i.e., China, Iran, North Korea and Russia), and for FNs from countries identified on the U.S. Department of State’s list of State Sponsors of Terrorism located at https://www.state.gov/state-sponsors-of-terrorism/ for submission of additional information. The additional information will NOT be required for any of the other FNs planned to participate on the award, and therefore, a folder(s) will not be created. As part of the requirement to submit additional information for PIs/Co-PIs, for FNs from countries at risk, and for FNs from countries identified as State Sponsors of Terrorism, your organization must ensure completion of the “Foreign National Participation Data Document” also located at https://www.netl.doe.gov/business/business-forms/financial-assistance. The document and all required attachments must be uploaded to the secured file sharing drop box folder(s) provided by DOE’s FN Request Coordinator. The assigned PM will contact the appropriate FN Data Entry POC in the event there are issues with the submission. Please note that all FNs in PI/Co-PI roles, FNs from countries of risk, and FNs from countries identified on the U.S. Department of State’s list of State Sponsors of Terrorism are NOT permitted to participate on the award until written authorization is received from the Contracting Officer. The Contracting Officer will notify your organization of DOE’s decision regarding the participation of FNs in PI/Co-PI roles, from countries of risk (i.e., China, Iran, North Korea, and Russia), and from countries identified on the U.S. Department of State’s list of State Sponsors of Terrorism. The DOE reserves the right to request additional information or deny participation of any FN at any time. Please provide the requested documents to the attention of Jacqulyn Wilson, who is the Specialist from the Finance and Acquisition Center handling the administrative portion of your application. Jacqulyn Wilson can be reached at (304) 285-4135 or jacqulyn.wilson@netl.doe.gov. Shawn Smearcheck is the DOE Project Manager from the Project Management Division handling the technical portion of your application and can be reached at (304) 285-5098 or shawn.smearcheck@netl.doe.gov. 302 Sincerely, Jacqulyn M. Wilson Contracting Officer Finance and Acquisition Center cc: FOA File Basicinfo@netl.doe.gov GDO_Comms@hq.doe.gov bcarey@akenergyauthority.org jacqulyn.wilson@netl.doe.gov shawn.smearcheck@netl.doe.gov jacqulyn.wilson@netl.doe.gov janet.laukaitis@netl.doe.gov carol.painter@netl.doe.gov 303 304 4860-2460-5322\2 ***Specialist response in blue.***    Alaska Energy Authority  Questions for Department of Energy Regarding FOA 2740 Topic 3  November 14, 2023  Pre‐Award Costs/Process Questions  1. What is required from Alaska Energy Authority (“AEA”) for commitment such that federal award  can be signed?   a. AEA must follow the guidance stated within the Successful Application Letter. In addition  to the deliverables in the letter, this also includes providing an updated Budget Sheet and  SOPO to reflect the change in scope.   Letters of commitment for any new cost share should also be provided.  2. FOA states Pre‐Award costs cannot be incurred prior to the Selection Official signing the Selection  Statement and Analysis.  Has the date of Selection Statement and Analysis occurred? When does  it occur?  Is it the same as the date of award?   a. DOE/CO can authorize pre‐award costs back to date of selection.  However, this will need  to be justified by the recipient and agreed to by the TAL, TPO and CS. The selection signing  will be completed when all parties have agreed on the final version of deliverables,  completing the negotiation period.   The date of your selection letter/notice was 10/17/23.   Does AEA intend on asking to go further back  than the date you were notified the project was selected?  If so, what is the rationale for doing so?    3. Is there a special format or process for prior written approval of pre‐award costs and approval  through Contracting Officer?  To request pre‐award costs, please send the Specialist (Angela.Bosley@netl.doe.gov) and cc the PO an  email/letter requesting approval of pre‐award costs with an itemized list of activities/costs (that are  tied to the SOPO tasks/subtasks) along with the rationale for why the work was started and the date  pre‐award costs were first incurred. This list should also include the total dollar value and cost share  requirement. Below is an example of what this list would look like.   For example:  XXX activity under SOPO Task Y $50 (started on FILL IN DATE and FILL IN RATIONALE)  YYY activity under SOPO Task Z $100(started on FILL IN DATE and FILL IN RATIONALE)  Total $150 (Federal $75/Cost Share $75)    4. Is there any supplemental information needed which would justify a higher award, like a State  Energy Security Plan?  a. No. The scope was based on an evaluation of DOE interests and ongoing work.     305 4860-2460-5322\2 5. Was the award limited by the definition of “interregional” which caps the amount at $250M?  a. The selection process did evaluate but did not prioritize it.     6. Are pre award costs such as preparing the Cyber Security Plan billable?   We’d need to better understand why work on this plan was started before AEA was even notified of  selection.  Please clarify.    Scope of Project Question  1. Can project scope approved for federal award be discussed, re‐considered as the scope is  conditioned on elimination of the two overhead transmission lines?    2. Can non‐federal cost share funds be used to complete AC overhead lines?  3. Can AC substations used to interconnect the HVDC line be included in the scope?  4. Can AC substations included in the original application’s proposed project be included or is this  specific prohibition against all AC equipment?  5. Would replacing the two overhead AC transmission lines with overhead HVDC lines be an  acceptable alternative project?  6. If other awardees do not or cannot claim their grants and funding remains, will AEA be eligible  to submit additional information or another request to increase the award amount?  a. If unused funds are available, the FOA will not reopen.   7. If the project is studied and the schedule will exceed 96 months, will this create a limit on the  funding issued at that point in time?  a. May be constrained by statute         Cost Share Match Sources Questions  1. Can indebtedness proceeds previously issued for the federal award projects be used for cost share  match?    This is too broad to make an assessment.  AEA would need to more clearly detail the scenario  in which debt proceeds were generated. If easier to discuss, we could set up a meeting.    2. Can federal tax‐exempt proceeds be used in conjunction with federal award moneys as cost share  match (e.g. future debt issuances by the State or Alaska Energy Authority)?    This is too broad to make an assessment.  AEA would need to more clearly detail the scenario  in which federal tax‐exempt proceeds were generated.  If easier to discuss, we could set up a  meeting.    It is noted that Federal award funds cannot be used as a selectee’s cost share.  Reference  Appendix A of the FOA and 2 CFR 200 Part 306.  306 4860-2460-5322\2   3. Does AEA need to have entire cost share match required at final award? A portion of cost share  match raised during construction?     AEA has to provide a budget for all project costs (Federal and Cost share).  The cost share does  not need to all be “in hand” at the start of the project; albeit the selectee must have a plan to  acquire, achieve, and satisfy the cost share requirements of the FOA.    4. If construction of a federal award project component (BESS) has started (e.g. design,  environmental review completed, contracted certain component parts) can the committed but  non‐expended portions of the project be eligible for cost share match?    a. Prefer to remain on task with the original SOPO. Pre award spending is not available for  cost share.   Do we have an overlapping project?  If so, this needs to be clarified (including identification of  any associated Federal award number(s)) as projects have to be distinct and costs/funds not co‐ mingled.  Please clarify.  5. Does submission of Budget Justification spreadsheet (SF‐424A) and acceptance by Contracting  Officer fulfill requirement of prior review and approval for cost share match?   Yes    6. Can receipt of federal tax credits following construction of the project be considered a cost share  match source?  In my limited experience with tax credits, the most common tax credit is typically “non‐ refundable” where a “credit” is applied to reduce the amount of taxes due to the IRS.  Is AEA  expecting a “refundable” tax credit whereby AEA would receive a “refund” back from the IRA?   If the latter is what is expected, if earned on federal project, this is likely to be considered  program income and the treatment would default to either a term in the award or, if there  wasn’t a term, back to the regulations at 2 CFR 200 Part 307. Please clarify.      Materials Procurement  1. Manufacturers of HVDC equipment may all be foreign company manufacturers and procurement  and construction some time into the future.  Can a waiver of the Buy American provisions be  requested after the date of final award once specifications and available manufacturers can be  determined?    a. A BABA waiver is available if necessary.       307 308 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 4 SPECIAL TERMS AND CONDITIONS FOR USE IN MOST GRANTS AND COOPERATIVE AGREEMENTS 7  LEGAL AUTHORITY AND EFFECT (JUNE 2015) ........................................................................................ 7   RESOLUTION OF CONFLICTING CONDITIONS ......................................................................................... 7  AWARD AGREEMENT TERMS AND CONDITIONS – BIPARTISAN INFRASTRUCTURE LAW / INFLATION REDUCTION ACT (DECMBER 2014) (NETL – MARCH 2023) ................................................. 7  CONFERENCE SPENDING (FEBRUARY 2015) ............................................................................................ 7  PAYMENT PROCEDURES - REIMBURSEMENT THROUGH THE AUTOMATED CLEARING HOUSE (ACH) VENDOR INQUIRY PAYMENT ELECTRONIC REPORTING SYSTEM (VIPERS) ...................... 8  COST SHARING NOT INVOLVED ................................................................................................................. 8  REBUDGETING AND RECOVERY OF INDIRECT COSTS - REIMBURSABLE INDIRECT COSTS AND FRINGE BENEFITS ................................................................................................................................. 9  REBUDGETING AND RECOVERY OF INDIRECT COSTS - REIMBURSABLE INDIRECT COSTS ...... 9  REBUDGETING AND RECOVERY OF INDIRECT COSTS - INDIRECT COSTS AND FRINGE BENEFITS ARE NOT REIMBURSABLE ...................................................................................................... 10  PRE-AWARD COSTS (DECEMBER 2014) ................................................................................................... 10  USE OF PROGRAM INCOME - DEDUCTION ............................................................................................. 10  STATEMENT OF FEDERAL STEWARDSHIP ............................................................................................. 10  STATEMENT OF SUBSTANTIAL INVOLVEMENT................................................................................... 10  SITE VISITS ..................................................................................................................................................... 11  REPORTING REQUIREMENTS (APRIL 2023) ............................................................................................ 11  PUBLICATIONS .............................................................................................................................................. 12  FEDERAL, STATE, AND MUNICIPAL REQUIREMENTS ......................................................................... 12  INTELLECTUAL PROPERTY PROVISIONS AND CONTACT INFORMATION ..................................... 12  NOTICE REGARDING THE PURCHASE OF AMERICAN-MADE EQUIPMENT AND PRODUCTS -- SENSE OF CONGRESS ................................................................................................................................... 12  INSURANCE COVERAGE (DECEMBER 2014) ........................................................................................... 13  REAL PROPERTY (DECEMBER 2014)......................................................................................................... 13  EQUIPMENT (DECEMBER 2014) ................................................................................................................. 13  SUPPLIES (DECEMBER 2014) ...................................................................................................................... 14  INTANGIBLE PROPERTY (DECEMBER 2014) ........................................................................................... 14  PROPERTY TRUST RELATIONSHIP (DECEMBER 2014) ......................................................................... 14  INSOLVENCY, BANKRUPTCY OR RECEIVERSHIP ................................................................................ 14  PERFORMANCE OF WORK IN UNITED STATES ..................................................................................... 15  CATEGORICAL EXCLUSION (CX) ................................................................................................................. 15  309 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 5 DECONTAMINATION AND/OR DECOMMISSIONING (D &D) COSTS ................................................. 15  SYSTEM FOR AWARD MANAGEMENT AND UNIVERSAL IDENTIFIER REQUIREMENTS ............ 15  FINAL INCURRED COST AUDIT (DECEMBER 2014)............................................................................... 16  LOBBYING RESTRICTIONS (MARCH 2012) .............................................................................................. 16  CORPORATE FELONY CONVICTION AND FEDERAL TAX LIABILITY ASSURANCES (MARCH 2014).................................................................................................................................................................. 17  NONDISCLOSURE AND CONFIDENTIALITY AGREEMENTS ASSURANCES (JUNE 2015) .............. 17  REPORTING OF MATTERS RELATED TO RECIPIENT INTEGRITY AND PERFORMANCE (DECEMBER 2015) ......................................................................................................................................... 18  SUBAWARD/SUBCONTRACT CHANGE NOTIFICATION .......................................................................... 19  GO/NO-GO DECISION 20  IMPLEMENTATION OF EXECUTIVE ORDER 13798, PROMOTING FREE SPEECH AND RELIGIOUS LIBERTY (NOVEMBER 2020) 21  CONTINUED USE OF REAL PROPERTY AND EQUIPMENT (OCTOBER 2022) ....................................... 21  FOREIGN NATIONAL PARTICIPATION – APPROVAL REQUIRED (MARCH 2023) ............................... 21  POST AWARD DUE DILIGENCE REVIEWS (SEPTEMBER 2023) ............................................................... 22  EXPORT CONTROL (MARCH 2023) ................................................................................................................ 22  INTERIM CONFLICT OF INTEREST POLICY FOR FINANCIAL ASSISTANCE (MARCH 2023) ............ 22  ORGANIZATIONAL CONFLICT OF INTEREST (MARCH 2023) ................................................................. 23  BUY AMERICAN REQUIREMENT FOR INFRASTRUCTURE PROJECTS (MARCH 2023) ..................... 23  PROHIBITION ON CERTAIN TELECOMMUNICATIONS AND VIDEO SURVEILLANCE SERVICES OR EQUIPMENT (MARCH 2023) 27  PROHIBITION RELATED TO FOREIGN GOVERNMENT-SPONSORED TALENT RECRUITMENT PROGRAMS (MARCH 2023) 28  PARTICIPANTS AND OTHER COLLABORATING ORGANIZATIONS (SEPTEMBER 2023) .................. 28  HUMAN SUBJECTS RESEARCH (MARCH 2023) .......................................................................................... 29  FRAUD, WASTE AND ABUSE (MARCH 2023) .............................................................................................. 30  TRANSPARENCY OF FOREIGN CONNECTIONS (SEPTEMBER 2023) ..................................................... 30  FOREIGN COLLABORATION CONSIDERATIONS (MARCH 2023) ........................................................... 31  REPORTING SUBAWARD AND EXECUTIVE COMPENSATION (SEPTEMBER 2023) ........................... 32  POTENTIALLY DUPLICATIVE FUNDING NOTICE (MARCH 2023) .......................................................... 34  REQUIRED RISK MITIGATION (MARCH 2023) ............................................................................................ 34  REPORTING, TRACKING AND SEGREGATION OF INCURRED COSTS (MARCH 2023) ...................... 35  COMMUNITY BENEFITS OUTCOMES AND OBJECTIVES – NETL .......................................................... 35  CYBERSECURITY PLAN (SEPTEMBER 2023) .............................................................................................. 35  DAVIS-BACON ACT REQUIREMENTS (MARCH 2023) ............................................................................... 35  310 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 6 AFFIRMATIVE ACTION AND PAY TRANSPARENCY REQUIREMENTS (SEPTEMBER 2023) ............ 37  SIGNAGE (SEPTEMBER 2023) 38  311 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 7 SPECIAL TERMS AND CONDITIONS FOR USE IN MOST GRANTS AND COOPERATIVE AGREEMENTS LEGAL AUTHORITY AND EFFECT (JUNE 2015) (a) A DOE financial assistance award is valid only if it is in writing and is signed, either in writing or electronically, by a DOE Contracting Officer. (b) Recipients are free to accept or reject the award. A request to draw down DOE funds constitutes the Recipient's acceptance of the terms and conditions of this Award. RESOLUTION OF CONFLICTING CONDITIONS Any apparent inconsistency between Federal statutes and regulations and the terms and conditions contained in this award must be referred to the DOE Award Administrator for guidance. AWARD AGREEMENT TERMS AND CONDITIONS – BIPARTISAN INFRASTRUCTURE LAW / INFLATION REDUCTION ACT (DECMBER 2014) (NETL – MARCH 2023) This award/agreement consists of the Assistance Agreement cover page, plus the following: Attachment 1 Intellectual Property Provisions Attachment 2 Statement of Project Objectives Attachment 3 Federal Assistance Reporting Checklist and Instructions Attachment 4 Budget Information Attachment 5 Community Benefits Outcomes and Objectives The following are incorporated into this Award by reference:  DOE Assistance Regulations, 2 CFR part 200 as amended by 2 CFR part 910 at https://www.eCFR.gov.  Research Terms & Conditions (November 12, 2020) and the DOE Agency Specific Requirements (November 2020) at https://www.nsf.gov/awards/managing/rtc.jsp.  National Policy Requirements (November 12, 2020) at https://www.nsf.gov/awards/managing/rtc.jsp.  Public Law 117-58, also known as the Bipartisan Infrastructure Law (BIL).  The Recipient’s application/proposal as approved by DOE. CONFERENCE SPENDING (FEBRUARY 2015) The recipient shall not expend any funds on a conference not directly and programmatically related to the purpose for which the grant or cooperative agreement was awarded that would defray the cost to the United States Government of a conference held by any Executive branch department, agency, board, commission, or office for which the cost to the United States Government would otherwise exceed $20,000, thereby circumventing the required notification by the head of any such Executive Branch department, agency, board, commission, or office to the Inspector General (or senior ethics official for any entity without an Inspector General), of the date, location, and number of employees attending such conference. 312 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 8 PAYMENT PROCEDURES - REIMBURSEMENT THROUGH THE AUTOMATED CLEARING HOUSE (ACH) VENDOR INQUIRY PAYMENT ELECTRONIC REPORTING SYSTEM (VIPERS) a. Method of Payment. Payment will be made by reimbursement through ACH. b. Requesting Reimbursement. Requests for reimbursements must be made electronically through Department of Energy's Oak Ridge Financial Service Center (ORFSC) VIPERS. To access and use VIPERS, you must enroll at https://vipers.doe.gov. Detailed instructions on how to enroll are provided on the web site. For non-construction awards, you must submit a Standard Form (SF) 270, "Request for Advance or Reimbursement" at https://vipers.doe.gov and attach a file containing appropriate supporting documentation. The file attachment must show the total federal share claimed on the SF 270, the non-federal share claimed for the billing period if cost sharing is required, and cumulative expenditures to date (both Federal and non-Federal) for each of the following categories: salaries/wages and fringe benefits; equipment; travel; participant/training support costs, if any; other direct costs, including subawards/contracts; and indirect costs. For construction awards, you must submit a SF 271, "Outlay Report and Request for Reimbursement for Construction Programs," through VIPERS. c. Timing of submittals. Submittal of the SF 270 or SF 271 should coincide with your normal billing pattern, but not more frequently than every two weeks. Requests for reimbursement must be limited to the amount of disbursements made during the billing period for the federal share of direct project costs and the proportionate share of any allowable indirect costs incurred during that billing period. At a minimum, Recipient’s should meet the required cost share percentage (specified in the Cost Sharing Term) by each go/no go decision point specified in the Statement of Project Objectives (Attachment 2). d. Adjusting payment requests for available cash. You must disburse any funds that are available from repayments to and interest earned on a revolving fund, program income, rebates, refunds, contract settlements, audit recoveries, credits, discounts, and interest earned on any of those funds before requesting additional cash payments from DOE/NNSA. e. Payments. The DOE approving official will approve the invoice as soon as practicable but not later than 30 days after your request is received, unless the billing is improper. Upon receipt of an invoice payment authorization from the DOE approving official, the ORFSC will disburse payment to you. You may check the status of your payments at the VIPER web site. All payments are made by electronic funds transfer to the bank account identified on the ACH Vendor/Miscellaneous Payment Enrollment Form (SF 3881) that you filed. COST SHARING NOT INVOLVED a. Total Estimated Project Cost is the sum of the Government share and Recipient share of the estimated project costs. The Recipient's cost share must come from non-Federal sources unless otherwise allowed by law. By accepting federal funds under this award, you agree that you are liable for your percentage share of total allowable project costs, on a budget period basis, even if the project is terminated early or is not funded to its completion. This cost is shared as follows: 313 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 9 Budget Period No.$%$% 1 #DIV/0! #DIV/0! $0 Total Project $0 #DIV/0! $0 #DIV/0! $0 TotalGovernment Share Recipient Share   b. If you discover that you may be unable to provide cost sharing of at least the amount identified in paragraph a of this term, you should immediately provide written notification to the DOE Award Administrator indicating whether you will continue or phase out the project. If you plan to continue the project, the notification must describe how replacement cost sharing will be secured. c. You must maintain records of all project costs that you claim as cost sharing, including in-kind costs, as well as records of costs to be paid by DOE/NNSA. Such records are subject to audit. d. Failure to provide the cost sharing required by this term may result in the subsequent recovery by DOE/NNSA of some or all the funds provided under the award. REBUDGETING AND RECOVERY OF INDIRECT COSTS - REIMBURSABLE INDIRECT COSTS AND FRINGE BENEFITS a. If actual allowable indirect costs are less than those budgeted and funded under the award, you may use the difference to pay additional allowable direct costs during the project period. If at the completion of the award the Government's share of total allowable costs (i.e., direct and indirect), is less than the total costs reimbursed, you must refund the difference. b. Recipients are expected to manage their indirect costs. DOE will not amend an award solely to provide additional funds for changes in indirect cost rates. DOE recognizes that the inability to obtain full reimbursement for indirect costs means the recipient must absorb the underrecovery. Such underrecovery may be allocated as part of the organization's required cost sharing. REBUDGETING AND RECOVERY OF INDIRECT COSTS - REIMBURSABLE INDIRECT COSTS a. If actual allowable indirect costs are less than those budgeted and funded under the award, you may use the difference to pay additional allowable direct costs during the project period. If at the completion of the award the Government's share of total allowable costs (i.e., direct and indirect), is less than the total costs reimbursed, you must refund the difference. b. Recipients are expected to manage their indirect costs. DOE will not amend an award solely to provide additional funds for changes in indirect cost rates. DOE recognizes that the inability to obtain full reimbursement for indirect costs means the recipient must absorb the underrecovery. Such underrecovery may be allocated as part of the organization's required cost sharing. c. The budget for this award includes indirect costs, but does not include fringe benefits. Therefore, fringe benefit costs shall not be charged to nor shall reimbursement be requested for this project nor shall the fringe benefit costs for this project be allocated to any other federally sponsored project. In addition, fringe benefit costs shall not be counted as cost share unless approved by the Contracting Officer. 314 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 10 REBUDGETING AND RECOVERY OF INDIRECT COSTS - INDIRECT COSTS AND FRINGE BENEFITS ARE NOT REIMBURSABLE The budget for this award does not include indirect costs or fringe benefits. Therefore, these expenses shall not be charged to nor reimbursement requested for this project nor shall the fringe and indirect costs from this project be allocated to any other federally sponsored project. In addition, indirect costs or fringe benefits shall not be counted as cost share unless approved by the Contracting Officer. REBUDGETING AND RECOVERY OF INDIRECT COSTS – DE MINIMIS RATE AND FRINGE BENEFITS: a. The Recipient has elected to charge a de minimis rate of 10% allocated to a base of modified total direct costs (MTDC) per 2 CFR Part 200.414(f). This methodology must be used consistently until the Recipient choses to negotiate indirect cost billing rates. De minimis costs are not verifiable from the Recipient’s records, therefore, the Recipient cannot claim the resulting indirect costs as cost share per 2 CFR Part 200.306(b)(1). b. If the recipient has elected to include fringe benefits in the MTDC, fringe benefit costs have been allocated to this award under a segregated fringe billing rate. The fringe costs were found to be reasonable, allocable, and allowable as reflected in the budget. PRE-AWARD COSTS (DECEMBER 2014) You are entitled to reimbursement for costs incurred on or after [], as authorized by the pre-award costs letter dated [], if such costs are allowable in accordance with the applicable Federal cost principles referenced in 2 CFR part 200 as amended by 2 CFR part 910. USE OF PROGRAM INCOME - DEDUCTION If you earn program income during the project period as a result of this award, you must deduct the program income from the total allowable project costs to determine the net allowable costs on which the Federal share is based. STATEMENT OF FEDERAL STEWARDSHIP DOE/NNSA will exercise normal Federal stewardship in overseeing the project activities performed under this award. Stewardship activities include, but are not limited to, conducting site visits; reviewing performance and financial reports; providing technical assistance and/or temporary intervention in unusual circumstances to correct deficiencies which develop during the project; assuring compliance with terms and conditions; and reviewing technical performance after project completion to ensure that the award objectives have been accomplished. STATEMENT OF SUBSTANTIAL INVOLVEMENT DOE has substantial involvement in work performed under awards made as a result of this FOA. DOE does not limit its involvement to the administrative requirements of the award. Instead, DOE has substantial involvement in the direction and redirection of the technical aspects of the project as a whole. Substantial involvement includes, but is not limited to, the following: 315 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 11 1. DOE shares responsibility with the recipient for the management, control, direction, and performance of the project. 2. DOE may intervene in the conduct or performance of work under this award for programmatic reasons. Intervention includes the interruption or modification of the conduct or performance of project activities. 3. DOE may redirect or discontinue funding the project based on the outcome of DOE’s evaluation of the project at the Go/No-Go decision point(s) as identified in the Project Management Plan. 4. Reviewing and concurring with ongoing technical performance to ensure that adequate progress has been obtained within the current Budget Period authorized by DOE before work can commence on subsequent Budget Periods. 5. DOE participates in major project decision-making processes. SITE VISITS DOE/NNSA's authorized representatives have the right to make site visits at reasonable times to review project accomplishments and management control systems and to provide technical assistance, if required. You must provide, and must require your subrecipients to provide, reasonable access to facilities, office space, resources, and assistance for the safety and convenience of the government representatives in the performance of their duties. All site visits and evaluations must be performed in a manner that does not unduly interfere with or delay the work. REPORTING REQUIREMENTS (APRIL 2023) a. Requirements. The reporting requirements for this award are identified on the Federal Assistance Reporting Checklist, DOE F 4600.2, attached to this award. Failure to comply with these reporting requirements is considered a material noncompliance with the terms of the award. Noncompliance may result in withholding of future payments, suspension, or termination of the current award, and withholding of future awards. A willful failure to perform, a history of failure to perform, or unsatisfactory performance of this and/or other financial assistance awards, may also result in a debarment action to preclude future awards by Federal agencies. b. Dissemination of scientific/technical reporting products. Reporting project results in scientific and technical information (STI) publications/products to the DOE Office of Scientific and Technical Information (OSTI) ensures dissemination of research results to the public as well as preservation of the results. The DOE form F 4600.2, B. Scientific/Technical Reporting, has instructions for the DOE Energy Link (E-Link) system managed by OSTI. Scientific/technical reports and other STI products submitted under this award will be disseminated publicly on the Web via OSTI.GOV (https://www.osti.gov), unless the STI contains patentable material, protected data, or SBIR/STTR data, which must be indicated per instructions in DOE 4600.2. c. Restrictions. Restrictions. STI products submitted to the DOE via E-link must not contain any Protected Personally Identifiable Information (PII), limited rights data, classified information, information subject to export control classification, or other information not subject to public release. The Contracting Officer or Technical Project Officer should be contacted with any questions. Limited rights data means data (other than computer software) developed at private expense that embody trade secrets or are commercial or financial and confidential or privileged. SBIR/STTR Protected Data, and other data subject to statutory data protection 316 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 12 authorized by the award may be submitted, provided such data is properly marked and identified during submission. Submissions must not contain any “Proprietary”, “Confidential” or “Business Sensitive” markings or similar restrictive markings not authorized by the applicable government agreement.; it is acknowledged that DOE has the right to cancel or ignore such markings. PUBLICATIONS a. You are encouraged to publish or otherwise make publicly available the results of the work conducted under the award. b. An acknowledgment of Federal support and a disclaimer must appear in the publication of any material, whether copyrighted or not, based on or developed under this project, as follows: Acknowledgment: "This material is based upon work supported by the Department of Energy, Grid Deployment Office, under Award Number DE-GD0000XXX." Disclaimer: "This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof." FEDERAL, STATE, AND MUNICIPAL REQUIREMENTS You must obtain any required permits and comply with applicable federal, state, and municipal laws, codes, and regulations for work performed under this award. INTELLECTUAL PROPERTY PROVISIONS AND CONTACT INFORMATION a. The intellectual property provisions applicable to this award are provided as an attachment to this award or are referenced on the Assistance Agreement Face Page. A list of all intellectual property provisions may be found at http://energy.gov/gc/standard-intellectual-property-ip-provisions-financial-assistance-awards b. Questions regarding intellectual property matters should be referred to the DOE Award Administrator and the Patent Counsel designated as the service provider for the DOE office that issued the award. The IP Service Providers List is found at http://energy.gov/gc/downloads/intellectual-property-ip-service-providers-acquisition- and-assistance-transactions NOTICE REGARDING THE PURCHASE OF AMERICAN-MADE EQUIPMENT AND PRODUCTS -- SENSE OF CONGRESS It is the sense of the Congress that, to the greatest extent practicable, all equipment and products purchased with funds made available under this award should be American-made. 317 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 13 INSURANCE COVERAGE (DECEMBER 2014) See 2 CFR 200.310 for insurance requirements for real property and equipment acquired or improved with Federal funds. REAL PROPERTY (DECEMBER 2014) Subject to the conditions set forth in 2 CFR Part 200.311, title to real property acquired or improved under a Federal award will vest upon acquisition in the non-Federal entity. The non-Federal entity cannot encumber this property and must follow the requirements of 2 CFR Part 200.311 before disposing of the property. Except as otherwise provided by Federal statutes or by the Federal awarding agency, real property will be used for the originally authorized purpose as long as needed for that purpose. When real property is no longer needed for the originally authorized purpose, the non-Federal entity must obtain disposition instructions from the Federal awarding agency or pass-through entity. The instructions must provide for one of the following alternatives: (a) retain title after compensating the Federal awarding agency as described in 2 CFR Part 200.311(c)(1); (b) Sell the property and compensate the federal awarding agency as specified in CFR Part 200.311(c)(2); or (c) transfer title to the Federal awarding agency or to a third Party designated/approved by the Federal awarding agency as specified in CFR Part 200.311(c)(3). See 2 CFR Part 200.311 for additional requirements pertaining to real property acquired or improved under a Federal award. Also see 2 CFR Part 910.360 for amended requirements for Real Property for For-Profit recipients. EQUIPMENT (DECEMBER 2014) Subject to the conditions provided in 2 CFR Part 200.313, title to equipment (property) acquired under a Federal award will vest conditionally with the non-Federal entity. The non-Federal entity cannot encumber this property and must follow the requirements of 2 CFR Part 200.313 before disposing of the property. States must use equipment acquired under a Federal award by the state in accordance with state laws and procedures. Equipment must be used by the non-Federal entity in the program or project for which it was acquired as long as it is needed, whether or not the project or program continues to be supported by the Federal award. When no longer needed for the originally authorized purpose, the equipment may be used by programs supported by the Federal awarding agency in the priority order specified in 2 CFR Part 200.313(c)(1)(i) and (ii). Management requirements, including inventory and control systems, for equipment are provided in 2 CFR Part 200.313(d). When equipment acquired under a Federal award is no longer needed, the non-Federal entity must obtain disposition instructions from the Federal awarding agency or pass-through entity. 318 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 14 Disposition will be made as follows: (a) items of equipment with a current fair market value of $5,000 or less may be retained, sold, or otherwise disposed of with no further obligation to the Federal awarding agency; (b) Non-Federal entity may retain title or sell the equipment after compensating the Federal awarding agency as described in 2 CFR Part 200.313(e)(2); or (c) transfer title to the Federal awarding agency or to an eligible third Party as specified in CFR Part 200.313(e)(3). See 2 CFR Part 200.313 for additional requirements pertaining to equipment acquired under a Federal award. Also see 2 CFR Part 200.439 Equipment and other capital expenditures. See 2 CFR Part 910.360 for amended requirements for Equipment for For-Profit recipients. SUPPLIES (DECEMBER 2014) See 2 CFR Part 200.314 for requirements pertaining to supplies acquired under a Federal award. See also § 200.453 Materials and supplies costs, including costs of computing devices. INTANGIBLE PROPERTY (DECEMBER 2014) Title to intangible property (as defined in 2 CFR Part 200.59) acquired under a Federal award vests upon acquisition in the non-Federal entity. Intangible property includes trademarks, copyrights, patents and patent applications. See 2 CFR Part 200.315 for additional requirements pertaining to intangible property acquired under a Federal award. Also see 2 CFR Part 910.362 for amended requirements for Intellectual Property for For-Profit recipients. PROPERTY TRUST RELATIONSHIP (DECEMBER 2014) Real property, equipment, and intangible property, that are acquired or improved with a Federal award must be held in trust by the non-Federal entity as trustee for the beneficiaries of the project or program under which the property was acquired or improved. See 2 CFR Part 200.316 for additional requirements pertaining to real property, equipment, and intangible property acquired or improved under a Federal award. INSOLVENCY, BANKRUPTCY OR RECEIVERSHIP a. You shall immediately notify the DOE of the occurrence of any of the following events: (i) you or your parent's filing of a voluntary case seeking liquidation or reorganization under the Bankruptcy Act; (ii) your consent to the institution of an involuntary case under the Bankruptcy Act against you or your parent; (iii) the filing of any similar proceeding for or against you or your parent, or its consent to, the dissolution, winding-up or readjustment of your debts, appointment of a receiver, conservator, trustee, or other officer with similar powers over you, under any other applicable state or federal law; or (iv) your insolvency due to your inability to pay your debts generally as they become due. 319 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 15 b. Such notification shall be in writing and shall: (i) specifically set out the details of the occurrence of an event referenced in paragraph a; (ii) provide the facts surrounding that event; and (iii) provide the impact such event will have on the project being funded by this award. c. Upon the occurrence of any of the four events described in the first paragraph, DOE reserves the right to conduct a review of your award to determine your compliance with the required elements of the award (including such items as cost share, progress towards technical project objectives, and submission of required reports). If the DOE review determines that there are significant deficiencies or concerns with your performance under the award, DOE reserves the right to impose additional requirements, as needed, including (i) change your payment method; or (ii) institute payment controls. d. Failure of the Recipient to comply with this term may be considered a material noncompliance of this financial assistance award by the Contracting Officer. PERFORMANCE OF WORK IN UNITED STATES The Recipient agrees that at least 100% of the direct labor cost for the project (including subrecipient labor) shall be incurred in the United States, unless the Recipient can demonstrate to the satisfaction of the Department of Energy that the United States economic interest will be better served through a greater percentage of the work being performed outside the United States. CATEGORICAL EXCLUSION (CX) DOE must comply with the National Environmental Policy Act (NEPA) prior to authorizing the use of federal funds. Based on all information provided by the Recipient, DOE has made a NEPA determination by issuing a CX, thereby authorizing use of funds for the defined project activities. If the Recipient later adds to or modifies the activities reviewed and approved under the original DOE NEPA determination, the Recipient must notify the DOE Contracting Officer before proceeding with the new and/or modified activities. Those additions or modifications may be subject to review by the DOE NEPA Compliance Officer and approval by the DOE Contracting Officer, and may require a new NEPA determination. [insert any special conditions, if applicable] DECONTAMINATION AND/OR DECOMMISSIONING (D &D) COSTS Notwithstanding any other terms of this Agreement, the Government shall not be responsible for or have any obligation to the recipient for (i) Decontamination and/or Decommissioning (D&D) of any of the recipient's facilities, or (ii) any costs which may be incurred by the recipient in connection with the D&D of any of its facilities due to the performance of the work under this Agreement, whether said work was performed prior to or subsequent to the effective date of this Agreement. SYSTEM FOR AWARD MANAGEMENT AND UNIVERSAL IDENTIFIER REQUIREMENTS A. Requirement for System for Award Management (SAM) Unless exempted from this requirement under 2 CFR 25.110, the prime recipient must remain registered and maintain current information in SAM for the entire period of performance of the award. This includes providing information on the prime recipient’s immediate and highest level owner and subsidiaries, as well as on all of its predecessors that have been awarded a Federal contract or Federal financial assistance agreements within the last three years, if applicable, until the prime 320 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 16 recipient submits the final financial report required under this award or receives the final payment, whichever is later. This requires the prime recipient to review its information in SAM at least annually after the initial registration, and to update its information as soon as there are changes. Reviews and updates may be required more frequently due to changes in recipient information or as required by another award term. B. Requirement for Unique Entity Identifier If authorized to make subawards under this award, the prime recipient: 1. Must notify potential subrecipients that no entity (see definition in paragraph C of this award term) may receive a subaward until the entity has provided its unique entity identifier to the prime recipient. 2. Must not make a subaward to an entity unless the entity has provided its unique entity identifier to the prime recipient. Subrecipients are not required to obtain an active SAM registration, but must obtain a unique entity identifier. C. Definitions For purposes of this term: 1. System for Award Management (SAM) means the Federal repository into which a recipient must provide information required for the conduct of business as a recipient. Additional information about registration procedures may be found at the SAM internet site (currently at https://www.sam.gov). 2. Unique Entity Identifier means the identifier assigned by SAM to uniquely identify business entities. 3. Entity includes non-Federal entities as defined at 2 CFR 200.1 and also includes all of the following for purposes of this part: a. A foreign organization; b. A foreign public entity; c. A domestic for-profit organization; and d. A Federal agency. 4. Subaward has the meaning given in 2 CFR 200.1. 5. Subrecipient has the meaning given in 2 CFR 200.1. FINAL INCURRED COST AUDIT (DECEMBER 2014) In accordance with 2 CFR Part 200 as amended by 2 CFR Part 910, DOE reserves the right to initiate a final incurred cost audit on this award. If the audit has not been performed or completed prior to the closeout of the award, DOE retains the right to recover an appropriate amount after fully considering the recommendations on disallowed costs resulting from the final audit. LOBBYING RESTRICTIONS (MARCH 2012) 321 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 17 By accepting funds under this award, you agree that none of the funds obligated on the award shall be expended, directly or indirectly, to influence congressional action on any legislation or appropriation matters pending before Congress, other than to communicate to Members of Congress as described in 18 U.S.C. 1913. This restriction is in addition to those prescribed elsewhere in statute and regulation. CORPORATE FELONY CONVICTION AND FEDERAL TAX LIABILITY ASSURANCES (MARCH 2014) By entering into this agreement, the undersigned attests that [] has not been convicted of a felony criminal violation under Federal law in the 24 months preceding the date of signature. The undersigned further attests that [] does not have any unpaid Federal tax liability that has been assessed, for which all judicial and administrative remedies have been exhausted or have lapsed, and that is not being paid in a timely manner pursuant to an agreement with the authority responsible for collecting the tax liability. For purposes of these assurances, the following definitions apply: A Corporation includes any entity that has filed articles of incorporation in any of the 50 states, the District of Columbia, or the various territories of the United States [but not foreign corporations]. It includes both for- profit and non-profit organizations. NONDISCLOSURE AND CONFIDENTIALITY AGREEMENTS ASSURANCES (JUNE 2015) (1) By entering into this agreement, the undersigned attests that [] does not and will not require its employees or contractors to sign internal nondisclosure or confidentiality agreements or statements prohibiting or otherwise restricting its employees or contactors from lawfully reporting waste, fraud, or abuse to a designated investigative or law enforcement representative of a Federal department or agency authorized to receive such information. (2) The undersigned further attests that [] does not and will not use any Federal funds to implement or enforce any nondisclosure and/or confidentiality policy, form, or agreement it uses unless it contains the following provisions: a.‘‘These provisions are consistent with and do not supersede, conflict with, or otherwise alter the employee obligations, rights, or liabilities created by existing statute or Executive order relating to (1) classified information, (2) communications to Congress, (3) the reporting to an Inspector General of a violation of any law, rule, or regulation, or mismanagement, a gross waste of funds, an abuse of authority, or a substantial and specific danger to public health or safety, or (4) any other whistleblower protection. The definitions, requirements, obligations, rights, sanctions, and liabilities created by controlling Executive orders and statutory provisions are incorporated into this agreement and are controlling.’’ b. The limitation above shall not contravene requirements applicable to Standard Form 312, Form 4414, or any other form issued by a Federal department or agency governing the nondisclosure of classified information. c. Notwithstanding provision listed in paragraph (a), a nondisclosure or confidentiality policy form or agreement that is to be executed by a person connected with the conduct of an intelligence or intelligence- related activity, other than an employee or officer of the United States Government, may contain provisions appropriate to the particular activity for which such document is to be used. Such form or agreement shall, at a 322 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 18 minimum, require that the person will not disclose any classified information received in the course of such activity unless specifically authorized to do so by the United States Government. Such nondisclosure or confidentiality forms shall also make it clear that they do not bar disclosures to Congress, or to an authorized official of an executive agency or the Department of Justice, that are essential to reporting a substantial violation of law. REPORTING OF MATTERS RELATED TO RECIPIENT INTEGRITY AND PERFORMANCE (DECEMBER 2015) a. General Reporting Requirement If the total value of your currently active grants, cooperative agreements, and procurement contracts from all Federal awarding agencies exceeds $10,000,000 for any period of time during the period of performance of this Federal award, then you as the recipient during that period of time must maintain the currency of information reported to the System for Award Management (SAM) that is made available in the designated integrity and performance system (currently the Federal Awardee Performance and Integrity Information System (FAPIIS)) about civil, criminal, or administrative proceedings described in paragraph 2 of this award term and condition. This is a statutory requirement under section 872 of Public Law 110-417, as amended (41 U.S.C. 2313). As required by section 3010 of Public Law 111-212, all information posted in the designated integrity and performance system on or after April 15, 2011, except past performance reviews required for Federal procurement contracts, will be publicly available. b. Proceedings About Which You Must Report Submit the information required about each proceeding that: 1. Is in connection with the award or performance of a grant, cooperative agreement, or procurement contract from the Federal Government; 2. Reached its final disposition during the most recent five year period; and 3. Is one of the following: (A) A criminal proceeding that resulted in a conviction, as defined in paragraph 5 of this award term and condition; (B) A civil proceeding that resulted in a finding of fault and liability and payment of a monetary fine, penalty, reimbursement, restitution, or damages of $5,000 or more; (C) An administrative proceeding, as defined in paragraph 5. of this award term and condition, that resulted in a finding of fault and liability and your payment of either a monetary fine or penalty of $5,000 or more or reimbursement, restitution, or damages in excess of $100,000; or (D) Any other criminal, civil, or administrative proceeding if: (i) It could have led to an outcome described in paragraph 2.c.(1), (2), or (3) of this award term and condition; 323 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 19 (ii) It had a different disposition arrived at by consent or compromise with an acknowledgment of fault on your part; and (iii) The requirement in this award term and condition to disclose information about the proceeding does not conflict with applicable laws and regulations. c. Reporting Procedures Enter in the SAM Entity Management area the information that SAM requires about each proceeding described in paragraph 2 of this award term and condition. You do not need to submit the information a second time under assistance awards that you received if you already provided the information through SAM because you were required to do so under Federal procurement contracts that you were awarded. d. Reporting Frequency During any period of time when you are subject to the requirement in paragraph 1 of this award term and condition, you must report proceedings information through SAM for the most recent five year period, either to report new information about any proceeding(s) that you have not reported previously or affirm that there is no new information to report. Recipients that have Federal contract, grant, and cooperative agreement awards with a cumulative total value greater than $10,000,000 must disclose semiannually any information about the criminal, civil, and administrative proceedings. e. Definitions For purposes of this award term and condition: 1. Administrative proceeding means a non-judicial process that is adjudicatory in nature in order to make a determination of fault or liability (e.g., Securities and Exchange Commission Administrative proceedings, Civilian Board of Contract Appeals proceedings, and Armed Services Board of Contract Appeals proceedings). This includes proceedings at the Federal and State level but only in connection with performance of a Federal contract or grant. It does not include audits, site visits, corrective plans, or A. Reporting of Matters Related to Recipient Integrity and Performance. 2. Conviction, for purposes of this award term and condition, means a judgment or conviction of a criminal offense by any court of competent jurisdiction, whether entered upon a verdict or a plea, and includes a conviction entered upon a plea of nolo contendere. 3. Total value of currently active grants, cooperative agreements, and procurement contracts includes— (A) Only the Federal share of the funding under any Federal award with a recipient cost share or match; and (B) The value of all expected funding increments under a Federal award and options, even if not yet exercised. SUBAWARD/SUBCONTRACT CHANGE NOTIFICATION Except for subawards and/or subcontracts specifically proposed as part of the Recipient’s Application for award, the Recipient must notify the DOE Contracting Officer and Project Officer in writing 30 days prior to 324 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 20 the execution of new or modified subawards/subcontracts. This notification does not constitute a waiver of the prior approval requirements outlined in 2 CFR 200, nor does it relieve the Recipient from its obligation to comply with applicable Federal statutes, regulations, and executive orders. In order to satisfy this notification requirement, Recipient documentation must, as a minimum, include the following: 1. A description of the research to be performed, the service to be provided, or the equipment to be purchased; 2. Cost share commitment letter if the subawardee is providing cost share to the award; 3. Updated budget justification, budget pages; 4. An assurance that the process undertaken by the Recipient to solicit the subaward/subcontract complies with their written procurement procedures as outlined in 2 CFR 200.317 through 200.327. 5. An assurance that no planned, actual or apparent conflict of interest exists between the Recipient and the selected subawardee/subcontractor and that the Recipient’s written standards of conduct were followed;1 6. A completed Environmental Questionnaire, if applicable; 7. An assurance that the subawardee/subcontractor is not a debarred or suspended entity; and 8. An assurance that all required award provisions will be flowed down in the resulting subaward/subcontract. The Recipient is responsible for making a final determination to award or modify subawards/subcontracts under this agreement, but the Recipient may not proceed with the subaward/subcontract until the Contracting Officer determines, and provides the Recipient written notification, that the information provided is adequate. Should the Recipient not receive a written notification of adequacy from the Contracting Officer within 30 days of the submission of the subaward/subcontract documentation stipulated above, Recipient may proceed to award or modify the proposed subaward/subcontract. GO/NO-GO DECISION The Government has elected to include a go/no-go decision in the Statement of Project Objectives (SOPO) of the award. If it is advantageous for the Government to proceed beyond the technical milestone(s) set forth in the SOPO, the Contracting Officer will notify the recipient in writing authorizing the recipient to proceed beyond the technical milestone(s) in the SOPO. If it is determined that it would not be advantageous for the Government to proceed beyond the technical milestone(s), the Contracting Officer will notify the recipient in 1 It is DOE’s position that the existence of a “covered relationship” as defined in 5 C.F.R. § 2635.502(a)&(b) between a member of the Recipient’s owners or senior management and a member of a subawardee’s/subcontractor’s owners or senior management creates at a minimum an apparent conflict of interest that would require the Recipient to notify the Contracting Officer and provide detailed information and justification (including, for example, mitigation measures) as to why the subaward or subcontract does not create an actual conflict of interest. Recipients must also notify the Contracting Officer of any new subcontract or subaward to: (1) an entity that is owned or otherwise controlled by the Recipient; or (2) an entity that is owned or otherwise controlled by another entity that also owns or otherwise controls the Recipient, as it is DOE’s position that these situations also create at a minimum an apparent conflict of interest. 325 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 21 writing of such decision and the award is considered completed. The maximum liability to the Government is limited to the allowable, allocable, and reasonableness of the cost incurred by the recipient within the funds made available. The Government reserves the right to deobligate any remaining funds from the award. The recipient shall submit all final deliverables, including a final scientific/technical report, for the completed work in accordance with the reporting requirements of the award. IMPLEMENTATION OF EXECUTIVE ORDER 13798, PROMOTING FREE SPEECH AND RELIGIOUS LIBERTY (NOVEMBER 2020) States, local governments, or other public entities may not condition sub-awards in a manner that would discriminate, or disadvantage sub-recipients based on their religious character. CONTINUED USE OF REAL PROPERTY AND EQUIPMENT (OCTOBER 2022) Real property and equipment purchased with project funds (federal share and recipient cost share) under this Award are subject to the requirements at 2 CFR 200.311, 200.313, and 200.316 (non-Federal entities, except for-profit entities) and 2 CFR 910.360 (for-profit entities). The Recipient may continue to use the real property and equipment after the conclusion of the award period of performance so long as the Recipient: a. Continues to use the property for the authorized project purposes; b. Complies with the applicable reporting requirements and regulatory property standards; c. As applicable to for-profit entities, UCC filing statements are maintained; and d. Submits a written Request for Continued Use for DOE authorization, which is approved by the DOE Contracting Officer. The Recipient must request authorization from the Contracting Officer to continue to use the property for the authorized project purposes beyond the award period of performance (“Request for Continued Use”). The Recipient’s written Request for Continued Use must identify the property and include: a summary of how the property will be used (must align with the authorized project purposes); a proposed use period (e.g., perpetuity, until fully depreciated, or a calendar date where the Recipient expects to submit disposition instructions); acknowledgement that the recipient shall not sell or encumber the property or permit any encumbrance without prior written DOE approval; current fair market value of the property; and an Estimated Useful Life or depreciation schedule for equipment. When the property is no longer needed for authorized project purposes, the Recipient must request disposition instructions from DOE. For-profit entity disposition requirements are set forth at 2 CFR 910.360. Property disposition requirements for other non-federal entities are set forth in 2 CFR 200.310 through 200.316. FOREIGN NATIONAL PARTICIPATION – APPROVAL REQUIRED (MARCH 2023) If the Recipient (including any of its subrecipients and contractors) anticipates involving foreign nationals in the performance of this award, the Recipient must provide DOE with specific information about each foreign national to ensure compliance with the requirements for foreign national participation and access approvals. The volume and type of information required may depend on various factors associated with the award. 326 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 22 Approval for foreign nationals in Principal Investigator/Co-Principal Investigator roles, from countries of risk (i.e., China, Iran, North Korea, and Russia), and from countries identified on the U.S. Department of State’s list of State Sponsors of Terrorism (https://www.state.gov/state-sponsors-of-terrorism/) must be obtained from DOE before they can participate in the performance of any work under this award. A “foreign national” is defined as any person who is not a United States citizen by birth or naturalization. DOE may elect to deny a foreign national’s participation in the award. Likewise, DOE may elect to deny a foreign national’s access to a DOE sites, information, technologies, equipment, programs, or personnel. DOE’s determination to deny participation or access is not appealable. The Recipient must include this term in any subaward and in any applicable contractual agreement(s) associated with this award. POST AWARD DUE DILIGENCE REVIEWS (SEPTEMBER 2023) During the period of performance of the Award, DOE may conduct ongoing due diligence reviews, through Government resources, to identify potential risks of undue foreign influence. In the event a risk is identified, DOE may require risk mitigation measures, including but not limited to, requiring an individual or entity not participate in the Award. EXPORT CONTROL (MARCH 2023) The United States government regulates the transfer of information, commodities, technology, and software considered to be strategically important to the U.S. to protect national security, foreign policy, and economic interests without imposing undue regulatory burdens on legitimate international trade. There is a network of Federal agencies and regulations that govern exports that are collectively referred to as “Export Controls.” The Recipient is responsible for ensuring compliance with all applicable United States Export Control laws and regulations relating to any work performed under the award. The Recipient must immediately report to DOE any export control violations related to the project funded under this award, at the recipient or subrecipient level, and provide the corrective action(s) to prevent future violations. INTERIM CONFLICT OF INTEREST POLICY FOR FINANCIAL ASSISTANCE (MARCH 2023) The DOE interim Conflict of Interest Policy for Financial Assistance (COI Policy) can be found at https://www.energy.gov/management/department-energy-interim-conflict-interest-policy-requirements- financial-assistance. This policy is applicable to all non-Federal entities applying for, or that receive, DOE funding by means of a financial assistance award (e.g., a grant, cooperative agreement, or technology investment agreement) and, through the implementation of this policy by the entity, to each Investigator who is planning to participate in, or is participating in, the project funded wholly or in part under this Award. The term “Investigator” means the PI and any other person, regardless of title or position, who is responsible for the purpose, design, conduct, or reporting of a project funded by DOE or proposed for funding by DOE. The Recipient must flow down the requirements of the interim COI Policy to any subrecipient non-Federal entities, with the exception of DOE National Laboratories. Further, the Recipient must identify all financial conflicts of interests (FCOI), i.e., managed and unmanaged/ unmanageable, in its initial and ongoing FCOI reports. 327 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 23 Prior to award, the Recipient was required to: 1) ensure all Investigators on this Award completed their significant financial disclosures; 2) review the disclosures; 3) determine whether a FCOI exists; 4) develop and implement a management plan for FCOIs; and 5) provide DOE with an initial FCOI report that includes all FCOIs (i.e., managed and unmanaged/unmanageable). Within 180 days of the date of the Award, the Recipient must be in full compliance with the other requirements set forth in DOE’s interim COI Policy. ORGANIZATIONAL CONFLICT OF INTEREST (MARCH 2023) Organizational conflicts of interest are those where, because of relationships with a parent company, affiliate, or subsidiary organization, the Recipient is unable or appears to be unable to be impartial in conducting procurement action involving a related organization (2 CFR 200.318(c)(2)). The Recipient must disclose in writing any potential or actual organizational conflict of interest to the DOE Contracting Officer. The Recipient must provide the disclosure prior to engaging in a procurement or transaction using project funds with a parent, affiliate, or subsidiary organization that is not a state, local government, or Indian tribe. For a list of the information that must be included the disclosure, see Section VI. of the DOE interim Conflict of Interest Policy for Financial Assistance at https://www.energy.gov/management/department-energy-interim-conflict-interest-policy-requirements- financial-assistance. If the effects of the potential or actual organizational conflict of interest cannot be avoided, neutralized, or mitigated, the Recipient must procure goods and services from other sources when using project funds. Otherwise, DOE may terminate the Award in accordance with 2 CFR 200.340 unless continued performance is determined to be in the best interest of the Federal government. The Recipient must flow down the requirements of the interim COI Policy to any subrecipient non-Federal entities, with the exception of DOE National Laboratories. The Recipient is responsible for ensuring subrecipient compliance with this term. If the Recipient has a parent, affiliate, or subsidiary organization that is not a state, local government, or Indian tribe, the Recipient must maintain written standards of conduct covering organizational conflicts of interest. BUY AMERICAN REQUIREMENT FOR INFRASTRUCTURE PROJECTS (MARCH 2023) A. Definitions Components are defined as the articles, materials, or supplies incorporated directly into the end manufactured product(s). Construction Materials are an article, material, or supply—other than an item primarily of iron or steel; a manufactured product; cement and cementitious materials; aggregates such as stone, sand, or gravel; or aggregate binding agents or additives—that is used in an infrastructure project and is or consists primarily of non-ferrous metals, plastic and polymer-based products (including polyvinylchloride, composite building materials, and polymers used in fiber optic cables), glass (including optic glass), lumber, drywall, coatings (paints and stains), optical fiber, clay brick; composite building materials; or engineered wood products. 328 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 24 Domestic Content Procurement Preference Requirement- means a requirement that no amounts made available through a program for federal financial assistance may be obligated for an infrastructure project unless— (A) all iron and steel used in the project are produced in the United States; (B) the manufactured products used in the project are produced in the United States; or (C) the construction materials used in the project are produced in the United States. Also referred to as the Buy America Requirement. Infrastructure includes, at a minimum, the structures, facilities, and equipment located in the United States, for: roads, highways, and bridges; public transportation; dams, ports, harbors, and other maritime facilities; intercity passenger and freight railroads; freight and intermodal facilities; airports; water systems, including drinking water and wastewater systems; electrical transmission facilities and systems; utilities; broadband infrastructure; and buildings and real property; and generation, transportation, and distribution of energy -including electric vehicle (EV) charging. The term “infrastructure” should be interpreted broadly, and the definition provided above should be considered as illustrative and not exhaustive. Manufactured Products are items used for an infrastructure project made up of components that are not primarily of iron or steel; construction materials; cement and cementitious materials’ aggregates such as stone, sand, or gravel; or aggregate binding agents or additives. Primarily of iron or steel means greater than 50% iron or steel, measured by cost. Project- means the construction, alteration, maintenance, or repair of infrastructure in the United States. Public- The Buy America Requirement does not apply to non-public infrastructure. For purposes of this guidance, infrastructure should be considered “public” if it is: (1) publicly owned or (2) privately owned but utilized primarily for a public purpose. Infrastructure should be considered to be “utilized primarily for a public purpose” if it is privately operated on behalf of the public or is a place of public accommodation. B. Buy America Requirement None of the funds provided under this award (federal share or recipient cost-share) may be used for a project for infrastructure unless: 1. All iron and steel used in the project is produced in the United States—this means all manufacturing processes, from the initial melting stage through the application of coatings, occurred in the United States; 2. All manufactured products used in the project are produced in the United States—this means the manufactured product was manufactured in the United States; and the cost of the components of the manufactured product that are mined, produced, or manufactured in the United States is greater than 55 percent of the total cost of all components of the 329 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 25 manufactured product, unless another standard for determining the minimum amount of domestic content of the manufactured product has been established under applicable law or regulation; and 3. All construction materials are manufactured in the United States—this means that all manufacturing processes for the construction material occurred in the United States. The Buy America Requirement only applies to articles, materials, and supplies that are consumed in, incorporated into, or permanently affixed to an infrastructure project. As such, it does not apply to tools, equipment, and supplies, such as temporary scaffolding, brought into the construction site and removed at or before the completion of the infrastructure project. Nor does a Buy America Requirement apply to equipment and furnishings, such as movable chairs, desks, and portable computer equipment, that are used at or within the finished infrastructure project but are not an integral part of the structure or permanently affixed to the infrastructure project. Recipients are responsible for administering their award in accordance with the terms and conditions, including the Buy America Requirement. The recipient must ensure that the Buy America Requirement flows down to all subawards and that the subawardees and subrecipients comply with the Buy America Requirement. The Buy America Requirement term and condition must be included all sub-awards, contracts, subcontracts, and purchase orders for work performed under the infrastructure project. C. Certification of Compliance The Recipient must certify or provide equivalent documentation for proof of compliance that a good faith effort was made to solicit bids for domestic products used in the infrastructure project under this Award. The Recipient must also maintain certifications or equivalent documentation for proof of compliance that those articles, materials, and supplies that are consumed in, incorporated into, affixed to, or otherwise used in the infrastructure project, not covered by a waiver or exemption, are produced in the United States. The certification or proof of compliance must be provided by the suppliers or manufacturers of the iron, steel, manufactured products and construction materials and flow up from all subawardees, contractors and vendors to the Recipient. The Recipient must keep these certifications with the award/project files and be able to produce them upon request from DOE, auditors or Office of Inspector General. D. Waivers When necessary, the Recipient may apply for, and DOE may grant, a waiver from the Buy America Requirement. Requests to waive the application of the Buy America Requirement must be in writing to the Contracting Officer. Waiver requests are subject to review by DOE and the Office of Management and Budget, as well as a public comment period of no less than 15 calendar days. Waivers must be based on one of the following justifications: 330 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 26 1. Public Interest- Applying the Buy America Requirement would be inconsistent with the public interest; 2. Non-Availability- The types of iron, steel, manufactured products, or construction materials are not produced in the United States in sufficient and reasonably available quantities or of a satisfactory quality; or 3. Unreasonable Cost- The inclusion of iron, steel, manufactured products, or construction materials produced in the United States will increase the cost of the overall project by more than 25 percent. Requests to waive the Buy America Requirement must include the following: • Waiver type (Public Interest, Non-Availability, or Unreasonable Cost); • Recipient name and Unique Entity Identifier (UEI); • Award information (Federal Award Identification Number, Assistance Listing number); • A brief description of the project, its location, and the specific infrastructure involved; • Total estimated project cost, with estimated federal share and recipient cost share breakdowns; • Total estimated infrastructure costs, with estimated federal share and recipient cost share breakdowns; • List and description of iron or steel item(s), manufactured goods, and/or construction material(s) the recipient seeks to waive from the Buy America Preference, including name, cost, quantity(ies), country(ies) of origin, and relevant Product Service Codes (PSC) and North American Industry Classification System (NAICS) codes for each; • A detailed justification as to how the non-domestic item(s) is/are essential the project; • A certification that the recipient made a good faith effort to solicit bids for domestic products supported by terms included in requests for proposals, contracts, and non-proprietary communications with potential suppliers; • A justification statement—based on one of the applicable justifications outlined above—as to why the listed items cannot be procured domestically, including the due diligence performed (e.g., market research, industry outreach, cost analysis, cost-benefit analysis) by the recipient to attempt to avoid the need for a waiver. This justification may cite, if applicable, the absence of any Buy America-compliant bids received for domestic products in response to a solicitation; and • Anticipated impact to the project if no waiver is issued. The Recipient should consider using the following principles as minimum requirements contained in their waiver request: • Time-limited: Consider a waiver constrained principally by a length of time, rather than by the specific project/award to which it applies. Waivers of this type may be appropriate, for example, when an item that is “non-available” is widely used in the project. When requesting such a waiver, the Recipient should identify a reasonable, definite time frame (e.g., no more than one to two years) designed so that the waiver is reviewed to ensure the condition for the 331 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 27 waiver (“non-availability”) has not changed (e.g., domestic supplies have become more available). • Targeted: Waiver requests should apply only to the item(s), product(s), or material(s) or category(ies) of item(s), product(s), or material(s) as necessary and justified. Waivers should not be overly broad as this will undermine domestic preference policies. • Conditional: The Recipient may request a waiver with specific conditions that support the policies of IIJA/BABA and Executive Order 14017. DOE may request, and the Recipient must provide, additional information for consideration of this wavier. DOE may reject or grant waivers in whole or in part depending on its review, analysis, and/or feedback from OMB or the public. DOEs final determination regarding approval or rejection of the waiver request may not be appealed. Waiver requests may take up to 90 calendar days to process. PROHIBITION ON CERTAIN TELECOMMUNICATIONS AND VIDEO SURVEILLANCE SERVICES OR EQUIPMENT (MARCH 2023) As set forth in 2 CFR 200.216, recipients and subrecipients are prohibited from obligating or expending project funds (Federal and non-Federal funds) to: (1) Procure or obtain; (2) Extend or renew a contract to procure or obtain; or (3) Enter into a contract (or extend or renew a contract) to procure or obtain equipment, services, or systems that uses covered telecommunications equipment or services as a substantial or essential component of any system, or as critical technology as part of any system. As described in Public Law 115- 232, section 889, covered telecommunications equipment is telecommunications equipment produced by Huawei Technologies Company or ZTE Corporation (or any subsidiary or affiliate of such entities). (i) For the purpose of public safety, security of government facilities, physical security surveillance of critical infrastructure, and other national security purposes, video surveillance and telecommunications equipment produced by Hytera Communications Corporation, Hangzhou Hikvision Digital Technology Company, or Dahua Technology Company (or any subsidiary or affiliate of such entities). (ii) Telecommunications or video surveillance services provided by such entities or using such equipment. (iii) Telecommunications or video surveillance equipment or services produced or provided by an entity that the Secretary of Defense, in consultation with the Director of the National Intelligence or the Director of the Federal Bureau of Investigation, reasonably believes to be an entity owned or controlled by, or otherwise connected to, the government of a covered foreign country. See Public Law 115-232, section 889 for additional information. 332 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 28 PROHIBITION RELATED TO FOREIGN GOVERNMENT-SPONSORED TALENT RECRUITMENT PROGRAMS (MARCH 2023) A. Prohibition Persons participating in a Foreign Government-Sponsored Talent Recruitment Program of a Foreign Country of Risk are prohibited from participating in this Award. The Recipient must exercise ongoing due diligence to reasonably ensure that no individuals participating on the DOE-funded project are participating in a Foreign Government-Sponsored Talent Recruitment Program of a Foreign Country of Risk. Consequences for violations of this prohibition will be determined according to applicable law, regulations, and policy. Further, the Recipient must notify DOE within five (5) business days upon learning that an owner of the Recipient or subrecipient or individual on the project team is or is believed to be participating in a Foreign Government-Sponsored Talent Recruitment Program of a Foreign Country of Risk. DOE may modify and add requirements related to this prohibition to the extent required by law. B. Definitions 1. Foreign Government-Sponsored Talent Recruitment Program. An effort directly or indirectly organized, managed, or funded by a foreign government, or a foreign government instrumentality or entity, to recruit science and technology professionals or students (regardless of citizenship or national origin, or whether having a full-time or part-time position). Some foreign government-sponsored talent recruitment programs operate with the intent to import or otherwise acquire from abroad, sometimes through illicit means, proprietary technology or software, unpublished data and methods, and intellectual property to further the military modernization goals and/or economic goals of a foreign government. Many, but not all, programs aim to incentivize the targeted individual to relocate physically to the foreign state for the above purpose. Some programs allow for or encourage continued employment at United States research facilities or receipt of federal research funds while concurrently working at and/or receiving compensation from a foreign institution, and some direct participants not to disclose their participation to U.S. entities. Compensation could take many forms including cash, research funding, complimentary foreign travel, honorific titles, career advancement opportunities, promised future compensation, or other types of remuneration or consideration, including in-kind compensation. 2. Foreign Country of Risk. DOE has designated the following countries as foreign countries of risk: Iran, North Korea, Russia, and China. This list is subject to change. PARTICIPANTS AND OTHER COLLABORATING ORGANIZATIONS (SEPTEMBER 2023) Prior to award, the Recipient was required to provide the following information on participants and other collaborating organizations. If there are any changes to Participants and Collaborating Organizations information previously submitted to DOE, the Recipient must submit updated information within thirty (30) calendar days after the end of the quarterly reporting period in which the change occurred: A. What individuals have worked on the project Provide the following information for individuals at the prime recipient and subrecipient level: (1) all senior and key personnel; and (2) each person who has worked or is expected to work at least one 333 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 29 person month per year on the project regardless of the source of compensation (a person month equals approximately 160 hours of effort). i. Name ii. Organization iii. Job Title iv. Role in the project v. Start and end date (month and year) working on the project vi. State, U.S. territory, and/or country of residence vii. Whether this person collaborated with an individual or entity located in a foreign country in connection with the scope of this Award, and viii. If yes to vii, whether the person traveled to the foreign country as part of that collaboration, and, if so, where and what the duration of stay was. B. Organizations Identify all subrecipients, contractors, U.S. National Laboratories, partners, and collaborating organizations. Recipients must also include all foreign collaborators as outline din the Foreign Collaboration Considerations term of the award Terms and Conditions. For each, provide name, UEI, zip code or latitude/longitude, role in the project, contribution to the project and start and end date. HUMAN SUBJECTS RESEARCH (MARCH 2023) Research involving human subjects, biospecimens, or identifiable private information conducted with Department of Energy (DOE) funding is subject to the requirements of DOE Order 443.1C, Protection of Human Research Subjects, 45 CFR Part 46, Protection of Human Subjects (subpart A which is referred to as the “Common Rule”), and 10 CFR Part 745, Protection of Human Subjects. Federal regulation and the DOE Order require review by an Institutional Review Board (IRB) of all proposed human subjects research projects. The IRB is an interdisciplinary ethics board responsible for ensuring that the proposed research is sound and justifies the use of human subjects or their data; the potential risks to human subjects have been minimized; participation is voluntary; and clear and accurate information about the study, the benefits and risks of participating, and how individuals’ data/specimens will be protected/used, is provided to potential participants for their use in determining whether or not to participate. The Recipient shall provide the Federal Wide Assurance number identified in item 1 below and the certification identified in item 2 below to DOE prior to initiation of any project that will involve interactions with humans in some way (e.g., through surveys); analysis of their identifiable data (e.g., demographic data and energy use over time); asking individuals to test devices, products, or materials developed through research; and/or testing of commercially available devices in buildings/homes in which humans will be present. Note: This list of examples is illustrative and not all inclusive. No DOE funded research activity involving human subjects, biospecimens, or identifiable private information shall be conducted without: 334 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 30 1) A registration and a Federal Wide Assurance of compliance accepted by the Office of Human Research Protection (OHRP) in the Department of Health and Human Services; and 2) Certification that the research has been reviewed and approved by an Institutional Review Board (IRB) provided for in the assurance. IRB review may be accomplished by the awardee’s institutional IRB; by the Central DOE IRB; or if collaborating with one of the DOE national laboratories, by the DOE national laboratory IRB. The Recipient is responsible for ensuring all subrecipients comply and for reporting information on the project annually to the DOE Human Subjects Research Database (HSRD) at https://science.osti.gov/HumanSubjects/Human-Subjects-Database/home. Note: If a DOE IRB is used, no end of year reporting will be needed. Additional information on the DOE Human Subjects Research Program can be found at: https://science.osti.gov/ber/human-subjects. FRAUD, WASTE AND ABUSE (MARCH 2023) The mission of the DOE Office of Inspector General (OIG) is to strengthen the integrity, economy and efficiency of DOE’s programs and operations including deterring and detecting fraud, waste, abuse and mismanagement. The OIG accomplishes this mission primarily through investigations, audits, and inspections of Department of Energy activities to include grants, cooperative agreements, loans, and contracts. The OIG maintains a Hotline for reporting allegations of fraud, waste, abuse, or mismanagement. To report such allegations, please visit https://www.energy.gov/ig/ig‐hotline. Additionally, the Recipient must be cognizant of the requirements of 2 CFR 200.113 Mandatory disclosures, which states: The non‐Federal entity or applicant for a Federal award must disclose, in a timely manner, in writing to the Federal awarding agency or pass‐through entity all violations of Federal criminal law involving fraud, bribery, or gratuity violations potentially affecting the Federal award. Non‐Federal entities that have received a Federal award including the term and condition outlined in appendix XII of 2 CFR Part 200 are required to report certain civil, criminal, or administrative proceedings to SAM (currently FAPIIS). Failure to make required disclosures can result in any of the remedies described in § 200.339. (See also 2 CFR part 180, 31 U.S.C. 3321, and 41 U.S.C. 2313.) TRANSPARENCY OF FOREIGN CONNECTIONS (SEPTEMBER 2023) The Recipient must notify the DOE Contracting Officer within fifteen (15) business days of learning of the following circumstances in relation to the Recipient and subrecipients: 1. Any current or pending subsidiary, foreign business entity, or offshore entity that is based in or funded by any foreign country of risk or foreign entity based in a country of risk; 335 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 31 2. Any current or pending contractual or financial obligation or other agreement specific to a business arrangement, or joint venture-like arrangement with an entity owned by a country of risk or foreign entity based in a country of risk; 3. Any current or pending change in ownership structure of the Recipient or subrecipients that increases foreign ownership related to a country of risk. Each notification shall be accompanied by a complete and up-to-date capitalization table showing all equity interests held including limited liability company (LLC) and partnership interests, as well as derivative securities. Include both the number of shares issued to each equity holder, as well as the percentage of that series and of all equity on fully diluted basis. For each equity holder, provide the place of incorporation and the principal place of business, as applicable. If the equity holder is a natural person, identify the citizenship(s); 4. Any current or pending venture capital or institutional investment by an entity that has a general partner or individual holding a leadership role in such entity who has a foreign affiliation with any foreign country of risk; 5. Any current or pending technology licensing or intellectual property sales to a foreign country of risk; and 6. Any changes to the Recipient or the subrecipients’ board of directors, including additions to the number of directors, the identity of new directors, as well as each new director’s citizenship, shareholder affiliation (if applicable); each notification shall include a complete up-to-date list of all directors (and board observers), including their full name, citizenship and shareholder affiliation, date of appointment, duration of term, as well as a description of observer rights as applicable. Should DOE determine the connection poses a risk to economic or national security, DOE will require measures to mitigate or eliminate the risk. DOE has designated the following countries as foreign countries of risk: Iran, North Korea, Russia, and China. This list is subject to change. Recognizing the disclosures may contain business confidential information, subrecipients may submit their disclosures directly to DOE. FOREIGN COLLABORATION CONSIDERATIONS (MARCH 2023) A. Consideration of new collaborations with foreign entities, organizations, and governments. The Recipient must provide DOE with advanced written notification of any potential collaboration with foreign entities, organizations or governments in connection with its DOE-funded award scope. The Recipient must await further guidance from DOE prior to contacting the proposed foreign entity, organization or government regarding the potential collaboration or negotiating the terms of any potential agreement. B. Existing collaborations with foreign entities, organizations and governments. The Recipient must provide DOE with a written list of all existing foreign collaborations, organizations, and governments in which has entered in connection with its DOE-funded award scope. C. In general, a collaboration will involve some provision of a thing of value to, or from, the Recipient. A thing of value includes but may not be limited to all resources made available to, or from, the recipient 336 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 32 in support of and/or related to the Award, regardless of whether or not they have monetary value. Things of value also may include in-kind contributions (such as office/laboratory space, data, equipment, supplies, employees, students). In-kind contributions not intended for direct use on the Award but resulting in provision of a thing of value from or to the Award must also be reported. Collaborations do not include routine workshops, conferences, use of the Recipient’s services and facilities by foreign investigators resulting from its standard published process for evaluating requests for access, or the routine use of foreign facilities by awardee staff in accordance with the Recipient’s standard policies and procedures. REPORTING SUBAWARD AND EXECUTIVE COMPENSATION (SEPTEMBER 2023) a. Reporting of first-tier subawards. 1. Applicability. Unless the Recipient is exempt as provided in paragraph d. of this award term, the Recipient must report each action that equals or exceeds $30,000 in Federal funds for a subaward to a non-Federal entity or Federal agency (see definitions in paragraph e. of this award term). 2. Where and when to report. i. The non-Federal entity or Federal agency must report each obligating action described in paragraph a.1. of this award term to http://www.fsrs.gov. ii. For subaward information, report no later than the end of the month following the month in which the obligation was made. (For example, if the obligation was made on November 7, 2010, the obligation must be reported by no later than December 31, 2010.) 3. What to report. The Recipient must report the information about each obligating action that the submission instructions posted at http://www.fsrs.gov specify. b. Reporting total compensation of recipient executives for non-Federal entities. 1. Applicability and what to report. The Recipient must report total compensation for each of its five most highly compensated executives for the preceding completed fiscal year, if i. The total Federal funding authorized to date under this Federal award is $30,000 or more as defined in 2 CFR 170.320; ii. In the preceding fiscal year, the Recipient received: a) 80 percent or more of the Recipient’s annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and b) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and iii. The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 337 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 33 U.S.C. 78m(a), 78o(d)) or section 6104 of the Internal Revenue Code of 1986. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at https://www.sec.gov/answers/execomp.htm.) 2. Where and when to report. The Recipient must report executive total compensation described in paragraph b.1. of this award term: i. As part of the Recipients registration profile at https://www.sam.gov. ii. By the end of the month following the month in which this award is made, and annually thereafter. c. Reporting of total compensation of subrecipient executives. 1. Applicability and what to report. Unless the Recipient is exempt as provided in paragraph d. of this award term, for each first-tier non-Federal entity subrecipient under this award, the Recipient shall report the names and total compensation of each of the subrecipient's five most highly compensated executives for the subrecipient's preceding completed fiscal year, if: i. In the subrecipient’s preceding fiscal year, the subrecipient received; a) 80 percent or more of its annual gross revenues from Federal procurement contracts (and subcontracts) and Federal financial assistance subject to the Transparency Act, as defined at 2 CFR 170.320 (and subawards); and b) $25,000,000 or more in annual gross revenues from Federal procurement contracts (and subcontracts), and Federal financial assistance subject to the Transparency Act (and subawards); and ii. The public does not have access to information about the compensation of the executives through periodic reports filed under section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a), 78o(d)) or section 6104 of the Internal Revenue Code of 1986. (To determine if the public has access to the compensation information, see the U.S. Security and Exchange Commission total compensation filings at https://www.sec.gov/answers/execomp.htm.) 2. Where and when to report. The Recipient must report subrecipient executive total compensation described in paragraph c.1. of this award term: i. To the recipient ii. By the end of the month following the month during which the Recipient makes the subaward. For example, if a subaward is obligated on any date during the month of October of a given year ( i.e., between October 1 and 31), the Recipient must report any required compensation information of the subrecipient by November 30 of that year. d. Exemptions If, in the previous tax year, the Recipient had gross income, from all sources, under $300,000, it is exempt from the requirements to report: 338 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 34 i. Subawards, and ii. The total compensation of the five most highly compensated executives of any subrecipient. e. Definitions. For purposes of this award term: 1. Federal Agency means a Federal agency as defined at 5 U.S.C. 551(1) and further clarified by 5 U.S.C. 552(f). 2. Non-Federal entity means all of the following, as defined in 2 CFR part 25: i. A Governmental organization, which is a State, local government, or Indian tribe; ii. A foreign public entity; iii. A domestic or foreign nonprofit organization; and iv. A domestic or foreign for-profit organization. 3. Executive means officers, managing partners, or any other employees in management positions. 4. Subaward: i. This term means a legal instrument to provide support for the performance of any portion of the substantive project or program for which the Recipient received this award and that the recipient awards to an eligible subrecipient. ii. The term does not include the Recipient’s procurement of property and services needed to carry out the project or program (for further explanation, see 2 CFR 200.331). iii. A subaward may be provided through any legal agreement, including an agreement that the Recipient or a subrecipient considers a contract. 5. Subrecipient means a non-Federal entity or Federal agency that: i. Receives a subaward from the Recipient under this award; and ii. Is accountable to the Recipient for the use of the Federal funds provided by the subaward. 6. Total compensation means the cash and noncash dollar value earned by the executive during the recipient's or subrecipient's preceding fiscal year. For more information on disclosure and reporting requirements, see 17 CFR 229.402(c)(2). POTENTIALLY DUPLICATIVE FUNDING NOTICE (MARCH 2023) If the Recipient or subrecipients have or receive any other award of federal funds for activities that potentially overlap with the activities funded under this Award, the Recipient must promptly notify DOE in writing of the potential overlap and state whether project funds (i.e., recipient cost share and federal funds) from any of those other federal awards have been, are being, or are to be used (in whole or in part) for one or more of the identical cost items under this Award. If there are identical cost items, the Recipient must promptly notify the DOE Contracting Officer in writing of the potential duplication and eliminate any inappropriate duplication of funding. REQUIRED RISK MITIGATION (MARCH 2023) 339 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 35 [Placeholder – In the event DOE determines the award requires mitigation measures to address undue foreign influence risks, the mitigations measures would be captured in a T&C, depending on the nature of the required measure.] REPORTING, TRACKING AND SEGREGATION OF INCURRED COSTS (MARCH 2023) BIL funds can be used in conjunction with other funding, as necessary to complete projects, but tracking and reporting must be separate to meet the reporting requirements of the BIL and related Office of Management and Budget (OMB) Guidance. The Recipient must keep separate records for BIL funds and must ensure those records comply with the requirements of the BIL. COMMUNITY BENEFITS OUTCOMES AND OBJECTIVES – NETL The Recipient must meet the stated objectives and milestones set forth in its Community Benefits Outcomes and Objectives (CBOO) Plan, which is incorporated into the Award. A report on the Recipient’s progress towards meeting the objectives and milestones set forth in the CBOO must be provided on an annual basis. CYBERSECURITY PLAN (SEPTEMBER 2023) The Secretary of Energy, per BIL Section 40126, designated the DOE’s Office of Cybersecurity, Energy Security, and Emergency Response (CESER) as responsible for coordinating cybersecurity project plans for IIJA provisions the Secretary deemed to have a cyber risk. CESER coordinates with DOE National Laboratory Subject Matter Experts (SMEs) to provide project lifecycle support activities that maintain or improve the project cybersecurity over its lifecycle. The Recipient is responsible for maintaining and improving project cybersecurity throughout the period of performance, including responding to DOE feedback on the plans and the associated milestones, deliverables, including attending associated cybersecurity plan lifecycle support meeting dates with CESER and DOE SMEs. Any revisions to the cybersecurity plans and all related deliverables shall be emailed securely to CR-IIJACybersecurityplans@hq.doe.gov. Any DOE and/or National Laboratory review comments or feedback provided to Recipients does not constitute an endorsement or approval of any specific elements within the cybersecurity plan or the proposed security approach. Therefore, such feedback should not be referenced or used in marketing or promotional materials. All cybersecurity plans and deliverables are exempt from disclosure under the Freedom of Information Act (5 U.S.C. § 552) pursuant to Section 40126(e). This exemption is limited to information provided to or collected by the federal government described in Pub. L. 117-58 § 41026, 42 U.S.C. § 18725. DAVIS-BACON ACT REQUIREMENTS (MARCH 2023) This award is funded under Division D of the Bipartisan Infrastructure Law (BIL). All laborers and mechanics employed by the recipient, subrecipients, contractors or subcontractors in the performance of construction, alteration, or repair work in excess of $2,000 on an award funded directly by or assisted in whole or in part by funds made available under this award shall be paid wages at rates not less than those prevailing on similar projects in the locality, as determined by the Secretary of Labor in accordance with subchapter IV of chapter 31 of title 40, United States Code commonly referred to as the “Davis-Bacon Act” (DBA). 340 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 36 Recipients shall provide written assurance acknowledging the DBA requirements for the award or project and confirming that all of the laborers and mechanics performing construction, alteration, or repair work in excess of $2,000 on projects funded directly by or assisted in whole or in part by and through funding under the award are paid or will be paid wages at rates not less than those prevailing on projects of a character similar in the locality as determined by Subchapter IV of Chapter 31 of Title 40, United States Code (Davis-Bacon Act). The Recipient must comply with all Davis-Bacon Act requirements, including but not limited to: (1) ensuring that the wage determination(s) and appropriate Davis-Bacon clauses and requirements are flowed down to and incorporated into any applicable subcontracts or subrecipient awards. (2) being responsible for compliance by any subcontractor or subrecipient with the Davis-Bacon labor standards. (3) receiving and reviewing certified weekly payrolls submitted by all subcontractors and subrecipients for accuracy and to identify potential compliance issues. (4) maintaining original certified weekly payrolls for 3 years after the completion of the project and must make those payrolls available to the DOE or the Department of Labor upon request, as required by 29 CFR 5.6(a)(2). (5) conducting payroll and job-site reviews for construction work, including interviews with employees, with such frequency as may be necessary to assure compliance by its subcontractors and subrecipients and as requested or directed by the DOE. (6) cooperating with any authorized representative of the Department of Labor in their inspection of records, interviews with employees, and other actions undertaken as part of a Department of Labor investigation. (7) posting in a prominent and accessible place the wage determination(s) and Department of Labor Publication: WH-1321, Notice to Employees Working on Federal or Federally Assisted Construction Projects. (8) notifying the Contracting Officer of all labor standards issues, including all complaints regarding incorrect payment of prevailing wages and/or fringe benefits, received from the recipient, subrecipient, contractor, or subcontractor employees; significant labor standards violations, as defined in 29 CFR 5.7; disputes concerning labor standards pursuant to 29 CFR parts 4, 6, and 8 and as defined in FAR 52.222- 14; disputed labor standards determinations; Department of Labor investigations; or legal or judicial proceedings related to the labor standards under this Contract, a subcontract, or subrecipient award. (9) preparing and submitting to the Contracting Officer, the Office of Management and Budget Control Number 1910-5165, Davis Bacon Semi-Annual Labor Compliance Report, by April 21 and October 21 of each year. Form submittal will be administered through the iBenefits system (https://doeibenefits2.energy.gov) or its successor system. 341 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 37 The Recipient must undergo Davis-Bacon Act compliance training and must maintain competency in Davis- Bacon Act compliance. The Contracting Officer will notify the Recipient of any DOE sponsored Davis-Bacon Act compliance trainings. The Department of Labor offers free Prevailing Wage Seminars several times a year that meet this requirement, at https://www.dol.gov/agencies/whd/government- contracts/construction/seminars/events. The Department of Energy has contracted with, a third-party DBA electronic payroll compliance software application. The Recipient must ensure the timely electronic submission of weekly certified payrolls as part of its compliance with the Davis-Bacon Act unless a waiver is granted to a particular contractor or subcontractor because they are unable or limited in their ability to use or access the software. Davis Bacon Act Electronic Certified Payroll Submission Waiver A waiver must be granted before the award starts. The applicant does not have the right to appeal DOE’s decision concerning a waiver request. For additional guidance on how to comply with the Davis-Bacon provisions and clauses, see https://www.dol.gov/agencies/whd/government-contracts/construction and https://www.dol.gov/agencies/whd/government-contracts/protections-for-workers-in-construction. AFFIRMATIVE ACTION AND PAY TRANSPARENCY REQUIREMENTS (SEPTEMBER 2023) All federally assisted construction contracts exceeding $10,000 annually will be subject to the requirements of Executive Order 11246: (1) Recipients, subrecipients, and contractors are prohibited from discriminating in employment decisions on the basis of race, color, religion, sex, sexual orientation, gender identity or national origin. (2) Recipients and Contractors are required to take affirmative action to ensure that equal opportunity is provided in all aspects of their employment. This includes flowing down the appropriate language to all subrecipients, contractors and subcontractors. (3) Recipients, subrecipients, contractors and subcontractors are prohibited from taking adverse employment actions against applicants and employees for asking about, discussing, or sharing information about their pay or, under certain circumstances, the pay of their co‐workers. The Department of Labor’s (DOL) Office of Federal Contractor Compliance Programs (OFCCP) uses a neutral process to schedule contractors for compliance evaluations. OFCCP’s Technical Assistance Guide should be consulted to gain an understanding of the requirements and possible actions the recipients, subrecipients, contractors and subcontractors must take. See OFCCP’s Technical Assistance Guide at: https://www.dol.gov/sites/dolgov/files/ofccp/Construction/files/ConstructionTAG.pdf?msclkid=9e397d68c4b11 1ec9d8e6fecb6c710ec. Additionally, for construction projects valued at $35 million or more and lasting more than one year, Recipients, subrecipients, contractors, or subcontractors may be selected by OFCCP to participate in the Mega Construction Project Program. DOE, under relevant legal authorities including Sections 205 and 303(a) of Executive Order 11246, will require participation as a condition of the award. This program offers extensive 342 SAMPLE ONLY – SUBJECT TO CHANGE WITHOUT NOTICE DE-GD0000XXX Page 38 compliance assistance with EO 11246. For more information regarding this program, see https://www.dol.gov/agencies/ofccp/construction/mega-program. SIGNAGE (SEPTEMBER 2023) The Recipient is encouraged to display DOE standard infrastructure investment signage, available for download from DOE (https://www.energy.gov/branding), during construction of the project. Expenditures for such signage shall be a permitted eligible cost of the project. 343 344 Award Number: Award Recipient:Alaska Energy Authority (May be award recipient or sub-recipient) Section A - Budget Summary Federal Cost Share Total Costs Cost Share %Proposed Budget Period Dates Budget Period 1 $7,413,433 $7,413,433 $14,826,866 50.00%07/01/2023 - 06/30/2025 Budget Period 2 $0 $0 $0 0.00%07/01/2025 - 06/30/2031 Budget Period 3 $0 $0 $0 0.00% Budget Period 4 $0 $0 $0 0.00% Budget Period 5 $0 $0 $0 0.00% Total $7,413,433 $7,413,433 $14,826,866 50.00% Section B - Budget Categories CATEGORY Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Total Costs % of Project Comments (as needed) a. Personnel $2,618,317 $0 $0 $0 $0 $2,618,317 17.66% b. Fringe Benefits $0 $0 $0 $0 $0 $0 0.00% c. Travel $75,400 $0 $0 $0 $0 $75,400 0.51% d. Equipment $80,000 $0 $0 $0 $0 $80,000 0.54% e. Supplies $80,000 $0 $0 $0 $0 $80,000 0.54% f. Contractual Sub-recipient $0 $0 $0 $0 $0 $0 0.00% Contractor $2,798,000 $0 $0 $0 $0 $2,798,000 18.87% FFRDC $0 $0 $0 $0 $0 $0 0.00% Total Contractual $2,798,000 $0 $0 $0 $0 $2,798,000 18.87% g. Construction $7,400,000 $0 $0 $0 $0 $7,400,000 49.91% h. Other Direct Costs $0 $0 $0 $0 $0 $0 0.00% Total Direct Costs $13,051,717 $0 $0 $0 $0 $13,051,717 88.03% i. Indirect Charges $1,775,149 $0 $0 $0 $0 $1,775,149 11.97% Total Costs $14,826,866 $0 $0 $0 $0 $14,826,866 100.00% Instructions and Summary Date of Submission: SUMMARY OF BUDGET CATEGORY COSTS PROPOSED The values in this summary table are from entries made in subsequent tabs, only blank white cells require data entry Additional Explanation (as needed): Alaska Energy Authority Form submitted by: Please read the instructions on each worksheet tab before starting. If you have any questions, please ask your DOE contact! Do not modify this template or any cells for formulas! 1. If using this form for award application, negotiation, or budget revision, fill out the blank white cells in workbook tabs a. through j. with total project costs. 2. Blue colored cells contain instructions, headers, or summary calculations and should not be modified. Only blank white cells should be populated. 3. Enter detailed support for the project costs identified for each Category line item within each worksheet tab to autopopulate the summary tab. 4. The total budget presented on tabs a. through i. must include both Federal (DOE) and Non-Federal (cost share) portions. 5. All costs incurred by the preparer's sub-recipients, contractors, and Federal Research and Development Centers (FFRDCs), should be entered only in section f. Contractual. All other sections are for the costs of the preparer only. 6. Ensure all entered costs are allowable, allocable, and reasonable in accordance with the administrative requirements prescribed in 2 CFR 200, and the applicable cost principles for each entity type: FAR Part 31 for For- Profit entities; and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities. 7. Add rows as needed throughout tabs a. through j. If rows are added, formulas/calculations may need to be adjusted by the preparer. Do not add rows to the Instructions and Summary tab. If your project contains more than five budget periods, consult your DOE contact before adding additional budget period rows and columns. 8. ALL budget period cost categories are rounded to the nearest dollar. BURDEN DISCLOSURE STATEMENT Public reporting burden for this collection of information is estimated to average 24 hours per response, including the time for reviewing instructions, searching existing data sources, gathering and maintaining the data needed, and completing and reviewing the collection of information. Send comments regarding this burden estimate or any other aspect of this collection of information, including suggestions for reducing this burden, to Office of Information Resources Management Policy, Plans, and Oversight, AD-241-2 - GTN, Paperwork Reduction Project (1910-5162), U.S. Department of Energy 1000 Independence Avenue, S.W., Washington, DC 20585; and to the Office of Management and Budget, Paperwork Reduction Project (1910-5162), Washington, DC 20503.345 Time (Hrs) Hourly Rate ($/Hr) Total Budget Period 1 Time (Hrs) Hourly Rate ($/Hr) Total Budget Period 2 Time (Hrs) Hourly Rate ($/Hr) Total Budget Period 3 Time (Hrs) Hourly Rate ($/Hr) Total Budget Period 4 Time (Hrs) Hourly Rate ($/Hr) Total Budget Period 5 1 Sr. Engineer (EXAMPLE!!!)2000 $85.00 $170,000 200 $50.00 $10,000 200 $50.00 $10,000 200 $50.00 $10,000 200 $50.00 $10,000 2400 $190,000 2 Technicians (2)4000 $20.00 $80,000 0 $0.00 $0 0 $0.00 $0 0 $0.00 $0 0 $0.00 $0 4000 $80,000 1 thru 8 Contracting Officer 780 89.88 $70,103 $70,103 1 thru 8 Executive Director 390 183.59 $71,601 $71,601 1 thru 8 Communicaitons Director 780 112.94 $88,096 $88,096 1 thru 8 GIS 585 83.79 $49,014 $49,014 1 thru 8 Owned Assets Director 780 165.94 $129,432 $129,432 1 thru 8 Senior Infrastructure Engineer 3,900 111.09 $433,269 $433,269 1 thru 8 Infrastructure Engineer 780 104.63 $81,610 $81,610 1 thru 8 Federal Project Manager 3,900 152.99 $596,661 $596,661 1 thru 8 Environmental Engineer 3,120 152.99 $477,329 $477,329 1 thru 8 Program Controls 3,900 106.19 $414,134 $414,134 1 thru 8 Program Project Manager 1,950 106.19 $207,067 $207,067 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 $0 $0 $0 $0 $0 0 $0 Total Personnel Costs 20865 $2,618,317 0 $0 0 $0 0 $0 0 $0 20865 $2,618,317 Additional Explanation (as needed): A loaded labor rate is utilized for billing purposes. This is comprised of base salary, leave/holiday, and employer paid health, retirement, and taxes. Position Title INSTRUCTIONS - PLEASE READ!!! 1. List project costs solely for employees of the entity completing this form. All personnel costs for subrecipients and contractors must be included under f. Contractual. 2. All personnel should be identified by position title and not employee name. Enter the amount of time (e.g., hours or % of time) and the base hourly rate and the total direct personnel compensation will automatically calculate. Rate basis (e.g., rate negotiated for each hour worked on the project, labor distribution report, state civil service rates, etc.) must also be identified. 3. If loaded labor rates are utilized, a description of the costs the loaded rate is comprised of must be included in the Additional Explanation section below. DOE must review all components of the loaded labor rate for reasonableness and unallowable costs (e.g. fee or profit). 4. If a position and hours are attributed to multiple employees (e.g. Technician working 4000 hours) the number of employees for that position title must be identified. 5. Each budget period is rounded to the nearest dollar. SOPO Task #Rate BasisProject Total Dollars Budget Period 4 Budget Period 5 a. Personnel Project Total Hours Budget Period 1 Budget Period 2 Budget Period 3 Detailed Budget Justification 346 Labor Type Total Project Personnel Costs Rate Total Personnel Costs Rate Total Personnel Costs Rate Total Personnel Costs Rate Total Personnel Costs Rate Total EXAMPLE!!! Sr. Engineer $170,000 20%$34,000 $10,000 20%$2,000 $10,000 20%$2,000 $10,000 20%$2,000 $10,000 20%$2,000 $38,000 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Total:$0 $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Detailed Budget Justification b. Fringe Benefits Additional Explanation (as necessary): Please use this box (or an attachment) to list the elements that comprise your fringe benefits and how they are applied to your base (e.g. Personnel) to arrive at your fringe benefit rate. The Alaska Energy Authority is billed a loaded payroll rate. See detail in Personnel tab for detail components of the loaded rate. INSTRUCTIONS - PLEASE READ!!! 1. Fill out the table below by position title. If all employees receive the same fringe benefits, you can show "Total Personnel" in the Labor Type column instead of listing out all position titles. 2. The rates and how they are applied should not be averaged to get one fringe cost percentage. Complex calculations should be described/provided in the Additional Explanation section below. 3. The fringe benefit rates should be applied to all positions, regardless of whether those funds will be supported by Federal Share or Recipient Cost Share. 4. Each budget period is rounded to the nearest dollar. ______ A fringe benefit rate has been negotiated with, or approved by, a federal government agency. A copy of the latest rate agreement is/was included with the project application.* __X____ There is not a current federally approved rate agreement negotiated and available.** *Unless the organization has submitted an indirect rate proposal which encompasses the fringe pool of costs, please provide the organization’s benefit package and/or a list of the components/elements that comprise the fringe pool and the cost or percentage of each component/element allocated to the labor costs identified in the Budget Justification (Form EERE 335.1). **When this option is checked, the entity preparing this form shall submit an indirect rate proposal in the format provided in the Sample Rate Proposal at https://www.energy.gov/eere/funding/downloads/sample-indirect-rate-proposal-and-profit-compliance-audit, or a format that provides the same level of information and which will support the rates being proposed for use in the performance of the proposed project. A federally approved fringe benefit rate agreement, or a proposed rate supported and agreed upon by DOE for estimating purposes is required at the time of award negotiation if reimbursement for fringe benefits is requested. Please check (X) one of the options below and provide the requested information if not previously submitted. Budget Period 2 Budget Period 3Budget Period 1 Budget Period 4 Budget Period 5 347 SOPO Task #Purpose of Travel Depart From Destination No. of Days No. of Travelers Lodging per Traveler Flight per Traveler Vehicle per Traveler Per Diem Per Traveler Cost per Trip Total Cost (per trip x # trips) Basis for Estimating Costs Domestic Travel 1 EXAMPLE!!! Visit to PV manufacturer 2 2 $250 $500 $100 $160 $2,020 Current GSA rates 1 and 2 In-State Trips - Northern Sites 10 trips per year; 2 people per trip. Assumes 2 day trip. Anchorage Northern Alaska 2 2 $200 $800 $60 $2,640 $26,400 Previous experience 1 and 2 In-State Trips - Southern Sites 10 trips per year; 2 people per trip. Assumes 2 day trip. Anchorage Southern Alaska 2 2 $200 $800 $60 $2,640 $26,400 Previous experience 1 and 2 Out of State Trips - 2 per year WA - DC; 2 people per trip. Assume Anchorage Out of State 5 2 $245 $1,200 $60 $5,450 $10,900 Previous experience 1 and 2 Out of State Conference / Transmission Training; two trips per year; 2 people per trip. Assumes 5 day trip. Anchorage Out of State 5 2 $245 $1,200 $200 $60 $5,850 $11,700 Previous experience International Travel Budget Period 1 Total $75,400 $75,400 Domestic Travel International Travel Budget Period 4 Total $0 $0 Domestic Travel International Travel Budget Period 5 Total $0 PROJECT TOTAL $75,400 $75,400 INSTRUCTIONS - PLEASE READ!!! 1. Identify Foreign and Domestic Travel as separate items. Examples of Purpose of Travel are subrecipient site visits, DOE meetings, project mgmt. meetings, etc. Examples of Basis for Estimating Costs are past trips, travel quotes, GSA rates, etc. 2. All listed travel must be necessary for performance of the Statement of Project Objectives. 3. Only travel that is directly associated with this award should be included as a direct travel cost to the award. 4. Federal travel regulations are contained within the applicable cost principles for all entity types. 5. Travel costs should remain consistent with travel costs incurred by an organization during normal business operations as a result of the organizations written travel policy. In absence of a written travel policy, organizations must follow the regulations prescribed by the General Services Administration. 6. Columns E, F, G, H, I, J, and K are per trip. 7. The number of days is inclusive of the day of departure and the day of return. 8. Recipients should enter City and State (or City and Country for International travel) in the Depart from and Destination fields. 9. Each budget period is rounded to the nearest dollar. Additional Explanation (as needed): c. Travel Detailed Budget Justification Budget Period 1 Budget Period 2 Budget Period 5 348 SOPO Task #Equipment Item Qty Unit Cost Total Cost Basis of Cost Justification of need 3,4,5 EXAMPLE!!! Thermal shock chamber 2 $70,000 $140,000 Vendor Quote - Attached Reliability testing of PV modules- Task 4.3 1,2 Office set-up 8 $10,000 $80,000 Previous experience 10 new staff office set-up $0 $0 $0 $0 $0 Budget Period 1 Total $80,000 $0 $0 $0 $0 $0 $0 Budget Period 2 Total $0 $0 $0 $0 $0 $0 $0 Budget Period 3 Total $0 $0 $0 $0 $0 $0 $0 Budget Period 4 Total $0 $0 $0 $0 $0 $0 $0 Budget Period 5 Total $0 TOTAL EQUIPMENT $80,000 d. Equipment Detailed Budget Justification INSTRUCTIONS - PLEASE READ!!! 1. Equipment is generally defined as an item with an acquisition cost greater than $5,000 and a useful life expectancy of more than one year. Please refer to the applicable Federal regulations in 2 CFR 200 for specific equipment definitions and treatment. 2. List all equipment below, providing a basis of cost (e.g. contractor quotes, catalog prices, prior invoices, etc.). Briefly justify items as they apply to the Statement of Project Objectives. If it is existing equipment, provide logical support for the estimated value shown. 3. During award negotiations, provide a contractor quote for all equipment items over $50,000 in price. If the contractor quote is not an exact price match, provide an explanation in the additional explanation section below. If a contractor quote is not practical, such as for a piece of equipment that is purpose-built, first of its kind, or otherwise not available off the shelf, provide a detailed engineering estimate for how the cost estimate was derived. 4. Each budget period is rounded to the nearest dollar. Additional Explanation (as needed): Budget Period 3 Budget Period 2 Budget Period 1 Budget Period 4 Budget Period 5 349 SOPO Task #General Category of Supplies Qty Unit Cost Total Cost Basis of Cost Justification of need 4,6 EXAMPLE!!! Wireless DAS components 10 $360.00 $3,600 Catalog price For Alpha prototype - Task 2.4 1,2 Misc. Supplies 40 $2,000.00 $80,000 Previous experience 20 staff members - $2,000/pp per year $0 $0 $0 $0 $0 $0 Budget Period 1 Total $80,000 Budget Period 2 Total $0 Budget Period 3 Total $0 Budget Period 4 Total $0 Budget Period 5 Total $0 TOTAL SUPPLIES $80,000 Detailed Budget Justification INSTRUCTIONS - PLEASE READ!!! 1. Supplies are generally defined as an item with an acquisition cost of $5,000 or less and a useful life expectancy of less than one year. Supplies are generally consumed during the project performance. Please refer to the applicable Federal regulations in 2 CFR 200 for specific supplies definitions and treatment. 2. List all proposed supplies below, providing a basis of costs (e.g. contractor quotes, catalog prices, prior invoices, etc.). Briefly justify the need for the Supplies as they apply to the Statement of Project Objectives. Note that Supply items must be direct costs to the project at this budget category, and not duplicative of supply costs included in the indirect pool that is the basis of the indirect rate applied for this project. 3. Multiple supply items valued at $5,000 or less used to assemble an equipment item with a value greater than $5,000 with a useful life of more than one year should be included on the equipment tab. If supply items and costs are ambiguous in nature, contact your DOE representative for proper categorization. 4. Add rows as needed. If rows are added, formulas/calculations may need to be adjusted by the preparer. 5. Each budget period is rounded to the nearest dollar. Additional Explanation (as needed): Budget Period 1 e. Supplies Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 350 SOPO Task # Sub-Recipient Name/Organization Sub-Recipient Unique Entity Identifier (UEI) Purpose and Basis of Cost Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Project Total 2,4 EXAMPLE!!! XYZ Corp.Partner to develop optimal lens for Gen 2 product. Cost estimate based on personnel hours. $48,000 $32,000 $16,000 $96,000 $0 $0 $0 $0 $0 $0 Sub-total $0 $0 $0 $0 $0 $0 SOPO Task #Purpose and Basis of Cost Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Project Total 6 Contractor for developing robotics to perform lens inspection. Estimate provided by contractor. $32,900 $86,500 $119,400 1 thru 8 State of Alaska or competitive bid $425,000 $425,000 1 thru 8 Competitive bid $48,000 $48,000 2,3,4 Competitive bid $100,000 $100,000 2 thru 8 Competitive bid $400,000 $400,000 2,3,4 Lands Consultant Competitive bid $400,000 $400,000 2 thru 7 Labor/Governmental Consulting Competitive bid $225,000 $225,000 1 thru 8 Project Coordination Committee Competitive bid $600,000 $600,000 1 thru 8 Contractor Federal Project Reporting Competitive bid $150,000 $150,000 2 thru 7 Contractor Projects (see construction tab)Competitive bid $0 $0 2 thru 8 Accounting & Auditing Services Competitive bid $150,000 $150,000 4,5 Insurance Consultant Competitive bid $100,000 $100,000 4,5 Competitive bid $200,000 $200,000 Sub-total $2,798,000 $0 $0 $0 $0 $2,798,000 SOPO Task #Purpose and Basis of Cost Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Project Total $0 $0 Sub-total $0 $0 $0 $0 $0 $0 $2,798,000 $0 $0 $0 $0 $2,798,000 Detailed Budget Justification f. Contractual INSTRUCTIONS - PLEASE READ!!! 1. The entity completing this form must provide all costs related to sub-recipients, contractors, and FFRDC partners in the applicable boxes below. 2. Sub-recipients (partners, sub-awardees): Subrecipients shall submit a Budget Justification describing all project costs and calculations when their total proposed budget exceeds either (1) $100,000 or (2) 25% of total award costs. These sub-recipient forms may be completed by either the sub-recipients themselves or by the preparer of this form. The budget totals on the sub-recipient's forms must match the sub-recipient entries below. A subrecipient is a legal entity to which a subaward is made, who has performance measured against whether the objectives of the Federal program are met, is responsible for programmatic decision making, must adhere to applicable Federal program compliance requirements, and uses the Federal funds to carry out a program of the organization. All characteristics may not be present and judgment must be used to determine subrecipient vs. contractor status. 3. Contractors: List all contractors supplying commercial supplies or services used to support the project. For each Contractor cost with total project costs of $100,000 or more, a Contractor quote must be provided. A contractor is a legal entity contracted to provide goods and services within normal business operations, provides similar goods or services to many different purchasers, operates in a competitive environment, provides goods or services that are ancillary to the operation of the Federal program, and is not subject to compliance requirements of the Federal program. All characteristics may not be present and judgment must be used to determine subrecipient vs.contractor status. 4. Federal Funded Research and Development Centers (FFRDCs): FFRDCs must submit a signed Field Work Proposal during award application. The award recipient may allow the FFRDC to provide this information directly to DOE, however project costs must also be provided below. 5. Each budget period is rounded to the nearest dollar. Additional Explanation (as needed): Contractor Name/Organization EXAMPLE!!! ABC Corp. Legal Services Public Relations Firm Cultural Consultation Design & Engineering Consultant NEPA Consultant FFRDC Name/Organization Total Contractual 351 SOPO Task #General Description Cost Basis of Cost Justification of need 3 EXAMPLE ONLY!!! Three days of excavation for platform site $28,000 Engineering estimate Site must be prepared for construction of platform. HVDC Transmission tie between the Kenai Peninsula and Beluga - Phase 1 Design, Permitting, and Siting Kenai HVDC Terminal/Switchyard $1,550,000 Engineering estimate Beluga HVDC Terminal/Switchyard $1,550,000 Engineering estimate HVDC Submarine Cable $2,800,000 Engineering estimate Central BESS - Design & Engineering $750,000 Cost Estimate Northern BESS - Design & Engineering $750,000 Cost Estimate Budget Period 1 Total $7,400,000 Budget Period 2 Total $0 Budget Period 3 Total $0 Budget Period 4 Total $0 Budget Period 5 Total $0 TOTAL CONSTRUCTION $7,400,000 Detailed Budget Justification g. Construction PLEASE READ!!! 1. Construction, for the purpose of budgeting, is defined as all types of work done on a particular building, including erecting, altering, or remodeling. Construction conducted by the award recipient is entered on this page. Any construction work that is performed by a contractor or subrecipient should be entered under f. Contractual. 2. List all proposed construction below, providing a basis of cost such as engineering estimates, prior construction, etc., and briefly justify its need as it applies to the Statement of Project Objectives. 3. Each budget period is rounded to the nearest dollar. Overall description of construction activities: Example Only!!! - Build wind turbine platform Additional Explanation (as needed): Budget Period 1 Budget Period 2 Budget Period 5 Budget Period 3 Budget Period 4 352 SOPO Task #General Description and SOPO Task # Cost Basis of Cost Justification of need 5 EXAMPLE!!! Grad student tuition - tasks 1-3 $16,000 Established UCD costs Support of graduate students working on project Budget Period 1 Total $0 Budget Period 2 Total $0 Budget Period 3 Total $0 Budget Period 4 Total $0 Budget Period 5 Total $0 TOTAL OTHER DIRECT COSTS $0 Detailed Budget Justification h. Other Direct Costs Additional Explanation (as needed): INSTRUCTIONS - PLEASE READ!!! 1. Other direct costs are direct cost items required for the project which do not fit clearly into other categories. These direct costs must not be included in the indirect costs (for which the indirect rate is being applied for this project). Examples are: tuition, printing costs, etc. which can be directly charged to the project and are not duplicated in indirect costs (overhead costs). 2. Basis of cost are items such as vendor quotes, prior purchases of similar or like items, published price list, etc. 3. Each budget period is rounded to the nearest dollar. Budget Period 1 Budget Period 3 Budget Period 2 Budget Period 4 Budget Period 5 353 Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Total Provide ONLY Applicable Rates: Overhead Rate 0.00%0.00%0.00%0.00%0.00% General & Administrative (G&A)0.00%0.00%0.00%0.00%0.00% FCCM Rate, if applicable 0.00%0.00%0.00%0.00%0.00% OTHER Indirect Rate 31.86%0.00%0.00%0.00%0.00% Indirect Costs (As Applicable): Overhead Costs $0 $0 G&A Costs $0 FCCM Costs, if applicable $0 OTHER Indirect Costs $1,775,149 $1,775,149 Total indirect costs requested:$1,775,149 $0 $0 $0 $0 $1,775,149 INSTRUCTIONS - PLEASE READ!!! 1. Fill out the table below to indicate how your indirect costs are calculated. Use the box below to provide additional explanation regarding your indirect rate calculation. 2. The rates and how they are applied should not be averaged to get one indirect cost percentage. Complex calculations or rates that do not do not correspond to the below categories should be described/provided in the Additional Explanation section below. If questions exist, consult with your DOE contact before filling out this section. 3. The indirect rate should be applied to both the Federal Share and Recipient Cost Share. 4. NOTE: A Recipient who elects to employ the 10% de minimis Indirect Cost rate cannot claim resulting cost as a Cost Share contribution, nor can the Recipient claim "unrecovered indirect costs" as a Cost Share contribution. Neither of these costs can be reflected as actual indirect cost rates realized by the orgnaization, and therefore are not verifiable in the Recipient records as required by Federal Regulation (200.306(b)(1)) 5.. Each budget period is rounded to the nearest dollar. Explanation of BASE AEA has submitted a NICRA to the cognizant agency for review and approval for a provisional FY2024 indirect cost rate . AEA fully expects to have an approved NICRA and indirect cost rate effective for its fiscal year FY24. For estimating purposes, AEA computed the indirect rate based on the 31.86% provisional rate submitted for review. Detailed Budget Justification You must provide an explanation (below or in a separate attachment) and show how your indirect cost rate was applied to this budget in order to come up with the indirect costs shown. A federally approved indirect rate agreement, or rate proposed (supported and agreed upon by DOE for estimating purposes) is required if reimbursement of indirect costs is requested. Please check (X) one of the options below and provide the requested information if it has not already been provided as requested, or has changed. Example: Labor + Fringe ______ An indirect rate has been approved or negotiated with a federal government agency. A copy of the latest rate agreement is included with this application and will be provided electronically to the Contracting Officer for this project. _____ The organization does not have a current, federally approved indirect cost rate agreement and has provided an indirect rate proposal in support of the proposed costs. __X___ This organization has elected to apply a 10% de minimis rate in accordance with 2 CFR 200.414(f). i. Indirect Costs 354 Organization/Source Type (Cash or In Kind) Cost Share Item Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 Total Project Cost Share ABC Company EXAMPLE!!! Cash Project partner ABC Company will provide 20 PV modules for product development at the price of $680 per module $13,600 $13,600 State of Alaska 206,500,000 Subject to legislative approval, the state of Alaska will invest in this project a 100% match. $7,413,433 $0 $0 $0 $7,413,433 $0 $0 $0 $0 $0 $0 $0 $0 $0 TOTAL COST SHARE $7,413,433 $0 $0 $0 $0 $7,413,433 $14,826,866 50.0% Additional Explanation (as needed): Cost Share Detailed Budget Justification PLEASE READ!!! 1. A detailed presentation of the cash or cash value of all cost share proposed must be provided in the table below. All items in the chart below must be identified within the applicable cost category tabs a. through i. in addition to the detailed presentation of the cash or cash value of all cost share proposed provided in the table below. Identify the source organization & amount of each cost share item proposed in the award. 2. Cash Cost Share - encompasses all contributions to the project made by the recipient, subrecipient, or third party (an entity that does not have a role in performing the scope of work) for costs incurred and paid for during the project. This includes when an organization pays for personnel, supplies, equipment, etc. for their own company with organizational resources. If the item or service is reimbursed for, it is cash cost share. All cost share items must be necessary to the performance of the project. Contractors may not provide cost share. Any partial donation of goods or services is considered a discount and is not allowable. 3. In Kind Cost Share - encompasses all contributions to the project made by the recipient, subrecipient, or third party (an entity that does not have a role in performing the scope of work) where a value of the contribution can be readily determined, verified and justified but where no actual cash is transacted in securing the good or service comprising the contribution. In Kind cost share items include volunteer personnel hours, the donation of space or use of equipment, etc. The cash value and calculations thereof for all In Kind cost share items must be justified and explained in the Cost Share Item section below. All cost share items must be necessary to the performance of the project. If questions exist, consult your DOE contact before filling out In Kind cost share in this section. Contractors may not provide cost share. Any partial donation of goods or services is considered a discount and is not allowable. 4. Funds from other Federal sources MAY NOT be counted as cost share. This prohibition includes FFRDC sub-recipients. Non-Federal sources include any source not originally derived from Federal funds. Cost sharing commitment letters from subrecipients and third parties must be provided with the original application. 5. Fee or profit, including foregone fee or profit, are not allowable as project costs (including cost share) under any resulting award. The project may only incur those costs that are allowable and allocable to the project (including cost share) as determined in accordance with the applicable cost principles prescribed in FAR Part 31 for For-Profit entities and 2 CFR Part 200 Subpart E - Cost Principles for all other non-federal entities. 6. NOTE: A Recipient who elects to employ the 10% de minimis Indirect Cost rate cannot claim the resulting indirect costs as a Cost Share contribution. 7. NOTE: A Recipient cannot claim "unrecovered indirect costs" as a Cost Share contribution, without prior approval. 8. Each budget period is rounded to the nearest dollar. Cost Share Percent of Award:Total Project Cost: 355 Award Number: Federal Non-Federal Federal Non-Federal Total (a)(b)(c)(d)(e)(f)(g) 1.Budget Period 1 $7,413,433 $7,413,433 $14,826,866 2.Budget Period 2 $0 $0 $0 3.Budget Period 3 $0 $0 $0 4.Budget Period 4 $0 $0 $0 5.Budget Period 5 $0 $0 $0 6.Totals $7,413,433 $7,413,433 $14,826,866 Budget Period 1 Budget Period 2 Budget Period 3 Budget Period 4 Budget Period 5 $2,618,317 $0 $0 $0 $0 $2,618,317 $0 $0 $0 $0 $0 $0 $75,400 $0 $0 $0 $0 $75,400 $80,000 $0 $0 $0 $0 $80,000 $80,000 $0 $0 $0 $0 $80,000 $2,798,000 $0 $0 $0 $0 $2,798,000 $7,400,000 $0 $0 $0 $0 $7,400,000 $0 $0 $0 $0 $0 $0 $13,051,717 $0 $0 $0 $0 $13,051,717 $1,775,149 $0 $0 $0 $0 $1,775,149 $14,826,866 $0 $0 $0 $0 $14,826,866 7.$0 SF-424A (Rev. 4-92) Section B - Budget Categories Applicant Name:Alaska Energy Authority 0 Budget Information - Non Construction Programs OMB Approval No. 0348-0044 Section A - Budget Summary Grant Program Function or Activity Catalog of Federal Domestic Assistance Number Estimated Unobligated Funds New or Revised Budget h. Other 6.Object Class Categories Grant Program, Function or Activity Total (5) a. Personnel b. Fringe Benefits c. Travel d. Equipment e. Supplies f. Contractual g. Construction Authorized for Local Reproduction i. Total Direct Charges (sum of 6a-6h) j. Indirect Charges k. Totals (sum of 6i-6j) Program Income Previous Edition Usable Prescribed by OMB Circular A-102 356 GRIP Preliminary Budget BreakdownDRAFT4/4/2024TaskBudget Period 1FY 2024 FY 2025 Budget Period 2FY 2026 FY 2027 Budget Period 3FY 2028 FY 2029 Budget Period 4FY 2030 FY 2031Total FY2026‐FY2031Budget Period 1 + FY2006‐FY2031- 0.00%78.16%0.00%30.88%0.00%66.27%1.0000    Project Management and Planning1.1000    Project Management Plan (PMP): 1.2000    Community Benefits Plan 1.3000    National Environmental Policy Act (NEPA) Compliance 1.4000    Cybersecurity Plan (CSP)2.0000    HVDC Transmission tie between the Kenai Peninsula and BelugaPhase 1 ‐ Design Permitting and Siting     2.1110 Preliminary Design - Kenai HVDC Terminal/Switchyard400,000$ 75,000$ 325,000$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 400,000$ ‐$                     400,000$                           2.1130 Preliminary Design - Beluga HVDC Terminal/Switchyard400,000$ 75,000$ 325,000$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 400,000$ ‐$                     400,000$                           2.1150 Preliminary Design - HVDC Submarine Cable750,000$ 100,000$ 650,000$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 750,000$ ‐$                     750,000$                      -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   2.1210 Permitting - Kenai HVDC Terminal/Switchyard250,000$ 25,000$ 225,000$ 250,000$ 195,409$ 54,591$ 150,000$ 46,313$ 103,687$ 150,000$ 99,411$ 50,589$ 800,000$ 550,000$             800,000$                           2.1230 Permitting - Beluga HVDC Terminal/Switchyard250,000$ 25,000$ 225,000$ 250,000$ 195,409$ 54,591$ 150,000$ 46,313$ 103,687$ 150,000$ 99,411$ 50,589$ 800,000$ 550,000$             800,000$                           2.1250 Permitting - HVDC Submarine Cable650,000$ 25,000$ 625,000$ 1,000,000$ 781,638$ 218,362$ 500,000$ 154,378$ 345,622$ 250,000$ 165,685$ 84,315$ 2,400,000$ 1,750,000$         2,400,000$                  -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   2.1310 Design & Engineering - Kenai HVDC Terminal/Switchyard500,000$ 25,000$ 475,000$ 500,000$ 390,819$ 109,181$ 150,000$ 46,313$ 103,687$ -$ -$ -$ 1,150,000$ 650,000$             1,150,000$                       2.1330 Design & Engineering - Beluga HVDC Terminal/Switchyard500,000$ 25,000$ 475,000$ 500,000$ 390,819$ 109,181$ 150,000$ 46,313$ 103,687$ -$ -$ -$ 1,150,000$ 650,000$             1,150,000$                       2.1350 Design & Engineering - HVDC Submarine Cable1,000,000$ 25,000$ 975,000$ 1,000,000$ 781,638$ 218,362$ 500,000$ 154,378$ 345,622$ -$ -$ -$ 2,500,000$ 1,500,000$         2,500,000$                  -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   2.1410 Site Agreements - Kenai HVDC Terminal/Switchyard400,000$ 400,000$ -$ -$ -$ 250,000$ 77,189$ 172,811$ -$ -$ -$ 650,000$ 250,000$             650,000$                           2.1430 Site Agreements - Beluga HVDC Terminal/Switchyard400,000$ 400,000$ -$ -$ -$ 250,000$ 77,189$ 172,811$ -$ -$ -$ 650,000$ 250,000$             650,000$                           2.1450 Site Agreements - HVDC Submarine Cable400,000$ 400,000$ -$ -$ -$ 250,000$ 77,189$ 172,811$ -$ -$ -$ 650,000$ 250,000$             650,000$                      -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              Phase 2 ‐ Procurement & Acquisiton (Material and Services)-$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   2.2110 Long Lead Purchases - Kenai HVDC Terminal/Switchyard-$ -$ 22,000,000$ 17,196,030$ 4,803,970$ 30,000,000$ 9,262,673$ 20,737,327$ -$ -$ -$ 52,000,000$ 52,000,000$       52,000,000$                     2.2130 Long Lead Purchases - Beluga HVDC Terminal/Switchyard-$ -$ 22,000,000$ 17,196,030$ 4,803,970$ 30,000,000$ 9,262,673$ 20,737,327$ -$ -$ -$ 52,000,000$ 52,000,000$       52,000,000$                     2.2150 Long Lead Purchases - HVDC Submarine Cable-$ -$ 25,723,463$ 20,106,429$ 5,617,034$ 35,000,000$ 10,806,452$ 24,193,548$ -$ -$ -$ 60,723,463$ 60,723,463$       60,723,463$                -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              Phase 3 ‐ Construction & Deployment-$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   2.3110 Right-of-Way Clearing/Site Prep - Kenai HVDC Terminal/Switchyard-$ -$ -$ -$ -$ 9,000,000$ 2,778,802$ 6,221,198$ -$ -$ -$ 9,000,000$ 9,000,000$         9,000,000$                       2.3130 Right-of-Way Clearing/Site Prep - Beluga HVDC -$ -$ -$ -$ -$ 9,000,000$ 2,778,802$ 6,221,198$ -$ -$ -$ 9,000,000$ 9,000,000$         9,000,000$                       2.3150 Right-of-Way Clearing/Site Prep - HVDC Submarine Cable-$ -$ -$ -$ -$ 10,000,000$ 3,087,558$ 6,912,442$ -$ -$ -$ 10,000,000$ 10,000,000$       10,000,000$                -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   2.3210 Construction - Kenai HVDC Terminal/Switchyard-$ -$ -$ -$ -$ 12,500,000$ 3,859,447$ 8,640,553$ 19,000,000$ 12,592,077$ 6,407,923$ 31,500,000$ 31,500,000$       31,500,000$                     2.3230 Construction - Beluga HVDC Terminal/Switchyard-$ -$ -$ -$ -$ 12,500,000$ 3,859,447$ 8,640,553$ 19,000,000$ 12,592,077$ 6,407,923$ 31,500,000$ 31,500,000$       31,500,000$                     2.3240 Construction - HVDC Submarine Cable-$ -$ -$ -$ -$ 16,575,286$ 5,117,715$ 11,457,571$ 45,422,135$ 30,103,107$ 15,319,028$ 61,997,421$ 61,997,421$       61,997,421$                -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              Phase 4 ‐ Testing & Commissioning-$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   2.4110 Commissioning & Testing - Kenai HVDC Terminal/Switchyard-$ -$ -$ -$ -$ -$ -$ -$ 500,000$ 331,370$ 168,630$ 500,000$ 500,000$             500,000$                           2.4130 Commissioning & Testing - Beluga HVDC Terminal/Switchyard-$ -$ -$ -$ -$ -$ -$ -$ 500,000$ 331,370$ 168,630$ 500,000$ 500,000$             500,000$                           2.4150 Commissioning & Testing - HVDC Submarine Cable-$ -$ -$ -$ -$ -$ -$ -$ 1,000,000$ 662,741$ 337,259$ 1,000,000$ 1,000,000$         1,000,000$                  5,900,000$            400,000$               5,500,000$            73,223,463$          57,234,220$          15,989,243$          166,925,286$        51,539,144$          115,386,142$        85,972,135$          56,977,250$          28,994,885$          332,020,884$ 326,120,884$     332,020,884$              DNI OH, Indirects & Consultants9-2024-03-18 AlaskaEnergyAuthority_Budget_Justification REVISED only budget Period 1WBS Task - Budget357 GRIP Preliminary Budget BreakdownDRAFT4/4/2024TaskBudget Period 1FY 2024 FY 2025 Budget Period 2FY 2026 FY 2027 Budget Period 3FY 2028 FY 2029 Budget Period 4FY 2030 FY 2031Total FY2026‐FY2031Budget Period 1 + FY2006‐FY2031- 0.00%78.16%0.00%30.88%0.00%66.27%3.0000    Central BESS0.00%0.00%0.00%0.00%Phase 1 ‐ Design Permitting and Siting3.1110    Preliminary Design- Central BESS-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   3.1200 Prermitting - Central BESS-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   3.1300 Design & Engineering - Central BESS750,000$ 75,000$ 675,000$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 750,000$ ‐$                     750,000$                           3.1400 Site Agreements - Central BESS-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              Phase 2 ‐ Procurement & Acquisiton (Material and Services)-$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   3.2100 Long Lead Purchases - Central BESS-$ -$ -$ -$ -$ -$ -$ -$ 10,000,000$ 1,000,000$ 9,000,000$ 10,000,000$ 10,000,000$       10,000,000$                -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              Phase 3 - Construction & Deployment-$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   3.3100 Right-of-Way Clearing/Site Prep - Central BESS-$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   3.3130 Construction - Central BESS-$ -$ -$ -$ -$ -$ -$ -$ 8,000,000$ 8,000,000$ -$ 8,000,000$ 8,000,000$         8,000,000$                  -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              Phase 4 ‐ Testing & Commissioning-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   3.4100 Commissioning & Testing - Central BESS-$ -$ -$ -$ -$ -$ -$ -$ 500,000$ 500,000$ -$ 500,000$ 500,000$             500,000$                      750,000$ 75,000$ 675,000$ -$ -$ -$ -$ -$ -$ 18,500,000$ 9,500,000$ 9,000,000$ 19,250,000$ 18,500,000$ 19,250,000$ 4.0000    Northern BESS0.00% 0.00% 0.00% 0.00%Phase 1 ‐ Design Permitting and Siting4.1110    Preliminary Design - Northern Bess-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   4.1200 Permitting - Northern BESS-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   4.1300 Design & Engineering - Northern BESS750,000$ 75,000$ 675,000$ -$ -$ -$ -$ -$ -$ -$ -$ -$ 750,000$ ‐$                     750,000$                           4.1500 Site Agreements - Northern Bess-$ -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              Phase 2 ‐ Procurement & Acquisiton (Material and Services)-$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   4.2100 Long Lead Purchases - Northern Bess-$ -$ -$ -$ -$ -$ -$ -$ 17,500,000$ 17,500,000$ -$ 17,500,000$ 17,500,000$       17,500,000$                -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              Phase 3 ‐ Construction & Deployment-$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   4.3100 Right-of-Way Clearing/Site Prep - Northern BESS-$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   4.3300 Construction - Northern BESS-$ -$ -$ -$ -$ -$ -$ -$ 14,000,000$ 14,000,000$ -$ 14,000,000$ 14,000,000$       14,000,000$                -$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                              Phase 4 ‐ Testing & Commissioning-$ -$ -$ -$ -$ -$ -$ -$ ‐$                     ‐$                                   4.4100 Commissioning & Testing - Northern BESS-$ -$ -$ -$ -$ -$ -$ -$ 573,135.00$ 573,135$ -$ 573,135$ 573,135$             573,135$                      750,000$               75,000$                 675,000$               ‐$                        ‐$                        ‐$                        ‐$                        ‐$                        ‐$                        32,073,135$          32,073,135$          ‐$                        32,823,135$ 32,073,135$       32,823,135$                -$ 7,400,000$ 550,000$ 6,850,000$ 73,223,463$ 57,234,220$ 15,989,243$ 166,925,286$ 51,539,144$ 115,386,142$ 136,545,270$ 98,550,385$ 37,994,885$ 384,094,019$ 376,694,019$ 384,094,019$ 550,000$ 64,850,000$ 63,000,000$ 17,600,000$ 53,600,000$ 120,000,000$ 61,900,000$ 31,500,000$ 413,000,000$ 413,000,000$ 65,400,000$ 80,600,000$ 173,600,000$ 93,400,000$ 9-2024-03-18 AlaskaEnergyAuthority_Budget_Justification REVISED only budget Period 1WBS Task - Budget358 GRIP Preliminary Budget BreakdownDRAFT4/4/2024TaskBudget Period 1FY 2024 FY 2025 Budget Period 2FY 2026 FY 2027 Budget Period 3FY 2028 FY 2029 Budget Period 4FY 2030 FY 2031Total FY2026‐FY2031Budget Period 1 + FY2006‐FY2031General Administration CostsPersonnel1,536,298$            1,597,750$            1,661,660$            1,728,127$            6,523,836$            4,987,537$         6,523,836$                  Fringe1,082,019$            1,125,300$            1,170,312$            1,217,124$            4,594,754$            3,512,735$         4,594,754$                  Travel75,400$                 79,170$                 83,129$                 87,285$                 324,983$               249,583$             324,983$                      Equipment80,000$                 ‐$                        80,000$                 ‐$                        160,000$               80,000$               160,000$                      Supplies80,000$                 84,000$                 88,200$                 92,610$                 344,810$               264,810$             344,810$                      Indirect Costs1,775,149$            1,782,317$            1,593,413$            1,794,719$            6,945,599$            5,170,449$         6,945,599$                  ‐$                        ‐$                        ‐$                        ‐$                        ‐$                        ‐$                     ‐$                              4,628,866$            4,668,537$            4,676,714$            4,919,865$            18,893,982$          14,265,116$       18,893,982$                Project Coordination Committee600,000$               600,000$               60,000$                 600,000$               1,860,000$            1,260,000$         1,860,000$                  Contractor ‐ Federal Reporting150,000$               150,000$               150,000$               150,000$               600,000$               450,000$             600,000$                      Accounting & Audit Services150,000$               150,000$               150,000$               150,000$               600,000$               450,000$             600,000$                      Legal425,000$               425,000$               425,000$               425,000$               1,700,000$            1,275,000$         1,700,000$                  Public Relations48,000$                 48,000$                 48,000$                 48,000$                 192,000$               144,000$             192,000$                      Labor/Government Consulting225,000$               225,000$               225,000$               225,000$               900,000$               675,000$             900,000$                      Insurance Consultant100,000$               10,000$                 10,000$                 10,000$                 130,000$               30,000$               130,000$                      Cultural Consultant100,000$               100,000$               100,000$               100,000$               400,000$               300,000$             400,000$                      Land Consultant400,000$               400,000$               400,000$               400,000$               1,600,000$            1,200,000$         1,600,000$                  NEPA Consultant200,000$               200,000$               30,000$                 ‐$                        430,000$               230,000$             430,000$                      ‐$                        ‐$                        ‐$                        ‐$                     ‐$                              Design & Engineering Consultants400,000$               400,000$               400,000$               400,000$               1,600,000$            1,200,000$         1,600,000$                  2,798,000$            2,708,000$            1,998,000$            2,508,000$            10,012,000$          7,214,000$         10,012,000$                Indirect Costs7,426,866$            7,376,537$            6,674,714$            7,427,865$            28,905,982$          21,479,116$       28,905,982$                14,826,866$          80,600,000$          173,600,000$        143,973,135$        413,000,001$        398,173,135$     413,000,001$              9-2024-03-18 AlaskaEnergyAuthority_Budget_Justification REVISED only budget Period 1WBS Task - Budget359 360 GRIP Preliminary Schedule DRAFT 4/4/2024 Task FY 2024 FY 2025 FY 2026 FY 2027 FY 2028 FY 2029 FY 2030 FY 2031 2.0000 HVDC Transmission tie between the Kenai Peninsula and Beluga Phase 1 - Design Permitting and Siting 2.1110 Preliminary Design - Kenai HVDC Terminal/Switchyard 2.1130 Preliminary Design - Beluga HVDC Terminal/Switchyard 2.1150 Preliminary Design - HVDC Submarine Cable 2.1210 Permitting - Kenai HVDC Terminal/Switchyard 2.1230 Permitting - Beluga HVDC Terminal/Switchyard 2.1250 Permitting - HVDC Submarine Cable 2.1310 Design & Engineering - Kenai HVDC Terminal/Switchyard 2.1330 Design & Engineering - Beluga HVDC Terminal/Switchyard 2.1350 Design & Engineering - HVDC Submarine Cable 2.1410 Site Agreements - Kenai HVDC Terminal/Switchyard 2.1430 Site Agreements - Beluga HVDC Terminal/Switchyard 2.1450 Site Agreements - HVDC Submarine Cable Phase 2 - Procurement & Acquisiton (Material and Services) 2.2110 Long Lead Purchases - Kenai HVDC Terminal/Switchyard 2.2130 Long Lead Purchases - Beluga HVDC Terminal/Switchyard 2.2150 Long Lead Purchases - HVDC Submarine Cable Phase 3 - Construction & Deployment 2.3110 Right-of-Way Clearing/Site Prep - Kenai HVDC 2.3130 Right-of-Way Clearing/Site Prep - Beluga HVDC 2.3150 Right-of-Way Clearing/Site Prep - HVDC Submarine Cable 2.3210 Construction - Kenai HVDC Terminal/Switchyard 2.3230 Construction - Beluga HVDC Terminal/Switchyard 2.3240 Construction - HVDC Submarine Cable Phase 4 - Testing & Commissioning 2.4110 Commissioning & Testing - Kenai HVDC Terminal/Switchyard 2.4130 Commissioning & Testing - Beluga HVDC Terminal/Switchyard 2.4150 Commissioning & Testing - HVDC Submarine Cable 3.0000 Central BESS Phase 1 - Design Permitting and Siting 3.1110 Preliminary Design- Central BESS 3.1200 Prermitting - Central BESS 3.1300 Design & Engineering - Central BESS 3.1400 Site Agreements - Central BESS Phase 2 - Procurement & Acquisiton (Material and Services) 3.2100 Long Lead Purchases - Central BESS Phase 3 - Construction & Deployment 3.3100 Right-of-Way Clearing/Site Prep - Central BESS 3.3130 Construction - Central BESS Phase 4 - Testing & Commissioning 3.4100 Commissioning & Testing - Central BESS 4.0000 Northern BESS Phase 1 - Design Permitting and Siting 4.1110 Preliminary Design - Northern Bess 4.1200 Permitting - Northern BESS 4.1300 Design & Engineering - Northern BESS 4.1500 Site Agreements - Northern Bess Phase 2 - Procurement & Acquisiton (Material and Services) 4.2100 Long Lead Purchases - Northern Bess Phase 3 - Construction & Deployment 4.3100 Right-of-Way Clearing/Site Prep - Northern BESS 4.3300 Construction - Northern BESS Phase 4 - Testing & Commissioning 4.4100 Commissioning & Testing - Northern BESS 11-2024-03-18 AlaskaEnergyAuthority_Budget_Justification REVISED only budget Period 1 (002).xlsx WBS Task - Schedule361 362 PROJECT MANAGEMENT PLAN {Title of Project} WORK PERFORMED UNDER AGREEMENT {Agreement Number} {Recipient Organization Name} {Address} {City, State, Zip Code} Period of Performance: {start date} to {end date} Submitted: {date} Revision: {#} PRINCIPAL INVESTIGATOR {Name} {Phone Number} {E-Mail} BUSINESS CONTACT {Name} {Phone Number} {E-Mail} SUBMITTED TO U. S. Department of Energy National Energy Technology Laboratory DOE Project Officer: {Name} 363 This report should not contain any proprietary, business sensitive, or other information not subject to public release. ACRONYM LIST .......................................................................................... 1 I. EXECUTIVE SUMMARY AND TECHNICAL APPROACH ................... 2 II. KEY PERSONNEL ............................................................................... 3 III. TEAM MEMBERS ................................................................................ 4 IV. PROJECT BUDGET AND SPEND PLAN ............................................ 7 V. MILESTONE LOG .............................................................................. 10 VI. PROJECT SCHEDULE AND DELIVERABLES .................................. 11 VII. METRICS ........................................................................................... 13 VIII. RISK MANAGEMENT ........................................................................ 15 TABLE OF CONTENTS 364 3 ACRONYM LIST CSP: Cybersecurity Plan CBP: Community Benefits Plan DOE: Department of Energy FOA: Funding Opportunity Announcement FY: Fiscal Year (federal) PMP: Project Management Plan Q#: Quarter # SOPO: Statement of Project Objectives 365 4 Add project specific acronyms as needed. RECIPIENT SHOULD REMOVE ALL ITALICIZED INSTRUCTIONS AND EXAMPLES FROM EACH. I. EXECUTIVE SUMMARY AND TECHNICAL APPROACH Provide a synopsis of the overall project that briefly describes the technical approach, objective(s), goals, and expected outcomes and relevant performance targets of the project. The applicant should provide a summary of the end of project goal(s). At a minimum, there must be one SMART end of project goal. The summary provided should be consistent with the SOPO. 366 5 II. KEY PERSONNEL List the project team’s key personnel, their role, and contact information. Key personnel are identified in the Financial Assistance Agreement and, at a minimum, include the Principal Investigator and Business Point of Contact. Note that changes to key personnel require prior DOE approval. KEY PERSONNEL Role Name Phone Email Principal Investigator Business Point of Contact 367 III. TEAM MEMBERS Complete the following table to provide a summary of Prime Recipient and Team Member planned activities by SOPO task and/or subtask number(s). SUMMARY OF TEAM MEMBER PLANNED ACTIVITIES Team Member Planned Activities by SOPO Task/Subtask Number(s) Prime Recipient 1.0 - Manage and execute the project. Develop required plans. X.Y - Design evaluations. Utility ABC X.Y - Providing data. X.Y - Software demonstration host; will install at backup/secondary control center. Professor Tom Smith, (University Name) X.Y - Engineering code development. 368 Complete the following table to provide information about the roles, location, and funding for members of the project team. If a team member has multiple roles and/or multiple locations, include a separate entry for each role and location. Include any team member:  receiving or providing project funds (government or cost share) equal to or greater than $25,000;  providing intellectual property (include value if applicable); and/or  serving as demonstration host/location regardless of value. For each team member listed in the table, select the role description from the following:  Subrecipient,  Demonstration Host/Location,  Vendor (e.g., services, equipment, supplies, etc.)  Intellectual Property Provider (e.g., source code, data, algorithms, etc.),  Cost Share Provider, and  Other Use the address that is closest to where the team member’s work will be performed. SUMMARY OF TEAM MEMBER ROLES AND FUNDING Team Member Role Location Value Utility XYZ Demo Host/Location 123 Main Street Morgantown, WV 26505 $0 Utility XYZ Demo Host/Location 14 Main Street Pittsburgh, PA 15219 $0 Vendor ABC Vendor 456 Main Street Pittsburgh, PA 15219 $100,000 Another Utility Cost Share Provider 1 Another Utility Drive Morgantown, PA 19543 $250,000 369 370 9 IV. PROJECT PHASE AND SPEND PLAN Complete the following tables, and ensure that each budget category is consistent with the SF- 424A form included with the Financial Assistance Agreement. Use the following template guidance to capture the overall project budget summary. Following, provide the budget is detailed by each Phase as detailed in the SOPO. PLANNED BUDGET SUMMARY Budget Category Federal Share Non-Federal Share Total Personnel Fringe Benefits Travel Equipment Supplies Contractual (List each contract valued at $25,000 or more. Add rows as necessary) Remaining Contractual (Sum of all contracts that are individually valued at under $25,000) Construction Other Sub-Total Direct Charges Indirect Charges Total 371 1 PLANNED BUDGET PHASE 1 Design, Permitting and Siting Budget Category Federal Share Non-Federal Share Total Personnel Fringe Benefits Travel Equipment Supplies Contractual (List each contract valued at $25,000 or more. Add rows as necessary) Remaining Contractual (Sum of all contracts that are individually valued at under $25,000) Construction Other Sub-Total Direct Charges Indirect Charges Total PLANNED BUDGET PHASE 2, Procurement and Acquisition (Materials and Services) Budget Category Federal Share Non-Federal Share Total Personnel Fringe Benefits Travel Equipment Supplies 372 1 Contractual (List each contract valued at $25,000 or more. Add rows as necessary) Remaining Contractual (Sum of all contracts that are individually valued at under $25,000) Construction Other Sub-Total Direct Charges Indirect Charges Total PLANNED BUDGET PHASE 3, Construction and Deployment Budget Category Federal Share Non-Federal Share Total Personnel Fringe Benefits Travel Equipment Supplies Contractual (List each contract valued at $25,000 or more. Add rows as necessary) Remaining Contractual (Sum of all contracts that are individually valued at under $25,000) Construction Other Sub-Total Direct Charges Indirect Charges Total 373 1 PLANNED BUDGET PHASE 4, Testing and Commissioning Budget Category Federal Share Non-Federal Share Total Personnel Fringe Benefits Travel Equipment Supplies Contractual (List each contract valued at $25,000 or more. Add rows as necessary) Remaining Contractual (Sum of all contracts that are individually valued at under $25,000) Construction Other Sub-Total Direct Charges Indirect Charges Total Complete the following table to outline the planned spending for each quarter during the project. The list should correspond to the Federal Fiscal Year (FY). For example, “FY18, Q1” would refer to the quarter that began October 1, 2017. QUARTERLY SPEND PLAN Quarter Federal Share Non-Federal Share Total FY##, Q1 FY##, Q2 FY##, Q3 FY##, Q4 374 1 FY##, Q1 375 14 Add/Remove rows as needed. TOTAL 376 15 V. MILESTONE LOG Complete the following table to identify milestones that demonstrate significant progress toward meeting the overall project goals. Include go/no-go decision points and their associated decision criteria in the table. A milestone is a time-based marker that indicates that a significant activity, process, or phase of work has been initiated or completed. A milestone may be either a progress measure (which can be activity based) or a SMART technical milestone. SMART milestones should be Specific, Measurable, Achievable, Relevant, and Timely, and must demonstrate a technical achievement rather than simply completing a task. For each milestone, list the associated SOPO task/subtask and how the achievement of the milestone will be verified. (For Topic Area 3 Projects, the Project Officer should ensure that the following items are included: : The readiness, viability, and expected timing of the deployment strategy, including key milestones relating to critical financial, development, and implementation stages of the project) Additional milestone guidance is provided immediately following in this PMP template. MILESTONE LOG Milestone (or Decision Point) SOPO Task/ Subtask Number Planned Completion Date Verification Method (or Decision Criteria) NDAs with industry partners are signed X.Y MM/DD/YY Confirmation email to Federal Project Officer. Design specification complete. X.Y MM/DD/YY Confirmed in quarterly report. 377 16 Guidance for Creating Project Management Plan Milestones Include Go/No-Go decision points as listed in the SOPO. At a minimum, each project must have at least one Go/No-Go decision point for each phase (approximately every 12 to 18-month period) of the project. The applicant should also provide the specific objective criteria to be used to evaluate the project at the Go/No-Go decision point. Go/No-Go decision points are considered “SMART” and can fulfill the requirement for an annual SMART milestone. A milestone is used to gauge overall progress toward achieving the project goals. In order to exhibit project progress/achievement as accurately as possible, a milestone must be specific, measurable, attainable, relevant, and timely. The project must have at least one milestone per quarter for the duration of the project with at least one SMART technical milestone per year (depending on the project, more milestones may be necessary to comprehensively demonstrate progress). A sufficient number of milestones should be included that demonstrate work completed or progress made towards achieving project goals. Fundamentally, a milestone:  Marks the end or the beginning of an event;  Occurs by a specific date;  Has no duration of time, expends no resources, and has no associated costs; and  Can be verified. A milestone is not a process, task, activity, or deliverable. However, as shown in the following examples, the completion of a process, task, activity; or submission of a deliverable can be a milestone.  A process: “Oversight of the NEPA program” may be a significant element of the project, however it does not help measure actual progress. On the other hand, “Obtain a NEPA Categorical Exclusion” (as part of the NEPA process) can be a milestone.  A SOPO task/subtask or activity: While the task “Development of the Preliminary Design” may be substantial, it is not a milestone. However, “Complete the Preliminary Design” could be a milestone since it would be a measure of progress made towards achieving the project goals.  A deliverable: “Submit the Communications Plan” may be considered a milestone since it marks completion of a significant task, activity, phase, etc. As such, the deliverable can provide a measure of project progress. However, unless the deliverable marks the completion of an important work package or phase, it may not possess sufficient significance to warrant being a milestone. It is understood that Recipients will use a variety of internal indicators, benchmarks, etc. to track/gauge the progress made by the team toward completing the planned project. However, many of these may not have the significance to be included as a PMP milestone. 378 VI. PROJECT SCHEDULE AND DELIVERABLES Complete the following table to provide the schedule and estimated cost for executing each of the tasks and subtasks described in the SOPO. Additionally, provide a WBS Gantt chart as an appendix to this PMP. SCHEDULE & COST SUMMARY BY PHASE SOPO Task/ Subtask Number SOPO Task/ Subtask Title Planned Start Date Planned Completion Date Planned Total Cost (DOE and Cost Share) 1.0 Project Management and Planning MM/DD/YY MM/DD/YY $XXX,XXX Complete the following table to include only the deliverables defined in the SOPO. DELIVERABLES LOG SOPO Task/ Subtask Number Deliverable Planned Completion Date 1.1 Project Management Plan MM/DD/YY 1.2 Community Benefits Plan MM/DD/YY 1.3 National Environmental Policy Act (NEPA) Compliance MM/DD/YY 1.4 Cybersecurity Plan (* if applicable) MM/DD/YY VII. METRICS Complete the following table to include all the metrics stipulated in the FOA, and any metrics defined by the Recipient. PROJECT METRICS 379 SOPO Task/ Subtask Number Tracking Metric Units (%, $, #, etc.) Goal for Phase X.X Estimated capital cost $/unit $1,000 X.X Number of utilities participating in energy emergency exercises # 15 X.X System energy efficiencies % Improvement by >20% X.X Outage time of critical loads Hours/ Interruption Reduced by >98% XX Increase the capacity of transmission facilities % Improvement by >20% SELECT APPROPRIATE COLUMN HEADERS BASED ON PHASE. 380 19 VIII. RISK MANAGEMENT Complete the following table to identify both internal and external risks (i.e., technical, resource, management, etc.), that may impact the likelihood of project success. For each identified risk, indicate any relevant task/subtask, likelihood of occurrence and the extent and potential impact on successful project completion. Provide a narrative below the table that describes the project’s risk management process, including at a minimum: monitoring frequency, new risk identification, risk retirement, and team member involvement. RISK MANAGEMENT LOG Risk Likelihood (High, Medium, Low) Impact (High, Medium, Low) Potential Impact (Identify SOPO Task/Subtask, if applicable) Mitigation Strategy Inability to secure required cost share. Low High Scope of project will be reduced or project may be terminated. {Insert appropriate mitigation strategy here} Loss of utility partner. Low Medium Significant delay in starting demonstration phase in Task 5.0. {Insert appropriate mitigation strategy here} 381 382     Draft – 03/20/2024  FOA-0002740 Grid Resilience and Innovation Partnerships (GRIP), Topic Area 3 STATEMENT OF PROJECT OBJECTIVES (SOPO) Alaska Energy Authority Railbelt Innovation Resiliency Project – Phase 1 A. OBJECTIVES   The Railbelt Innovation Resiliency Project (RIR) aims to enhance resiliency and transfer capability along the Railbelt. The Railbelt has experienced decreasing frequency regulation, slowed disturbance response and increasing magnitude natural frequency oscillations. The current configuration of the Railbelt system restricts the adoption of clean energy, diversification of the fuel supply, and Alaska's preparation for a sustainable carbon-free future. A key priority to achieve this objective is to reinforce interconnections between the primary regions of the Railbelt by adding parallel lines and implementing Battery Energy Storage Systems (BESS) to resolve long- standing frequency control and instability issues. Along with the High Voltage Direct Current (HVDC) submarine cable, these additions will alleviate transmission congestion and optimize interregional transfer capability. The project's innovative solutions hold the promise of curbing escalating energy prices, which currently rank among the highest in the nation, while providing rural residents and disadvantaged communities with an opportunity to enhance community viability. Sharing these solutions with other communities will support collective efforts toward achieving clean, reliable, and affordable energy for all. B. SCOPE OF WORK     The RIR project involves several primary components to meet the project's objectives. The projects involve the interconnection of AC Transmission with a High Voltage Direct Current (HVDC) submarine circuit and three large capacity Battery Energy Storage systems (BESS). Coordinated interregional control and operations of the BESS and HVDC line will tie all the individual systems together to maximize stability and limit congestion. The first component is a HVDC transmission tie connection between the Kenai Peninsula and the Beluga substation. This transmission tie consists of an HVDC cable and the associated converter stations. The overall objective of this segment is to construct a parallel path between the Central region and Southern region which will improve transfer capability and increase resilience. The parallel line will reduce generating costs and will provide an optional path if fires or avalanches interrupt power transfer. The tie connection adds a new bay on the Kenai along with a converter station. A similar process is repeated on the west side of Cook Inlet where the HVDC transitions back to AC at the Beluga substation. 383     Draft – 03/20/2024  The second component includes the addition of two Battery Energy Storage Systems (BESS). The new BESS units will be located in both Northern and Central regions and will augment the existing BESS unit in the Southern region. Incorporating BESS units in all three regions (Southern, Central & Northern) will provide significant reliability and economic benefit to the entire Railbelt. The Northern BESS will be installed within a building to provide maximum protection from Fairbanks’ extreme temperatures. Both BESS units will include battery modules, power transformers, switchgear and associated bus, steel, control, fire suppression and communications equipment. C. TASKS TO BE PERFORMED Task 1.0: Project Management and Planning Subtask 1.0010: Project Management Plan (PMP): Within 30 days of award, the Recipient shall provide the Project Management Plan (PMP) to the designated Federal Project Officer (FPO). The Recipient shall not proceed beyond Task 1.0 until the PMP has been accepted by the FPO. The PMP shall be revised and resubmitted as often as necessary, during the course of the project, to capture any major/significant changes to the planned approach, budget, key personnel, major resources, etc. The Recipient shall manage and direct the project in accordance with the accepted PMP to meet all technical, schedule and budget objectives and requirements. The Recipient will coordinate activities to effectively accomplish the work. The Recipient will ensure that project plans, results, and decisions are appropriately documented, and that project reporting and briefing requirements are satisfied. Subtask 1.0020: Community Benefits Plan Within 30 days of award, the Recipient shall revise the Community Benefits Plan (CBP) and submit to the designated Federal Project Officer (FPO). The Recipient shall not proceed beyond Task 1.0 until the CBP has been accepted by the FPO. The CBP shall be revised and resubmitted as often as necessary, during the project execution, to capture any major/significant changes to the CBP with regard to the four priority goals; Community and Labor Engagement; Investing in the American Workforce; Diversity, Equity, Inclusion, and Accessibility; and Justice 40 Initiative. The Recipient will coordinate activities to effectively implement the CBP goals. The Recipient will ensure that metrics, SMART community benefits plan commitments, and 384     Draft – 03/20/2024  outcomes are appropriately documented, and that reporting and briefing requirements to stakeholders are satisfied. Subtask 1.0030: National Environmental Policy Act (NEPA) Compliance As required, the Recipient shall provide the documentation necessary for NEPA  compliance. Subtask 1.0040: Cybersecurity Plan (CSP) The CSP shall be revised and resubmitted as often as necessary, during the course of the project, to capture any major/significant changes. Subtask 1.0050: Regulatory, State, Local, Regional, and/or Federal Approval As applicable, the Recipient will secure and maintain relevant regulatory agency, state, local, regional, and/or federal agencies approvals. Phase 1 - Design, Permitting and Siting Task 2.0: HVDC Transmission tie between the Kenai Peninsula and Beluga  Subtask 2.1: Preliminary Design (description) Subtask 2.1.1: Kenai HVDC Terminal/Switchyard (description) Subtask 2.1.2: Beluga HVDC Terminal/Switchyard (description) Subtask 2.1.3: HVDC Submarine Cable (description) Task 2.2: Permitting (description) Subtask 2.2.1: Kenai HVDC Terminal/Switchyard (description) Subtask 2.2.2: Beluga HVDC Terminal/Switchyard (description) Subtask 2.2.3: HVDC Submarine Cable (description) Task 2.3: Design & Engineering (description) 385     Draft – 03/20/2024  Subtask 2.3.1: Kenai HVDC Terminal/Switchyard (description) Subtask 2.3.2: Beluga HVDC Terminal/Switchyard (description) Subtask 2.3.3: HVDC Submarine Cable (description) Task 2.4: Site Agreements (description) Subtask 2.3.1: Kenai HVDC Terminal/Switchyard (description) Subtask 2.3.2: Beluga HVDC Terminal/Switchyard (description) Subtask 2.3.3: HVDC Submarine Cable (description) Task 3.0: Central BESS D. DELIVERABLES Listed below are a summary of the initial document to be submitted. Subtask 1.001: Project Management Plan as outlined above. Subtask 1.0020: Community Benefits Plan as outlined above. Subtask 1.0030: NEPA Compliance (as applicable) Subtask 1.0040: Cybersecurity Plan 386     Draft – 03/20/2024  Technical Go/No Go Decision Briefings Document(s)     Final Project Accomplishments (format to be provided by the FPM)             Due 30 days prior to the end of the performance period  (add deliverables) Additional deliverables as well as any documents that the DOE and AEA determine are applicable will be delivered to DOE. In addition to the deliverables listed above, the Recipient shall submit all periodic, topical, final, and other reports in accordance with the Federal Assistance Reporting Checklist and accompanying instructions. E. BRIEFINGS/TECHNICAL PRESENTATIONS The Recipient shall prepare, and present periodic briefings, technical presentations and demonstrations as requested by the Federal Project Officer, which may be held at a DOE or the Recipient’s facility, other mutually agreeable location, or via webinar. Such meetings may include all or a combination of the following: Kickoff Briefing - Not more than 60 days after submission of the Project Management Plan, the Recipient shall prepare and present a project summary briefing as part of a Project Kickoff Meeting. Technical Go/No Go Decision Briefings – Not less than 90 days prior to the planned start of a phase relative to an established go/no go decision point, the Recipient shall brief the DOE on the status of the project success criteria, milestones, Go/No-Go Decision point metrics that are documented in the Project Management Plan (PMP), and their plans for the subsequent periods of work. The Go/No-Go Decision will be based on the successful completion of the milestones and metrics as defined in the PMP (including approval of associated deliverables) as well as meeting the established milestones defined in the Community Benefits Outcomes and Objectives (CBOO) for the given performance period. The Recipient will not begin the next phase of work (or a subsequent task/subtask) until receiving written authorization from the DOE Contracting Officer (CO) to proceed in accordance with the award terms and conditions. The DOE will consider the information from this briefing, as well as the content of deliverables submitted to date, prior to authorizing continuing the project. Final Project Briefing - Not less than 30 days prior to the end of the project, the Recipient shall prepare and present a Final Project Briefing on the results and accomplishments of the entire project. Other Briefings – The Recipient shall prepare and present technical, financial, and/or administrative briefings as requested by the DOE. A project technical review briefing will be 387     Draft – 03/20/2024  conducted no less than annually. Additionally, the DOE may require Recipients to make technical presentations at national and/or industry conferences.    388     Draft – 03/20/2024         389     Draft – 03/20/2024  3.0000      Central BESS Phase 1 ‐ Design Permitting and Siting 3.1110      Preliminary Design- Central BESS        3.1200 Prermitting - Central BESS        3.1300 Design & Engineering - Central BESS        3.1400 Site Agreements - Central BESS Phase 2 ‐ Procurement & Acquisiton (Material and Services)        3.2100 Long Lead Purchases - Central BESS Phase 3 - Construction & Deployment        3.3100 Right-of-Way Clearing/Site Prep - Central BESS        3.3130 Construction - Central BESS Phase 4 ‐ Testing & Commissioning        3.4100 Commissioning & Testing - Central BESS 4.0000      Northern BESS Phase 1 ‐ Design Permitting and Siting 4.1110      Preliminary Design - Northern Bess        4.1200 Permitting - Northern BESS        4.1300 Design & Engineering - Northern BESS        4.1500 Site Agreements - Northern Bess Phase 2 ‐ Procurement & Acquisiton (Material and Services)        4.2100 Long Lead Purchases - Northern Bess Phase 3 ‐ Construction & Deployment        4.3100 Right-of-Way Clearing/Site Prep - Northern BESS        4.3300 Construction - Northern BESS Phase 4 ‐ Testing & Commissioning        4.4100 Commissioning & Testing - Northern BESS   390 DRAFT – March 15, 2024    1    Railbelt InnovaƟon Resiliency Project: Community Benefits Outcomes and ObjecƟves  Community Benefits Outcomes and Objectives    Recipient Name: Alaska Energy Authority   Project Title: Railbelt InnovaƟon Resiliency Project   Grant Number: 13888581  I. ExecuƟve Summary   The Railbelt InnovaƟve Resiliency (RIR) Project will directly benefit both Tribal  and disadvantaged  communiƟes (DACs) in Alaska’s Railbelt region. The project seeks to build a resilient, clean, smart, and  affordable electrical grid in Alaska. RIR Community Benefits outcomes and objecƟves include:    Robust public parƟcipaƟon plan with public AEA memo issued in response to stakeholder  feedback.    Increased transfer capacity between regions to enable higher renewable energy integraƟon and  a reducƟon in fossil fuel generaƟon and associated emissions.   Improved long term air quality in communiƟes that house fuel‐based power generaƟon.   Resilience and reliability improvements for Tribal  communiƟes and DACs on the Railbelt.   CreaƟon of construcƟon jobs and long term operaƟon posiƟons.   CreaƟon of apprenƟceship and internship programs to reinvigorate Alaska’s energy workforce,  including local and Alaska NaƟve hiring preference.   Decreased on‐Railbelt community energy burdens with potenƟal member savings of  $44,080,000 annually.   Decreased off‐Railbelt community energy burdens via increased Power Cost EqualizaƟon (PCE)  with potenƟal consumer PCE credit increases of $1,089,145 annually.   The project team will work to develop a Memorandum of Agreement (MOA) with each of the 17 Alaska  NaƟve Village StaƟsƟcal areas on the Railbelt to promote local hiring and creaƟng meaningful  engagement. All procurement will comply with Alaska public contracƟng law which incorporates the  Davis‐Bacon Act (DBA).  DBA is a set of federal  laws applicable to federal public construcƟon projects.  The LiƩle Davis‐Bacon Act (LDBA) is a set of state laws applicable to state projects. Some projects, such  as certain highway projects, may be funded with both federal  and state funds and may be covered by  both federal  and state laws. In these cases, construcƟon contractors must comply with the most  stringent provisions of both sets of laws.                 391 DRAFT – March 15, 2024    2    Railbelt InnovaƟon Resiliency Project: Community Benefits Outcomes and ObjecƟves  Milestone Table   Category and Commitment ExisƟng or Planned  Budget   period 1   Budget  period 2   Budget  period 3   Budget  period 4   Community and Labor  Engagement        Issue RFP and select contractor to  assist with public parƟcipaƟon  plan.  Planned X      DraŌ stakeholder engagement  strategies and outreach media.   Planned A focus group  will be used  to test the  effecƟveness  of these  materials on  diverse  populaƟons.       Launch RIR website with public  meeƟng schedule, project  descripƟon, ArcGIS Online  mapping tool, and public  comment secƟon.  Planned X     Each (4) uƟlity provider and AEA  hosts introductory public work  session.  Planned X     Conduct surveys to address data  gaps idenƟfied during  introductory public work sessions.  Planned X     One‐on‐one work sessions with  relevant organizaƟons, including  Tribes  and DACs.   Planned & ExisƟng   Contact already  made with:  Alaska  FederaƟon of  NaƟves, Alaska  Village Electric  CooperaƟve,  Alaska Black  Caucus, Alaska  Municipal  League, IBEW  Local 1547,  IUOE Local 302,  Alaska  OperaƟng  Engineers  Training  Trust,  Alaska Joint  Electrical  ApprenƟceship  & Training  Trust.       392 DRAFT – March 15, 2024    3    Railbelt InnovaƟon Resiliency Project: Community Benefits Outcomes and ObjecƟves  Joint meeƟng re: submarine  HVDC cable through Cook Inlet to  discuss best pracƟces to minimize  environmental impacts.   Planned     In addiƟon to  federal  requirements,  Project team  and  Environmental  Contractor will  meet with  Alaska  Department of  Fish and Game,  NaƟonal  Marine  Fisheries  Service, and  Kenaitze and  Knik Tribal   Councils.         “Going to the people” outreach  conducted in more informal  seƫngs to recruit diverse group of  stakeholders.  Planned Outreach  conducted at  minimum of 3  public events  designed to  reach  diverse/releva nt audiences:  (Alaska  FederaƟon of  NaƟves  convenƟon,  Alaska Black  Caucus  Sunday night  Zoom  meeƟngs,  Alaska State  Fair, etc.)       Each (4) uƟlity provider as well as  Alaska Energy Authority hosts  second public work session.  Survey results shared as well as  public comment themes to‐date.   Planned X     RIR public parƟcipaƟon plan  report published by AEA, along  with memo in response,  summarizing and responding to  comments.   Planned  X     393 DRAFT – March 15, 2024    4    Railbelt InnovaƟon Resiliency Project: Community Benefits Outcomes and ObjecƟves  AEA will conduct work sessions  with Labor organizaƟons as part  of public parƟcipaƟon plan.  Planned      AEA will work to establish MOAs  with Railbelt Tribes  or Tribal   enƟƟes and local governments to  discuss local hiring opportunies.   Planned X     Support for Worker   Organizing/CollecƟve Bargaining  ☐ Pledge to remain  neutral during any  union organizing  campaigns  ☐Pledge to permit  union recogniƟon  through card check   ☐ IntenƟon to enter  into binding  arbitraƟon to seƩle  first contracts  ☐ Pledge to allow  union organizers  access to appropriate  onsite non‐work  spaces (e.g. lunch  rooms)  ☐ Pledge to refrain  from holding capƟve  audience meeƟngs    X X     Diversity, Equity, Inclusion, and  Accessibility  ☐ Local and/or  targeted recruitment  efforts  ☐ MWBE contracƟng  ☐ Partner with  quality pre‐ apprenƟceship or  apprenƟceship  readiness program  X X X X  Discuss intern opportuniƟes with  Alaska NaƟve Science and  Engineering Program.  Planned      AEA commitment that work  performed with GRIP funding will  be done in compliance with  Alaska public contracƟng law.  ExisƟng   X X X  Project is subject to the Office of  Federal  Contract Compliance  Programs’ requirements for hiring  ExisƟng X X X X  394 DRAFT – March 15, 2024    5    Railbelt InnovaƟon Resiliency Project: Community Benefits Outcomes and ObjecƟves  and adhering to an AffirmaƟve  AcƟon Plan.  AffirmaƟve acƟon and anƟ‐bias  trainings for project hirers.  Planned X X X X  Work  with the University of Alaska,  contractors and our uƟlity partners  to develop apprenƟce and training.  ExisƟng  X X X  Work  sessions with Alaska  OperaƟng Engineers/Employers  Training Trust  (AOEETT), and the  Alaska Joint Electrical  ApprenƟceship & Training  Trust   (AJEATT) will assess how these  apprenƟceship programs serve  workers facing systemic barriers to  employment, and how to reduce  those barriers through RIR  implementaƟon. Findings to be  included in public parƟcipaƟon  report.   Planned X X X X  Collect data on workforce veteran  status, ethnicity, gender, and  disability status through RIR  implementaƟon.   Planned X     Conduct work sessions with  organizaƟons represenƟng DACs  affected by project, including tribal  councils, Alaska Black Caucus, and  Alaska FederaƟon of NaƟves, to  understand desired benefits and  reduced impacts. Minutes included  in public parƟcipaƟon plan report.   Planned  X X X  JusƟce40 IniƟaƟve  X X     AEA will host a joint meeƟng with  Alaska Department of Fish and  Game, NaƟonal Marine Fisheries  Service, and Kenaitze and Knik  Tribal  Councils to discuss how to  minimize adverse environmental  impacts re: placement of HVDC  cable across Cook Inlet. Minutes  included in public parƟcipaƟon plan  report.   Planned      RIR will increase transfer capacity  between the three Railbelt regions,  paving the way for development of  clean energy soluƟons that will  miƟgate environmental impacts  Projected X     395 DRAFT – March 15, 2024    6    Railbelt InnovaƟon Resiliency Project: Community Benefits Outcomes and ObjecƟves  from 3,218 natural‐gas‐produced  GWh on Railbelt each year,  resulƟng in 1.61 billion kilograms of  carbon dioxide equivalent.  RIR is projected to result in a 10‐ 15% reducƟon in thermal spending  due to decreased line losses and  reduced reserves, represenƟng a  non‐cumulaƟve decrease of over  200 million kilograms carbon  dioxide equivalent per year.  Preliminary EsƟmate        Improved long‐term air quality in  communiƟes that house fuel‐based  power generaƟon.  Projected       Railbelt’s 260,000 residenƟal uƟlity  accounts serve 623,916 individuals,  242,407 (39%) of whom live in a  DAC or on Tribal  Land. BPMC  engineers project GMRP (of which  RIR is a part) overall fuel savings  could result in a reducƟon of 0.5  cents/kWh to 1.5 cents/kWh. The  combined Railbelt uƟliƟes sold  4,408 GWh (GigawaƩ‐Hours) in  2020, suggesƟng total savings of  $44,080,000 for a 1 cent per kWh  cost reducƟon. Much of these $44  million in annual savings should  pass through to member‐owners.  Projected       In FY22 PCE served 188  communiƟes, 154 (82%) of whom  qualify as DACs or Tribal  lands.  Approximately 108,914,530 of PCE‐ eligible kWh were produced  between residenƟal and  community faciliƟes in those 154  DACs. At  a one cent decrease in the  average class rate, the increased  credit amount that would be issued  by AEA to PCE‐enrolled DACs is  $1,089,145. Actual average class  rate reducƟon presumed to be  lower due to exclusion of Juneau  from GMRP project.  Projected       26% of Railbelt customers live in an  Alaska NaƟve Village StaƟsƟcal  Area (ANVSA), many of which are  located in remote areas with  Planned      396 DRAFT – March 15, 2024    7    Railbelt InnovaƟon Resiliency Project: Community Benefits Outcomes and ObjecƟves  energy infrastructure that is  parƟcularly vulnerable to natural  disaster. Increased grid resiliency is  a primary goal of this project, best  embodied by the interregional  transmission line that will be  installed parallel to the line that  currently Ɵes together the  Railbelt’s Southern and Central  regions, and which will allow for  conƟnued energy transmission  between regions in the event of a  major natural disaster.  IdenƟfies benefits/impacts to  disadvantaged communiƟes  ☒ Yes  (Cantwell  ANVSA,  Chickaloon ANVSA,  ChiƟna ANVSA,  Copper Center ANVSA,  Eklutna ANVSA,  Gakona ANVSA,  Gulkana ANVSA,  Kenaitze ANVSA,  Knik ANVSA,  Nanwalek ANVSA,  Nenana ANVSA,  Ninilchik ANVSA,  Northway ANVSA,  Port Graham ANVSA,  Seldovia ANVSA,  Tanacross  ANVSA,  Tazlina ANVSA)  ☐ No       ReducƟon in energy costs ☒ Yes   ☐ No       A decrease in environmental  exposure and burdens   ☒ Yes   ☐ No       An increase in quality job creaƟon,  the clean energy job pipeline, and  job training for individuals  ☒ Yes   ☐ No       Increases in clean energy  enterprise creaƟon and contracƟng  (e.g., minority‐owned or diverse  business enterprises)  ☒ Yes   ☐ No       An increase in energy resilience ☒ Yes   ☐ No  Project makes  clean energy  project  development  by       397 DRAFT – March 15, 2024    8    Railbelt InnovaƟon Resiliency Project: Community Benefits Outcomes and ObjecƟves  independent  power  producers  more cost‐ feasible by  increasing  customer base  and economy  of scale due to  increased  transfer  capacity    Resilience  benefits  include right  of way  clearing, aerial  inspecƟons,  and  refurbishment  of exisƟng  lines and  structures.  X X                                        398 National Environmental Policy Act (NEPA) Compliance   As required, AEA will undertake the NEPA process to consider the potential  environmental consequences of the project, to consult with other interested agencies, to  document the analysis, and to make this information available to the public for comment  before the implementation of the project.    AEA believes that this project could require an Environmental Impact Statement (EIS).  If  an EIS is required, AEA will undertake a study with a Lead Agency to identify and analyze  adverse environmental impacts and reasonable alternatives as appropriate.      399 400 Railbelt Innovative Resiliency Project December 2023 V0.2 Cybersecurity Plan 401 Tabl e of Contents A.Project Title: Railbelt Innovative Resiliency (RIR) Project ........................................................ 4 B.Overview of the Cybersecurity Plan .................................................................................................. 4 C.Asset, Change, and Configuration Management ........................................................................ 5 D.Threat and Vulnerability Management .......................................................................................... 17 E.Risk Management.................................................................................................................................. 21 F.Identity and Access Management .................................................................................................. 23 G.Situational Awareness ......................................................................................................................... 28 H.Event and Incident Response, Continuity of Operations ........................................................ 33 I.Supply Chain and Third-Party Risk Assessment ....................................................................... 42 J.Training ................................................................................................................................................. 43 K.Cybersecurity Architecture ................................................................................................................ 48 L.Cybersecurity Program Management ............................................................................................ 63 M.Physical Security of Critical Transmission Facilities ............................................................... 67 402 THIS CYBER SECURITY PLAN IS A CONFIDENTIAL DOCUMENT.PAGE 3 thru PAGE 68 HAVE BEEN INTENTIONALLY DELETED FROM THIS PUBLICATION 403 404 Alaska Energy Authority Grid Resilience and Innovation Partnership Federal Funding and Match Requirement Project Funding Plan as of March 7, 2024 Appropriations Other Funding Expenditure Funding FY Fed Match Fund Source To Be Determined No Approp Needed Fed State Funds or Source To Be Determined Existing AEA Revenue Bonds ** 2025 206.50 12.70 - 20.00 Grant negotiations, bondholder outreach, legal review, and other preparatory costs. Initiate design, engineering, and National Environmental Policy Act (NEPA)/ permitting process for High Voltage Direct Current (HVDC) and Battery Energy Storage Systems (BESS).32.70 12.70 20.00 2026 - - 6.50 25.00 NEPA process, begin procurement of BESS, site design and engineering.31.50 6.50 25.00 2027 - - 8.80 - NEPA process.8.80 8.80 - 2028 - - 21.80 5.00 Complete NEPA process, construct BESS building, begin right-of-way clearing and site preparation.26.80 21.80 5.00 2029 - - 60.00 - HVDC component construction begins (Soldotna switchyard, Soldotna-Bernice HVDC line, Beluga landing, HVDC submarine cable); BESS testing and commissioning.60.00 60.00 - 2030 - - 30.95 - HVDC component construction continues (Soldotna switchyard, Soldotna-Bernice HVDC line, Beluga landing, HVDC submarine cable).30.95 30.95 - 2031 - - 15.75 - HVDC component construction complete (Soldotna switchyard, Soldotna-Bernice HVDC line, Beluga landing, HVDC submarine cable).15.75 15.75 - 2032 - - - - - - - 2033 - - - - - - - 2034 - - - - - - - Total 206.50 12.70 143.80 50.00 206.50 156.50 50.00 Activity 413.00413.00 $ in Millions 405 406 OMB Number: 4040-0004 Expiration Date: 11/30/2025 * 1. Type of Submission: * 2. Type of Application: * 3. Date Received: 4. Applicant Identifier: 5a. Federal Entity Identifier: 5b. Federal Award Identifier: 6. Date Received by State: 7. State Application Identifier: * a. Legal Name: * b. Employer/Taxpayer Identification Number (EIN/TIN): * c. UEI: * Street1: Street2: * City: County/Parish: * State: Province: * Country: * Zip / Postal Code: Department Name: Division Name: Prefix: * First Name: Middle Name: * Last Name: Suffix: Title: Organizational Affiliation: * Telephone Number: Fax Number: * Email: * If Revision, select appropriate letter(s): * Other (Specify): State Use Only: 8. APPLICANT INFORMATION: d. Address: e. Organizational Unit: f. Name and contact information of person to be contacted on matters involving this application: Application for Federal Assistance SF-424 Preapplication Application Changed/Corrected Application New Continuation Revision Completed by Grants.gov upon submission. Alaska Energy Authority 92-6001185 F3N8ZSHJXUH8 813 W. Northern Lights Blvd. Anchorage AK: Alaska USA: UNITED STATES 99503-2407 Mr.Ryan McLaughlin Infrastructure Engineer 907-771-3012 rmclaughlin@akenergyauthority.org DocuSign Envelope ID: D56AF6DF-CE15-48A9-B44F-89A1362BBB9C * 9. Type of Applicant 1: Select Applicant Type: Type of Applicant 2: Select Applicant Type: Type of Applicant 3: Select Applicant Type: * Other (specify): * 10. Name of Federal Agency: 11. Catalog of Federal Domestic Assistance Number: CFDA Title: * 12. Funding Opportunity Number: * Title: 13. Competition Identification Number: Title: 14. Areas Affected by Project (Cities, Counties, States, etc.): * 15. Descriptive Title of Applicant's Project: Attach supporting documents as specified in agency instructions. Application for Federal Assistance SF-424 A: State Government Environmental Protection Agency 66.046 Climate Pollution Reduction Grants EPA-R-OAR-CPRGI-23-07 Climate Pollution Reduction Grants Program: Implementation Grants (General Competition) Climate Pollution Reduction Grant - Dixon Diversion View AttachmentsDelete AttachmentsAdd Attachments View AttachmentDelete AttachmentAdd Attachment DocuSign Envelope ID: D56AF6DF-CE15-48A9-B44F-89A1362BBB9C * a. Federal * b. Applicant * c. State * d. Local * e. Other * f. Program Income * g. TOTAL . Prefix: * First Name: Middle Name: * Last Name: Suffix: * Title: * Telephone Number: * Email: Fax Number: * Signature of Authorized Representative: * Date Signed: 18. Estimated Funding ($): 21. *By signing this application, I certify (1) to the statements contained in the list of certifications** and (2) that the statements herein are true, complete and accurate to the best of my knowledge. I also provide the required assurances** and agree to comply with any resulting terms if I accept an award. I am aware that any false, fictitious, or fraudulent statements or claims may subject me to criminal, civil, or administrative penalties. (U.S. Code, Title 18, Section 1001) ** The list of certifications and assurances, or an internet site where you may obtain this list, is contained in the announcement or agency specific instructions. Authorized Representative: Application for Federal Assistance SF-424 * a. Applicant Attach an additional list of Program/Project Congressional Districts if needed. * b. Program/Project * a. Start Date: * b. End Date: 16. Congressional Districts Of: 17. Proposed Project: AK-001 AK-001 Add Attachment Delete Attachment View Attachment 10/01/2024 09/30/2029 348,415,151.00 0.00 0.00 0.00 0.00 0.00 348,415,151.00 a. This application was made available to the State under the Executive Order 12372 Process for review on b. Program is subject to E.O. 12372 but has not been selected by the State for review. c. Program is not covered by E.O. 12372. Yes No Add Attachment Delete Attachment View Attachment ** I AGREE Mr.Curtis Thayer Executive Director 907-771-3000 cthayer@akenergyauthority.org Completed by Grants.gov upon submission. * 20. Is the Applicant Delinquent On Any Federal Debt? (If "Yes," provide explanation in attachment.) * 19. Is Application Subject to Review By State Under Executive Order 12372 Process? Completed by Grants.gov upon submission. If "Yes", provide explanation and attach DocuSign Envelope ID: D56AF6DF-CE15-48A9-B44F-89A1362BBB9C 3/29/2024 | 4:01:23 PM AKDT SECTION A - BUDGET SUMMARY $ BUDGET INFORMATION - Non-Construction Programs OMB Number: 4040-0006 Expiration Date: 02/28/2025 Grant Program Function or Activity (a) Catalog of Federal Domestic Assistance Number (b) Estimated Unobligated Funds New or Revised Budget Federal (c) Non-Federal (d) Federal (e) Non-Federal (f) Total (g) 5. Totals 4. 3. 2. 1.$$$$ $$$$ Climate Pollution Reduction Grant 66.046 348,415,151.00 348,415,151.00 348,415,151.00 348,415,151.00$ Standard Form 424A (Rev. 7- 97) Prescribed by OMB (Circular A -102) Page 1 DocuSign Envelope ID: D56AF6DF-CE15-48A9-B44F-89A1362BBB9C SECTION B - BUDGET CATEGORIES 7. Program Income d. Equipment e. Supplies f. Contractual g. Construction h. Other j. Indirect Charges k. TOTALS (sum of 6i and 6j) i. Total Direct Charges (sum of 6a-6h) (1) Authorized for Local Reproduction Prescribed by OMB (Circular A -102) Page 1A Standard Form 424A (Rev. 7- 97) GRANT PROGRAM, FUNCTION OR ACTIVITY (2) (3) (4) (5) Total6. Object Class Categories a. Personnel b. Fringe Benefits c. Travel Climate Pollution Reduction Grant 3,010,185.00 1,492,121.00 245,360.00 80,000.00 200,000.00 304,920,588.00 36,890,571.00 346,838,825.00 1,576,326.00 348,415,151.00 3,010,185.00 1,492,121.00 245,360.00 80,000.00 200,000.00 304,920,588.00 36,890,571.00 346,838,825.00 1,576,326.00 348,415,151.00 $$$$$ $$$$$ $$$$$ $ $ DocuSign Envelope ID: D56AF6DF-CE15-48A9-B44F-89A1362BBB9C SECTION D - FORECASTED CASH NEEDS 14. Non-Federal SECTION C - NON-FEDERAL RESOURCES (a) Grant Program (b) Applicant (d) Other Sources(c) State (e)TOTALS $ $ $$$ $ $ $ $ $8. 9. 10. 11. 12. TOTAL (sum of lines 8-11) 15. TOTAL (sum of lines 13 and 14) 13. Federal Total for 1st Year 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Climate Pollution Reduction Grant 12,377,338.00 12,377,338.00 1,902,105.00 1,902,105.00 4,326,544.00 4,326,544.00 4,326,544.00 4,326,544.00 1,822,145.00 1,822,145.00 $$ $$$ $$$$ FUTURE FUNDING PERIODS (YEARS) SECTION F - OTHER BUDGET INFORMATION SECTION E - BUDGET ESTIMATES OF FEDERAL FUNDS NEEDED FOR BALANCE OF THE PROJECT Authorized for Local Reproduction $ $ $$ $ $16. 17. 18. 19. 20. TOTAL (sum of lines 16 - 19) 21. Direct Charges: 22. Indirect Charges: 23. Remarks: (a) Grant Program (b)First (c) Second (d) Third (e) Fourth Climate Pollution Reduction Grant 14,841,181.00 111,916,104.00 152,585,037.00 56,695,491.00 14,841,181.00 111,916,104.00 152,585,037.00 56,695,491.00 $1,576,326$346,838,825 AEA negotiating NICRA for FY24, provisional indirect rate of 31.86% $$ Standard Form 424A (Rev. 7- 97) Prescribed by OMB (Circular A -102) Page 2 DocuSign Envelope ID: D56AF6DF-CE15-48A9-B44F-89A1362BBB9C 3/29/2024 | 4:01:23 PM AKDT OMB Number: 2030-0020 Expiration Date: 06/30/2024EPA KEY CONTACTS FORM Authorized Representative: Original awards and amendments will be sent to this individual for review and acceptance, unless otherwise indicated. Name:Prefix:Mr.First Name:Curtis Middle Name: Last Name:Thayer Suffix: Title:Executive Director Complete Address: Street1:813 W. Northern Lights Blvd. Street2: City:Anchorage State:AK: Alaska Zip / Postal Code:99503-2407 Country:USA: UNITED STATES Phone Number:907-771-3000 Fax Number:907-771-3044 E-mail Address:cthayer@akenergyauthority.org Payee: Individual authorized to accept payments. Name:Prefix:Ms.First Name:Pamela Middle Name: Last Name:Ellis Suffix: Title:Controller Complete Address: Street1:813 W. Northern Lights Blvd. Street2: City:Anchorage State:AK: Alaska Zip / Postal Code:99503-2407 Country:USA: UNITED STATES Phone Number:907-771-3981 Fax Number:907-771-3044 E-mail Address:pellis@akanergyauthority.org Administrative Contact: Individual from Sponsored Programs Office to contact concerning administrative matters (i.e., indirect cost rate computation, rebudgeting requests etc). Name:Prefix:Ms.First Name:Pamela Middle Name: Last Name:Ellis Suffix: Title:Controller Complete Address: Street1:813 W. Northern Lights Blvd. Street2: City:Anchorage State:AK: Alaska Zip / Postal Code:99503-2407 Country:USA: UNITED STATES Phone Number:907-771-3981 Fax Number:907-771-3044 E-mail Address:pellis@akenergyauthority EPA Form 5700-54 (Rev 4-02) DocuSign Envelope ID: 235AFF1F-D830-4493-A51D-61BBA7EE6BC3 EPA KEY CONTACTS FORM Project Manager: Individual responsible for the technical completion of the proposed work. Name:Prefix:Mr.First Name:Ryan Middle Name: Last Name:McLaughlin Suffix: Title:Infrastructure Engineer Complete Address: Street1:813 W. Northern Lights Blvd. Street2: City:Anchorage State:AK: Alaska Zip / Postal Code:99503-2407 Country:USA: UNITED STATES Phone Number:907-771-3012 Fax Number:907-771-3044 E-mail Address:rmclaughlin@akenergyauthority EPA Form 5700-54 (Rev 4-02) DocuSign Envelope ID: 235AFF1F-D830-4493-A51D-61BBA7EE6BC3 3/29/2024 | 9:11:18 AM AKDT Preaward Compliance Review Report for All Applicants and Recipients Requesting EPA Financial Assistance Note: Read Instructions before completing form. OMB Number: 2030-0020 Expiration Date: 06/30/2024 I. A. Applicant/Recipient (Name, Address, City, State, Zip Code) Name:Alaska Energy Authority Address:813 W. NORTHERN LIGHTS BLVD. City:Anchorage State:AK: Alaska Zip Code:99503-2407 B. Unique Entity Identifier (UEI):F3N8ZSHJXUH8 II. Is the applicant currently receiving EPA Assistance?Yes No Curtis ThayerName: 907-771-3000Phone: cthayer@akenergyauthority.orgEmail: Executive DirectorTitle: C. Applicant/Recipient Point of Contact III. List all pending civil rights lawsuits and administrative complaints filed under federal law against the applicant/recipient that allege discrimination based on race, color, national origin, sex, age, or disability. (Do not include employment complaints not covered by 40 C.F.R. Parts 5 and 7.) None IV. List all civil rights lawsuits and administrative complaints decided against the applicant/recipient within the last year that alleged discrimination based on race, color, national origin, sex, age, or disability and enclose a copy of all decisions. Please describe all corrective actions taken. (Do not include employment complaints not covered by 40 C.F.R. Parts 5 and 7.) None V. List all civil rights compliance reviews of the applicant/recipient conducted under federal nondiscrimination laws by any federal agency within the last two years and enclose a copy of the review and any decisions, orders, or agreements based on the review. Please describe any corrective action taken. (40 C.F.R. § 7.80(c)(3)) None VI. Is the applicant requesting EPA assistance for new construction? If no, proceed to VII; if yes, answer (a) and/or (b) below. Yes No a. If the grant is for new construction, will all new facilities or alterations to existing facilities be designed and constructed to be readily accessible to and usable by persons with disabilities? If yes, proceed to VII; if no, proceed to VI(b). Yes No b. If the grant is for new construction and the new facilities or alterations to existing facilities will not be readily accessible to and usable by persons with disabilities, explain how a regulatory exception (40 C.F.R. 7.70) applies. Grant will fund construction of the Dixon Diversion Project. The Project will impact mechanical rooms and other spaces that, because of their intended use, will not require accessibility to the public or beneficiaries and therefore fall under the regulatory exception laid out in 40 C.F.R. 7.70(b)(2) DocuSign Envelope ID: 235AFF1F-D830-4493-A51D-61BBA7EE6BC3 VII. Does the applicant/recipient provide initial and continuing notice that it does not discriminate on the basis of race, color, national origin, sex, age, or disability in its program or activities? (40 C.F.R 5.140 and 7.95) Yes No a. Do the methods of notice accommodate those with impaired vision or hearing?Yes No b. Is the notice posted in a prominent place in the applicant's/recipient’s website, in the offices or facilities or, for education programs and activities, in appropriate periodicals and other written communications? Yes No c. Does the notice identify a designated civil rights coordinator?Yes No VIII. Does the applicant/recipient maintain demographic data on the race, color, national origin, sex, age, or disability status of the population it serves? (40 C.F.R. 7.85(a)) Yes No IX. Does the applicant/recipient have a policy/procedure for providing meaningful access to services for persons with limited English proficiency? (Title VI, 40 C.F.R. Part 7, Lau v Nichols 414 U.S. (1974)) Yes No X. If the applicant is an education program or activity, or has 15 or more employees, has it designated an employee to coordinate its compliance with 40 C.F.R. Parts 5 and 7? Provide the name, title, position, mailing address, e-mail address, fax number, and telephone number of the designated coordinator. Karen Turner, Human Resources Director, 813 W. Northern Lights Blvd. Anchorage, AK 99503. KTurner@aidea.org, 907-771-3000 phone, 907-771-3946 fax. XI. If the applicant is an education program or activity, or has 15 or more employees, has it adopted grievance procedures that assure the prompt and fair resolution of complaints that allege a violation of 40 C.F.R. Parts 5 and 7? Provide a legal citation or applicant’s/ recipient’s website address for, or a copy of, the procedures. https://humanrights.alaska.gov For the Applicant/Recipient I certify that the statements I have made on this form and all attachments thereto are true, accurate and complete. I acknowledge that any knowingly false or misleading statement may be punishable by fine or imprisonment or both under applicable law. I assure that I will fully comply with all applicable civil rights statutes and EPA regulations. A. Signature of Authorized Official B. Title of Authorized Official Executive Director C. Date For the U.S. Environmental Protection Agency I have reviewed the information provided by the applicant/recipient and hereby certify that the applicant/recipient has submitted all preaward compliance information required by 40 C.F.R. Parts 5 and 7; that based on the information submitted, this application satisfies the preaward provisions of 40 C.F.R. Parts 5 and 7; and that the applicant has given assurance that it will fully comply with all applicable civil rights statures and EPA regulations. A. Signature of Authorized EPA Official B. Title of Authorized Official C. Date DocuSign Envelope ID: 235AFF1F-D830-4493-A51D-61BBA7EE6BC3 3/29/2024 | 9:11:18 AM AKDT Instructions for EPA FORM 4700-4 (Rev. 04/2021) General. Recipients of Federal financial assistance from the U.S. Environmental Protection Agency must comply with the following statutes and regulations. Title VI of the Civil Rights Acts of 1964 provides that no person in the United States shall, on the grounds of race, color, or national origin, be excluded from participation in, be denied the benefits of, or be subjected to discrimination under any program or activity receiving Federal financial assistance. The Act goes on to explain that the statute shall not be construed to authorize action with respect to any employment practice of any employer, employment agency, or labor organization (except where the primary objective of the Federal financial assistance is to provide employment). Section 13 of the 1972 Amendments to the Federal Water Pollution Control Act provides that no person in the United States shall on the ground of sex, be excluded from participation in, be denied the benefits of, or be subjected to discrimination under the Federal Water Pollution Control Act, as amended. Employment discrimination on the basis of sex is prohibited in all such programs or activities. Section 504 of the Rehabilitation Act of 1973 provides that no otherwise qualified individual with a disability in the United States shall solely by reason of disability be excluded from participation in, be denied the benefits of, or be subjected to discrimination under any program or activity receiving Federal financial assistance. Employment discrimination on the basis of disability is prohibited in all such programs or activities. The Age Discrimination Act of 1975 provides that no person on the basis of age shall be excluded from participation under any program or activity receiving Federal financial assistance. Employment discrimination is not covered. Age discrimination in employment is prohibited by the Age Discrimination in Employment Act administered by the Equal Employment Opportunity Commission. Title IX of the Education Amendments of 1972 provides that no person in the United States on the basis of sex shall be excluded from participation in, be denied the benefits of, or be subjected to discrimination under any education program or activity receiving Federal financial assistance. Employment discrimination on the basis of sex is prohibited in all such education programs or activities. Note: an education program or activity is not limited to only those conducted by a formal institution. 40 C.F.R. Part 5 implements Title IX of the Education Amendments of 1972. 40 C.F.R. Part 7 implements Title VI of the Civil Rights Act of 1964, Section 13 of the 1972 Amendments to the Federal Water Pollution Control Act, and Section 504 of The Rehabilitation Act of 1973. Items "Applicant" means any entity that files an application or unsolicited proposal or otherwise requests EPA assistance. 40 C.F.R. §§ 5.105, 7.25. "Recipient" means any State or its political subdivision, any instrumentality of a State or its political subdivision, any public or private agency, institution, organizations, or other entity, or any person to which Federal financial assistance is extended directly or through another recipient, including any successor, assignee, or transferee of a recipient, but excluding the ultimate beneficiary of the assistance. 40 C.F.R. §§ 5.105, 7.25. "Civil rights lawsuits and administrative complaints" means any lawsuit or administrative complaint alleging discrimination on the basis of race, color, national origin, sex, age, or disability pending or decided against the applicant and/or entity which actually benefits from the grant, but excluding employment complaints not covered by 40 C.F.R. Parts 5 and 7. For example, if a city is the named applicant but the grant will actually benefit the Department of Sewage, civil rights lawsuits involving both the city and the Department of Sewage should be listed. "Civil rights compliance review" means: any federal agency-initiated investigation of a particular aspect of the applicant's and/or recipient's programs or activities to determine compliance with the federal non-discrimination laws. Submit this form with the original and required copies of applications, requests for extensions, requests for increase of funds, etc. Updates of information are all that are required after the initial application submission. If any item is not relevant to the project for which assistance is requested, write "NA" for "Not Applicable." In the event applicant is uncertain about how to answer any questions, EPA program officials should be contacted for clarification. DocuSign Envelope ID: 235AFF1F-D830-4493-A51D-61BBA7EE6BC3 Certification for Contracts, Grants, Loans, and Cooperative Agreements (2) If any funds other than Federal appropriated funds have been paid or will be paid to any person for influencing or attempting to influence an officer or employee of any agency, a Member of Congress, an officer or employee of Congress, or an employee of a Member of Congress in connection with this Federal contract, grant, loan, or cooperative agreement, the undersigned shall complete and submit Standard Form-LLL, ''Disclosure of Lobbying Activities,'' in accordance with its instructions. (3) The undersigned shall require that the language of this certification be included in the award documents for all subawards at all tiers (including subcontracts, subgrants, and contracts under grants, loans, and cooperative agreements) and that all subrecipients shall certify and disclose accordingly. This certification is a material representation of fact upon which reliance was placed when this transaction was made or entered into. Submission of this certification is a prerequisite for making or entering into this transaction imposed by section 1352, title 31, U.S. Code. Any person who fails to file the required certification shall be subject to a civil penalty of not less than $10,000 and not more than $100,000 for each such failure. If any funds have been paid or will be paid to any person for influencing or attempting to influence an officer or employee of any agency, a Member of Congress, an officer or employee of Congress, or an employee of a Member of Congress in connection with this commitment providing for the United States to insure or guarantee a loan, the undersigned shall complete and submit Standard Form-LLL, ''Disclosure of Lobbying Activities,'' in accordance with its instructions. Submission of this statement is a prerequisite for making or entering into this transaction imposed by section 1352, title 31, U.S. Code. Any person who fails to file the required statement shall be subject to a civil penalty of not less than $10,000 and not more than $100,000 for each such failure. * APPLICANT'S ORGANIZATION * SIGNATURE: * DATE: * PRINTED NAME AND TITLE OF AUTHORIZED REPRESENTATIVE Suffix: Middle Name: * Title: * First Name: * Last Name: Prefix: CERTIFICATION REGARDING LOBBYING (1) No Federal appropriated funds have been paid or will be paid, by or on behalf of the undersigned, to any person for influencing or attempting to influence an officer or employee of an agency, a Member of Congress, an officer or employee of Congress, or an employee of a Member of Congress in connection with the awarding of any Federal contract, the making of any Federal grant, the making of any Federal loan, the entering into of any cooperative agreement, and the extension, continuation, renewal, amendment, or modification of any Federal contract, grant, loan, or cooperative agreement. The undersigned certifies, to the best of his or her knowledge and belief, that: Statement for Loan Guarantees and Loan Insurance The undersigned states, to the best of his or her knowledge and belief, that: Completed on submission to Grants.gov Completed on submission to Grants.gov DocuSign Envelope ID: 235AFF1F-D830-4493-A51D-61BBA7EE6BC3 3/29/2024 | 9:11:18 AM AKDT 10. a. Name and Address of Lobbying Registrant: 9. Award Amount, if known: $ * Street 1 * City State Zip Street 2 * Last Name Prefix * First Name Middle Name Suffix DISCLOSURE OF LOBBYING ACTIVITIES Complete this form to disclose lobbying activities pursuant to 31 U.S.C.1352 OMB Number: 4040-0013 Expiration Date: 02/28/2025 1. * Type of Federal Action: a. contract b. grant c. cooperative agreement d. loan e. loan guarantee f. loan insurance 2. * Status of Federal Action: a. bid/offer/application b. initial award c. post-award 3. * Report Type: a. initial filing b. material change 4. Name and Address of Reporting Entity: Prime SubAwardee * Name Alaska Energy Authority * Street 1 813 W. Northern Lights Blvd.Street 2 * City Anchorage State AK: Alaska Zip 99503 Congressional District, if known:AK-001 5. If Reporting Entity in No.4 is Subawardee, Enter Name and Address of Prime: 6. * Federal Department/Agency: Environmental Protection Agency 7. * Federal Program Name/Description: Climate Pollution Reduction Grants CFDA Number, if applicable: 66.046 8. Federal Action Number, if known: EPA-R-OAR-CPRGI-23-07 N/A b. Individual Performing Services (including address if different from No. 10a) Prefix * First Name Middle Name * Street 1 * City State Zip Street 2 N/A 11. * Last Name Suffix Information requested through this form is authorized by title 31 U.S.C. section 1352. This disclosure of lobbying activities is a material representation of fact upon which reliance was placed by the tier above when the transaction was made or entered into. This disclosure is required pursuant to 31 U.S.C. 1352. This information will be reported to the Congress semi-annually and will be available for public inspection. Any person who fails to file the required disclosure shall be subject to a civil penalty of not less than $10,000 and not more than $100,000 for each such failure. * Signature: Completed on submission to Grants.gov Completed on submission to Grants.gov *Name:Prefix Mr.* First Name Curtis Middle Name * Last Name Thayer Suffix Title:Executive Director Telephone No.:907-771-3000 Date: Federal Use Only: Authorized for Local Reproduction Standard Form - LLL (Rev. 7-97) DocuSign Envelope ID: 235AFF1F-D830-4493-A51D-61BBA7EE6BC3 3/29/2024 | 9:11:18 AM AKDT 1 Project Workplan – Dixon Diversion 1. Overall Project Summary and Approach (45 points) a. Description of GHG Reduction Measures (20 points) The Alaska Energy Authority (AEA) proposes the Dixon Diversion project as a Greenhouse Gas Reduction Measure under the Alaska Priority Sustainable Energy Action Plan (PSEAP). The Dixon Diversion project is a significant and transformative expansion of the existing AEA-owned Bradley Lake Hydroelectric project on the Kenai Peninsula of Alaska. The objective of this project is to divert water coming off the Dixon Glacier into Bradley Lake which will increase the capacity of the hydroelectric project by 190,800 MWh/year, as well as offset 106,668 MTCO2e of emissions and displace at least 1.5 billion cubic feet of natural gas annually. The Dixon Diversion project will accomplish this objective through the following project elements: a diversion dam and intake structure at the toe of the Dixon Glacier, a 4.7-mile long 14-foot diameter underground tunnel to convey water from the Martin River to the existing Bradley Lake reservoir, modifications to the existing dam to raise the reservoir elevation by 14 feet, and 1 mile of new access road. By utilizing existing energy infrastructure, this project allows for a significant renewable resource to be developed on an extremely small footprint and represents the largest renewable energy project in Alaska in the last 30 years. The original Bradley Lake hydroelectric project, commissioned in 1991, has been a steadfast source of low-cost renewable power in Alaska. Located 27 air miles northeast of Homer, Alaska, it boasts 120 MW of installed capacity, featuring a 125-foot-high concrete-faced, rock-filled dam structure, a 3.5-mile-long power tunnel and vertical shaft, generating plant, interior substation, 20 miles of transmission line, and substation. This project generates approximately 400,000 MWh of renewable electricity annually, representing 10% of the total annual power consumed by Railbelt electric utilities. Bradley power stands out as one of the most cost-effective energy sources on the Railbelt. Alaska’s interconnected transmission system, colloquially referred to as the Railbelt, serves 75% of Alaska’s population. It spans nearly 700 miles from the Bradley Lake Project in the south to Delta Junction in the north and is operated by four member owned cooperatives, one city owned utility, and AEA. Power generated from the Bradley Lake hydroelectric project has consistently served all consumers along the entire Railbelt. The Dixon Diversion would not be the first major expansion to the Bradley Lake project. As recently as 2020, AEA completed the West Fork Upper Battle Creek Diversion project. This project constructed a concrete diversion dam, three miles of new road, and a 5-foot diameter pipeline buried alongside the road to convey water from the diversion dam at the headwaters of Battle Creek into Bradley Lake. The additional water flowing into Bradley Lake increased the energy coming out of the project by about 40,000 MWh, or a 10% increase in power generation. The Battle Creek Diversion Project was completed on schedule and within the original budget. The existing and proposed components of the Bradley Lake, Battle Creek, and Dixon Diversion project are shown below. 2 Figure 1: Dixon Diversion Project Map AEA has identified the Dixon Diversion project as an economic and beneficial expansion of the already successful Bradley Lake Hydroelectric project. This project would increase the energy generated from Bradley by an impressive 50%, meeting 5% of the total demand of the entire Railbelt. The Dixon Diversion project will use CPRG funds to complete the relicensing process and construct the expansion. This process entails amending the existing Federal Energy Regulatory Commission (FERC) license, an endeavor necessitating several years of comprehensive studies, which AEA has already initiated. Notably, in 2022, AEA filed the Notice of Amendment and Initial Consultation Document, subsequently accepted by FERC. Progressing through the process, preliminary studies were conducted in the summer of 2022, followed by soliciting input from the public and resource agencies on the Draft 3 Study Plan document in November 2022. Further preliminary studies were undertaken in 2023, focusing on hydrology, stream gauging, and video monitoring to assess fish habitat and usage in the Martin River, the river that comes off the Dixon Glacier. A Final Study Plan will be submitted in April 2024 which will outline the remaining two years of study plans. This plan will be developed and accepted with input and concurrence from applicable resource agencies to ensure the project's potential effects are well known. Some of the major studies that will occur in the 2024 and 2025 field seasons include but are not limited to: geotechnical drilling and investigation at the tunnel inlet and outlet, continued hydrology and stream gaging, water quality monitoring, geomorphology, aquatic habitat characterization and fish use, and cultural resource studies. Pre-engineering and design work will occur concurrently with the environmental studies, and following the 2025 field season, a Draft Amendment Application (DAA) will be submitted for comment and review to the public, stakeholders, resource agencies, and FERC. The DAA will go through an extensive review process and a Final Amendment Application will be submitted to FERC in 2026. After FERC approval and completion of the National Environmental Protection Act (NEPA) process, the project will go out to bid for construction. Construction of the Dixon Diversion project will be completed through two primary phases: Dam Raise & Powerline Construction, and Diversion Dam & Tunnel Construction. The dam raise and powerline construction may be bid separately and completed first. The primary reasons for this are that as soon as the dam raise is complete, Bradley Lake will have additional storage capacity that can be utilized. The lake level will be raised by at least 14 feet through modifications to the dam, including the addition of a gate to the spillway crest and raising the existing dam crest and parapet wall accordingly. The byproduct of additional storage capacity and higher head pressures at the powerplant will result in more efficient energy production from all Bradley water representing an additional 8000 MWh of energy production annually. There were multiple different levels of dam raise investigated as part of this project, and 14 feet likely strikes the right balance in gaining additional reservoir capacity, without altering the dam's structural integrity. The 14-foot raise will be accomplished through minimal intervention. Bradley Lake is surrounded by steep rocky faces along its perimeter, and inflows from a glacial outwash plain to the east. Acreage in the flat outwash plain will become inundated as the reservoir level increases, but total inundation will remain small as most of the lake is surrounded by steep rocky cliffs. AEA has modeled a range of reservoir raise scenarios and an increase up to 28 feet is possible within the project's current areal constraints. 4 Figure 2: Inundation map of Bradley Lake for a range of dam raise scenarios Simultaneous to the dam raise, crews would work on installing infrastructure to run three-phase power from the Bradley Lake Powerhouse to the Bradley Dam. This power will run beneath the existing road up to the dam, improving its operability and acting as a power supply for the Tunnel Boring Machine (TBM) used to drill the Dixon Diversion Tunnel, providing clean hydroelectric power in lieu of the alternative diesel-generator-powered TBM operation. Following installation of 3-phase power and modifications to the Bradley Dam, operations to begin constructing the diversion dam, intake structure, and tunnel can begin. The diversion dam will be constructed near the toe of the Dixon Glacier on State land. This area is accessible only by helicopter, so crews and equipment will be flown in to initiate work on the diversion dam while the tunnel is being constructed. Crews will work out of a man-camp at the project site which will eventually be converted into a permanent maintenance equipment building. The diversion dam will be either constructed as a rock fill dam or rubber dam, with a gated sluiceway for sediment transport and minimum instream flows down the Martin River. Construction of the intake structure and diversion dam is expected to last approximately 1 season. 5 Figure 3: Conceptual design of diversion dam and tunnel intake (plan view) Figure 4: Toe of Dixon Glacier, location of future diversion dam and tunnel intake 6 The tunnel construction will be the most expensive and involved aspect of this project. The tunnel will be 4.7 miles long, underground from Bradley Lake to the Dixon diversion dam. The tunnel diameter will be 14 feet, and AEA has determined that there are enough TBMs currently in operation worldwide to source for boring a tunnel of that size. TBM was compared to a drill and blast method of tunnel construction and was found to drill at much faster rates of penetration to justify the mobilization costs of the equipment. The TBM has additional benefits including reduced friction inside the tunnel due to smoother walls from TBM construction compared to drill and blast. Following construction of 300 feet of starter tunnel using drill and blast methods, the TBM will drill uphill towards the diversion dam and TBM operations will take approximately a year to complete. Due to the underground nature of this phase of the project, operations can continue through the winter season. Upon completion of the tunnel, equipment and power can be run to the diversion dam via the newly drilled tunnel. This will allow enhanced remote operability of equipment at the diversion dam as well as provide an alternative means to mob and demob equipment from the diversion dam. Upon commissioning of the project, the tunnel should be able to convey up to 1400 cubic feet per second (cfs) of water into Bradley Lake. Several times each summer, flood events along the Martin River will exceed the diversion tunnel's capacity and excess water will flow downriver past the diversion dam creating channel maintenance events on the lower Martin River. The Dixon Diversion project is expected to come online by early 2030, prior to the start of the 2030 water year, and will immediately provide benefits to the entire Railbelt upon commissioning. With a hydroelectric facility and powerplant already in place, all water that is diverted from Dixon Glacier into Bradley Lake will generate electricity that will directly offset natural gas generated energy in Alaska and provide greenhouse gas reduction benefits to the entire state of Alaska. b. Demonstration of Funding Need (10 points) The Total Project Cost for the Dixon Diversion, using a class 4/5 Engineer’s Estimate is $342 million. This includes preliminary study and engineering costs, relicensing efforts, and construction costs. This does not include AEA costs. AEA is not aware of any Federal funding opportunities that currently exist for the development of new state-owned hydroelectric projects of this magnitude. There is a substantial amount of work that has been completed and ongoing to submit the FERC license amendment necessary for the project. This includes preliminary engineering and geotech work for the diversion dam construction and tunnel boring efforts, hydrology and stream gaging to determine energy potential and minimum instream flow requirements for salmon, and permitting and license preparation. AEA has funded work to-date through a $1 million grant from AEA’s Renewable Energy Fund, $1.36 million total contribution from local electric utilities, and $5 million in FY24 State of Alaska funds appropriated through the legislature. AEA has put in a request for an additional $7 million from the State of Alaska’s FY25 budget to complete preliminary environmental and engineering work in the 2025 season. Some of project costs may be eligible for the Clean Electricity Investment Tax Credit (48E) or the Clean Electricity Production Tax Credit (45Y), which are expected to be in place until at least 2032, authorized 7 through the Inflation Reduction Act (IRA) and the state may be eligible to receive those credits through the elective pay provisions provided by the IRA. The amount of that credit will vary based on several factors and would be reduced if AEA uses tax exempt bonds or receives grants to fund the project. Any proceeds from tax credits would be received after the commissioning and would not provide the cash flow needed for construction. The Dixon Diversion Project appears to be economical and cost competitive with current and future natural gas prices. A Climate Pollution Reduction Grant would ensure this beneficial and transformational project can be completed on time, reducing greenhouse gas emissions in Alaska and reducing Alaska’s dependence on rapidly dwindling natural gas supplies. If AEA were not to receive a grant under this program, funding would most likely be secured through utility revenue bonds. The project's cost would fall on customers of the five Railbelt utility co-ops. Alaska’s small population and harsh winters are attributed, in part, to the high energy burden experienced by its residents. A Climate Pollution Reduction Grant would relieve the upward pressure on rates that are incurred owing to debt service costs resulting from needed investment for utility-scale energy projects. c. Transformative Impact (15 points) 75% of Alaska’s population is served by the Railbelt for their electric needs. The Railbelt electric transmission (Railbelt) is an electric transmission system comprised of interconnected transmission infrastructure assets owned by four independent member-owned electric cooperatives; one municipal electric utility; and the State-owned Alaska Interties and Bradley Lake Hydroelectric Project transmission assets. This transmission system spans over 700 miles from Bradley Lake at its southernmost point, to Delta Junction in interior Alaska at its northernmost point. The Railbelt also serves multiple major centers of economic activity, and critical assets along its lines, including but not limited to, military installations, hospital / critical care facilities, fire/police/EMS facilities, major ports of entry, and key access points for natural resource extraction and processing all of which rely on power delivered via the Railbelt for their daily operation. In 2022, the Railbelt generated 4698 GWH of electricity primarily through carbon intensive means. Natural gas fired generators account for approximately 64% of the generation along the Railbelt, with coal and fuel oil accounting for another ~20%. The Railbelt is highly reliant on natural gas and other fossil fuels for its electricity and heating needs, and any increase in renewable generation via hydropower development would directly offset such costly carbon-based energy generation assets. The Dixon Diversion project is expected to meet ~5% of the Railbelt’s electricity demand and would be the largest renewable energy project in Alaska in 30 years. The Bradley Lake hydroelectric project provides firm, year-round power which utilities can dispatch at times of peak demand. In Alaska peak demand occurs in the winter when temperatures are coldest and daylight hours are shortest. Peak generation plants are inefficient compared to baseload plants. Using storage hydropower to meet these peak demands reduce the frequency whereby inefficient and high-carbon emitting generation facilities are turned on to accommodate such peaks in energy demand. 8 An additional concern in Alaska, and reason to accelerate this project, is the impending natural gas shortage in Southcentral Alaska. Natural gas is the primary energy generation fuel source in Southcentral Alaska, and all such gas is extracted from Cook Inlet gas fields. Cook Inlet is Alaska’s oldest producing oil and gas basin and has been producing hydrocarbons since the 1950’s. This pool has been in decline for decades, but in a few years the gas produced from Cook Inlet will not be sufficient to meet the energy demands for the Railbelt. A 2023 report commissioned by Enstar, the local natural gas utility in Southcentral Alaska, found that natural gas demand from Cook Inlet will likely exceed supply by 2027- 2028. There have been more recent estimates that predict that shortage happening even sooner. Currently, there are no cost-effective alternatives to offset the oncoming shortage. The most likely scenario is that utilities will have to import liquefied natural gas (LNG) to meet the natural gas shortage in the coming years. Southcentral Alaska does not have an LNG import terminal, which would need to be built, and LNG will come with even higher emissions than locally sourced natural gas due to overseas shipping-related emissions. Importing LNG also would represent a significant increase in the cost of energy for all Alaskans. Alaska already faces some of the highest energy costs in the nation, importing LNG would increase the price of natural gas deliveries by at least 50%. The energy produced from the Dixon Diversion project will offset 1.5-1.6 billion cubic feet (bcf) annually. This energy represents 7.5% of the projected unmet natural gas demand in 2030, a significant step in addressing the energy needs for the Railbelt. The Dixon Diversion is a significant expansion of the Bradley Lake Hydroelectric project and is a firm, reliable energy source that helps regulate energy needs along the Railbelt. Storage hydro has many benefits compared to other types of renewable sources, especially in Alaska, because it is dispatchable year-round. The coldest and darkest winter months correspond to the highest energy demands, and storage hydro remains available to draw from during those times of high demand. Solar and wind are both great renewable resources in Alaska, but their energy output is unpredictable and can destabilize the grid. Increasing firm renewable resources, such as storage hydro, allows utilities to regulate energy and integrate more non-firm energy sources. A recent cold weather event in January 2023 illustrated the need for storage hydro. Anchorage had been experiencing temperatures below –20 F, breaking daily low-temperature records and the frigid temperatures had been persistent for weeks. The Cook Inlet Natural Gas Storage Facility, an underground gas storage reservoir, had experienced failures on two of five wells. Utilities were all directed to maximize their hydroelectric production to alleviate the pressure on the gas delivery system. Wind and solar resources in Alaska were not able to contribute during this critical period, highlighting the fact that a MW from a storage hydro project like the Dixon Diversion project is far more valuable to Alaska than a MW of energy from wind or solar. 2. Impact of GHG Reduction Measures (60 points) a. Magnitude of GHG Reductions from 2025-2030 (20 points) The Dixon Diversion project is scheduled to be completed and commissioned by early 2030. This will capture a full water year in 2030 and associated greenhouse gas reductions from that water. In these systems water typically starts flowing in late April / early May. A minimum instream flow (MIF) will be 9 established through the FERC licensing process, and once flows exceed the MIF, excess water will be diverted through the Dison Diversion tunnel into Bradley Lake. The water year typically ends in late October / early November once temperatures consistently drop below freezing and there is not enough flow to divert water anymore. The project is expected to be commissioned before spring break-up so the magnitude of greenhouse gas reductions from 2025-2030 would be equivalent to the energy produced from a full water year. Based on synthetic flows of the Martin River averaged over the previous decade, accounting for expected minimum instream flow requirements and the capacity of the 14-foot diameter diversion tunnel, the Dixon Diversion project will produce 190,800 MWh of electricity annually. EPA’s 2022 eGRID conversion factor for the Alaska Railbelt (AKGD – ASCC Alaska Grid subregion) nonbaseload rates gives an accurate estimation of CO2e reductions for projects that displace electricity generation. For the Railbelt the eGRID subregion annual CO2e non-baseload output emission rate is 1,232.508 lb/MWh. 190,800 𝑀𝑀𝑀𝑀ℎ× 1,232.508 𝑙𝑙𝑙𝑙 𝐶𝐶𝐶𝐶2𝑒𝑒𝑀𝑀𝑀𝑀ℎ×  1 𝑀𝑀𝑀𝑀2204.62 𝑙𝑙𝑙𝑙=106,668 𝑀𝑀𝑀𝑀 𝐶𝐶𝐶𝐶2𝑒𝑒 Magnitude of GHG Reductions from 2025-2030 = 106,668 MTCO2e b. Magnitude of GHG Reductions from 2025-2050 (10 points) To estimate the magnitude of GHG Reductions from 2025-2050, the same annual energy output from Dixon will be used over a 25-year period. It is likely that the energy numbers over this period could be even higher, due to an observable trend of higher flows in recent years due to warmer summers melting the source glaciers at a faster rate. 106,668 𝑀𝑀𝑀𝑀𝐶𝐶𝐶𝐶2𝑒𝑒 × 25 𝑦𝑦𝑒𝑒𝑦𝑦𝑦𝑦𝑦𝑦 = 2,666,701 𝑀𝑀𝑀𝑀𝐶𝐶𝐶𝐶2𝑒𝑒 Magnitude of GHG Reductions from 2025-2050 = 2,666,701 MTCO2e c. Cost effectiveness of GHG Reduction (15 points) $343,659,601/ 106,668MTCO2e = $3,222/MTCO2e The Dixon Diversion project boasts a remarkable level of cost-effectiveness that is not captured in the scoring. Due to the extensive and involved FERC licensing process, realization of project benefits are delayed until both licensing and construction are finished. Even through all project funds will be utilized within five years, the advantages of greenhouse gas reduction won’t commence until the fifth year. Nevertheless, upon completion, this project is poised to deliver year-round benefits to Alaska for approximately a century. When considering the lifecycle of a typical hydroelectric project, the cost- effectiveness is notably high, with hydroelectric projects consistently producing the most economical energy along the Railbelt. d. Documentation of GHG Reduction Assumptions (15 points) 10 Annual greenhouse gas reductions resulting from the Dixon Diversion project are calculated from offsets of expected energy production from the hydroelectric project. To develop estimations of energy produced from the Dixon Diversion project, it is critical to accurately measure the discharge of the Martin River. The Martin River, which comes off the Dixon Glacier, is a fast moving, cold, and highly turbid river. Upon exiting the glacier, the Martin River quickly enters a canyon characterized by a series of waterfalls and deep canyon walls. Upon exiting the canyon, the river becomes highly braided and remains that way until the reaching tidewater. Due to its remote nature, highly mobile bed load, and lack of defined channel, the Martin River is a challenge to accurately measure. In the summer of 2023, there was a large field effort to characterize the Martin River. The United States Geological Survey (USGS) installed and operates a stage gage on the Martin River around where it first exits the canyon (USGS 15238951). AEA hired a contractor to install additional stream gages on the Martin River, with the primary gage located at the “Constriction”. The contractor performed 10 site visits between April and September to gather discharge measurements. These measurements were used to build a stage-discharge relationship for both gage locations, and from there the daily flow could be estimated over the summer. A hydrograph was created for the summer 2023 season using a combination of the two established gage sites on the Martin River. Figure 5: Hydrograph of discharge on Martin River, 2023 Water Year Although the gage records on Martin River only go back 1 year, a synthetic flow was created by establishing a relationship between stage heights on the Martin River and the Upper Bradley River near Nuka Glacier. The Upper Bradley River at Nuka Glacier USGS gage has a 40-year record, and the Nuka and Dixon glaciers are adjacent and at similar elevations, which allows a fair comparison of discharge in the two basins. 11 Figure 6: Synthetic 40 year annual runoff volume (acre-ft) from Dixon Glacier A 10 year average of synthetic flow was used to estimate discharge from the Dixon glacier. This was done to capture the increase in flows from recent years due to higher summer temperatures resulting in an increased contribution of flow from ice melt. It was also assumed that the first 100 cfs of flow would always go downstream to account for future minimum instream flow stipulations. The Dixon Diversion Tunnel will be 14 feet in diameter and has a modeled capacity of 1,400 cfs, so any flood flows in excess of 1,400 cfs were assumed to go downstream on the Martin River rather than divert to Bradley Lake and would not contribute to the energy numbers for the project. Using the 10-year synthetic flow record, 238,500 acre-ft of runoff is predicted annually from the Martin River from rainfall, snow melt, and glacier melt. A majority of this flow will occur in July and August. The minimum instream flow (MIF) will account for 32,100 acre-ft, or 13% of the total runoff. Flood flows will account for 22,200 acre-ft or 10% of the total runoff, leaving 182,800 acre-ft diverted to Bradley Lake. At the Bradley Lake hydroelectric project, the efficiency of the generators gives a conversion of acre-ft to MWh of almost exactly 1:1 (ranges from 0.95-1.05). For modeling purposes, it is assumed a 1:1 ratio and 182,800 acre-ft of diverted water will account for an additional 182,800 MWh of renewable energy generation. The proposed 14-foot dam raise would increase the capacity of Bradley Lake and raise lake levels which would in turn raise head pressure at the Bradley Lake hydroelectric plant. The increased head pressure will increase efficiency of the two 60 MW generators and account for ~8,000 MWh of electric generation annually. Combining the values of 10-year average annual diverted water with the increased head pressure from a higher reservoir gives an average annual increase in energy from the Dixon Diversion project of 190,800 MWh. EPA’s 2022 eGRID data was used to estimate the greenhouse gas reductions that will result from the Dixon Diversion project. Generation data from the Alaska Railbelt is represented by the AKGD – ASCC Alaska Grid Subregion. As mentioned earlier, electricity produced on the Railbelt is primarily through natural gas fired generators. The eGRID nonbaseload rates will give an accurate representation of CO2e 12 reductions for projects that displace electricity generation. The eGRID factors consider the differences in baseload generation vs peaking generation, and for the Railbelt eGRID subregion the annual CO2e non- baseload output emission rate is 1,232.508 lb/MWh. Multiplying the AKGD non-baseload output emission rate with the expected energy production from Dixon and converting to metric tons produces a result of 106,668 MTCO2e annual reduction in greenhouse gas produced in Alaska. 3. Environmental Results – Outputs, Outcomes, Performance Measures (30 points) a. Expected Outputs and Outcomes (10 points) The Dixon Diversion is a significant expansion of the existing Bradley Lake hydroelectric project. Building off existing renewable energy infrastructure, AEA will achieve significant greenhouse gas reductions from a relatively small footprint. Specific outputs from the Dixon Diversion project include: Diversion dam and intake structure near the toe of Dixon Glacier, 4.7 mile long 14 foot diameter tunnel to convey water from the Dixon Glacier into Bradley Lake, 1 mile of new access road leading to the tunnel outlet, modifications to the existing Bradley Lake dam to raise reservoir level by 14 feet, and new 3-phase power and conduit running from the existing hydroelectric generating facility to the new diversion dam. The expected outcomes of the Dixon Diversion project are: 1. 190,800 MWh of annual renewable energy generation, 2. A reduction in annual CO2e emissions of 106,668 MTCO2e, and 3. An offset of 1.5 billion cubic feet of natural gas used for electric generation by Railbelt utilities. This project is the largest renewable energy project in Alaska in over 40 years. Not only will Dixon offset a significant amount of greenhouse gas emissions, it will provide electric utilities operational flexibility since storage hydro can be used at any time during the year. Additionally, Dixon helps the State of Alaska in addressing its impending natural gas supply shortage. All the clean electricity produced by this project will directly offset significantly more expensive electricity that will be produced using imported LNG in the coming years. b. Performance Measures and Plan (10 points) The Bradley Lake hydroelectric project is governed by the Bradley Lake Project Management Committee (BPMC) which oversees the planning, execution, and monitoring of the Bradley Lake Project. This committee meets monthly and is responsible for coordinating, budgeting, scheduling, resource allocation, risk management, and stakeholder communication. The BPMC was established following commissioning of the original hydroelectric project in 1982 and consists of AEA and the five Railbelt utilities that purchase power from Bradley Lake. The five utilities are Chugach Electric Association, Golden Valley Electric Association, Homer Electric Association, Matanuska Electric Association, and the City of Seward. The Bradley Lake Power Sales Agreement (PSA) defines the terms and conditions in which power generated from Bradley is sold and allocated. The PSA outlines in specific terms that AEA sells, and utilities subsequently purchase their percentage share of the project capacity. Each utility submits a Water Year energy budget of expected monthly usage (MWh). Predicted vs Actual inflows to the 13 reservoir are closely monitored and the Bradley Lake operations committee, containing representatives from each utility, are frequently adjusting energy usage from the project to reflect present-day reservoir conditions. The coordination of five electric utilities utilizing Bradley Lake for power necessitates the accurate and reliable tracking of lake inflows and power generation. Additional power produced from the Dixon Diversion project would be assumed to be allocated according to the current ownership breakdown. This system is fair and reliable and has produced an equitable distribution of energy offtake for over 40 years. Future performance measuring and tracking for the Dixon Diversion project would be an AEA responsibility carried out by the BPMC through the Bradley Lake Water Tracking Spreadsheet. Gauges will be installed at the Dixon diversion dam to accurately measure the exact contribution of inflows into Bradley Lake from the Dixon Glacier. Additional energy contributions resulting from the dam raise and higher head pressures can easily be calculated by increased generator efficiency calculations. In addition to accurate water tracking, the energy produced by the two 60MW turbines at the Bradley Lake hydroelectric plant is closely metered. The Bradley Lake project monitors and tracks all power distributed from the plant and that data is reported to the BPMC. Total energy output from the Dixon Diversion project will be converted into avoided CO2e emissions offset through EPA’s 2022 eGRID conversion factors for the AKGD subregion non-baseload generation. AEA will use the most recent version of this dataset in future years as that data becomes available. c. Authorities, Implementation Timeline, and Milestones (10 points) AEA owns the existing Bradley Lake hydroelectric project and will be wholly responsible for managing the Dixon Diversion project and all required reporting to the DOE. AEA will coordinate closely with the members of the BPMC as well as the operations team at Bradley in order for all current and future stakeholders to be well informed of project activities and progress. AEA is under contract with an engineering firm and an environmental firm to complete preliminary engineering and design work and perform the required environmental studies in preparation for a FERC license amendment. AEA is also closely working and consulting with state and federal resource agencies such as Alaska Department of Fish and Game, United States Fish and Wildlife Service, and the Kenai National Wildlife Refuge to gather feedback and input into AEA’s study plans. This ensures that the baseline environmental conditions of the project are fully understood as the project progresses. AEA will contract with an engineering firm to complete the final design but is also evaluating alternative contract procurement options to expedite project completion such as: Early Contractor Involvement (ECI), Construction Manager at Risk (CMAR), Construction Manager General Contractor (CMGC), or Progressive Design Build (PDB). A conceptual project schedule is provided below for FERC licensing, engineering, and construction of the Dixon Diversion. Use of alternative contract procurement could expedite the schedule. The conceptual project schedule considered which project components would need to be completed during the spring, 14 summer, and fall season. Some components, such as procurement and tunneling could be completed year-round. 15 Figure 7: Conceptual Project Schedule The above schedule outlines major project milestones and tasks along with estimated durations and completion dates. Construction is anticipated to last about 3 seasons, with additional context provided below: Season 1: - Project procurement and Notice to Proceed would occur in prior fall season, allowing contractor the winter season to plan, as well as full first season of construction - Procurement of long lead time components, such as Tunnel Boring Machine (TBM), electrical equipment for the high-voltage system, dam spillway gates, and intake gates at Dixon - First season of construction would concentrate on installation of the electrical conduits from Bradley Station to Bradley Lake, as well as the access to the downstream portal and portal development. There would be bidding and schedule efficiencies gained if the powerline could be completed in advance of season 1. - Development and commissioning of workforce housing. - Initial construction of the Dixon diversion dam and the upstream portal could be developed in the first season but could be delayed until the second season without any delay to the commissioning to the project as it is not a critical path milestone. Access to the upstream portal and diversion dam would be by helicopter until tunnel boring operations are complete. - Improvements associated with raising Bradley Dam could occur during any of the summer seasons and is not a critical path item; however, the project will see immediate gains in reservoir capacity once this milestone is achieved. Season 2: - Development of the downstream started tunnel would take place early in the second year of construction. - TBM tunneling operations would begin in Season 2 and are foreseen as running through the winter season, operating from the three-phase line power installed in the first season. Season 3: - Completion of the TBM operation, dismantling and removal of the TBM, and steel lining of fault sections within tunnel. - Once the tunnel is completed through the upstream portal, the inlet structure and associated mechanical work can be completed. At this point, it may be possible for diversion access to be through the completed tunnel and eliminate the need for helicopter access. The contractor 16 would need to consider how the timing of these activities might delay the commissioning of the project. - Electrical work within the tunnel to bring power and communication to the diversion structure. - Completion, testing, and commissioning of the project. 4. Low-income and Disadvantaged Communities (35 points) a. Community Benefit (25 points) In 2021, Alaska ranked first among U.S states with a per capita energy expenditure of $8,711, amounting to nearly 11.15% of its GDP. This ranking has remained consistent since 2015 1. The Dixon Diversion project will result in lower energy costs over the long-term and provide resiliency benefits to all customers of the Railbelt – a 700-mile-long stretch of Alaska that serves as the State's economic backbone and is home to approximately three quarters of the state’s population. With anticipated increases in natural gas prices of >50% within the next 10 years, the addition of low-cost, reliable, year- round power from storage hydro projects such as Dixon becomes even more critical. The Dixon Diversion project enhances Alaska’s energy security by increasing renewable penetration and grid stability, improving resilience to fuel price fluctuations and supply side disruptions, and providing stored energy to regulate other intermittent renewable energy resources. The Railbelt region includes 20 census tracts that are considered disadvantaged with a population of 62,348 and 17 Alaska Native Village Statistical Areas (ANVSA) with a combined population of 160,082 resulting in a total disadvantaged population of 22.430, or 39.6% of the population on the Railbelt 2. These communities will receive direct benefits from the Dixon Diversion project via lower cost energy generation and improved public health benefits from reduced carbon emissions. Alaska has the third highest per capita energy- related CO2 emissions in the United States 3. Importantly, the benefits of federal investment in the Railbelt are not limited to those directly connected to the Railbelt grid. AEA manages the Power Cost Equalization (PCE) program, which extends the financial benefits of lower Railbelt electric rates to positively impact over 81,000 residents in 188 remote communities statewide4; these rural communities not connected to the Railbelt’s electric network will directly benefit from reduced Railbelt rates resulting from utility scale renewable projects such as Dixon. Almost all these remote communities are disadvantaged with extremely high electricity costs; PCE reduces costs in these communities based on a statutory formula tied to Railbelt rates. Using the statutory PCE credit formula, a one-cent reduction in residential electric rates on the Railbelt results in an increased credit to PCE communities estimated to be $1.4 million based on historical usage. This innovative, built-in transfer mechanism demonstrates Alaska’s prioritization of equitable benefits sharing 1 https://www.eia.gov/state/seds/data.php?incfile=/state/seds/sep_sum/html/rank_pr.html&sid=US 2 https://live.laborstats.alaska.gov/data-pages/alaska-population-estimates 3 https://view.officeapps.live.com/op/view.aspx?src=https%3A%2F%2Fwww.eia.gov%2Fenvironment%2Femissions%2Fstate%2Fexcel%2Ftable4. xlsx&wdOrigin=BROWSELINK 4 https://www.akenergyauthority.org/Portals/0/Power%20Cost%20Equalization/2024.02.26%20FY23%20PCE%20Statistical%20Report%20by%20 Community%20(Final%20Optimzed).pdf?ver=om4p4ZK_A-xwHiFPOHfvDQ%3d%3d 17 and provides a time-tested means to ensure benefits realized by Railbelt consumers extend to Justice40 communities statewide. Over 40% of the benefits of this project will impact low-income and disadvantaged communities by lowering the cost of energy, improving health outcomes, and increasing energy resiliency. In addition, with the project expected to lower energy costs over the long-term, the potential for creating induced jobs exists but is not measurable now. AEA does not anticipate negative effects on these communities from this project; it uses a small footprint that is remotely located, away-from almost all communities and is not expected to adversely impact fish habitat. AEA will solicit feedback from communities to identify any other potential negative impacts. b. Community Engagement (10 points) AEA’s mission is to reduce the cost of energy in Alaska; and, the Dixon Diversion project delivers on that mission, as well as provides positive environmental and public health benefits. AEA has already conducted several public outreach meetings in accordance with FERC relicensing processes related to the Dixon Diversion project and plans to implement a broader community outreach and engagement program to increase knowledge about the benefits of the project and provide additional opportunities for public input. AEA will partner with local and Tribal governments, community organizations, and utilities to foster meaningful public involvement and provide public outreach. AEA hosted Joint Agency and public meetings to review the Dixon Diversion project and Proposed Study Plans on May 27, 2022, March 5, 2024, and March 19, 2024. These meetings were posted on AEA’s public facing website, listed on the State of Alaska’s public meeting notice board, and distributed to the project’s email distribution list which includes Tribal Entities, state resource agencies, and various other project stakeholders. AEA plans to conduct additional joint public and agency meetings as the project progresses and develops. These include a 2024 Field season debrief meeting in December 2024, a 2025 pre-Field Season meeting in April 2025, a 2025 Field Season Debrief Meeting in December 2025, and 2-3 public meetings to solicit comments on the Draft Amendment Application submitted to FERC in 2026. Communication with the public will flow both ways, and outreach will occur at recurring events and in stand-alone community meetings. The community outreach and engagement program will include: public meetings, both in person and virtual; social media posts; updates on AEA’s website; participation by AEA in recurring events, such as, Alaska Municipal League Office Hours, Tribal Council meetings, City Council meetings, and Chamber of Commerce lunches; and, participation in more informal settings, such as the Alaska Federation of Natives Convention, Alaska Black Caucus Sunday night Zoom meetings, Alaska State Fair, Alaska Federation of Filipino Americans programming, and energy and environmental conferences held throughout the state. During 2023, AEA staff members participated in dozens of different events throughout the state providing information at exhibitor booths, participating in panel discussion, and presenting on AEA’s ongoing projects. 18 Furthermore, the Dixon Diversion project and its benefits align with another AEA project, the Railbelt Innovation Resiliency Project, which was awarded a grant through the Department of Energy’s Grid Resilience and Innovative Partnership Program. Assuming the Dixon Diversion project is funded, similar timelines for these two projects create a synergistic opportunity for community engagement. 5. Job Quality (5 points) AEA expects new jobs to be created during the project's construction, which will be bid out. AEA is committed to fostering safe, healthy, and inclusive workplaces with equal opportunity, free from harassment and discrimination. Implementing projects that contribute to reducing GHG emissions will consider Good Jobs Principles. Work performed with this funding will be done in compliance with Alaska public contracting law, which contains provisions for local hire, apprenticeship training, prevailing wages and other forward-looking policies. Bidding and contract documents include specific provisions to implement equity-focused policies related to all phases of contracting and construction. The contract provisions address nondiscrimination, equal employment opportunity, reasonable accommodations for employees with disabilities, and non-segregation of facilities. 6. Programmatic Capability and Past Performance (30 points) a. Past Performance (10 points) AEA has mature staff and management systems in place to administer awards. AEA has a full suite of qualified individuals and a system of checks and balances. AEA’s Finance and Accounting departments manage the fiscal compliance and reporting requirements for grants and sub-awards. Additionally, AEA staffs a grants department that includes a grants manager and a grant coordinator. Internal control procedures are in place for compliance reviews, budgetary controls, invoice approvals, periodic project status and financial reporting. AEA hires an independent audit firm to report on compliance for each major federal program, report on internal control over compliance, and report on the Schedule of Expenditures of Federal Awards required by the Uniform Guidance. AEA’s FY2023 Single Audit Report found that the Alaska Energy Authority complied, in all material respects, with the compliance requirements referred to above that could have a direct and material effect on each of its major federal programs for the year ended June 30, 2023. AEA policies and procedures are published on our website, including for Procurement, Governance, Annual Reports, and Audits. The wide array of current and past programs, and grant management experience, ensures that AEA is appropriately prepared to manage this project, including through a subaward and project delivery and assessment process the following is a small sample of the many awards AEA manages from federal agencies: Department of Energy (DOE) Project Title: Preventing Outages and Enhancing the Resilience of the Electric Grid Formula Grant to States Assistance Agreement No.: DE-GD0000002 CFDA: 81.254 19 Description: This project is in direct support of Section 40101(d) of the Infrastructure Investment and Jobs Act (i.e., Bipartisan Infrastructure Law (BIL)). The objective of this project is to improve the resilience of the electric grid against disruptive events. Per BIL Section 40101(a)(1), a disruptive event is an event in which operations of the electric grid are disrupted, preventively shut off, or cannot operate safely due to extreme weather, wildfire, or a natural disaster. Contact: Lucas Greza, Lucas.Greza@netl.doe.gov, (304)285-4663 Denali Commission (DC) Project Title: 2019 Nikolai Rural Power System Upgrades Assistance Agreement No.: 01574-00 CFDA No.: 90.100 Description: Design a new power plant in Nikolai, Alaska. Contact: Katie Conway, kconway@denali.gov (907) 341-9617 United States Department of Agriculture (USDA) Project Title: Sustainable Wood Energy Systems Assistance Agreement No.: 19 DG –11100106-811 CFDA: 10.674 Description: Technical assistance aimed at helping communities displace fossil fuels and reduce heating costs through assessing, developing, and maintaining biomass heating and biomass combined heat and power projects in Alaska. Contact: Priscilla Morris, Priscilla.morris@usda.gov (907) 743-9467 U.S. Department of Defense (DOD) Project Title: 2022 Black Rapids Training Center Line Extension Assistance Agreement No.: DOD-HQ00052210045 CFDA: 12.600 (contract 31201) Description: A 34-mile electrical power line extension to connect the Black Rapids military installation to supply safe, reliable, and efficient grid power. Contact: Tim Robert timothy.b.robert.civ@mail.mil, (916) 557-7315 Environmental Protection Agency (EPA) Project Title: 2016-2022 State Clean Diesel Emission Reduction Act Assistance Agreement No.: DS-01J63901 CFDA: 66.040 Description: Partially fund the replacement of up to twenty-five non-certified and lower tier diesel engines with Tier 2 and 3 marine engines and low PM emitting nonroad engines based on a community prioritization list. Contact: Lucita Valiere, valiere.lucita@epa.gov (206) 553-8087 In addition to the sample of Federal awards listed above, AEA completed the West Fork Upper Battle Creek Diversion Project in 2020. This project was very similar in nature to the proposed Dixon Diversion project, as it was an expansion of the existing Bradley Lake Hydroelectric Project to divert water from an adjacent glacial basin into the Bradley Lake Reservoir. AEA successfully worked with state resource agencies pre and post project to quantify fish use and habitat in Battle Creek and develop minimum instream flows that have so far proven to increase fish use in Lower Battle Creek. AEA has a track record 20 from the Battle Creek project of efficiently working with FERC throughout the license amendment process, as well as managing construction contractors in a remote location to complete a large-scale project on time and on budget. b. Reporting Requirements (10 points) Department of Energy (DOE) - Project Title: Preventing Outages and Enhancing the Resilience of the Electric Grid Formula Grant to States DOE requires submission of a project management plan within 90 days of award date and quarterly progress reports during the period of performance. DOE also requires that all projects under this grant adhere to BABA and Davis-Bacon requirements. AEA has met all required outcomes to date. Denali Commission (DC) - Project Title: 2019 Nikolai RPSU All progress and financial reporting requirements for this project have been met. The final close out report will be submitted in June 2024. United States Department of Agriculture (USDA) - Project Title: Sustainable Wood Energy Systems AEA submitted quarterly progress and financial reports throughout the duration of this grant. U.S. Department of Defense (DOD) - Project Title: 2022 Black Rapids Training Center Line Extension AEA has worked cooperatively with the owner agency, Office of Liaison Defense Community Cooperation (OLDCC), and Golden Valley Electric Association (GVEA) to review the conflicts and keep the agency appraised of the revised schedule. AEA submits progress and financial reports through the OLDCC project portal. Environmental Protection Agency (EPA) - Project Title: 2016-2022 State Clean Diesel Emission Reduction Act In 2015 AEA received the DERA funds via Reimbursable Services Agreement from Department of Environmental Conservation (DEC) and reported through DEC. Starting in 2016, AEA’s relationship was directly with the EPA. AEA’s quarterly reporting, both financial and progress reports have always been on time. AEA conducted several site monitors, which have resulted in no findings. For this program, AEA submits a final technical report at the end of each award. c. Staff Expertise (10 points) AEA is an independent and public corporation of the State of Alaska, est. 1976. AEA is governed by a board of directors with the mission to “reduce the cost of energy in Alaska.” AEA is the State Energy Office and lead agency for statewide energy policy and program development. Whether building modern and code-compliant bulk fuel tank farms, upgrading to high- efficiency generators in rural powerhouse systems or integrating renewable energy projects, AEA emphasizes community-based project management. AEA’s core programs work to diversify Alaska’s energy portfolio, lead energy planning and policy, invest in Alaska’s energy infrastructure and provide rural Alaska with technical and community assistance. 21 AEA has over 25 professionals on staff, including engineers, planners, project developers, project managers, accountants and finance officers, and policy analysts. As the state’s designated energy office, AEA has managed hundreds of millions of dollars in federal, state, and private funds to plan and build infrastructure in urban and rural Alaska. AEA’s building is located conveniently in Anchorage with adequate technology, spacing, and facilitation equipment. AEA has capabilities for video conferencing, hosting meetings, and a team for procuring services and materials. Collectively, AEA staff have worked with nearly every community in the state to deliver critical supply and demand energy services. Likewise, AEA staff are networked to the vast array of Alaska energy stakeholders from small rural non-profits and utilities to large regional Alaska Native Corporations and tribal organizations, and from conservation organizations to technology- or solution-oriented working groups. AEA’s capacity to conceptualize, implement, and successfully complete supply and demand energy projects through an outcomes-focused process positions the agency well to lead a coordinated joint team that will overcome barriers to implement the Whitter Shore Power project. AEA has the experience, expertise, equipment, and staff ready to achieve the project objectives set out in this application. AEA has a whole team of staff specifically designated for grants, compliance, procurement, contracting, and finance. Each of these teams has adequate resources to ensure the project is on budget and on schedule. AEA is engaged in all levels of consumer energy including project and resource identification, design and permitting, and financing and construction. Over decades of experience developing energy projects in Alaska, AEA has continuously improved on process, application of technology and delivery of service. AEA integrates energy technology and advances in grid services into all program areas both on the supply- and demand-side. AEA, as owner of significant generation and transmission assets in the Railbelt region of Alaska, and in furtherance of its mission to reduce the cost of energy in the State, plays an important role in ensuring that sound public policy and energy planning initiatives within the region maximize the potential benefits to the broadest group of stakeholders. Without a specific certificated area, and as owners of assets which cross multiple jurisdictional boundaries, AEA is uniquely positioned to facilitate discussions amongst stakeholder groups and find solutions for the region in its entirety. AEA does so through its leadership role on the management committees associated with its assets. AEA also manages the Renewable Energy Fund, the Emerging Energy Technology Fund, the Power Cost Equalization Program and various Energy Efficiency and Conservation Programs. AEA provides grants and loans for qualified energy infrastructure projects and owns energy infrastructure for the benefit of Alaskans. AEA has the legal authority to enter into a financial assistance relationship with U.S. Department of Energy as discussed in this application. Additionally, as a state agency, AEA produces an annual report to the Governor, yearly federal single audit, and financial statements. The Alaska Energy Authority (AEA) has mature staff and management systems in place to administer this award. Per the organizational chart, we have a full suite of highly qualified individuals and a system of 22 checks and balances in place. AEA’s financial and project management capabilities are demonstrated in our yearly audit and financial report, located on our website. https://www.akenergyauthority.org/Who- We-Are/Newsroom/Publications-and-Resources AEA has successfully managed, completed and closed well over 300 grants in the last decade from many different agencies as well as private funds from the Volkswagen Settlement and Wells Fargo. 7. Budget (45 points) Total funding request for the Dixon Diversion project is $348,415,151. Detailed Budget Narrative and Budget Spreadsheet are included as an attachment to this application. Budget Attachments: - Budget_AlaskaEnergyAuthority.pdf - Budgetcalcs_AlaskaEnergyAuthority.xlsx Technical Appendix – Dixon Diversion a. Magnitude of GHG Reductions from 2025-2030 (20 points) The Dixon Diversion project is scheduled to be completed and commissioned by early 2030. This will capture a full water year in 2030 and associated greenhouse gas reductions from that water. In these systems water typically starts flowing in late April / early May. A minimum instream flow (MIF) will be established through the FERC licensing process, and once flows exceed the MIF, excess water will be diverted through the Dison Diversion tunnel into Bradley Lake. The water year typically ends in late October / early November once temperatures consistently drop below freezing and there is not enough flow to divert water anymore. The project is expected to be commissioned before spring break-up so the magnitude of greenhouse gas reductions from 2025-2030 would be equivalent to the energy produced from a full water year. Based on synthetic flows of the Martin River averaged over the previous decade, accounting for expected minimum instream flow requirements and the capacity of the 14-foot diameter diversion tunnel, the Dixon Diversion project will produce 190,800 MWh of electricity annually. EPA’s 2022 eGRID conversion factor for the Alaska Railbelt (AKGD – ASCC Alaska Grid subregion) nonbaseload rates gives an accurate estimation of CO2e reductions for projects that displace electricity generation. For the Railbelt the eGRID subregion annual CO2e non-baseload output emission rate is 1,232.508 lb/MWh. 190,800 𝑀𝑀𝑀𝑀ℎ× 1,232.508 𝑙𝑙𝑙𝑙 𝐶𝐶𝐶𝐶2𝑒𝑒𝑀𝑀𝑀𝑀ℎ×  1 𝑀𝑀𝑀𝑀2204.62 𝑙𝑙𝑙𝑙=106,668 𝑀𝑀𝑀𝑀 𝐶𝐶𝐶𝐶2𝑒𝑒 Magnitude of GHG Reductions from 2025-2030 = 106,668 MTCO2e b. Magnitude of GHG Reductions from 2025-2050 (10 points) To estimate the magnitude of GHG Reductions from 2025-2050, the same annual energy output from Dixon will be used over a 25-year period. It is likely that the energy numbers over this period could be even higher, due to an observable trend of higher flows in recent years due to warmer summers melting the source glaciers at a faster rate. 106,668 𝑀𝑀𝑀𝑀𝐶𝐶𝐶𝐶2𝑒𝑒 × 25 𝑦𝑦𝑒𝑒𝑦𝑦𝑦𝑦𝑦𝑦 = 2,666,701 𝑀𝑀𝑀𝑀𝐶𝐶𝐶𝐶2𝑒𝑒 c. Documentation of GHG Reduction Assumptions (15 points) Annual greenhouse gas reductions resulting from the Dixon Diversion project are calculated from offsets of expected energy production from the hydroelectric project. To develop estimations of energy produced from the Dixon Diversion project, it is critical to accurately measure the discharge of the Martin River. The Martin River, which comes off the Dixon Glacier, is a fast moving, cold, and highly turbid river. Upon exiting the glacier, the Martin River quickly enters a canyon characterized by a series of waterfalls and deep canyon walls. Upon exiting the canyon, the river becomes highly braided and remains that way until the reaching tidewater. Due to its remote nature, highly mobile bed load, and lack of defined channel, the Martin River is a challenge to accurately measure. In the summer of 2023, there was a large field effort to characterize the Martin River. The United States Geological Survey (USGS) installed and operates a stage gage on the Martin River around where it first exits the canyon (USGS 15238951). AEA hired a contractor to install additional stream gages on the Martin River, with the primary gage located at the “Constriction”. The contractor performed 10 site visits between April and September to gather discharge measurements. These measurements were used to build a stage-discharge relationship for both gage locations, and from there the daily flow could be estimated over the summer. A hydrograph was created for the summer 2023 season using a combination of the two established gage sites on the Martin River. Figure 5: Hydrograph of discharge on Martin River, 2023 Water Year Although the gage records on Martin River only go back 1 year, a synthetic flow was created by establishing a relationship between stage heights on the Martin River and the Upper Bradley River near Nuka Glacier. The Upper Bradley River at Nuka Glacier USGS gage has a 40-year record, and the Nuka and Dixon glaciers are adjacent and at similar elevations, which allows a fair comparison of discharge in the two basins. Figure 6: Synthetic 40 year annual runoff volume (acre-ft) from Dixon Glacier A 10 year average of synthetic flow was used to estimate discharge from the Dixon glacier. This was done to capture the increase in flows from recent years due to higher summer temperatures resulting in an increased contribution of flow from ice melt. It was also assumed that the first 100 cfs of flow would always go downstream to account for future minimum instream flow stipulations. The Dixon Diversion Tunnel will be 14 feet in diameter and has a modeled capacity of 1,400 cfs, so any flood flows in excess of 1,400 cfs were assumed to go downstream on the Martin River rather than divert to Bradley Lake and would not contribute to the energy numbers for the project. Using the 10-year synthetic flow record, 238,500 acre-ft of runoff is predicted annually from the Martin River from rainfall, snow melt, and glacier melt. A majority of this flow will occur in July and August. The minimum instream flow (MIF) will account for 32,100 acre-ft, or 13% of the total runoff. Flood flows will account for 22,200 acre-ft or 10% of the total runoff, leaving 182,800 acre-ft diverted to Bradley Lake. At the Bradley Lake hydroelectric project, the efficiency of the generators gives a conversion of acre-ft to MWh of almost exactly 1:1 (ranges from 0.95-1.05). For modeling purposes, it is assumed a 1:1 ratio and 182,800 acre-ft of diverted water will account for an additional 182,800 MWh of renewable energy generation. The proposed 14-foot dam raise would increase the capacity of Bradley Lake and raise lake levels which would in turn raise head pressure at the Bradley Lake hydroelectric plant. The increased head pressure will increase efficiency of the two 60 MW generators and account for ~8,000 MWh of electric generation annually. Combining the values of 10-year average annual diverted water with the increased head pressure from a higher reservoir gives an average annual increase in energy from the Dixon Diversion project of 190,800 MWh. EPA’s 2022 eGRID data was used to estimate the greenhouse gas reductions that will result from the Dixon Diversion project. Generation data from the Alaska Railbelt is represented by the AKGD – ASCC Alaska Grid Subregion. As mentioned earlier, electricity produced on the Railbelt is primarily through natural gas fired generators. The eGRID nonbaseload rates will give an accurate representation of CO2e reductions for projects that displace electricity generation. The eGRID factors consider the differences in baseload generation vs peaking generation, and for the Railbelt eGRID subregion the annual CO2e non- baseload output emission rate is 1,232.508 lb/MWh. Multiplying the AKGD non-baseload output emission rate with the expected energy production from Dixon and converting to metric tons produces a result of 106,668 MTCO2e annual reduction in greenhouse gas produced in Alaska. SECTION A - BUDGET SUMMARY $ BUDGET INFORMATION - Non-Construction Programs OMB Number: 4040-0006 Expiration Date: 02/28/2025 Grant Program Function or Activity (a) Catalog of Federal Domestic Assistance Number (b) Estimated Unobligated Funds New or Revised Budget Federal (c) Non-Federal (d) Federal (e) Non-Federal (f) Total (g) 5. Totals 4. 3. 2. 1.$$$$ $$$$ Climate Pollution Reduction Grant 66.046 348,415,151.00 348,415,151.00 348,415,151.00 348,415,151.00$ Standard Form 424A (Rev. 7- 97) Prescribed by OMB (Circular A -102) Page 1 SECTION B - BUDGET CATEGORIES 7. Program Income d. Equipment e. Supplies f. Contractual g. Construction h. Other j. Indirect Charges k. TOTALS (sum of 6i and 6j) i. Total Direct Charges (sum of 6a-6h) (1) Authorized for Local Reproduction Prescribed by OMB (Circular A -102) Page 1A Standard Form 424A (Rev. 7- 97) GRANT PROGRAM, FUNCTION OR ACTIVITY (2) (3) (4) (5) Total6. Object Class Categories a. Personnel b. Fringe Benefits c. Travel Climate Pollution Reduction Grant 3,010,185.00 1,492,121.00 245,360.00 80,000.00 200,000.00 304,920,588.00 36,890,571.00 346,838,825.00 1,576,326.00 348,415,151.00 3,010,185.00 1,492,121.00 245,360.00 80,000.00 200,000.00 304,920,588.00 36,890,571.00 346,838,825.00 1,576,326.00 348,415,151.00 $$$$$ $$$$$ $$$$$ $ $ SECTION D - FORECASTED CASH NEEDS 14. Non-Federal SECTION C - NON-FEDERAL RESOURCES (a) Grant Program (b) Applicant (d) Other Sources(c) State (e)TOTALS $ $ $$$ $ $ $ $ $8. 9. 10. 11. 12. TOTAL (sum of lines 8-11) 15. TOTAL (sum of lines 13 and 14) 13. Federal Total for 1st Year 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter Climate Pollution Reduction Grant 12,377,338.00 12,377,338.00 1,902,105.00 1,902,105.00 4,326,544.00 4,326,544.00 4,326,544.00 4,326,544.00 1,822,145.00 1,822,145.00 $$ $$$ $$$$ FUTURE FUNDING PERIODS (YEARS) SECTION F - OTHER BUDGET INFORMATION SECTION E - BUDGET ESTIMATES OF FEDERAL FUNDS NEEDED FOR BALANCE OF THE PROJECT Authorized for Local Reproduction $ $ $$ $ $16. 17. 18. 19. 20. TOTAL (sum of lines 16 - 19) 21. Direct Charges: 22. Indirect Charges: 23. Remarks: (a) Grant Program (b)First (c) Second (d) Third (e) Fourth Climate Pollution Reduction Grant 14,841,181.00 111,916,104.00 152,585,037.00 56,695,491.00 14,841,181.00 111,916,104.00 152,585,037.00 56,695,491.00 $1,576,326$346,838,825 AEA negotiating NICRA for FY24, provisional indirect rate of 31.86% $$ Standard Form 424A (Rev. 7- 97) Prescribed by OMB (Circular A -102) Page 2 813 West Northern Lights Boulevard, Anchorage, Alaska 99503 T 907.771.3000 Toll Free 888.300.8534 F 907.771.3044 Page 1 of 2 March 18, 2024 Alaska Energy Authority 813 W. Northern Lights Blvd Anchorage, AK 99503 RE: EPA-R-OAR-CPRGI-23-07: Alaska Energy Authority, Individual Application – Dixon Diversion Project Administrator Regan, The Bradley Lake Management Committee (BPMC) is writing in support of an application submitted by the Alaska Energy Authority (AEA) for funding the Climate Pollution Reduction Grants (CPRG) Implementation General Competition for the Dixon Diversion Project (the “Project”). The Project is a significant and transformative expansion of the existing Bradley Lake Hydroelectric Project (Bradley Lake), a 120-megawatt facility owned by AEA and managed by the BPMC that generates about 10 percent of the total annual power used by Railbelt electric utilities serving 550,000 Alaskans at some of the lowest cost energy in Alaska. The BPMC is comprised of representatives from AEA and the five electric utilities that serve the Railbelt and purchase power from Bradley Lake through an established Power Sales Agreement. By utilizing existing energy infrastructure, the Project allows for a significant renewable resource to be developed on an extremely small footprint and represents the largest renewable energy project in Alaska in the last 30 years. The Project would leverage the existing assets at Bradley Lake to generate an additional 190,800 megawatt-hours per year, increasing Bradley Lake's annual average energy output by almost 50%, and offsetting approximately 106,668 MTCO2e of emissions annually. This additional hydroelectric generation would displace 1.5 billion cubic feet of Cook Inlet natural gas, or approximately 7.5% of the unmet natural gas demand for Alaska's Railbelt region in 2030. Cook Inlet natural gas supply shortages are anticipated to occur within the next three years, placing upward supply-side pressure on natural gas prices, widening the gap between low-cost hydroelectric and natural-gas fired generation. The Project directly benefits the 75 percent of the state’s population connected to the grid and indirectly benefits Alaskans in 188 rural communities that are geographically isolated from the Railbelt but are eligible for Alaska’s rural electric subsidy Power Cost Equalization program. AEA has a proven record of accomplishment in managing projects of similar scope; AEA successfully completed the Battle Creek Diversion project, a similar expansion to Bradley Lake, in 2020. With its experience and expertise, the AEA is well-positioned to implement the Dixon Diversion project. 813 West Northern Lights Boulevard, Anchorage, Alaska 99503 T 907.771.3000 Toll Free 888.300.8534 F 907.771.3044 Page 2 of 2 The BPMC is committed to the success of the Dixon Diversion Project. With funding from the U.S. Environmental Protection Action, our ratepayers will benefit from more affordable energy and Alaskans will benefit from reduced greenhouse gas emissions. Respectfully, Bradley P. Janorschke BPMC Chair Alaska Energy Authority 813 W. Northern Lights Blvd Anchorage, AK 99503 March 26, 2024 Re: Climate Pollution Reduction Implementation Grant (CPRG) - Letter of Commitment for the Dixon Diversion project Executive Director Thayer, On behalf of the Alaska Municipal League, please accept this letter of commitment for an implementation grant application to the Environmental Protection Agency’s Climate Pollution Reduction Grant program by the Alaska Energy Association (AEA) for the transformative expansion of the existing AEA-owned Bradley Lake Hydroelectric project on the Kenai Peninsula of Alaska. This expansion would provide more than 190,800 MWh/year worth of low-cost hydropower to the Railbelt system that powers 70% of Alaska’s population. In drafting the state plan, we saw the role of the AEA as a key transformative partner in Alaska’s Priority CPRG Plan. Alaska Municipal League (AML) is excited to be a part of a potential generational opportunity for transformative impacts on the energy systems of disadvantaged, rural communities in Alaska. AML represents and works to support Alaska’s 165 municipal governments in addressing their challenges. In line with our Infrastructure program and long-term work with DEC on the State of Alaska’s CPRG PCAP, we intend to support AEA with planning support, community outreach, progress tracking, and energy data needs. AML will support the application with workforce development infrastructure which will consist of aiding applicants with recruitment, skill development, and career navigation. AML will work with the Alaska Department of Environmental Conservation (DEC) to establish a statewide tracking and reporting system for CPRG awardees to combine data in a singular database. The system will supplement sub-awardees with technical assistance provided by partners to encourage timely reporting, with methodology consistent with the State’s GHG emissions inventory. Lastly, AML will lead a statewide cohort of awardees to participate in CPRG planning and creation of a sustainability plan. We look forward to this program and AML strongly supports the AEA proposal. Should it be selected, we will partner to initiate long-term emission reduction, greater resiliency to disruptive events, and economic and environmental benefits in Alaska. Sincerely, Nils Andreassen Executive Director Alaska Municipal League COVER PAGE CPRG – PROPOSAL TO ADDRESS RURAL ALASKA’S CRITICAL ENERGY CHALLENGES APPLICANT INFORMATION Organization: Alaska Energy Authority (AEA) Primary Contact Name: Curtis W. Thayer, AEA Executive Director Phone Number: 907-771-3009 Email Address: cthayer@akenergyauthority.org TYPE OF APPLICATION: Lead Applicant for a Coalition; coalition members include the Tanana Chiefs Conference (TCC) and Northwest Arctic Borough (NAB) FUNDING REQUESTED: $49,986,112 APPLICATION TITLE: CPRG – Proposal to Address Rural Alaska’s Critical Energy Challenges BRIEF DESCRIPTION OF GHG MEASURES: AEA is spearheading a comprehensive measure proposal aimed at addressing critical energy challenges faced by rural communities in Alaska. This proposal encompasses the following components presented by AEA and its coalition partners: Diesel Genset Replacement, Distribution System Upgrades, Village Energy Efficiency Program (VEEP), NAB’s Power and Water Plant Upgrades, and TCC’s distribution and powerplant upgrades. AEA is committed to making substantial, long-term emissions reductions while simultaneously delivering numerous benefits to these remote communities. SECTORS: Electricity Generation EXPECTED TOTAL CUMULATIVE GHG EMISSION REDUCTIONS: Estimated cumulative GHG reductions for 2025 – 2030 (in metric tons) - 22,943 Estimated cumulative GHG reductions for 2025 – 2050 (in metric tons) - 146,846 LOCATIONS: The proposed measures will be implemented in numerous disadvantaged communities located throughout much of rural Alaska. APPLICABLE PRIORITY CLIMATE ACTION PLAN (PCAP) ON WHICH MEASURES ARE BASED: PCAP Lead Organization: Alaska Department of Environmental Conservation (DEC) PCAP Title: State of Alaska Priority Sustainable Energy Action Plan PCAP Website: CPRG - Alaska Federal Funding (akfederalfunding.org) List of GHG reduction measures and PCAP page reference for each measure: Replacement of low tier high-emitting diesel generators with more advanced Tier 2 and 3 marine engines that emit lower PM levels. Upgrade distribution systems throughout rural Alaska. These modifications will improve overall system efficiency by reducing line losses and diesel fuel usage within powerhouses. Expand upon the Village Energy Efficiency Program (VEEP) by upgrading public buildings and infrastructure with energy-efficient materials for high-energy cost communities. These measures are included in the “AEA DERA, VEEP, and Rural Distribution Programs” measure on page 47-49 of the PCAP. 1 WORKPLAN CPRG – PROPOSAL TO ADDRESS RURAL ALASKA’S CRITICAL ENERGY CHALLENGES 1. Overall Project Summary and Approach a. Description of GHG Reduction Measures The Alaska Energy Authority (AEA), the state’s energy office, submits this coalition application in partnership with Tanana Chiefs Conference (TCC) and the Northwest Arctic Borough (NAB) to address rural Alaska’s critical energy challenges and provide significant greenhouse gas (GHG) emissions reductions. AEA, as the lead applicant, will submit a Memorandum of Agreement signed by all coalition members by July 1, 2024. This grant application requests $49,986,112 and encompasses several measures that will result in decreased greenhouse gas (GHG) emissions across the State of Alaska. The State of Alaska has produced its Priority Sustainable Energy Action Plan (PSEAP) in accordance with the guidance of the Climate Pollution Reduction Grant (CPRG) program, and which satisfies the requirements of a Priority Climate Action Plan (PCAP). AEA, TCC and NAB propose funding for five distinct initiatives in this application related to a measure in Alaska’s PSEAP under the electric generation sector that will reduce GHG emissions through energy efficiency upgrades to public buildings and infrastructure, distribution system upgrades, and diesel engine efficiency. AEA proposes programs conceptually similar to its current and past activities under the Diesel Emissions Reductions Act program (DERA), the Village Energy Efficiency Program (VEEP), and rural distribution upgrades program. These activities are included in the “AEA DERA, VEEP, and Rural Distribution Programs” measure on page 47-49 of the PSEAP. In addition, this measure in the PSEAP provides for AEA to subaward to coalition members for similar activities including rural distribution upgrades, diesel power plant upgrades, and energy efficient improvements to public buildings and infrastructure to better serve the unique needs of each community. TCC proposes to implement a program for upgrades to the distribution lines and power plants in nine communities in the TCC Region. NAB proposes upgrades at power plants and water plants in communities to maximize alternative energy use. The measures proposed in this application enable greater access and deployment of affordable, reliable, and emissions-reducing generation. These measures were chosen as a priority as they have the most potential to result in tangible improvements for rural, disadvantaged communities, including reductions in GHG emissions and lower energy burdens, they are ready to begin implementing upon funding being made available, and they will have a transformative impact by enabling future renewable integrations allowing for a transition to a clean energy economy in rural Alaska. Addressing the issues with rural Alaska’s energy efficiency and resiliency is an on-going challenge. Compared to other states, Alaska contains many isolated non-road connected communities that must rely on islanded electrical grids. Approximately 30% of the state’s population resides in over 200 rural and tribal communities that rely on local and regional power generation. Typically, these community power plants have at least one diesel engine running continuously. Rural Alaskans rely on these engines for their prime power; however, many of these power plants are older and lack modern controls, emissions reducing technology, and operating efficiency is low. These islanded grids are owned and operated by approximately 100 utility operators, including cooperatives, tribal, and municipal entities. Many of these rural Alaska communities are only accessible by plane or marine vessel, with over half classified by the Denali Commission as distressed communities. In addition to the sub-standard diesel engine inventory, many of Alaska’s rural communities suffer from degraded electric distribution systems and infrastructure. These systems were built for a 30-year life but are now approaching 50+ years old, with aging poles and sagging lines that create a life and health safety risk and lower overall system efficiency through line losses. Many poles are installed in permafrost and 2 with on-going climate change and the melting of this permafrost, many poles are subject to significant shifting. AEA Project Description AEA is spearheading a comprehensive measure proposal aimed at addressing critical energy challenges faced by rural communities in Alaska. AEA requests $30,031,791 to fund three key initiatives, each of which are a vital piece to the state’s PSEAP: expansion of diesel engine and genset replacements, distribution system upgrades, and enhanced VEEP support. AEA, and the coalition members, are committed to making substantial, long-term emissions reductions while simultaneously delivering additional benefits to these remote communities. The federal DERA program provides formula-based funding based on population. DERA encompasses a variety of project types, ranging from replacing school buses to upgrading railroad engines. AEA, on behalf of the State of Alaska, exclusively utilizes DERA funds to replace prime power diesel engines in rural Alaska. These engines are typically located within the village and have a substantial impact on its air quality. In most rural Alaskan communities, the absence of a larger electric grid and road connections requires each community to generate electricity locally. Small diesel power plants are used for this purpose, creating isolated grids. The average rural power plant engines have about 90,000 hours or 10 years of run time, which is approaching the end of the typical operating life, meaning many are inefficient compared to newer models, resulting in increased fuel consumption and higher power costs. Installing newer, certified, and more efficient engines helps reduce emissions per unit of fuel and improves electricity generation efficiency. AEA's existing annual DERA work plan includes specific estimates for each community. With the money that would be awarded under this CPRG, AEA intends to issue sub- award grants in a DERA-like program to replace the oldest gensets and diesel engines in rural Alaska communities, enabling more engines to be replaced, and expanding the scope and reach of the EPA’s DERA program. Pictures of leaning poles and distribution lines in Oscarville 3 Given the complexities of working in rural Alaska, the limited construction season, and supply chain challenges, AEA typically sees a two-year cycle for these replacement projects. Due to the volume of the funds, we intend to distribute the sub-awards over the 5-year period allowed by the grant and provide three rounds of funding opportunities. The milestones involved with this measure are: 1) confirm each rural community has an eligible engine and prepare emission tables and budget; 2) procurement of contractors and design of the engine/generator installations and development of specifications specific to each installation; 3) construction procurement; 4) submittals by contractors to AEA; 5) installation and commissioning; and 6) final closeout of award. Additional details related to milestones are included in Section 3 of the application. The second initiative of the proposed measures is the upgrade of distribution systems in rural communities. The framework for this program will follow the process of AEA’s existing Rural Power System Upgrade (RPSU) Program. AEA will issue sub-award grants to communities determined to be of the highest priority. AEA is currently working on a distribution inventory and assessment to rank the highest need communities. These microgrids, predominantly diesel-generated (as described above), are typically over 50 years old and in need of modernization. The upgrades will reduce line losses, diesel fuel usage, and ensure readiness for renewable energy integration. AEA personnel will project manage the distribution upgrades in each community. Based on current staffing levels, consulting engineers, and statewide construction contractor support, it is reasonable to expect that AEA could construct two (2) distribution projects per year. Costs for the upgrade will vary significantly depending on the size of the community, the soil conditions, buried or above ground, and if above ground – the number of poles that need to be replaced. The milestones for this proposal are: 1) project planning, including selection of community, stakeholder engagement, development of a project management plan (PMP); 2) project design, including engineering and procurement; 3) construction and integration; and 6) final closeout of award. The overall project timeline for each distribution upgrade is two years. The tasks in the first year include planning, design, permitting, and purchasing long lead items. Should AEA have funding for multiple projects, a bulk purchase of commonly used, BABA-certified transformers may be made. This would help move projects through the queue at a more rapid pace and potentially secure lower per-unit costs owing to bulk-order discounts. The tasks in the second year (or season) will be for construction. Most of Alaska’s construction season ranges from early April to as late as October. Alaska’s extreme climate conditions are always considered when planning construction projects accordingly. This is to minimize any risks that could lead to delays with project deliverables; any delay in project implementation will result in a corresponding delay in GHG reductions. AEA’s third initiative of the proposed measures is VEEP. The Alaska Legislature established VEEP in 2010 under 3 AAC 108.400, as an AEA-administered grant program aimed at reducing per capita consumption through energy efficiency. VEEP's objective is to actively implement energy and cost-saving efficiency measures in public spaces and facilities within small, high-energy-cost rural Alaskan communities. Energy efficiency upgrades provide a rapid return on investment, significant cost savings, and corresponding GHG reductions. Project scope can range anywhere from smaller measures, such as replacing antiquated lighting technology with LED, to larger improvements, such as upgrading a building's thermal envelope by installing new windows and doors, ventilation systems, boilers, and water heaters. These projects generally take eighteen to twenty-four months to complete. AEA anticipates issuing 10-15 awards through one solicitation, targeting larger projects with maximum GHG reductions. The milestones for this proposal are: 1) project planning, including request for proposals, grants to communities, development of a PMP; 2) construction, including energy audits, punch list, and final inspection; and 6) final closeout of award. 4 Prior applicants to the VEEP program have been solicited through a competitive process and ranked based on cost, energy demand, cost match, administrative capacity, participation in other end-use efficiency programs, and equitable geographic distribution of funding. AEA intends to use similar scoring criteria for funds available through CPRG emphasizing GHG emissions reduction. Once selected, applicants are awarded a pass-through grant, which the community manages with support from AEA. The most recent solicitation was sponsored by the Denali Commission and Wells Fargo and awarded in 2019 and has successfully facilitated 56 projects. Collectively these projects have offset 1,098,688 kWh resulting in an estimated $566,612 saved annually throughout the awarded communities. By working as a coalition, this application will enhance the opportunities to improve the needs of specific remote communities in the state. The additional CPRG funding with more targeted outcomes will improve the outcomes during the 5-year period than if AEA was to administer the CPRG program on its own. TCC Project Description TCC proposes to implement a program for upgrades to the distribution lines and power plants of nine tribal communities in the TCC Region. The nine communities include: Allakaket, Alatna, Evansville, Bettles, Healy Lake, Eagle, Rampart, Northway, and Arctic Village. These tribes would work with the respective utilities in each community to implement upgrades to increase utility generation and distribution efficiency and unlock the ability to the electric utility to integrate high-penetration renewables. TCC will work with the respective utilities and complete estimates for all utility upgrades and integration requirements, to include engineering, construction, operations, and maintenance, etc. The proposed budget of $10 million is based upon recent experience for distribution and power plant upgrades in similar remote, microgrid communities, including those who have implemented high penetration renewable energy. CPRG funding is a unique opportunity for these communities to dramatically change their generation to be more resilient, improve economic conditions through reduced energy burdens (expenditures for diesel), and create local jobs both during construction and for maintenance of the system. NAB Project Description The NAB represents and includes the 11 federally recognized and rural tribal communities of Kotzebue (Qikiqtabruk), Kivalina (Kivalieiq), Noatak (Nautaaq), Selawik (Aqulibaq), Deering (Ipnatchiaq), Buckland (Nunachiaq), Kiana (Katyaak), Noorvik (Nuurvik), Ambler (Ivisaappaat), Shungnak (Issingnak), and Kobuk (Laugviik). NAB proposes upgrades at power plants and water plants in these communities to maximize alternative energy use. The NAB recently received a grant award from the Department of Energy (DOE), Office of Clean Energy Demonstrations (OCED) for up to $54.8 million to implement solar and battery energy storage systems (BESS) for each community in the borough with the objective of significantly reducing diesel consumption, improving the heating of borough residences, and lowering the cost of living. The OCED project will also significantly reduce GHG emissions. However, achieving maximum diesel savings requires the ability to “turn off” the community’s diesel generators when sufficient power is available through the solar/BESS; unfortunately, the power plants and drinking water plants for each community require waste heat from the generators to keep these critical facilities warm. Shutting the diesel generators off for even a few hours during the sunlight-rich, but still very cold months of March and April could result in freeze-ups of the generators or the water plant. This proposed initiative from NAB requests $9,954,321 to fund the addition of external, electric boilers for these critical facilities. These boilers will be sized to operate with the anticipated excess electricity produced from the solar/BESS. Appropriate controls and thermostats will also be integrated with the units to enable the remote monitoring and control of the boilers. The proposed upgrades for Kotzebue 5 also include improvements to the power plant’s intake air and cooling system that will significantly improve the overall plant’s efficiency. Similar to the smaller communities, an electric boiler is planned for the power plant to provide heat when wind/solar meets community demand and the diesel engines can be shut off. This will also heat the office area of the plant (currently the full building is heated with excess generator heat). Additional upgrades include protection of the plant cooling and intake air system to optimize the operation of the generators. Insulation and motorized dampers will be provided in this area to minimize the introduction of outside cold air when the engines are not operating. Currently five communities in the Borough have implemented solar and/or BESS at varying levels (Kotzebue, Deering, Buckland, Noatak, and Shungnak). In these communities (such as Shungnak), the diesel engines are run at low levels (like 25-30% load), even when the solar/BESS system could meet the entire electrical demand of the community to ensure the power plants and water plants are kept warm. The OCED project will build-out these systems to a greater extent and build new systems for the other NAB communities. In each case, excess solar power is anticipated to be available to support the proposed electric boilers during periods of peak solar production. TCC and the NAB expect projects in the communities they represent to be completed within 36 months of receiving funding. The risks associated with the projects are similar for all activities proposed in this application. The complexities of working in rural Alaska, the limited construction season, and supply chain challenges, may delay projects but there is sufficient time in the timeline to address any challenges that arise and successfully complete the proposed projects within the five-year period of performance of the grant. The milestones for TCC and NAB’s proposals are: 1) project planning, including procurement and stakeholder engagement; 2) project development; 3) construction and integration; and 6) final closeout of award. Additional details related to milestones are included in Section 3 of the application. AEA, as the lead applicant, would provide subawards to TCC and NAB to perform all activities related to this proposal. In line with the Alaska Municipal League’s (AML) infrastructure program and long-term work with the Department of Enviromental Conservation (DEC) on the State of Alaska’s CPRG PCAP, AML will support the coalition with planning support, community outreach, progress tracking, and energy data needs. As a sub-recipient to this application, AML will support the coalition with workforce development infrastructure which will consist of aiding applicants with recruitment, skill development, career navigation, and wraparound services such as childcare, housing and living stipends. b. Demonstration of Funding Need In 2021, Alaska ranked first among U.S states with a per capita energy expenditure of $8,711, amounting to nearly 11.15% of its GDP. This ranking has remained consistent since 2015 1. The high energy burden experienced by Alaska residents is attributed, in part, to a small population and harsh climate. Funding for capital projects in rural Alaska is consistently challenging due to the lack of a tax base in these communities. The low populations and high costs for these communities also limit opportunities for most other forms of project financing. AEA, in collaboration with TCC and NAB is requesting funds through the CPRG program, because it is the missing link that will help Alaska meet its obligation of providing a better quality of life to its residents and environment by reducing GHG emissions. If awarded, the possibility of maximized energy efficiency and sustainability in Alaska’s rural communities would quickly become a long-sought reality. Most of the funding opportunities from the Inflation Reduction Act (IRA) and the Infrastructure Investment and Jobs Act (IIJA) support the deployment of renewable energy generation and carbon 1 https://www.eia.gov/state/seds/data.php?incfile=/state/seds/sep_sum/html/rank_pr.html&sid=US 6 sequestration but there are no funding opportunities that provide for the infrastructure upgrades necessary to successfully integrate renewable energy sources into remote microgrids. These upgrades are an essential step in transitioning rural communities to clean energy. Furthermore, these types of activities do not qualify for any of the dozens of tax incentives authorized by the IRA. A tax credit is available for some energy efficiency upgrades to commercial buildings; however, that credit is not extended to public buildings and the energy efficiency tax credits are not eligible for elective pay, which provides the benefit of the credit to tax exempt agencies such as state, local, and tribal governments. DERA, rural distribution upgrades, and VEEP have received funding from the local, state, and federal level in the past including state cost matching, the Denali Commission, the VW Settlement Trust Fund, and the U.S. Department of Agriculture’s (USDA) High Energy Cost Grant program. Unfortunately, the demand for these initiatives far exceeds the available funding resources. Starting in federal fiscal year 2015, AEA has received $3.3 million in funds from the U.S. Environmental Protection Agency (EPA) through the DERA program. The state has consistently provided a 1-to-1 match of $3.3 million for a total of $6.6 million in project costs. This has enabled AEA to fund the replacement of 27 high-emission engines for higher tier 2 or 3 engines in 17 distressed communities. Due to recent inflation, the number of engines AEA can replace with existing federal and state funding has decreased. In 2020, only four engines were replaced compared to six the previous year (2019) and eight the year prior to that 2. In 2022, AEA received $1,038,138 in DERA funds. That amount secured the replacement of four engines with new low-emission engines in two communities. AEA and rural communities have requested funds for distribution upgrade projects through federal programs such as the Denali Commission, Bureau of Indian Affairs, USDA, as well as state matches. However, the funds currently available from these agencies do not meet the high demand for these upgrades and often these sources combined still fall short of fully funding a given project. Currently, five communities have active projects and several more are awaiting funding. For example, in Kipnuk, the distribution system is in extremely poor condition with leaning poles and aging infrastructure. The community had a new power system and tank farm constructed with AEA and Denali Commission funds as of 2017- 2019 in addition to other funds sourced from AEA’s Renewable Energy Fund (REF) program and other federal sources. The community was able to provide $250,000 in cash for design. AEA matched their funds and took their story to the Denali Commission, which was able secure Bureau of Indian Affairs funds in the amount of $800,000. And still the total amount secured to date is insufficient to complete all the improvements needed. Another example is the distribution upgrade for the Native Village of Manokotak. Manokotak is a small community located within the Dillingham Census Area. According to the Economic Innovation Group’s distressed community index, Manokotak scores 88.9 (out of 100) which deems it as ‘distressed’ due to several economic factors. The community is isolated and powered by a diesel engine power plant that has no outside interties or local sources of 2 www.akenergyauthority.org/what-we-do/rural-energy/diesel-emission-reduction-act-program Figure 1 Manokotak Utility Company performing repairs during power outage December 2023 7 alternative energy. In November 2023, AEA applied for a $3 million grant under the USDA’s Rural Utilities Service High-Energy Cost Grant (HECG) program to provide Manokotak with the funds needed for its distribution and powerhouse upgrades. Although Manokotak was awarded partial funding in the amount of $2 million, it still leaves the community roughly $1.5 million short of being able to complete the project in its entirety. Manokotak declared a state of emergency on December 21, 2023. The community lost power due to a winter storm, leaving 300 of the 450 without power and heating. As a result, pipes began to freeze and burst 3. Many residents evacuated their homes to seek shelter in the local school which became an emergency shelter. AEA spent all of what remained in its contingency funds for the year to restore power to the community. In addition to harsh winter conditions, it was determined that the power outage was a direct result of degraded powerhouse and distribution lines in the community 4. In addition to the previously mentioned communities, AEA is aware of additional communities that require extensive upgrades to their distribution systems: Nelson Lagoon, Napaskiak, Venetie, Port Heiden, and Rampart. This list does not include many other rural communities that may be facing the same challenges. AEA is currently performing a distribution inventory and assessment. The inventory will help AEA to create a list of high-priority distribution upgrade projects that will be ranked by life, health, safety, and prioritized for potential CO2 emission reductions. Between 2016 and 2023, AEA conducted VEEP solicitations for a total of $2.7 million of project funds administered. AEA has $2.5 million in VEEP funding available from sources such as the Denali commission, Wells Fargo, Department of Energy’s Energy Efficiency and Conservation Block Grant Program, and state legislature. But, like the DERA and distribution upgrade programs, the funds available do not meet the demand. There is no funding budgeted from the state for the current fiscal year, or for next year. TCC Specific Funding Need The nine TCC communities, seven microgrids, included in this proposal have not yet pursued funding for renewable energy projects due to the high barrier of entry required to include implement power plant upgrades to enable future renewable development. Alaska Power and Telephone (AP&T), as the major utility for seven of these nine communities, has led the way with renewable energy in rural Alaska with 75% of their energy generation coming from hydropower. This funding opportunity will allow for increased renewable energy generation by AP&T in the interior, where power is currently 100% generated by fossil fuels. NAB Specific Funding Need Funding capital projects for communities in the NAB is challenging for those aforementioned reasons mentioned in this section; the recent OCED award will provide a transformative change to the communities in the borough but cannot realize maximum diesel reductions unless the diesel engines can be shutdown. Auxiliary heating for the power and water plants is necessary to enable “engine off” conditions. Achieving the maximum diesel savings for each community will limit emissions, improve air quality, and provide economic opportunity due to lower power costs. c. Transformative Impact Alaska has the third highest per capita energy-related CO2 emissions in the United States 5. Communities in rural Alaska are experiencing some of the most significant impacts from on-going climate change, 3 Manokotak issues state of disaster emergency (kdlg.org) 4 Power outage plagues Western Alaska town for days (alaskasnewssource.com) 5 Carbon Emissions by State 8 including coastal erosion, permafrost melting, and reductions in subsistence species populations that most communities rely upon as part of their food source. These impacts threaten the ability for several communities to continue to exist. As a result, these communities acutely understand the need to reduce GHG emissions and transform their economies. Efficient diesel power plants, upgraded distribution lines, and energy efficiency project funding will reduce GHG emissions, lower the energy burden of rural communities, improve resiliency to disruptive events concerning fuel conveyance, and provide opportunities for economic development. Upgraded distribution infrastructure will allow for the future integration of renewable generation sources. CPRG funding for this application would have a transformative impact on the energy systems of disadvantaged, rural communities in Alaska. Replacing inefficient diesel engines is expected to provide fuel savings, emission reductions, and health benefits for many years into the future. Upgrades to rural distribution systems and power plants will reduce line losses, decrease diesel fuel usage, and ensure readiness for renewable energy integration. Making disadvantaged, rural communities renewable ready is an essential step towards ensuring environmental justice and equitable access to the benefits of clean energy. According to the International Energy Agency, integrating higher shares of renewable energy into the grid can decrease electricity system costs by 15-40 percent 6. The utility upgrades TCC is planning with AP&T, Rampart’s Electric Utility, and Arctic Village’s Electric Utility mark a significant stride towards fostering future renewable development in Alaska. These upgrades signify a crucial step in modernizing the energy infrastructure of these regions, laying a robust foundation for integrating renewable energy sources efficiently. With a focus on digital compatibility, these utilities are poised to seamlessly incorporate industry-leading power electronics into their systems, such as SMA and SolarEdge inverters, Woodward EasYgen, and ComAp diesel generator controls, among others. By ensuring compatibility with these technologies, the utilities are positioning themselves to accommodate the growing demand for renewable energy solutions, enabling smoother integration and management of solar, wind, and other renewable sources into their grids. Distribution and efficiency upgrades facilitate the integration of advanced technologies such as smart grids and smart meters. These technologies enable better monitoring and management of energy use, reducing waste and improving overall energy efficiency 7. Energy efficiency upgrades reduce long-term fixed energy costs in communities through improvements including outdoor lighting retrofits. Not only do these upgrades provide a rapid return on investments and significant cost savings, but they also add to the safety of these communities by increasing visibility in school yards, public work facilities, and streets. In particular, the proposed subaward to NAB will enable each community to achieve maximum diesel savings and optimize the benefits provided through the OCED grant. Furthermore, less fuel consumption means that fuel deliveries do not have to occur as regularly, resulting in greater resilience to disruptive events concerning fuel conveyance such as freight disruption by weather and disaster that may materially delay fuel shipments. It also reduces the opportunity for fuel spills or other releases. If awarded, the work done with CPRG funding can provide a framework for a viable path to renewable integration in other rural communities. The transformative impacts of the proposed initiatives are strategically aligned with the broader goal of fostering a more sustainable energy ecosystem in Alaska. As the state continues to embrace renewable energy initiatives, improvements and upgrades funded by CPRG will play a pivotal role in accelerating the transition towards cleaner and more resilient energy systems, ultimately contributing to a more sustainable future for Alaska and its communities. 6 Assessing the Economic Impact of Electrical Grid Upgrades An Investor Perspective (energy5.com) 7 Assessing the Economic Impact of Electrical Grid Upgrades An Investor Perspective (energy5.com) 9 2. Impact of GHG Reduction Measures The measures contained in this coalition application contribute to energy efficiency in rural communities through different means and will result in a significant reduction of CO2 equivalent GHG by displacing large amounts of diesel fuel that would have been consumed if not for implementation of these measures. The sections below will address and quantify how each proposed measure will reduce emissions in five years and then in the next twenty-five years. a. Magnitude of GHG Reductions from 2025 through 2030 For AEA’s genset and diesel engine replacement, AEA anticipates having ten engines installed by the end of 2026, another ten by the end of 2027, and finally eight more online by the end of 2028. All upgrades will be fully operational and contributing to lower emissions in unison no later than the start of federal fiscal year 2029. By the end of federal fiscal year 2030, replacing 28 engines would reduce about 4,739 metric tons of CO2 emitted. A series of studies and simulations for rural distribution upgrades in four rural Alaska communities, performed by a contractor on behalf of AEA, were used as a proxy for determining potential GHG reductions that would result from CPRG funding. The four proxy projects would displace approximately 121,000 gallons of fuel and a reduction of 767 metric tons CO2 equivalent for 2025 – 2030. Although there is no way to specifically quantify GHG reductions for future projects not yet scoped, AEA used historical performance and funding, adjusted for inflation, to estimate the impact of CPRG funding for the VEEP program. From 2016 through 2023, 56 communities were awarded $2.7 million under VEEP. This offset 1,189,463 kWh per year, totaling 830.9 metric tons of CO2 equivalent. AEA anticipates VEEP funding through CPRG will offset 3,002,198 kWh per year and result in a reduction of 8,388 metric tons CO2 equivalent for 2025 – 2030. TCC’s proposed measure will reduce diesel fuel use by over 72,000 gallons annually and reduce emissions by 774 tons annually based on the existing efficiency of the communities’ systems compared to expected increased efficiency of 23.12% after the improvements. NAB’s proposed measure will reduce diesel fuel use by over 155,635 gallons annually and reduce emissions by 1,590 tons annually based on achieving maximum, feasible diesel off hours and the expected increased efficiency at the Kotzebue power plant. Below are the estimates for each proposed measure: Total GHG Reductions 2025 – 2030 Genset Replacement Program – 4,739 metric tons CO2 VEEP – 8,388 metric tons CO2 Distribution Upgrades – 767 metric tons CO2 TCC Region Powerplant & Distribution Upgrades – 3,484 metric tons CO2 Northwest Arctic Borough Powerplant Upgrades – 5,565 metric tons CO2 TOTAL: 22,943 metric tons CO2 b. Magnitude of GHG Reductions from 2025 through 2050 Through constant equipment monitoring, proper operations, and preventative maintenance the durability and quantity of GHG reduction measures could continue reducing GHG emissions at the same rate year by year through 2050. To ensure proper operations and maintenance, AEA and coalition members will provide training and operator manuals to ensure operators have the information and skills needed. As part of its existing work, AEA provides comprehensive technical assistance to rural utilities to ensure infrastructure lasts its full economic life, preventing catastrophic electrical emergencies, and building community self-sufficiency. In addition, AEA has full time circuit rider positions that support 10 rural powerhouse operators. Assuming a best-case scenario, the total amount of GHG reductions could reach as high as 146,846 metric tons of CO2 equivalent in that timeframe. Below are the estimates for each proposed measure: Total GHG Reductions 2025 – 2050 Genset Replacement Program – 35,310 metric tons CO2 VEEP – 50,328 metric tons CO2 Distribution Upgrades – 4,873 metric tons CO2 TCC Region Powerplant & Distribution Upgrades – 18,968 metric tons CO2 Northwest Arctic Borough Powerplant Upgrades – 37,367 metric tons CO2 TOTAL: 146,846 metric tons CO2 c. Cost Effectiveness of GHG Reductions Formula = (Requested CPRG Funding) / (Sum of Quantified GHG Emission Reductions from 2025-2030) AEA’s Proposals = ($30,031,790) / (13,894 metric tons CO2) = $2,162 per one (1) metric ton CO2 TCC Proposals = ($10,000,000) / (3,484 metric tons CO2) = $2,869 per one (1) metric ton CO2 NWAB Proposals = ($9,954,321) / (5,565metric tons CO2 (2025-2030)) = $1,796 per one (1) metric ton CO2 Combined Cost Effectiveness = ($49,986,112) / (22,943 metric tons CO2) = $2,179 per one (1) metric ton CO2 The factors that impact the proposed measures' cost effectiveness are the higher cost of shipping and construction in rural, remote communities (many of which are not on the road system), the age and condition of the existing infrastructure, harsh climate, and short construction seasons. d. Documentation of GHG Reduction Assumptions The models and tools used to calculate GHG emissions reductions were the EPA Diesel Emissions Quantifier (DEQ), Heat Recovery Simulation Analysis, Power Cost Equalization Reports, EPA GHG Equivalencies Calculator and Microsoft Excel. Please reference the Technical Appendix enclosed in this application for a detailed breakdown of the GHG calculations, methodology, and assumptions. 3. Environmental Results – Outputs, Outcomes, and Performance Measures a. Expected Outputs and Outcomes Alaska Energy Authority An expected output for the overall CPRG grant is timely reporting. As the lead applicant for the coalition, AEA will prepare and submit required progress reports and a final report including information regarding technical progress; accomplishments; milestones achieved; summary of expenditures; community engagement; strategy for mitigating environmental risks; and progress on job quality. The NAB and TCC will provide AEA with reporting on their measures to include in the required reports. Outputs and Outcomes for Expansion of DERA-like program Outputs: Over three rounds of subawards, AEA expects to install approximately 25-28 new gensets in 12-14 communities. AEA expects to create construction jobs to implement this measure. Outcomes: AEA expects this measure to reduce GHG emissions by 35,310 metric tons between 2025- 2050. Expected outcomes of this measure are reduced diesel usage, cost savings from reduced diesel usage, reduced GHG emissions, and improved public health and climate impacts due to GHG emission reductions. In addition, AEA expects to hire one circuit rider to support all activities in the CPRG grant. Outputs and Outcomes for Rural Distribution Upgrades 11 Outputs: AEA expects to construct two distribution projects per year over the five-year period of performance for the CPRG grant. AEA expects to complete 3-5 rural distribution upgrade projects in total depending on the cost of each upgrade. Costs for the upgrade will vary significantly depending on the size of the community, the soil conditions, buried or above ground, and the number of poles to be replace. AEA expects to create construction jobs to implement this measure. Outcomes: AEA expects this measure to reduce GHG emissions by 4,873 metric tons between 2025- 2050. Expected outcomes of this measure are: Improved Environmental Impact: AEA expects benefitted communities will begin to integrate renewable energy sources because of this measure, contributing to sustainability. Upgrading the distribution infrastructure will improve overall system efficiency by reducing line losses and diesel fuel usage at the powerhouse. Distribution upgrades also ensure that the microgrids are well- equipped for renewable energy, enabling the local distribution systems to effectively manage the fluctuations introduced to the system. Reduced Diesel Consumption and Associated Savings: Less reliance on diesel generators lowers emissions, improving air quality and environmental health. It also reduces the potential for diesel spills and releases. Resilience: Modernized infrastructure enhances community resilience to disruptions, ensuring a reliable power supply. Health and Safety: Replacement of aging structures, leaning power poles, sagging lines, reduces accidents and enhances public safety and system reliability. Economic Opportunity: Reliable energy infrastructure attracts businesses, fostering economic development and job creation. Community Empowerment: Access to sustainable energy solutions improves overall quality of life, fostering education, skill development and entrepreneurship. Outputs and Outcomes for VEEP Outputs: AEA expects to issue 10-15 awards for VEEP through one solicitation but will have time for additional rounds if all funding is not expended with the first solicitation. Each award may benefit more than one community, depending on the subawardee. AEA expects to create construction jobs to implement this measure. Outcomes: AEA expects this measure to reduce GHG emissions by 50,328 metric tons between 2025- 2050. Expected outcomes of this measure are reduced diesel usage, cost savings from reduced diesel usage, reduced GHG emissions, and improved public health and climate impacts due to GHG emission reductions. In addition, VEEP projects benefit the community through increasing public safety by implementing energy efficient lighting projects in public spaces. Tanana Chiefs Conference The integration of high-penetration renewables and increased energy efficiency should lead to environmental benefits, such as reduced greenhouse gas emissions and mitigated environmental impacts associated with energy generation through diesel generators. Upgrade Plans: Develop detailed plans for upgrading the distribution lines and power plants in each community, considering factors such as energy efficiency, reliability, and integration of high-penetration renewables. Infrastructure Upgrades: Implement upgrades to the distribution lines and power plants in all nine communities according to the developed plans. This may include installing new equipment, upgrading existing infrastructure, and improving overall system capacity. 12 Collaborative Efforts: Foster collaboration between the Tribes and respective utility service areas to ensure successful implementation of the upgrades. This may involve regular meetings, joint planning sessions, and coordination of resources. Outcomes: The proposed project will reduce diesel fuel use by over 72,000 gallons annually and reduce emissions by over 770 tons annually and 18,968 metric tons between 2025-2050. Increased Energy Efficiency: The upgrades to distribution lines and power plants should lead to improved energy efficiency, reducing energy losses and optimizing overall system performance. The impacted power plants are anticipated to increase their efficiency by 23.12% after completion of this project. Enhanced Reliability: By upgrading the infrastructure, the reliability of the electrical grid in the 9 communities should be improved, resulting in fewer power outages and disruptions. Integration of Renewables: The upgrades should enable the electric utility to integrate high-penetration renewables more effectively into the grid, such as solar and wind power, thereby reducing reliance on fossil fuels and promoting sustainability. The proposed project will enable development of solar and battery energy storage infrastructure for each community that will result in an estimated 1.5M kwh of renewable generation annually and further fuel reductions of over 72,000 gallons annually. Cost Savings: As a result of increased energy efficiency and reduced maintenance needs, the upgraded infrastructure should lead to cost savings for both the utility and the communities. Across the benefitting utilities, diesel fuel savings are anticipated to be over $325,000 annually. Community Empowerment: Through collaboration and capacity building, the project should empower local communities to take more active roles in managing their energy infrastructure, leading to greater self-sufficiency and resilience. Environmental Benefits: The integration of high-penetration renewables and increased energy efficiency should lead to environmental benefits, such as reduced greenhouse gas emissions and mitigated environmental impacts associated with energy generation. Northwest Arctic Borough Outputs: Expected outputs for this project are efficiency upgrades for the overall electrical systems in the 11 communities through diesel use reduction. Outcomes: This measure is expected to reduce GHG emissions by 1,753 tons of CO2e annually and by 37,367 metric tons between 2025-2050. Energy efficiency is one of the most effective means of reducing diesel consumption in rural Alaska. Expected outcomes of this measure are reduced diesel usage, cost savings from reduced diesel usage, reduced GHG emissions, and improved public health and climate impacts due to GHG emission reductions. The proposed project will reduce diesel fuel use by over 155,635 gallons annually. Furthermore, decreased and stabilized energy prices will encourage opportunities for future economic development, offering potential job opportunities. b. Performance Measures and Plan As an extension of Alaska Municipal League’s (AML) current support to the Alaska Dept. of Environmental Conservation (DEC), which is administering the CPRG planning grant, AML will work with DEC to establish a statewide tracking and reporting system for CRPG awardees. AML will work with DEC to establish a statewide tracking and reporting system for CRPG awardees to utilize. This system will include consistent reporting timelines, methodology consistent with the State’s GHG emissions 13 inventory, and a dashboard providing reporting individually and cumulatively. This State-led effort not only complements EPA’s own activities but ensures a platform for long-term accountability and progress. While targeted to meet the needs of CPRG and Tribal CPRG implementation awardees, the ability to report progress will be available to any state agency, or local or Tribal government, as aligned with measures described in Alaska’s Priority (and eventually Comprehensive) Action Plan. AML will work with DEC and awardees to establish a consistent and simplified reporting structure, which will be completed through an online portal that leads to progress demonstrated via a publicly available dashboard. Reporting will be based on the outputs and outcomes identified in each awardee’s implementation plan and built to include both unique measures and those that are similar across projects. AEA expects a robust subrecipient monitoring process that will require each sub awardee to complete timely reporting. AEA and sub awardees will implement a system of monitoring that is initiated through a baseline assessment that vets and downscales broadly available data, after which quarterly (depending on grant award terms) data is included and submitted for review and analysis. AEA will leverage the statewide reporting and monitoring effort led by DEC, through AML, such that subrecipient engagement is managed through a single entity across awards. This dedicated position will ensure consistency of data collection and alleviate any staff burden of AEA, TCC, and the NAB. The project’s technical points of contact at AEA, TCC, and the NAB will track project’s benefits and avoided disbenefits that are quantifiable and measurable, see table below. Baseline measures will be Outputs/Outcomes Measure Upgrades/Improvements completed Number of projects completed / communities benefited Public health benefits TBD Enhanced c. Authorities, Implementation Timeline, and Milestones Alaska Energy Authority 14 AEA will implement the DERA-like, rural distribution upgrades, and VEEP as described in this application, and has the authority to do so in coordination local governments and tribes; AEA will work local governments and tribes early in the planning phase for each measure to secure local approval and support. AEA has the authority to procure services and issue subawards. AEA is an independent and public corporation of the State of Alaska, est. 1976 and is governed by a board of directors with the mission to “reduce the cost of energy in Alaska.” AEA is the State Energy Office and lead agency for statewide energy policy and program development. AEA’s core programs work to diversify Alaska’s energy portfolio, lead energy planning and policy, invest in Alaska’s energy infrastructure, and provide rural Alaska with technical and community assistance. AEA’s enabling legislation, which includes authority to implement the programs described in this plan is in Alaska Statutes, chapter 44.83. The impact of AEA’s programs extend to the construction of rural power generation and bulk fuel facilities, distribution systems and transmission lines, renewable energy asset construction and integration, and ad-hoc maintenance and improvement of aging infrastructure. Rural Electric Utility Workers, under AEA’s circuit rider program, continuously travel to rural communities to administer itinerant training to rural utility operators, and diligently maintain an inventory and assessment record for nearly every rural powerhouse in the state by conducting comprehensive on-site assessments. This record informs the powerhouse construction schedule and ensures alignment with community needs. The schedule below indicates what is typical for AEA’s projects under the DERA Program. Given the complexities of working in rural Alaska, the limited construction season, and supply chain challenges, AEA typically sees a two-year cycle for these replacement projects. Due to the volume of the funds, we intend to distribute the sub-awards over the 5-year period allowed by the grant and provide three rounds of funding opportunities. The table below reflects a typical genset replacement project schedule Figure 1 o Task 1: Confirm each rural community has an eligible engine and prepare emission o Task 2: Design and identify specifications – Procure contractual assistance for the design of the engine/generator installations and development of specifications specific to each o Task 3: Construction procurement – Issue invitation to bid (ITB) to select a contractor that will provide engines, generators, and associated equipment, including any required assembly o Task 4: Submittals – o Task 5: Installation and Commissioning – Install generator repowers/replacements and help integrate the electronically controlled engines with the existing switchgear, fuel, exhaust, and 15 cooling systems. If requested, AEA staff will offer technical assistance during the startup and o The table below reflects the schedule for and milestones for rural distribution upgrades. AEA will project manage these projects and expect individual projects will closeout at different times. AEA can complete 2 upgrade projects a year but timing can vary based on location, improvements, and supply chain. Distribution projects will be needs based meaning they will be selected based on needs from our distribution inventory and assessment database. Communities that have the greatest need for an upgrade will be selected to receive a project. Mile Task/Phase Start End Deliverable 1. Planning Sep 24 Jun 25 Select Communities based on need Sep 24 Dec 24 Meet with the Community Sep 24 Mar 25 Resolution Project Management Plan Jan 25 Mar 25 Signed PMP Grant to Community Mar 25 Jun 25 Grant agreement 2. Design Jun 25 Jun 29 Engineering Jun 25 Jun29 Signed Notice to Proceed 95% Design Jan 26 Jun 26 Design documents, community acceptance Long lead items Jun 26 Jun 27 Transformers Final Design, ITB Jun 26 Jun 27 Design documents, permitting, ITB 3. Construction Apr 27 Sep 29 On-site construction Apr 27 Aug 29 Field Reports Final inspection Aug 29 Sep 29 Checklists, photos 4. Close Out Sep 29 Sep 29 Final Report The table below reflects the schedule for and milestones for VEEP. Individual subawards will closeout at different times. These projects typically take 18 to 24 months to complete but can vary based on location, improvements, and supply chain. Milestone Task Start End Deliverable 1. Planning Sep 24 Dec 24 Project Management Plan Request for Applications Jan 25 Mar 25 Applications from Eligible Applicants Grant to Community Mar 25 Jun 25 Signed Agreements 16 2. Construction Jun 25 Jun 29 Audit (if applicable)Jun 25 Jun 26 Audit Report Construction Jun 25 Jun 29 Monthly/Quarterly Reports Punch List Sep 27 Aug 29 Punch List Final Inspection Sep 27 Aug 29 Trip Report 3.Project closeout Dec 27 Sep 29 Final Report Tanana Chiefs Conference TCC will implement efficiency upgrades to power plants and water plants as discussed in this application and has the authority to do so for the tribes it represents. Estimated Performance Period:September 2024 – Task 1.0: – December 2024) Task Details: The project planning task includes RFP development, contract procurement, stakeholder engagement. Subtask 1.1: Procurement: Negotiate with EPA for award allocation, formalize written agreements, develop RFPs for Engineering Services and Construction Contractors and complete Deliverables: Project and Risk Management Plans, RFPs, and contracts Subtask 1.2: Community Engagement: Community meetings, informal interviews with village leadership, develop stakeholder engagement plan, presentations and listening sessions at annual and subregional meetings, coordinate and schedule trainings, contemplate cooperative labor agreements. Deliverables: Documented engagement plan for life of project Task 2.0: Project Developm – July 2025) Task Details: The project development task includes design, permitting, site control, and associated activities to prepare for construction, as detailed in the subtasks below. Subtask 2.1: Engineering Design: Complete 35%, 65%, 95%, and construction ready drawings Deliverables: Construction ready drawing set, calculations, basis of design, specifications, review and version logs Subtask 2.2: Permitting: Prepare permit applications, review, and submit to jurisdictional agencies for approval., as necessary. Deliverables: Secured permits Subtask 2.3: Community Engagement: Community meetings, implement stakeholder engagement plan, collect feedback and respond, create project webpage, post project information publicly, presentations and listening sessions at annual and subregional meetings, assess community needs for local workforce, coordinate training opportunities, stablish workplace committees for project hires, update webpage. Deliverables: Formal coordination and documentation of workforce development requests, community needs assessment Task 3.0: Construction and Integration (August 2025 – August 2027) 17 Task Details: The construction and integration task includes pre-construction activities, construction, inspection, and closeout, as detailed in the subtasks below over two years across the proposed communities. The tasks are generally the same for each community. Subtask 3.1: Pre-construction: Review construction plans with selected contractor and confirm schedule, finalize contract, procure materials and mobilize Deliverables: Construction contract, bill of materials Subtask 3.2: Construction: Site preparation, improves to each power plant Deliverables: Installed assets Subtask 3.3: Community Engagement, Community meetings, update project webpage Deliverables: Updates to project webpage, community meetings reports Subtask 3.4: Inspection and Closeout: Substantial completion inspection and punch list, address punch list items, final and regulatory inspections, troubleshooting, operator training Deliverables: Punchlist, inspection reports, training logs, signed transmittal from contractor to owner indicating completion and turnover Northwest Arctic Borough The NAB will implement efficiency upgrades to power plants and water plants as discussed in this application and has the authority to do so for the communities it represents. Estimated Performance Period: September 2024 – Task 1.0: Project Planning (September 2024 – Task Details: The project planning task includes RFP development, contract procurement, and Task 2.0: Project Development (January 2025 – Task Details: The project development task includes design, permitting, and contractor procurement for Task 3.0: Construction and Integration and closeout (August 2025 – Task Details: The construction and integration task includes pre-construction activities, construction, inspection, and closeout. The tasks are generally the same for each community. We anticipate that the water/power plant upgrades for five communities will be completed in 2026 and upgrades for the completed in 2027. Required reporting will be complete throughout the project. Alaska Municipal League As a sub-recipient, AML will support the application with workforce development infrastructure which will consist of aiding applicants with recruitment, skill development, career navigation, and wraparound services such as childcare, housing and living stipends. Workforce development infrastructure is an ongoing effort, and the coalition will have access to these tools when the planning process begins in the fall/winter of 2024. AML will work with the Alaska Department of Environmental Conservation (DEC) to establish a statewide tracking and reporting system for CPRG awardees to combine data in a singular database. The system will supplement sub-awardees with technical assistance provided by partners to encourage timely reporting, with methodology consistent with the State’s GHG emissions inventory. The tracking and reporting system will be piloted in time to complete the first round of semi-annual reporting required by the grant program. Lastly, AML will lead a statewide cohort of awardees to participate in CPRG planning and creation of a sustainability plan. 4. Low-Income and Disadvantaged Communities The benefits from the measures proposed by the coalition in this application will almost entirely benefit low-income and disadvantaged communities. 18 Although AEA has not selected communities for its measures at the time the application was submitted, AEA expects almost all subawards to benefit communities that are in disadvantaged census tracts, Power Cost Equalization (PCE) communities, or communities where most residents are Alaska Native. The reasoning for this expectation is the type of work proposed by AEA and the criteria it uses to select projects for subawards. The PCE program is an endowed fund source that provides economic assistance to communities and residents of rural electric utilities where the cost of electricity can be three to five times higher than for customers in more urban areas of the state. This program serves over 88,000 Alaskans in over 190 communities that are largely reliant on diesel fuel for power generation. Of the PCE communities, only five communities are considered not disadvantaged and another seven communities are considered partially disadvantaged, details are provided in the attachment to this application. Please note the CEJST disadvantaged status was adjusted to reflect the presence of federally recognized tribes in a community to reflect the intent for these tribal communities to be included in the definition of disadvantaged. For communities where there are tribal governments and >50% of the population is Alaska Native, our list presumes full disadvantaged status; for communities where there are tribal governments and <50% of the population is Alaska Native, this list presumes partial disadvantaged status. For the 20 communities that will benefit from the work performed by TCC and NAB, only the community of Bettles is considered not disadvantaged. Bettles is included in the application because Evansville and Bettles are electrically intertied and neighboring communities; Evansville is a federally recognized tribe. The table below includes residential electricity rates for these communities, before PCE assistance. NAB Community Residential Utility Rate ($/kW-hr) TCC Community Residential Utility Rate ($/kW-hr) Kotzebue $0.41 Allakaket $1.10 Kivalina $0.66 Alatna $1.10 Deering $0.67 Evansville $0.78 Buckland $0.50 Bettles $0.78 Selawik $0.67 Healy Lake $1.00 Noatak $0.67 Eagle $0.89 Kiana $0.73 Rampart $0.81 Noorvik $0.69 Northway $0.65 Ambler $0.86 Arctic Village $1.00 Shungnak $0.77 Kobuk $0.77 The replacement of older diesel engines and gensets through a DERA-like program are expected to result in immediate fuel savings and emissions reductions. Energy efficiency improvements through an expansion of VEEP will reduce diesel consumption, providing immediate cost savings and this program also enhances community safety through improved lighting in public areas and buildings. Upgrades to 19 rural distribution systems are anticipated to significantly reduce line losses, improving energy efficiency and environmental impact. Reduced reliance on diesel generators will lead to lower emissions, better air quality, and lower consumer costs. The work proposed by TCC in this application will provide improved electricity reliability, energy savings costs, access to future renewable energy integration, jobs, community empowerment, and health and safety benefits, and environmental protection to the nine communities benefitted. The work proposed by the NAB in this application will improve efficiency enabling each community to achieve maximum diesel savings and optimize the benefits provided through the recent DOE OCED grant. These improvements will improve reliability, reduce energy burden, create jobs, and provide health and environmental impacts. Four NAB communities (Noatak, Ambler, Shungnak, and Kobuk) receive fuel via air shipment, resulting in per gallon diesel prices in excess of $16. The project’s technical points of contact at AEA, TCC, and NAB will track project’s benefits and avoided disbenefits that are quantifiable and measurable. Reduced GHG emissions from all measures in this application will provide improved public health and mitigate climate impacts over the long term. In addition, less fuel consumption means that fuel deliveries do not have to occur as regularly, resulting in greater resilience to disruptive events concerning fuel conveyance such as freight disruption by weather and disaster that may materially delay fuel shipments. The coalition does not anticipate negative effects on benefited communities. AEA, TCC, and NAB will solicit feedback from communities and engage stakeholders throughout the projects to identify and address potential negative impacts. Community Engagement AEA, TCC, and NAB are accustomed to engaging with local governments and tribal entities through permitting and regulatory processes for rural energy projects. The applicable projects would establish milestones urging earlier dialogue with local governments and Tribal entities. These talks should begin early enough to inform project development in response to local communities’ needs and concerns. Local governments and Tribal entities are uniquely situated to help identify the most effective actions the projects can take toward partnerships that advance workforce issues; diversity, equity, inclusion, and accessibility; and the flow of project benefits to disadvantaged communities. AEA, TCC, and NAB also have established relationships with tribal entities, local governments, and other State departments, with a focus on workforce, permitting, and community development. Early engagement with these stakeholders will help ensure the project is responsive to local energy plans and goals. In line with the infrastructure program and long-term work with the State of Alaska’s CPRG PCAP, the Alaska Municipal League intends to support AEA with planning support, community outreach, progress tracking, and energy data needs. AEA, TCC, NAB will coordinate with AML to develop a stakeholder engagement strategy that focuses on rural, disadvantaged communities and includes municipal and Tribal governments, and public and cooperative utilities. Communication with the public will flow both ways, and outreach will occur at recurring events and in stand-alone community meetings. The community outreach and engagement plan will include: public meetings, both in person and virtual; social media posts; updates on participating organization’s websites; participation in recurring events, such as, Alaska Municipal League Office Hours, Tribal Council meetings, City Council meetings; and, participation in more informal settings, such as the Alaska Federation of Natives Convention, Alaska Rural Energy Conference, the Alaska State Fair, and other energy and environmental conferences held throughout the state. One recurring conference, which AEA, TCC and NAB participate in, that is critical to 20 sharing information amongst rural communities is the Alaska Rural Energy Conference (AREC), scheduled this year for October 2-4, 20249, in Fairbanks, Alaska. The AREC enables communities and experts from around the state to work together and share practical information on energy projects. 5. Job Quality AEA and the coalition members are focused on ensuring the CPRG grant funds and GHG reduction measures offer high-quality jobs within a diverse and skilled workforce. The coalition expects to create new job opportunities, primally in construction, while implementing the GHG reduction measures outlined in our proposal. We expect to create local jobs that will likely be seasonal, part-time work which would provide meaningful employment. The goal is to recruit a diverse pool of workers that is also representative of the communities impacted by these measures. As with most projects in Alaska, those with Alaska experience are preferred. AEA anticipates adding one circuit rider position to support the measures proposed in this application. AEA offers competitive wages, comprehensive health and retirement benefits, tuition reimbursement, 11 paid holidays, and generous leave accrual. As a state agency, AEA is obligated to a fair and transparent procurement process for the bid and selection of all our intended labor per 2 CFR § 200.317. We are committed to fostering safe, healthy, and inclusive workplaces with equal opportunity free from harassment and discrimination and will utilize these funds in alignment with the U.S. Dept of Labor and Commerce Good Jobs Principles. Work performed with this funding will be done in compliance with Alaska public contracting law, which contains provisions for local hire, registered apprenticeship training, prevailing wages, equal employment opportunity and other forward-looking policies. TCC follows a Native preference policy per the requirements of section 7 of Public Law 93-638. The coalition fully intends to follow federal guidelines by including clauses in construction contracts that require construction contractors and subcontractors to pay wages at rates not less than those prevailing, as determined by the Davis-Bacon Act wages and submit certified payroll when necessary. The coalition will participate in the statewide workforce development activities organized by the Alaska Municipal League (AML) for applicants to CPRG implementation grants. This program provides a pathway for the coalition and sub awardees to leverage existing but coordinated recruitment and retention resources, as well as skills development. Funding will be available to provide opportunities for: Recruitment – AML’s partnership with the Associated General Contractors includes the ability for projects to participate in AGC’s We Build Alaska public outreach campaign, which has the ability to geofence and target social media messaging. Skills Development – AML works with the Alaska Safety Alliance, Alaska Works Partnership, University of Alaska, and Alaska AFL-CIO to identify appropriate workforce training opportunities. As workforce needs are identified, including the need for reskilling, they can access any of these partnerships. Career Navigation – AML will coordinate with DOL&WD for access to Alaska Job Centers, as well as through AFL-CIO and other programs, to support project workforce career navigation, including pathways for certification, apprenticeship, and degree programs. Wraparound Services – AML works closely with multiple partners who have mechanisms in place to facilitate childcare, housing, and housing stipends for staff and contractors, especially in conjunction with infrastructure investments across Alaska. AEA and its partners are committed to competitive wages, comprehensive benefits, collaborative health and safety planning, utilization of skilled labor from Registered Apprenticeship programs, collaboration with labor organizations, implementation of second chance hiring policies, and expanding outreach to disadvantaged communities with high unemployment. 21 6. Programmatic Capability and Past Performance a. Past Performance AEA is an independent and public corporation of the State of Alaska, est. 1976, and is the state's energy office and leading agency for statewide energy policy and program development. AEA is governed by a board of directors with the mission to "reduce the cost of energy in Alaska." Our core programs work to diversify Alaska's energy portfolio, lead energy planning and policy, invest in Alaska's energy infrastructure, and provide rural Alaska with technical and community assistance. As the state's designated energy office, AEA has managed hundreds of millions of dollars in federal, state, and private funds to plan and build infrastructure in urban and rural Alaska and is the hub for information exchanges, technical assistance, multiagency coordination, and dynamic pilot projects informing policy decisions and funding solutions for energy and efficiency projects in the future. AEA staffs a full suite of highly qualified individuals, including engineers, planners, project developers, project managers, accountants and finance officers, and policy analysts. AEA has successfully managed, completed, and closed well over three-hundred grants in the last decade, several of which were grant funds from the EPA. We are registered at Grants.gov and SAM.gov, have a UEI number, and have the legal authority to enter a financial assistance relationship with the EPA CPRG program. AEA has mature staff and management systems in place to administer awards. AEA’s Finance and Accounting departments manage the fiscal compliance and reporting requirements for grants and sub-awards. Additionally, AEA staffs a grants department that includes a grants manager and a coordinator. Internal control procedures are in place for compliance reviews, budgetary controls, invoice approvals, project status and financial reporting. AEA hires an independent audit firm to report on compliance for each major federal program, report on internal control over compliance, and report on the Schedule of Expenditures of Federal Awards required by the Uniform Guidance. AEA’s FY2023 Single Audit Report found that the Alaska Energy Authority complied, in all material respects, with the compliance requirements referred to above that could have a direct and material effect on each of its major federal programs for the year ended June 30, 2023. AEA policies and procedures are published on our website, including for Procurement, Governance, Annual Reports, and Audits. The wide array of current and past programs, and grant management experience, ensures that AEA is prepared to manage this project, including through a subaward and project delivery and assessment process. Following is a sample of the many awards AEA manages from federal agencies: Alaska Energy Authority BIL Preventing Outages and Enhancing the Resilience of the Electric Grid Agency: Department Of Energy (DOE) Assistance Agreement No.: DE-GD0000002 CFDA: 81.254 Description: This project is in direct support of Section 40101(d) of the Infrastructure Investment and Jobs Act (i.e., Bipartisan Infrastructure Law). This project's objective is to improve the electric grid's resilience against a disruptive event such as being preventively shut off, or cannot operate safely due to extreme weather, wildfire, or a natural disaster. Contact: Lucas Greza, lucas/greza@netl.doe.gov, (304) 285-4663 2022 Black Rapids Training Center Line Extension Agency: U.S. Department of Defense (DOD) Assistance Agreement No.: DOD-HQ00052210045 CFDA: 12.600 (contract 31201) 22 Description: A 34-mile electrical power line extension to connect the Black Rapids military installation to supply safe, reliable, and efficient grid power. Contact: Tim Robert, timothy.b.robert.civ@mail.mil, (916) 557-7315 State Clean Diesel Emission Reduction Act 2016-2022 Agency: Environmental Protection Agency (EPA) Assistance Agreement No.: DS-01J63901 CFDA: 66.040 Description: Partially fund the replacement of up to twenty-five non-certified and lower tier diesel engines with Tier 2 and 3 marine engines and low PM emitting nonroad engines based on a community prioritization list. Contact: Lucita Valiere, valiere.lucita@epa.gov (206) 553-8087 Tanana Chiefs Conference Federal Low Income Home Energy Assistance Program Funding Source: U.S. DHHS Administration for Children & Families Funding Source Award #: 21PNAKE5C6 Contact: Desiree Joseph desiree.joseph@tananachiefs.org (907) 452-8251, Ext. 3521 Description: This grant provides funds for The Low-Income Home Energy Assistance Program (LIHEAP) helps keep families safe and healthy through initiatives that assist families with energy costs. LIHEAP provides federally funded assistance to reduce the costs associated with home energy bills, energy crises, weatherization, and minor energy-related home repairs. Reporting History and Status: TCC provided regular and timely reporting per the terms of the grant and completed delivery of the varied scope of work. Federal Diesel Emission Reduction Project Manley Hot Springs Funding Source: U.S. EPA GAP Program Funding Source Award #: DE-01J89201 Contact: Sherry Davis davis.sherry@epa.gov 907-271-6322 Description: The project replaced two unregulated diesel gensets located in Manley, AK that were producing at a very inefficient rate with two Tier 3 diesel gensets that are more efficient for the community. The project also included the replacement of manual switchgear with an automatic control system to safely switch between gen-sets, balancing runtime and maximize the life of the system; as well as allow for the power generation system to be prepared to accept renewable power in the future. The project dramatically reduced emissions (75.7% reduction in NOx and 81.5% reduction in PM2.5) positively impacting community health and wellbeing simply by the increased efficiency and is expected to reduce annual diesel usage in the community by 16.4% or 7,154 gallons. b. Reporting Requirements Alaska Energy Authority BIL Preventing Outages and Enhancing the Resilience of the Electric Grid Performance Period: 7/24/2023 - 4/30/2028 This award is active and requires quarterly project and award management reporting. DOE also requires that all projects under this grant adhere to BABA and Davis-Bacon requirements. AEA was awarded at the beginning of the Q3, 2023 and has been obligated to submit for two quarters. AEA has successfully managed grant requirements to-date through close communication with the DOE project officer. 2023 Q3 – Submitted 10/23/23 2023 Q4 – Submitted 1/10/2024 2022 Black Rapids Training Center Line Extension 23 Performance period: 9/1/2022-3/31/2027 This is an active project and AEA has worked cooperatively with the owner agency, Office of Liaison Defense Community Cooperation (OLDCC), and Golden Valley Electric Association (GVEA) to review the conflicts and keep the agency appraised of the revised schedule. AEA submits progress and financial reports through the OLDCC project portal. State Clean Diesel Emission Reduction Act 2016-2022 Performance Period: 10/1/2017 - 9/30/24 In 2015 AEA received the DERA funds via Reimbursable Services Agreement from Department of Environmental Conservation (DEC) and reported through DEC. Starting in 2016, AEA’s relationship was directly with the EPA. AEA’s quarterly reporting, both financial and progress reports, have always been on time. AEA conducted several site monitors, which have resulted in no findings. For this program, AEA submits a final technical report at the end of each award. Tanana Chiefs Conference Federal Low Income Home Energy Assistance Program Start Date: 11-Mar-21 End Date: 30-Sep-22 Reporting History and Status: TCC provided regular and timely reporting per the terms of the grant and completed delivery of the varied scope of work. Federal Diesel Emission Reduction Project Manley Hot Springs Funding Source: U.S. EPA GAP Program Start Date: 1-Oct-20 End Date: 30-Jun-23 Reporting History and Status: TCC provided regular and timely reporting per the terms of the grant and completed delivery of the varied scope of work. c. Staff Expertise Alaska Energy Authority (AEA): Business Point of Contact: Curtis Thayer serves as the Alaska Energy Authority (AEA) executive director. Previously, he was the commissioner for the Department of Administration and cabinet member for Governor Sean Parnell, responsible for 1,100 public employees and an annual budget of $350 million. As part of his public service, he served as the deputy commissioner of the Department of Commerce, Community, and Economic Development, and worked in Washington, D.C. with Alaska’s Congressional Delegation. A graduate of the United States Department of Energy’s National Renewable Energy Laboratory Executive Energy Leadership Institute program, Thayer has gained a comprehensive understanding of advanced energy technologies that has helped him guide his organizations in making energy-related decisions. The project budget and work plan anticipate a 3%-time commitment from Thayer to the project. Tim Sandstrom is AEA’s Chief Operating Officer and will represent Mr. Thayer, directly overseeing the rural energy team. He has been with AEA since 2011 and served as director of rural programs. Sandstrom oversees the management of AEA’s Rural Power System Upgrade, Bulk Fuel Upgrade, Circuit Rider, Emergency Response, and Training Programs. As a senior management team member, he is also responsible for implementing AEA’s strategy and budget management for his programs. With over 35 years in construction, project management, and engineering project management throughout Alaska, Sandstrom brings a broad range of private sector experience to his work. The project budget and work plan anticipate a 3% time commitment from Sandstorm to the project. Technical Point of Contact: Rebecca Garrett, Rural Programs Manager, has been with Alaska Energy Authority since 1997 and has managed projects and programs in varying size and complexity since 1998. She earned her project management professional (PMP) certification and keeps an active registration. 24 She will take on the day-to-day administration of this award, starting by preparing the Project Management Plan. From there, she will assign individual projects to qualified project managers who will provide project oversight, review, and accept plans, procedures, deliverables, and reports. Ms. Garrett will be responsible for project communications between contractors, consultants, and the AEA team. She will track specific contractual deliverables against the schedule to ensure contractors are on track to meet critical milestones. She will be the primary point of contact for the award. The budget and work plan anticipate 25% of Garrett’s time committed to this project. Program/Project Managers: AEA has a team of highly qualified project and program managers who work under Rebecca Garrett, Rural Programs Manager, and Audrey Alstrom Director of Renewable Energy and Energy Efficiency. Staff assignments will be made as projects, and the technologies they will implement become clear. Financial Management: AEA’s Controller will oversee the project’s financial progress. Once the Project Management Plan is accepted, a grant agreement will be issued to the individual project sites. Each Project has a unique project code and grant number used to track each funding source and required match. The finance team will certify financial reports for EPA’s reporting requirements. AEA’s Grants Manager will oversee the award from the EPA and the grant agreement documents with remote Alaskan communities and ensure AEA’s compliance with grant requirements and related reporting. Tanana Chiefs Conference (TCC): Dave Messier, TCC Infrastructure Division Director | Dave Messier will serve as the Project Manager of the project. He has overseen more than $40M in grant funded infrastructure projects in rural, Tribal communities over the past 8 years. Dave manages TCC’s Rural Energy program; in that capacity he works with the various remote power utilities in the TCC region. Dave has many years of project management experience working for small Tribes across the state. He is well equipped to manage the team, develop contracts, provide contract oversight, and operate in accordance with grant provisions. Dave will act as the liaison for all the stakeholders including participating Tribal communities, landowners, contractors, and Tanana Chiefs Conference. Dave has an undergraduate degree with a minor in business from Cornell University, received his MBA in 2012 and is a Certified Project Management Professional. Ben Shilling, TCC Chief Financial Officer | Ben Shilling will oversee all financial aspects of this grant. Ben oversees TCC’s financial reporting, accounting and procurement departments which are directly responsible for the financial management of grants and managing procurement. Within these departments Ben has a team of 22 employees under him at TCC. TCC has over $470 million in assets and over $250 million in annual revenues. Under Mr. Shilling’s leadership TCC has maintained an A+ Bond Rating and has had many years of clean audits with no findings. Ben has been a CPA since 1989 and Certified Information Systems Auditor since 1994. Ben also leads the distribution of both restricted and unrestricted funds to TCC tribes. Dave and Ben will be supported by Edward Dellamary, TCC Rural Energy Specialist to conduct day to day oversight and review of technical deliverables, perform community outreach, prepare grant reports and review technical deliverables. Cortnie Doan, TCC Grants and Office Manager will review invoices and financial account. Northwest Arctic Borough: Ingemar Mathiasson, NAB Energy Manager, works in the NAB’s Economic Development Department. He will be the Project Manager and oversee all aspects of the project. He has developed and managed renewable energy and energy efficiency projects in all 11 communities within the Borough and has been the Project Manager for successful solar, battery, and diesel hybrid systems in Buckland, Deering, Shungnak, and Noatak, along with a biomass construction project in Ambler. Mr. Mathiasson will also ensure community engagement and outreach, in coordination with the Northwest Arctic Energy Steering Committee’s education and outreach efforts. 25 Angie Sturm has been the NAB Treasurer since 2016. Ms. Sturm received her Bachelor of Business Administration degree in Accounting and Management from the University of Alaska Anchorage. Before accepting her position at the Borough, Angie was an Auditor for KPMG, an international accounting firm with an office in Anchorage. She will oversee all financial transactions and financial reporting associated with this project. Alaska Municipal League: Nils Andreassen, AML’s Executive Director, has worked with communities across Alaska for more than 15 years, including to serve in a management role at nonprofit organizations for 10 years. Nils has contributed to State efforts and helped draft its Arctic policy, as well as its Climate Action Plan. Nils serves on the Denali Commission, served on the Governor’s Broadband Task Force, and is on the board of directors of the National League of Cities (NLC). His role in this project is to maintain and cultivate relationships that strengthen delivery of the program, assist with outreach to communities, and contribute input into the strategic direction and deployment of the project. The Alaska Municipal League (AML) is a member-based service organization that works to strengthen Alaska’s 165 cities and boroughs. AML has responded to Executive Order 14008 and the federal prioritization of tackling climate change, environmental justice, and inequity by providing a suite of services that help local governments meet associated goals. AML members and associated Tribal governments can utilize our shared service program to contract for a coordinated approach to addressing equity and environmental justice within the context of project development and implementation. 7. Budget and Timely Expenditure of Grant Funds a. Budget Detail The budget detail is included as an attachment to this application. b. Expenditure of Awarded Funds AEA, TCC, and NAB have developed a project budget and schedule that is reasonable and achievable within a 5-year period of performance. This plan is grounded in previous experience with the type of work proposed in this application and recent cost estimates for equipment, such as diesel engines and electric boilers. AEA, TCC, and NAB have extensive experience in issuing and managing contracts to complete the type of work proposed. The coalition’s procurement teams will issue contracts that include specific deliverables with expenditures linked to milestones and associated completion dates. Reimbursement will be based on completion of specific deliverables and contracts will be written to ensure compliance with the CPRG objectives and timelines. AEA will regularly assess the subawardees’ and contractors’ performance against the timeline and milestones and adjust the plan accordingly to ensure timely completion. AEA, TCC, and NAB use financial management systems that allow for tracking of expenditures and comparison to budgets and will meet regularly with the project teams to assess progress. Each coalition member has experienced financial staff. c. Reasonableness of Costs The proposed budget is grounded in previous experience with the type of work proposed in this application, knowledge of site conditions, and recent cost estimates for equipment, such as diesel engines and electric boilers. Labor rates used in this cost estimate were based on prevailing wage rates for this region as currently established by the US Department of Labor. Additionally, travel was included in the budget for site visits to account for the remote nature of the work. The budget detail attachment includes a narrative description of the budget that supports the values used and the corresponding excel attachment includes a detailed breakout of budgeted costs for each measure. 1 TECHNICAL APPENDIX CPRG – PROPOSAL TO ADDRESS RURAL ALASKA’S CRITICAL ENERGY CHALLENGES GHG Reduction Estimate Method The reduction of diesel fuel consumption is the primary driver of all components proposed in this application to reduce GHG emissions. Before being able to determine the amount of CO2 equivalent that may be reduced, the first agenda was gathering data of previous projects that were identical in scope and determining how much fuel was saved after implementation of these measures. The main source of data, which will be mentioned often in this section, comes from the Power Cost Equalization (PCE) Program.1 This program is the number one most-used resource to gather data for all measures listed in this application. The PCE program was created to provide economic assistance to communities and residents of rural electric utilities where the cost of electricity can be three to five times higher than for customers in more urban areas of the state. AEA, along with the Regulatory Commission of Alaska (RCA), administers the program that serves over 88,000 Alaskans in 193 communities that are largely reliant on diesel fuel for power generation. All communities discussed in this application, whether those used as proxies or the ones to be funded for upgrades if awarded this grant, are all part of the PCE program. Utilities that are eligible for this program submit monthly reports to AEA that document the eligible power sold and PCE credits applied to eligible customers’ bills. AEA calculates the amount of PCE on a monthly basis and issues payment to the utility. At end of each Alaska fiscal year (1 July – 30 June), the PCE report for that year for all eligible communities is generated and posted to AEA’s website.2 Although these particular calculations are not used in determining GHG reductions, their results do provide the metrics needed to determine GHG emission reductions proposed in this application. The four main data points used from each PCE report were: 1) Diesel kWh Generated; 2) Fuel Used (gallons); 3) Line Loss (%); and 4) Fuel Efficiency (kWh per gallon of diesel) Although the calculations are already indicated on each PCE report, the fuel efficiency and line loss data formulas are as follows: Fuel Efficiency (kWh) = Diesel kWh Generated / Fuel Used (gallons) Line Loss (%) = 100 - (Total kWh Sold & Powerhouse Consumption / Diesel kWh Generated) These two metrics that proved valuable in determining if projects funded for distribution and power plant upgrades, reduced GHG emissions. The methods used for gathering data with respect to the diesel genset replacement was EPA’s Diesel Emissions Quantifier (DEQ) tool.3 Required data was input for the baseline engine (engine model currently utilized at various locations requiring upgrade) as well as data for the upgraded engine. Short tons were then converted to metric tons using a standard calculator. Models/Tools Used The models and tools used were the following: EPA Diesel Emissions Quantifier (DEQ); Heat Recovery Simulation Analysis; Power Cost Equalization Reports; EPA GHG Equivalencies Calculator, and multiple excel spreadsheets with formulas 1 Alaska Energy Authority > What We Do > Power Cost Equalization (akenergyauthority.org) 2 Alaska Energy Authority > What We Do > Power Cost Equalization > PCE Reports & Publications (akenergyauthority.org) 3 My Account: Diesel Emissions Quantifier | Diesel Emissions Reduction Act (DERA) | US EPA 2 The DEQ was the primary tool used when calculating GHG reductions for diesel genset replacements. However, some uncontrolled nonroad engines are to be replaced by Tier 2 or 3 marine engines. The DEQ uses load factors, applied to rated engine horse power to determine average engine horsepower for emission calculations. The nonroad and marine engine load factors are different, and are not representative of actual average engine horsepower. Additionally, the DEQ does not directly support comparing emissions reductions unless the baseline and replacement are of the same category (e.g. nonroad -> nonroad, marine -> marine). Therefore, to determine emissions reductions for different engine types accurately, the DEQ calculator was run for each engine separately and the results were exported to Excel for comparison. Below is an example of a DEQ study for a nonroad -> marine engine project exported to excel for comparison. The engines used in this model are as follows: Baseline Engine – John Deere 4039, Non-Certified, 30kW Prime Replacement Engine – John Deere 4045TFM75, Tier 2 Marine, 65kW Prime Figure 1 Nonroad to Marine Engine Comparison In addition to the DEQ, a Heat Recovery Simulation Analysis model is used for distribution upgrade projects as needed. This model is commonly used and provided by an engineering firm that works closely with the applicant on many rural projects: Gray Stassel Engineering (GSE), Inc.4 This firm has supported over 120 communities in Rural Alaska by providing services for many aspects of a project’s life cycle. GSE firm has extensive knowledge and experience with the diesel genset replacements and RPSU programs as they have been directly involved in the design and construction of over 65 diesel power plants design/construction and 30 distribution projects which included small-scale interties to connect neighboring communities. The distribution upgrade projects normally involve heat recovery analysis and implementation in conjunction with upgrading transformers, power lines, and poles. The data required for the heat recovery simulator includes generation metrics from the applicable PCE report, the proposed engine’s heat rejection rates, and the estimated annual heating requirements of the end user buildings. The completed results will indicate has shown for Manokotak’s study below. 4 Gray Stassel Engineering (gse.engineering) 3 Figure 2 Heat Recovery Simulator Once the estimated fuel savings are calculated, this number will be converted into CO2 equivalent by using EPA’s equivalencies calculator which uses Intergovernmental Panel on Climate Change’s (IPCC) standard below: 10,180 grams of CO2 /gallon of diesel = 10.180 x 10-3 metric tons CO2 /gallon of diesel Measure Implementation Assumptions All measures are expected to have a lifetime of at least 20-25 years. When calculating GHG emissions reductions on the DEQ for one Engine A and one Engine B, the results were used to calculate emissions reductions from 2025 through 2050. See two tables below. Genset Replacement # Communities # Engines A - <1M kWh B - >1M - 2M kWh Type A Type B Round 1 Q424 – Q426 3 2 6 4 Round 2 Q325 – Q427 3 2 6 4 Round 3 Q226 – Q428 3 1 6 2 Total 14 28 Table 1 Breakdown of Size Communities/Type Engines Per Round 4 Engine A Engine B Baseline Replacement Baseline Replacement John Deere 4039, Non- Certified John Deere 4045TFM75, Tier 2 Marine CAT3406C Non- Certified Detroit Diesel 6063TK35, Tier 1 – Low PM Emissions Reduced 42.28 metric tons Emissions Reduced 76.75 metric tons Table 2 Engine A and B Results from DEQ With the data above, formulas were inputted to this spreadsheet which indicate how many metric tons of GHG are reduced each year and as diesel genset projects progress during all three rounds. Table 3 Genset Replacement GHG Reductions, 2025-2050 For AEA’s proposed distribution projects, the assumptions were that made that a total of four projects would be completed with CPRG funds. AEA used simulations from four proxy communities to determine GHG reductions. This is a conservative estimate; AEA anticipates completing up to five distribution upgrades. For the Native Village of Manokotak, which was briefly mentioned in Section 1 of the application, studies and simulations have indicated that the project will save the community around 7,000 gallons of diesel fuel per year upon completion. The community of Napaskiak’s distribution upgrade involves the purchase and installation of high-efficiency transformers. This measure would reduce line loss and save the community 3,000 gallons of diesel per year. Nelson Lagoon, a small community apart of the Aleutian Island chain, is in dire need of distribution and heat recovery upgrades. Simulations for this community have also indicated that 7,000 gallons of diesel fuel would be saved once upgrades are complete. Kipnuk’s distribution system is considered in extremely poor condition. Simulations indicate this project would bring the community up to standards, reducing line losses, and 6x Engine A 4x Engine B Total CO2 (MT) 6x Engine A 4x Engine B Total CO2 (MT) 6x Engine A 2x Engine B Total CO2 (MT) 2025 2026 2027 254 307 561 561 2028 507 614 1,121 254 307 561 1,682 2029 761 921 1,682 507 614 1,121 254 154 407 3,211 2030 1,015 1,228 2,243 761 921 1,682 507 307 814 4,739 2031 1,268 1,535 2,803 1,015 1,228 2,243 761 461 1,222 6,268 2032 1,522 1,842 3,364 1,268 1,535 2,803 1,015 614 1,629 7,796 2033 1,776 2,149 3,925 1,522 1,842 3,364 1,268 768 2,036 9,325 2034 2,029 2,456 4,485 1,776 2,149 3,925 1,522 921 2,443 10,853 2035 2,283 2,763 5,046 2,029 2,456 4,485 1,776 1,075 2,850 12,382 2036 2,537 3,070 5,607 2,283 2,763 5,046 2,029 1,228 3,257 13,910 2037 2,790 3,377 6,167 2,537 3,070 5,607 2,283 1,382 3,665 15,439 2038 3,044 3,684 6,728 2,790 3,377 6,167 2,537 1,535 4,072 16,967 2039 3,298 3,991 7,289 3,044 3,684 6,728 2,790 1,689 4,479 18,496 2040 3,552 4,298 7,850 3,298 3,991 7,289 3,044 1,842 4,886 20,025 2041 3,805 4,605 8,410 3,552 4,298 7,850 3,298 1,996 5,293 21,553 2042 4,059 4,912 8,971 3,805 4,605 8,410 3,552 2,149 5,701 23,082 2043 4,313 5,219 9,532 4,059 4,912 8,971 3,805 2,303 6,108 24,610 2044 4,566 5,526 10,092 4,313 5,219 9,532 4,059 2,456 6,515 26,139 2045 4,820 5,833 10,653 4,566 5,526 10,092 4,313 2,610 6,922 27,667 2046 5,074 6,140 11,214 4,820 5,833 10,653 4,566 2,763 7,329 29,196 2047 5,327 6,447 11,774 5,074 6,140 11,214 4,820 2,917 7,736 30,724 2048 5,581 6,754 12,335 5,327 6,447 11,774 5,074 3,070 8,144 32,253 2049 5,835 7,061 12,896 5,581 6,754 12,335 5,327 3,224 8,551 33,781 2050 6,088 7,368 13,456 5,835 7,061 12,896 5,581 3,377 8,958 35,310 Diesel Genset Replacement GHG Reductions 2025 - 2050 Grand Total CO2 (MT) Round 3 Round 1 Year Diesel Genset Replacement In Progress Diesel Genset Replacement In Progress Diesel Genset Replacement In Progress Round 2 5 saving approximately 9,000 gallons of diesel per year. Due to logistics, funding, and feasibility, the projects would be staggered over the 5-year period of performance. Due to this schedule, the reduction measures were calculated as depicted in the table below. Table 4 Distribution Upgrades Implementation Assumptions With the funds requested for VEEP projects, we’re anticipating up to 15 projects to be complete during the period of performance. Project lengths would vary from 18 months or as long as 36 months. The number of anticipated projects and assumed timelines were considered when calculating GHG emissions as indicated on the following table. AEA used historical performance and funding, adjusted for inflation, to estimate the impact of CPRG funding for the VEEP program. From 2016 through 2023, 56 communities were awarded $2.7 million under VEEP; this offset 1,189,463 kWh per year, totaling 830.9 metric tons of CO2 equivalent. AEA adjusted the historical VEEP funding for inflation to determine the amount of kWh reduced per VEEP dollar spent in 2024 dollars, which is shown below, and applied that to the proposed CPRG VEEP budget and then used the EPA’s GHG Equivalencies Calculator to determine GHG reductions. AEA anticipates VEEP funding through CPRG will offset 3,002,198 kWh per year and result in a reduction of 8,388 metric tons CO2 equivalent for 2025 – 2030. GHG Reductions per Year (MT) Cumulative Reductions (MT) GHG Reductions per Year (MT) Cumulative Reductions (MT) GHG Reductions per Year (MT) Cumulative Reductions (MT) GHG Reductions per Year (MT) Cumulative Reductions (MT) 2025 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 2026 59.0 59.0 0.0 0.0 0.0 0.0 0.0 0.0 59.0 2027 59.3 118.3 59.0 59.0 0.0 0.0 0.0 0.0 177.3 2028 59.3 177.6 59.3 118.3 61.0 61.0 0.0 0.0 356.9 2029 59.3 236.9 59.0 177.3 61.0 122.0 26.0 26.0 562.2 2030 59.3 296.2 59.3 236.6 61.0 183.0 26.0 52.0 767.8 2031 59.3 355.5 59.3 295.9 61.0 244.0 26.0 78.0 973.4 2032 59.3 414.8 59.3 355.2 61.0 305.0 26.0 104.0 1,179.0 2033 59.3 474.1 59.3 414.5 61.0 366.0 26.0 130.0 1,384.6 2034 59.3 533.4 59.3 473.8 61.0 427.0 26.0 156.0 1,590.2 2035 59.3 592.7 59.3 533.1 61.0 488.0 26.0 182.0 1,795.8 2036 59.3 652.0 59.3 592.4 61.0 549.0 26.0 208.0 2,001.4 2037 59.3 711.3 59.3 651.7 61.0 610.0 26.0 234.0 2,207.0 2038 59.3 770.6 59.3 711.0 61.0 671.0 26.0 260.0 2,412.6 2039 59.3 829.9 59.3 770.3 61.0 732.0 26.0 286.0 2,618.2 2040 59.3 889.2 59.3 829.6 61.0 793.0 26.0 312.0 2,823.8 2041 59.3 948.5 59.3 888.9 61.0 854.0 26.0 338.0 3,029.4 2042 59.3 1,007.8 59.3 948.2 61.0 915.0 26.0 364.0 3,235.0 2043 59.3 1,067.1 59.3 1,007.5 61.0 976.0 26.0 390.0 3,440.6 2044 59.3 1,126.4 59.3 1,066.8 61.0 1,037.0 26.0 416.0 3,646.2 2045 59.3 1,185.7 59.3 1,126.1 61.0 1,098.0 26.0 442.0 3,851.8 2046 59.3 1,245.0 59.3 1,185.4 61.0 1,159.0 26.0 468.0 4,057.4 2047 59.3 1,304.3 59.3 1,244.7 61.0 1,220.0 26.0 494.0 4,263.0 2048 59.3 1,363.6 59.3 1,304.0 61.0 1,281.0 26.0 520.0 4,468.6 2049 59.3 1,422.9 59.3 1,363.3 61.0 1,342.0 26.0 546.0 4,674.2 2050 59.3 1,482.2 59.3 1,422.6 61.0 1,403.0 26.0 572.0 4,879.8 Project 1 Project 2 Project 3 Project 4 Year AEA Distribution Upgrades 2025 - 2050 Combined Total (MT 6 Table 5 VEEP Project Implementation Assumptions TCC and NAB used similar assumptions and considerations for their proposals, relying on diesel offset to determine GHG reduction and 2023 PCE data as a baseline. NAB’s diesel reductions are driven, in part, by being able to maximize diesel off time at its water and power plants. TCC is anticipating being 50% complete with their projects by end of 2026 and 100% complete in 2027. NAB is anticipating 50% completion by end of 2027 and fully complete in 2028. These assumptions were then applied to the following spreadsheets to calculate their respective emissions reductions. NAB Community Diesel Savings and GHG Reductions are below. GHG Reductions per Year (MT) Cumulative Reductions (MT) GHG Reductions per Year (MT) Cumulative Reductions (MT) GHG Reductions per Year (MT) Cumulative Reductions (MT) 2025 0 0 0 0 0 0 0 2026 699 699 0 0 0 0 699 2027 699 1,398 699 699 0 0 2,097 2028 699 2,097 699 1,398 699 699 4,194 2029 699 2,796 699 2,097 699 1,398 6,291 2030 699 3,495 699 2,796 699 2,097 8,388 2031 699 4,194 699 3,495 699 2,796 10,485 2032 699 4,893 699 4,194 699 3,495 12,582 2033 699 5,592 699 4,893 699 4,194 14,679 2034 699 6,291 699 5,592 699 4,893 16,776 2035 699 6,990 699 6,291 699 5,592 18,873 2036 699 7,689 699 6,990 699 6,291 20,970 2037 699 8,388 699 7,689 699 6,990 23,067 2038 699 9,087 699 8,388 699 7,689 25,164 2039 699 9,786 699 9,087 699 8,388 27,261 2040 699 10,485 699 9,786 699 9,087 29,358 2041 699 11,184 699 10,485 699 9,786 31,455 2042 699 11,883 699 11,184 699 10,485 33,552 2043 699 12,582 699 11,883 699 11,184 35,649 2044 699 13,281 699 12,582 699 11,883 37,746 2045 699 13,980 699 13,281 699 12,582 39,843 2046 699 14,679 699 13,980 699 13,281 41,940 2047 699 15,378 699 14,679 699 13,980 44,037 2048 699 16,077 699 15,378 699 14,679 46,134 2049 699 16,776 699 16,077 699 15,378 48,231 2050 699 17,475 699 16,776 699 16,077 50,328 Year VEEP Projects 2025 - 2050 Group 1 (18 mos) Group 2 (24 mos) Group 3 (36 mos) Combined Total (MT) 7 Table 6 TCC Implementation Assumptions Table 7 NAB Implementation Assumptions Year GHG Reductions per Year (MT) Cumulative Reductions (MT) Year GHG Reductions per Year (MT) Cumulative Reductions (MT) Year GHG Reductions per Year (MT) Cumulative Reductions (MT) 2025 0 0 2034 774 6,581 2043 774 13,549 2026 387 387 2035 774 7,355 2044 774 14,323 2027 774 1,161 2036 774 8,129 2045 774 15,097 2028 774 1,936 2037 774 8,903 2046 774 15,871 2029 774 2,710 2038 774 9,678 2047 774 16,646 2030 774 3,484 2039 774 10,452 2048 774 17,420 2031 774 4,258 2040 774 11,226 2049 774 18,194 2032 774 5,032 2041 774 12,000 2050 774 18,968 2033 774 5,807 2042 774 12,774 TCC Target Communities Year GHG Reductions per Year (MT) Cumulative Reductions (MT) Year GHG Reductions per Year (MT) Cumulative Reductions (MT) Year GHG Reductions per Year (MT) Cumulative Reductions (MT) 2025 0 0 2034 1,590 11,926 2043 1,590 26,237 2026 0 0 2035 1,590 13,516 2044 1,590 27,827 2027 795 795 2036 1,590 15,106 2045 1,590 29,417 2028 1,590 2,385 2037 1,590 16,696 2046 1,590 31,007 2029 1,590 3,975 2038 1,590 18,286 2047 1,590 32,597 2030 1,590 5,565 2039 1,590 19,876 2048 1,590 34,187 2031 1,590 7,155 2040 1,590 21,466 2049 1,590 35,777 2032 1,590 8,746 2041 1,590 23,056 2050 1,590 37,367 2033 1,590 10,336 2042 1,590 24,647 Northwest Arctic Borough Communities 8 GHG Reduction Estimate Assumptions/Measure-Specific Activity Data The heat recovery simulator is a tool used to calculate potential fuel savings. Additionally, assumptions are based on similar projects that have already been implemented. To keep assumptions as realistic as possible, planned projects are compared with past projects that are similar in project scope, genset type, energy demand, population, and location. Data is pulled from PCE reports to determine GHG reductions before and after an emissions-reduction project is completed. From the PCE reports, total diesel kWh generated, total diesel fuel used (gallons), and fuel efficiency are the metrics gathered for review. Line loss is also referenced to indicate if energy efficiency projects funded under VEEP had improved for the community. Furthermore, data is gathered from a community’s report before a project is completed, and then again after it is implemented. Reference Case Scenario (GHG Emissions or Activity Level) Nikolai is a good example of how projects funded under the RPSU program have reduced GHG emissions with fuel savings. Nikolai recently had upgrades to its distribution, heat recovery, power plant replacement, and fuel upgrades. The project began in 2021 and was completed in March 2023. Below is a table of vital data pulled from the PCE reports for fiscal years 2021 – 2023 during that timeframe.5 Nikolai, AK State of Alaska Fiscal Year Diesel kWh Generated Total Fuel Used (gal) Fuel Efficiency (kWh per gal) Line Loss (%) 2021 355,204 37,474 9.48 17% 2022 532,152 55,378 9.61 19.40% 2023 446,222 38,294 11.65 10.30% Table 8 Nikolai PCE Data, 2021-2023 The fuel consumption numbers are misleading. Since 2021, Nikolai’s upgrades allowed for a total of 10,212 gallons of diesel fuel to be displaced. 512 gallons of fuel were displaced in 2022 and 9,700 gallons were displaced in 2023. Those amounts were calculated by using the following method: Fuel efficiency improved with 9.61 kWh per gallon in 2022 versus 2021’s efficiency of 9.48 kWh per gallon. If 2021 had the same efficiency as 2022, it would have saved 512 gallons of fuel because: 355,204 kWh (2021 diesel kWh generated) / 9.61 kWh per gal (2022 fuel efficiency) = 36,961.91 gal 37,474 gal (2021 total fuel used) - 36,961.91 gal (2021 fuel used with 9.61 efficiency) = 512 gal saved For comparison between 2023 and 2022: 532,152 kWh (2022 diesel kWh generated) / 11.65 kWh per gal (2023 fuel efficiency) = 45,678.28 gal 55,378 gal (2022 total fuel used) – 45,678.28 gal (2022 fuel used with 11.65 efficiency) = 9,700 gal saved 5 Alaska Energy Authority > What We Do > Power Cost Equalization > PCE Reports & Publications (akenergyauthority.org) 9 GHG Emissions ReducedThe following tables indicate measure-specific reductions to GHG emissions. Table 5 breaks it down by each specific measure for annual reductions through 2050. Table 6 shows the consolidated amount of GHG reductions from all proposed measures. Table 9 Individual Breakdown of Coalition Measures’ GHG Reduction 1 122 First Ave Fairbanks, AK 99701 907-452-8251 March 22, 2024 Alaska Energy Authority 813 W. Northern Lights Blvd Anchorage, AK 99503 RE: Letter of Intent for EPA-R-OAR-CPRGI-23-07: Alaska Energy Authority, Coalition Application Rural Energy Measure Executive Director Thayer, to join as a coalition member for the coalition application beingsubmitted by the Alaska Energy Authority (AEA) in conjunction with Northwest Arctic Borough (NWAB) and Tanana Chiefs Conference (TCC) for funding through the Climate Pollution Reduction Grants (CPRG) Implementation General Competition for the AEA Diesel Genset Replacement Program (DGR), the Village Energy Efficiency Program TCC is excited to be a part of a potential generational opportunity for transformative impacts on the energy systems of disadvantaged, rural communities in Alaska, especially when considering the array of benefits to be realized from the multi-faceted, programmatic elements of the application, including engine replacements through DGR, upgrades to rural distribution systems, and energy efficiency measures through VEEP. This application is comprehensive and seeks to address those primary barriers to ensuring reliable and safe utility operation, future integration of renewable energy resources, and supporting efficient energy use and practices within those disadvantaged, rural Alaskan communities. These activities promise long-term emissions reductions, greater resiliency to disruptive events, economic and environmental benefits, and improved quality of life. TCC is a committed coalition member on this application and will work in collaboration with AEA and those coalition members in drafting and executing a Memorandum of Agreement (MOA) which addresses all roles and responsibilities required to be undertaken by each member for the successful implementation of the coalition application. TCC understands that July 1, 2024 is the target date for an MOA signed by all coalition members to be made available to the Environmental Protection Agency as required under the CPRG program and will work with other coalition members to achieve this target. 2 122 First Ave Fairbanks, AK 99701 907-452-8251 Sincerely, TANANA CHIEFS CONFERENCE Brian Ridley Chief March 25, 2024 Alaska Energy Authority 813 W. Northern Lights Blvd Anchorage, AK 99503 RE: Letter of Intent for EPA-R-OAR-CPRGl-23-07: Alaska Energy Authority, Coalition Application - Rural Energy Measure Executive Director Thayer, This letter provides notice of the Northwest Arctic Borough's {NAB) formal intent to participate with the Alaska Energy Authority (AEA) and the Tanana Chiefs Conference (TCC) under a coalition application to be submitted by the AEA for funding through the EPA's Climate Pollution Reduction Grants (CPRG) Implementation General Competition. This grant application will include the AEA Diesel Genset Replacement Program (DGR), the Village Energy Efficiency Program (VEEP), and Rural Distribution Measures (the "Project"). The NAB is excited to be a part of a potential generational opportunity for transformative impacts on the energy systems of disadvantaged, rural communities in Alaska especially when considering the array of benefits to be realized from the multi-faceted, programmatic elements of the application including engine replacements through DGR, upgrades to rural distribution systems, and energy efficiency upgrades measures through VEEP. This application is comprehensive and seeks to ensure reliable and safe utility operation, the future integration and maximum use of renewable energy resources, and supports the efficient energy use and practices within disadvantaged, rural Alaskan communities. These activities promise long-term emissions reductions (GHG and criteria pollutants), greater resiliency to disruptive climate change related events, economic and environmental benefits, and improved quality of life. The NAB is a committed coalition member on this application and will work in collaboration with AEA and those coalition members in drafting and executing a Memorandum of Agreement (MOA) which addresses all roles and responsibilities required to be undertaken by each member for the successful implementation of the coalition application. The NAB understands that July 1, 2024 is the target date for an MOA signed by all coalition members to be made available to the Environmental Protection Agency as required under the CPRG requirements and with the coalition, intends to achieve this target. Respectfully, Dickie Moto Mayor, Northwest Arctic Borough Curtis Thayer Alaska Energy Authority 813 W. Northern Lights Blvd Anchorage, AK 99503 March 26, 2024 Re: Climate Pollution Reduction Implementation Grant (CPRG) - Letter of Commitment for proposal to address Alaska’s critical energy challenges Executive Director Thayer, On behalf of the Alaska Municipal League (AML), please accept this letter of commitment for an implementation grant application to the Environmental Protection Agency’s Climate Pollution Reduction Grant program by the Alaska Energy Authority (AEA), as part of a coalition that includes the Tanana Chiefs Conference (TCC) and Northwest Arctic Borough (NAB). In drafting the state plan, we saw the role of the AEA as a key transformative leader contributing to emissions reductions. AML is excited to be a part of a potential generational opportunity for transformative impacts on the energy systems of disadvantaged, rural communities in Alaska especially when considering the array of benefits to be realized from the multi-faceted, programmatic elements of the application including engine replacements through DGR, upgrades to rural distribution systems, and energy efficiency measures through VEEP. In line with our Infrastructure program and long-term work with DEC on the State of Alaska’s CPRG PCAP, we intend to support AEA with planning support, community outreach, progress tracking, and energy data needs. As a sub-recipient, AML will support the application with workforce development infrastructure which will consist of aiding applicants with recruitment, skill development, career navigation, and wraparound services such as childcare, housing and living stipends. AML will work with the Alaska Department of Environmental Conservation (DEC) to establish a statewide tracking and reporting system for CPRG awardees to combine data in a singular database. The system will supplement sub-awardees with technical assistance provided by partners to encourage timely reporting, with methodology consistent with the State’s GHG emissions inventory. Lastly, AML will lead a statewide cohort of awardees to participate in CPRG planning and creation of a sustainability plan. We look forward to this program and AML strongly supports the AEA proposal. Should it be selected, we will partner to initiate long-term emission reduction, greater resiliency to disruptive events, and economic and environmental benefits in Alaska. Sincerely, Nils Andreassen Executive Director Alaska Municipal League Page 1 of 7 BIL 40503: ENERGY AUDITOR TRAINING GRANT PROGRAM CONCEPT PAPER TEMPLATE The DOE created this optional Concept Paper Template to assist with submitting the required Concept Paper information. Each Concept Paper must be limited to a single concept and a single topic area. The Concept Paper must conform to the requirements listed below, including the stated page limits. COVER PAGE (1 page maximum) Control Number: 3204-1516 Project Title: Alaska Commercial Energy Auditors Training Program Specific Topic Area Addressed: Commercial Energy Auditors Prime Applicant Organization: Alaska Energy Authority Lead Project Manager Name and Contact Information: Shaylyn Storms, sstorms@akenergyauthority.org, 907-771-3073 Business Points of Contact Names and Contact Information: Curtis Thayer, cthayer@akenergyauthority.org, 907-771-3009 Names of All Team Members and Organizations: 1. Shaylyn Storms, Alaska Energy Authority Federal Budget Requested (divided among prime and sub-recipients, if applicable): Total Federal Budget Requested: $1,150,964.00 Confidentiality Statements if applicable: Click or tap here to enter text. Page 2 of 7 STATEMENT OF NEED (5 pages maximum) The statement of need must demonstrate the need for assistance to train energy auditors to conduct energy audits or surveys of commercial and residential buildings. As the state energy office with the mission to reduce energy costs in Alaska and the lead agency for statewide energy policy and program development, the Alaska Energy Authority (AEA) requests $1,150,964.00 in funds to support a new commercial energy auditor training program. We intend to host multiple weeklong training seminars with at least two participants from each energy region in Alaska annually (reference Figure 1). As part of this effort, AEA intends to collaborate with the Alaska Housing Finance Corporation (AHFC), our sister agency interested in launching Alaska’s residential energy auditor training program, and may collaborate with the Alaska Department of Labor and Workforce Development to provide a commercial energy auditor training program that will recruit, test, and certify individuals across the state. Alaska has over 2,000 commercial and public facilities but lacks a commercial energy auditor training program and has fewer than 30 total in-state energy auditors, with most located in the state's more populated areas. With so few in-state energy auditors and some larger rural areas having no available auditors, there persists a large imbalance regarding access to such energy audit services. The absence of commercial energy auditors in these regions results in one being flown in any time an organization requires an energy audit, increasing costs and making energy efficiency upgrades prohibitively costly for small, rural, local, and tribal, governments and organizations. Energy audits are critical for assessing and developing cost-effective and efficient energy-saving strategies. Energy audits serve as an initial step for facility owners to understand how energy is used within their respective commercial building envelopes. Energy audits are necessary to determine those options available to commercial building owners and to understand what improvements would result in some measurable energy-cost savings. Energy audits are often required by financial assistance programs designed to aid owners of eligible commercial or residential structures (i.e., grant programs that fund building-scale renewable energy, energy efficiency, and conservation projects) in order to determine the net savings from an energy efficiency measure to understand the pre and post- performance of such energy efficiency improvements. By offering a state commercial energy auditor training program, facility owners can conveniently receive energy audits or surveys from a number of trained auditors to identify cost-effective and high-net-impact energy efficiency measures (EEMs). By implementing EEMs, facility owners and the entire state stand to benefit. For instance, facility owners Page 3 of 7 can save an average of 30% on energy-related costs annually. These saved funds can then be reallocated toward other measures and improvements, helping reduce the overall energy burden for Alaska consumers by increasing the quality of life for those using the building, while also providing for more available discretionary income. Furthermore, executing measures reduces emissions associated with energy production and consumption, reinforcing Alaska’s commitment to energy efficiency and sustainability. In summary, providing this training program will help advance AEA’s mission, contribute to a skilled and capable clean energy Alaskan workforce, which is essential for the successful implementation of our DOE-funded programs, and reduce our state’s carbon-based emissions from unnecessary energy use by commercial buildings. Page 4 of 7 ENERGY AUDITOR TRAINING PROGRAM PLAN (5 pages maximum) Applicants are required to describe succinctly: Project Overview: The proposed energy auditor training program plan that includes: • proposed training curriculum for energy audit trainees; • identification of the covered certification(s) that those trainees will receive on completion of that training curriculum; • expected per-individual cost of training; and • plan for connecting trainees with employment opportunities. 1. Training Curriculum for Commercial Energy Audit Trainees: Ideas • Introduction to Commercial Energy Auditing • Building Energy Systems and Technologies • Energy Audit Techniques and Tools • Energy Modeling and Analysis • Building Codes and Standards • Energy Efficiency Measures and Recommendations • Report Writing and Presentation Skills • Hands-on Field Training and Case Studies • Regulatory Compliance and Documentation CEA Course Objectives • Developing an Energy Audit Strategy and Plan • Energy Use Analysis • Data Collection and Analysis • Economic Analysis • Lighting Systems • HVAC Systems • Domestic Hot Water and Water Conservation • Motors, VFDs, and Compressors • Building Envelope • Building Automation and Energy Management Systems • Alternative Generation and Energy Storage • Energy in Transport 2. Certifications: Trainees will receive the following certifications upon completion: 1. Certified Energy Auditor (CEA) certification from the Association of Energy Engineers (AEE) 2. The American Society of Heating, Refrigerating, and Air-Conditioning Engineers (ASHRAE) Building Energy Assessment Professional (BEAP) certification Page 5 of 7 3. Energy Management Professional (EMP) Certificate - third-party certification 3. Expected Per-Individual Cost: The estimated cost per individual for a weeklong training seminar, including travel with lodging, materials, and certification-related fees, is between $9,500.00 and $9,845.00. Budget Item Cost (On-Time Registration) Cost (Late Registration) Certification-Related Fees: CEA Certification Application and Examination Fees $500.00 $500.00 CEA Retest Fees $250.00 $250.00 CEA Non-Member 4-Day Course Price $1,750.00 $2,095.00 ASHRAE BEAP Application Fees for Non-members $595.00 $595.00 Energy Management Professional (EMP) Certificate (Third-Party Certification) $1,000.00 $1,000.00 Instructor Fee* $392.00 $392.00 Total $4,487.00 $4,832.00 Travel: Round-Trip Airfare $1,000.00 $1,000.00 Ground Transportation $315.00 $315.00 Lodging $1,500.00 $1,500.00 Food $420.00 $420.00 Stipend $1,400.00 $1,400.00 Total $4,635.00 $4635.00 Materials: Study and examination supplies $378.00 $378.00 Total $378.00 $378.00 Grand Total $9,500.00 $9,845.00 * Based on a class of five (5) participants. Cost is subject to change based on class size. 4. Employment Opportunity Plan: AEA aims to support trained auditors through these employment opportunities: 1. Job Placement Assistance: Establish partnerships with local Alaska businesses, energy consulting firms, engineering companies, and (local, state, and federal) government agencies to facilitate job placements for graduates. 2. Networking Events: During the training week, organize virtual and in-person networking events where trainees can connect with potential employers and industry professionals. 3. Resume Building and Interview Skills Workshops: During the training week, workshops will be conducted to assist trainees with resume building, job readiness, and interview preparation. 4. Listserv: Create a listserv for program graduates to learn about job openings in the energy auditing field. Page 6 of 7 Strategic Planning: Describe how the proposed Energy Auditor Training Program Plan supports, coordinates, or collaborates, with the State Energy Program; Energy Efficiency Revolving Loan Fund Capitalization Grant Program; State-Based Home Energy Efficiency Contractor Training Grants; Home Energy Rebates Building Energy Codes, or other relevant programs. There are several ways a Commercial Energy Auditor Training Program can contribute to the success of other relevant programs. 1. The training program's goals can support the objectives of the State Energy Program, which focus on building capacity for energy efficiency improvements, reducing energy consumption, and promoting renewable energy adoption. This support ensures trained commercial auditors contribute to statewide energy goals and initiatives. 2. Audits as required under the Energy Efficiency Revolving Loan Fund and Capitalization Grant Program. The training program will produce trained commercial energy auditors who can fulfill this requirement. Additionally, the results of these audits identify energy-saving opportunities for commercial buildings and help owners understand the benefits of energy efficiency upgrades. 3. The training program can collaborate with other relevant programs focused on similar initiatives. By sharing resources, best practices, and expertise, these collaborations can amplify the impact of energy efficiency efforts and create synergies to address broader energy goals. Leveraging resources, expertise, and partnerships will produce positive outcomes across the state. 4. Commercial audits are often sought out by our applicants applying for Energy Efficiency and Conservation Block Grant (EECBG) Program sub-grants through AEA’s Renewable Energy – Village Energy Efficiency Program (RE-VEEP). RE-VEEP expands on AEA’s Village Energy Efficiency Program (VEEP), established to reduce per capita consumption through energy efficiency. RE- VEEP will award sub-grants to eligible local governments within Alaska to finance building-scale renewable energy, energy efficiency, and conservation projects in public buildings and facilities located in rural Alaska. The training program will increase the number of trained commercial energy auditors in Alaska, making it easier for applicants to find an auditor who can perform the work. Page 7 of 7 ADDENDUM (2 pages maximum) Optional Supports: Applicants may provide graphs, charts, or other data to supplement their Statement of Need and/or Energy Auditor Training Program Plan. Figure 1. Map of Alaska’s Eleven Energy Regions. Page 1 of 8 BIL 40503: ENERGY AUDITOR TRAINING GRANT PROGRAM CONCEPT PAPER COVER PAGE Control Number: 3204-1517 Project Title: Alaska Residential Energy Auditors Specific Topic Area Addressed: Residential Energy Auditors Prime Applicant Organization: Alaska Energy Authority Lead Project Manager Name and Contact Information: Shaylyn Storms, sstorms@akenergyauthority.org, 907-771-3073 Business Points of Contact Names and Contact Information: Curtis Thayer, cthayer@akenergyauthority.org, 907-771-3009 Names of All Team Members and Organizations: Alaska Housing Finance Corporation – • Michael Spencer, Mspencer@ahfc.us, 907-330-8197 • Lars Borson-Paine, Lborson-paine@ahfc.us, 907-330-8198 Cold Climate Housing Research Center - • Mindy O’neall, Mindy@cchrc.org, 907-457-3454 Alaska Department of Labor - • Shena Marcil, shena.marcil@alaska.gov, 907-269-4590 Alaska Energy Rater’s - (to be formed) Federal Budget Requested (divided among prime and sub-recipients, if applicable): $849,036.00 Confidentiality Statements if applicable: Click or tap here to enter text. Page 2 of 8 STATEMENT OF NEED It is simply an understatement to say that in the context of the United States, Alaska has severe and unique climactic zones. This fact and the prevalence of poor-quality housing and high energy costs make energy efficiency paramount within the state. Residential energy use accounts for 7.6% of Alaska’s energy use and can be a significant household expense, with Alaska’s average household spending $4,186 on heating and electricity, over 1.8 times the national average.1 Furthermore, there is considerable variation between regions, with rural and northern communities spending an average of 27% of their annual income on residential energy.2 Approximately 14,600 housing units in Alaska are considered inefficient, which is most pronounced in these rural communities.3 Most of these communities rely primarily on diesel-fueled electric generators for power, creating an opportunity to drastically reduce both emissions and costs by improving energy efficiency in the built environment. Alaska ranks second only to Hawaii in the total share of electricity, with 14% in 2022 generated from petroleum. On a per capita basis, Alaska ranks fourth in the nation in emissions due to its small population and harsh winters.4 As part of its mission to “provide Alaskans with safe, quality, and affordable housing,” Alaska Housing and Finance Corporation (AHFC) has focused on improving energy efficiency statewide for over three decades; however, it is clear that there is still a great need for further efforts. The State of Alaska (SOA) does not certify energy auditors and has delegated these responsibilities to AHFC through statutes and regulations. AHFC houses a long-standing Home Energy Rating System (AKHERS) specific to Alaska’s unusual climate needs, which provides the state's training and testing of residential energy auditors. Additionally, AHFC administers other energy efficiency programs, such as the Alaska Weatherization Assistance Program, supplemental grant programs, and Home Energy Rebate program, and establishes statutorily mandated building and energy code requirements for home financing. As the administrator of these programs, AHFC keenly understands the need for additional residential energy auditors in Alaska. Residential energy auditors both begin and end the process of energy efficiency improvements. They provide the base testing required to assess necessary improvements, have the background knowledge to suggest improvements, model cost savings benefits, and evaluate improvements through post-testing. In this regard, residential energy auditors are crucial to AHFC’s statewide programming to improve energy efficiency. Yet Alaska is facing a workforce shortage at a critical time: AHFC’s AKHERS trained over 150 energy auditors by the end of the State’s 2008 - 2018 Home Rebate Program. Today, there are 29 active Raters statewide. Only one resides in an area designated as rural. With an influx of federal grant programs in the state, including a new Home Energy Rebate (HER) Program, the demand for residential energy audits is anticipated to increase dramatically over the next decade. AHFC anticipates its work in developing the HER Program will result in an additional 20,968 residential energy audits over the coming decade. Further drivers include AHFC’s application for Climate Pollution Reduction Grant funding, which will help supplement residential energy audits for the HER 1 “U.S. Energy Information Administration - EIA - Independent Statistics and Analysis.” n.d. Www.eia.gov. https://www.eia.gov/state/?sid=AK#tabs-2. 2 The Outlook for Energy Costs in Rural Alaska in 2020 – Alaska Village Electric Cooperative. (n.d.). Avec.org. Retrieved March 22, 2024, from https://avec.org/2020/04/12/the-outlook-for-energy-costs-in-rural-alaska-in- 2019/#:~:text=Rural%20households%20spend%2027%25%20of%20their%20annual%20income 3 State of Alaska Priority Sustainable Energy Action Plan Meeting the requirements of the Priority Climate Action Plan for EPA’s Climate Pollution Reduction Grant Program. (n.d.). Retrieved March 22, 2024, from https://www.epa.gov/system/files/documents/2024-03/ak-priority-sustainable-energy- plan.pdf 4 Goodfellow, P., & Birnbaum, M. (2023). Alaska Greenhouse Gas Emissions Inventory 1990-2020 [Review of Alaska Greenhouse Gas Emissions Inventory 1990-2020]. Alaska Department of Environmental Conservation Division of Air Quality. Page 3 of 8 Program, as well as potential future Clean Air Act Compliance, which would require a residential energy audit for each home being sold in Fairbanks, the second most populous city in the state. Due to these drivers, as the state's statutorily mandated training organization for energy auditors, AHFC seeks federal funding to help streamline its training pipeline and certify, at a minimum, an additional 40 raters to meet this incoming need. This need for residential energy auditors is further complicated by the lack of energy auditors in rural areas of the state, where housing improvement needs are the greatest. It is evident through the aforementioned drivers that job openings will be available, and AHFC seeks to ensure that these spots are filled with members of these communities. In many rural parts of Alaska, the workforce is severely limited in capacity because there is not enough work for a contractor to operate in a single town or village. It is common for a contractor to serve a large region and travel from a hub community to smaller communities to maintain enough business. With an influx of new energy auditor demand, these jobs must be developed within these disadvantaged communities. With the proper programming, something AHFC is uniquely positioned to administer, as displayed by its success with its current programs, EAT Grant funding can address the crucial needs of these communities concurrently. The funding will increase workforce development, decrease energy costs, reduce total carbon emissions, and improve the quality of housing, which can be considered a public health concern. Page 4 of 8 ENERGY AUDITOR TRAINING PROGRAM PLAN Project Overview: Training Capacity & Expertise The Alaska Energy Authority (AEA) is an independent and public corporation of the State of Alaska, established in 1976. AEA is governed by a board of directors with the mission to “reduce the cost of energy in Alaska.” AEA is the State Energy Office and lead agency for statewide energy policy and program development. AEA emphasizes community-based project management, whether building modern and code-compliant bulk fuel tank farms, upgrading to high-efficiency generators in rural powerhouse systems, or integrating renewable energy projects. AEA’s core programs work to diversify Alaska’s energy portfolio, lead energy planning and policy, invest in Alaska’s energy infrastructure, and provide rural Alaska with technical and community assistance. AEA has successfully managed, completed, and closed well over 300 grants in the last decade from many different agencies. The Alaska Housing Finance Corporation’s (AHFC) mission is to “provide Alaskans access to safe, quality, affordable housing”. Over the years, AHFC's responsibilities have expanded to include affordable housing programs, energy efficiency, senior housing, and more. Additionally, AEA and AHFC are the primary state entities responsible for state energy initiatives and have a strong, collaborative working relationship. AEA programs include commercial and community- scale energy projects, whereas AHFC programs include residential energy-related projects. As such, AEA and AHFC work or will work collaboratively to administer State Energy Program (SEP), State Energy Program: Bipartisan Infrastructure Law (SEP BIL), Home Energy Rebates (HER), State Energy Program: Energy Efficiency Revolving Loan Fund (SEP EE RFL), and Training for Residential Energy Contractors (TREC) funds for the state. Through this funding opportunity, AHFC will coordinate the Residential Energy Auditor Training program. As the eligible State Energy Office and Prime Applicant for the Energy Auditor Training (EAT) grant, AEA will sub-grant the funds to AHFC to administer the program via a Memorandum of Agreement. AHFC houses a long-standing Home Energy Rating System (AKHERS) specific to Alaska’s unusual climate needs, which provides the training, testing, and continuing education of residential energy auditors. This program is supported by the AHFC-developed and maintained AKWarm Home Energy Rating software system and Alaska Retrofit Information System (ARIS). This database is used to log energy audits. As part of the Alaska Home Energy Rebate System, AHFC maintains a vigorous training process for new residential energy auditors and oversees required continuing education for current residential energy auditors within the state. The State of Alaska (SOA) does not certify energy auditors and has delegated these responsibilities to AHFC through statutes and regulations; as such, AHFC is seeking federal funding to increase Alaska’s residential energy auditor workforce by streamlining its current training curriculum as well as providing financial support for our current mentorship program and the development of a new apprenticeship program. Additionally, AHFC administers other energy efficiency programs, such as the Alaska Weatherization Assistance Program, supplemental grant and energy rebate programs, and establishes statutorily mandated building and energy code requirements for home financing. Proposed Training Curriculum AHFC’s pathway for residential energy auditors is unique in that instead of culminating in a certification, once trainees have completed the required training and building science hours, they can enter into a Page 5 of 8 formal agreement with AHFC, which allows them to conduct residential energy audits within the state. Without this formal agreement, aspiring auditors would be incapable of using AKWarm, the DOE WX- approved energy modeling software required to perform audits within the state. In this way, AHFC is the statewide authority on residential energy auditing at the same level as a covered certification agency. Aspiring residential energy auditors must apply directly to AHFC to enter its certification pathway. However, applicants must have 8,000 or more hours of building science experience before applying. After this requirement is met and trainees are accepted, they must complete four courses—completion of an 80- hour Energy Auditor Course and a general building science course. Applicants are then eligible to continue onto AHFC’s Building Energy Efficiency Standards (BEES) and Methods of Analysis on Residential Structures (MARS) courses, comparable to BPI 1100 and 1200 standards with Alaska-specific considerations. These courses cover combustion safety, air tightness workshop, blower door basics and diagnostics, ventilation requirements and testing procedures, Alaska-specific amendments to the 2018 IECC building code, and require passing scores on written examinations. BEES is available online, while MARS is an in-person training only, potentially burdening trainees from rural areas across this vast state. Lastly, trainees must complete in-person training held by AHFC, focusing on the use of AHFC’s AKWarm Software and ARIS Database. Once these trainings have been completed, AHFC requires new auditors to complete a mentorship program. In this program, AHFC connects new auditors with experienced energy auditor mentors. These auditors are required to conduct a minimum of five residential energy audits, which are evaluated for accuracy by the experienced mentors. Through this pathway, AHFC has demonstrated the ability to educate qualified residential auditors who have been ready to enter the workforce for over a decade. With EAT Grant funding, AHFC seeks to train a total of 40 new residential energy auditors within the grant program’s 36-month operational window. Through this pathway, per-individual direct training costs are expected to be $3,000. Proposed Changes to Training Pathway To meet anticipated workforce needs, AHFC also seeks funding to create a more streamlined residential energy auditor training pathway while maintaining current and vigorous educational standards. To do so, AHFC plans to develop a Residential Energy Auditor Apprenticeship Program with assistance from the Alaska State Department of Labor and Workforce Development. In this program, the current building science hours would be lowered to 4,000 hours, decreasing a currently stringent barrier to entry while increasing the population of potential trainees, specifically in rural areas with fewer workforce opportunities. Once trainees in this track have completed AHFC’s current four-course curriculum, they will be required to apprentice current energy auditors for no less than ten residential audits. Using EAT Grant funds, AHFC will compensate apprentices at a rate of half the average cost of a residential energy audit within the state ($600) while compensating the current energy auditor for the remaining half. This is intentionally structured so trainee wages will not account for more than 10 percent of grant funding. In this way, trainees will receive income and on-the-job training concurrently. While this population of trainees would still need to fulfill AHFC’s mentorship program, AHFC seeks to train 20 additional new residential energy auditors through this track. The direct per-individual training costs for these apprentices are expected to be $6,000, in addition to the costs accrued by the mentorship track. AHFC has contracted with the Cold Climate Housing Research Center to transfer the MARS course to the Canvas Learning Management System. With additional grant funding, AHFC will continue transferring its in-person training to Canvas, specifically the BEES certification and AKWarm training. This will Page 6 of 8 simplify the current training pathway and decrease the direct costs of the training programs for potential applicants. Additionally, this will reduce travel costs and time barriers, specifically for applicants from rural and disadvantaged communities. Workforce Development Through the proposed apprenticeship program, AHFC will connect trainees with current auditors who may choose to expand their business by hiring these new auditors. Additionally, should these new auditors decide to start personal businesses, this apprenticeship program will provide them with business management experience not currently offered through AHFC’s educational track. To address workforce gaps and difficulties in rural areas and address the goals of the Justice40 Initiative, AHFC will partner with the 14 housing authorities across the state to train no less than one new residential energy auditor per housing authority. These new auditors may be current or new housing authority employees. AHFC has a solid working relationship with these authorities in addition to the state-wide Association of Alaska Housing Authorities (AAHA). Strategic Planning: The Research and Rural Development Department at AHFC administers statutorily mandated building and energy codes as well as other energy efficiency programs, such as the Alaska Weatherization Assistance Program (WAP), supplemental grants, and Home Energy Rebate programs, which currently work in congruence with the Alaskan Home Energy Rating System. AHFC is seeking or has received multiple federal grants pertaining to these criteria, all of which would work in concordance with this Residential EAT Grant as they rely on a solid workforce of residential energy auditors. Through these programs, AHFC is working to create a more profound transformation of the residential energy landscape in Alaska that reduces emissions, creates jobs, and provides more affordable, livable housing. Home Energy Rebate Program (HER) AHFC’s Research and Rural Development Department is in the process of developing a Home Energy Rebate Program (HER) with funding made available under the Inflation Reduction Act. AHFC anticipates employment opportunities for trainees due to developing and administering the HER programs section 50121 and 50122, which will present job opportunities to qualified workers. The HER Program will require pre- and post-retrofit energy assessments to be conducted by residential energy auditors in order to qualify households for rebates. Approximately 10,484 households will utilize this program, increasing demand to 20,968 total residential energy audits in the next decade. The EAT Program will be crucial to developing the workforce required to meet this new demand. Training for Residential Energy Contractors It is important to note that although applicable, funding from the Training for Residential Energy Contractors (TREC) award will not be used to train Residential Energy Auditors. Instead, the focus of Alaska’s TREC project’s workforce development program – the Alaska Home Energy Efficiency Training (AK HEET) – will be on 1) building envelope air sealing and insulation training and 2) heat pump consultation and solar installation training. Of course, residential energy auditors will be required to model energy improvements for the anticipated influx of heat pumps within Alaskan households as well as measure improvements in air sealing. Page 7 of 8 Weatherization Assistance Program (WAP) Through the WAP, AHFC provides funding for weatherization retrofits in rural areas of the state. It is important to note that in Alaska, weatherization is not used synonymously with energy efficiency in the built environment. Instead, it refers explicitly to improvements to building shells to weatherize them against the harsh climate. The WAP hires rural contractors using AHFC’s AKWarm technology to assess and improve rural residences, although they are not trained to conduct official residential energy audits. This population of rural contractors, with whom AHFC currently has relationships, are great candidates for the mentorship program training track. This program crossover would significantly improve the state's energy efficiency and weatherization benefits while providing additional workforce opportunities in rural Alaska. Climate Pollution Reduction Grant AHFC has notified the EPA of its intent to apply for $100 million to make funding available for residential weatherization purposes. The primary purpose of this funding will be to enhance AHFC’s existing Weatherization Assistance Program by providing additional funding to service providers and Housing Authorities. Resources may also be allocated to the Supplemental Housing Development Grant program if statutorily allowable. AHFC’s goal is to more than triple the number of households weatherized throughout the state with the funding from this program. A portion of the funding will be used to enhance and expand the upcoming Home Energy Rebate Program through energy rating reimbursements and additional energy rebate incentives. This funding may also be used to establish energy-efficiency-improvement-financing mechanisms that will allow program participants to afford the upfront cost of improvements. State Energy Plan AHFC uses State Energy Plan (SEP) funding to host an annual training for energy efficiency professionals within the state entitled Energy Efficiency Now (EENow). EENow provides required continuing education units (CEUs) for Alaskan residential energy auditors who may otherwise need to travel out-of-state to acquire these CEUs. SEP funding has been approved for two additional EENow trainings, allowing AHFC to use this forum to provide continuing education for the additional residential energy auditors trained using EAT Grant funding. Page 8 of 8 ADDENDUM (2 pages maximum) Optional Supports: Applicants may provide graphs, charts, or other data to supplement their Statement of Need and/or Energy Auditor Training Program Plan. Click or tap here to enter text. 813 W Northern Lights Blvd, Anchorage, AK 99503  Phone: (907) 771-3000  Fax: (907) 771-3044  Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG MEMORANDUM TO: Curtis W. Thayer, Executive Director FROM: Conner Erickson, Director of Planning DATE: March 21, 2024 RE: Naknek-Dillingham Intertie & BESS Project Project Overview The “Naknek-Dillingham Intertie & BESS” (NDIB) Project is a proposed transmission line inter-connecting nine rural, majority Alaska native, disadvantaged communities in the Bristol Bay region. The Project is managed by a team of individuals representing Electric Power Systems Inc (EPS), Nushagak Electric Cooperative (NEC), and Naknek Electric Cooperative (NEC2), collectively the “Applicant team.” Currently, these nine communities currently provide power via their respective independent microgrids. The NDIB is an innovative project which would the first of its kind in rural Alaska. The NDIB is comprised of the construction of a 168 mile 69kV transmission line, which is proposed to be constructed in a cost-effective and innovative method using driven poles and slip joints, in addition to a custom software application which provides for efficient operational and control of the transmission system including the management of waste heat requirements, and economic dispatch. The NDIB would also include two battery energy storage systems (BESS) in Naknek and Dillingham for the regulation of intermittent renewable energy, and for peak-shaving purposes where stored energy can be dispatched during those instances of high-energy-demand from fish processing activities, reducing the frequency of the irregular firing of diesel generators. Project benefits are anticipated to include diesel fuel cost savings, enhanced regional energy resiliency, and the provision of redundant regional power, via the proposed new interconnected transmission grid coupled with the existing, independent diesel powerhouses. Furthermore, the transmission would allow for the future integration and use of the energy which could be generated by the Nuyakuk River Hydroelectric (NRH) Project, a 10- 12 megawatt hydroelectric facility which is currently in the design and permitting phase, including FERC compliance. Hydroelectric energy generated from the NRH is estimated to offset approximately 1.5 million gallons of diesel fuel annually. While AEA has not provided any direct funding to the NDIB, the related NRH project has received $2 million in Renewable Energy Fund (REF) grant funding via two, $1 million dollar grants received in Round 13 and Round 14. Alaska Energy Authority Page 2 of 9 The NDIB in the concept paper was estimated at a total cost of $190 million, which would be split between a federal grant amount of $95 million and a required non-federal cost- match of $95 million. Past Milestones In January 2024, the Applicant team submitted a concept paper to the U.S. Department of Energy’s (DOE) Grip Resilience and Innovation Partnerships (GRIP) Program under GRIP Topic Area 2: Smart Grid Grants. Upon DOE’s review of the application, in a letter from DOE dated February 29, 2024, the Applicant team was encouraged to submit a full application. The full application is due to DOE on April 17, 2024. The NDIB project was included in the list recently provided to the legislature, as requested by Senate Finance, for all outstanding cost-match needs for applications submitted to IIJA/IRA programs. Copies of the submitted concept paper, and the letter of encouragement provided by DOE have been provided for reference as Attachment A, and Attachment B, respectively. Current Status On March 11, 2024, Alaska Energy Authority (AEA) employees met with the Applicant team to discuss the potential GRIP application and to review the project. AEA, as part of the concept paper submission provided a general letter of support for the project (provided for reference as Attachment C), however, no mention of AEA matching funds was made in the letter. AEA has been clear in all its correspondence with the Applicant team that AEA at this time, cannot make any match commitments to the project. During the meeting, it also came as a surprise to AEA, that AEA was stated as the lead applicant for the full application. AEA stated that this was the first time AEA had heard of this. The consensus at the conclusion meeting was that all participants (both from AEA and the Applicants) was that the project was a great project and would be quite innovative for rural Alaska, however, the question of available match and the source of such match remains, with AEA having made no commitments whatsoever. AEA stated to the Applicant team that the question of match, and how it could be provided, was not a problem unique to their project and that there were ongoing difficulties regarding the match for the GRIP 3 sub-sea HVDC line for $206.5 million in the legislature as well. In a recent e-mail from the Applicant team dated March 19, 2024 the following statement correctly summarized the overall sentiment expressed by AEA during the discussion: “the general consensus was that the project [itself] is great, but to ask for that amount of funding and for AEA to be the lead applicant is a bridge too far”. In the same e-mail message, the Applicant team stated that they are investigating other sources of match and that they are appealing to Bristol Bay Native Association (BBNA) to Alaska Energy Authority Page 4 of 9 Attachment A: Copy of GRIP Topic 2 NDIB Project Concept Paper Submission Grid Resilience and Innovation Partnerships Program (GRIP) FOA 3195 Concept Paper Form The following form is to be completely filled out and submitted on https://infrastructure-exchange.energy.gov/. Ensure that the form is saved using the provided button on the bottom of the form. This will ensure that your file is properly submitted. If the button is not used, submission of application cannot be guaranteed. Project Overview Applicant Name: Project Partner(s): Project Name: Applicable GRIP Topic Area: Transmission/Distribution/Combined: Anticipated Total Project Budget: Federal Funds Requested: Applicant Cost Share: Project Details Brief description of the project, including outcomes that would result from the successful completion of the project that align with the strategic goals and objectives of the GRIP program and the applicable GRIP Topic Area. 2,000 character limit. Brief description of the impact of DOE funding on the project. 2,000 character limit. Select the type(s) of technology(ies): List the primary technologies and/or tools that will be deployed in the project. 2,000 character limit. Project Location(s): If selecting multiple items, hold down "Ctrl" button when clicking. If the project will be deploying hardware, describe the role and impact of hardware deployment as part of the proposed project scope and identify any elements of this deployment that represent a significant innovation for the industry and/or project. Enter “N/A” if no hardware will be deployed. 2,000 character limit. If the project will be deploying software, describe the role and impact of software deployment as part of the proposed project scope and identify any elements of this deployment that represent a significant innovation for the industry and/or the project. Enter “N/A” if no software will be deployed. 2,000 character limit. If the project will include development of a new business/regulatory/financing approach, describe the approach and the potential for and path to replicability or broader adoption. 2,000 character limit. Describe the readiness, viability, and expected timing of the project (include the impact of DOE funding in the response). 2,000 character limit. Identify risks and challenges (e.g. technical, labor, financial, market, environmental, regulatory, security) to project success, and outline mitigation strategies for each risk. 2,000 character limit. Briefly describe the Project Management Team and any key personnel and project partners, including vendors and suppliers (if identified; if not yet identified, address how the project will secure vendors/suppliers). Indicate whether the Team has the required skills, any prior applicable experience, prior projects with partners, and access to equipment /facilities to successfully execute the proposed project. If those are not met, explain how the Team will obtain knowledge/access for successful execution. 2,000 character limit. Community Benefits Plan Demonstrate how this Community Benefits Plan will address community and labor engagement, and how feedback from specific and relevant community stakeholders will be incorporated into the Community Benefits Plan. 4,000 character limit. Project Impacts Describe how the project supports State, local, Tribal, community and regional resilience, in reducing the likelihood and consequences of disruptive events, decarbonization, or other energy strategies and plans. 2,000 character limit. What will be the grid-benefitting outcomes to be delivered by the project (e.g. number of customers impacted, unlocked clean energy generation, improvement in reliability metrics). List 1-3 outcomes maximum. 2,000 character limit. How will this project reduce innovative technology risk, achieve further deployment at-scale, and lead to additional private sector investments? 2,000 character limit. Provide expected number of jobs or workforce development opportunities that the project will create. Describe how these positions are the result of community engagement or agreement. Explain how your project will generate quality jobs and that workforce development opportunities provided are relevant to impacted communities. 4,000 character limit. Identify Community Benefits Plan elements that will support Diversity, Equity Inclusion, and Accessibility, including methods to ensure accountability to specific goals throughout the project. 4,000 character limit. Ensure that the form has been fully and correctly completed. Once you have verified that all the information is accurate click the button below. You will not be able to make changes to this form afterwards. Submit the completed form to https://infrastructure-exchange.energy.gov/. Identify how this project will contribute to the Justice40 Initiative goal that 40% of overall benefits flow to disadvantaged communities. 4,000 character limit. Alaska Energy Authority Page 6 of 9 Attachment B: Copy of DOE Letter of Encouragement February 29, 2024 SENT VIA ELECTRONIC MAIL Electric Power Systems, Inc. Patricia Perryman tperryman@epsinc.com SUBJECT: Funding Opportunity Announcement (FOA) no. DE-FOA-0003195, titled “Bipartisan Infrastructure Law (BIL) – Grid Resilience and Innovation Partnerships (GRIP)” – Concept Paper Notification Concept Paper Control Number: 3195-2171 Dear Patricia Perryman: Thank you for submitting a Concept Paper under Topic Area 2 in response to the subject FOA. The Concept Paper for proposed project titled “Naknek-Dillingham Intertie & BESS” was carefully reviewed in accordance with the evaluation criteria in the FOA. Based on the results of the Concept Paper review, your organization is hereby encouraged to submit a full application in accordance with the instructions and requirements contained within the FOA by the due date/time specified on the FOA cover page. Please be advised that receiving a letter of encouragement does not guarantee that an application will be selected for negotiations leading to award. If the Department of Energy (DOE) has identified potential area(s) for improvement based on the concept paper merit review criteria identified in the FOA, it is marked with an “X” (see below). DOE will not provide any additional feedback or guidance beyond what is provided below. The Concept Paper did not propose or thoroughly describe how the proposed work, if successfully accomplished, would clearly meet the objectives as stated in the FOA for the specific topic area. The Concept Paper does not clearly describe how the proposed work aligns with and supports State, local, Tribal, and/or regional resilience, decarbonization, or other energy strategies and plans. The Concept Paper does not adequately identify risks (e.g. technical, financial, market, environmental, regulatory) and challenges, including possible mitigation strategies, to project success. The Concept Paper has not adequately identified, including possible mitigation strategies, technical, operational, and administrative risks to the security of the applicant’s assets. The Concept Paper has not adequately explained the impact of DOE funding. The Concept Paper does not adequately propose strategies and accountability mechanisms to ensure: a. Meaningful community and labor engagement, b. Quality jobs and workforce development, c. Support for Diversity, equity, inclusion, accessibility, d. Supporting the goals of the Justice40 Initiative. Electric Power Systems, Inc. Page 2 of 2 February 29, 2024 _ The proposed project team does not appear to have adequate qualifications, experience, capabilities, and other resources necessary to complete the proposed project. _ The applicant has not adequately provided an estimated total project cost, and/or characterized the project’s economic viability, and/or demonstrated that the project provides enhanced system value and/or provides improved current and future system cost-effectiveness and delivers economic benefit. This letter comprises the sole debriefing the DOE will provide with regard to your Concept Paper. Please also ensure you have carefully read the Registrations Requirements located in the FOA document. There are several one-time actions that must be completed before submitting an application in response to this FOA (e.g., register with the System for Award Management (SAM), obtain a Unique Entity Identifier (UEI) number, etc.). It is vital that applicants address these items as soon as possible. Some may take several weeks, and failure to complete them could interfere with an applicant’s ability to apply to this FOA. The DOE will conduct two webinars in the coming weeks: • On March 5, 2024, 1:00 PM – 2:00 PM EST DOE will conduct a Community Benefits Plan training webinar for applicants that will include important program update information. To register for the webinar, please copy and paste the following link into your browser: https://doe.webex.com/weblink/register/rf943977a9b8d61037c9bacc55cacdb73 • On March 12, 2024, 3:30 PM – 4:30 PM EST DOE will conduct a Program Update webinar that will include more detail on program updates as well as broad guidance to applicants based on our findings from the Concept Paper review process. To register for the webinar, please copy and paste the following link into your browser: https://doe.webex.com/weblink/register/ra5824dcfd55a545813f140b54474b8af • The purpose of these webinars is to discuss and emphasize FOA requirements within the FOA document that applicants may need to focus on in the full application. Attendance is not mandatory and will not positively or negatively impact the overall review of any applicant submissions. Questions will not be taken as part of these webinars. The DOE did not make an applicant eligibility determination as part of the concept paper review. Applicant eligibility determinations will be considered at the full application stage of the FOA process. To be considered for substantive evaluation, an applicant’s submission must meet the criteria set forth in Section III.A of the FOA (Eligible Applicants). If the full application does not meet the eligibility requirements, it will be considered ineligible and removed from further evaluation. The DOE recognizes the significant effort your organization expended to prepare a concept paper in response to this FOA. On behalf of the DOE, the FOA team would like to express our appreciation for your interest in the Grid Deployment Office and this FOA. Sincerely, DE-FOA-0003195 Team Email CC: dburlingame@epsinc.com Alaska Energy Authority Page 8 of 9 Attachment C: Copy of AEA Letter of Support for NDIB Concept Paper Submission Power Cost Equalization (PCE) Endowment Fund (Managed by APFC) Reporting of Investment Gain (Loss) by Month and YTD And Fund Balance by Month as of 02/29/2024 (in Thousands) $14,681 ($9,762)($13,770)($16,140) $34,200 $22,377 ($4,704) $11,408 $14,681 $4,919 ($8,851)($23,989)$10,211 $32,588 $27,884 $39,292 $950,973 $941,098 $927,182 $899,929 $934,034 $957,123 $944,310 $955,392 1.65% -1.10% -1.56% -1.88% 3.85% 2.46% -0.52% 1.25%1.65% 0.55% -1.00% -2.79% 1.15% 3.58% 3.10% 4.31% -4.00% -3.00% -2.00% -1.00% 0.00% 1.00% 2.00% 3.00% 4.00% 5.00% ($200,000) $0 $200,000 $400,000 $600,000 $800,000 $1,000,000 $1,200,000 July August September October November December January February Investment Gain (Loss) Monthly Investment Gain (Loss) YTD Fund Balance Investment Rate of Return Monthly Investment Rate of Return YTD 813 West Northern Lights Boulevard, Anchorage, Alaska 99503 T 907.771.3000 Toll Free 888.300.8534 F 907.771.3044 REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG TO: Curtis Thayer, Executive Director FROM: Rebecca Garrett, Rural Programs Manager DATE: April 2, 2024 SUBJECT: AEA Rural Programs & Projects Highlights Emergency Response AEA declared an emergency in Chignik when an avalanche took out distribution and left the community without power for 4 days in February. The emergency response to the Manokotak emergency has been wrapped up. Final numbers will be generated over the next month. AEA has been assisting with power instability in Mertarvik and a generator end from emergency stock was sent on in March to deal with the most recent outage. The gen-end will be replaced with one the community already had on order from out of state. Active emergency response updates are provided to the board immediately. Training Alaska Energy Authority (AEA), with funding from the Denali Commission, provided training at the Alaska Vocational Technical Center (AVTEC) facility in Seward, Alaska for twelve power plant operators in classes that started January 29th. Three students returned and completed the two week in person lab, the final requirement for certification in early January. These trainings are key components to the maintenance, operations, and extension of the serviceable life of rural energy infrastructure and assets. Furthermore, this provides workforce development including well-paying local jobs in rural communities. Circuit Rider staff offered itinerant training in two communities for powerhouse operators. There are seven training programs for power plant operators, bulk fuel operators, utility management, the Circuit Rider program, and emergency response, with a total budget of nearly $10M. AEA is working with AVTEC to AEA to upgrade the power plant lab. The project will include installing a Detroit diesel engine and upgrade the switchgear so that the lab better resembles a typical rural powerhouse. The project budget is $300K State capital and Denali Commission funding. Rural Power System Upgrades (RPSU) Newly constructed powerhouse modules for Napaskiak and Rampart are currently being assembled in south-central Alaska. Local operators will be invited to Anchorage to participate in Alaska Energy Authority Page 2 of 3 the testing of the module before transporting the modules on-site in the spring. Once the modules are delivered, extensive onsite training will be conducted with the local operators and utility managers before transferring the project over to the community. The Napaskiak and Rampart collectively accrued an estimated total of $10 million. The Rampart on-site construction exceeded the engineer's estimate by over 30%. Project cost increases now exceed 50%. The cost increments are consequences of inflation, logistics delays/unavailability, and workforce deficits. On those accounts, the RPSU Program has started shifting towards maintenance and improvement projects instead of full replacement. Power system upgrades for Nelson Lagoon and Manokotak have been delayed to 2025. AEA continues to work with the communities and seek funding for both of these projects as the designs are coming together. These two projects are estimated at over $10M. The Distribution Inventory and Assessment (I&A) was delayed for a period of time as the survey was completely rewritten over the winter. Six sites have been completed to date and about ten more locations are currently in the queue. AEA was awarded partial funding from a USDA High Energy Cost Grant for a Distribution upgrade in Manokotak. In the next few weeks we will submit grant applications to the Denali Commission for the Tuluksak RPSU, Napaskiak Distribution, and Manokotak Distribution funding shortfall via their competitive funding opportunity. From system replacement to maintenance and improvement to I&A, there are thirty-nine rural power system projects total with an overall budget of over $48M. Bulk Fuel Upgrades (BFU) There are approximately 400 eligible bulk fuel facilities all over Alaska experiencing a growing difficulty with aging infrastructure, deferred maintenance, capacity concerns, foundation failure due to permafrost degradation, environmental threats, and increased ocean/river erosion. These facilities vary from large storage and dispensing facilities to individual tanks outside buildings with an average size approaching 100,000 gallons. AEA has been working on a Bulk Fuel Inventory & Assessment (I&A) and has completed about 200 facilities in about 100 communities. We are about 60% complete with the planned assessments and are planning our operations this season which are expected to complete the project. The I&A will provide accurate information on the current condition of bulk fuel facilities consequentially producing the same benefits realized in the Powerhouse Systems I&A program. Scammon Bay is AEA’s large construction project this year. The ITB closed with an apparent low bidder within budget. When completed, this project is estimated to cost $9-10 million and will include 200,000 gallons of bulk fuel storage. The community will still need a new barge header that will cost $5 million. In today’s market, construction of new bulk fuel tank farms roughly cost between $6-10 million. With limited funding, the BFU program has transitioned heavily towards maintenance and Alaska Energy Authority Page 3 of 3 improvement (M&I) type projects that require local matching funds to ensure project completion. Under this program, each community has a list of maintenance projects, estimated costs, and priority for each project. There are seventeen M&I projects in various stages. Currently, there are thirty-five active bulk fuel projects with a total budget of over $43M. AEA continues to seek funding for the Ekwok BFU project which is fully designed and shovel ready. Bill Short Title Sponsor(s) Status DateHB 121UTILITIES: RENEWABLE PORTFOLIO STANDARD SUMNER (H) ENE 3/17/2023HB 154AK HOUSING FINANCE CORP: SUSTAIN ENERGY RLS BY REQUEST OF THE GOVERNOR (H) FIN 4/19/2023HB 178VILLAGE SAFE WATER FACILITIES FINANCE (H) FIN 4/26/2023HB 227ELECTRIC UTILITY LIABILITY RAUSCHER (H) RLS 3/28/2024HB 256ELECTRIC UTILITY PLANT/FACILITY CLOSURES MCCABE (H) L&C 1/16/2024HB 307INTEGRATED TRANSMISSION SYSTEMS RLS BY REQUEST OF THE GOVERNOR (H) FIN 2/2/2024HB 313PUBLIC UTILITY REGULATORY COST CHARGE RLS BY REQUEST OF THE GOVERNOR (H) L&C 2/9/2024HB 328COMMUNITY ENERGY FACILITIES; NET METERING TOMASZEWSKI (H) ENE 2/15/2024HB 349RENEWABLE ENERGY PROJECT LEASES GROH (H) RES 2/20/2024HB 365POWER COST EQUALIZATION MCCABE (H) ENE 2/20/2024HB 368ELECTRICAL ENERGY & ENERGY PORTFOLIO STDS ENERGY (H) FIN 3/22/2024HB 388COOK INLET RESERVE‐BASED LENDING RESOURCES (H) RES 2/28/2024HB 390AIDEA & AEA GAS OFFTAKE/POWER AGREEMENTS RESOURCES (H) ENE 3/6/2024HB 394RCA REGULATE NATURAL GAS STORAGE FACILITY RESOURCES (H) RES 3/20/2024SB 101UTILITIES: RENEWABLE PORTFOLIO STANDARD TOBIN (S) L&C 3/15/2023SB 118CRITICAL NATURAL RESOURCES; REPORTS MERRICK (S) FIN 2/15/2024SB 125AK HOUSING FINANCE CORP: SUSTAIN ENERGYRLS BY REQUEST OF THE GOVERNOR (S) FIN 4/5/2023SB 152COMMUNITY ENERGY FACILITIES; NET METERING WIELECHOWSKI (S) L&C 5/15/2023SB 217INTEGRATED TRANSMISSION SYSTEMS RLS BY REQUEST OF THE GOVERNOR (S) RES 2/2/2024SB 243ALASKA ENERGY AUTHORITY GOVERNANCE RESOURCES (S) FIN 3/6/2024SB 257ELECTRIC UTILITY REGULATION RESOURCES (S) L&C 3/1/2024SSCR5DISAPPROVE EO 128RLS TRANSM TO 3/26/2024Alaska Energy Authority                                                                                       Bill Tracker ‐ 33rd Legislature                                    Updated 4/5/2024                                                                                                                                                                                                                                                                                                                                                                                                                                                                      Page 1 of 1   Legislative Requests/AEA Responses Date Request Who Assigned to Date answered 4/4/24 GRIP Match Senator Bishop’s office Curtis 4/4/24 4/3/24 State Appropriations 2003-2023 OMB through DCCED Curtis 4/3/24 4/3/24 RPSU – BFU Senator Hoffman’s Office Tim/Curtis 4/4/24 3/28/24 Dock Electrification Senator Stedman’s / Senator Bishop’s Office Curtis 4/1/24 3/22/24 HVDC – GRIP Senator Giessel Curtis 3/29/24 3/20/24 PPF Re-capitalization Representative Donna Mears Curtis 3/20/24 3/19/24 IIJA/IRA match and RPSU-BFU Senator Stedman’s Office Curtis 3/20/24 3/18/24 HB 365 and PCE Representative McCabe through DCCED Curtis 3/18/24 3/04/24 Wheeling Charges Senate Resources Committee Curtis 3/15/24 2/26/24 How much power will Dixon Diversion provide Anne Rittgers, Senator Bishop’s office Curtis 2/2624 2/8/24 Gas generation in Anchorage bowl. Anne Rittgers from Senator Bishop’s Office Curtis 2/8/24 2/5/24 SuWa Hydro Project Status Letter- resend Anneliese from Senator Hughes office Jennifer 2/2/24 1/16/24 Su-Wa Hydro questions Senator Hughes Curtis 1/23/24 12/16/23 Hydroelectric project funding. OMB through Micaela Fowler. Tim / Conner / Curtis 12/15/23 15 year lookback on all energy projects the state has funded in Fairbanks Region. GO and GLO Tim / Curtis 12/18/23 12/1/23 Alaska Energy Security Task Force Report Representative Rauscher’s office (Craig Valdez) Curtis 12/2/2023 11/15/23 How does GRIP Award fit into the “comprehensive statewide energy plan.” How do the two battery banks integrate with Westinghouse Announcement. Representative Mike Prax Conner / Curtis 12/2/2023 MODERNIZING THE RAILBELT GRID Curtis W. Thayer Executive Director Senate Finance Subcommittee March 27, 2024 ALASKA ENERGY AUTHORITY Grid Resilience and Innovation Partnerships 2AEA Modernizing the Railbelt Grid | Senate Finance Subcommittee | March 27, 2024 On October 18, 2023, the U.S. Department of Energy (DOE) announced up to $3.5 billion in Grid Resilience and Innovation Partnerships (GRIP) Program investments for 58 projects across 44 states to strengthen electric grid resilience and reliability across America. In the fall of 2023, AEA was awarded $206.5 million by DOE to advance the Railbelt Innovation Resiliency (RIR) project, which aims to enhance the resiliency and transfer capability along Alaska’s Railbelt. -To utilize the funds, there must be a commitment to match 100 percent —or $206.5 million —bringing the project’s total cost to $413 million. -These federal funds were the result of a successful collaboration between AEA and Railbelt utilities: -Chugach Electric Association -Golden Valley Electric Association -Homer Electric Association -Matanuska Electric Association, and -Seward Electric. -With this DOE funding, Alaska can leverage dollar-for-dollar matching federal investment to expand on transmission upgrades already underway and modernize the transmission system for the benefit of all of the Railbelt communities, while at the same time improve resilience and energy security, diversify its energy portfolio, and accelerate the effective future integration of renewable and clean power. AEA Modernizing the Railbelt Grid | Senate Finance Subcommittee | March 27, 2024 Increases transfer capacity between regions that enables higher renewable energy integration into the electricity system. Improves resilience and reliability for tribal and disadvantaged communities in the Railbelt region, and a reduction in reliance on fossil fuel generation and associated emissions. Supports the retention of high- quality jobs in the region, including 650 highly paid jobs with competitive employer-sponsored benefits. Creates apprenticeship and internship programs to train a new generation of lineworkers and wireworkers to reinvigorate Alaska’s energy workforce. The Railbelt Innovation Resiliency (RIR) project will construct a high- voltage direct current (HVDC) submarine cable to serve as a parallel transmission route from the Kenai Peninsula to Anchorage, creating a much-needed redundant system in case of disruptive events. Anticipated outcomes and benefits include: 3 $413 Million (206.5 Million Federal and $206.5 Million Alaska Match) Railbelt Innovation Resiliency Project: HVDC Submarine Cable HVDC Submarine Cable from Kenai to Beluga 4AEA Modernizing the Railbelt Grid | Senate Finance Subcommittee | March 27, 2024 The RIR project encompasses several projects —one of them being the installation of a new submarine high-voltage direct current (HVDC) transmission line from the Kenai Peninsula across Cook Inlet to the existing Beluga Power Plant —and, if feasible, one or two battery energy storage systems (BESS) in the Central (Anchorage) and Northern (Fairbanks) regions. Location: The project involves connecting the Railbelt’s Southern region (Kenai Peninsula) to the Central region (Anchorage, Matanuska-Susitna Valley) via Beluga with an HVDC submarine circuit. Cable length: Approximately 65 miles total length, 37.5 mile subsea cable/2.5 miles from the landing to Beluga, and 25 miles from the Southern landing to Soldotna. Cable size: The cable is approximately 8” in diameter with roughly 250 megawatt transfer capability. Cable depth to be buried in the seabed: About 4-6 feet deep. Landings may be installed using horizontal directional drilling. Project highlights: 5AEA Modernizing the Railbelt Grid | Senate Finance Subcommittee | March 27, 2024 At its most basic level a BESS consists of one or more batteries that store electrical energy for use at a later time. This stored energy can then be drawn upon when needed to meet various demands for power across different applications. BESS can also provide advantages over other energy storage systems including greater efficiency and flexibility, faster response times when powering equipment or devices, and lower costs overall. Coordinated interregional control and operations of the BESSs and HVDC line will tie all the individual systems together to maximize stability and limit congestion. BESS in Central (Anchorage) and Northern (Fairbanks) Regions 6AEA Modernizing the Railbelt Grid | Senate Finance Subcommittee | March 27, 2024 Schedule The statutory period for the project is eight (8) years and the construction schedule below is based on a design-bid-build process —a traditional project delivery method that consists of three distinct phases in sequence: -Second Quarter 2024 –Award -Summer 2024 –Preliminary Engineering -December 2024 –Complete Preliminary Design -July 2027 –Complete National Environmental Policy Act (NEPA) Process -December 2027 –Contractor Selection -January 2028 to December 2029 –Long Lead Items -January 2030 to December 2031 –Construction 7AEA Modernizing the Railbelt Grid | Senate Finance Subcommittee | March 27, 2024 Why are Transmission Upgrades Needed? Many of the transmission lines and associated equipment serving Alaska were constructed more than 40 years ago. Transmission upgrades are needed to improve Alaska’s resilience and energy security, diversify its energy portfolio, and accelerate the effective future integration of renewable and clean power. Energy Security Energy Diversity Redundant Energy Reliable transmission infrastructure ensures that those projects will be able to connect to the grid and provide energy anywhere it is needed along the Railbelt. As Cook Inlet natural gas supplies decline, new energy projects, including renewable energy, will become increasingly important to our energy security. A second transmission line from the Southern region (Kenai Peninsula) of the Railbelt to the Central region (Anchorage) will ensure power in the event of an emergency shutdown along existing lines. Benefits and Opportunities 8AEA Modernizing the Railbelt Grid | Senate Finance Subcommittee | March 27, 2024 Alaska has a once-in-a-generation opportunity to expand on upgrades underway by leveraging federal funding to modernize the transmission system for all Railbelt communities. Transmission line upgrades and BESS acquisition will provide consumers with multiple benefits, including: Decreased line loss: Upgraded line will substantially reduce energy losses from resistance, contributing to lower energy prices. Grid redundancy and stability: Adds redundancy and stability on the Railbelt by creating an alternate path for generation to flow north and south. Better cost alignment: Align the allocation of resources with traditional utility methodology, i.e. cost causer/cost payer. Rural benefits: Upgrades will benefit rural communities; when energy costs decrease on the Railbelt, residential rates are reduced for communities that receive Power Cost Equalization. Increased resilience and reliability: BESS increases grid resilience and reduces outage risk by supporting load for several hours. New renewable energy: Allows for development of new renewable energy projects on the Kenai Peninsula for consumers. Increased stability: Regardless of fuel supply diversity and decarbonization solutions, these improvements are needed for increased stability. Fiscal Year 2025 GRIP Match 9AEA Modernizing the Railbelt Grid | Senate Finance Subcommittee | March 27, 2024 Appropriations Other Funding Activity Expenditure Funding FY Fed Match Fund Source To Be Determined No Approp Needed Fed State Funds or Source To Be Determined Existing AEA Revenue Bonds ** 2025 206.50 12.70 -20.00 Grant negotiations, bondholder outreach, legal review, and other preparatory costs. Initiate design, engineering, and National Environmental Policy Act (NEPA)/ permitting process for High Voltage Direct Current (HVDC) and Battery Energy Storage Systems (BESS).32.70 12.70 20.00 2026 --6.50 25.00 NEPA process, begin procurement of BESS, site design and engineering.31.50 6.50 25.00 2027 --8.80 -NEPA process.8.80 8.80 - 2028 --21.80 5.00 Complete NEPA process, construct BESS building, begin right-of-way clearing and site preparation.26.80 21.80 5.00 2029 --60.00 - HVDC component construction begins (Soldotna switchyard, Soldotna-Bernice HVDC line, Beluga landing, HVDC submarine cable); BESS testing and commissioning.60.00 60.00 - 2030 --30.95 - HVDC component construction continues (Soldotna switchyard, Soldotna-Bernice HVDC line, Beluga landing, HVDC submarine cable).30.95 30.95 - 2031 --15.75 - HVDC component construction complete (Soldotna switchyard, Soldotna-Bernice HVDC line, Beluga landing, HVDC submarine cable).15.75 15.75 - 2032 ------- 2033 ------- 2034 ------- Total 206.50 12.70 143.80 50.00 206.50 156.50 50.00 413.00 413.00 Grid Resilience and Innovation Partnership Federal Funding and Match Requirement (Thousands) Project Funding Plan as of March 7, 2024 FY2024 AIDEA Dividend $ 6,952.0 Reappropriation from 2012 AEA Project $ 2,294.1 FY2025 AIDEA Dividend $ 3,453.9 FY2025 GRIP Match $12,700.0 Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org Thank You 10AEA Modernizing the Railbelt Grid | Senate Finance Subcommittee | March 27, 2024 MODERNIZING THE RAILBELT GRID Curtis W. Thayer Executive Director Senate Resources Committee March 13, 2024 ALASKA ENERGY AUTHORITY MODERNIZING THE RAILBELT GRID Curtis W. Thayer Executive Director House Resources Committee March 13, 2024 ALASKA ENERGY AUTHORITY AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Railbelt Energy –AEA owns the Bradley Lake Hydroelectric Project, the Alaska Intertie, and the Sterling to Quartz Creek Transmission Line —all of which benefit Railbelt consumers by reducing the cost of power. Power Cost Equalization (PCE) –PCE reduces the cost of electricity in rural Alaska for residential customers and community facilities, which helps ensure the sustainability of centralized power. Rural Energy –AEA constructs bulk fuel tank farms, diesel powerhouses, and electrical distribution grids in rural villages. AEA supports the operation of these facilities through circuit rider and emergency response programs. Renewable Energy and Energy Efficiency –AEA provides funding, technical assistance, and analysis on alternative energy technologies to benefit Alaskans. These include biomass, hydro, solar, wind, and others. Grants and Loans –AEA provides loans to local utilities, local governments, and independent power producers for the construction or upgrade of power generation and other energy facilities. Energy Planning –In collaboration with local and regional partners, AEA provides economic and engineering analysis to plan the development of cost-effective energy infrastructure. About AEA AEA’s mission is to reduce the cost of energy in Alaska. To achieve this mission, AEA strives to diversify Alaska's energy portfolio — increasing resiliency, reliability, and redundancy. 2 AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 AEA Active Projects and Services 3 60+ Subcommittee Meetings 11 Task Force Meetings 150+ Hours of Public Meetings 8 Energy Symposiums with 16 hours of OnDemand learning 6 Subcommittees have created over 60 preliminary actions for considerations: Railbelt Transmission, Generation, and Storage Coastal Generation, Distribution, and Storage Rural Generation, Distribution, and Storage State Energy Data Incentives and Subsidies Statutes and Regulations 4 Alaska Energy Security Task Force 5 MODERNIZING THE RAILBELT GRID Bradley Bradley Lake is Alaska’s largest source of renewable energy. Energized in 1991, the project is situated 27‐air miles northeast of Homer on the Kenai Peninsula. The 120 MW facility provides low-cost energy to 550,000+ members on the Railbelt. Bradley Lake’s annual energy production is ~10% of Railbelt electricity at 4.5 cents/kWh (or ~54,400 homes/year) and over $20 million in savings per year to Railbelt utilities from Bradley Lake versus natural gas. AEA, in partnership with the Railbelt utilities, is studying the Dixon Diversion Project which would increase the annual energy production of Bradley Lake by 50% —or the equivalent of 14,000-28,000 homes. Bradley Lake Hydroelectric Project 6 Bradley Lake generators are rated to produce up to 120 MW of power Bradley Lake generates about 10 percent of the total annual electrical energy sued by Railbelt electrical utilities From 1995 through 2023 the project averaged 390,000 MWh of energy production annually at $0.04 per kWh. CAPACITY ENERGY GENERATION COST PER KWH 120MW 10%$0.04 Alaska Intertie AEA owns the 170-mile Alaska Intertie transmission line that runs between Willow and Healy. The line operates at 138 kV (it was designed to operate at 345 kV) and includes 850 structures. A vital section of the Railbelt transmission system, the Intertie is the only link for transferring power between northern and southern utilities. The Intertie transmits power north into the Golden Valley Electric Association (GVEA)system and provides Interior customers with low-cost, reliable power —between 2006 and 2023, the Intertie saved GVEA customers an average of $36 million annually. The Intertie provides benefits to Southcentral customers as well through cost savings and resilience to unexpected events. Constructed in the mid‐1980s with $124 million in State of Alaska appropriations, there is no debt associated with the Alaska Intertie. 7AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 8AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Railbelt Transmission System Urgently Needs Modernization Grid Forming A grid with alternate paths will increase reliability, resiliency, and fuel diversification. Fuel Savings Upgrades and alternate paths will reduce line losses. Energy Security Natural or other events can isolate cities or regions from energy. The majority of the Railbelt transmission system was constructed over 40 years ago. A resilient, reliable, and redundant Railbelt transmission system is not only achievable but also necessary to create the needed capacity to integrate additional renewable energy in the future. Generation Changes New renewable energy projects are not located in existing cities. New transmission to connect new renewable projects to existing transmission paid for by projects. However, existing transmission must be upgraded to transmit energy to and between the Railbelt regions. AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Grid Resilience and Innovation Partnerships (GRIP): HDVC Line Increases transfer capacity between regions that enables higher renewable energy integration into the electricity system. Improves resilience and reliability for tribal and disadvantaged communities in the Railbelt region, and a reduction in reliance on fossil fuel generation and associated emissions. Supports the retention of high- quality jobs in the region, including 650 highly paid jobs with competitive employer-sponsored benefits. Creates apprenticeship and internship programs to train a new generation of lineworkers and wireworkers to reinvigorate Alaska’s energy workforce. AEA secured $206.5 million for GRIP Topic Area 3: Grid Innovation through the United States Department of Energy’s Grid Deployment Office. A cost share of 100 percent, or $206.5 million, is required for a total project amount of $413 million. The Railbelt Innovation Resiliency project will construct a high-voltage direct current (HDVC) submarine cable to serve as a parallel transmission route from the Kenai Peninsula to Anchorage, creating a much-needed redundant system in case of disruptive events. Anticipated outcomes and benefits include: 9 $413 Million (206.5 Million Federal and $206.5 Million Alaska Match) AEA is studying the Dixon Diversion Project to optimize the energy potential of the AEA-owned Bradley Lake Hydroelectric Project. Like the West Fork Upper Battle Creek Diversion Project, the Dixon Diversion Project would divert water from Dixon Glacier in order to increase Bradley Lake's annual energy production by 50 percent. Located five miles from Bradley Lake and would utilize existing powerhouse at Bradley Lake Estimated annual energy 100,000-200,000 MWh (~24,000-30,000 homes) Estimated to offset 1.5-1.6 billion cubic feet of natural gas per year in Railbelt power generation (equal to 7.5% of Alaska's unmet natural gas demand projected for 2030) Estimated completion is 2030 *Funding will be used for engineering studies (feasibility, hydrological, geological) and environmental studies (fisheries, water quality, geomorphology). 10AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Dixon Diversion Project $5-7 Million for Studies and $342 Million for Construction 11AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Sterling to Quartz (SSQ) and Soldotna to Sterling Transmission Lines In 2020, AEA acquired the SSQ Transmission Line, a critical component of the interconnected Railbelt transmission system on the Kenai Peninsula, as part of the Bradley Lake Hydroelectric Project. Location –39.4 miles of 115 kilovolt (kV) transmission and out of use 69 kV transmission from Sterling to Quartz substation (Kenai Lake) Benefits –AEA ownership ensures better cost alignment, increase reliability, and more timely repairs and upgrades Status –69 kV line decommissioned & removed. Engineers are designing and are procuring equipment for the upgrade of the existing 115 kV line to 230 kV. Upgrade will reduce line losses, increase line reliability and system resiliency Cost –Estimated cost to upgrade line to 230 kV standards is $63 million for SSQ and $27 million for Soldotna to Sterling $90 Million (Under Construction) Battery Energy Storage Systems for Grid Stabilization 12AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Scope –The BESS projects consist of an upgrade to the existing BESS system in the North, and also new BESS systems in the Southern, and Central regions of the grid. The Northern BESS is located at Fairbanks, the Southern BESS is located in Kenai, the Central Region BESS will be located at Anchorage. BESS will be needed to fully realize the benefits of a 230 kV bulk power supply system, regulate energy from various generation, and increase resilience. Schedule –Estimated completion date is 2026: -Southern (Kenai) –In service -Central (Anchorage) –October 2024 -Northern (Fairbanks) –To be determined Budget –Estimated cost is up to $194 million (depending on technology choices and capacity) Benefits –Increase system resilience, transfer capability, more efficient use of system and lowering impediments to additional renewable generation development $194 Million Total Cost ($57 Million Current Available Funds) Grid Resilience Formula Grant Program, IIJA 40101(d) Per IIJA section 40101(a)(1),8 a disruptive event is defined as “an event in which operations of the electric grid are disrupted, preventively shut off, or cannot operate safely due to extreme weather, wildfire, or a natural disaster.” Over the next five years, Alaska will receive $60 million in federal formula grants to catalyze projects to increase grid resilience against disruptive events. In August 2023, the first two years of allocations, $22.2 million, was awarded to AEA. AEA’s competitive solicitation for these funds closed in February 2024. Notification of sub-awards are expected Q2 2024, pending DOE approval. For fiscal year 2025, AEA requested $17,627,018, Alaska’s formula allocation for year 3, in Federal Receipt Authority and $1,816,579 in matching funds. Resilience measures include but are not limited to: -Relocating or reconductoring powerlines -Improvements to make the grid resistant to extreme weather -Increasing fire resistant components -Integrating distributed energy resources like microgrids and energy storage Formula-based funding requires a 15% state match and a 33% small utility match.13 $60 Million (Over Five Years) 14 OTHER FEDERAL FUNDING OPPORTUNITIES AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 State of Alaska Electric Vehicle (EV) Infrastructure Implementation Plan AEA and the Alaska Department of Transportation & Public Facilities (DOT&PF), continue their partnership in deploying the State of Alaska EV Infrastructure Implementation Plan (The Plan). The first round of Alaska NEVI awards was announced on September 25, 2023. AEA and DOT&PF selected projects in nine communities for a total investment of $8 million. The $6.4 million in NEVI funding will be matched with $1.6 million from private entities selected to install, own, and operate the new EV charging stations. On September 29, 2023, the Federal Highway Administration approved the fiscal year 2024 plan. This unlocked $11 million in addition to $19 million available in the fiscal years 2022 and 2023. Phases 2 and 3 of The Plan will develop charging infrastructure in more than 30 communities along the Marine Highway System and in hub communities as funding allows. 15AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 $52 Million (Over Five Years) AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Home Efficiency Rebates Rebates for energy efficiency retrofits range from $2,000-$4,000 for individual households and up to $400,000 for multifamily buildings. Grants to states to provide rebates for home retrofits. Up to $2,000 for retrofits reducing energy use by 20% or more, and up to $4,000 for retrofits saving 35% or more. Maximum rebates amounts are doubled for retrofits of low-and moderate-income homes. Alaska’s Allocation is $37.4 million. No State match is required. Funding is estimated to be available between fall 2024 and spring 2025. Home Electrification and Appliance Rebates Develop a high efficiency electric home rebate program. Inclusive of means testing and will provide 50% of the project cost for incomes ranging from 80% to 150% of area median income. Rebates to cover 100% of the proposed cost for incomes 80% of area medium income and below, with similar tiers applied for multifamily buildings. Includes a $14,000 cap per household, with an $8,000 cap for heat pump costs, $1,750 for a heat pump water heater, and $4,000 for electrical panel/service upgrade. Other eligible rebates include electric stoves, clothes dryers, and insulation/air sealing measures. Alaska’s Allocation is $37.1 million. No State match is required. Funding is estimated to be available between fall 2024 and spring 2025.16 AEA is collaborating with the Alaska Housing Financing Corporation to distribute Alaska’s allocation of $74 Million Home Energy and High Efficiency Rebate Allocations Black Rapids Training Site (BRTS) Defense Community Infrastructure Pilot Program AEA partnered with Golden Valley Electric Cooperative (GVEA) was awarded this grant from the Office of Local Defense Community Cooperation under the Defense Community Infrastructure Pilot Program. Federal Receipt Authority of $12.7 Million received in fiscal year 2024. A $3 million supplemental budget request was submitted by AEA to complete additional work requested by the Department of Defense. No State match is required. $15.7 Million GVEA will use the funds to extend a transmission line 34 miles along the Richardson Highway to BTRS. Currently, BTRS is powered by three diesel generators that are nearing the end of their useful lives. This extension will improve long-term sustainability and reliability for BRTS by tying them into GVEA’s power grid. AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 17 Other Federal Funding Opportunities Energy Efficiency Revolving Loan Fund –$4.5 million $4,569,780 to establish and capitalize a revolving loan fund, under which the State shall provide loans and grants for residential energy audits, upgrades, and retrofits to increase energy efficiency, physical conform and air quality of existing building infrastructure. AEA will administer the program in collaboration with the Alaska Housing Finance Corporation (AHFC). State Energy Program –$3.6 million $3,661,930 to develop Statewide Energy Plan and Statewide Energy Security Profile, as well as (1) update AkWarm Energy Modeling Software to the requirements imposed by the Inflation Reduction Act and (2) modernize Alaska Retrofit Information Systems database to accept the AkWarm modifications in collaboration with AHFC. Electric Vehicle (EV) Charging Equipment Competitive –$1.6 million $1,670,000 to (1) increase access to vehicle electrification in multiple rural and underserved communities across Alaska; (2) demonstrate the benefits of EVs to key decision-makers and the broader public to accelerate clean transportation transition; and (3) support the development of community charging equipment. A 20% match is required, shared by AEA and project partners. Funds will become available in Fall 2023. State-Based Home Energy Efficiency Contractor Training Grant Program –$1.3 million $1.3 million to fund a State-Based Home Energy Efficiency Contractor Training Grant Program to develop and implement a state workforce energy program that prepares workers to deliver energy efficiency, electrification, and clean energy improvements, including those covered by the Inflation Reduction Act Home Energy Rebate Programs. 18AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 AEA and AHFC collaborating to develop a Statewide Solar Program: -AEA focus on development of community solar projects in disadvantaged communities using a Renewable Energy Fund- style grant program. -AHFC focus on residential rooftop solar for low income households. Program benefits include: -energy cost savings, -increased resiliency, -equitable access to solar, -asset ownership benefits low income and disadvantaged, communities, -workforce development, and -reduction in greenhouse gas emissions. This is a competitive grant program —no match required. AEA and AHFC submitted an application for a $100 million grant. Solar For All Competition $100 Million (Application Pending) 19 AEA PROGRAMS AND PROJECTS 20AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 21 Houston Solar Farm, Houston, AK Power Cost Equalization (PCE) The PCE program was established in 1984 as one of the components of a statewide energy plan. The cost of electricity for Alaska’s rural residents is notably higher than for urban residents. PCE lowers the cost of electric service paid by rural residents. Ultimately ensuring the viability of rural utilities and the availability of reliable, centralized power. Residential customers are eligible for PCE credit up to 750 kWhs per month. Community facilities can receive PCE credit for up to 70 kWhs per month multiplied by the number of residents in a community. In the fiscal year 2024, AEA disbursed $42 million to rural electric utilities for the benefit of rural communities. 750 kWh $42M70 kWh RESIDENTIAL PUBLIC FACILITIES FUNDS DISBURSED RURAL COMMUNITIES RURAL COMMUNITIES ALASKANS 188 82 80,000 22 Rural Power Systems Upgrade Bulk Fuel Upgrade ~197 Eligible communities 35 Active projects ~400 Rural bulk fuel facilities 35 Active projects AEA and Federal Partners, Denali Commission (*$2 Million) Rural Power Systems Upgrades and Bulk Fuel Upgrades* Capital Budget -$2.5 Million Capital Budget -$2 Million AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Electric Emergency Response AEA provides support when an electric utility has lost or will lose the ability to generate or transmit power to its customers and the condition is a threat to life, health, and/or property. Funding provides the current level of technical support through the Electrical Emergencies Program. During the fiscal year 2023 there were six (6) electrical emergencies. Power was restored within24 hours in each case. The average cost of an electrical emergency assistance is approximately $45,000 each. 23 Capital Request: General Fund -$200,000 Renewable Energy Fund (REF) AEA, in concert with the REF Advisory Committee, has forwarded to the Legislature a capitalization request of $32 million for Round 16 of the REF. An appropriation of $32 million would fully fund all 24 recommended projects. Funding approval for the REF is at the discretion of the Legislature and Governor. $317 million invested in the REF by the State since inception. 100+ operational projects and 60 are in development. The Department of Energy recently announced $125 million for solar and hydroelectric projects in rural Alaska —several of these projects benefited from seed money from REF totaling almost $12 million. REF Highlights Round 13: 11 Projects –$4.75M Round 14: 27 Projects –$15M Round 15: 18 Projects –$17M Round 16: 24 Projects -Pending AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 24 AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 The PPF loan program continues to see an increase in applications due to federal matching fund requirements and other incentives. The Inflation Reduction Act provides tax credits of up to 40%. A fund capitalization of $25 million would allow for additional funds needed to support the increased demand in funding. The PPF loan program continues to see an increase in applications due to federal matching fund requirements and other incentives. The Inflation Reduction Act provides tax credits of up to 40%. A fund capitalization would allow for additional funds needed to support the increased demand in funding. Power Project Fund (PPF) Loan Program Outstanding Loans $31 Million 16 Loans Competitive Rates Current PPF Interest Rate 5.43% as of March 2024 Pending Applications $755,500 Loans Under Review Uncommitted Cash Balance Program in abeyance until additional capital is secured 25 Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org Thank You 26 APPENDIX 27 SUSITNA -WATANA HYDROELECTRIC PROJECT 28 29AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Susitna-Watana At-A -Glance The proposed Susitna-Watana Hydroelectric Project is a large hydro project that would provide long-term stable power for generations of Alaskans. The project would result in approximately 70% of the power generated in the Railbelt originating from renewable sources, up from the current 15% —a nearly four-fold increase. Dam Height –705 feet Dam Elevation –2,065 Feet Reservoir Length –~42 miles Reservoir Width –~1.25 miles Installed Capacity –618 MW Annual Energy –2,800,000 MWh Cost –~$5.6 billion (2014$) percent estimated supply of current Railbelt energy demand 50 100+ years is the project life providing long- term, stable rates billion estimated energy cost savings ($2014) over first 50 years $11.2 The Susitna-Watana Hydroelectric Project would offset the need for 22.6 billion cubic feet per year of Cook Inlet natural gas if it were operational today. Why Susitna-Watana? 30 31AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 2019 Abeyance Rescinded 2017 Licensing Abeyance Susitna-Watana History . . 32AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Susitna-Watana Employment Opportunities Pre-Construction Employment ~5,000 Direct jobs ~3,870 Indirect jobs Construction Employment ~12,000 Direct jobs ~11,305 Indirect jobs Operations Employment (Life of Project) ~24-28 Direct jobs ~105 Indirect jobs 32,308 Total Jobs 17,028 Direct jobs 15,280 Indirect jobs 33AEA Modernizing the Railbelt Grid | House Resources Committee | March 13, 2024 Susitna-Watana Timeline SENATE BILL 243: AEA GOVERNANCE Curtis W. Thayer Executive Director Senate Finance Committee March 13, 2024 ALASKA ENERGY AUTHORITY Senate Bill 243 Railbelt Energy –AEA owns the Bradley Lake Hydroelectric Project, the Alaska Intertie, and the Sterling to Quartz Creek Transmission Line —all of which benefit Railbelt consumers by reducing the cost of power. Power Cost Equalization (PCE) –PCE reduces the cost of electricity in rural Alaska for residential customers and community facilities, which helps ensure the sustainability of centralized power. Rural Energy –AEA constructs bulk fuel tank farms, diesel powerhouses, and electrical distribution grids in rural villages. AEA supports the operation of these facilities through circuit rider and emergency response programs. Renewable Energy and Energy Efficiency –AEA provides funding, technical assistance, and analysis on alternative energy technologies to benefit Alaskans. These include biomass, hydro, solar, wind, and others. Grants and Loans –AEA provides loans to local utilities, local governments, and independent power producers for the construction or upgrade of power generation and other energy facilities. Energy Planning –In collaboration with local and regional partners, AEA provides economic and engineering analysis to plan the development of cost-effective energy infrastructure. About AEA AEA’s mission is to reduce the cost of energy in Alaska. To achieve this mission, AEA strives to diversify Alaska's energy portfolio — increasing resiliency, reliability, and redundancy. 2 Senate Bill 243 AEA Active Projects and Services 3 The “Why” 4Senate Bill 243 Historical: From 1976 until 1993, AEA was governed by its own board of directors. Distinct Purpose: The underlying purposes of AIDEA and AEA are fundamentally different. Unique Mission: Reduce the cost of energy in Alaska, diversify Alaska’s energy portfolio, and increase resiliency, reliability, and redundancy —and our mission is growing (owned assets, energy data department). Exponential Growth: AEA’s capital budget has increased over 1,000% in the last four years. Distinct Expertise: A distinctive set of skills and expertise is required for optimal governance. It is common and appropriate for a single-purpose entity to have a governing board made up of experts in the topic area. “As governor, I find that it is in the best interests of efficient administration to separate the membership of the board of directors of the Alaska Energy Authority from the membership of the board of directors of the Alaska Industrial Development and Export Authority.” —Executive Order 128 New AEA Board Makeup 5Senate Bill 243 As proposed by the Governor, AEA’s board membership makeup would include: (1) the commissioner of commerce, community, and economic development (2) six public members appointed by the governor as follows: -(A) one member with expertise or experience in managing or operating an electric utility that is not connected to an interconnected electric energy transmission network, as that term is defined in AS 42.05.790; -(B) one member with expertise or experience in developing energy projects in rural communities; -(C) one member with expertise or experience in managing or operating an electric utility connected to an interconnected electric energy transmission network, as that term is defined in AS 42.05.790; -(D) one member with financial expertise in large-scale energy project development; and -(E) two members with expertise or experience in finance, energy policy, energy technology, engineering, law, or economics. AEA’s Exponential Growth 6Senate Bill 243 AEA has received —and anticipates a substantial increase in —federal funding from the Infrastructure Investment and Jobs Act (IIJA) and others, over the next several years. Pipeline of federal funding: -$84 million awarded (Energy Efficiency Conservation Block Grant, Department of Defense Grant, State Energy Planning Grant, National Electric Vehicle Infrastructure grant, and Grid Resilience 40101(d) Grant) -$573.5 million conditionally awarded (Grid Resilience and Innovation Partnerships, Energy Efficiency Reconciliation Loan Capitalization Program, and Home Efficiency and Appliance Rebates) -$104 million competitive applications pending decision (Solar for All, Wood Innovations Grant, and Energy Future Grant, and High-Energy Cost Grant) Availability of tax incentives for clean energy projects and direct pay reimbursement available for tax exempt entities for the first time. In addition to AEA’s netbook value of $1.3 billion, several large projects are underway: -$413 million to build an undersea High Voltage Direct Current from the Kenai Peninsula to Anchorage -$342 million for the Dixon Diversion Project to increase the annual energy production of Bradley Lake by 50 percent (Estimated to offset 1.5 billion cubic feet of natural gas per year in Railbelt power generation) -$90 million for Railbelt transmission upgrades (Sterling Substation and Quartz Creek transmission line) AEA’s Statutory Programs 7Senate Bill 243 Alaska Energy Security Task Force: Development of the Governor’s Alaska Energy Security Task Force Report submitted in December 2023. New federal funding diversifies AEA’s existing statutory programs and projects portfolio including: -Rural Power System Upgrades and Bulk Fuel Upgrades:AEA continues to manage legacy funding for critical rural energy projects and training programs in partnership with the Denali Commission. -Renewable Energy Fund: AEA also manages this competitive grant program, and has received legislative funding for the last three consecutive fiscal years (over $37 million). -Alaska Intertie:AEA-owned transmission asset that saves Interior ratepayers nearly $40 million annually. -Bradley Lake Hydroelectric Project:AEA-owned generation asset that provides 10 percent of Railbelt's energy. o $166 million in Required Project Work will be funded by bond proceeds, which are being planned and will progress over the next several years, such as transmission and battery energy storage systems (BESS). Federal funds for transmission, grid resilience, and other power projects may be leveraged by bond funds to advance energy projects and reduce energy costs in the state. o $342 million for the Dixon Diversion project to increase Bradley Lake's annual energy production by 50 percent. o $90 million for Sterling to Quartz Creek upgrade of the existing 115 kV line to 230 kV currently underway. o $57 million for BESS to increase system resilience, transfer capability, more efficient use of system and lowering impediments to additional renewable generation development. -Power Cost Equalization: AEA manages this annual ~$45 million program vital for rural Alaskans. -Renewable Energy and Energy Efficiency Programs: To promote Alaska's clean energy sector, AEA manages biomass, hydro, solar, and wind programs and projects across the state. Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org Thank You 8 APPENDIX 9 Total Capital Appropriations FY2021 to FY2024 (in thousands) 10Senate Bill 243 INTEGRATED TRANSMISSION LINES Curtis W. Thayer Executive Director Senate Labor & Commerce Committee March 4, 2024 ALASKA ENERGY AUTHORITY About AEA AEA Integrated Transmission Lines | Senate Labor & Commerce Committee | March 4, 2024 2 AEA’s mission is to reduce the cost of energy in Alaska. To achieve this mission, AEA strives to diversify Alaska's energy portfolio — increasing resiliency, reliability, and redundancy. Renewable Energy and Energy Efficiency –AEA provides funding, technical assistance, and analysis on alternative energy technologies to benefit Alaskans. These include biomass, hydro, solar, wind, and others. Grants and Loans –AEA provides loans to local utilities, local governments, and independent power producers for the construction or upgrade of power generation and other energy facilities. Energy Planning –In collaboration with local and regional partners, AEA provides economic and engineering analysis to plan the development of cost-effective energy infrastructure. Railbelt Energy –AEA owns the Bradley Lake Hydroelectric Project, the Alaska Intertie, and the Sterling to Quartz Creek Transmission Line —all of which benefit Railbelt consumers by reducing the cost of power. Power Cost Equalization (PCE) –PCE reduces the cost of electricity in rural Alaska for residential customers and community facilities, which helps ensure the sustainability of centralized power. Rural Energy –AEA constructs bulk fuel tank farms, diesel powerhouses, and electrical distribution grids in rural villages. AEA supports the operation of these facilities through circuit rider and emergency response programs. 3 Foundation of a Dependable Transmission System Resiliency Grid resiliency is defined as the ability to withstand, manage, and respond quickly to disruptions such as severe weather events, equipment failures, or cyberattacks. Reliability Reliability defines standards and system performance such that the system is designed to withstand sudden events. Redundancy An important aspect of grid resiliency and reliability, redundancy is the existence of more than one means for performing a given function. Railbelt Transmission Lines 4 AEA Integrated Transmission Lines | Senate Labor & Commerce Committee | March 4, 2024 5 Railbelt Transmission System Urgently Needs Modernization Grid Forming A grid with alternate paths will increase reliability, resiliency, and fuel diversification. Fuel Savings Upgrades and alternate paths will reduce line losses. Energy Security Natural or other events can isolate cities or regions from energy. The majority of the Railbelt transmission system was constructed more than 40 years ago. A resilient, reliable, and redundant Railbelt transmission system is not only achievable but also necessary to create the needed capacity to integrate additional renewable energy in the future. Generation Changes New renewable energy projects are not located in existing cities. New transmission to connect new renewable projects to existing transmission paid for by projects. However, existing transmission must be upgraded to transmit energy to and between the Railbelt regions. 60+ Subcommittee Meetings 11 Task Force Meetings 150+ Hours of Public Meetings 8 Energy Symposiums with 16 hours of OnDemand learning 6 Subcommittees have created over 60 preliminary actions for considerations: Railbelt Transmission, Generation, and Storage Coastal Generation, Distribution, and Storage Rural Generation, Distribution, and Storage State Energy Data Incentives and Subsidies Statutes and Regulations 6 Alaska Energy Security Task Force Priority A: Railbelt Transmission, Generation, and Storage AEA Integrated Transmission Lines | Senate Labor & Commerce Committee | March 4, 2024 7 Strategies and Actions Strategy A-1: Unify & Upgrade Transmission & Storage Action A-1.1 Unify all existing transmission assets along the Railbelt and Bradley Lake under Alaska Energy Authority or a new not -for-profit regulated utility. Strategy A-2: Diversify Generation Action A-2.1 Adopt Clean Energy Standard and incentives to diversify generation. Action A-2.2 Modify existing statute(s) requiring the Regulatory Commission of Alaska to consider long term diversification goals when approving additional/new Railbelt power generation. Action A-2.3 Progress known near term energy diversification projects to a go/no-go decision: 2.3.1: Dixon Diversion Action A-2.4 Progress known long term energy diversification projects to a go/no-go decision: 2.4.1: Susitna Watana 2.4.2: AKLNG, Bullet Line & Alternatives Strategies and Actions Strategy E-2: Reduce the barriers to private sector investments Action E-2.1 Establish a strategic approach to policy, tax, and program development that stimulates and incentivizes private sector activity that leads to reduced cost, locally sourced, and reliable energy. Priority E: Incentives and Subsidies 8 Northern System Southern & Central System Alaska Energy Authority 813 W Northern Lights Blvd. Anchorage, AK 99503 Phone: (907) 771-3000 Fax: (907) 771-3044 akenergyauthority.org Thank You 9 DATE DESCRIPTION TOPIC AND AUDIENCE LOCATION TEAM MEMBER April 3, 2024 Panelist 2024 Alaska Sustainable Energy Conference (ASEC) Pre-Conference Workshop 2: Transmission and Distribution: The Clean Energy Transitions Secret Weapon Virtual Jim Mendenhall April 2, 2024 Panelist Alaska Infrastructure Development Symposium: State Energy Updates Dena’ina Civic and Convention Center, Anchorage, AK Curtis W. Thayer April 2, 2024 Atendees Alaska Infrastructure Development Symposium: Rural Alaska Bulk Fuel Summit Dena’ina Civic and Convention Center, Anchorage, AK Shannon Apgar-Kurtz, Rebecca Garrett, Dean Maschner, Dawn Molina, Bill Price, Ashley Streveler April 2, 2024 Panelist 2024 ASEC Pre-Conference Workshop 2: Transmission and Distribution: The Clean Energy Transitions Secret Weapon Virtual Bill Price April 1, 2024 Attendee Railbelt Reliability Council Board Meeting CIRI Office, Anchorage, AK Bill Price April 1, 2024 Host Dixon Diversion Terrestrial Meeting Virtual Bryan Carey March 29, 2024 Interview Electric Vehicle Tech (EV) Educational Documentary Production by Launch Alaska AEA Office Curtis W. Thayer, Audrey Alstrom March 28, 2024 Vendor Booth AEA EV Program, Anchorage Transporation Fair Alaska Airlines Center, Anchorage, AK Quinlan Harris, Yosty Storms March 25, 2024 Media Follow Up Railbelt Upgrades, TIm Lydon, Alaska Magazine Email Brandy M. Dixon March 22, 2024 Host/Presenter Alaska Electric Vehicle Working Group (AKEVWG) Technical Session: Microtrends and Winter vs. Summer Performance Virtual Audrey Alstrom March 22, 2024 Attendee Utility Working Group Comms Monthly Check-In Virtual Brandy M. Dixon March 19, 2024 Host Dixon Diversion Terrestrial Meeting Virtual Bryan Carey March 18, 2024 Media Interivew AEA Update, Tim Bradner with Alaska Economic Report and Legislative Digest for KTOO Capital Views Virtual Curtis W. Thayer March 14, 2024 Attendee 2024 ASEC Planning Committee Virtual Brandy M. Dixon March 11, 2024 Media Interview Railbelt Upgrades, Tim Lydon, Alaska Magazine Phone Curtis W. Thayer March 7, 2024 Newsletter AKEVWG March Newsletter Sent to 274 Recipients Email Brandy M. Dixon March 6, 2024 Media Response AEA Response to ACEP Railbelt Decarbonization Study Article by Mikel Insalaco, Alaska Business Email Brandy M. Dixon, Bryan Carey, Conner Erickson, Bill Price, Curtis W. Thayer March 6, 2024 Panelist 2024 ASEC Pre-Conference Workshop 1: Utility Decision-Making: Navigating Constraints, Innovating for the Future Virtual Curtis W. Thayer March 5, 2024 Host Dixon Diversion Joint Agency and Public Meeting Virtual Bryan Carey March 4, 2025 Attendee Railbelt Reliability Council Board Meeting BP Energy Center Anchorage, AK Bill Price February 29, 2024 Attendee 2024 ASEC Planning Committee Virtual Brandy M. Dixon February 28, 2024 Speaker AEA Update Presentation on Grid Modernization (Specifically the Anchorage to Healy Phase) to the Greater Fairbanks Chamber of Commerce: Energy, Environment & Natural Resources Committee Virtual Curtis W. Thayer February 22, 2024 Media Interview Chignik Power Restored, Christina McDermott, KDLG in Dillingham Phone Curtis W. Thayer February 20, 2024 Presenter AEA Overview and Programs Update Presentation to Fairbanks Economic Development Corporation: Energy for All Alaska Task Force Virtual Curtis W. Thayer February 19, 2024 Attendee Utility Working Group Comms Monthly Check-In Virtual Brandy M. Dixon AEA COMMUNITY OUTREACH Last Updated on April 3, 2024 (6-Month Look Back) 813 W Northern Lights Blvd, Anchorage, AK 99503 • Phone: (907) 771-3000 Fax: (907) 771-3044 • Email: info@akenergyauthority.org • Website: akenergyauthority.org DATE DESCRIPTION TOPIC AND AUDIENCE LOCATION TEAM MEMBER February 15, 2024 Attendee 2024 ASEC Planning Committee Virtual Brandy M. Dixon February 14, 2024 Presenter AEA Overview and Programs Update to Greater Fairbanks Chamber of Commerce In Person Curtis W. Thayer February 8, 2024 Newsletter AKEVWG February Newsletter Sent to 266 Recipients Email Brandy M. Dixon February 7, 2024 Presenter AEA Overview and Programs Update to Southeast Conference Virtual Curtis W. Thayer February 7, 2024 Presenter AEA Presentation to Alaska Forum on the Environment In Person Audrey Alstrom, Conner Erickson February 6-9, 2024 Attendee/Opening Remarks 2024 National Association of State Energy Officials (NASEO) Energy Policy Outlook Conference The Fairmont, Washington, DC Curtis W. Thayer February 6, 2024 Media Interview Bond Package, James Brooks, Alaska Beacon Phone Curtis W. Thayer February 6, 2024 Host Public Notice: Joint Agency and Public Meeting Virtual Bryan Carey February 5, 2024 Attendee Railbelt Reliability Council Board Meeting CIRI Office Anchorage, AK Bryan Carey, Bill Price February 1, 2024 Presenter AEA Executive Order 128 Overview Presentation to House Energy Committee In Person Curtis W. Thayer February 1, 2024 Presenter AEA Overview and Programs Update to House Energy Committee In Person Curtis W. Thayer January 31, 2024 Host/Presenter AEA RE-VEEP Informational Presentation to Applicants In Person Yosty Storms January 31, 2024 Presenter AEA Overview and Programs Update to Alaska Power Association In Person Curtis W. Thayer January 29, 2024 Press Release AEA releases 2023 REF Impact and Evaluation Report Email/Social Media Brandy M. Dixon January 25, 2024 Vendor Booth AEA Vendor Booth at the Mat-Su Transportation Fair Fairgrounds, Ravel Hall, Palmer, AK Quinlan Harris, Yosty Storms January 24, 2024 Presenter AEA SESP Presentation to NASEO Island Cohort In Person Audrey Alstrom January 22, 2024 Media Interview Executive Order 128, James Brooks, Alaska Beacon Phone Curtis W. Thayer January 18, 2024 Host AKEVWG Technical Session: DriveOhio – Construction and Opening of the first NEVI-Funded Sites In-Person/Virtual AEA EV Team January 18, 2024 Attendee 2024 ASEC Planning Committee Virtual Brandy M. Dixon January 17, 2024 Presenter AEA ARPPOW Meeting to Rural Operator Virtual Kyle Killmer January 12, 2024 Newsletter AKEVWG January Newsletter Sent to 266 Recipients Email Brandy M. Dixon January 9, 2024 Host/Presenter Renewable Energy Grant Fund Advisory Committee Meeting In Person/Virtual Karen Bell, Conner Erickson January 9, 2024 Media Inquiry Manokotak, Christina McDermott, KDLG Radio in Dillingham Phone Call Tim Sandstrom February 5, 2024 Attendee Railbelt Reliability Council Board Meeting CIRI Office Anchorage, AK Bryan Carey, Bill Price January 4, 2024 Attendee 2024 ASEC Planning Committee Virtual Brandy M. Dixon January 2, 2024 Press Release AEA opens application for $22.1 million in grid resilience sub-awards Email/Social Media Brandy M. Dixon December 21, 2023 Podcast Alaska Powerline Podcast, Michael Rovito, Alaska Power Association Virtual Curtis W. Thayer December 20, 2023 Press Release AEA awarded $1.67 million from DOE for EV charging infrastructure in rural Alaska Email/Social Media Brandy M. Dixon December 19, 2023 Press Release AEA announces $2.6 million in grants available for rural energy projects Email/Social Media Brandy M. Dixon December 14, 2023 Newsletter AKEVWG December Newsletter Sent to 265 Recipients Email Brandy M. Dixon December 14, 2023 Host/Presenter AKEVWG Technical Session: Car Dealership Panel Discussion Virtual Josi Hartley December 14, 2023 Attendee Utility Working Group Comms Monthly Check-In Virtual Brandy M. Dixon December 11, 2023 Press Release AEA launches a new digital library of over 7,500 items Email/Social Media Brandy M. Dixon December 8, 2023 Media Interview Alaska National Electric Vehicle Infrastructure (NEVI) Plan, Madeleine Ngo, The New York Time Phone Call Curtis W. Thayer, Josi Hartley December 6, 2023 Presenter AEA Federal Funding Presentation to 73rd Annual Alaska Municipal League Local Government Conference In Person Conner Erickson AEA Community Outreach Page 2 of 3 DATE DESCRIPTION TOPIC AND AUDIENCE LOCATION TEAM MEMBER December 6-8, 2023 Attendee/Presenter/Vendor Booth 73rd Annual Alaska Municipal League Local Government Conference Dena’ina Civic and Convention Center, Anchorage, AK Audrey Alstrom, Katherine Aubrey, Karen Bell, Brandy M. Dixon, Conner Erickson, Josi Hartley, Anna M. Larsen, Taase Toli-Moana, Bill Price, Curtis W. Thayer November 29, 2023 Attendee/Presenter Legislative Forum: Energy Generation and Transmission Legislative Information Office, Anchorage , AK Brandy M. Dixon, Curtis Thayer, Tim Sandstrom November 28, 2023 Presenter AEA Overview and Funding Opportunities Presentation to 33rd Annual Bureau of Indian Affairs' Tribal Providers Conference In Person Audrey Alstrom November 28-30, 2023 Attendee/Presenter/Vendor Booth 33rd Annual Bureau of Indian Affairs' Tribal Providers Conference Dena’ina Civic and Convention Center, Anchorage, AK Audrey Alstrom, Katherine Aubrey, Karen Bell, Brandy M. Dixon, Conner Erickson, Josi Hartley, Quinlan Harris, Dawn Molina, Khae Pasao, Bill Price, Yosty Storms, Karen Turner November 23, 2023 Presenter AEA and Task Force Overview Presentation to Golden Valley Electric Association In Person Curtis W. Thayer November 15, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. Thayer November 15, 2023 Presenter Institute of Electrical and Electronics Engineers, Alaska's Electric Vehicles Program In Person Josi Hartley November 9, 2023 Newsletter AKEVWG November Newsletter Sent to 270 Recipients Email Brandy M. Dixon November 9, 2023 Media Inquiry Inflation Reduction Act Home Rebate Programs, Madeleine Ngo, The New York Times Email Brandy M. Dixon November 9, 2023 Attendee Utility Working Group Comms Monthly Check-In Virtual Brandy M. Dixon November 7, 2023 Press Release AEA and DOT&PF Receive FHWA Approval for FY24 Alaska NEVI Plan Email/Social Media Brandy M. Dixon November 7, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. Thayer November 7, 2023 Media Interview Grid Resilience and Innovation Partnership Program Award, James Brooks, Alaska Beacon Phone Curtis W. Thayer October 31, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. Thayer October 30, 2023 Media Inquiry Renewable Energy in Alaska, Jim Carlton, The Wall Street Journal Phone Brandy M. Dixon October 26, 2023 Host AKEVWG Technical Session: Site Host Selection, Schedule and Path Forward In-Person/Virtual Josi Hartley October 26, 2023 Media Inquiry Alaska Energy Security Task Force Report Public Testimony, Tim Ellis, KUAC Fairbanks Email Brandy M. Dixon October 23, 2023 Media Inquiry GRIP 1 and 2 Applications Status, Alan Bailey, Petroleum News Email Brandy M. Dixon October 19-20, 2023 Host Power Cost Equalization Walk-In Information Session at the 2023 Alaska Federation of Natives Convention William A. Egan Civic & Convention Center, Anchorage, AK Katherine Aubrey October 18, 2023 Press Release Press Release AEA Secures $206.5 Million from U.S. DOE to modernize Alaska’s energy infrastructure Email Brandy M. Dixon October 16, 2023 Media Inquiry Alaska NEVI Plan, Tim Bradner, Frontiersman Email Brandy M. Dixon October 16-19, 2023 Attendee 2023 National Association of State Energy Officials (NASEO) Annual Meeting Hilton Portland Downtown, Portland, OR Curtis W. Thayer October 16, 2023 Media Inquiry Alaska NEVI Plan, Tim Bradner, Frontiersman Email Brandy M. Dixon October 16, 2023 Newsletter AKEVWG October Newsletter Sent to 266 Recipients Email Brandy M. Dixon October 16, 2023 Media Inquiry Energy Efficiency and Conservation Block Grant Program, Jenny Willoughby, KTNA Email Brandy M. Dixon October 13, 2023 Press Release AEA Awarded $1.6 Million in U.S. DOE Funds for Clean Energy Projects in Alaska Email/Social Media Brandy M. Dixon October 13, 2023 Media Interview Village Energy Efficiency Program, Haley Lehman, Fairbanks Daily News-Miner Phone Curtis W. Thayer October 10, 2023 Host Alaska Energy Security Task Force Meeting In-Person/Virtual Curtis W. Thayer AEA Community Outreach Page 3 of 3 813 W Northern Lights Blvd, Anchorage, AK 99503  Phone: (907) 771-3000  Fax: (907) 771-3044  Email: info@akenergyauthority.org REDUCING THE COST OF ENERGY IN ALASKA AKENERGYAUTHORITY.ORG RGYAUTHORITY.ORG Launch Alaska interviews AEA for Electric Vehicle Tech Educational Documentary On Friday, March 29, Curtis W. Thayer, AEA executive director, and Audrey Alstrom, AEA director of renewable energy and energy efficiency programs, were interviewed by Launch Alaska as part of the development of an educational video to inform consumers and policymakers about electric vehicle (EV) technology capabilities in Alaska and beyond. With support from the United States Department of Energy’s Energy Program for Innovation Clusters and partners, this series of technology demonstrations will generate valuable vehicle performance data and showcase the viability of EVs to complete critical tasks in Arctic and sub-Arctic environments. Participating companies and organizations will receive the following considerations in the 2024 EV Tech Challenge documentary: (1) name and logo included in the video credit sequence, (2) on-stage acknowledgment during the documentary premiere event in Fall 2024, and (3) name listed in all promotional materials developed to support the documentary. Son carrying on Jim White legacy; re-entering Pelch well in Kenai page 2 Vol. 29, No. 13 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of March 31, 2024 • $2.50 l EXPLORATION & PRODUCTION l FINANCE & ECONOMY l MEET ALASKA Willow’s on the way ConocoPhillips seeing banner season on the North Slope, from east to west By STEVE SUTHERLIN Petroleum News C onocoPhillips Alaska is in full swing with construction for its Willow project on the North Slope in the National Petroleum Reserve, which is estimated to produce 180,000 barrels of oil per day at its peak. “At ConocoPhillips we’re incredibly busy with drilling in major projects all across the Slope from Kuparuk all the way out to Willow,” Connor Dunn, vice president, Willow, said in a presentation to the Alaska Support Industry Alliance at its Meet Alaska event in Anchorage March 22. In addition to Willow, the company is proceeding with development of satel- lites in Kuparuk and continued explo- ration in the western North Slope area, Dunn said, adding that in a few years he expects to see some 2 billion to 3 billion barrels or more of development arise from these efforts. “In all, ConocoPhillips has drilled nearly 68 exploration wells since the year 2000, including 28 in the NPR-A, and that’s generated significant exploration and devel- opment opportunities,” he said. “Willow gets a lot of the fanfare,” he said. “There’s over $7 billion to first oil in 2029 but ANS in consolidation ANS up 10.1% YTD, on track for solid Q1 2024; OPEC+ plus cuts supportive By STEVE SUTHERLIN Petroleum News A laska North Slope crude added 13 cents March 27 to close at $85.62 per barrel, while West Texas Intermediate slid 27 cents to close at $81.35 and Brent slid 16 cents to close at $86.09. The Alaska benchmark extended its recent con- solidation in the mid $80s after trading in a tight $1.19 range over the trading week ending March 27. Wednesday to Wednesday, ANS gained just 7 cents from its March 20 close of $85.55. On March 27, ANS closed at a $4.27 premium over WTI, and at a 47-cent discount to Brent. ANS is on track for a solid first quarter, up $7.86 or 10.1% year to date on March 27. WTI and Brent saw YTD gains of 10.74% and 8.39% respectively. Quarterly gains were supported by supply cuts from the Organization of the Petroleum Exporting Countries and its allied exporting countries includ- ing Russia. The wisdom of Herrera A strange similarity between geologists and climatologists feeds disparity By STEVE SUTHERLIN Petroleum News I n 1960 I came to Alaska straight out of college in the UK and was given a job by BP as an exploration geologist,” Roger Herrera said in remarks to Meet Alaska March 22 in Anchorage. “I cut my teeth here in Alaska in the days when there were no maps, only oblique aerial photographs, which were very distorted and not much information, so you started from scratch.” Herrera, reprising his role as closing speaker at the first Meet Alaska in 1984, shared that he trav- eled the world to many lands, taking the “broad consensus of the area I was in as far as its geological potential is concerned.” “A field geologist never has enough information or hard data; if he or she doesn’t have a fairly vivid imagination — perhaps a disciplined one but never- theless vivid — they’re not going to be any good at all because most of the rocks are hidden from them.” The rocks of interest are either under the ground or inaccessible on the surface, he said. You must work it out with intelligence and persuade somebody to spend tens of millions of dollars to drill a well and make a discovery. Herrera spent some 20 years “doing that sort of see CONOCO UPDATE page 7 see OIL PRICES page 7 see HERRERA’S WISDOM page 6 see INLET GAS page 5 No commercial hydrocarbons in Bear 1, per ConocoPhillips 10-K In its 2023 10-K, ConocoPhillips reported on its Bear 1 wild- cat, saying that “no commercial hydrocarbons were found and the well was deemed a dry hole and permanently plugged and aban- doned.” The well was “at a location 30 miles south of the Greater Kuparuk Area and east of the Colville River on state lands.” Bear 1, which was on oil and gas lease ADL 393519, was spud in late February and completed on April 3, 2023. The lease is nei- ther contained within any existing unit nor adjacent to any ConocoPhillips unit. As previously reported, prior to completion ConocoPhillips Alaska President Erec Isaacson described the company's Bear 1 well as a Brookian Topset play, which was what the Oil see TAKE REGULATION page 6 9th Circuit OKs incidental take regs, with rework of 1 component On March 19 a three-judge panel in the U.S. Court of Appeals for the 9th Circuit issued a majority decision regarding a U.S. Fish and Wildlife Service five-year incidental take regulation for the minor disturbance of polar bears and walruses in the southern Beaufort Sea and adjacent lands. The decision requires FWS to rework one aspect of the regulation but also allows the regulation to remain in place meantime. One judge on the panel issued a dis- senting decision, arguing that the regulation, as it stands, should be fully approved. The regulation was designed to enable oil and gas exploration and development activities to be carried out in the region. Impact on polar bears? Several environmental organizations have argued that Pikka and nearby oil discoveries together could rival Kuparuk Yereth Rosen’s recent article in the Alaska Beacon about two speakers at the March 22 Meet Alaska conference carried highlights from Santos about its plans for the future that are worth highlighting. The speech by Connor Dunn, a senior vice president with ConocoPhillips Alaska who oversees the Willow project, was covered by Petroleum News’ Steve Sutherlin in a separate article in this issue. Mark Ireland, senior vice president for subsurface and exploration at Santos, the company that is see SANTOS HIGHLIGHTS page 5 see BEAR 1 WELL page 6 Sims: Not price, but market size preventing more gas development Is there a lot of natural gas remaining in Cook Inlet? Yes, Enstar President John Sims told the Resource Development Council March 21. Would offering producers a higher price lead to development of more volumes? That hasn’t worked. Sims said Enstar has offered higher priced contracts but that didn’t result in additional volumes of natural gas offered under contract. He said it’s not the market price for Cook Inlet natural gas that’s holding back exploration and production to meet the JOHN SIMS MARK IRELAND ROGER HERRERA CONNOR DUNN “ “Russia’s actions could push the Brent oil price to $90 already in April, reach mid- $90 by May and close to $100 by September, keeping pressure on the U.S. administration in the run-up to elections,” J.P. Morgan said. looming natural gas shortage, it’s the small market size, which means companies can’t, in a reasonable amount of time, earn returns from the needed massive investment. The problem is the expense — in the bil- lions — for development and the very small and isolated market, Sims said. With fewer than 800,000 people in the state, and natural gas usage of just 70 billion cubic feet per year, companies can’t earn a return on their investment in a reasonable amount of time, he said. In the Lower 48, by contrast, there is a population of millions and a corresponding- ly large and connected market for resources from any new project. Enstar’s role Enstar’s role in the natural gas market is as a certificated public utility, which means it has a duty to serve not shared by produc- ers, independent power producers or any- one else, Sims said. It must provide gas. And not just to residential and retail cus- tomers. Other utilities in Enstar’s service area can call on Enstar to provide them with gas service, he said, as when Homer Electric Association wasn’t able to renew its con- tract for natural gas and turned to Enstar. HEA had been an Enstar transportation customer, but after it requested to be a gas sales customer, Enstar is now on the hook for HEA, he said, and over several months was able to negotiate a contract with Hilcorp for the volumes needed to serve HEA. But, Sims said, the contract covering the HEA volumes isn’t the type of firm contract Enstar has for its own volumes, which includes a penalty for non-delivery. The HEA contract excludes that provision. And it isn’t just HEA, Sims said: other utilities, Chugach Electric Association and Matanuska Electric Association, are also in Enstar’s service territory. It happened in the past with Fairbanks Natural Gas: it came to Enstar when its contracted supplier in Cook Inlet couldn’t deliver, he said. Enstar’s share of the 70 bcf per year gas requirement is about half, 35 bcf, and with the addition of HEA is up to some 40 bcf. The old HEA contract ends this March, and Enstar’s contract for the HEA volumes starts April 1. Enstar’s own existing contract runs through 2033, but contracts for the other utilities expire before then. Scope of the problem Sims said the group studying how to resolve the problem, Enstar and the other utilities working with BRG and Cornerstone, isn’t ready to reveal the full draft of its Phase II report, but he said Phase II has whittled the utilities’ options down to four. And none of those options meet the 2028 4-year milestone when some gas contracts start to expire. Liquefied natural gas is needed, and shipments would need to begin arriving in 2027 to get volumes into storage for 2028. Permitting is the greatest time unknown in the process — Federal Energy Regulatory Commission and U.S. Corps of Engineers permitting durations, and the time to modify or construct in-water piers. None of the proposed projects meets the 2028 date, with three of the four having start dates in 2029 or 2030, while a fourth starts only in 2032. Legislative action needed What can be done locally? Sims said incentives from the Legislature — tied to firm contracts for Cook Inlet utilities — are essential because of the inability of the market to provide the needed investment. There are a lot of ideas being floated in Juneau, he said, but urged focus on solu- tions the producers have told legislators are necessary for investment, particularly royal- ty reduction. Sims said royalty reductions would need to be tied to firm contracts with the utilities for the gas. While strong support for Cook Inlet exploration and production is needed in the short term, the long-term focus needs to be on action on a large natural gas supply proj- ect. Storage, carbon sequestration In addition to more supply, more gas storage is also needed. Sims said CINGSA, Cook Inlet Natural Gas Storge Alaska, a subsidiary of Enstar, has won approval from the Regulatory Commission of Alaska to add two wells at its Kenai-area storage facility, providing additional production capability. In response to a question from the audi- ence, Sims said additional storage in Cook Inlet beyond CINGSA is also needed. Renewables can provide power, but nat- ural gas will continue to be required when wind and solar aren’t available, and to meet peak needs, he said. A functioning transmis- sion system is crucial for renewables to work, and Sims urged support for the $200 million needed from the Legislature to match federal funds available to upgrade the transmission system. Carbon sequestration is also important because it is becoming a requirement for companies to gain financing — Sims said it is as crucial as storage. Residents and businesses are on the hook for cost impacts and illustrated the impact on the Anchorage School District — not even Enstar’s largest customer — with the cost of gas alone $4.9 million in 2023, a 30% increase would mean a $1.47 million per year impact, Sims said. The utilities group is working to mini- mize impacts, but he said the longer it takes to make a decision, to pick an option, the fewer options will be available and those at higher rates. —KRISTEN NELSON PETROLEUM NEWS • WEEK OF MARCH 31, 2024 5 Safer. Smarter. Our CDR2-AC rig reflects the latest innovations in Arctic drilling to provide our customers with incident free performance and operational and technical excellence. CDR2-AC is the first Arctic rig designed and built by Nabors specifically for Coil Tubing Drilling operations. The rig was built to optimize CTD managed pressure drilling to provide precise control of wellbore pressures for improved safety, decreased costs, and increased wellbore lengths. Combining safety and environmental excellence with greater efficiency means CDR2-AC can deliver the high value results customers have come to expect from Alaska’s premier drilling contractor. Learn more about Nabors’ new drilling technologies at Nabors.com. nabors.com Better. continued from page 1 INLET GAS developing the huge Pikka project west of the central North Slope, said the first and second phase of Pikka, plus other oil discovered nearby repre- sent more than 1.5 billion barrels of known oil and could eventually rival Kuparuk, the second largest oil field on the North Slope. “When we add in our annual explo- ration appraisal program, I think in a few years in the future, we’ll be look- ing at north of 2, 3 billion barrels of development in front of us. And that’s where we get to the scale of a Kuparuk,” he said. “We’re seeing levels of activity that we haven’t seen for a decade or so, with more to come,” said Ireland, whose North Slope experience includes Western North Slope devel- opment manager for ConocoPhillips Alaska dating back almost 25 years. He was picked up in 2019 by Oil Search prior to its acquisition by Santos. —KAY CASHMAN continued from page 1 SANTOS HIGHLIGHTS 4/2/24, 8:24 AM Assembly resolution creates pathway to finance private energy upgrades | Local News | newsminer.com https://www.newsminer.com/news/local_news/assembly-resolution-creates-pathway-to-finance-private-energy-upgrades/article_415f1c00-ee05-11ee-…1/5 https://www.newsminer.com/news/local_news/assembly-resolution-creates-pathway-to-finance-private-energy- upgrades/article_415f1c00-ee05-11ee-adcf-2343f45ac456.html Assembly resolution creates pathway to finance private energy upgrades Jack Barnwell Mar 31, 2024 Photo courtesy Todd Paris A solar panel roof installation goes up on the home of Todd Paris. Photo courtesy Todd Paris Commercial and industrial property owners could have a new avenue to finance energy efficiency and solar panel installations through their property tax assessments after the Fairbanks North Star Borough approved a resolution Thursday night. The resolution, co-sponsored by Assemblymembers Mindy O’Neall and Savannah Fletcher, allows the borough to administer a local Commercial Property Assessed Clean Energy and Resilience Act (C-PACER) program. 4/2/24, 8:24 AM Assembly resolution creates pathway to finance private energy upgrades | Local News | newsminer.com https://www.newsminer.com/news/local_news/assembly-resolution-creates-pathway-to-finance-private-energy-upgrades/article_415f1c00-ee05-11ee-…2/5 “This would ideally help reduce energy costs among our commercial users, stimulate the economy and improve properties with renewable energy or energy efficiency products, reduce greenhouse emissions, increase air quality and resiliency and create jobs in the community,” O’Neall said Thursday. The resolution merely establishes an avenue to implement the program, it doesn’t commit the borough to creating it immediately. The borough would still need to create the framework for an actual PACER program, which will require a separate process. The Alaska Legislature approved the program in 2017 through the approval of House Bill 80 and subsequently signed by then-Gov. Bill Walker. C-PACER allows local governments to create and manage a program for property owners to secure a loan with participating lenders to finance the construction, installation or modification of improvements such as solar panels through property assessments. The borough would administer the program by collecting the owed amount and transferring it on to the financing company. The C-PACER program only applies to commercial and industrial programs; residential properties are excluded. O’Neall said the resolution only states that the borough intends to create a C-PACER program that falls within state statute. The program received some support during the Assembly meeting’s citizens’ comments period, including from the Fairbanks Economic Development Corporation. “We agree that this resolution has a proper public purpose,” said FEDC Executive Director Jomo Stewart. “Our community will benefit from the fact that other communities are doing this, so we should have a good framework of examples to learn from as we create our own.” Bali Kumar, a Minneapolis-based C-PACER lender and former administrator of the Michigan C- PACER program, lauded the program’s benefits. Kumar said the most recent loan his firm closed was in Anchorage, which set up its program. In addition, one of his top employees grew up in North Pole and returns annually with her family. 4/2/24, 8:24 AM Assembly resolution creates pathway to finance private energy upgrades | Local News | newsminer.com https://www.newsminer.com/news/local_news/assembly-resolution-creates-pathway-to-finance-private-energy-upgrades/article_415f1c00-ee05-11ee-…3/5 “It allows property owners to borrow capital to rehabilitate, renovate and improve existing buildings, build state-of-the-art new buildings that don’t have high energy costs and burdens,” Kumar said. Kumar said C-PACER program interest rates are similar to traditional lenders. The program is active in 30 other states. “Ultimately, it is up to the property owner whether they want to go through the C-PACER loan or a traditional bank loan,” Kumar said. “A lot of people will choose a C-PACER loan because they have the option of a very long payback.” Kumar added traditional banks currently may be unwilling to loan “maximum dollars’ needed for a project, leaving developers and property owners to seek the next option, which tends to be C- PACER lenders. According to the Alaska Energy Authority, which works with lenders, the Alaska C-PACER program covers projects such as wind turbines, solar panels, and heat pumps along with more traditional energy efficiency projects such as HVAC, windows, lighting and weatherproofing. AEA also set up standardized documents and materials municipalities can utilize for local programs. Melaine Lucas-Conwell, Anchorage’s C-PACER Program administrator, agreed. Anchorage launched its C-PACER program in 2021. Matanuska-Susitna launched its C-PACER program in January. “This program would be a great benefit across the state,” Lucas-Conwell said. She said the system allows municipalities such as Anchorage to use its existing tax assessment system to encourage private-sector lenders to provide lower-interest loans for building improvements not normally financed. “Beyond improving our building stock, C-PACER creates and retains local jobs to create, maintain, install and operate these programs,” Lucas-Conwell said. Anchorage administers two loans, including one for a commercial office building that wanted more energy efficiency; the C-PACER program allowed the building to reduce its energy costs by 42%. She added the program doesn’t burden taxpayers. 4/2/24, 8:24 AM Assembly resolution creates pathway to finance private energy upgrades | Local News | newsminer.com https://www.newsminer.com/news/local_news/assembly-resolution-creates-pathway-to-finance-private-energy-upgrades/article_415f1c00-ee05-11ee-…4/5 “The loans are made by private lenders and the program fees pay for the administration [of the program],” Lucas-Conwell said. Borough Assemblymembers asked whether the borough would be on the hook should a property fall into foreclosure or tax delinquency. Borough Attorney Jill Dolan said the borough wouldn’t be responsible for any C-PACER program balance, adding the lien exists with the property. If a new owner purchases the property, they would be responsible for the remainder of the balance. “This does not take priority over borough tax property liens, but it does take priority over other secured property liens,” Dolan said. “[The C-PACER loan] would not fall to us, it would pass on to the next owner ... the lien remains on the property.” Dolan said the borough might be on the hook only if it retained a foreclosed commercial or industrial property for a public purpose instead of re-selling it. Borough Mayor Bryce Ward cautioned the Assembly that the borough’s current assessing software system cannot process any C-PACER work. “Anything that we would potentially do would have to be tracked by hand,” Ward said. “We do not want to continue to have the antiquated program we currently have for tax collections, but that is a long process to replace.” Ward called the assessing software a critical part of the borough function and replacement will be delicate. “It would be disruptive if not done properly,” Ward said. He added the administration plans to solicit bids for a replacement but could take a “couple of years to get that program developed and implemented.” O’Neall acknowledged the concern she said is being addressed. She added the resolution’s benefit was that it simply provides direction for C-PACER program. “Sometimes, a program like this takes a few years,” O’Neall said. “As we are looking for vendors to upgrade our system, I hope this program can be implemented in the creation of that software.” 4/2/24, 8:24 AM Assembly resolution creates pathway to finance private energy upgrades | Local News | newsminer.com https://www.newsminer.com/news/local_news/assembly-resolution-creates-pathway-to-finance-private-energy-upgrades/article_415f1c00-ee05-11ee-…5/5 jbarnwell The Assembly passed it unanimously but Assemblymember Barbara Haney had some concerns about potential impacts down the road. “We have lots of industrial stuff and I see a lot of equipment laying idle in the borough because a particular industry might have gone bust,” Haney said. “I don’t want to see the borough stuck with a portfolio of land that it can’t unload because of claims on these lands by some of these finance companies.” Most Assemblymembers were generally supportive of the resolution and C-PACER program concept. “I was thrilled to see this come across,” said Assemblymember Scott Crass. “We’ve been looking for levers to help out with air quality in our community. I think this is a first great step and through our process address any concerns.” Contact reporter Jack Barnwell at 907-459-7587 or jbarnwell@newsminer.com. 4/1/24, 9:41 AM FAST Planning looking at electric vehicle infrastructure | Local News | newsminer.com https://www.newsminer.com/news/local_news/fast-planning-looking-at-electric-vehicle-infrastructure/article_6ed771a2-ed3b-11ee-8119-534e62890b7…1/5 https://www.newsminer.com/news/local_news/fast-planning-looking-at-electric-vehicle- infrastructure/article_6ed771a2-ed3b-11ee-8119-534e62890b7c.html FAST Planning looking at electric vehicle infrastructure Jack Barnwell Mar 29, 2024 News-Miner image Golden Valley Electric Association opened an electric vehicle fast-charging station in February 2022. News-Miner image 4/1/24, 9:41 AM FAST Planning looking at electric vehicle infrastructure | Local News | newsminer.com https://www.newsminer.com/news/local_news/fast-planning-looking-at-electric-vehicle-infrastructure/article_6ed771a2-ed3b-11ee-8119-534e62890b7…2/5 Fairbanks Surface Area Transportation Planning, in partnership with Michael Baker International, is conducting a study and survey as part of an electric vehicle infrastructure deployment plan in North Pole and Fairbanks. Jeff Kupko, with Michael Baker International, provided an update to the FAST Planning policy board on Wednesday about ongoing efforts. Kupko said FAST Planning recently completed its first open house and steering committee on the subject, with more planned over the next year. “One of the biggest efforts is documenting the existing conditions, what the current EV landscape looks like in the region, what are the challenges specific to the region and where the existing chargers are,” Kupko said. He added the plan will also look at existing constraints and the status of electrical infrastructure such as Golden Valley Electrical Association. “Fairbanks and North Pole aim to become electric vehicle-ready communities by developing a convenient, equitable, and local EV charging network,” Kupko said of the plan’s vision statement. “This network will support the integration of EVs as a new transportation option among existing options and provide residents and visitors with ample charging access to make EV ownership feasible and accessible for all.” At the moment, Fairbanks has one public electric vehicle charging station located in the parking lot of GVEA’s offices on Illinois Street. 4/1/24, 9:41 AM FAST Planning looking at electric vehicle infrastructure | Local News | newsminer.com https://www.newsminer.com/news/local_news/fast-planning-looking-at-electric-vehicle-infrastructure/article_6ed771a2-ed3b-11ee-8119-534e62890b7…3/5 FAST Planning has submitted grant funding applications for various projects and has included charging stations in its Transporation Improvement Plan, a four-year document that outlines spending priorities. In addition, the Alaska Department of Transportation has been working on rolling out its “alternative fuel corridor” plan as part of the federal National Electric Vehicle Infrastructure (NEVI) program. The steering committee overseeing the project includes input from local businesses, local and state agencies and other stakeholders. NEVI provides federal funding to states to help develop a route for electrical vehicle charging stations. For Alaska, that route would run initially from Anchorage to Fairbanks up the Parks Highway. Kupko said FAST Planning’s deployment plan will ensure local and state efforts aren’t being duplicated. Kupko added his role as a consultant on the state NEVI project ensures a seamless process. Kupko said FAST Planning rolled out a public survey that closes April 19 designed to gauge public interest and concerns on electric vehicles in the Fairbanks and North Pole areas. “We will also have an open house in the fall once we’ve developed a draft plan,” Kupko said. “That way we have another test point to make sure we are hitting what expectations may be.” The draft electric vehicle infrastructure deployment plan will come before FAST Planning’s technical committee and the policy board for review and consideration. Any final plan will serve as a roadmap for FAST Planning to expand the area’s electrical vehicle infrastructure. Kupko said the goals include expanding both public and private charging stations, get a better understanding of the electric vehicle owners’ needs and patterns and setting up a network that is both equitable and practical across the region. “We also want to position the region as a cold climate testing hub,” Kupko said. “This was a really hot topic in the steering committee meeting with the recognition there is a lot of testing that goes on in the region.” 4/1/24, 9:41 AM FAST Planning looking at electric vehicle infrastructure | Local News | newsminer.com https://www.newsminer.com/news/local_news/fast-planning-looking-at-electric-vehicle-infrastructure/article_6ed771a2-ed3b-11ee-8119-534e62890b7…4/5 Eventually, the plan calls for the installation of a mix of different public charging stations based on the current market demand. The plan calls for partnerships for partnerships with major employers, public facilities and private businesses to host charging stations as part of grant-funded programs. “We want to serve a mix of places such as parks and businesses and multi-family residences,” Kupko said. Jackson Fox, FAST Planning’s executive director, noted the reaction to electrical vehicles during a recent open house ranged from very receptive to staunchly opposed. “We got a good conversation going with folks who attended,” Fox said. The open house also generated ideas on potential locations for charging stations. FAST Planning already has a list of ideas, such as the Noel Wien and North Pole libraries, Pioneer Park, the Lavery Transportation Center and parking garage in downtown Fairbanks and the Morris Thompson Cultural and Visitor Center. Locations proposed by residents included such as Sophie Station Hotel and Wedgewood Resort, areas that have a combination of short-stay and extended-stay lodgings and residential apartments. Fox said there has been interest in installing charging stations at the Univeristy of Alaska Fairbanks. Fox said comments also included the challenges electric vehicles face during Interior Alaska’s stark winter months when temperatures drop below zero. Electric vehicle batteries, he said, likely would not hold a full charge. “I think skepticism about electric vehicles in Fairbanks and North Pole is very real,” Fox said. “FAST Planning isn’t pushing people into EVs, this is trying to figure out what the needs are and how we can potentially serve that user group as local dealerships begin to sell electric vehicles.” Fox noted the number of electric vehicles in the borough has grown significantly in the past year. Fox reported in December that there were 35 vehicles, but has since grown to 132. “By the end of the year it could be a couple hundred,” Fox said. “I don’t know what the growth is going to be, whether it will be a slow growth or rapid. And technology is certainly going to change.” However, he said the draft plan due for consideration in the fall will provide a better snapshot. 4/1/24, 9:41 AM FAST Planning looking at electric vehicle infrastructure | Local News | newsminer.com https://www.newsminer.com/news/local_news/fast-planning-looking-at-electric-vehicle-infrastructure/article_6ed771a2-ed3b-11ee-8119-534e62890b7…5/5 jbarnwell Fairbanks Mayor David Pruhs, a policy board member, said the data has a practical element to address the borough’s air quality. The Environmental Protection Agency designates the Fairbanks and North Pole areas as a serious nonattainment area due its high level of 24-hour wintertime fine particulate matter (PM2.5) levels. The majority of the wintertime PM2.5 levels are caused by wood stove smoke, but vehicle emissions play a small part in the issue. “This is going to be exciting to see how this [electric vehicle] industry grows and formulates itself in Fairbanks,” Pruhs said. Fairbanks Councilmember Jerry Cleworth was more skeptical, noting the electric vehicle sales have cooled in the last year and corporate development appears to be falling off. “Whether that’s a blip on the map and sales are going to go up again, I don’t know, but when I read those numbers, I don’t know if this will be a replacement of the gas engine,” Cleworth said. Cleworh said he initially saw the infrastructure deployment plan as a way to determine whether charging stations are feasible and who would make the investments in the infrastructure. “A lot of that will just be guesswork based on the current projections,” Cleworth said. He added a new technology, such as commercially viable fuel cells, could come along and make electric vehicles obsolete. “I take the cautious approach, as we’re not here to sell EVs or showcase them,” Cleworth said. “We’re here to see what the market is and what we need to do as FAST Planning to try and accommodate that ... it’s a heavy investment so I go in slowly into this.” For more information on the plan and FAST Planning’s survey, visit tinyurl.com/yc76p5tw. Contact reporter Jack Barnwell at 907-459-7587 or jbarnwell@newsminer.com. Support Industry Innovations: Methanol, Drone Delivery, Energy Diversification https://www.akbizmag.com/industry/oil-gas/support-industry-innovations-methanol-drone-delivery-energy-diversification/ 1/5 Support Industry Innovations: Methanol, Drone Delivery, Energy Diversification BY RINDI WHITE | MAR 27, 2024 | ENERGY, FEATURED, NEWS, OIL & GAS Renewable Independent Power Producers and CleanCapital held a ribbon cutting for its 8.5 megawatt Houston Solar Farm project last year. CLEANCAPITAL “Alaska has a lot of things going for it: we have a harsher climate, bigger issues to overcome. We have the right attitude to try and solve problems because we’re used to Support Industry Innovations: Methanol, Drone Delivery, Energy Diversification https://www.akbizmag.com/industry/oil-gas/support-industry-innovations-methanol-drone-delivery-energy-diversification/ 2/5 doing hard things here,” says JR Wilcox, owner of Alyeschem, a company building a distributed chemical manufacturing company on the North Slope. Wilcox, along with Jenn Miller, CEO of Houston solar farm operator Renewable IPP, and Hunter Van Wyhe, operations engineer for Furie Operating Alaska and head of its drone aircraft project, spoke as part of a panel on Alaska Innovations at the Alaska Support Industry Alliance’s 2024 Meet Alaska conference at the Hotel Captain Cook March 22. Panel members discussed unique-to-Alaska innovations that are helping solve problems in the oil, gas, and electrical industries. Arctic Chemicals Wilcox’s company, Alyeschem, is working on a project that will use North Slope natural gas, carbon dioxide, and water to create two products, methanol and hydrogen, in what will be the first petrochemical facility in the US Arctic. The hydrogen will be used to treat locally produced high-sulfur diesel fuel to make ultra-low-sulfur diesel, which Slope producers are federally required to use in moving equipment to reduce emissions. Methanol, currently imported thousands of miles to Alaska and then trucked hundreds more to reach the Slope, is widely used to prevent hydrate buildup in gas compression plants and to prevent temporarily shut-in wells and pipelines from freezing. Producing methanol and hydrogen on site will reduce the need for North Slope producers to import the two largest commodities hauled up the Dalton Highway. The benefits, Wilcox says, are numerous. “It’s part economics and part operational reliability,” he says. He further illustrates in his presentation, “The North Slope is a world-class energy basin and can continue to be for generations to come. Its future hinges on lowering operating costs, increasing the resource base, monetizing gas, and adapting to the clean fuel transition. Value-added chemistry is the key to all of these challenges.” Support Industry Innovations: Methanol, Drone Delivery, Energy Diversification https://www.akbizmag.com/industry/oil-gas/support-industry-innovations-methanol-drone-delivery-energy-diversification/ 3/5 Wilcox has been working on the chemical plant project for about ten years. It has traction; a plant location and pipeline right-of-way are acquired; gas supply contracts are executed; sales contracts are in final form and major permits acquired. McKinley Alaska Private Investment and BP Energy Partners, through BP Natural Gas Opportunity Partners II LP, have signed on as major equity partners, he says. Alaska Industrial Development and Export Authority (AIDEA) announced in December its approval of a cost reimbursement agreement “to undertake feasibility activities” of Alyeschem. “Alyeschem already has site control, a gas supply contract, equity investors, major permits, and front-end engineering and design completed. Partnering with AIDEA for potential investment is one more step closer to making this a reality for Alaskans,” Wilcox said when AIDEA announced its investment. Engineering on the project is now at the 30-percent completion phase; a final investment decision is pending. Once that decision is made, Wilcox says construction can happen in 2025 with a commissioning late that year. Unmanned Deliveries HEX Cook Inlet is the parent company of Furie Operating Alaska. Furie currently produces gas from the Kitchen Lights Unit in Cook Inlet. A byproduct of gas production is water, which needs to be tested on a weekly basis to meet state Department of Environmental Conservation permit stipulations. Samples are sent to shore in one-gallon containers, but sometimes getting them there can be problematic—when no helicopters are flying or no ships scheduled to be at the platform 15 miles offshore, for example. Furie leaders suggested sending the samples via drone. “The approval process for these drone operations is not easy,” Van Wyhe told the Meet Alaska audience. “There’s a reason you’re not currently getting packages delivered by drones right now.” The permitting process is daunting, but Furie leaders decided to forge ahead. They have worked since 2021 with the UAF Alaska Center for Unmanned Aircraft Systems Integration (ACUASI) to develop a program that would allow Support Industry Innovations: Methanol, Drone Delivery, Energy Diversification https://www.akbizmag.com/industry/oil-gas/support-industry-innovations-methanol-drone-delivery-energy-diversification/ 4/5 the company to conduct flights to and from its offshore platform. Furie and ACUASI developed the program over 2022 and in 2023 secured a Beyond Visual Line of Sight waiver, the first such waiver in the United States approved for flights to and from an offshore platform. It’s also the second Beyond Visual Line of Sight waiver granted in the state of Alaska with no limitations to flights under 400 feet, Van Wyhe says. Van Wyhe and Mark Slaughter, chief commercial officer for Furie, say the first flight is scheduled for June. Due to magnetic interference from the platform, a second pilot has to control the drone once it approaches, so hand-off procedures have to be perfected. Van Wyhe estimates it takes between 20 to 30 minutes to fly the 15 miles to the platform. The partnership with ACUASI is vital; the center is helping Furie get the project set up and proven, and it will assist with training Furie’s drone operators, helping Furie select the best drone for the company’s needs. At the end of the process, ACUASI will pass the reins to Furie. “We feel this is an innovative solution to challenges we’re currently facing and a good opportunity to utilize emerging technology in the oil and gas industry,” Van Wyhe told the Meet Alaska audience. Innovation via Diversification The discussion about innovations wasn’t limited to oil and gas; Meet Alaska’s conference was in part about Alaska’s energy future, and according to Miller, Alaska’s energy future is squarely in diversification—particularly reducing the state’s reliance on dwindling Cook Inlet natural gas. Miller and three business partners, all with an oil and gas background, started Renewable Independent Power Producers (Renewable IPP) in 2017 with an eye toward energy diversification. The group started by building a 140-kW solar array in 2018, a project that they self-funded, designed, and built. That pilot project came in 5 percent under budget, and the performance matched the group’s estimates. Support Industry Innovations: Methanol, Drone Delivery, Energy Diversification https://www.akbizmag.com/industry/oil-gas/support-industry-innovations-methanol-drone-delivery-energy-diversification/ 5/5 From that promising start, the group moved on to a 1.2-MW expansion in Willow financed through a loan, their own investment, and contribution from an angel investor. That was the first utility-scale project Renewable IPP undertook. Approved by the Regulatory Commission of Alaska and with a power purchase agreement from Matanuska Electric Association, the project paved the way for an even larger project: the 8.5-MW Houston Solar Farm. The Houston project was financed in part by CleanCapital, an asset management firm that specializes in development and financing of utility-scale solar and battery energy storage projects. Through the project, Miller says, CleanCapital became a minority partner with Renewable IPP. Alaska Energy Authority also supported that project, she says, via a $5 million low-interest loan. Miller notes that solar power in Alaska wasn’t economic a decade ago, but the cost of solar has dropped significantly since then. Renewable IPP has proved its ability to take a project from concept to operation on a lean budget, which is key to making solar work. Sticking with projects from development through operation helps when talking with power companies about future projects, she says. “When we go to meet with utilities, it builds a lot of trust. It’s not just, ‘Hey, we’re going to sell you this project and we hope it works out,’” she notes. “On a national or a global scale, these projects are very, very small, but it’s set us up to really scale.” Miller notes that Renewable IPP is working on a larger project on the Kenai Peninsula. What’s innovative about building solar arrays? Well, Miller says, the fact that it’s being done in Alaska, to start: a cold environment known for having limited daylight. “With solar in Alaska, we often get a gut reaction of ‘What? How does that work?’” Miller notes. “The reaction has been, every single time, ‘If it works in Alaska, doesn’t it work everywhere?’ We’re proving up the resource, showing that it can work in harsh climates.” 4/3/24, 2:43 PM Work on Eielson microreactor project may resume this summer | KUAC.org https://fm.kuac.org/energy-and-environment/2024-03-25/work-on-eielson-microreactor-project-may-resume-this-summer 1/6 Work on Eielson microreactor project may resume this summer KUAC | By Tim Ellis Published March 25, 2024 at 11:51 AM AKDT LISTEN • 3:01 Eielson AFB File Photo Air Force ocials say the microreactor could provide resilience in the form of backup power to ensure Eielson's readiness to deploy its F-35 fth-generation ghters, as well as the Alaska Air National Guard's air tankers and other air assets based there. Senate Resources Committee co-chair urges Air Force to move ahead on promising source of 'cheap energy' The Pentagon may move ahead this summer on a proposal to build a small self- contained nuclear power plant on Eielson Air Force Base. A senior Air Force ocial updated state lawmakers on the project last week. It’s been six months since Air Force Assistant Secretary Ravi Chaudhary announced with great fanfare in Fairbanks that the service had decided to award a contract to build and operate the rst microreactor on a U.S. military installation. 4/3/24, 2:43 PM Work on Eielson microreactor project may resume this summer | KUAC.org https://fm.kuac.org/energy-and-environment/2024-03-25/work-on-eielson-microreactor-project-may-resume-this-summer 2/6 KUAC File Photo Gwen Holdmann, UAF’s Associate Vice Chancellor for Research, Innovation and Industry Partnerships, introduces a panel of federal ocials at a Aug. 31 town hall meeting at Schaible Auditorium. From left, Ravi Chaudhary, Assistant Air Force Secretary for Energy, Installations and Environment; Nancy Balkus, Deputy Assistant Air Force Secretary for Environment, Safety and Infrastructure; Col. Paul Townsend, 354th Fighter Wing commander; and Stephen Philpott, Safety and Licensing Project Manager for the U.S. Nuclear Regulatory Commission. “I am super-excited to announce the Notice of Intent toward selection of our rst microreactor technology to Oklo Incorporated,” Chaudhary said in an event held on the University of Alaska Fairbanks campus. But a couple of weeks later, the Air Force rescinded the decision to tentatively award the contract to the California based Oklo, because another company protested. And since then, military ocials have said very little about the proposal. Until last week. “The Notice of Intent to Award was then reissued in February, and then in March, a bidder then submitted a GAO protest,” said Nancy Balkus, another Air Force assistant secretary told a group of Alaska lawmakers on March 18th. “So that’s where we stand today,” Balkus told members of the state Senate Resources Committee during an update on the microreactor project. Balkus told committee members the protest led this month with the federal Government Accounting Oce must be resolved with 100 days -- by June 20th. She couldn’t provide details about the protest, but said the Air Force remains determined to stick to its original schedule and have the microreactor operational in 2028. 4/3/24, 2:43 PM Work on Eielson microreactor project may resume this summer | KUAC.org https://fm.kuac.org/energy-and-environment/2024-03-25/work-on-eielson-microreactor-project-may-resume-this-summer 3/6 “We believe that having documented the entire process,” she said, “that the next, second, third and fourth will take less time to implement, because we will have established a path.” When questioned by Committee Co-Chair Sen. Cathy Giessel of Anchorage about the cost of the project, Balkus said that’ll be worked out after the contract is nalized. “We do not have a cost gure at this time,” she said. “That will be negotiated with the vendor once they have gotten through the design and licensing process.” Idaho National Laboratory Microreactors like those proposed for Eielson Air Force Base are small enough to be transported by trucks in shipping containers, as shown in this rendering generated by the Idaho National Laboratory. Balkus said the contractor will build and operate the facility, and the Air Force will purchase the electricity and heat it generates. In response to a query by Committee Co- Chair Sen. Click Bishop of Fairbanks about how the reactor will be refueled, she said that’s also yet to be determined. “Will the entire assembly be taken back to the manufacturing plant? Will a new unit be coming in with new fuel already loaded into it? We don’t have that level of detail at this time.” The 5-megawatt facility would generate only about a third of the electricity Eielson requires. But Balkus suggested that if the initial pilot project is successful, additional microreactors could be brought to the base to increase energy output. 4/3/24, 2:43 PM Work on Eielson microreactor project may resume this summer | KUAC.org https://fm.kuac.org/energy-and-environment/2024-03-25/work-on-eielson-microreactor-project-may-resume-this-summer 4/6 Bishop told Balkus that he hopes there won’t be any more delays, because he says microreactor technology holds great promise for both reducing greenhouse-gas emissions and helping Alaska solve stubborn economic problems by nding less- expensive ways to generate electricity. “If we’re going to be competitive and stop the outmigration and bend the curve on our GDP going the wrong direction, and want to grow Alaska,” he said, “we have got to have – I call it cheap energy.” Bishop said in an interview Friday that Alaska’s elected leaders have taken steps in the right direction over the past couple of years with legislation that promotes development of electricity-generating microreactors. Those include Senate Bill 177, a measure adopted in 2022 that clears some state regulatory hurdles, and a separate package enacted last year that among other things dictates where microreactors may be built in Alaska. Energy and Environment Tim Ellis Tim Ellis has been working as a KUAC reporter/producer since 2010. He has more than 30 years experience in broadcast, print and online journalism. See stories by Tim Ellis 4/2/24, 8:44 AM Unalaska to pursue geothermal energy, leaving Chena Power out of the equation | KUCB https://www.kucb.org/science-environment/2024-03-22/city-of-unalaska-announces-plans-to-pursue-geothermal-energy-leaving-chena-power-out-of-th…1/7 Local News The KUCB Newsroom provides newscasts Monday through Thursday at noon and 5 PM on KUCB Radio. You can nd many of our local news stories here. Unalaska to pursue geothermal energy, leaving Chena Power out of the equation KUCB | By Theo Greenly Published March 22, 2024 at 12:30 PM AKDT Courtesy Of Ounalashka Corp./Chena Power LLC The Makushin Geothermal Project began building an access corridor to the site of the proposed power plant in 2021. Unalaska is still pursuing the Makushin Geothermal Project, even after a rocky four years to try to get the project off the ground. The latest hurdle requires that the city must break ties with the company previously hired to lead the project. The City of Unalaska announced in a statement earlier this month they were pursuing a grant from the U.S. Environmental Protection Agency to fund the Makushin Geothermal Project, and that they would partner with the Qawalangin Tribe of Unalaska and Unalaska’s Native corporation, the Ounalashka Corp. Donate 4/2/24, 8:44 AM Unalaska to pursue geothermal energy, leaving Chena Power out of the equation | KUCB https://www.kucb.org/science-environment/2024-03-22/city-of-unalaska-announces-plans-to-pursue-geothermal-energy-leaving-chena-power-out-of-th…2/7 But the Ounalashka Corp. is tied to Fairbanks-based Chena Power. The two companies partnered in 2020, forming a joint venture known as OCCP, to pursue the project. That joint venture has a 50-year lease on the resource at Makushin. But slow progress due to OCCP’s failure to meet several funding deadlines led the city to choose not to renew its agreement with them. This all means that for the city’s plan to work without Chena Power’s involvement, the Ounalashka Corp. would likely have to break ties with Chena. Today, the Native corporation’s board of directors plans to meet to discuss ways to move forward, which could include dissolving its partnership with Chena Power, essentially buying them out. Bernie Karl, the chief ocer of Chena Power and president of OCCP, has been at the center of the project since its inception, when he brought the project back to life after it had simmered for years. But OCCP does have a buy-sell agreement, meaning it is possible for the Ounalashka Corp. to buy Karl out of the partnership. “They have the right to get rid of me,” Karl said in an interview Thursday. “It looks to me like they've moved ahead with the city and the tribe. They've already moved ahead, so it looks to me like they want to do this without OCCP.” But Karl says the city has prevented the Unalaska City Council and Ounalashka Corp. shareholders from understanding the whole picture, namely by withholding the company’s monthly reports. “If the city shared those reports with the council, they’d understand that we were right on track,” Karl said, and that they were on track to enter the next stage within a few months. “We’re so close right now,” he said. “We've already bought the drill rig.” But OCCP has already been granted three timeline extensions, pushing the proposed operation date back from 2024 to 2027. The pandemic and its fallout have led to numerous supply-chain issues, and the cost of borrowing has gone up drastically since the project began in 2020. 4/2/24, 8:44 AM Unalaska to pursue geothermal energy, leaving Chena Power out of the equation | KUCB https://www.kucb.org/science-environment/2024-03-22/city-of-unalaska-announces-plans-to-pursue-geothermal-energy-leaving-chena-power-out-of-th…3/7 Ounalashka Corp. CEO Natalie Cale said in a statement that the company was “disappointed in the series of events that have unfolded” since the project’s inception, “the majority of which were out of OCCP’s control.” “This has always been an expensive project. The fact that most of the costs are upfront, with the real savings and benets (economical and environmental) in the long-term, seems lost on lenders,” she wrote. City leaders say the city has urgent power needs that the geothermal project was supposed to address. City Manager Bil Homka said the city has put other power projects on the back burner because the geothermal project was supposed to solve them. Now, Homka says, the city cannot afford to wait for geothermal to come online and has to move forward with alternative ways to solve the city’s urgent power needs. The city led its intent to apply for up to $500 million in federal grants for the Makushin Geothermal Project Feb. 1, nearly a month before the city council’s Feb. 27 meeting when they decided not to renew their agreement with the OCCP. The deadline for the city to apply for the EPA grant is April 1. Tags Science & Environment MAKUSHIN Makushin Geothermal Project OCCP OC/CHENA POWER Ounalashka Corporation The Qawalangin Tribe of Unalaska ALTERNATIVE ENERGY renewable energy GEOTHERMAL Alaska State News Theo Greenly Theo Greenly reports from the Aleutians as a Report for America corps member. He got his start in public radio at KCRW in Santa Monica, California, and has produced radio stories and podcasts for stations around the country. More EV chargers around the corner for Fairbanks: Where will they go? https://www.webcenterfairbanks.com/2024/03/22/more-ev-chargers-around-corner-fairbanks-where-will-they-go/ 1/3 FAIRBANKS, Alaska (KTVF) - Spring sunshine seeped into the Morris Thompson Cultural and Visitors Center Tuesday, as 20 or so people talked shop about electric vehicle ownership in the interior at an open house hosted by Fairbanks Area Surface Transportation (FAST) Planning. “We pulled in and I was like, ‘Wow, there’s like six electric vehicles here,’ so it kind of brings people who are early adopters or interested in the technology together,” said Evans Callis, who recently purchased a 2022 Chevy Bolt. In Fairbanks in 2024, six EVs in a single parking lot is not so common. “Here in our community we have just over 100 electric vehicles in and around town, which is not a lot of vehicles,” FAST Planning Executive Director Jackson Fox said. Current projections anticipate between a 42% and 63% growth rate per year for EV sales statewide, according to a 2024 Alaska Energy Authority (AEA) report. More EV chargers around the corner for Fairbanks: Where will they go? https://www.webcenterfairbanks.com/2024/03/22/more-ev-chargers-around-corner-fairbanks-where-will-they-go/ 2/3 “Local dealerships are selling electric vehicles, and in the next year we might have 200 or 300. We don’t know how fast or slow that’s going to grow,” Fox added. Not deterred by the roughly 50% driving range reduction in the extreme cold, Callis said he was eyeing long-term cost savings as part of his decision to switch. “They’re lower maintenance. They’re cheaper to run. When our gas vehicle did bite the dust, it was looking like $4,000 to $6,000 fix on it,” he said. “I was like, ‘I could put that toward a down payment on an EV, spend less money on gas, and still come out ahead in the long run,’” Callis added. The primary purpose of Tuesday’s open house was to peer into the future of public EV charging stations in the Fairbanks area, under the assumption that ownership will continue on its upward trajectory. Currently, there’s one such station in town. It’s at Golden Valley Electric Association. Three more are getting set for construction this summer. Two of those are proposed for Fairbanks, funded by AEA: one at Fred Meyer West, the other at the Westmark Hotel. The third is a privately-funded station at Three Bears in North Pole. They’re all planned to be the top tier type — or “Level Three” — with an output of 50- 350 kilowatts that can fully charge an empty battery in 20 minutes to an hour. Construction and installation costs for the Level Three chargers vary, but fall around a couple hundred thousand dollars apiece, not including maintenance. Fox said FAST Planning has $1 million federal dollars per year to continue building similar stations, but locations for those aren’t yet decided. “We’ve heard some ideas from our local government partners on where they would like to have these charging stations, but we’re also looking to hear from the business community and the folks that own electric vehicles,” he said. Fox explained he’d previously received interest from the University of Alaska Fairbanks, Fairbanks international Airport and the North Pole Branch and Noel Wien libraries. At the open house, attendees could also weigh in on possible locations by marking a map with multi-colored sticky notes, often suggesting other community centers and populous areas, like Sophie Station Suites. More EV chargers around the corner for Fairbanks: Where will they go? https://www.webcenterfairbanks.com/2024/03/22/more-ev-chargers-around-corner-fairbanks-where-will-they-go/ 3/3 “At the completion of this plan, we’ll open up an opportunity for applications to start to build out some of this network,” Fox said. As for who pays what following installation, there are a couple possibilities. FAST Planning could use some of the $1 million annual federal funds to subsidize the stations for up to five years following installation. “We could make the charging stations free if we wanted to do that,” Fox said. The other option would create public-private partnerships, in which FAST Planning would provide the upfront money to get a station ready to go, and then a property owner would take over maintenance and could charge users for the electricity. FAST Planning’s in-town efforts dovetail with Alaska Energy Authority’s ongoing $50 million dollar plan to construct charging stations along the state’s highway corridors. Phase one of that project runs up the Parks Highway, connecting Anchorage to Fairbanks, with distance intervals between the 15 proposed stations ranging from eight to 77 miles. Nine of those stations have been recommended for a site award, and AEA is aiming for completion by the 2026 fiscal year. Apart from the charging station build out, Interior EV owners at the open house were hopeful for long-term private involvement in other capacities, too, with EV-specific repairs topping the list of concerns. “The biggest thing I see as a drawback right now is the maintenance situation. When it does need to serviced, really, you’re stuck with the dealer, and that’s your only option,” Callis said. Copyright 2024 KTVF. All rights reserved. 3/26/24, 12:53 PM Enstar CEO says Cook Inlet gas shortfall more serious than thought earlier By Tim Bradner For the Frontiersman | Local News St… https://www.frontiersman.com/news/enstar-ceo-says-cook-inlet-gas-shortfall-more-serious-than-thought-earlier-by-tim-bradner/article_cfc900ec-e89b-…1/4 https://www.frontiersman.com/news/enstar-ceo-says-cook-inlet-gas-shortfall-more-serious-than-thought-earlier-by- tim-bradner/article_cfc900ec-e89b-11ee-aca5-03df0456c046.html Enstar CEO says Cook Inlet gas shortfall more serious than thought earlier By Tim Bradner For the Frontiersman By Tim Bradner For the Frontiersman Mar 22, 2024 Natural gas platform in Cook Inlet. Courtesy photo A projected natural gas shortage facing Alaskan communities may be worse than previously thought, the president of the state’s largest gas utility said. 3/26/24, 12:53 PM Enstar CEO says Cook Inlet gas shortfall more serious than thought earlier By Tim Bradner For the Frontiersman | Local News St… https://www.frontiersman.com/news/enstar-ceo-says-cook-inlet-gas-shortfall-more-serious-than-thought-earlier-by-tim-bradner/article_cfc900ec-e89b-…2/4 Imports of liqueed natural gas thought of earlier as a short-term solution no longer appear to be an option at least at any scale, John Sims, CEO of Enstar Natural Gas Co., told the Resource Development Council in Anchorage. State oil and gas ocials say aging gas elds in the Cook Inlet basin, which have been producing since the 1960s, will see drops in production beginning in 2027 and be in serious decline by 2030. It’s a serious problem because half of Alaska’s population lives in Southcentral Alaska, mostly in Anchorage. Space heating and most power generation in the region are fueled by gas. Regional gas demand is steady at about 70 billion cubic feet per year, and that is met my existing production. But by 2027 annual is projected to drop to 65 billion cubic feet per year, to 55 billion by 2028 and 48 billion by 2030, according to a 2023 Alaska Division of Oil and Gas study. Enstar and electric utilities in the region have been studying options for meeting the supply gap with imports of LNG but now nd there isn’t time to build regasication and dock facilities for handling LNG imports by tanker before 2030, Sims said. “That was a ‘big gulp’ moment for us,” Sims said. Unless more production can be coaxed out of the region’s gas elds the utilities may have to rely on smaller-scale shipments of LNG using ISO containers, which will be extremely expensive, Sims said. Hilcorp Energy, the largest gas producer in Cook Inlet, has told the utilities that it cannot renew gas contracts on a rm, or guaranteed, basis as contracts expire beginning this year. It’s possible that Hilcorp or smaller companies active in the region could supply some gas on an interruptible, or non-guaranteed, basis but utilities are bound by regulatory rules to guarantee service to customers and must have rm contracts with producers to supply that, Sims said. Hilcorp, the largest producer, has told the utilities it can no longer oer rm contracts, he said. Electric utilities in the region depend on gas for most power generation although Matanuska Electric Association, which serves a large area north of Anchorage, has a dual-fuel capability, and oil, at its power plant. 3/26/24, 12:53 PM Enstar CEO says Cook Inlet gas shortfall more serious than thought earlier By Tim Bradner For the Frontiersman | Local News St… https://www.frontiersman.com/news/enstar-ceo-says-cook-inlet-gas-shortfall-more-serious-than-thought-earlier-by-tim-bradner/article_cfc900ec-e89b-…3/4 The problem also aects Alaska’s sole liquid fuels renery operated by Marathon Petroleum on the Kenai Peninsula, Casey Sullivan, external aairs manager for the company, said at the same brieng Sims spoke at. Marathon uses natural gas in operations at the renery, which supplies most of Alaska’s gasoline as well as jet fuel for Anchorage’s airport and Joint Base Elemdorf Richardson in Anchorage, a major military installation. Ironically, Alaska has 35 tcf of gas that is stranded on the North Slope, 800 miles to the north, but with no pipeline to move the gas to the southern part of the state. Absent a $10 billion-plus state subsidy to build a pipeline, the North Slope gas is not an option. Sims said that Enstar and the major electric utilities have spent $3.5 million on studies of possible LNG imports. The group is still studying the ndings and are not yet ready to release the estimates, Enstar spokesperson Lindsay Hobson said. However, based on preliminary ndings released last year the cost of imported LNG could be in the range of $15 per mmcf, Sims said in previous briengs. That’s about twice the prevailing price now paid to producers in the region. That assumes LNG imports using small tankers or large barges. If that option is unavailable until 2030, until import facilities are built, the option of using ISO containers or small LNG barges could push costs to $25 per mmcf, or more, Sims has said. That is about three times current prices, at least for the volume of LNG shipped in. This would be very damaging to a regional economy already struggling with high energy costs and an out-migration of working-age adults and families, Sims said. State legislators in Juneau are meanwhile working on incentives that could encourage new production. Bills that would reduce the state royalty rate could help one small producer, HEX LLC, nance new wells to tap a resource near its Kitchen Lights eld in Cook Inlet. That could result in some new gas in the near term, Mark Slaughter, chief commercial ocer for HEX, told a legislative committee in Juneau. 3/26/24, 12:53 PM Enstar CEO says Cook Inlet gas shortfall more serious than thought earlier By Tim Bradner For the Frontiersman | Local News St… https://www.frontiersman.com/news/enstar-ceo-says-cook-inlet-gas-shortfall-more-serious-than-thought-earlier-by-tim-bradner/article_cfc900ec-e89b-…4/4 The legislation that is most advanced is House Bill 223, by State Rep. George Rauscher, R-Sutton, that would reduce the state royalty from 12.5 percent of the production value to zero if new Cook Inlet gas is sold to public utilities. The bill would also reduced royalties on new oil in the Inlet to 5 percent. Gov. Mike Dunleavy has a separate bill, now active in the state Senate, that would drop the royalty to 5 percent for new Cook Inlet gas. In his talk to the RDC Sims urged legislators to required that new state incentives be linked to rm, non-interruptible, supply contracts gas sold to utilities. If the gas contracts are interruptible, or non-rm, they won’t help the utility, which need rm contracts, he said. EIA forecasts record US crude oil output at 13.2 million bpd in 2024 page 4 see HICKORY-1 WELL page 10 see MILNE EXPANSION page 10 Hickory-1 well operations have begun on Alaska’s North Slope On March 11, Australia-based 88 Energy Ltd. released an ASX announce- ment, saying Hickory-1 well operations have commenced, with well bore prepa- rations complete and perforation of the Upper SFS zone to begin ahead of perfo- rating, fracking and flow testing the Upper SFS zone. Hickory-1 was drilled but not tested last winter. Two flow tests are scheduled, one each in the Upper SFS and SMD-B reser- voirs, with each frac and flowback operation expected to take approximately 10 days. 88 Energy said it has strengthened its technical advisory team to include additional engineering expertise, as well as experienced members of the Pantheon Resources Great Bear team being available to share their relevant recent and extensive see RAILBELT BILL page 10 Bill for Railbelt transmission changes could improve usage On March 4 the Alaska Senate Resources Committee heard testimony on Senate Bill 217, a bill introduced by Gov. Mike Dunleavy to change the way in which the electricity transmission system in the Alaska Railbelt is managed and funded. An identical bill, House Bill 307, has been introduced to the House of Representatives. As previously reported by Petroleum News, the bills would change the way in which transmission costs are recovered by the utilities that operate sections of the transmission system and would require the utilities to form an integrated transmission system association to assist in adminis- tering the arrangements for transmission system cost recovery. Currently the use of the system is hindered by the wheeling or “pancaking” of the fees that each utility charges for the use of its individual sections of the system. This can render the Hilcorp applies to expand Milne Point unit; new drilling planned As Hilcorp Alaska continues to expand production from its North Slope Milne Point unit it is now looking at acreage it holds adjoining the unit and has applied to the Alaska Department of Natural Resources’ Division of Oil and Gas to expand the Milne Point unit by some 13,275 acres. A map accompanying Hilcorp’s Dec. 29 application shows the majority of the expansion area to the north of the existing unit, with one smaller proposed expansion area near the unit’s southeast edge. Hilcorp said in its application that accumulations in the proposed expansion area include the Kuparuk and Schrader Bluff reservoirs, accessible from the Moose, Raven (or R) and F pads. The F Pad is the most northerly of the three, with the R Pad under construction to the southwest of F Pad and the Moose Pad, developed in 2018, southwest of the R and F pads near the western boundary of the unit. The expansion area includes parts of six leases: ADL 355017, ADL 355018, ADL 355021, ADL 355016, ADL 28232 and ADL 394167. Hilcorp said three of those, ADL 355017, ADL 355018 and Vol. 29, No. 11 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of March 17, 2024 • $2.50 l FINANCE & ECONOMY l UTILITIES l NATURAL GAS Demand supports ANS US oil inventories fall as Ukraine strikes major Russian oil facilities By STEVE SUTHERLIN Petroleum News O il futures leapt some 3% March 13 as the U.S. Energy Information Administration reported a drawdown of U.S. crude reserves and gasoline reserves. West Texas Intermediate crude lofted $2.16, or 2.8% March 13 to close at $79.72 per barrel and Brent leapt $2.11 or 2.6% to close at $84.03. The daily Alaska North Slope crude closing price estimate from the Alaska Department of Revenue for March 13 was not released by press time for Petroleum News. ANS and Brent have been closely correlated of late, in fact Brent on March 12 held a slim 19-cent premium over ANS. Assuming a corresponding 2.6% increase for ANS March 13, ANS likely jumped some $2.12 to close in the vicinity of $83.85. The Alaska Department of Revenue in its Spring Revenue Forecast released March 13 said the ANS price for FY 2024 is projected at $84.08, and $78.00 for FY 2025. Although an ANS crude price was then yet A bill for clean energy Railbelt electric utilities support intent of targets for future energy sources By ALAN BAILEY For Petroleum News During its March 7 meeting the Alaska House Resources Committee gathered comments from Alaska Railbelt electric utilities on House Bill 368, a bill designed to enact a clean energy standard for the generation of electricity in the Alaska Railbelt. Officials from utilities Homer Electric Association, Matanuska Electric Association and Golden Valley Electric Association expressed posi- tive views of the bill, which would set a target of 35% clean power generation by Dec. 31, 2036, and 60% of clean power generation by Dec 31, 2051. These target dates would be delayed if the Railbelt electricity transmission system is not upgraded to meet the min- imum capabilities required to support the shipment of the clean energy. The renewable energy portfolio standard During the 2023 legislative session two bills were introduced, Senate Bill 101 and House Bill 121, pro- posing a renewable energy portfolio standard, or RPS, for Alaska. The RPS would require all electric utilities in the state to supply at least 25% of their electricity from renewable sources by Dec. 31, 2027, 55% by Dec. 31, 2035, and 80% by Dec. 31, 2040. Financial penalties would be assessed for utilities that do not meet the RPS targets. These bills were strong- ly supported by advocates for the use of renewable energy, while electric utilities raised questions over Inlet’s energy dilemma House Resources Committee reviews tough alternatives as gas shortage looms By KRISTEN NELSON Petroleum News C ook Inlet natural gas provides the fuel for most Southcentral heat and power, but it’s in short supply, with the supply getting shorter. Is there more gas in the Cook Inlet basin? Absolutely, members of the Alaska House Resources Committee were told in a March 4 presen- tation by Trevor Jepsen and Ed King, staff to commit- tee Chair Tom McKay. But additional Cook Inlet gas will cost more to produce, as it requires development costs in some cases, exploration costs in others and for a third tranche of gas, research and development costs. The U.S. Geological Survey has estimated there are some 19 trillion cubic feet of natural gas in Cook Inlet, King said, but not all those gas molecules are equal — not as accessible and not as developable. He said the Alaska Department of Natural Resources estimates that 820 billion cubic feet of gas are proved and developed, requiring just operating costs to get to market, at some $8 to $10 per thousand cubic feet. That is the gas that Hilcorp Alaska, Furie and a few smaller producers are currently providing. Then there is discovered but undeveloped gas, which has development costs, and is likely to cost $11 to $16 per mcf, King said. The next tranche is undiscovered, economically viable, estimated at $17 to $25 per mcf because of see OIL PRICES page 9 see ENERGY STANDARD page 8 see INLET ENERGY page 8 ASHLEY GILBERT GWEN HOLDMANN The United States produced more crude oil than any nation at any time, for the past six years in a row, the EIA said in a March 11 report. 10 PETROLEUM NEWS • WEEK OF MARCH 17, 2024 knowledge of multiple flow tests on adjacent acreage. Results from the Upper SFS reservoir will be avail- able on completion of flow back activities, 88 Energy said. The Hickory-1 well is located within 88 Energy’s Project Phoenix acreage, directly adjacent to the Trans- Alaska Pipeline System and the Dalton Highway. The Upper SFS will be the first zone tested followed by the SMD-B zone. Each zone will be independently isolated, stimulated and flowed to surface using nitrogen lift to assist in the efficient clean-up of the well. Although as mentioned the entire program for each zone is expected to take approximately 10 days, 88 Energy may choose to adjust the schedule during the flow back program to ensure optimal data collection. Extensive suite An extensive suite of data will be captured, including but not limited to downhole and surface fluid samples, downhole pressure and temperature data, surface pres- sure and temperature data. Flow rates of oil, gas and water will also be recorded. The entire testing program is scheduled for comple- tion during March 2024. The March 10 announcement was authorized by the company’s board, including Ashley Gilbert, Managing Director. Approval on Nov. 30 As reported in the Dec. 10 issue of Petroleum News, on Nov. 30, an operating subsidiary of 88 Energy received approval for the Toolik River unit, Hickory 1, frac and flow testing unit plan of operations amendment from the Alaska Department of Natural Resources' Division of Oil and Gas. The Toolik River unit or TRU, is approximately 30 miles south of Deadhorse in oil and gas lease 392314. 88 Energy planned to build a 500-foot by 500-foot ice pad connected to the Dalton Highway by a 400-foot by 35-foot ice road, with a total footprint of approximately six acres. All buildings used for the project were to be tempo- rary. Ultra-low sulfur diesel fuel will be trucked to the proj- ect site by commercial carriers and stored in four 9,980- gallon tanks on pad as needed to support operations. Spill response equipment will be staged on location and managed by an onsite spill technician contracted through Alaska Chadux Corp. Stick picking and site inspection will occur during the following summer. Tundra travel and ice construction will be permitted separately through LAS 34367. Plan activities include the following: •Construct ice pad and driveway •Re-enter Hickory 1 well •Frac and flow tests •Stick picking •Closeout site inspections The Nov. 30 approval letter was addressed to Gilbert. Pantheon: Talitha, Alkaid In an Oct. 12, 2023, ASX release, 88 Energy said it remains very encouraged by the progress of its neighbor to the north of Project Phoenix, Pantheon Resources (operated by Great Bear), which recently announced a “material, independently certified contingent resource for the Lower Basin Floor Fan, or BFF, reservoir,” noting that the BFF reservoir was the deepest of the multiple hydrocarbon-bearing pay zones intersected as part of the Hickory-1 exploration well. Four of the wells drilled in 2022 were drilled by Great Bear Pantheon. The company completed the Alkaid 2 well in its Alkaid discovery, together with a near vertical pilot hole for that well. The company also drilled a pilot hole in its Talitha prospect and drilled its Theta West 1 exploration well. All of these wells were drilled near the Dalton Highway, south of Prudhoe Bay. —KAY CASHMAN continued from page 1 HICKORY-1 WELL n See map on page 11 ADL 355021, are net profit share leases. Hilcorp earlier applied to the Alaska Oil and Gas Conservation Commission for a smaller expansion to the northwest of the existing Schrader Bluff oil pool as described in AOGCC Conservation Order 477. (See story in Jan. 23 issue of Petroleum News.) The AOGCC request lists four affected leases, two of which coincide with the six leases in the unit application expansion. In addition to being a larger expansion, the unit expansion request includes both Kuparuk and Schrader Bluff reservoirs. Proposed drilling Hilcorp told the division it proposes to drill 10 wells in the expansion area this year and next, three Kuparuk formation wells — one from K Pad and two from F Pad — and seven Schrader Bluff wells, all from R Pad. The company told the division an additional 18 wells target- ing Schrader Bluff across two leases, ADL 355018 and ADL 355021, are planned by the end of 2008. Both of those leases are listed in the Schrader Bluff expansion request to AOGCC. F Pad and R Pad are in the northern expansion area, with R Pad currently under construction. K Pad is in the southern expansion area. The most recent work at that pad was approval earlier this year of a Hilcorp proposal to install a 6-inch FlexSteel line inside an existing abandoned 14-inch line from SK Junction to K Pad. The new line will bring high-pressure water to K Pad for injection and production support. That project was approved in January and is expected to be completed by April. AOGCC production data for January shows K Pad production all coming from the Kuparuk River oil pool. Previous drilling Hilcorp listed four wells previously drilled in the northern area of the proposed expansion and said there has been no drilling in the proposed expansion area in the southeast. Exploration activity in the northern expansion area occurred between 1992 and 2004. NW Milne 1 was drilled in 1992. Hilcorp said the well “logged oil to the base of the Kuparuk sands.” In 1996, N Milne 1 and N Milne 2 were drilled, with N Milne 1 logging oil to the base of the Kuparuk sands while N Milne 2 found those sands to be wet. Nikaitchuq 2, drilled in 2004, did not encounter Kuparuk sands, Hilcorp said. The first three wells found the Schrader Bluff interval to be wet. The fourth well, Nikaitchuq 2, logged an oil water contact at 4,171 feet true vertical depth, “marking the northern extent of the oil in the Schrader Bluff Oil reser- voir in the main fault block of the expansion area,” Hilcorp said. Nikaitchuq 2 was not tested, while the other three pri- marily targeted the deeper Kuparuk, “with the intent to try to determine the extent of the oil accumulation.” —KRISTEN NELSON continued from page 1 MILNE EXPANSION transmission of power across multiple sectors of the sys- tem uneconomic, because of the manner in which the fees charged by individual utilities stack up. Instead, under the terms of the new bills, a new transmission cost recovery mechanism would involve a tax that each inde- pendent power producer and electric cooperative would pay, based on the amount of electricity that each of these entities generates. Independent power producers would also become exempt from paying local taxes, in a similar manner to nonprofit electric cooperatives. Moving cheap power Gwen Holdman, University of Alaska Fairbanks Associate Vice Chancellor for Research, Innovation & Industry Partnerships, told the committee that the trans- mission issues revolve around moving cheap power to consumers, wherever they are located, from whatever sources are available. And she characterized the current Railbelt transmission system as being “kind of in the dark ages.” The expectation is that future power supplies will involve much more movement of power between different regions of the Railbelt — power generation sys- tems benefit from economies of scale, a factor that drives the need to be able to viably ship power to wherever it is needed. For example, were a major geothermal energy project to be constructed at Mount Augustine in Cook Inlet, Golden Valley Electric Association in Fairbanks would likely want to be able to make use of some of that power, Holdman suggested. Transmission system upgrades needed Tony Izzo, chief executive officer of Matanuska Electric Association, told the committee that a top prior- ity recommendation from the Railbelt subcommittee of the gov- ernor's Energy Security Task Force had been the need to upgrade and unify the Railbelt transmission sys- tem. The wheeling and pancaking of transmission fees, together with significant limitations in the capac- ities of transmission interties between different regions of the Railbelt, constrain the possibilities for utilities to use the lowest cost power generation in the system. On the other hand, the utilities are cooperatives that have systems that are built under the constraints of what their members can afford, without shareholders to pro- vide investment dollars, Izzo said. Economic dispatch MEA and the neighboring Chugach Electric Association are operating an economic dispatch arrange- ment in which they minimize electricity costs through shared use of their most efficient power generation. As part of this arrangement, the utilities do not charge each other wheeling fees for use of their transmission sys- tems, Izzo said. If the current constraints in the use of the major trans- mission interties could be eliminated, the whole Railbelt could benefit from a similar arrangement, he comment- ed. Izzo also commented that federal grants for upgrad- ing the transmission system, together with required state matching funds, could make possible the construction of a system that could lower electricity costs by enabling the development of large-scale renewables while also improving supply reliability. A critical point John Burns, chief executive officer of Fairbanks based Golden Valley Electric Association, told the committee that the Railbelt electrical system has reached a critical point, with a need for transformative change. The requirement to make it possible to viably move low cost electrons from relatively large scale genera- tion sources to wherever they are needed, without constraint, will require appropriate legislation, he said. “We should be agnostic as to where generation sources are located,” Burns said. —ALAN BAILEY continued from page 1 RAILBELT BILL TONY IZZO JOHN BURNS MEA and the neighboring Chugach Electric Association are operating an economic dispatch arrangement in which they minimize electricity costs through shared use of their most efficient power generation. Federal agency says Alaska’s coastline has potential for more renewable energy, carbon storage projects https://www.webcenterfairbanks.com/2024/03/22/more-ev-chargers-around-corner-fairbanks-where-will-they-go/ 1/4 A little-known federal agency called Bureau of Ocean Energy Management has a big role in regulating nearly 7,000 miles of coastline in Alaska. Last week, the bureau’s Regional Director Givey Kochanowski and Public Affairs Officer John Callahan met with dozens of lawmakers in Juneau. They also met with KTOO reporter Anna Canny, who asked them about the emergence of new technologies like offshore renewable energy and carbon storage projects in the state. This interview has been edited for length and clarity. Federal agency says Alaska’s coastline has potential for more renewable energy, carbon storage projects https://www.webcenterfairbanks.com/2024/03/22/more-ev-chargers-around-corner-fairbanks-where-will-they-go/ 2/4 Givey Kochanowski: Good morning. I’m Givey Kochanowski. I’m the Regional Director for the Alaska region of the Bureau of Ocean Energy Management. John Callahan: Yeah, John Callahan, and I’m the Public Affairs Officer for the Alaska Region. Anna Canny: Thanks for joining me this morning. So I want to start off just for some of our listeners who haven’t heard of the Bureau of Ocean Energy Management. Could you give us a little rundown of some of the work your agency does? Givey Kochanowski: We were created by Congress, originally to economically and environmentally friendly developed the Outer Continental Shelf, and those means the federal waters of the United States. And here in Alaska and elsewhere, that begins three miles offshore. So we’re not a funding or development agency. We’re a regulatory and permitting agency. So we work with other federal and state agencies to accomplish our mission in partnership. John Callahan: Um, if you wanted to explore for oil and gas, or minerals, or develop any energy sources in that zone — more than three miles offshore — we’re the bureau that you would come to. Anna Canny: Sounds like that would apply to a wide variety of resource development projects. And I know in the past, the agency has focused on oil and gas projects, but I’m wondering if you could speak a little bit to the agency’s recent shift towards renewable energy projects? Givey Kochanowski: It’s kind of a shift, but it’s kind of not a shift at the same time. We have never stopped doing our legacy mission of conventional energy, we have active leases and Cook Inlet and on the North Slope for conventional energy. We have petroleum engineers on staff that helped maintain our work and the conventional side. But in addition to that, we’re expanding into some exciting new areas, which include renewable power, critical minerals and marine minerals, and also carbon storage. But on a renewable front, what’s really exciting right now is a study that just came out from the National Renewable Energy Lab that we funded, looking at the renewable energy potential for Cook Inlet. And that has grid-wide impacts for Alaska where the majority of our population lives. Federal agency says Alaska’s coastline has potential for more renewable energy, carbon storage projects https://www.webcenterfairbanks.com/2024/03/22/more-ev-chargers-around-corner-fairbanks-where-will-they-go/ 3/4 John Callahan: Tidal energy is promising, wind energy is probably more promising in terms of a development prospect in the near-term. There’s an area off Southern Cook Inlet, north of the Barren Islands, that has literally literally some of the best winds in the world — it blows hard, it goes constantly — and those are the sort of resources that we’re looking to bring to bear. Anna Canny: Okay, so developing renewables, that’s huge for cutting the amount of carbon emissions we’re putting into the atmosphere. On the flip side of that, I noticed you mentioned carbon storage or carbon sequestration — basically taking carbon out of the atmosphere and storing it, in this case, underground. And I thought that was really interesting. That’s been a hot topic here in Alaska, since Governor Dunleavy introduced his carbon management bill last session. So what will BOEM’s role be in, in safely rolling out those types of projects in the state? Givey Kochanowski: If you look at a map of the state, many of the areas in coastal Alaska that fall in the federal jurisdiction, are very well suited for carbon storage — so the Cook Inlet and Northwestern Alaska — I think this is an exciting time to be in this space to be in the ground level of it. And that it’s also wonderful to come down here and learn that the state government is working in parallel to a lot of what we’re trying to accomplish, that there could be a lot of synergies there and collaboration. John Callahan: Yeah, and, and very relevant to that, so carbon sequestration, as you know, is a very promising technology, right? But it’s in its relative infancy. Our bureau, we again, are the ones who are going to be tasked with regulating that, in the offshore space. And in fact, we have been developing draft regulations in concert with other cooperating agencies, and expect to have draft regulations out to that effect later this year. Anna Canny: And finally, you’re in town this week talking with legislators about some of these things — the carbon sequestration, the new renewable energy projects – how are those conversations going? And could you give us an idea of, of what that might mean for the agency’s future work in the region? John Callahan: All the legislators down here, both left and right, are very focused on energy issues — well-informed, we’ve gotten good questions. And we really Federal agency says Alaska’s coastline has potential for more renewable energy, carbon storage projects https://www.webcenterfairbanks.com/2024/03/22/more-ev-chargers-around-corner-fairbanks-where-will-they-go/ 4/4 appreciate the opportunity to educate them on how BOEM is part of that energy mix, especially as we get this renewable energy initiative kicked off. Givey Kochanowski: Yeah, and you know, as Alaskans, many of us have concerns about the overreach of the federal government pushing stuff onto the state without state coordination or collaboration, and there’s no better way to get collaboration than working with the state, coming down here talking to legislators working with state agencies, like the Alaska Energy Authority, and the Department of Natural Resources, Department of Revenue. And we have several state agencies as part of our Cook Inlet workgroup, looking at ways to harmonize the development pathway for industry, so that you don’t get nine or ten different answers from nine agencies, that you get a solid approach to what will it take to actually make a project happen in Alaska. DOG transfers Mustang control to Finnex retro to Nov. 1 page 6 see SOURDOUGH RESET page 11 see POWER AGREEMENT page 10 Jade seeks Sourdough reset; files reconsideration request On March 1, Jade Energy sent John Boyle. commissioner of the Alaska Department of Natural Resources, by certified mail a “Request for Reconsideration of Commissioner Decision Relayed in Point Thomson Area F 2024 6th POD — Held in Abeyance.” (That decision was made on Feb. 24.) The request for reconsideration is a step in a process that must be followed before Jade can sue DNR in Alaska Superior Court. Erik Opstad, Jade managing member, has not publicly said whether court is his next step. Another option for the independent is to walk away and take an estimated $20 million loss without recompense. see TMX NUMBERS page 8 Alberta revenues from TMX look good; no in-service date yet set The number crunching for Canada’s Trans Mountain pipeline expansion, TMX, is now in full swing with the new pipeline connection of 890,000 barrels per day from the Alberta oil sands to Vancouver’s tanker terminal expected to generate C$40 billion in royalties and taxes over two decades, more than cover- ing the C$31 billion price tag of the expansion project. So far, so good for Alberta. Although the TMX owner — the Canadian government — has yet to set an in-service date for TMX, the company has served notice to producers to start moving crude into Trans Mountain. “TMX has issued a call for line-fill … as a matter of fact they are looking for 2.1 million barrels per day in April and another 2.1 million bpd in May,” said Derek Evans, chief City of Unalaska exits Makushin geothermal, ends power agreement During its monthly meeting on Feb. 27 the Unalaska City Council allowed the expiry of a power purchase agreement with Ounalashka Chena Power LLC, or OCCP, for the pur- chase of electricity from a planned geothermal power plant on the flank of the Makushin volcano on Unalaska Island in the Aleutians. The decision leaves OCCP, developer of the proj- ect, without a customer for electricity from the geothermal system. And, with the company already experiencing difficul- ty in securing sufficient investment and grant funding to com- plete the project, the Unalaska city decision has presumably brought the project to a halt. PPA modification In early November OCCP requested a modification to the PPA that would increase the price of the electricity from the planned power plant from 16 cents per kilowatt hour to 22 cents per kilowatt hour. During a Nov. 28 Unalaska council meeting David Matthews, OCCP program manager for the Makushin project, commented that the electricity rate in the PPA was associated with the price of diesel fuel and that the Vol. 29, No. 10 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of March 10, 2024 • $2.50 l EXPLORATION & PRODUCTION l ALTERNATIVE ENERGY l FINANCE & ECONOMY Excited but cautious APA views exploration drilling on E. North Slope as risky but high reward By KAY CASHMAN Petroleum News When asked to provide more color on the risk profile for the exploration drilling program APA Corp. is participating in this winter on Alaska’s eastern North Slope, the company’s CEO and President John J. Christmann said, “these are 3D and amplitude supported but this is a step-out in an area where there is risk associated with it so I’m not going to give you a number on a ratio. … We’re going to drill three wells and they are risky but they’re high reward.” APA is the holding company for Apache Corp. Its partners in the venture are operator Bill Armstrong’s Lagniappe Alaska and Santos’ Oil Search (Alaska), both of which hold a 25% work- ing interest ownership in the 148-lease block on 275,000 acres being explored. APA holds a 50% working interest. Christmann was participating in a Feb. 22 con- ference call covering fourth quarter and full year 2023 financial and operational results. He asked Tracy Henderson, the company’s What about using coal? Study recommends coal-biomass plant with CCS for low-cost Southcentral power By KRISTEN NELSON Petroleum News A new coal- and biomass-fired power plant, coupled with carbon capture and storage, CCS, may provide the cheapest, lowest carbon and longest lasting answer to the problem of providing future electrical power to Southcentral Alaska as Cook Inlet’s natural gas supply is depleted. This was the conclusion of studies that Frank Paskvan, with the University of Alaska Fairbanks’ Institute of Northern Engineering, reviewed for the House Special Committee on Energy March 5. One, by the Alaska CCUS Workshop, published as SPE Paper 213051 last year (“Alaska CCUS Workgroup and a Roadmap to Commercial Deployment”) focuses on carbon capture, utilization and storage, and a second, released Feb. 28, a joint project of UAF-INE and the Energy & Environmental Research Center at the University of North Dakota, focuses on the potential of low-carbon ANS tests mid-$80s A March 1 breakout fades, but ANS recovers for a mere 5-cent weekly loss By STEVE SUTHERLIN Petroleum News A NS held its own in the $80s on the trading week ending Wednesday March 6, slipping just 5 cents over the week as it gained 84 cents on the day to close at $82.34 per barrel. West Texas Intermediate gained 98 cents to close at $79.13 and Brent gained 92 cents to close at $82.96. The Alaska benchmark tested the mid $80s March 1, jumping $1.14 to close at $83.05. WTI leapt $1.71 to close at $79.97 and Brent slipped 7 cents to close at $83.55. But all three benchmarks gave up ground on March 4 and March 5. On March 4 ANS fell 75 cents to close at $82.30. WTI plunged $1.23 to close at $78.74 and Brent dropped 75 cents to close at $83.55. ANS dropped 80 cents March 5 to close at $81.51, while WTI shed 59 cents to close at $78.15 and Brent fell 76 cents to close at $82.04. Red ink was the order of the day Feb. 29, as see APA DRILLING page 10 see WHAT ABOUT COAL? page 12 see OIL PRICES page 9 DEREK EVANS ERIK OPSTAD “What interested us in the block was that we do see materiality with these prospects that warranted exploration.” —Tracy Henderson On March 3, the Saudi Arabia Press Agency reported that Saudi Arabia will extend its voluntary crude production cut of 1 million barrels per day through end of second quarter 2024. The study also found that biomass-coal energy supply with CCS is lower cost than natural gas generated energy, with or without CCS, “and biomass-coal energy supply with CCS provides lower CO2 emissions than the current natural gas energy supply without CCS.” 10 PETROLEUM NEWS • WEEK OF MARCH 10, 2024 cost of diesel fuel had increased significantly since the original 16-cent pricing had been set. At the same time, there had been a 22% increase in project costs. And at the 22-cent price, the cost of the geothermal energy would still be significantly lower than the cost of diesel fueled power, Matthews had said. OCCP is seeking a price adjustment that would satisfy investors in the project while also lowering the cost of energy in Unalaska, Matthews commented. As recently as January OCCP announced that it was approaching a final investment decision for the project. However, although the project has been planned and per- mitted, the company has been struggling to find the means to fully fund the project. City manager recommendation In a memo to the city council, for discussion at the Feb. 27 council meeting, City Manager William Homka recommended allowing the PPA to expire. And during the meeting several council members, while supporting the concept of developing the geothermal energy, expressed concern about continued support for the proj- ect, given recurring delays in the project timeline and the requested increase in the price of the electricity. The city has been supportive of developing Makushin geothermal power, given the city’s aging electrical sys- tem and its dependence on diesel fueled generation. One council member commented that the city had placed on hold investigations into the use of wind power, given the prospect of obtaining geothermal power. Because of the planned geothermal power system, the city had also decided not to proceed with the acquisition of a flywheel system and battery energy storage, to stabilize renewable energy supplies, Homka wrote. Three modifications to the PPA Homka wrote that there had been three modifications to the original PPA, authorized in August 2020. These modifications have ultimately involved moving the orig- inal commercial operation deadline from May 31, 2024, to May 31, 2027, and extending the deadline for project financing from June 10, 2021, to Dec. 10, 2023. Then in December 2023 OCCP notified the city that it needed to revise its project schedule and delay project completion to a date in 2028, Homka wrote. “The city has been patient and supportively waiting for the project to advance,” Homka wrote. “But, in wait- ing, the city has deferred on investing in electric genera- tion and distribution system needs.” Homka wrote that the requested change in the elec- tricity rate in the PPA from 16 cents to 22 cents would increase the cost commitment for a 30-year PPA from $480 million to $660 million. OCCP is also seeking to sell 20% of its power to another entity, to avoid a poten- tial tax problem associated with selling to a single cus- tomer, Homka wrote. There is potential to sell power to a fish processing plant on Unalaska Island. A need for testing Homka also commented that OCCP has been working with the Department of Energy to try to gain energy loans for the project but has run into issues relating to the need to conduct tests to confirm the amount of energy that the project would be capable of producing. Testing of the resource would require drilling into the geother- mal source — current knowledge of the resource comes from an exploration well drilled several decades ago. The testing might cost somewhere around $25 million to conduct and could not be started until there are suitable weather conditions in a few months time, Homka wrote. There were also issues relating to the required construc- tion of a road to the project site, he wrote. As a consequence of all of these issues, Homka said that, at this point, the city should allow the PPA to expire. OCCP responds Makushin program manager David Matthews filed a memo with the city council, in response to Homka’s memo. Matthews wrote that “there has been an incredi- ble amount of progress and milestones accomplished, short of a commitment for a full project financing pack- age.” Until a few weeks ago OCCP had understood that full project financing was in sight. The company suc- cessfully completed phases 1 and 2 of the Department of Energy loan commitment process but has found that the process for due diligence with DOE has not been as straightforward as DOE had previously indicated. And there are mitigating circumstances that would support not allowing the PPA with the city to lapse, Matthews wrote. Although OCCP does not yet have suf- ficient financing to complete the project, the company has secured financing that is allowing the project to pro- ceed. The company has a contract with Ormat Technologies for the engineering and construction of the power plant and has selected contractors for the whole project. “Timelines have changed only due to the difficulty securing long term financing,” Matthews wrote. OCCP has requested an increase to the electricity rate in the PPA, because the current rate is insufficient to cover all financing options. At the same time, the increased rate would still be lower than electricity rates resulting from diesel generation, Matthews wrote. A six-month time window Matthews recommended that a modified PPA should be approved. The city could then give OCCP six months to secure a path to adequate financing. If that financing arrangement is not achieved, the project would come to an end. This six-month time window would not signifi- cantly delay the city’s efforts to implement an alternative plan for improvements to the electrical system, he sug- gested. During the Feb. 27 council meeting Matthews sug- gested that another option would be to maintain the elec- tricity rate at 16 cents and to seek grant funding to fill the funding gap. Again, OCCP would be given six months to secure the funding. If on the other hand grant funding were to be found after the rate had been increased to 22 cents, it would be possible to reduce the rate back down. At this point OCCP has the necessary permits and has done the engineering for the project. And the project remains a great opportunity for the city, Matthews said. At the end of the meeting a council member proposed a motion to extend the PPA for a further six months. However, since no one seconded the motion, the motion failed, thus allowing the PPA to expire. —ALAN BAILEY continued from page 1 POWER AGREEMENT exploration manager, to expand on his response and she said: “What interested us in the block was that we do see materi- ality with these prospects that warranted exploration.” Armstrong’s work led to the discovery of Pikka, a billion barrel new field now under construction west of Prudhoe Bay. He thinks there are new oil discoveries to be made east of Prudhoe Bay in the Brookian. In a text to Petroleum before the part- nership deal was struck between APA, Santos and Lagniappe, Armstrong described the area as “defined off of high effort, reprocessed modern 3D. Really exciting stuff. Big targets.” There has been “virtually no prior drilling in the area. The wells that have been drilled have great shows and some have bypassed pay on old logs,” Armstrong added. When asked in the Q&A segment of the Feb. 22 conference call whether the partners were searching for Pikka look- alikes, Henderson said: “Yes, I would agree with that. We’re looking at more play types like Pikka and Willow (both under development now) on the other side of Prudhoe Bay. And that is the Brookian play we’re going to be exploring for in a younger sequence but it’s absolutely … the same geologic model and set up that we expect to see. Basically just further east than it’s been explored for.” When asked “what’s next in the time- line for the program, Christmann said: “We’re in the exploration stage right now, so we’ve done a lot of scoping. It’s onshore on state lands. Things can move a little quicker than on federal there. You’re close to big pipeline capacity, but let’s work through the exploration phase, see what we find and then go from there at a later date. But we’re excited about it.” In 2024, APA plans to invest $1.9 bil- lion to $2.0 billion in upstream oil and gas capital worldwide. APA said it will invest for the long term by directing $100 mil- lion of the upstream budget toward explo- ration activities predominantly in Alaska. Approximately $27 million has already been spent in the state on the initial phase of exploration. “In Alaska it is a position that sits between Prudhoe Bay and ANWR in the Brookian play, so we’ve entered into the area where we have analogues there that have worked, but they are in an area where that play has not really been explored for. So we’re testing … in an underexplored region, As John said we are drilling three wells in this winter sea- son. All of those will spud in Q1,” Henderson said. We’ve “got good seismic control and they’re fully supported so we feel good about them but it IS exploration,” Christmann said. The partners are looking at drilling three more wells next winter, so a total of six wells with three rigs drilling simulta- neously. lAPA CORP.continued from page 1 APA DRILLING 3/26/24, 9:43 AM Alaska Matters: Funding for Cook Inlet Energy Transmission https://alaskasenate.org/senator/claman/030824_alaska_matters.htm 1/5 Protecng Your Rights: Serving West Anchorage March 8, 2024 In this issue: GRIP funds for electric transmission upgrades Execuve Order update Community Informaon Dear Friends and Neighbors, As our Anchorage school students begin spring break, we've had a busy week in Juneau working to address Cook Inlet energy, public educaon funding, and governor's execuve orders. Please read on for updates. GRIP funding in the Capital Budget Last fall, the Alaska Energy Authority received a $206 million grant from the Department of Energy to construct a subsea power transmission line between Anchorage and Kenai. The Grid Resilience and Innovaon Partnership (GRIP) money comes as part of the Infrastructure Investment and Jobs Act, which passed Congress with the strong support of all three members of the Alaska Delegaon. The construcon of a second transmission line along the Kenai Peninsula poron of the Railbelt will help guarantee transmission of power in the event of an emergency shutdown along exisng lines. The plan also calls for the installaon of mulple Baery Energy Storage Systems, which will increase the capacity to produce and store affordable energy on the Railbelt. Transmission upgrades are an important part of a diverse energy soluon. As Cook Inlet natural gas supplies decline, new energy projects, including renewable energy, will become increasingly important to our energy security. Reliable transmission infrastructure ensures that those projects will be able to connect to the grid and provide energy anywhere it is needed along the Railbelt. The GRIP funding comes with a requirement for state matching funds. It is crical that we appropriate the funds to match this federal grant and secure upgrades to our energy infrastructure. 4/3/24, 2:28 PM In this issue: NEVI Plan Spotlight, EV Signs, Funding Opportunitites, and Upcoming Events https://mailchi.mp/16c0d5baf8d2/aea-submits-ev-infrastructure-plan-to-joint-office-13722287?e=[UNIQID]1/9 View this email in your browser Alaska Electric Vehicle Working Group Newsletter, March 7, 2024 Plan Spotlight We still have a lot of material to cover in our ongoing spotlight on sections of Alaska’s Electric Vehicle Infrastructure Implementation Plan. This month’s topic is State Agency Coordination. This section dives into the Alaska Energy Authority’s (AEA’s) history of administering funds for electric vehicle (EV) infrastructure development, and how we are working with our partner, the Alaska Department of Transportation & Public Facilities (DOT&PF), to administer Alaska’s National Electric Vehicle Infrastructure (NEVI) funds and 4/3/24, 2:28 PM In this issue: NEVI Plan Spotlight, EV Signs, Funding Opportunitites, and Upcoming Events https://mailchi.mp/16c0d5baf8d2/aea-submits-ev-infrastructure-plan-to-joint-office-13722287?e=[UNIQID]2/9 implement this plan. You can read the full section on pages 6-8. Here are some highlights: AEA was designated as the State’s lead agency for EV planning in 2018. DOT&PF and AEA signed a memorandum of agreement in 2022 to determine the financial and contracting process required to implement the NEVI Plan since DOT&PF is the responsible recipient of the funds. AEA agreed to: Plan and designate alternative fuel corridors Manage project selection and match requirements Develop a public involvement plan Hold a public project evaluation and selection process Award NEVI funds Be in compliance with federal regulations Ensure alignment with DOT&PF’s planning process DOT&PF agreed to: Provide input and make sure the Plan is following state priorities Make sure the plan aligns with DOT&PF’s Family of Plans and Sustainable Transportation Program Share regulatory expertise with AEA Include NEVI funding in the Statewide Transportation Improvement Program Provide annual funding notices and manage the federal contractual agreement with the Federal Highway Administration What does this sign mean? Subscribe 4/3/24, 2:28 PM In this issue: NEVI Plan Spotlight, EV Signs, Funding Opportunitites, and Upcoming Events https://mailchi.mp/16c0d5baf8d2/aea-submits-ev-infrastructure-plan-to-joint-office-13722287?e=[UNIQID]3/9 Whether or not you drive an EV, you might have noticed these signs popping up around the state. These signs are displayed at EV chargers installed with Volkswagen (VW) Environmental Mitigation Trust funds. When Alaska became a beneficiary of $8.125 million of VW funds in 2018, the Governor designated AEA as the lead agency for EV planning. As part of this responsibility, we administered the VW funds, of which 15 percent were used to deploy EV charging infrastructure throughout the state. AEA helped guide the process to award these funds to individual site hosts from Healy South to Seward and Homer to build, own, and operate charging stations. All of the charging stations that were built with VW funds are privately owned and operated but remain publicly available. Alaska’s NEVI funds will be awarded similarly. AEA and DOT&PF administer the funds, but once the money is awarded to individual site hosts and the charging stations are built, everything will be available for public use but privately owned and operated by the site hosts. Take a look at the chart below to see how NEVI funding is allocated. 4/3/24, 2:28 PM In this issue: NEVI Plan Spotlight, EV Signs, Funding Opportunitites, and Upcoming Events https://mailchi.mp/16c0d5baf8d2/aea-submits-ev-infrastructure-plan-to-joint-office-13722287?e=[UNIQID]4/9 Southeast Alaska EV Charging Station Implementation Program – RFA 2024-01 4/3/24, 2:28 PM In this issue: NEVI Plan Spotlight, EV Signs, Funding Opportunitites, and Upcoming Events https://mailchi.mp/16c0d5baf8d2/aea-submits-ev-infrastructure-plan-to-joint-office-13722287?e=[UNIQID]5/9 Recently, the Southeast Conference (SEC) issued a Request for Applications (RFA) that would award successful applicants the chance to construct electric vehicle charging stations. The SEC plans to help fund and construct between six to 10 level-2 chargers in Southeast communities that do not currently have publicly available charging stations. Awardees will receive up to $30,000 per selected site, or potentially more if installing multiple chargers. The awarded funds can cover up to 80 percent of the project cost and successful applicants will be expected to cover any excess costs. Eligible applicants include: For-profit businesses or commercial property owners Units of the State of Alaska or local government Public agencies or authorities within the State of Alaska Special purpose districts Federally recognized Indian Tribes This funding was secured through a grant from AEA and is funded by the Environmental Protection Agency and VW. Interested parties can find the application and other materials on the SEC website. Applications are due April 2, 2024. Clean Bus Planning Awards 4/3/24, 2:28 PM In this issue: NEVI Plan Spotlight, EV Signs, Funding Opportunitites, and Upcoming Events https://mailchi.mp/16c0d5baf8d2/aea-submits-ev-infrastructure-plan-to-joint-office-13722287?e=[UNIQID]6/9 Applicants to the Clean Bus Planning Awards (CBPA) program can apply to receive technical assistance resources from the National Renewable Energy Laboratory (NREL) to help deploy zero-emission bus fleets. The Joint Office of Energy and Transportation is funding this $5 million program to help successful applicants develop comprehensive bus fleet electrification transition plans. After the plans have been developed, applicants will also be eligible for assistance in deploying the new fleet once the plan is complete. Eligible applicants include state and local governments providing bus service (including local school districts), private school bus fleets, nonprofit school transportation associations, tribes, tribal organizations, or tribally controlled school bus services for Bureau of Indian Affairs-funded schools, and recipients of Federal Transit Administration grants. Eligible entities can apply using NREL’s CBPA application form. Applications are open on a rolling basis until September 30, 2024. Latest Alaska EV Count 4/3/24, 2:28 PM In this issue: NEVI Plan Spotlight, EV Signs, Funding Opportunitites, and Upcoming Events https://mailchi.mp/16c0d5baf8d2/aea-submits-ev-infrastructure-plan-to-joint-office-13722287?e=[UNIQID]7/9 Upcoming Events Alaska Electric Vehicle Working Group Meeting, March 22, 2024 Join us from 11:30 a.m. to 1 p.m. for a presentation on EV microtrends and winter versus summer performance in Alaska — this will be a hybrid meeting. Past Issues 4/3/24, 2:28 PM In this issue: NEVI Plan Spotlight, EV Signs, Funding Opportunitites, and Upcoming Events https://mailchi.mp/16c0d5baf8d2/aea-submits-ev-infrastructure-plan-to-joint-office-13722287?e=[UNIQID]8/9 Join in Person AEA Office, Denali Room 813 W Northern Lights Blvd. Anchorage, AK 99503 Join via Zoom here Meeting ID: 827 4448 7775 Passcode: 860888 • 833 548 0282 US Toll-free • 877 853 5257 US Toll-free • 888 475 4499 US Toll-free • 833 548 0276 US Toll-free Anchorage Transportation Fair, Thursday, March 28, 2024 Stop by anytime between 3 to 7 p.m. Alaska Airlines Center 3550 Providence Dr, Anchorage, AK 99508 To learn more click here. What We're Reading Clean Bus Planning Awards · Joint Office of Energy and Transportation (driveelectric.gov) 4/3/24, 2:28 PM In this issue: NEVI Plan Spotlight, EV Signs, Funding Opportunitites, and Upcoming Events https://mailchi.mp/16c0d5baf8d2/aea-submits-ev-infrastructure-plan-to-joint-office-13722287?e=[UNIQID]9/9 Clean Bus Planning Awards Support Fleet Electrification With Custom Transition Plans | News | NREL Anchorage Transportation Fair (arcgis.com) Opportunities - Southeast Conference (seconference.org) Facebook LinkedIn Website The Alaska Energy Authority’s Alaska Electric Vehicle Working Group involves collaborative stakeholders focused on promoting the use of electric vehicles (EVs) in Alaska by removing barriers to EV adoption and increasing access to charging infrastructure. Stay up to date on AEA's EV efforts at our website here. Copyright © 2024 Alaska Energy Authority, All rights reserved. Want to change how you receive these emails? You can update your preferences or unsubscribe from this list. 2/28/24, 1:47 PM Over 20 Alaska villages on tap for $125M in federal funds for solar and hydroelectric projects - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/02/27/over-20-alaska-villages-on-tap-for-125m-in-federal-funds-for-solar-and-hydroelectric-proj…1/7   Obituaries •Games •ADN Store •e-Edition •Sponsored Content • Promotions •Get our free newsletters ADVERTISEMENT Energy Over 20 Alaska villages on tap for $125M in federal funds for solar and hydroelectric projects By Alex DeMarban Updated: 21 hours ago Published: 22 hours ago    Alaska News   •  Politics   •  Iditarod   •  Opinions   •  Talk to us Get our free newslettersSections 2/28/24, 1:47 PM Over 20 Alaska villages on tap for $125M in federal funds for solar and hydroelectric projects - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/02/27/over-20-alaska-villages-on-tap-for-125m-in-federal-funds-for-solar-and-hydroelectric-proj…2/7 The village of Huslia on Thursday, March 12, 2015. (Loren Holmes / ADN) Solar and hydroelectric projects in villages across rural Alaska are on deck to receive up to $125 million in funding from the giant 2021 federal infrastructure law. The projects, including new solar arrays for several villages, will reduce the use of costly diesel fuel that’s used to make electricity at village power plants across the state, the Biden administration said Tuesday. If they’re funded and built, the projects will also create jobs and income for tribes that sell the power. One of the projects could receive up to $26 million to deploy solar power arrays and battery storage banks in eight Interior Alaska villages, according to the U.S. Energy Department. The Tanana Chiefs Conference, a tribal consortium representing 39 villages, applied for the funding. Villages that will benefit include Nulato, Huslia and Holy Cross. The selection is a “huge deal” for the region, said Edward Dellamary, rural energy manager for the Tanana Chiefs Conference. 2/28/24, 1:47 PM Over 20 Alaska villages on tap for $125M in federal funds for solar and hydroelectric projects - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/02/27/over-20-alaska-villages-on-tap-for-125m-in-federal-funds-for-solar-and-hydroelectric-proj…3/7 It can offset the region’s diesel consumption by up to 40% and provide a business model that other villages can follow, he said. The plan calls for a tribal ownership of the projects, with profits from the sale of power to the local utility reinvested back into the village, the agency said. “This will assist communities that have some of the highest energy costs not just in Alaska, but in the whole country,” Dellamary said in a phone interview. ADVERTISEMENT About 1,000 residents in the eight villages will directly benefit, he said. [Alaska natural gas promoter floats new plan: Send North Slope gas to Southcentral first] The Energy Department said that the Alaska projects are among 17 projects across the U.S. that have been selected for award negotiations of up to $366 million. The negotiations are a step toward final funding. Dellamary said Tuesday that he had met earlier in the day with Energy Secretary Jennifer Granholm at the agency’s Tribal Clean Energy Summit in Temecula, California. The meeting was part of the negotiation process, he said. U.S. Sen. Lisa Murkowski said in a statement that the funding from the agency will benefit Alaska more than any other state. It’s part of the Energy Improvement in Rural or Remote Areas program. “One of my priorities when crafting the bipartisan infrastructure law was cleaner and more affordable energy for Alaska,” Murkowski said. “I see the opportunities we have to utilize more of our local resources, the hardships that high energy costs cause across our state, and pushed this innovative program as a way to tackle both.” “This major investment — a result of our work in the Infrastructure, Investment and Jobs Act — will fund hydroelectric facilities, battery storage, transmission lines, and other energy infrastructure” in several Alaska villages, U.S. Sen. Dan Sullivan said in the statement. 2/28/24, 1:47 PM Over 20 Alaska villages on tap for $125M in federal funds for solar and hydroelectric projects - Anchorage Daily News https://www.adn.com/business-economy/energy/2024/02/27/over-20-alaska-villages-on-tap-for-125m-in-federal-funds-for-solar-and-hydroelectric-proj…4/7 The Energy Department said the funding for other projects in Alaska includes: • Up to $55 million to create 10 solar and battery storage projects in villages across the Northwest Arctic Borough in the state’s northwestern region. The villages will be able to sell the power to the local utility, bringing in close to $1 million in annual revenue. The project will also distribute heat pumps that help reduce heating costs. Overall, the villages will save about $2 million in electric and heating costs. • Up to $27 million for the Thayer Creek Hydroelectric Project in the village of Angoon, in Southeast Alaska. The 850-kilowatt, run-of-river project could meet three times the community’s electricity needs, providing additional power for heating and fish processing. Kootznoowoo Inc., the Alaska Native corporation for the village of about 350, applied for the funding. • Up to $7.3 million to replace a leaking wooden dam in Chignik with a new facility that diverts a portion of a river to to product energy, called a “run-of-river” facility. It could fully replace diesel consumption in the village of about 100, and provide extra power for heating and local economic activities like fish processing. The Lake and Peninsula Borough applied for the funding. • Up to $10 million to Old Harbor, a village of about 200 on Kodiak Island, for a run- of-river hydropower facility that could offset diesel use by 95% and operate year- round. The Alutiiq Tribe of Old Harbor applied for the grant. President Joe Biden signed the $1.2 trillion infrastructure bill into law in 2021. The statement from Alaska’s senators said more than $7 billion from the law has been announced for Alaska, with over 1,600 projects identified for funding. Both lawmakers voted for the act and helped craft it, along with the late U.S. Rep. Don Young. Do you have additional ideas for coverage on this topic? Do you have questions? Do you see an er ror? What's missing? Are you involved in the stor y or affected by it and have additional thoughts about it? Let us know here.