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Home My WebLink AboutNative Village of Eklutna Solar Energy Project Feasibility Study - Dec 2022 - REF Grant 70140191 Confidential EKLUTNA SOLAR FEASIBILITY STUDY Renewable IPP, LLC December 16, 2022 2 Confidential DISCLAIMER This report - predictions about future events. These statements are necessarily subjective and involve known and unknown risks, uncertainties and other important factors that could cause our actual results, performance or achievements, or industry results to differ materially from any future results, performance or achievement described in or implied by such statements, including statements relating future revenue, expenses, margins, profitability, net income, taxes, tax credits, adjusted net income, adjusted operating expenses and other measures of results of operations. Actual results may differ materially from the expected results described in our forward-looking statements. 3 Confidential TABLE OF CONTENTS EXECUTIVE SUMMARY .................................................................................................................... 5 PROJECT DESCRIPTION ................................................................................................................ 10 SITE AND LAYOUTS ..................................................................................................................... 11 SYSTEM DESIGN CONSIDERATIONS & INTERCONNECTION ............................................. 16 Substructure & Racking ................................................................................................................. 16 Bi-facial Solar Panels & DC/AC Ratio ............................................................................................. 16 Substation & Grid Interconnection .................................................................................................17 SUMMARY OF KEY POLICIES AFFECTING PROJECT ECONOMICS ..................................... 19 TAX CREDITS ................................................................................................................................. 19 Investment Tax Credit (ITC) ........................................................................................................... 21 Production Tax Credit (PTC) .......................................................................................................... 21 GRANTS AND LOANS .................................................................................................................. 22 State ............................................................................................................................................. 22 Federal .......................................................................................................................................... 22 ADDITIONAL INCENTIVES .......................................................................................................... 23 PROJECT ROLES & OWNERSHIP OPTIONS .............................................................................. 24 PROJECT VIABILITY ........................................................................................................................ 26 COST ............................................................................................................................................... 26 ENERGY MARKET & PRICE IMPLICATIONS ............................................................................. 28 ECONOMIC ANALYSIS ................................................................................................................. 29 Property Taxes .............................................................................................................................. 29 Tax Credit Sensitivity- PTC vs. ITC ................................................................................................. 29 Fixed Tilt vs Single Axis Tracking ................................................................................................... 30 Impact of Energy Price .................................................................................................................. 30 Debt Considerations ...................................................................................................................... 31 Lease Value Based on Project Owner ............................................................................................ 32 Overall Commentary of Project Viability ....................................................................................... 33 PROJECT SCHEDULE ...................................................................................................................... 35 PERMITS ............................................................................................................................................ 37 KEY UNCERTAINTIES AND RISKS ............................................................................................... 40 4 Confidential REPORT ORIGINATORS ................................................................................................................. 43 APPENDIX A: SCHEDULE .............................................................................................................. 44 5 Confidential EXECUTIVE SUMMARY Renewable IPP completed a feasibility study of deploying a utility scale solar farm on Eklutna Inc. owned lands. Initial study work evaluated feasibility of locating the farm on either the site located North of the Alaska Railroad tracks and the Gravel Pit site located South of the Alaska Railroad tracks. Evaluation of each site included determining a preliminary layout of a fixed tilt solar farm system and a single axis tracking solar system. An adequately sized system fits on either site, single axis tracking occupies more acres per watt of electricity produced than a fixed tilt system. Figure 1: Site map Next production models were built and optimized for each site and each system configuration to assess generation given the location of Bear Mountain, local shading for nearby trees, and solar irradiance data. The production modeling demonstrated that while Bear Mountain does impact production by 6 to 8%, the highest impact of the shading coincides with the lowest production months of December and For a fixed-tilt design the maximum system size that can be accommodated at Camp Mohawk and the Gravel Pit are 7.4 MW-AC and 5.8 MW-AC, respectively. Single axis tracking occupies more space per MW-AC than fixed tilt and the Gravel Pit and Camp Mohawk sites can accommodate 5.1 to 5.6 MW-AC, respectively. A single axis tracking system is more efficient in material costs and construction costs, which are the largest cost categories. The tracking systems is overall more economic to deploy but has not been deployed on a utility scale in Alaska at this time. Tracking systems have been successfully deployed in similar climates like New York, Maine, and Alberta, Canada. Renewable IPP has been conducting due diligence with suppliers for deployment in Alaska for other projects and has confirmed there are systems avai snow loads, and wind loads. 6 Confidential Renewable IPP researched the available tax incentives for utility scale solar developments. Given the passing of the Inflation Reduction Act (IRA) by Congress in 2022, it is recommended to execute the project as one or two 4.95 MW-AC developments. Under the IRA, system sizes below 5MW-AC are eligible for an additional tax incentive (10% increase in ITC and interconnection costs are ITC eligible). As the max system size (5.1 to 7.4 MW-AC) that can fit on either site -AC, the tradeoff for a smaller system is outweighed by the additional tax incentives. A 4.95 MW-AC single access tracking system would occupy 53 acres on either the Camp Mohawk or Gravel Pit site. Below is layout drawing of (2) 4.95 MW-AC single access tracking systems on the Camp Mohawk site (North) and Gravel Pit Site (South). Figure 2: Two layouts of 4.95 MW-AC (each) single access tracking systems on the Camp Mohawk site (North) and Gravel Pit Site (South). Additionally, Renewable IPP worked with Matanuska Electric Association (MEA) to determine if solar electricity generated at the Eklutna site could be interconnected and integrated into the grid. A full interconnection and integration study is needed to fully detail preliminary assessment is there is capacity to bring up to 10 MW-AC into the grid from the Eklutna area and interconnection could be accomplished by upgrading existing single-phase lines to 3-phase lines 7 Confidential recommended two phases of 4.95 MW-AC are reinforced by the 10 MW-AC integration constraint identified by MEA. Eklutna and Renewable IPP met with MEA to solicit feedback on the project and MEA expressed interest in receiving more renewable generation and advised that the project may want to consider including battery storage. A cost estimate for a single project phase of a 4.95 MW-AC single axis tracking and fixed tilt system was developed to inform the economic modeling. A variation in cost was accounted for from P10 to P90 given the current market uncertainties induced by inflation, the Inflation Reduction material requirements. The P90 cost estimate accounts for the cost uncertainties listed above and Table 1: 4.95MW-AC System Cost Estimate P10 Total Project Cost $/W-DC P90 Total Project Cost $/W-DC Fixed Tilt $7,752,000 $1.11/W-DC $11,257,000 $1.60/W-DC Single Axis Tracking $7,903,000 $1.13/W-DC $10,952,000 $1.56/W-DC These costs were brought into the economic modeling. The project is anticipated to qualify for a 60% ITC if the construction commences before 2033 and labor and material requirements outlined in the Inflation Reduction Act are met. The economic modeling compared the value of the Production Tax Credit (PTC) to the Investment Tax Credit (ITC) and determined the ITC generates more value for the project owner. Subsequent modeling compared the single axis tracking returns to a fixed tilt system returns and determined the single axis tracking system generates more returns for the project owner. Modeling also evaluated the economic effect of the negotiated net electricity price and ownership model. The net electricity price is negotiated with the Utility in a Power Purchase Agreement. As the agreed electricity price is currently unknown, prices from $0.055 to $0.070 per kWh were modeled to assess project viability. Eklutna ownership, for-profit third-party ownership and utility ownership models were evaluated. Eklutna and utility ownership provide stronger project economics than for- profit third-party ownership as Eklutna ownership saves land lease cost and Utility ownership saves property tax operating cost. Modeling determined that a reasonably low electricity price still allows for a viable solar development on the sites. At an electricity price of $0.055 per kWh, project viability for a for-profit, third-party owner is questionable but this is a viable price point for either Eklutna or Utility ownership. At $0.06 per kWh, the project looks profitable for all ownership models evaluated. The internal rate of return (IRR) for Eklutna as the project owner and assuming a single axis tracking system are below. The variation accounts for uncertainty in project cost (P10 to P90), the negotiated electricity price, and the uncertainty of property tax liability for Eklutna. 8 Confidential Table 2: IRR for Eklutna for a Single Axis Tracking System Net Energy Price Tracking After Tax IRR for Eklutna No Property Taxes Tracking After Tax IRR for Eklutna Property Taxes $0.055 per kWh 8.2 to 11.7% 5.1 to 8.9% $0.060 per kWh 9.3 to 13% 6.3 to 10.3% $0.065 per kWh 10.4 to 14.3% 7.5 to 11.7% $0.070 per kWh 11.4 to 15.6% 8.7 to 13% This is the IRR without debt, with the project funded with a 100% equity investment. Sourcing debt financing can improve the returns on equity. With the debt service coverage ratio (DSCR) optimized for a range of between 1.0 and 1.5 (between the P10 and P90 project costs) for interest rates from 4% to 7% the returns range between 7.7% and 32.5%. Eklutna likely has access to low-cost debt through the Alaska Energy Authori Fund or the Tribal Energy Loan Program which are discussed in detail in Optimizing debt prior to financial close will depend on the current available interest rates Renewable IPP evaluated the project viability for Eklutna to own the project as well as the viability of utility ownership (such as MEA) and third-party ownership. In the case of a utility or third-party ownership, Eklutna generates revenue from leasing the land to the solar project. In the case of Eklutna ownership, profits are generated from the tax incentives and electricity sales. Both are viable options for Eklutna to evalu management, and economic diversification can help determine the desired path forward. Renewable IPP developed a project schedule for the Phase 1 project including the preliminary assessment of permit and regulatory review requirements, procurement timelines, and natural pace of project management and engineering. The development timeline from project development kickoff to commercial operation is 3.5 years. More details on options to accelerate the timeline are noted in the The zoning for the proposed Eklutna sites was evaluated during Renewable feasibility. The proposed sites are located within the Eklutna Overlay (CE-EVO). Solar Farms are currently permitted in the CE- 9 Confidential installations in the CE-EVO to allow the project to move ahead. More discussion on this process is detailed in the Permits section of this document. This is the most significant permitting activity within the project. The key next steps for Eklutna to take after digesting this report are to solidify the project framing. We recommend: 1. Confirming community support of the project 2. Selecting the Phase 1 site (Camp Mohawk or Gravel Pit) 3. Finalize the site layout, size, and system type 4. Initiating the code amendment process for the CE-EVO 5. Continuing discussions with MEA on regulation requirements and project interest 6. Decide if the project will include battery storage 7. Select an ownership model 8. Updating the cost estimate and economic models with framed project details 9. Determining developer, engineering/procurement/construction contractor, and operations and maintenance strategy (Eklutna or Contracted Out) 10. Decide Go/No-Go on development spend for studies (environmental and preliminary engineering) Renewable IPP is available to support Eklutna Inc in continuing to frame the project and be the developer, EPC Contractor, and O&M Contractor. We look forward to your questions and comments on this feasibility report and are excited about the opportunities to work together on a local solar farm. 10 Confidential PROJECT DESCRIPTION Renewable IPP evaluated two solar farm sites on Eklutna Inc lands: the Gravel Pit and Camp Mohawk, as depicted in Figure 2. Both sites are in the Municipality of Anchorage and would interconnect to the Matanuska Electric Association (MEA) distribution system. At this time there are no utility scale solar farms in the Municipality of Anchorage (MOA), and the proposed Eklutna solar farms would be the first solar farms in the MOA. Figure 3 In order to determine the recommended solar farm size, Renewable IPP, evaluated the available acreage, electric grid infrastructure and tax incentives. The available acreage for the two sites is approximately 55 acres for the Gravel Pit and 60 acres for Camp Mohawk. Eklutna Inc and Native Village of Eklutna shared environmental and future use information about both parcels. The Gravel Pit layouts were adjusted to leave access to the Southwestern area for alternative potential future development. Alaska solar farms perform best with wide row spacing to minimize inter-row shading during low sun angle months. For a fixed-tilt design the maximum system size that can be accommodated at Camp Mohawk and the Gravel Pit are 7.4 MW-AC and 5.8 MW-AC, respectively. Single axis tracking occupies more space per MW-AC than fixed tilt and the Gravel Pit and Camp Mohawk sites can accommodate 5.1 to 5.6 MW-AC, respectively. Projects under 5 MW-AC have the benefit of qualifying for the additional bonus of 10% Investment Tax Credit (ITC) for small projects located on tribal lands. Additionally, if the ITC is employed, interconnection costs are qualifying expenses for projects less than 5 MW-AC. Finally, s grid will reasonably support up to 10 MW-AC of generation capacity before requiring major improvements (substation transformer upgrade). Based on all these factors, Renewable IPP is proposing two solar farms, each 4.95 MW-AC (~7.009 MW-DC), to be built in two phases. The Gravel Pit site is recommended for the Phase 1 development with the Phase 2 development occurring on the Camp Mohawk site. The Gravel Pit has the advantage of being closer to 11 Confidential the distribution lines, free of trees and vegetation, has existing road access, and the site is likely to be improved during lead contamination clean up planned for 2024 and 2025. Layouts for single axis tracking and fixed tilt designs are shown below in Figures 4 and 5. SITE AND LAYOUTS The preliminary layouts of the 40-degree South facing fixed tilt system for both the Camp Mohawk and the Gravel Pit sites are shown below. The Camp Mohawk fixed tilt layout uses 47 fenced acres while the Gravel Pit fixed tilt layout uses 40 fenced acres. Figure 4: Fixed Tilt Layouts 12 Confidential The preliminary layout of the N-S single axis tracking arrangement for both Camp Mohawk and the Gravel Pit sites are below. Both the Camp Mohawk and the Gravel Pit layouts utilize 53 fenced acres. Figure 5: Single Axis Tracking Layouts. Renewable IPP completed production modeling using industry standard software, PVSyst and used the AK Birchwood TMY3 irradiance data set from NREL. Production modeling determined that there is negligible difference (<1%) in production opportunity between the two evaluated sites. Preliminary system sizing confirms that both sites can accommodate 4.95 MW-AC in either a 40-deg South facing fixed tilt design or a North to South (N-S) single axis tracking arrangement. The single axis tracking arrangement generates 22% more production but uses approximately 10 more acres than the fixed tilt design. Production Modeling also assessed the impact of shading from the nearby Bear Mountain and determined the effects of shading are less severe than expected. A 6 to 8% production loss due to shading is predicted. Most of the impact of shading takes place during the least productive months, December and January, helping to reduce the overall production impact. 13 Confidential The estimated, first year, annual production values per each 4.95MW-AC system are provided in Table 3 and Figures 6 and 7 illustrate monthly energy output (first year) for both fixed tilt and single axis tracking designs. The yield is a metric of how much energy (kWh) is produced for every kW of installed module capacity over the course of a year and the capacity factor compares the annual production to the module capacity assuming it were able to produce at maximum output every hour of the year. Finally, Figures 8 and 9, provides annual production for both systems over a 25-year operating life assuming annual energy generation decreases by 0.5% per year.1 Table 3: First year annual production, yield and capacity factor for 4.95MW-AC solar farm Design Annual Production (MWh) Yield (kWh/kW) Capacity Factor (%) 40-Degree Fixed Tilt 8,100 1,150 13.2% N-S Single Axis Tracking 9,900 1,400 16% 1 This assumption is based on the 2011 NREL Report and is the industry standard assumption. Jordan, D. - Progress in Photovoltaics: Research and Applications, vol. 21, no. 1, 13 Oct. 2011, pp. 12 29, www.nrel.gov/docs/fy12osti/51664.pdf, 10.1002/pip.1182. Accessed 27 Nov. 2019. 14 Confidential Figure 6: Monthly Electricity Production - Fixed Tilt System Figure 7: Monthly Electricity Production - Single Axis Tracking 15 Confidential Figure 8: Annual Electricity Production - Fixed Tilt System Figure 9: Annual Electricity Production - Single Axis Tracking 16 Confidential SYSTEM DESIGN CONSIDERATIONS & INTERCONNECTION Below is a summary of key design considerations which affect solar production and system cost. These and project economics for Alaska weather conditions. Also provided below is a summary of the high-level grid interconnection scope. SUBSTRUCTURE & RACKING Based on the conceptual design of fixed tilt or single axis tracking, the foundation system will be selected. For feasibility screening purposes, pile foundations are assumed for both design types and final foundation selection (pile, ballast, etc.) will be based on detailed geotechnical information. The fixed tilt case design assumes a fixed tilt array, facing South with a 40-degree tilt. previous design experience has found that a 40-degree tilt maximizes solar production while keeping wind load structural design requirements feasible. If single axis tracking is selected, there are several vendors available with systems that have been evaluated for their efficacy in Southcentral, Alaska. The single axis tracking design will be installed to allow each tracker to rotate from 60-degree tilt East to a 60-degree tilt West which optimizes the solar radiance and supports snow clearing. Tracking has not been deployed at scale yet in Alaska, so there is diligence required to vet vendors and equipment. Renewable IPP has been conducting due diligence of various modern tracking technologies with vendors to /wind loads. BI-FACIAL SOLAR PANELS & DC/AC RATIO The preliminary design assumes bi-facial panels & a high DC/AC ratio to maximize production in Alaska conditions. Bi-facial panels produce energy both from the front side, which receives direct sun exposure, and from reflective light which hits the back side. Bi-facial panels are ideally suited for Alaska solar farms which elevate arrays higher off the ground, place arrays further apart and at steeper angles than Lower 48 designs. In our proposed design the low side of the panel is 3.5 ft off ground level. These design parameters increase the reflective light exposure for the back side of the panels. Finally, the ground is covered by snow 4-5 months of the year, further increasing the reflective light production. A recent study completed by the Alaska Center for Energy and Power (ACEP) estimated bifacial panel gain to be as high as 20%; the project production modeling estimates a 10% bifacial gain on average. To further increase solar production the design uses a high DC/AC ratio. A high DC/AC ratio means that there is excess panel capacity compared to inverter rating. As Alaska has many overcast weather days compared to sunnier locations such as AZ or CO, the high DC/AC ratio provides increased production during the - the losses associated with clipped production is outweighed by the increased production during non-peak conditions. The preliminary design assumes a 1.416 DC/AC ratio. This ratio may change slightly based on the final panel selection. 17 Confidential SUBSTATION & GRID INTERCONNECTION The base case design assumes that the Eklutna Solar Farm will 3 phase distribution lines across the Glenn Highway from the Eklutna Village. The existing distribution lines by the Gravel Pit are single phase and will need to be upgraded to 3 Phase lines to carry 5 MW-AC. If Phase 2 is executed, a larger 3 Phase conductor would be required to carry 10 MW- AC. The distance of required conductor upgrades is between ¼ mile and 1-1/2 mile depending on the selected interconnection point and the selected site (Camp Mohawk or Gravel Pit). With these assumptions, the interconnection cost is estimated to be between $750,000 and $1,500,000. The range accounts for the varying tie in point distances and variation between scope of a simple conductor upgrade for a 5MW-AC project to a higher rated conductor upgrade that allows for both Phase 1 and Phase 2 interconnection of 10MW-AC on a larger conductor. Figure 10 below shows the existing single phase distribution lines, potential routes of conductors from each site to existing single phase lines and upgrades of single-phase lines to 3 phase lines. The existing substation capacity for 10 MVA. The only upgrades anticipated at the substation are upgrades to the protective relays and control logic. The Eklutna, MEA and Renewable IPP teams met on November 9 th, 2022, to solicit feedback from MEA on the project size, interconnection, integration and general utility interest to receive additional renewable energy. MEA shared general interest in the project and provided the technical interconnection information above (budgetary estimates are from Renewable IPP). MEA advised that future renewable energy projects will require either battery support to using their equipment to smooth the production profile. The significance of regulation on this project will be determined by an integration study, conducted with the interconnection study. An Interconnection Application is the first step to getting interconnection work kicked off with MEA. This is followed by a detailed interconnection and integration study. The study feeds the Power Purchase Agreement (PPA) and detailed interconnection engineering. 18 Confidential Figure 10: Interconnection options and upgrade requirements. 19 Confidential SUMMARY OF KEY POLICIES AFFECTING PROJECT ECONOMICS TAX CREDITS The Inflation Reduction Act (IRA) signed into law in 2022 offers tax credit incentives for solar projects and provides stable incentive values for projects which commence construction prior to 2033. Either an investment tax credit (ITC) or a production tax credit (PTC) can be selected for a commercial solar project. These offer tiered incentives with bonus incentives for projects which meet the bonus criteria. Up to 60% of the project costs could be eligible for an investment tax credit or a production tax credit of up to $0.032/kWh could be claimed on the production from the Eklutna Solar Project. Figure 11 provides a summary of the IRA tax incentives. es, like non-profits or local governments, can take advantage of the tax credits. Tax-exempt entities are eligible to receive the ITC or the PTC themselves in the form of a direct payment (a check for the value of the tax credit). This includes Indian Tribal governments (as defined in Section 30D(g)(9)), any Alaska Native Corporation (as defined in Section 3 of the Alaska Native Claims Settlement Act). To receive direct payment for projects which start construction in 2024 and exceed 1 MW, they must meet the domestic content requirements, or the value of the tax credit will be penalized to a lower percentage. The tax credits may also be transferred by selling the tax credit for a given year to an unrelated eligible taxpayer. 20 Confidential Figure 11 2. 2 Office, October 2022, https://www.energy.gov/eere/solar/federal-solar-tax-credits- businesses#_ednref8. Accessed 8 Nov 2022. 21 Confidential INVESTMENT TAX CREDIT (ITC) The Investment Tax Credit or ITC is a tax credit that reduces the federal income tax liability for a percentage of the cost of a solar system that is installed during the tax year. If projects meet the labor requirements, the value is 30% until 2033. The ITC is an upfront tax credit that does not vary by system performance. If a project does not meet the labor requirements, the ITC value is 6%. The labor requirements to qualify for the higher values of the tax credits require employers to pay certain workers a "prevailing wage" and employ a certain number of registered apprentices. The Department of Labor and Internal Revenue Service are anticipated to issue guidelines on labor requirements in Q1 2023 that further outline the wage and apprenticeship requirements to qualify for tax incentive bonuses. Expenses which are eligible costs for the ITC are project development and engineering costs, solar PV panels, inverters, racking, balance of system equipment, installation costs, transformers, circuit breakers, and surge arresters, and certain storage devices. Additionally, for projects under 5 MWAC, the interconnection costs spent by the project owner are also eligible expense for the ITC. Beyond the base ITC incentive, additional bonus incentives are available for projects which meet the qualifications. For the Eklutna project the bonuses available are: 1. Domestic Content Bonus of 10% meet this criterion as it is a pre-requisite to receive the entire ITC value with direct pay. This is not as critical for a for-profit entity with tax liability but is critical for a non-profit. The domestic manufactured in the US and manufactured products. Further guidance on qualifying for the domestic content bonus is expected in 2023. 2. Energy Community Bonus of 10% (2% if labor requirements are not met) for solar projects sited in energy communities. Further clarification from the Department of Treasury on likely meet the requirements due to the percentage of local tax revenues related to the extraction, processing, transport, and storage of coal, oil, or natural gas at any time beginning in 2010. Most of the State of Alaska is expected to meet these criteria. Clarification is expected in early 2023. 3. Low- Income Bonus of 10% for projects under 5 MWAC which are located in a low-income community (as defined in section 45D(e)) or on Indian land (as defined in section 2601(2) of the Energy Policy Act of 1992 (25 U.S.C. 3501(2)). The Eklutna sites likely qualify to apply for the additional low-income bonus due to their location on Indian land. PRODUCTION TAX CREDIT (PTC) The production tax credit is a per kilowatt-hour (kWh) tax credit for electricity generated by 22 Confidential liability and is adjusted for inflation annually. The value of this is $0.026/kWh until 2033 for projects that meet the labor requirements which are the same as for the ITC. The additional bonus adders are available as additional $/kWh for projects that meet the domestic content requirement and energy community criterion. The low-income bonus is not available for PTCs. The total potential value of the PTC $0.032/kWh. The interconnection costs spent by the owner are not eligible for PTC incentives. GRANTS AND LOANS STATE The Alaska Energy Authority has grant and loan opportunities with application periods annually. Renewable Energy Fund (REF) was established by the Alaska Legislature in 2008. REF issues grants for renewable energy projects across Alaska through a competitive application process which is administered by the Alaska Energy Authority (AEA). The average grant value awarded to a Railbelt project is $500,000. Up to $2 million per project could be awarded to a Railbelt project. Grant monies can be applied for based on project phase (reconnaissance, conceptual design, final design and permitting, and construction/commissioning). Available funding for the REF varies from year to year and is largely dependent on the fiscal health of the State of Alaska and the discretion of the Legislature. AEA cautions that in some years, no grant money has been made available. Power Project Fund (PPF) is an AEA administered loan program which provides loans to local utilities, local governments or independent power producers for the development, expansion, or upgrade of electric power facilities including distribution, transmission, efficiency and conservation, bulk fuel storage and waste energy. Loans up to $5 million are approved by the AEA Board and greater than $5 million require legislature approval. The PPF loan structure is attractive as it provides loan terms for the life of the project, spreading out debt payments. The current PPF interest rate as of November, 2022 was 4.27%. FEDERAL 1. Tribal Energy Loan Program and Tribal Energy Loan Guarantee Program a. Department of Energy offers Tribal Entities access to low-cost debt capital for energy projects. The direct loan program has been refunded through Inflation Reduction Act with all-in pricing comprised of a base interest rate (U.S. Treasury equivalent yield curve) plus a spread, typically ranging from 37.5 to 200 basis points. The average loan pricing available in November 2022 was ~5%. Loan guarantee program is also taking applications with interest rates negotiated between lender(s) and borrower. The funding opportunities are scheduled to close in August 2028. 2. Tribal Energy Plan Grant 23 Confidential a. Bureau of Indian Affairs grants are intended to support tribal communities to quickly and efficiently triage the known practical and impactful strategies to reduce greenhouse gas, lower energy costs, and operate more sustainably. Grants for planning are available for up to $25,000. 3. Energy and Mineral Development Program Grant a. Available through Bureau of Indian Affairs. The application period for this year has closed but is anticipated to reopen in subsequent years. i. Solar is eligible for funding. ii. Engineering studies, economic evaluation, and feasibilities studies are eligible for funding. iii. Grant values between $10,000 and $2.5 million are awarded. 4. Tribal Energy Development Capacity Grant a. Available through the Bureau of Indian Affairs. Annual application period gives Tribes the opportunity to receive financial assistance for the following activities: i. Developing the legal infrastructure to create any type of Tribal energy business. ii. Establishing an energy-focused corporation under Tribal or state incorporation codes. iii. Establishing an energy-related Tribal business charter under federal law (IRA Section 17 corporation. iv. Grants of $10,000 to $1 million are awarded annually. 5. Rural Energy for America Program a. Available through USDA. Opportunities for guaranteed loans and grants. Application period is open annually to small businesses in rural areas. b. Grants are available for up to 25% of the project cost or up to $500,000. ADDITIONAL INCENTIVES The solar farm development will likely qualify for environmental attributes and/or Renewable Ownership of RECs can be negotiated in the Power Purchase Agreement. Alaska Utilities have an increasing preference to receive 100% of RECs in order meet potential future Renewable Portfolio Standard (RPS) requirements. If an RPS policy is passed in the State of Alaska, this could increase the energy purchase price for renewable energy projects. The 2022 RPS bill introduced by Governor Dunleavy included a $0.02/kWh penalty for not meeting renewable energy generation percentages by the milestone dates. 24 Confidential PROJECT ROLES & OWNERSHIP OPTIONS The typical solar farm project includes the following roles: (1) project owner, (2) landowner, (3) developer, (4) engineering procurement and construction company (EPC), (5) operations and maintenance company (O&M) and (6) the utility. Each role is listed below with details of the role s core responsibilities and potential parties who may perform each role. Project Owner (Eklutna, Third Party or Utility) o Secures project financing (debt & equity) o Completes due diligence for financing o Completes tax incentive due diligence o Receives tax incentives & grants o Asset manager (accounting, tax filing, oversees O&M, performance management) Landowner (Eklutna) o If Third Party Owner- develop & agree land lease o If Owned by Eklutna- consider land use agreement for project o Drive zoning/code changes for project o Complete lot consolidation for project, as needed o Negotiate property tax exemption or reduction with MOA. Developer (Eklutna or Contract Out): o Shape project concept (scope, budget, schedule) o Negotiate PPA for project o Agree project contracts (land lease, EPC contract, O&M contract) o Complete feasibility studies & early phase permitting work o Coordinate and mediate project stakeholders o Assists in grant and/or loan applications o Project manage development activities EPC (Eklutna or Contract Out): o Completes detailed design o Procures materials o Constructs & commissions solar farm o Oversees interconnection scope with Utility O&M (Eklutna or Contract Out): o Preventative & corrective maintenance (snow clearing, inverter maintenance, etc.) o Performance monitoring Utility (MEA) o Completes interconnection/integration study o Drafts & agrees PPA with Board Approval o Completes PPA Filling with RCA o Purchases & receives generated energy o Completes interconnection engineering, procurement, construction & commissioning 25 Confidential The economic section compares financial parameters based on different ownership models and this section compares qualitative . At a high level if Eklutna funds and owns the system, the main benefit is the cash value of the ITC as the electricity sale income will be similar (slightly higher, but within a similar ballpark) to land lease income. If the utility or a third party funds and owns the project, Eklutna is not exposed to the financial risk of the project or time commitment to asset manage the solar farm long term, but only receives lease income instead of the upfront ITC value. All models are economically viable and Eklutna will ultimately select their preferred ownership model based on their long-term interests and risk versus reward. Regardless of who funds the project, the project is expected to qualify for the Federal Investment Tax Credit (ITC) which is anticipated to be 60% with labor requirements, domestic content, energy community, and low-income community requirements being met. The ITC is applied for and gained by the project funding entity. It is uncertain if Bureau of Indian Affairs grant opportunities would be affected by third party project funding. Table 4: Qualitative Ownership Comparison 26 Confidential PROJECT VIABILITY COST A P10 and P90 project cost estimate was carried out for both the fixed tilt and single axis tracking cases and are provided in Table 5 below. The P90 project costs capture the uncertainty in future material prices ic content requirements; uncertainty in interconnection cost; and potential increase in labor costs due to prevailing wage and apprenticeship requirements associated with the benefits. A breakdown of project cost between development, engineering, materials, construction and interconnection is provided in Figures 12-15. Accounting for scale, the project cost estimates are in line with National Renewable Energy Laboratory (NREL) Q1 2022 benchmark data for solar farm costs. The Q1 2022 benchmark cost for a fixed tilt, 500kW-DC is $1.94/W and a 100 MW-DC single axis tracking is $0.99/W3. NREL benchmark data for Q1 2023 is likely to come available in September 2023 and will likely show the effects of the Inflation Reduction Act and other political cost factors experienced in the latter half of 2022. Table 5: 4.95MW-AC System Cost Estimate P10 Total Project Cost $/W-DC P90 Total Project Cost $/W-DC Fixed Tilt $7,752,000 $1.11/W-DC $11,257,000 $1.60/W-DC Single Axis Tracking $7,903,000 $1.13/W-DC $10,952,000 $1.56/W-DC 3 Ramasamy, Vignesh, et al. U.S. Solar Photovoltaic System and Energy Storage Cost Benchmarks, With Minimum Sustainable Price Analysis: Q1 2022. 2022. 28 Confidential ENERGY MARKET & PRICE IMPLICATIONS The it is assumed that energy generated by the solar farm(s) would be sold to MEA. Technically energy could also be sold to Chugach Electric Association or Golden Valley Electric Association however which would lower the energy price for the project; therefore, these offtake scenarios were not evaluated. MEA currently generates 85% of its electricity using Cook Inlet natural gas and the remainder is generated primarily with Bradley Lake Hydro and small Independent Power Producer (IPP) projects. In evaluating the MEA energy market, two recent price data points are available. MEA reports the Small Facility Power Purchase Rate (SFPPR) to the RCA quarterly. The current SFPPR is $0.07411 per kWh. The SFPPR is for facilities smaller than 100kW-AC and estimates the generation cost saved by MEA based on fuel cost and non-fixed maintenance cost. The SFPPR is an indication of the maximum rate any commercial solar project could achieve; larger projects would likely receive significantly lower pricing as they are more costly to regulate. The 6 MW-AC Houston Solar Farm project negotiated an unregulated power purchase price of $0.067 per kWh which escalates at 1.5% per year. MEA has indicated that future renewable energy projects will either be required to pay a regulation fee or provide battery support. Based on current market conditions, it is estimated that the Eklutna Solar farm would likely receive an energy price lower than the Houston Solar Farm project price. There is potential for higher future energy pricing given Hilcorp announced uncertainty in ability to meet future Cool Inlet Gas Contract demand. Additionally, Governor Dunleavy introduced a Renewable Portfolio Standard (RPS) during the 2022 legislative session and if bill is passed in the future, utilities would be required to meet certain percentages of their generation with renewable energy, increasing the demand and potentially the price for renewable energy. Based on this market analysis, this feasibility study varies the net electricity price (price received after regulation charges) between $0.055/kWh and $0.07/kWh and assumes an annual price escalation of 1.5% as this escalator was approved by the RCA for the Houston Solar Farm project and is below the Federal Reserve inflation target of 2%. 29 Confidential ECONOMIC ANALYSIS This section completes analysis assuming Eklutna is eligible for 60% ITC; however, Eklutna should consult a tax professional to confirm their eligibility and tax assumptions. The internal rate of return (IRR) after taxes was evaluated over a 25-year period for economic analysis with varied project assumptions and parameters. Operations and maintenance costs are estimated at $91,500 per year. This includes physical operations and maintenance equipment and labor such as snow removal and repairs, cost of site electricity usage, annual cellular data plan for site data acquisition, and equipment insurance policies. A property tax rate of 1.51% and an appraised property value of $633,444 was used for the economic evaluation. These rates were arrived at in consultation with the Municipality of Anchorage codes and recent appraisal information. Property taxes are assumed to depreciate at 3% per year which estimates the solar equipment installation depreciation and the property value appreciation. PROPERTY TAXES Renewable IPP requested the Municipality of Anchorage (MOA) to evaluate the applicability of property tax liability should Eklutna Inc. elect to develop and own a solar farm on their land. Currently, the MOA exempts the land and buildings preliminary determination was if the exempted land is developed it could have tax liability and would be taxed at the mill rate for the area the land is located in. Renewable IPP recommends that Eklutna Inc continue discussions with the MOA and seek continued exemption status following development of the solar farm. As there is uncertainty in the requirement to pay property taxes on the solar farm value, the analysis was completed assuming both no property tax exemption and full property tax exemption, where applicable. TAX CREDIT SENSITIVITY- PTC VS. ITC The economic analysis first compared the value of the Investment Tax Credit (ITC) to the Production Tax Credit (PTC). To evaluate which tax credit opportunity is a better fit for this project, IRR values were compared using the highest production case (single axis tracking) with the lowest cost (P10). A PTC value of $0.032 per kWh was compared with a 60% ITC value. Using the highest production case and lowest cost, is the optimum case for the PTC however the ITC still resulted in higher returns by a large margin. Given the lower solar production yield in Alaska, the PTC inherently has less value, and this coupled with the additional bonus ITC percentages make the ITC incentive more attractive for the Eklutna Solar Farm project. Additionally, given the additional ITC bonus for projects less than 5 MW-AC, we recommend utilizing the ITC with two project phases. The comparative economic models kept all other assumptions equal to quantify the relative value of the two incentive options. The results below used the following model assumptions: no land lease cost, no grants or loans, property taxes were assumed applicable, and owner has no federal income tax liability and a net electricity price of $0.067 per kWh escalating at 1.5% per year. 30 Confidential Table 6: PTC vs. ITC P10 Tracking After Tax IRR ITC of 60% 11% PTC of $0.032 per kWh 6.3% FIXED TILT VS SINGLE AXIS TRACKING The difference in returns between the fixed tilt and single axis tracking was modeled considering the difference in production profiles and project costs. This comparison assumed the project utilizes the ITC and assumes Eklutna is the project owner and has no federal income tax liability. This model assumed no land lease costs as Eklutna is the owner and did not account for the value of grants or loans and assumes property taxes are applicable. A net electricity price of $0.067 per kWh escalating at 1.5% per year is modeled. The single axis tracking case provides the strongest estimated project returns. Single axis tracking has not been deployed at scale in Alaska yet, however this tracking technology has been deployed in Canada and other high snow areas of the US such as western New York and the northern Midwest. the regulation requirements for intermittent power generation will increase, which will put more pressure on the net PPA pricing a system can realize. Single axis tracking provides a promising technical solution to increase production to offset the potential integration cost associated with power regulation. Based on this economic screening single axis tracking would increase the economic viability of the project. Table 7: Fixed Tilt vs. Single Axis Tracking System After Tax IRR Eklutna Owns - ITC Fixed Tilt 4.8 to 9.1% Single Axis Tracking 8 to 12.2% IMPACT OF ENERGY PRICE Matanuska Electric Association has indicated that future renewable energy projects will likely require regulation reducing the net electricity price for the owner. To help overcome this future cost of regulation to the project the production profile from the single axis tracking case was used in the energy price sensitivity analysis. The below IRRs demonstrate the variability of energy price. All modeled electricity prices assume a 1.5% per year escalation for the first 25 years. In this scenario, Eklutna is assumed to be the project owner. As their requirement to pay property taxes on the solar farm value is uncertain at this time, analysis was completed assuming no property tax exemption and full property tax exemption. As Eklutna is the assumed owner of the solar farm, no lease costs are 31 Confidential included. No loans or grants are included in the below comparison. Eklutna is assumed to have no Federal Tax liability, so no Bonus Depreciation or Accelerated Depreciation (MACRS) is valued. Based on the starting PPA price sensitivity the project could be capable of generating positive returns even a . This illustrates there is potential for an Eklutna solar project to cover a potential regulation charge. However, at this time MEA has not provided what that charge would be and would likely require some additional study by MEA. Table 8: Project IRR vs. Net Energy Price for both Single Axis Tracking and Fixed Tilt Systems. Net Energy Price Tracking After Tax IRR for Eklutna No Property Taxes Tracking After Tax IRR for Eklutna Property Taxes Fixed After Tax IRR for Eklutna No Property Taxes Fixed After Tax IRR for Eklutna Property Taxes $0.055 per kWh 8.2 to 11.7% 5.1 to 8.9% 5.5% to 8.9% 2% to 5.9% $0.060 per kWh 9.3 to 13% 6.3 to 10.3% 6.5% to 10.2% 3.2% to 7.3% $0.065 per kWh 10.4 to 14.3% 7.5 to 11.7% 7.5% to 11.4% 4.4% to 8.6% $0.070 per kWh 11.4 to 15.6% 8.7 to 13% 8.5% to 12.5% 5.4% to 9.8% DEBT CONSIDERATIONS investment. Debt can also provide a source of financing for solar projects and can even help improve returns on equity. However, to understand the benefits and risks associated with debt financing the specific loan terms need to be considered. For example, if recourse debt is being considered the project owner would be able to claim the ITC on the debt and equity portions of the project (rather than just the equity portion for a non-recourse loan). This would make adding some debt to the financing mix quite attractive to leverage the value of the ITC. However, fully guaranteeing the debt to meet the recourse requirements may not be desirable to some entities. The amount of debt would need to be balanced against the impact the loan repayment has on the long-term project cashflow to manage the risk of future default in the case of any unplanned interruption of solar farm operation. So, generally the limiting factor on the debt-equity split for a given solar project will be how much cashflow is available for debt service each year of the project life and the risk appetite of the entity taking on the debt. After tax internal rate of return is highly sensitive to debt terms. Available interest rates will vary depending on ownership model and project timing. The below IRRs demonstrate the variability with interest rates and the Debt/Equity split to satisfy a reasonable range of debt service coverage ratios 32 Confidential (DSCR). Most entities have DSCR thresholds between 1 and 1.5. The below analysis varied the debt-to- equity ratio to maintain the DSCR in this range, keeping cashflow positive in the P90 case. This table assumes Eklutna is the project owner, 25-year term and fully guarantees the debt, making the debt ITC eligible. The modeling assumes property taxes apply. The net electricity price is assumed $0.065 per kWh with a 1.5% annual escalation. The range in IRR is the variation between the P10 and P90 anticipated project costs. The debt-to-equity ratio is determined based on meeting a reasonable DSCR value e project cashflow. Table 9: Impact of Debt and Interest Rate Interest Rate Debt Service Coverage Ratio Tracking After Tax IRR for Eklutna Debt-to-Equity Ratio 4% 1 to 1.6 20.5% to 32.5% 50/50 5% 1 to 1.57 15.6% to 28% 47/53 6% 1 to 1.55 10.5% to 21.8% 43/57 7% 1 to 1.52 7.7% t0 18.5% 40/60 LEASE VALUE BASED ON PROJECT OWNER The anticipated value to Eklutna should Eklutna desire to lease the land and not own the project will vary based on project ownership structure. A Utility Owner does not have property tax liability and therefore the project could afford a higher annual lease rate than a private ownership entity which would have property tax liability. The below comparison assumes a 50/50 Debt/Equity split with a 6% interest rate. The lease rate range is the variation between the P10 and P90 anticipated Single Axis Tracking project costs. The lease terms are assumed to escalate at 3% per year. Displayed price range represents the anticipated initial lease rate. For profit owners have an assumed federal tax liability of 21%. Non-profit owners have no federal tax liability. If the project owner has tax liability, they can take advantage of accelerated depreciation. Bonus depreciation through the Tax Cuts and Jobs Act begins phasing out in 2022 and as scheduled will depreciation is claimed in the economic analysis. If Congress were to revise the current bonus depreciation phase out and the ownership entity has tax liability this would increase the economic returns. Starting lease rates which allow for positive after tax cashflow are considered economically viable. All scenarios with positive after tax cashflow exceeded 10% after tax IRR. Hurdle rates for After-Tax IRR (internal rate of return) will vary by ownership entity and therefore the below lease rates should be taken as indicative ranges only. These values can help Eklutna understand the land leasing value potential compared to the estimated returns associated with owning a solar project. 33 Confidential To compare the opportunity of ownership to leasing, the Year 1 annual cash flow for the P10 cost case with Eklutna as an owner is compared. This Year 1 cash flow is pre-tax and only includes the before tax expenses and revenue. The annual pre-tax cashflow increases with time as property taxes deescalate and electricity price escalate annually. This is similar value to annual lease price escalation. Lease prices are assumed to escalate 3% per year while electricity price is modeled to escalate at 1.5% per year and property taxes (assuming equipment depreciation and land appreciation) are assumed to decline at 3% per year. Table 10: Impact of Net Electricity Pricing Net Electricity Starting Price For Profit Annual Lease Starting Rate - Tracking Utility Annual Lease Starting Rate - Tracking P10 Tracking Year 1 Pre-Tax Cash Flow* *(Excluding all tax incentives) $0.055 per kWh $0 $0 to $105,000 $13,210 $0.060 per kWh $0 to $40,000 $45,000 to $140,000 $63,212 $0.065 per kWh $0 to $80,000 $78,000 to $195,000 $113,214 $0.070 per kWh $0 to $125,000 $130,000 to $235,000 $163,216 OVERALL COMMENTARY OF PROJECT VIABILITY The above economic modeling scenarios compare varying financial parameters based on different ownership models. At a high level if Eklutna funds and owns the system, the main benefit is the cash value of the ITC as the electricity sale income will be similar (slightly higher, but within a similar ballpark) to land lease income. If the utility or a third party funds and owns the project, Eklutna is not exposed to the financial risk of the project or time commitment to asset manage the solar farm long term, but only receives lease income instead of the upfront ITC value. The economic analysis performed on a single project phase of the Eklutna solar farm indicates that at realistic electricity sales prices the project is economically viable for any ownership model. Both a fixed tilt system and a single axis tracking system are economic; the single axis tracking maximizes rate of returns. ation of regulation charges and their impact on the project returns will influence viability of the fixed tilt system. Higher returns are expected if a utility or Eklutna were to own the project yet with cost management and the addition of grants and competitive, optimized debt the project would be feasible in a third- party owner . Determination of property tax liability will impact if utility ownership or Eklutna ownership garners the maximum overall project returns. The impact of property taxes specifically affects the viability of Eklutna ownership of a fixed tilt system. 34 Confidential The returns of all the evaluated ownership models can be improved with debt. Optimizing the debt-to- equity ratio will depend on the risk appetite and available interest rates at time of financial close. With all options viable, Eklutna should weigh community interest, hurdle rates, capital constraints and their risk/reward metrics to select a path forward. 35 Confidential PROJECT SCHEDULE Before the project development can be kicked off, project framing must be finalized. Project framing will select the preferred site location and concept (single phase or two, inclusion of battery storage, etc.), select the project ownership model and initiate the MOA code amendment to permit development of solar farms within the Eklutna Overlay. These activities should be completed along with confirming project interest with MEA and Eklutna prior to incurring significant development spend (i.e. interconnection studies, engineering, etc.) to minimize potential regret cost or project recycle. Once key stakeholder commitment is confirmed, the Utility will facilitate an interconnection and integration study. Meanwhile, preliminary engineering of the solar farm itself is performed. These efforts, which are at risk spend, inform the design engineering, procurement schedule and project costs necessary to finalize the Power Purchase Agreement (PPA). Once the pricing is landed and the final PPA is agreed, the PPA can be submitted to the Regulatory Commission of Alaska (RCA) for approval. After this step, a third-party funding entity would release funds for project development. Then procurement, detailed engineering, and permitting activities commence. Currently, procurement lead times are around 52 to 60 weeks for specialized electrical components. Therefore, the construction usually takes place in two stages: an initial phase of site preparation and foundation installation followed by a secondary stage of installation of panels and AC electrical equipment. The engineering and construction of the interconnection is usually managed by the utility and occurs in parallel with the AC electrical equipment installations. Following completion of construction, the system is commissioned, a joint effort between the utility and the project group. The central north section of the gravel pit site is scheduled for lead contamination remediation in 2024 and 2025. The project construction could be timed to follow the lead contamination clean up and some site grading could possibly be incorporated into the remediation efforts. Table 11 below provides a high-level project schedule activities and Appendix A provides a complete Gantt chart schedule. The base schedule assumes a natural pace which results in a commercial operation date (COD) 3.5 years after Project Kickoff. The critical path for this schedule is dependent on timely completion of interconnection/integration studies which inform the PPA. If the project is funded by a third party, RCA approval of the PPA is the main pre-requisite for financial closing which releases third party funds for detailed engineering and ultimately, procurement and construction. If the project is funded by Eklutna, the schedule could be accelerated by completing key engineering as at-risk spend to specify long lead procurement items ahead of financial close. The distribution voltage transformer lead time is estimated to be one year, so completion of detailed engineering for the interconnection sets the critical path for system startup. 36 Confidential Table 11: Eklutna Solar High Level Task and Duration Summary Task Duration Socialize Project with Key Eklutna Stakeholders 13w Finalize Project Framing 130d CE-EVO Code Amendment for Solar 26w Decide Single Phase or 2 Phases & Finalize Project Size 4w Select Project Site 2w Decide if Solar or Solar + Storage 12w Storage Sizing & Cost Estimate (optional)8w Draft Electrical Single Line Drawing 8w Select Ownership Model and Decide Land Arrangement (e.g. lease)6w Update Cost Estimate and Production Estimate 6w Update Economic Model to Inform Electricity Price 4w Confirm Utility Interest in Project 4w Decide Go/No-Go Development Spend (e.g. studies, environmental, prelim engr) Development 354d Project Management 60d Validate project cost estimate 12w Validate production estimate 12w Update project schedule 12w Land 80d Develop & Agree Land Lease 16w Complete Phase 1 ESA 8w Complete SHPO Review 12w Interconnection/Integration Studies 130d Complete Interconnection Application 2w Develop RFP for Studies 6w Issue RFP and Select Firm 6w Complete Interconnection Study 12w Power Purchase Agreement 245d Draft PPA 6w PPA Review & Edits PPA 12w Parties Agree PPA Terms 4w Utility Board Approval of PPA 4w Sign PPA and Prepare RCA Filing & File 8w RCA Review & Approval 75d Financially Close Project 354d Review Grant and Debt Opportunities 20w Finalize Cost Estimate and Production Modeling 8w Financial Close 2w Preliminary Engineering 80d Geotechnical Site Assessment 16w Preliminary Civil Engineering 16w Preliminary Electrical Engineering 16w Permitting 494d FAA Study 4w USACOE Wetland JD & Gravel Permit 12w Bald Eagle Survey 4w Bald Eagle Permit (USFWS, if required)12w State Plan Review 4w Construction General Permit & SWPPP 8w Interconnection ROW 8w EPC 100d Engineering 100d Civil Engineering 12w Structural Engineering/Foundation Design 6w Electrical, Automations, Controls, Communications Engr 12w Interconnection Engineering 20w Procurement 280d Foundation & Racking 16w Solar Panels 52w Transformer and AC Electrical Long Leads 56w Interconnection Long Leads 30w Construction 516d Lead Contamination Clean Up 60w Site Preparation 4w Install Foundation & Racking 10w Panel Installation 12w AC Electrical Installation 6w DC Electrical Installation 3w Interconnection Construction 8w Commissioning 8w Commercial Operation 1d 37 Confidential PERMITS Table 12 below identifies the required permits for the Eklutna Solar farm. They are displayed in the order that they should be progressed. Table 12: Eklutna Solar Farm Permit Summary Eklutna Solar Farm Permitting Summary Permit/Review Status & Permit Plan State Plan Review- Alaska Department of Fire & Life Safety Submit after Engineering IFC & Prior to Construction: Alaska Department of Fire & Life Safety will review solar farm fire hazards, mitigations, and fire response plan. The review of civil, structural, electrical and fire response plans can be staged or executed in combination. Approval required prior to starting construction. Note: the plan review does not need to be completed prior to land clearing. US Army Core of Engineers- General Permit Begin once Location Selected: The Camp Mohawk Site include wetlands. Pile driving does not require gravel fill into wetlands. Fill on the property will be less than ½ acre; therefore, only a general permit is required. In previous discussions with the US ACOE, it was advised that a general permit take approximately 60 days to review & approve and does not require public comment. Construction General Permit /SWPPP Submit Prior to Construction: A SWPPP is required prior to starting construction as part of the construction general permit. The construction general permit and SWPPP are submitted through an automated system and are automatically issued. Needed prior to land clearing. FAA Review An FAA Review is required: Once site is selected review should be completed through the OE/AAA Portal. Initial review is a 2 4 week process. Subsequent review steps could be identified in initial review. https://oeaaa.faa.gov/oeaaa/external/userMgmt/permissionAction.jsp?action=showLoginForm Alaska Dept. of Fish & Game No permits required: Both the Gravel Pit and Camp Mohawk land locations and solar construction and operation activities where shared with ADF&G. ADF&G, Wildlife Biologist, Andrew Kastning ordinary high water line so you will not need anything from our Habitat office to proceed. If I confident we c US Fish & Wildlife Service Migratory Bird Treaty Act: from May 1st through July 15th to minimize the incidental take of birds during the nesting season. The project schedule currently shows land disturbance & clearing activities are outside 38 Confidential (USFWS) this window. If these activities were to move within the window, a permit may be required. The USFWS is anticipated to issue a new permitting rule in the winter of 2022/2023 which requires a permit for land/vegetation clearing during the recommended avoidance period. Bald and Golden Eagle Protection Act: Given the tall trees on th USFWS recommends completing an eagle nest survey. The USFWS recommends performing eagle nest surveys between April 15th and May 15th. If eagle nests are identified a permit from the USFWS will be required prior to starting construction and permits take approximately 90 days to issue. ROW & Driveway Permits Submit Prior to Construction: Once interconnection studies are complete, and the interconnection route is determined in conjunction with Matanuska Electric to identify any required ROW permits and will either assume full responsibility to acquire such permits or assist Matanuska Electric where appropriate to acquire such permits. The identified sites are close to the distribution lines and ROW permits may not be required. If needed, ROW permits are planned to be worked during 2023. A driveway permit could be required for the selected site which take about 2-weeks to process and will be submitted prior to construction. Zoning Required prior to financial close: The Camp Mohawk site and part of the Gravel Pit site are in the Municipality of Anchorage and are part of the Overlaying Zoning District, CE-EVO. (Municipality of Anchorage) Title 21 does not have a use type specifically for Solar Farms. They currently characterize solar farms as Utility Facilities. A Utility Facility is not a permitted use in CE-EVO zones. Eklutna Inc will need to garner community support for a code amendment and reach out to their local representatives to initiate a Title 21 code amendment to permit (either unconditionally, conditionally, or administratively) solar farms or utility facilities within the Eklutna Overlay. This process does not require any application fees but would require time to engage with stakeholders and support the assembly in progressing the code amendment. The timeline to progress a code amendment is estimated to be 3 months for community engagement and 3 months for working with the MOA Assembly on the code amendment. If the code amendment permits solar farms as a conditionally allowed or administratively allowed, an additional 6 months should be allotted for the subsequent permitting process. Land Use Review Within the Municipality of Anchorage commercial projects require a land use review through the Planning Department . Solar farms are currently characterized by the MOA as Utility Facilities. The land use review would be applied for after the code amendment is approved. US ACOE Ground Disturbance Risk Assessment Camp Mohawk and Gravel Pit parcels have trichloroethene (TCE) and 1,1,2-Trichloroethane (1,1,2-TCA) contamination. TCE concentrations near the railroad tracks pose a risk to construction workers during ground disturbance activities. 1,1,2-TCA contamination which is a degradation product of TCE is collocated with the TCE contamination and poses an elevated risk to construction workers during ground disturbance activities. The current preliminary solar determined using standardized assumptions to pose slightly elevated risk over acceptable thresholds to construction workers. Renewable IPP recommend that a detailed risk assessment using assumptions consistent with the planned solar farm foundation and trenching construction techniques be carried out in the 39 Confidential development phase of the project. This detailed risk assessment should also consider the TCE and 1,1,2-TCA contamination status following the lead contamination remediation. Such risk assessment will inform final layouts of the Solar Farm developments and required adjustments to construction techniques and worker protections to safely execute development onsite. The US ACOE advised that If Eklutna Inc. can share details on specific locations and types of activities being considered for the solar power facility, USACOE can further evaluate results from all environmental media at those specific areas using customized exposure assumptions. 40 Confidential KEY UNCERTAINTIES AND RISKS Risk And Uncertainty Summary Risk Description Risk Assessment Risk Mitigation(s) Subsurface Conditions: If difficult pile driving geology is identified on the selected project land site, project cost may increase. Low: Assessed to be low as geo- tech survey and pile testing are included in project plan. If difficult geology is identified during these early feasibility studies, multiple foundation design options are available to mitigate this risk. As studies conducted prior to signing PPA, foundation costs will be known at time of financial close. 1) Pile Testing 2) Geo-Tech Survey 3) Variety of foundation options for varying soil types. Cost impact known ahead of financial closing. Incentive Opportunities: A) ITC Low Income Bonus: The application and allocation process is yet to be defined. B) Community Bonus: Clarification on qualification process is yet to be issued. Low: The project likely Low- Income Bonus as its located on Indian land. The allocation process for applicants is expected to be issued in 2023 to clarify how projects which qualify for the low-income bonus can apply and receive the additional bonus. Low: The project likely qualifies for the Energy Community Bonus as its located in a census tract which has an unemployment rate at or above the national average unemployment rate for the previous year and has > 0.17 % or greater direct employment or > 25% local tax revenues related to the extraction, processing, transport, or storage of coal, oil, or natural gas. However, the qualification is as determined by the Secretary and such guidance has not been issued and the 1) Update Cost estimate after application and allocation process guidance is issued. 2) Update Cost estimate after the Secretary issues a process. 41 Confidential unemployment rates of census tracts are due to vary year on year. Grant and Loan Opportunities: A) BIA and DOE grant and loan opportunities have individual and nuanced qualifications. B) Grant and loan opportunities have dynamic application periods and have fixed funds available each year. Medium: The ownership and development structure selected by Eklutna Inc may disqualify the beneficiaries from some grant and loan opportunities. A detail legal assessment of the opportunities should be conducted once the development and ownership structure is defined. Medium: Additional funding opportunities could become available, or funding opportunities could expire based on the project development timeline. Most grants are expected to be available until 2028 based on allocation of IRA funding. 1) Conduct a detail legal assessment of the funding and incentive opportunities seeking once the development and ownership structure is defined. 2) Consider project schedule and ensure development aligns with funding opportunities needed. Ensure project developer/project owner are continually reviewing grant opportunities and tracking application timelines. Labor Cost: Labor requirements under the IRA include bonuses for employers who pay certain workers a "prevailing wage" and employ a certain number of registered apprentices. The Department of Labor and Internal Revenue Service are anticipated to issue guidelines on labor requirements in Q1 2023 that further outline the wage and apprenticeship requirements to qualify for tax incentive bonuses. Low: The extent to which roles will be encompassed in the wage determination and if the prevailing wage and fringe benefit values will exceed wages is unknown unknown. IBEW is anticipated to have registered apprentices available for electrical specific roles. 1) Update Cost estimate after IRS guidance. 2) Carry additional cost in the P90 cost estimate for higher labor rates. 3) Subcontract construction roles to Union organizations. Material Costs: A) Materials cost more than Medium: Current material supplies are volatile and experiencing inflation, this will be 1) Refresh project cost estimate every 6 months to keep current with supply 42 Confidential estimated exacerbated by Domestic Content Requirements in IRA as supply chains will need to adjust to requirements. Cannot lock in final pricing of key materials (solar panels, foundation/racking) until down payments can be made at financial close. cost and availability. 2) Review domestic content clarifications as they become available to better understand impacts. Schedule: Overall project delivery schedule is highly dependent on timely studies, PPA approval and financial closing. 3-month delays may result in 9 12-month construction delays due to seasonality of construction Medium: Eklutna Inc is young in its renewable energy project experience. Project schedule may extend if project management and development resources are not available to support project through key steps. Schedule delays could affect funding and incentive opportunities which have deadlines. 1) Employ development entity to manage project development. 2) Leverage BIA and DOE resources for project development, due diligence, and grant writing support. 3) Identify and engage with stakeholders early in the project and map out process with each. Environmental: Known lead, TCE, & 1,1,2- TCA contamination with proposed solar farm layouts. Medium: USACOE standardized assessment assumptions determined specific areas within the proposed layouts should not be constructed upon due to unacceptable risk to construction workers. 1) Complete lead contamination clean up in 2024 and 2025, as planned. 2) Consider including TCE and 1,1,2- TCA contamination remediation during lead remediation. 3) Complete a detailed site risk assessment considering solar farm construction techniques (pile driving) to determine accurate risk to construction works for project. 4) Use PPE or revise layouts to avoid high risk construction areas. Tracking Technology Tracking system does not perform as expected. Low: Tracking is a new technology for Alaska. Modern tracking systems have been deployed worldwide with high success rates in cold and snowy climates. 1) Conduct due diligence with tracking system manufacturers 2) Select tracking system designed for cold, snowy climates. 3) Get cost estimate from selected tracking supplier Project Size. Project size on the smaller range of Utility Scale projects Medium: Supply chain premiums or minimum orders are expected for small order sourcing of utility grade materials such tracking systems and racking. This could be a challenge due to project size. 1) Procure difficult to source materials for both Phases at once to enhance order size. 2) Get valid cost estimate from suppliers to confirm project cost prior to agreeing PPA energy price. 3) Source materials through a third 43 Confidential other project material orders. Regulation Charges Utility is expected to charge for regulating renewable energy sources as more renewable sources come onto the grid in the coming years. High: Regulation Charges would affect the net electricity pricing. Its unknown how significant regulation charges will be. At some price point, a including a battery in the project becomes more economic than paying the regulation fee. 1) Consider the value of adding onsite battery storage to the project to avoid utility regulation charges. 2) Ensure project IRR can support a lower net electricity price to encompass possible regulation charges. Land Use/ Rezoning Process Title 21 Eklutna Overlay Zone does not allow for solar farms. Medium: A code amendment is likely to take 6 to 12 months to pass through the assembly. The Eklutna Overlay code requirements are expected to be straightforward code changes if they have strong Village of Eklutna and Eklutna Inc. support. 1) Engage with community ahead of amendment process to ensure community support of project. 1) Work with Assemblymember to initiate the code change with sufficient time for a 6-to-12- month timeline. Property Tax Applicability exempt, development of solar farm may make developed lands taxable. Low: Economic analysis was performed accounting for the uncertainty. Both returns with property tax applicability and without were provided for evaluation. 1) Eklutna Inc should reach out to Eklutna Inc, Eklutna Village ownership of a solar farm on exempted lands. Given past development experiences, there may be similar situations Eklutna Inc can reference. 2) Utility ownership would be exempted from property taxes. 3) Economics for Eklutna ownership with property taxes are viable. REPORT ORIGINATORS Jennifer Miller, CEO Renewable IPP Chris Colbert, CFO Renewable IPP Jaime Bronga, Project Manager Renewable IPP