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REFAC Meeting documents 1-7-2011
STATE OF ALASKA eee 1016 West 6" Ave., Suite 205 Anchorage, AK 99501 Department of Labor and Workforce Development PHONE: (907) 269-4651 Division of Business Partnerships FAX: (907) 269-0068 The Alaska State Energy Sector Partnership (ASESP) Request fot Grant Applications The Alaska Department of Labor and Workforce Development, Division of Business Partnerships in conjunction with the Alaska Workforce Investment Board, requests grant applications for training projects in Renewable Energy and Energy Efficiency industries (RE/EE). The Division is seeking gtant applications for training in RE/EE areas of wind turbines, hydroelectric, biomass, geothermal and weatherization and rehabilitation of public facilities, commercial facilities and multi-tesidential facilities. RE/EE jobs require upgrading skills of incumbent workers; teaching new skills to workers in RE/EE technologies and preparing entry-level workers planning to enter RE/EE jobs and careers. Successful projects should clearly demonstrate partnerships, leveraging, outcomes, sustainability and credentialing trainees who successfully complete the training. Successful projects should have a strong linkage to jobs and employment in RE/EE industties. Please note this is an open grant solicitation with no specific deadline for the submission of a grant application. Applications will be accepted until all available funds have been committed. Applications will be reviewed and awards made periodically and thete are dates by when applications must be received for a particular review. The first deadline for submission of grant applications for the first teview is 5:00 p.m. on Tuesday, January 18, 2011. The Division of Business Partnerships is using its new Electronic Grants Administration and Management System, EGrAMS, for this Request for Grant Applications. EGrAMS can be accessed at the Division of Business Partnerships web page of http://www.labot.alaska.gov/bp/, A tutorial on how to use EGrAMS for submitting a grant application can also be accessed at the Division’s web site. Applicants are strongly encoutaged to complete the tutorial and to use EGrAMS for submitting their grant application. The view the Online Public Notice visit: http://notes4.statc.ak.us/pn Questions may be directed to Julie Frizzell, Program Coordinator, at Julie. Frizzell@alaska.gov. (907) 269-4590 Renewable Energy Fund = ALASKA @@l_ ENERGY AUTHORITY Advisory Committee Meeting Program Update January 7, 2011 Outlook RE Fund Rounds 1 - 3 : Estimated Cumulative Annual Fuel Savings e Estimated Cumulative ; Annual Fuel Savings 3 7 Round 1 and 3 Construction £5 Wind 2 Solar Total Grant = $101.8 million g 4 SOcean/River § 3 BHydro Does not include 8 projects that are not yet 52 | eee scheduled (Total grant =$14.8 million, annual a Geothermal fuel savings = 3.1 million gallons/yr) a osit 2012 2013 Year RE Fund Rounds 1-3 Estimated Cumulative Annual Fuel Savings ———— res — = Upper Tanana | | Southeast = Railbelt ®™ Northwest Arctic = North Slope m Lower Yukon Million Gallons (equiv) Ps m Kodiak ™ Copper River Bristol Bay ” @ Bering Straits 2010 2011 2012 2013 Aleutians Estimate of Electric vs. Heating Grants from RE Fund Rounds 1-3 Power - 98 $120,599,965 83% Heat - 33 $18,029,051 13% Heat & Power - 4 $6,186,611 4% Alaska Renewable Energy Fund oe Regional Summary Round 4 Ranking bere anaes! $36.5 million Allocation Preliminary 1/04/2011 Rounds 1-3 % of Rounds 1-3 Total Grant Funding Funding ‘Aleutians 11,593,784 Bering Straits 11,997,448 Bristol Bay 7,431,915 ‘Copper River/Chugach 14,057,970 Kodiak 4,973,160 Lower Yukon-Kuskokwim 24,064,078 North Slope 1,266,912 Northwest Arctic 22,117,405 Railbelt 19,193,454 Southeast 20,211,588 'Yukon-Koyukuk/Upper Tanana 12,128,901 i 565,439 149,602,054 Recommendation Cost of Power Population Even Split Additional Average Allocation funding Allocation Allocation Grant cost power cost of power needed to per capita per region Energy Region Funding % Total _|($/kWh) basis reach 50% % total basis basis ‘Aleutians 2,962,225 8% 0.51 4,505,837 (709,306) 1% 479,090 3,318,885 Bering Straits 1,753,217 5% 0.51 4,456,992 475,279 1% 534,711 3,318,885 Bristol Bay 724,950 2% 0.49 4,274,680 1,412,390 1% 365,077 3,318,885 Copper River/Chugach 1,554,985 4% 0.25 2,227,543 (441,213) 1% 365,077 3,318,885 Kodiak 3,989,340 11% 0.17 1,530,723 (3,223,978) 1% 365,077 3,318,885 Lower Yukon-Kuskokwim 1,463,369 4% 0.61 5,335,412 1,204,337 4% 1,362,969 3,318,885 North Slope 1,236,000 3% 0.14 1,220,045 (625,978) 1% 434,074 3,318,885 Northwest Arctic 420,000 1% 0.59 5,195,452 2,177,726 1% 383,932 3,318,885 Railbelt 8,753,252 24% 0.16 1,414,032 (8,046,236) 75% 27,380,798 3,318,885 Southeast 12,453,129 34% 0.15 1,359,666 (11,773,296) 11% 4,015,850 3,318,885 'Yukon-Koyukuk/Upper Tanana 1,197,264 3% 0.57 4,987,349 1,296,411 1% 543,962 3,318,885 Statewide = 0% 0.20 - TOTAL 36,507,731 100% 0.20 36,507,731 100% 36,507,731 36,507,731 Cumulative Rounds 1-4 Recommendation Cost of Power Population Even Split Additional % of Average Allocation funding Allocation Allocation Total Rounds Total cost power cost of power needed to per capita per region 1-3 Funding Funding |($/kWh) basis reach 50% % total basis basis 14,556,009 ; 20,967,940 (4,072,039). 1% 2,442,312 16,919,071 Bering Straits 13,750,665 ; 20,740,637 (3,380,347) 1% 2,725,861 16,919,071 Bristol Bay 8,156,865 : 19,892,248 | 1,789,259} 1% 1,861,098 | 16,919,071 ‘Copper River/Chugach 15,612,955 . 10,365,887 (10,430,012) 1% 1,861,098 16,919,071 Kodiak 8,962,500 : 7,123,229 (5,400,886) 1% 1,861,098 16,919,071 Lower Yukon-Kuskokwim 25,527,447 : 24,828,373 (13,113,261) 4% 6,948,168 16,919,071 North Slope 2,502,912 } 5,677,485 sase| 1% 2,212,829 | 16,919,071 Northwest Arctic 22,537,405 1 i 24,177,065 (10,448,872) 1% 1,957,213 16,919,071 27,946,706 ; 6,580,206 bai 656,603)| 75% 139,582,339 | 16,919,071 32,664,717 I. 6,327,214 (29,501,110) 11% 20,472,076 16,919,071 lYukon-Koyukuk/Upper Tanana 13,326,165 7 23,208,660 (1,721,835) 1% 2,773,019 | 16,919,071 Statewide 565,439 : 8,110,421 186,109,785 ; 186,109,785 100% 186,109,785 | 186,109,785 (Highlighted in blue indicates additional allocations |__ : needed to reach the 50% goal of regional spread) Alaska Renewable Energy Fund ‘> Regional Summary Round 4 Ranking eT $25 million Allocation Preliminary 1/04/11 Rounds 1-3 % of Rounds 1-3 Total Grant Funding Funding ‘Aleutians 11,593,784 Bering Straits 11,997,448 Bristol Bay 7,431,915 Copper River/Chugach 14,057,970 Kodiak 4,973,160 Lower Yukon-Kuskokwim 24,064,078 North Slope 1,266,912 Northwest Arctic 22,117,405 Railbelt 19,193,454 Southeast 20,211,588 lY ukon-Koyukuk/Upper Tanana 12,128,901 Statewide 565,439 149,602,054 Round 4 Recommendation Cost of Power Population Even Split Additional Average Allocation funding Allocation Allocation cost power cost of power needed to per capita per region ($/kWh basis reach 50% % total _ basis basis 198,150 1% 0.51 3,085,536 1,344,618 1% 328,074 2,272,727 Bering Straits 1,468,217 6% 0.51 3,052,087 57,827 1% 366,163 2,272,727 Bristol Bay 619,900 2% 0.49 2,927,243 843,721 1% 250,000 2,272,727 Copper River/Chugach 914,500 4% 0.25 1,525,392 (151,804) 1% 250,000 2,272,727 Kodiak 3,989,340 16% 0.17 1,048,218 (3,465,231) 1% 250,000 2,272,727 Lower Yukon-Kuskokwim 1,216,619 5% 0.61 3,653,618 610,190 4% 933,343 2,272,727 North Slope 210,000 1% 0.14 835,470 207,735 1% 297,248 2,272,727 Northwest Arctic 420,000 2% 0.59 3,557,775 1,358,887 1% 262,911 Zlater Railbelt 6,459,752 26% 0.16 968,310 (5,975,597)| 76% 18,939,765 2,272,727 Southeast 8,306,258 33% 0.15 931,081 (7,840,718) 11% 2,750,000 2,272,727 Yukon-Koyukuk/Upper Tanana 1,197,264 0.57 3,415,269 510,371 1% 372,498 2,272,727 Statewide 0.20 - 25,000,000 100% 0.20 25,000,000 TOTAL 100% 25,000,000 _ 25,000,000 Cumulative Rounds 1-4 Recommendation Cost of Power Population Even Split Additional % of Average Allocation funding Allocation Allocation Total Rounds Total cost power cost of power needed to per capita per region Energy Region 1-4 Funding Funding |($/kWh basis reach 50% % total basis basis Aleutians 11,791,934 7% 0.51 20,567,744 (1,508,062) 1% 2,291,296 | 15,872,914 Bering Straits 13,465,665 8% 0.51 20,344,779 (3,293,275) 1% 2,557,313 15,872,914 Bristol Bay 8,051,815 5% 0.49 19,512,583 1% 1,746,021 | 15,872,914 Copper River/Chugach 14,972,470 9% 0.25 10,168,043 (9,888,449) 1% 1,746,021 15,872,914 Kodiak 8,962,500 5% 0.17 6,987,274 (5,468,863) 1% 1,746,021] 15,872,914 Lower Yukon-Kuskokwim 25,280,697 14% 0.61 24,354,496 (13,103,449) 4% 6,518,541 15,872,914 North Slope 1,476,912 1% 0.14 5,569,124 1% 2,076,003 | 15,872,914 Northwest Arctic 22,537,405 13% 0.59 23,715,620 (10,679,595) 1% 1,836,193 15,872,914 Railbelt 25,653,206 15% 0.16 6,454,616 (22,425,898)} 76% 132,276,875 | 15,872,914 Southeast 28,517,846 16% 0.15 6,206,452 (25,414,620) 11% 19,206,226 15,872,914 Yukon-Koyukuk/Upper Tanana 13,326,165 8% 0.57 22,765,697 (1,943,316) 1% 2,601,555 | 15,872,914 Statewide 565,439 0% 0.20 7,955,624 [TOTAL 174,602,054 100% 0.20 174,602,054 (Highlighted in blue indicates additional allocations SER needed to reach the 50% goal of regional spread) 100% 174,602,054 | 174,602,054 Renewable Energy Fund /= ALASKA i ENERGY AUTHORITY Advisory Committee Meeting Program Update January 7, 2011 Current Status e Round 1-4 Grant and Funding Summary Cele Tae Applications Received 112 118 123 108 461 Projects Funded 73° 30’ 25 TBD 133 L Grants in Place 74° 29 13 TBD 116 Grants Cancelled 3? 2 0 N/A 4 Amount Requested ($M) $453.8 $293.4 $223.7 $123.1 $1,094 AEA Recommended ($M) $100.0 $36.8 $65.8 TBD $202.6 Appropriated ($M) $100.0 $25.0 $25.0 TBD $150.0 Cash Disbursed ($M) $37.8 $6.6 $0 $0 yd Available for reallocation ($M) $2.9* $1.0° Sac $0 $4.0 1- Includes eleven projects from an earlier solicitation issued by AEA. 2- Nikolaevsk Wind Farm, Southfork Hydro, and Galena Wood Heating project. Funds transferred to Takatz Lake project; these plus other funds make Takatz Lake Hydro project now fully funded ($2,000,000) per LB&A directive. 3- Angoon Heat Recovery project - completed with other funds. 4- Balance of Southfork Hydro ($152,134), Haines Central Wood ($99,602), Cordova Wood Processor (10,960), Fish Hook Hydro ($2,000,000) Ambler Solar ($529,430) and Manley Hot Springs ($193,625) projects. 5- Angoon grant balance ($545,934), Neck Lake Hydro balance (~$75,000) and ($386,986) balance after grant amounts adjusted. 6- Four projects (Fish Hook Hydro, Reynolds Creek Hydro, St. George Wind and Bethel Wind) remain unexecuted. For all four, the grantee is responsible for the delay in getting the grant executed. 7- Kenai Winds grant combined with Round | grant for same project. 8- Neck Lake Hydro ($90,000) Sy Alaska Industrial Development We al Export Authority we ye ; ‘IDEN = ALASKA * @@___» ENERGY AUTHORITY Alaska Renewable Energy Fund | DRAFT Methods for Proposal Evaluation and Grant Recommendation January 4, 2011 Overview of Review Process Renewable Energy Fund applications were evaluated in four stages. For more detail please refer to Evaluation Guidelines in the appendices and to documents posted on the Renewable Energy Fund webpage http://www.akenergyauthority.org/RE_Fund.html. Conducted by Alaska Energy Authority (AEA) staff, the first stage of review evaluated each application for completeness, eligibility, and responsiveness to the request for applications (RFA). AEA rejected four proposals that did not meet these threshold criteria. The second stage evaluated the technical and economic feasibility of the proposed projects. In addition to numerical scores, the second stage resulted in project-specific recommendations for full, partial, or no funding, as well as recommendations for special provisions for grant awards should the Legislature approve funding. The second stage was conducted by AEA staff with the assistance of Alaska Department of Natural Resources staff, Institute of Social Economic Research (ISER) staff, and private economists under contract to AEA under the coordination of ISER. Projects may have been recommended for partial or no funding if they were viable but: e Documentation submitted with the application was not sufficient to justify full funding for more than one phase of a project. e Funding for proposed project development phases would not be used until late fy2012 or afterwards. That is, funds would be tied up unreasonably. e There were competing projects for which planning is desirable e The applicant requested AEA to manage the project and the AEA program manager could confidently estimate a lower cost. e The proposal included operating costs, ineligible costs, unreasonably high costs, or other costs not recommended for funding. AEA recommended no funding for 28 projects following stage 2 review while one project was withdrawn by the applicant and was therefore also not recommended The third stage was a final scoring based on the specific guidelines in the RFA that was conducted by AEA staff. The scoring was done based on a number of matrices and pre- established weighting for each of the criteria. 1. Cost of Energy (25%): 2. Matching Funds (20%) 3. Economic and Technical Feasibility (20%): score from stage 2 813 West Northern Lights Boulevard e Anchorage, Alaska 99503-2495 www.aidea.org ¢ 907/771-3000 e FAX 907/771-3044 e Toll Free (Alaska Only) 888/300-8534 e www.akenergyauthority.org Project Readiness (10%) Economic and Other Alaska Benefit (15%) Sustainability (5%) Local Support (5%) So In the fourth stage all applications were ranked by region with the final funding recommendation being made based on the number and rank of applications with each region, the cost of energy, and a balance of statewide funding. Where AEA recommended less than the requested amount and the Legislature funds the project, AEA will work with grantees to assure that the revised scope of the final grant award is consistent with the grantee’s proposal and meets the public purposes of the program. Roles of AEA Staff and the Renewable Energy Fund Advisory Committee AEA staff requested and received input from the Renewable Energy Fund Advisory Committee regarding the process and final funding recommendations. Following is a summary of Committee involvement. AEA staff and the Committee met on June 8, 2010 and again on August 13, 2010 to discuss issues including the schedule of the upcoming RFA, progress on funded projects, ways to stimulate proposals for beneficial projects, and requiring minimum benefit/cost ratios. Midway through review of the applications AEA staff and the Committee met on November 9, 2010 to discuss the economic firms and AEA, DNR and ISER staff involved with the proposal evaluation, progress on review, a slight change on the Readiness criterion to address consistency with the state Energy Pathway, , a public request for additional review of proposals by ADF&G, how to address letters from legislators in the Local Support criterion score, update on construction project progress and round 3 grants, and grant report frequency. Following AEA evaluation of all applications, AEA staff and the Committee met on January 7, 2011 to address requirements for achieving a statewide balance of funds. Based on this discussion and the outcome of appeals due January 10 AEA finalized its recommendations. RE-Fund Round-4 Evaluation Guidelines Page 2 of 2 01/05/2011 KK y x = JIDEX /= ALASKA *& * Alaska Industrial Development = ENERGY AUTHORITY and Export Authority Appendix A Guidelines for Renewable Energy Fund Application Evaluation Table of Contents Stage 1 Review Process: Reviewers — Criteria....... Process. Stage 2 Review Process: Reviewers — Criteria Stage 3 Review Process: Reviewers — Criteria... Process. $$ Limitations on Recommendations Sec 1.14... Recommendation Guidelines Stage 4 Ranking of Applications for Funding Recommendations... Reviewers — Process. Scoring Criteria General Scoring Criteria Stage 2, Criterion 4 (a) Economic Benefit Cost Benefit Ratio Stage 2, Criterion 4 (b) Financing Plan Stage 2, Criterion 4 (c) Public Benefit Review Guidelines. Stage 3 Criteria — Match.............. Stage 3 Criteria Local Support. Stage 3 Criteria Project Readiness Stage 3 Criteria Public Benefit.......... Stage 3 Criteria Statewide Regional Balance.. Stage 3 Criteria Compliance with Other Awards Stage 3 Criteria Cost of Energy These are the Evaluation Guidelines and instructions for Evaluation of The Round 3 RFA for Renewable Energy Fund Grant Projects e Applications that do not comply with AS 42.45.45 and all of the material and substantial terms, conditions, and requirements of the RFA may be rejected. 813 West Northern Lights Boulevard e Anchorage, Alaska 99503-2495 www.aidea.org e 907/771-3000 e FAX 907/771-3044 e Toll Free (Alaska Only) 888/300-8534 e www.akenergyauthority.org If an application is rejected the applicant will be notified in writing that its application has been rejected and the basis for rejection. The Authority may waive minor requirements of the RFA that do not result in a material change in the requirements of the RFA and do not give an applicant an unfair advantage in the review process. Upon submission of the final recommendations to the Legislature the Authority will make all applications available for review on the Authority's web site. General: All communications with applicants during the evaluation process will go through the Grant Administrator. The Executive Director is the Executive Director of AEA, Program Managers are those Management Personal in AEA who have program oversight for AEA programs, Project Managers are the subject matter technical experts, and the Grant Manager is the person responsible for overseeing the grant process for the Authority. All applications will be reviewed using the same process and criteria established in the RFA. Decisions made in each stage of the review process will be documented in writing and made a part of the grant file. If reviewers think they may have a potential conflict of interest, (financial or personal interest, such as friend or family members) they should inform their supervisor immediately of the potential nature of the conflict. Reviewers should make notes of any questions they may have about an application. Reviewers should not contact applicants directly. If reviewers have questions about an application or process contact they should contact the Grant Administrator. If reviewers have technical questions they should contact the Program Managers. If an application is rejected or not recommended the applicants will be sent a letter from the Grant Administrator explaining why their application has been rejected or not recommended. Reviewers will be required to provide to the Grant Administrator the reasons for why the application is being rejected Notes should be made directly into the database on line. All written notes should be kept with the application file. All notes are considered public records and subject to Alaska public records act disclosure requirements. Any appeals from rejected applicants in Stage 1 or Stage 2 reviews will be directed to the Grant Administrator. The Grant Administrator will review the appeal with the Executive Director, Program Manager, and Legal staff as required to determine an appropriate course of action. Stage 1 Review Process: All applications received by the deadline will initially be reviewed by the Authority staff to assess if the application is complete, meets the minimum submission requirements, and has adequate information to proceed to Stage 2 — Technical Evaluation. Reviewers — Grant Administrator and at least one Program Manager RE-Fund Round-4 | Evaluation Guidelines Page 2 of 22 1/5/20119 Criteria All criteria are scored pass/fail. Failure to meet any of these criteria results in rejection of the Application. 1. The application is submitted by an Eligible Applicant (sec 1.2). 2. The project meets the definition of an Eligible Project (sec 1.3). 3. Aresolution or other formal authorization of the Applicant’s governing body is included with the application to demonstrate the Applicant's commitment to the project and any proposed use of matching resources (sec 1.2). 4. The application provides a detailed description of the phase(s) of project proposed, i.e. reconnaissance study, conceptual design/feasibility study, final design/permitting, and/or construction (sec 2.1). 5. The application is complete in that the information provided is sufficiently responsive to the RFA to allow AEA to consider the application in the next stage of evaluation. 6. The Applicant demonstrates that they will take ownership of the project; own, lease, or otherwise control the site upon which the project is located; and upon completion of the project operate and maintain it for its economic life for the benefit of the public. (sec 1.2) Process The Grant Administrator will evaluate criteria 1-3 & 6 above. The Program Managers will evaluate criteria 4-5 above. If it appears that the application could be complete with a clarification or minor additional data the Program Managers (PM) may make a recommendation to the Grant Manager for additional information. The Grant Administrator will request clarifying information from the applicant. The applicant will have a specified amount of time to provide the requested information. Failure of the applicant to respond timely or provide information that completes their application will result in the application being rejected. Applications that are determined by the Grant Administrator and Program Managers and determined to be incomplete or fail to meet the minimum requirements will be reviewed by the Executive Director with the assistance of Legal or procurement staff prior to being rejected at Stage 1. Applications that fail to pass will be provided written notice as to why their application failed stage 1. Any requests for reconsideration from rejected applicants in Stage 1 will be directed to the Grant Administrator. The Grant Administrator will review the request with the Executive Director, Program Manager, and Legal staff as required to determine an appropriate course of action. Stage 2 Review Process: All applications that pass Stage 1 will be reviewed for feasibility in accordance with the criteria below. Reviewers — Project Managers — the AEA technical subject matter experts. RE-Fund Round-4 | Evaluation Guidelines Page 3 of 22 1/5/2011 Staff from Department of Natural Resources — technical experts providing specific review and comment on projects that may have issues related to permitting and natural resource development. Economists - Contracted economist who will review cost benefit and other cost and pricing information provided for each application submitted for the purpose of providing the authority and independent assessment of the economics of the proposed project. ISER — University of Alaska Institute of Social and Economic Research — is providing coordination and Quality Assurance review of economic analysis work for selected projects. Program Managers — Overseers of the work of the Project Managers Criteria Each of the numbered criteria below will be scored with a numerical score 1-10 and weighted per the percentages below. Criteria Weight a b. 1. Project Management, Development, and Operation . The proposed schedule is clear, realistic, and described in adequate detail. The cost savings estimates for project development, operation, maintenance, fuel, and other project items are realistic, The project team’s method of communicating, monitoring, and reporting development progress is described in adequate detail. Logistical, business, and financial arrangements for operating and selling energy from the completed project are reasonable and described in adequate detail. 20% a d. 2. Qualifications and Experience . The Applicant, partners, and contractors have sufficient knowledge and experience to successfully complete and operate the project. The project team has staffing, time, and other resources to successfully complete and operate the project. The project team is able to understand and address technical, economic, and environmental barriers to successful project completion and operation. The project uses local labor and trains a local labor workforce. 20% 3. Tech a. ao nical Feasibility The renewable energy resource is available on a sustainable basis, and project permits and other authorizations can reasonably be obtained. A site is available and suitable for the proposed energy system. Project technical and environmental risks are reasonable. The proposed energy system can reliably produce and deliver energy as planned. If a demonstration project is being proposed: e Application in other areas of the state, or another specific benefit of the proposed project, is likely: 20% RE-Fund Round-4 | Evaluation Guidelines Page 4 of 22 1/5/20110 e need for this project is shown (vs. the ability to use existing technology); and e the risks of the proposed system are reasonable and warrant demonstration. 4. Economic Feasibility 25% a. The project is shown to be economically feasible (net savings in fuel, operation and maintenance, and capital costs over the life of the proposed project). In determining economic feasibility and benefits applications a will be evaluated anticipating the grantee will use cost-based rates. b. The project has an adequate financing plan for completion of | 5% the grant-funded phase and has considered options for financing subsequent phases of the project. c. Other benefits to the Alaska public are demonstrated. 10% Avoided cost rates alone will not be presumed to be in the best interest of the public. Process Project Managers will carefully review the proposals for their assigned technology group and provide an initial feasibility score on all criteria and a funding recommendation. An economist hired by AEA will review the economic information and provide an independent analysis of cost and benefits of each project. The reviewers will consider the independent analysis when scoring the economic feasibility and benefits criteria. Reviewers will use the formula and criteria in the attached Scoring Matrix Guide - for designated criteria in Stage 2. If the Project Manager believes they need additional information they will coordinate their request for follow-up information with the Grant Administrator. The purpose of follow-up is for clarification and to help the Project Manager gain a sufficient understanding of the project proposed. Any requests for additional information will be made by the Grant Administrator to the applicant by e-mail, Bcc to project manager, with a response time of 7 days or less. Applicants that fail to respond to requests for information or to adequately address the criteria in the technical review will be rejected in Stage 2. The Program Managers will meet with the project managers to review the applications and discuss final Stage 2 scoring. Scoring per the stage 2 criteria may be adjusted based on final discussions between the Project Manager, Program Managers, Economists, and Executive Director. A final weighted “feasibility” score will be given for each application reviewed and will be used to calculate the Phase 3 feasibility score. Applications that fail to adequately address the criteria in the technical review may not be recommended for funding or further review. Applications that fail to pass will be provided written notice as to why their application failed Stage 2. The Authority will develop a preliminary list of feasible applications based on the Stage 2 review with AEA recommendations on technical and economic feasibility and a recommended funding level to be considered in the Stage 3 review. RE-Fund Round-4 | Evaluation Guidelines Page 5 of 22 1/5/20110 Stage 3 Review Process: All applications that pass the technical review will be evaluated for the purpose of ranking applications and making recommendations to the Legislature based on the following criteria which include criteria required by 3 AAC 107.655 and AS 42.45.045. The Feasibility score from Stage 2 will be automatically weighted and scored in Stage three. The average of the Economic and Public Benefit score of stage 2 will be used for initial scoring of Economic and Other Public Benefit Score. This score will be reviewed by the Program Managers. The Grant Administrator, with staff assistance, will score the cost of energy, type and amount of matching funds, and local support, using the formulas and methods outlined in Appendix A. Two Program Managers will review the scoring of the Project Managers and Grant Manager and provide a score for readiness and previous success, and sustainability. AEA will develop a regional ranking of applications and a draft ranking of all projects for the Advisory committee to review. The Advisory Committee will review the final Stage 3 scores regional ranking recommendations of the Authority. The Committee may make recommendations to assist in achieving a statewide balance but will not be rescoring based on the criteria. Reviewers — e Grant Administrator (Local Support and Match Criteria) e Two Program Managers e Executive Director of AEA. e Advisory Committee (Review of Regional Ranking and Funding Recommendations) Criteria e Criteria noted below will be scored and weighted as noted. Criteria Round 3 Weight Cost of energy per resident in the affected project 25 area relative to other areas (From Worksheet) The type and amount of matching funds and other 20 resources an applicant will commit to the project. (See formula) Project feasibility (Score from Stage 2 weighted) 20 Project readiness. How quickly the proposed work 10 can begin and be accomplished and/or success in previous phases of project development. Public benefits including economic benefit to the 15 Alaska Public. Sustainability — the ability of the application to finance, | 5 operate and maintain the project for the life of the project Local Support (See formula) 5 Statewide Balance of Funds (Evaluated as a pass fail if there are similar projects in the same community. RE-Fund Round-4 | Evaluation Guidelines Page 6 of 22 1/5/20119 Statewide Balance is done in Stage 4.) Compliance with Previous Grant Awards and progress in previous phases of project development. (Evaluated as a pass fail) Process e Reviewers will use the Scoring Matrix Guides for designated criteria in Stage 2. e Each application will be given a single weighted score. e Where more than one evaluator is scoring a given criteria the scores of all evaluators for that criteria will be averaged. e Any requests for additional information will be made by the Grant Administrator by e- mail, Bcc to project manager, with a response time of 7 days or less. e The evaluation team may conduct interviews of applicants to determine a more complete understanding of the technical or financial aspects of their application. Funding Limitations on Recommendations Sec 1.14 Evaluators should take these limits into account when making recommendations as the applicants were instructed that they would be responsible for any project costs beyond the grant funds available to complete the project. Project Type/Phase Grant Limits Construction projects on the Railbelt $2. Million per project and SE Alaskan communities that have a low cost of power. Construction in all other areas of the $4. Million per project State not mentioned above. Recommendation Guidelines e The final recommendations will be one of the following: o Recommend — Full funding per application o Recommend - Partial funding with a recommended funding amount o Donot recommend for grant funding — (basis for not recommending to be explained) e Final AEA recommendations may also suggest specific terms or conditions be imposed on the grantee to assure the project is successful and the public receives value for the funds to be expended e Multi-phase funding guidelines o Fund multiple phases: Multiple phases can be completed in 2011/12, and project is well-defined, relatively inexpensive, and low-risk. o Fund limited phases: Project construction would be 2012+, not well-defined, expensive, higher risk, or there are competing projects for which planning is desirable. e Competing or interactive projects guidelines o If AEA is aware of the potential for substantial interaction among proposed and/or other known projects, then recommend planning with appropriate level of analysis and public input before committing substantial funding to one or more alternatives. e Partial Funding Guidelines RE-Fund Round-4 | Evaluation Guidelines Page 7 of 22 1/5/20110 o Partial funding levels will correspond to amount proposed in phases that are recommended. o Exception 1: If prepesalasks AEA to managethe-preject_and AEA thinks believes project can be built for less, then lower figure can be recommended. AEA will provide justification for lower figure in its recommendations. o Exception 2: Proposal requests funding for operating expense (labor, fuel) or non-renewable energy components (e.g. a diesel generator) not recommended for funding. o Exception 3 — If limiting funding to a maximum dollar limit for specific areas groups, or types of projects would provide the best statewide balance of funds AEA may do that. e Guidelines for recommendations for bio-fuels Projects (RFA 1.14) o Bio-fuel projects where the Applicant does not intend to generate electricity or heat for sale to the public will be limited to reconnaissance and feasibility phases only e Consideration of Resources Assessment Projects o Resource assessment associated with one or more site-specific projects is eligible for phase 2 funding. General regional or statewide assessment, not tied to particular proposed projects, is not eligible, and more appropriately done through the DNR/AEA Alaska Energy Inventory Data project. e Recommendation Guidelines will be documented and a part of the grant file. Stage 4 Ranking of Applications for Funding Recommendations All applications recommended for grants as a result the Stage 3 evaluation will be ranked in accordance with 3 AAC 107.660. To establish a statewide balance of recommended projects, the Authority will provide to the advisory committee a statewide and regional ranking of all applications recommended for grants in Stage 3. In consultation with the advisory committee the Authority will make a final prioritized list of all recommended projects giving significant weight to providing a statewide balance for grant money, and taking into consideration the amount of money that may be available, the number and types of project within each region, regional rank, and statewide rank of each application. In its final decision on an application the Authority may recommend a grant in an amount for the project phases different from what the Applicant requested. In recommending a grant for phases different from what the Applicant requested, the authority may limit its recommendation to a grant for one or more preliminary project phases before recommending a grant for project construction. Reviewers — e Grant Administrator e Program Manager e Executive Director of AEA. e Advisory Committee (Review of Regional Ranking and Funding Recommendations) RE-Fund Round-4 | Evaluation Guidelines Page 8 of 22 1/5/2011 Process e Upon completion of scoring and specific project recommendations by AEA all applications will be grouped within geographical regions, e Each group of applications will be ranked within their geographical region based on the final stage three score. e Each application will have stage three score and regional rank. e Adraft recommendation of projects for funding, (based on available funds) will be presented to the Advisory Committee for Review along with the complete list of all projects. e Consistent with the process established in rounds 1,2, and 3, AEA will prepare a summary of the draft recommendations by energy region that will compare potential allocations of funding by 1) population, 2) an even split for each region, and 3) the average cost of power in each region that takes into account populations of each community in each region. e Stage 4 revised allocations in each region should be at least 50% of the allocation based on 3) cost of power. In order to attain this goal AEA will refer to the stage 3 statewide ranking list, identify the next highest-ranked project in regions that do not meet the 50% goal, and add that recommendation to the stage 4 list. In order to meet total funding limits AEA will refer to the stage 3 statewide ranking list and remove the lowest-ranked recommendation. e The Advisory committee may provide additional recommendations as to the funding level of individual projects, the final ranking of projects, and the total amount of funding and number of project AEA forward to the legislature. e The final list of recommended projects for funding will provide a reasonable statewide balance of funds taking into consideration the overall score, the cost of energy, the rank of projects within a region. Recommendations to the Legislature The final recommendation to the legislature will include: e A list of recommended Applications for fy2012 funding. e A list of applications recommended if additional funds may be available. e A list of applications not recommended for funding. e A list of applications rejected as ineligible. The Final recommendation to the legislature will also contain specific information for each project as requested by the legislature and a summary of each project. Applicants may be required to provide additional information to the Legislature upon request. RE-Fund Round-4 | Evaluation Guidelines Page 9 of 22 1/5/20110 Scoring Criteria General Scoring Criteria e Pass/Fail scoring means either the criteria are met or they are not. e Aweighted score for each of the criteria will calculated and each complete application will be given a total score at the end of the Stage 2 and Stage 3 review process unless the application is determined not to meet the requirements of the RFA. e Reviewers should use the following weighted scoring of criteria as a guide in addition to the specific formula scoring matrices for some criteria defined in Appendix A of these procedures. Score | Guidelines (Intent is to provide a range) 10 A+ | The application demonstrates a thorough understanding of the criteria requirements and completely addresses them thoughtful manner. The application addresses the criteria in a manner clearly superior to other applications received. There is no need for additional follow-up with the applicant to understand how they meet the requirements of the criteria 7 B The application provides information that is generally complete and well-supported. Evaluators may still have a few questions regarding how the applicant meets the criterion but it is clear the applicant understands what is required. 5 Cc The application addresses the criteria in an adequate way. Meets minimum requirements under each of the criteria. Some issues may still need to be clarified prior to awarding a grant. 3 D The application information is incomplete or fails to fully address what is needed for the project or information has errors. The Authority may need more info to be able to complete the evaluation or need to resolve issues before recommending or awarding a grant. 0 F The application fails to demonstrate understanding of the criteria requirements or project proposed. Required information is poor or absent in the proposal. RE-Fund Round-4 | Evaluation Guidelines Page 10 of 22 1/5/20118 Stage 2, Criterion 4 (a) Economic Benefit Cost Ratio (Maximum Stage Two points 25) AEA staff will consider the economist evaluation when scoring this criterion. They will compare the economists and any Applicant proposed B/C and determine which of the B/C ranges may be most appropriate. If there is wide discrepancy between the two B/C ratios they will use their best judgment based on their understanding of the technical aspects of the proposal to assign a score. A project will be scored at 0 if the Benefit Cost ratio value is < 0.90 or if no or insufficient information is provided by the applicant to do an economic analysis. Benefit / Cost (B/C) Ratio Value Less than 0.90 (This indicates that there is relatively low economic benefit or economic analysis cannot be conducted.) >0.90 — =<1.00 >1.00 — =<1.10 >1.10 —- =<1.20 >1.20 — =<1.30 >1.30 — =<1.40 >1.40 - < 1.50 >1.50 - < 1.60 >1.60- <1.70 OlOIN| DO) B/ oo) = o Stage 2, Criterion 4 (b) Financing Plan (Maximum Stage Two points 5) The Financing plan score will be subjectively scored based on the applicant’s intent and level of detail described in the application on how the applicant proposes to fund the project. Questions to be considered under these criteria: e If recommended, are funds needed to complete the work identified in the application available and adequate to complete all the work in the Grant? e If additional funds are needed does the applicant specifically identify where they will come from? e Are these additional funds secured, or are they pending future approvals? e Is there a reasonable plan for covering potential cost increases or shortfalls in funding? e What impact, if any, would the timing of availability of additional funds have on the ability to proceed with the grant? If the above questions are addressed in the application and there is an adequate plan this will be given a point score of 5. If the plan is not adequate it will be scored lower based on the likelihood of funding being available to complete the project or additional commitments that may need to be made by the applicant prior to award of a grant. For example, an applicant may request construction funding above the RFA cap but does not indicate how the additional funding will be obtained. They may receive a lower score than an RE-Fund Round-4 | Evaluation Guidelines Page 11 of 22 1/5/20118 applicant who can demonstrate they have all the financial resources in place to complete the grant work proposed in the application. Stage 2, Criterion 4 (c) Public Benefit Review Guidelines (Maximum Stage two points 10) The score for this criterion will be provided by AEA reviewers during the Stage 2 evaluation. For the purpose of evaluating this criterion, public benefits are those benefits that would be considered unique to a given project and not generic to any renewable resource. i.e. decreased greenhouse gas emission, stable pricing of fuel source, won’t be considered under this category. Project review economists will provide a qualitative assessment of potential public benefits in their project review summary for each project they review. Economists will not provide scores for the criteria. Each category may be scored 0-2 with the maximum total public benefit weight being no more than 10 points. 0. no documented benefit 1 some benefit / not well documented 2 good benefit / well documented Score Will the project result in developing infrastructure such as 0-2 roads that can be used for other purposes? Will the project result in a direct long-term increase in jobs 0-2 such as for operating or supplying fuel to the facility? Will the project solve other problems for the community, 0-2 such as waste disposal? Will the project generate useful information that could be 0-2 used by the public in other parts of the State? Will this project either promote or sustain long-term 0-2 commercial economic development for the community? Are there other public benefits identified by the applicant? 0-2 Stage 3 Criterion — Match Total of 20 points will be calculated as follows: The scoring matrix for the total amount of match may be adjusted by the Grant Administrator after the initial review of applications based on a reasonable threshold for each level based on the applicants match in all applications. Type of Match 5 +| Percentage of | 10 +| Total Amount | 5 Pts Match to total | Pts of Match (1) Pts Grant Request Support of any kind referenced | 1 .01% - <5% of | 1 >$1-<$15K |1 but not given a specific value IE Grant = housing offered to outside workers, administration of RE-Fund Round-4 | Evaluation Guidelines Page 12 of 22 1/5/20118 project without compensation Previous investment towards =>5% - =<10% | 2 $15K - <$100K project completion of Grant = Another grant [State] as Match >10% - =<15% | 4 $100K <$1 mil of Grant = Other (Grant Fed) Or private >15% - =<30% | 6 $1 mil - <$6 of Grant mil Loan or Local Cash or any >30% - =<49% | 8 > $6 mil documented In-kind Match of Grant = > 49% of Grant | 10 (1) If there are multiple types of Match that with highest value is scored. Stage 3 Criterion Local Support Total of 5 Points Available Documented unresolved issues concerning the application no points 0 points will be given if these exist regardless of demonstrated support Resolution from city or village council 2 points Support demonstrated by local entity other than applicant 3 points Support demonstrated by two local entities other than the applicant 4 points Support demonstrated by three or more local entities other than the 5 points applicant Letters of support from legislators do not count toward this criterion. Stage 3 Criterion Project Readiness Up to ten points are available and may be assigned as follows. If evaluators believe there are other readiness criteria that should be considered they may adjust the score that when awarding points for this criteria Criteria Up to 10 points available Proposed work is reconnaissance level and is consistent with specific 4 points recommendations under the Alaska Energy Pathway Project is currently underway with feasibility or reconnaissance work, 4 points design work related to the project, or actual construction of the project and the applicant is using their own funds or funds from another eligible source to finance the activity. Applicant has completed previous phase(s) of proposed project and desires | 2 points additional funding to complete the next phase of project. Applicant has completed required feasibility and/or design work for project and is prepared to place an order for necessary equipment for the project; such as an item with a ‘long lead time’ to procure. Applicant has obtained all necessary permits, met all permit requirements, and addressed all regulatory agency stipulations. 2 points 2 points RE-Fund Round-4 | Evaluation Guidelines Page 13 of 22 1/5/20110 Stage 3 Criterion Public Benefit This criteria will be scored using a weighted calculation from the Phase 2 Economic (4.a) and Public Benefit score (4.b). Stage 3 Sustainability This criteria will be scored from 0 to 5 based on the evaluators’ assessment of the 1) capability of the grantee to demonstrate the capacity, both administratively and financially, to provide for the long-term operation and maintenance of the proposed project, 2) likelihood of the resource being available over the life of the project, 3) likelihood of market for energy produced over the life of the project. Stage 3 Criteria Statewide Regional Balance Rated as Pass, Fail, or Not Applicable (NA) Criteria If there is more than one project from the same community or area, which project has received an overall higher score during the review and/or has demonstrated that local residents are in favor of the project. Project funding will provide balance to the number and/or amount to a specific area of the State. Stage 3 Criteria Compliance with Other Awards Rated as Pass, Fail, or Not Applicable (NA Criteria Legislative | Alternative Energy Round L,I, Grant Solicitation (Round | or Ill 0) Has grantee provided all necessary information for grant preparation for grants awarded from previous solicitations? Is grantee making verifiable and adequate progress using previous grant funds; for this or another project? Has grantee provided all required financial and progress reports, per the terms of any previous grants? Stage 3 Criterion Cost of Energy This score is based on the residential cost power for each community using available data from 2009. Scores are assigned for each community using the following formula: Score = (cost of power) / 0.80 x 10, Score cannot be greater than 10. RE-Fund Round-4 Evaluation Guidelines Page 14 of 22 1/5/20110 Communities with a residential cost of power above $0.80/kWh are assigned a score of 10. Communities are with the highest cost of electrical energy getting the most points for this criterion. All other applications will be scored as a percentage of the highest costs against an established matrix. Cost of Power Score Community Utility ($/kWh) (1-10) Adak City of Adak 0.713 8.91 Afognak Kodiak Electric Association 0.153 1.91 Akiachak Native Community Akiachak Electric Co 0.630 7.88 Akiak City of Akiak 0.630 7.88 Akutan Akutan Electric Utility 0.323 4.04 Alakanuk AVEC 0.635 7.94 Alatna Alaska Power Company 0.667 8.34 Aleknagik Nushagak Electric Coop 0.463 5.79 Allakaket Alaska Power Company 0.667 8.34 Ambler AVEC 0.796 9.96 Anaktuvuk Pass North Slope Borough 0.150 1.88 Anchor Point (HEA 1) Homer Electric Association, Inc. 0.198 2.47 Anchorage, Municipality of | Chugach Electric Association, Inc. 0.126 1.57 Municipal Light & Power Department d/b/a Municipality of Anchorage, Municipality of | Anchorage 0.176 2.20 Golden Valley Electric Association, Anderson Inc. 0.168 2.10 Andreafsky AVEC 0.594 7.43 Inside Passage Electric Angoon Cooperative, Inc. 0.422 5.27 Aniak Aniak Light & Power Company 0.761 9.51 Anvik AVEC 0.656 8.20 Atka Andreanof Electric Corporation 0.767 9.58 Atmautluak Atmautluak Joint Utilities 0.774 9.68 Atqasuk North Slope Borough 0.150 1.88 Barrow Barrow Utilities & Electric Coop 0.132 1.65 Beaver Beaver Joint Utilities 0.550 6.88 Bethel Bethel Utilities Corporation, Inc. 0.537 6.71 Bettles Alaska Power Company 0.584 7.31 Matanuska Electric Association, Big Lake Inc. 0.169 2.12 Brevig Mission AVEC 0.603 7.53 Buckland City of Buckland 0.519 6.48 Golden Valley Electric Association, Cantwell Inc. 0.168 2.10 Central Central Electric, Inc. 0.509 6.36 RE-Fund Round-4 | Evaluation Guidelines Page 15 of 22 1/5/20110 Chalkyitsik Chuathbaluk Chefornak Chenega Bay Chevak Chickaloon Chignik Chignik Lagoon Chignik Lake Chilkat Valley Chiniak Chistochina Chitina Chugiak Circle Hot Springs (Central) Clam Gulch (HEA 1) Coffman Cove Cold Bay College Cooper Landing Copper Center Copperville Cordova Craig Crooked Creek Deadhorse Deering Delta Junction Dillingham Diomede (Little Diomede) Dot Lake Douglas Eagle Eagle River Eagle Village Eek Egegik Eklutna RE-Fund Round-4 | Evaluation Guidelines Chalkyitsik Village Energy System Middle Kuskokwim Electric Cooperative, Inc. Naterkaq Light Plant Chenega Bay IRA Village Council AVEC Matanuska Electric Association, Inc. Chignik Electric Chignik Lagoon Power Utility Chignik Lake Electric Utility, Inc. Inside Passage Electric Cooperative, Inc. Kodiak Electric Association Alaska Power Company Chitina Electric Inc. Matanuska Electric Association, Inc. Central Electric, Inc. Homer Electric Association, Inc. Alaska Power Company G &K, Inc. Golden Valley Electric Association, Inc. Chugach Electric Association, Inc. Copper Valley Electric Assn. Copper Valley Electric Assn. Cordova Electric Cooperative Inc. Alaska Power Company Middle Kuskokwim Electric Cooperative, Inc. TDX North Slope Generating, Inc. Ipnatchiaq Electric Company Golden Valley Electric Association, Inc. Nushagak Electric Coop Diomede Joint Utilities Alaska Power Company Alaska Electric Light & Power Alaska Power Company Matanuska Electric Association, Inc. Alaska Power Company AVEC Egegik Light & Power Company Matanuska Electric Association, Page 16 of 22 0.950 0.343 0.650 0.435 0.665 0.169 0.510 0.500 0.582 0.422 0.153 0.459 0.530 0.169 0.670 0.198 0.343 0.644 0.168 0.176 0.198 0.198 0.331 0.197 0.987 0.277 0.774 0.168 0.463 0.600 0.295 0.111 0.643 0.169 0.702 0.702 0.886 0.169 10.00 4.28 8.13 5.44 8.31 2.12 6.38 6.25 7.27 5.27 1.91 5.74 6.63 2.12 8.38 2.47 4.28 8.05 2.10 2.20 2.48 2.48 4.14 2.46 10.00 3.46 9.67 2.10 5.79 7.50 3.69 1.39 8.04 2.12 8.78 8.78 10.00 2.12 1/5/20110 Ekwok Elfin Cove Elim Emmonak Evansville Eyak Fairbanks False Pass Fort Greely Fort Wainwright Fort Yukon Fox Gakona Galena Gambell Glennallen Golovin Goodnews Bay Grayling Gulkana Gustavus Haines Halibut Cove (HEA 2) Healy Healy Lake Hollis Holy Cross Homer (HEA 1) Hoonah Hooper Bay Hope Houston Hughes Huslia Hydaburg Hyder/Stewart B.C. Igiugig lliamna RE-Fund Round-4 | Evaluation Guidelines Inc. Ekwok Electric Elfin Cove Utility Commission AVEC AVEC Alaska Power Company Cordova Electric Cooperative Inc. Golden Valley Electric Association, Inc. False Pass Electric Assoc Golden Valley Electric Association, Inc. Golden Valley Electric Association, Inc. Gwitchyaa Zhee Utility Company Golden Valley Electric Association, Inc. Copper Valley Electric Assn. City of Galena AVEC Copper Valley Electric Assn. Golovin Power Utilities AVEC AVEC Copper Valley Electric Assn. Gustavus Electric Company, Inc. Alaska Power Company Homer Electric Association, Inc. Golden Valley Electric Association, Inc. Alaska Power Company Alaska Power Company AVEC Homer Electric Association, Inc. Inside Passage Electric Cooperative, Inc. AVEC Chugach Electric Association, Inc. Matanuska Electric Association, Inc. Hughes Light & Power AVEC Alaska Power Company BC Hydro Igiugig Electric Company I-N-N Electric Coop Page 17 of 22 0.500 0.523 0.598 0.648 0.584 0.331 0.168 0.520 0.168 0.168 0.536 0.168 0.198 0.563 0.620 0.198 0.700 0.663 0.732 0.198 0.428 0.212 0.201 0.168 0.609 0.197 0.681 0.198 0.422 0.611 0.176 0.169 0.710 0.647 0.197 0.087 0.803 0.513 6.25 6.54 7.48 8.10 7.31 4.14 2.10 6.50 2.10 2.10 6.70 2.10 2.48 7.04 7.74 2.48 8.75 8.29 9.15 2.48 5.36 2.65 2.51 2.10 7.61 2.46 8.51 2.47 5.27 7.64 2.20 2.12 8.88 8.09 2.46 1.09 10.00 6.42 1/5/20110 Juneau, City & Borough of Kachemak (HEA 1) Kake Kaktovik Kalifornsky (HEA 1) Kaltag Karluk Kasaan Kasigluk Kasilof (HEA 1) Kenai (HEA 1) Kenny Lake Ketchikan Kiana King Cove King Salmon Kipnuk Kivalina Klawock Klukwan Knik-Fairview Kobuk Kodiak Kodiak Station Kokhanok Koliganek Kongiganak Kotlik Kotzebue Koyuk Koyukuk Kwethluk Kwigillingok Larsen Bay Levelock Lime Village Lower Kalskag Manley Hot Springs Manokotak Marshall McGrath McKinley Park RE-Fund Round-4 | Evaluation Guidelines Alaska Electric Light & Power Homer Electric Association, Inc. Inside Passage Electric Cooperative, Inc. North Slope Borough Homer Electric Association, Inc. AVEC Alutiiq Power Company Alaska Power Company AVEC Homer Electric Association, Inc. Homer Electric Association, Inc. Copper Valley Electric Assn. Ketchikan Public Utilities AVEC City of King Cove Naknek Electric Assn Kipnuk Light Plant AVEC Alaska Power Company Inside Passage Electric Cooperative, Inc. Matanuska Electric Association, Inc. Kobuk Valley Elect Coop Kodiak Electric Association Kodiak Electric Association Kokhanok Village Council New Koliganek Village Council Puvurnag Power Company AVEC Kotzebue Electric Assn AVEC City of Koyukuk Kwethluk Inc Kwig Power Company Larsen Bay Utility Company Levelock Electric Coop Lime Village Traditional Council AVEC Manley Utility Company, Inc. Manokotak Power Company AVEC McGrath Light & Power Company Golden Valley Electric Association, Page 18 of 22 0.111 0.198 0.422 0.150 0.198 0.630 0.600 0.197 0.526 0.198 0.198 0.198 0.096 0.687 0.240 0.416 0.653 0.725 0.197 0.422 0.169 0.870 0.153 0.153 0.900 0.500 0.550 0.592 0.464 0.631 0.450 0.520 0.500 0.440 0.700 1.170 0.597 0.998 0.450 0.625 0.608 0.168 1.39 2.47 5.27 1.88 2.47 7.87 7.50 2.46 6.57 2.47 2.47 2.48 1.20 8.59 3.00 5.20 8.16 9.06 2.46 5.27 2.12 10.00 1.91 1.91 10.00 6.25 6.88 7.40 5.81 7.89 5.63 6.50 6.25 5.50 8.75 10.00 7.46 10.00 5.63 7.81 7.60 2.10 1/5/20110 Mekoryuk Mendeltna Mentasta Metlakatla Minto Moose Pass Mountain Village Naknek Nanwalek (HEA 2) Napakiak Napaskiak Naukati Bay Nelchina Nelson Lagoon Nenana New Stuyahok Newhalen Newtok Nightmute Nikiski (HEA 1) Nikolai Nikolski Ninilchik (HEA 1) Noatak Nome Nondalton Noorvik North Pole Northway Northway Village Nuiqsut Nulato Nunam Iqua (Sheldon Point) Nunapitchuk Old Harbor Oscarville Ouzinkie Palmer Pedro Bay Pelican RE-Fund Round-4 | Evaluation Guidelines Inc. AVEC Copper Valley Electric Assn. Alaska Power Company Metlakatla Power & Light AVEC Chugach Electric Association, Inc. AVEC Naknek Electric Assn Homer Electric Association, Inc. Napakiak Ircinraq Power Company Napaskiak Electric Utility Alaska Power Company Copper Valley Electric Assn. Nelson Lagoon Electric Coop Golden Valley Electric Association, Inc. AVEC I-N-N Electric Coop Ungusrag Power Company AVEC Homer Electric Association, Inc. Nikolai Light & Power Utility . Umnak Power Company Homer Electric Association, Inc. AVEC Nome Joint Utility Systems I-N-N Electric Coop AVEC Golden Valley Electric Association, Inc. Alaska Power Company Alaska Power Company North Slope Borough AVEC Nunam Iqua Electric Co. AVEC AVEC Bethel Utilities Corporation, Inc. City of Ouzinkie Matanuska Electric Association, Inc. Pedro Bay Village Council Kake Tribal Corporation Page 19 of 22 0.646 0.198 0.478 0.092 0.614 0.176 0.606 0.416 0.201 1.080 0.600 0.370 0.198 0.740 0.168 0.630 0.513 0.800 0.531 0.198 0.804 0.600 0.198 0.726 0.368 0.513 0.714 0.168 0.424 0.424 0.150 0.631 0.530 0.526 0.624 0.537 0.365 0.169 0.910 0.434 8.08 2.48 5.98 1.15 7.68 2.20 7.57 5.20 2.51 10.00 7.50 4.63 2.48 9.25 2.10 7.87 6.42 10.00 6.64 2.47 10.00 7.50 2.47 9.08 4.60 6.42 8.92 2.10 5.30 5.30 1.88 7.89 6.63 6.57 7.80 6.71 4.56 2.12 10.00 5.43 1/5/20110 Perryville Petersburg Pilot Point Pilot Station Pitkas Point Platinum Point Hope Point Lay Port Alsworth Port Graham (HEA 2) Port Heiden (Meshik) Port Lions Quinhagak Red Devil Ruby Russian Mission Saint Mary's Saint Michael Saint Paul Salamatof (HEA 1) Sand Point Savoonga Saxman Scammon Bay Selawik Seldovia (HEA 2) Seward Shageluk Shaktoolik Shishmaref Shungnak Silver Springs Sitka (Mt. Edgecumbe) Skagway Slana Sleetmute Soldotna (HEA 1) South Naknek Stebbins Sterling (HEA 1) Stevens Village Stony River RE-Fund Round-4 | Evaluation Guidelines Native Village of Perryville Petersburg Municipal Power & Light Pilot Point Electrical Utility AVEC AVEC City of Platinum North Slope Borough North Slope Borough Tanalian Electric Coop Homer Electric Association, Inc. Port Heiden Utilities Kodiak Electric Association AVEC Middle Kuskokwim Electric Cooperative, Inc. City of Ruby AVEC AVEC AVEC St. Paul Municipal Electric Utility Homer Electric Association, Inc. TDX Sand Point Generating, Inc. AVEC Ketchikan Public Utilities AVEC AVEC Homer Electric Association, Inc. Seward Electric System AVEC AVEC AVEC AVEC Copper Valley Electric Assn. Sitka Electric Department Alaska Power Company Alaska Power Company Middle Kuskokwim Electric Cooperative, Inc. Homer Electric Association, Inc. Naknek Electric Assn AVEC Homer Electric Association, Inc. Stevens Village Energy Systems Middle Kuskokwim Electric Page 20 of 22 0.600 0.135 0.500 0.632 0.594 0.500 0.150 0.150 0.638 0.201 0.570 0.153 0.668 0.987 0.980 0.637 0.594 0.632 0.460 0.198 0.521 0.614 0.096 0.621 0.655 0.201 0.126 0.769 0.602 0.568 0.732 0.198 0.092 0.212 0.522 0.987 0.198 0.416 0.609 0.198 1.070 0.987 7.50 1.68 6.25 7.90 7.43 6.25 1.88 1.88 7.97 2.51 7.13 1.91 8.36 10.00 10.00 7.97 7.43 7.90 5.75 2.47 6.51 7.67 1.20 7.77 8.18 2.51 1.58 9.61 7.53 7.10 9.15 2.48 1.15 2.65 6.52 10.00 2.47 5.20 7.61 2.47 10.00 10.00 1/5/20110 Sutton-Alpine Takotna Talkeetna Tanacross Tanana PCE Tatitlek PCE Tazlina Teller Tenakee Springs Tetlin Thorne Bay Togiak (Twin Hills) Tok Toksook Bay Tolsona Tonsina Tuluksak Tuntutuliak Tununak Twin Hills Tyonek Unalakleet Unalaska (Dutch Harbor) Upper Kalskag Valdez Venetie Wainwright Wales Wasilla Whale Pass White Mountain Whittier Willow Women’s Bay Wrangell Yakutat RE-Fund Round-4 | Evaluation Guidelines Cooperative, Inc. Matanuska Electric Association, Inc. Takotna Community Assoc. Utilities Matanuska Electric Association, Inc. Alaska Power Company Tanana Power Company, Inc. Tatitlek Electric Utility Copper Valley Electric Assn. AVEC City of Tenakee Springs Alaska Power Company Alaska Power Company AVEC Alaska Power Company AVEC Copper Valley Electric Assn. Copper Valley Electric Assn. Tuluksak Traditional Power Utility Tuntutuliak Community Service Assoc AVEC Twin Hills Village Council Chugach Electric Association, Inc. Matanuska Electric Association, Inc. Unalaska Electric Utility AVEC Copper Valley Electric Assn. Venetie Village Electric North Slope Borough AVEC Matanuska Electric Association, Inc. Alaska Power Company White Mountain Utilities Chugach Electric Association, Inc. Matanuska Electric Association, Inc. Kodiak Electric Association Wrangell Municipal Light & Power Yakutat Power Page 21 of 22 0.169 1.250 0.169 0.531 0.664 0.760 0.198 0.715 0.295 0.197 0.594 0.295 0.531 0.600 0.198 0.198 0.650 0.531 0.550 0.492 0.176 0.264 0.597 0.597 0.198 0.750 0.150 0.648 0.169 0.435 1.080 0.176 0.169 0.153 0.132 0.347 2.12 10.00 2.12 6.64 8.30 9.50 2.48 8.94 3.69 2.46 7.42 3.69 6.64 7.50 2.48 2.48 8.13 6.64 6.88 6.15 2.20 3.30 7.46 7.46 2.48 9.38 1.88 8.10 2.12 5.44 10.00 2.20 2.12 1.91 1.66 4.34 1/5/20110 Alaska Renewable Energy Fund Ranking and Funding Allocation Round 4 Preliminary - 1/5/2011 IE NAKA Project Bene/Cost s Stage 3 jiew Scores (max Cost and Request Re mendation Development Phase 1. Tech & 4 State- Total Cost of 2. Econ Readi- 5. 6. wide Permitting Project | Stage 2 Appl Energy | Match Feas ness | Benefit | Local Total Rank Reconn/ /Final Energy Region ID Project Name Applicant Applicant Type Type | Score |AEAB/C| B/C 25 (20) (20) (10) 15) | Supt (5) 100) 74) | Proj Cost Type Funding |Cumulative | Feasibility | Design | Construct Southeast 687 |Hoonah Heat Recovery Project Inside Passage Electric Cooperative, Inc. Utility Heat Recovery} 89.33 3.55 482 13.19 17.00 17.87 8.00 12.50 4.00 76.55 1 1,005,000) Full 475,000) 475,000) 475,000) [Bering Straits 654 |Pilgrim Hot Springs Geothermal Resource Assessment ‘University of Alaska Fairbanks INE/ACEP_ |Governmt Entity Geothermal 86.67 1.91 1.87 11.50 18,00 17.33 5.67 13.75 5.00 3.83 75.08 2 3,330,467 Full 1,330,467 1,805,467, 1,330,467) [Northwest Arctic 668 |Upper Kobuk River Biomass ‘Northwest Inupiat Housing Authority |Governmt Entity Biomass 74.67 3.01 4.23 24.97 9.00 14.93 4.00 12.75 5.00 3.00 73.65 3 2,200,000 Full 250,000 2,055,467 | 250,000 [Southeast 636 | Thorne Bay School Wood Fired Boiler Project Southeast Island School District |Governmt Entity Biomass 76.00 1.34 2.26 18.56 13.00 15.20 8.00 9.38 4.00 3.50 71.64 4 580,179) Full 300,000 2,355,467 300,000) 680 _|Cold Bay Wind Energy Project G&K Electric Utility IPP Wind 82.33 1.89 1.00 20.13 8.00 16.47 4.00 12.38 4.00 4.00 68.97 5 2,937,068 158,625) 10,000] Partial 99,075| 2,454,542 99,075 Kodiak 653 | Terror Lake Unit 3 Hydroelectric Project Kodiak Electric Association, Inc. Utility Hydro 86.33 221 6.56 4.718 20.00 17.27 4.00 12.75 5.00 5.00 68.80 6 15,907,950) 7,000,000 7,459,790) Partial 3,751,840 6,206,382) 3,751,840) 1S 670-1 | Thayer Lake Hydropower Development Generation - Transmission ‘Kootznoowoo, Inc. IPP Hydro 75.00 177 1.65 13.19 13.00 15.00 6.00 12.13 5.00 4.33 68.65 7 30,402,216) 8,000,000, 1,956,000) Partial 1,060,500) 7,266,882 | 1,060,500 ‘ukon-Koyukuk/Upper Tanana | 665 |Upper Tanana Biomass CHP Project Alaska Power & Telephone Company Utility Biomass 81.33 3.10 450 16.59 11.00 16.27 3.67 13.50 5.00 233 68.36 8 18,000,000) 380,000 45,000) Full 380,000 7,646,882 380,000, Lower Yukon-Kuskokwim 604 | Bethel Renewable Energy Project TOX Power, Inc. IPP Wind 77.00 226 3.25 16.78 14.00 15.40 3.67 11.75 2.00 467 68.26 9 4,660,750) 3,961,638) 699,113) 213,690) 7,860,572 213,690) Railbelt 675 | Battle Creek Diversion Project Chugach Electric Association, Inc. Utility: Hydro 90.33 1.94 1.94 6.19 18.00 18.07 6.00 11.88 3.00 5.00 68.13 10 34,530,000 500,000 500,000 Full 500,000) 8,360,572) 500,000 Kodiak 644 |Old Harbor Hydroelectric \Alaska Village Electric Cooperative, Inc. Utility Hydro 79.67 1.52 1.47 19.50 8.00 15.93 4.00 10.50 4.00 483 66.77 "1 4,100,000 237,500) 12,500) Full 237,500) 8,598,072 / 237,500) Copper River/Chugach 618 |CVEA Silver Lake Feasibility Copper Valley Electric Association, Inc. Utility: Hydro 81.67 3.53 2.86 10.34 16.00 16.33 6.00 11.88 3.00 2.50 66.05 12 89,560,000 637,500 212,500 Full 637,500 9,235,572 637,500 [Bristol Bay 686 | Port Heiden Wind Turbine Project Lake & Peninsula Borough Local Governmt Wind 61.67 141 3.94 17.81 14,00 12.33 6.00 8.25 3.00 2.33 63.73 13 2,123,536} 1,700,000 448,536 Partial 250,000) 9,485,572 250,000 Railbelt 616 |GVEA Eva Creek Wind Turbine Purchase Golden Valley Electric Association Utility Wind 78.83 1.25 1.60 5.25 20.00 15.77 8.00 8.00 2.00 487 63.68 14 93,300,000) 1,463,200) 36,329,400, Full 1,463,200) 10,948,772 1,463,200) [Southeast 672 |Snettisham Transmission Line Avalanche Mitigation \Alaska Electric Light & Power Company Utility ‘Transmission 89.67 2.56 3.14 3.47 14.00 17.93 6.00 12.00 5,00 487 63.07 15 4,019,600) 3,215,680) 803,920) Partial 2,000,000, 12,948,772) 268,000) 1,732,000) Southeast 688 | Pelican Hydroelectric Upgrade Project City of Pelican Local Governmt Hydro: 66.67 1.42 3.50 13.56 13.00 13.33 8.00 9.38 3.00 2.33 62.60 16 5,520,836) 1,896,836 3,624,000) Full 1,896,836) 14,845,608 | 1,896,836) So 695 | Indian River Hydroelectric Project City of Tenakee Springs Electric Department Utility Local Governmt | Hydro. 80.67 1.84 2.01 9.22 11.00 16.13 6.00 12.00 2.00 5.00 61.35 17 2,711,000) 203,000) 26,000) Full 203,000} 15,048,608. 203,000 (ukon-Koyukuk/Upper Tanana | 658 | Organic Rankine Cycle Field Testing University of Alaska Fairbanks ACEP Governmt Entity Heat Recovery) 77.17 221 2.00 17.59 2.00 15.43 5.87 12.88 4.00 3.67 61.24 18 (472,787 Full 472,787) _ 15,521,395, 472,787 8 Bay 681 |Lake & Peninsula Wood Boilers ‘Lake & Peninsula Borough Local Governmt Biomass 34.00 0.90 0.80 22.66 16.00 6.80 6.00 2.25 5.00 2.33 61.04 19 369,900 123,300) Full 369,900) 15,891,295 369,900) |Copper River/Chugach 682 |Fivemile Creek Hydroelectric Project ‘Chitina Electric, Inc. Utility Hydro 78.67 1.37 1.18 16.56 9.00 15.73 6.00 7.50 2.00 4.17 60.96 20 4,405,000 3,602,000) 803,000) Partial 277,000) 16,168,295, 277,000) b 652 | Mount Spurr Geothermal Project Ormat Nevada, Inc. IPP Geothermal 75.17 1,08 0.67 4.72 19.00 15.03 6.00 6.38 5.00 AAT 60.29 2 300,000,000 1,999,972 3,882,298, Full 1,999,972| 18,168,267 1,999,972} Lower Yukon-Kuskokwim 685 |Napaskiak Wind, Power and Heat Recovery City of Napaskiak Electric Utility Local Governmt Wind 7283 148 1.71 18.75 8.00 14.57 4.00 8.25 3.00 3.33 59.90 22 1,075,000 171,275) 9,550) Partial 61,225) 18,229,492 61,225 ower Yukon-Kuskokwim 645 | St. Mary's/Pitka's Point Wind Construction [Alaska Village Electric Cooperative Utility Wind 64.50 0.95 1.07 18.56 12.00 12.90 4.00 2.00 5.00 4.33 58.80 23 4,500,000) 4,000,000 500,000) Partial 275,554) 18,505,046) 60,000 215,554 |Yukon-Koyukuk/Upper Tanana | 608 |Renewable Energy Feasibility Study Louden Tribal Council Local Governmt Biomass 74.67 297 3.27 17.59 0.00 14,93 4.33 14.25 4.00 3.50 58.61 24 11,000,000) 100,000 49,300) Full 100,000: 18,605,046 100,000 Railbelt 615 |CEA Transmission Line to Renewable Energy Resources Chugach Electric Association, Inc. Utility Transmission 88.33 10.21 10.74 4.72 9.00 17.67 4.00 14.13 5.00 4.00 58.51 25 61,780,000) 1,700,000) 80,000) Partial 600,000 19,205,046 | 600,000, ‘ukon-Koyukuk/Upper Tanana | 637 | Feasibility Assessments for Wood Heating in Interior AK Communities _| Interior Regional Housing Authority |Governmt Entity Biomass 81.00 1.42 1.12 21.66 0.00 16.20 4.00 7.50 5.00 3.67 58.02 26 154,477) Full 154,477 19,359,523) 184,477, Lower Yukon-Kuskokwim 607 |Lime Village Photovoltaic System Retrofit ‘Lime Village Traditional Council |Governmt Entity Solar 46.33 0.82 1.82 25.00 7.00 9.27 8.00 1.38 4.00 3.33 57.98 27 72,000) 69,000) 3,000) 25,000! 19,384,523) 25,000, [Southeast 605 | Biomass Fuel Dryer Project City of Craig, Alaska Local Governmt Biomass 66.00 1.04 433 6.16 18.00 13.20 9.00 3.38 4.00 417 57.90 28 600,000 350,000 250,000) Full 350,000 19,734,523) 350,000) b 693 | Fourth of July Creek Hydroelectric Project Independence Power, LLC IPP Hydro 75.33 2.14 2.25 3.94 15.00 15.07 6.00 11.75 3.00 267 $7.42 29 16,700,000) 136,500) 61,500) Full 136,500) 19,871,023 136,500 Northwest Arctic 667 | Kotzebue Paper & Wood Waste to Energy City of Kotzebue Local Governmt Other 67.83 149 1.49 14.50 10.00 13.57 0.00 10.13 5.00 3.67 56.86 3% 2,500,000) 85,000) 9,250) Full 85,000 19,956,023) 85,000, Lower Yukon-Kuskokwim 673 |Atmautluak Wind Renewable Energy Village of Atmautiuak Utility Governmt Entity | Wind 57.50 1.00 1.40 24.19 7.00 11.50 5.00 3.75 2.00 3.33 56.77 un 1,700,000) 225,000) 25,000) Partial 100,000) _ 20,056,023 100,000 [Bering Straits 648 | Stebbins Wind Feasibility ‘Alaska Village Electric Cooperative, Inc. Utility Wind 64.17 0.89 0.97 19.03 8.00 12.83 487 2.63 5.00 4.50 56.66 32 4,000,000 137,750 7,250) Full 137,750| 20,193,773 137,750 [Southeast 692 | Elfin Cove Hydroelectric Project |Community of Elfin Cove Utility Commission Utility Hydro 52.17 1.16 1.47 16.34 11.00 10.43 6.00 4.88 5.00 3.00 56.65 33 3,100,000 347,000 48,000) Full 347,000 20,540,773 347,000 |Southeast 620 |Whitman Lake Project City of Ketchikan dba Ketchikan Public Utilities Utility Local Governmt | Hydro. 68.50 3.30 3.00 20.00 13.70 7.67 2.25 5.00 5.00 56.62 uM 19,150,000) 2,000,000 14,500,000) Partial 700,000} 21,240,773 700,000) |Lower Yukon - Kuskokwim 639 |Eek Wind Feasibility |Alaska Village Electric Cooperative, Inc, Utility Wind 57.00 0.79 0.93 21.94 8.00 11.40 5.00 0.75 5.00 4.17 56.25 35 750,000) 142,500) 7,500) Full 142,500) 21,383,273, 142,500 j|Lower Yukon-Kuskokwim 664 | Kwethluk Wind Feasibility Organized Village of Kwethluk Governmt Entity Wind 62.67 4.41 1.15 16.25 11.00 12.53 4.00 4.88 4.00 3.50 56.16 6 1,466,813) 145,000) 16,000 Full 145,000) 21,528,273 145,000 [Southeast 705 | Japonski Island Boathouse Heat Pump \City and Borough of Sitka ‘Local Governmt Geothermal 73.00 1.52 2.88 13.00 14.60 4.00 10.00 5.00 5.00 54.48 7 165,000 125,000) 40,000 Full 125,000) _ 21,653,273 25,000) 100,000} Lower Yukon-Kuskokwim 643 | Marshall Wind Feasibility Alaska Village Electric Cooperative, Inc. Utility Wind 60.00 0.74 0.85 19.53 8.00 12.00 4.00 1.13 5.00 4.50 54.16 Be 2,000,000) 111,150) 5,850) Full 111,150) 21,764,423 111,150) bi 679 | Nelson Lagoon Wind Energy Project Nelson Lagoon Electrical Cooperative Utility Wind 55.33 0.89 0.96 23.13 8.00 11,07 4.00 0.38 4.00 3.33 53.90 30 1,815,480 158,625) 10,000 Partial 99,075) 21,863,498 | 99,075, North Slope 609 | Atqasuk Transmission Line North Slope Borough Local Governmt Other 73.33 233 3.57 469 11.00 14.87 5.00 12.00 3.00 3.17 53.52 40 14,000,000) 210,000) 21,000 Full 210,000) —_ 22,073,498 210,000 ukon-Koyukuk/Upper Tanana | 641 |Kaltag Solar Construction \Alaska Village Electric Cooperative, Inc. Utility Solar 60.33 0.67 0.56 19.69 10.00 12.07 2.00 0.75 4.00 487 53.17 a 100,000) 90,000) 10,000) Full 90,000| 22,163,498 | 90,000) Lower Yukon-Kuskokwim 646 |Scammon Bay Wind Feasibility ‘Alaska Village Electric Cooperative, Inc. Utility Wind 63.83 0.91 0.99 19.41 8.00 12.77 2.00 2.25 4.00 4.50 52.92 42 2,000,000) 142,500 7,500 Full 142,500) 22,305,998 142,500 Railbelt 674 | Stetson Creek Diversion/Cooper Lake Dam Facilities (Chugach Electric Association, Inc. Utility Hydro: 57.17 0.29 0.29 472 20.00 11.43 6.00 1.13 4.00 5.00 52.28 43 23,900,000) 2,000,000) 21,900,000) Partial 576,080| 22,882,078 30,000) 546,080 Railbelt 635 |Grant Lake Hydroelectric Facility ‘Kenai Hydro LLC IPP Hydro: 62.83 1.40 1.32 5.50 14.00 12.57 6.00 7.13 2.00 5.00 52.19 “4 27,160,000 1,500,000) 375,000) Partial 1,184,000} 24,066,078 1,184,000) Northwest Arctic: 647 _|Selawik Hybrid Wind Diesel System Turbine Upgrade \Alaska Village Electric Cooperative, Inc. Utility Wind 49.00 0.52 0.87 20.47 10.00 9.80 3.33 0.50 3.00 4.33 51.44 45 2,500,000) 85,000! 8,500 Full 85,000) 24,151,078) 85,000) Southeast | 629 Reynolds Creek Hydroelectric Project Transmission Line Alaska Power Company Utility Transmission 46.83 1.09 0.84 10.03 14.00 | 9.37 6.00 5.00 2.00 5.00 51.40 46 3,000,000) 2,000,000) 400,000; Full 2,000,000| 26,151,078, 2,000,000) Railbett 657 |AVTEC Hydro Training Facility ‘Alaska Vocational Technical Center Governmt Entity Hydro 90.33 2.15 1.56 3.94 2.00 18.07 6.00 13.38 3.00 4.50 50.88 47 720,388 703,800 16,588] Partial 67,500} 26,218,578 67,500| Bering Straits 642. |Koyuk Wind Phase Il Feasibility ‘Alaska Village Electric Cooperative, Inc. Utility ‘Wind $7.33 0.67 0.73 19.72 8.00 11.47 2.00 1.13 4,00 4.50 50.81 48 2,000,000) 142,500) 7,500) Full 142,500] 26,361,078 142,500 lLower Yukon-Kuskokwim 650 |Chefornak Wind Feasibilitly City of Chefornak Local Governmt ‘Wind 50.00 0.53 0.62 20.31 9.00 10.00 2.00 0.38 5.00 4.00 50.69 49 4,198,905) 250,000) 15,000| Partial 136,750] 26,497,828 136,750 Bering Straits 640 | Elim Wind Feasibility Alaska Village Electric Cooperative, Inc. Utility ‘Wind 59.33 0.76 0.82 18.69 8.00 11.87 2.00 1.13 4.00 4.50 50.18 50 2,000,000) 142,500) 7,500] Full 142,500] 26,640,328 142,500 ‘Aleutians 621 |Akutan Geothermal Development Project City of Akutan Local Governmt ‘Geothermal 59.50 1.59 2.03 10.09 12.00 11.90 5.67 2.75 4.00 3.33 49.74 51 ‘45,000,000 2,695,000) 355,000] Full 2,695,000] 29,335,328 2,695,000 Lower Yukon-Kuskokwim 669 | Akiachak Wind Feasibility & Conceptual Design Akiachak Native Community/Akiachak Ltd. Utility Governmt Entity | Wind 55.33 0.83 083 19.69 8.00 11.07 4.00 0.38 2.00 4.00 49.13 52 4,250,000 110,000: 15,000 Full 110,000) 29,445,328) 110,000 Bristol Bay 684 |New Koliganek Wind & Heat Recovery Feasibility Study New Koliganek Village Council |Governmt Entity Wind 53.17 0.94 0.96 15.63 8.00 10.63 6.00 1.50 3.00 3.17 47.93 53 662,050 105,050) 7,000) Full 105,050) 29,550,378) 105,050 Railbelt 660 |Cook Inlet TidGen Project ORPC Alaska, LLC IPP (Other 37.83 0.01 0.18 472 20.00 7.57 6.00 1.50 5.00 2.00 46.79 54 8,459,989 2,000,000 6,050,538 Full 2,000,000] 31,550,378 2,000,000 |Southeast 627 |Connelly Lake Hydroelectric Project [Alaska Power Company Utility Hydro 50.67 0.81 2.41 6.63 14.00 10.13 6.00 1.38 5.00 3.50 46.63 55 33,300,000) 1,040,000} 260,000 468,000] 32,018,378 468,000 ‘Aleutians 678 |False Pass Wind Energy Project City of False Pass Electric Utility Utility Local Governmt [Wind 52.67 0.75 0.60 16.25 8.00 10.53 4.00 0.63 4.00 2.50 45.91 56 1,594,320 128,625 10,000) 69,075] 32,087,453 69,075 [Copper River/Chugach 622 _|Cordova Community Biomass Feasibility Study Native Village of Eyak Local Governmt Biomass 56.67 0.00 10.34 7.00 11.33 4.00 2.63 5.00 447 44.47 57 1,800,000 245,065 3,000 75,000] 32,162,453) 75,000 Railbelt 690 [Hunter Creek Hydroelectric Project Eklutna, Inc. IPP Hydro 58.17 1.47 2.05 5.28 13.00 11.63 0.00 8.25 2.00 247 42.33 58 25,000,000 84,000 16,000) 84,000] 32,246,453) 84,000 Railbelt 689 | Port Graham Biomass Waste Heat Demo Project Port Graham Village Council Local Governmt Biomass 42.50 0.30 0.38 6.28 14.00 8.50 4.00 1.38 4.00 3.83 41.99 59 845,805 697,475) 148,330 75,000| 32,321,453) 75,000 Copper River/Chugach 649 | Kenny Lake School Wood Fired Boiler ‘Copper River School District Local Governmt Biomass 69.50 0.91 1.20 6.19 2.00 13.90 10.00 3.38 0.00 4.17 39.63 60 565,485) 565,485 Full 565,485) 32,886,938 565,485) Southeast 630 |Schubee Lake Hydroelectric Project ‘Alaska Power Company Utility Hydro 51.33 0.25 1.64 6.63 13.00 10.27 2.00 0.38 4.00 3.00 39.27 61 40,200,000 160,000 40,000| Partial 80,000] 32,966,938 80,000 North Slope 613 | Wainwright Wind Turbine Design North Slope Borough Utility Local Governmt |Wind 53.33 0.78 0.88 469 11.00 10.67 4.00 0.38 4.00 4.00 38.73 62 4,433,000 400,000) 40,000] Partial 298,000| 33,264,938 298,000 Railbelt 676 _|Eska Creek Hydroelectric Project Bering Pacific Engineering IPP Hydro 52.67 1.34 1.03 5.28 12.00 10.53 0.00 6.75 2.00 1.83 38.40 63 5,800,000 37,000 7,400) Full 37,000 33,301,938 37,000 North Slope 610 |Kaktovik Wind Diesel North Slope Borough Utility Local Governmt |Wind 57.00 0.67 0.78 469 10.00 11.40 4.00 0.75 3.00 4.50 38.34 64 4,565,200 132,000) 13,200 Full 132,000] 33,433,938) 132,000 North Slope 611. |Point Hope Wind Turbine Design North Slope Borough Utility Local Governmt |Wind 54.67 0.75 0.84 4.69 11.00 10.93 4.00 0.38 2.00 4.00 37.00 65 4,433,000 400,000 40,000} Partial 298,000] 33,731,938) 298,000) North Slope 612 |Point Lay Wind Generation Design North Slope Borough Utility Local Governmt |Wind 53.33 0.60 0.83 4.69 11.00 10.67 4.00 0.38 2.00 4.00 36.73 66 4,433,000 400,000) 40,000] Partial 298,000 298,000 |Southeast 656 |Metlakatla-Ketchikan Intertie Metlakatla Indian Community |Governmt Entity Transmission | 41.67 0.13 3.60 2.88 14.00 8.33 4.00 0.38 2.00 3.83 35.42 67 12,725,200] 9,405,200 3,320,000| Partial 1,180,000) E 750,000 430,000] [Southeast 625 | Excursion Inlet Hydro Project Phases | and Il Haines Borough Governmt Entity Hydro 37.67 0.05 1.38 6.63 7.00 7.53 1.67 1.00 5.00 2.83 31.66 68 15,500,000) 317,130 10,000] Partial 93,593 93,593 Railbelt 606 | Jack River Hydro Project Native Village of Cantwell Local Governmt Hydro 36.00 5.25 8.00 7.20 2.00 0.63 5.00 2.50 30.58 69 200,000) 190,000] 10,000] Partial 30,000 30,000 |Southeast 624 | Wrangell Electric Vehicle Feasibility Study City & Borough of Wrangell Local Governmt (Other 47.00 0.39 0.27 4.13 10.00 9.40 0.67 1.00 2.00 3.33 30.53 70 125,000 112,500] 12,500] Partial 25,000 25,000 |Southeast 707 |Sitka Renewable Energy Feasibility for Centennial Hall & Library City & Borough of Sitka Local Governmt Geothermal 51.67 0.76 288 12.00 10.33 0.00 0.75 0.00 4.00 29.96 1 39,000 30,000 9,000 Full 30,000 30,000 |Southeast 706 |Sitka Renewable Energy Feasibility for Wastewater Treatment Plant _|City & Borough of Sitka Local Governmt Geothermal 50.33 0.80 0.00 288 12.00 10.07 0.00 0.75 0.00 4.00 29.69 72 26,000 20,000 6,000) Full 20,000 20,000 [Southeast 632 | Reconnaissance Study of Tenakee Inlet Geothermal Resource Inside Passage Electric Cooperative Utility Geothermal 34.00 0.32 0.56 12.00 0.00 6.80 1.00 1.50 4.00 2.50 27.80 73 27,000,000) 2,579,200 J Partial 599,200 599,200 [Southeast 655 | Triangle Lake Hydroelectric Project ‘Metiakatla Indian Community |Governmt Entity Hydro 49.33 0.13 3.60 2.88 0.00 987 6.00 038 2.00 450 25.62 4 18,530,700) 500,000 Full 500,000 500,000 [SubTotal 1,093,700,924 77,932,412 _ 108,349,113 36,507,731 9,887,364) 8,396,134) 18,224,233 R4 RankedAll $36.5M Page 1 of 2 Alaska Renewable Energy Fund Ranking and Funding Allocation Round 4 Preliminary - 1/5/2011 Cost and Requi Grant Project Cost | Requested 14,500,000 4,000,000) 10,200,000] 2,000,000 175,000,000) 1,375,000) 142,000 142,000 3,795,000! 3,045,000 36,016,000) 1,021,287, 4,000,000! 250,050) 226,000,000) 2,000,000 149,709) 137,209) 4,560,000] 754,651 198,000) 158,400) ih Project Name Applicant ‘Yerrick Creek Hydroelectric Project ‘Alaska Power Company Kenai Winds Expansion Kenai Winds LLC ‘Southern Railbelt Small Hydro Reconn. Study Polarconsult Alaska, Inc. ‘Akiak Integrated Renewable Energy Projects City of Akiak AVCP Housing Wind Turbine Project AVCP Regional Housing Authority Waste Energy Powered Absorption Refrigeration Unit Valdez Fisheries Development Assn. Inc. ‘Adak Renewable Diesel Project TDX Adak Generating, LLC ‘Takatz Lake Hydroelectric Feasibility Analysis (City & Borough of Sitka NWAB School Alternate Energy Solar Awareness Project ‘Northwest Arctic Borough ‘Tok School Biomass Heating Project ‘Alaska Gateway School District Port St. Nick Fish Enhancement Hydropower City of Coffman Cove ‘Susitna Valley High School Wood Heat Matanuska Susitna Borough 755,500 750,000) Carlson Creek Hydroelectric Project ‘Alaska Power Company 6,300,000) 540,000) Nushagak Community Wind Power Project [Nushagak Electric & Telephone Cooperative (NETC) ‘Wind r r 3,554,880) 3,199,400] Nikiski Combined Cycle Conversion (NCCC) Alaska Electric & Energy Cooperative 85,000,000) 2,000,000 Yukon River Debris Mitigation Project Alaska Power & Telephone Company Other 1,190,876) 1,190,876 ‘Southwest Alaska Regional Geothermal Energy Project Naknek Electric Association, Inc. il . E 160,830,500 4,000,000) ‘Kachemak Bay Tidal Power \City of Homer 6,452,000, 620,811 ‘Turnagain Arm Tidal Electrical Generation Project ‘Turnagain Tidal Energy Corporation 2,500,000,000 2,000,000 Gulkana Village Pellet Fuels Project Gulkana Village Council 1,054,000) 955,000, |lonia Renewable Energy Training Center Alaska Mental Health Trust Authority 274,623 241,623) ‘Akiak Hydro Study City of Akiak 350,000] ‘Cook Inlet Tidal Hydrokinetic Power Generation ‘Baker Hughes, Inc. 3,600,000) 400,000) |Glacier Fork Hydroelectric Project Glacier Fork Hydro, LLC 370,000,000, 210,000) ‘Merrill Field Landfill Gas Heating/Energy Project ‘Municipality of Anchorage 2,200,000 2,000,000) Napakiak Wind Design & Construction Planning Napakiak Ircinraq Power Company 302,395) 282,395) Kongiganak Flywheel Energy Storage Puvurnaq Power Company 1,561,368) 1,395,231 High Penetration Wind Diesel Power and Heat Kipnuk Light Plant 4,624,041 3,424,041 Palmer Ice Arena Geothermal & Heat Recovery Improvements City of Palmer 1,344,695 1,094,695 Packers Creek Hydroelectric Project ‘Chignik Lagoon Power Utility 2,500,000 2,440,000) ‘Tuntutuliak Wind Energy Storage Tuntutuliak Community Services Assn., Inc. 708,162) Kwigillingok Wind Energy Storage Kwig Power Company 708, 162| Neck Lake Hydroelectric Project ‘Alaska Power Company 2,440,000 1,844,000 3,628,545,596 45,237,993 4,722,246,520 123,170,405, PPRPRRETTEEEE, i ; i j | j | Sia SESS \a EIS R4 RankedAll $36.5M Page 2 of 2 Alaska Renewable Energy Fund = Ranking and Funding Allocation Round 4 >A Sioa Preliminary - 1/5/2011 L__l— Project Bene/Cost “Stage 3 Review Scores (max) —— Cost and Request Recommendation Development Phase 1. Tech & 4. 6. State- Total Cost of 2. Econ | Readi- 5. Local |Sustain} wide Permitting Project |Stage 2} AEA | Appl |Energy| Match | Feas ness | Benefit} Supt | ability | Total | Rank Grant Reconn/ /Final Energy Region ID Project Name Applicant Applicant Type Type Score | B/C | B/C | (25) (20) (20) (10) (15) (5) (5) | (100)} (74) | Project Cost Requested | Match Offered pe Funding | Feasibility | Design Construct Cold Bay Wind Energy Project |G&K Electric Utility IPP 2,937,068) 158,625, 99,075 99,075, Nelson Lagoon Wind Energy Project Nelson Lagoon Electrical Cooperative Utility. 1,815,480) 158,625, 99,075 99,075, ‘Akutan Geothermal Development Project City of Akutan Local Governmt 45,000,000 2,695,000! 2,695,000: False Pass Wind Energy Project City of False Pass Electric Utility Utility Local Governmt 1,594,320 128,625 69,075, 69,075 Adak Renewable Diesel Project TDX Adak Generating, LLC Utility 4,000,000 250,050 55,346,868 3,390,925 2,962,225 267,225 Pilgrim Hot Springs Geothermal Resource Assessment University of Alaska Fairbanks INE/ACEP 3,330,467 | 1,330,467 | 2,000,000) 1,330,467 Bering Straits Stebbins Wind Feasibility ‘Alaska Village Electric Cooperative, Inc. 4,000,000, 137,750 7,250 137,750) Koyuk Wind Phase II Feasibility Alaska Village Electric Cooperative, Inc. 2,000,000) 142,500 7,500 142,500 Elim Wind Feasibility Alaska Village Electric Cooperative, Inc. 2,000,000 142,500) 7,500 142,500 Bering Straits Total 11,330,467 1,753,217 2,022,250 1,753,217| _ 1,753,217 686 | Port Heiden Wind Turbine Project Lake & Peninsula Borough Local Governmt Wind 61.67 | 1.41] 3.94 17.81 14.00 12.33 6.00 8.25 3.00 2.33 | 63.73 13 2,123,536 1,700,000 448,536) Partial 250,000: 250,000: 681 |Lake & Peninsula Wood Boilers Lake & Peninsula Borough Local Governmt Biomass 34.00 | 0.90) 0.80 22.66 16.00 6.80 6.00 2.25 5.00 2.33 | 61.04 19 493,200, 369,900) 123,300 Full 369,900: 369,900} Biistol Bay 684 |New Koliganek Wind & Heat Recovery Feasibility Study New Koliganek Village Council Governmt Entity Wind 53.17 | 0.94] 0.96| 15.63 8.00| 10.63 6.00 1.50 3.00 3.17| 47.93| 53 662,050 105,050) 7,000 Full 105,050) 105,050) 633 |Nushagak Community Wind Power Project Nushagak Electric & Telephone Cooperative (NETC) | Utility ‘Wind 0.80 | 0.99 3,554,889 3,199,400] 355,488] Not Recom 651 |Southwest Alaska Regional Geothermal Energy Project Naknek Electric Association, Inc. Utility Geothermal 0.99) 1.66 160,830,500 4,000,000] 5,624,000| Not Recom 702 |Packers Creek Hydroelectric Project ‘Chignik Lagoon Power Utility Utility Hydro 2,500,000 2,440,000| 60,000] Not Recom Bristol Bay Total 170,164,175 11,814,350 6,618,324: 724,950 105,050 250,000 369,900 618 |CVEA Silver Lake Feasibility Copper Valley Electric Association, Inc. ‘Utility Hydro. 81.67 | 3.53] 2.86 10.34 16.00 16.33 6.00 11.88 3.00 2.50 | 66.05 12 89,560,000 637,500 212,500, Full 637,500) 637,500: 682_|Fivemile Creek Hydroelectric Project ‘Chitina Electric, Inc. ‘Utility Hydro. 78.67 | 1.37) 1.18 16.56 9.00 15.73 6.00 7.50 2.00 4.17 | 60.96 20 4,405,000, 3,602,000, 803,000; Partial 277,000) 277,000, 622 |Cordova Community Biomass Feasibility Study Native Village of Eyak Local Govemmt Biomass 56.67 | 0.00 10.34 7.00| 11.33] 4.00 263 5.00 4.17 | 44.47| 57 1,800,000 245,065 3,000] _ Partial 75,000 75,000| Copper River/Chugach | 649 |Kenny Lake School Wood Fired Boiler Copper River School District Local Governmmt Biomass 69.50] 0.91| 1.20 6.19 2.00] 13.90] 10.00 3.38 0.00 4.17 | 39.63] 60 565,485 565,485 Full 565,485 565,485| 601 |Waste Energy Powered Absorption Refrigeration Unit Valdez Fisheries Development Assn., Inc. IPP Other 36,016,000 1,021,287 350,000] Not Recom 626 [Carlson Creek Hydroelectric Project ‘Alaska Power Company Utility Hydro 6,300,000 540,000 60,000| Not Recom 662 |Gulkana Village Pellet Fuels Project Gulkana Village Council ‘Governmt Entity Biomass 1,054,000 955,000 99,000] Not Recom Copper River/Chugach Total 139,700,485 7,566,337 | 4,527,500 1,554,985 712,500) 277,000 565,485 . 653 Hydro 15,907,950) Kodiak aa Hydro 4,100,000) Kodiak Total 20,007,950 604 | Bethel Renewable Energy Project TDX Power, Inc. IPP Wind 77.00 | 2.26} 3.25 16.78 14.00 15.40 3.67 11.75 2.00 4.67 | 68.26 9 4,660,750, 3,961,638) 699,113) Partial 213,690) 213,690 685 |Napaskiak Wind, Power and Heat Recovery City of Napaskiak Electric Utility Local Governmt Wind 72.83 | 1.48] 1.71 18.75 8.00 14.57 4.00 8.25 3.00 3.33 | 59.90| 22 1,075,000} 171,275 9,550) Partial 61,225 61,225, 645 |St. Mary's/Pitka's Point Wind Construction Alaska Village Electric Cooperative Utility Wind 64.50 | 0.95| 1.07 18.56 12.00 12.90 4.00 2.00 5.00 4.33 | 58.80/ 23 4,500,000) 4,000,000) 500,000; Partial 275,554 60,000, 215,554: 607 |Lime Village Photovoltaic System Retrofit Lime Village Traditional Council Governmt Entity ‘Solar 46.33 | 0.82/| 1.82 25.00 7.00 9.27 8.00 1.38 4,00 3.33 | 57.98] 27 72,000 69,000 3,000 Partial 25,000 25,000 673 |Atmautluak Wind Renewable Energy Village of Atmautiuak Utility Governmt Entity | Wind 57.50} 1.00| 1.40 24.19 7.00 11.50 5.00 3.75 2.00 3.33 | 56.77 31 1,700,000} 225,000; 25,000 Partial 100,000) 100,000; 639 | Eek Wind Feasibility Alaska Village Electric Cooperative, Inc. Utility Wind 57.00 | 0.79| 0.93 21.94 8.00 11.40 5.00 0.75 5.00 4.17 | 56.25 35 750,000} 142,500 7,500 Full 142,500, 142,500, 664 | Kwethluk Wind Feasibility Organized Village of Kwethluk Governmt Entity Wind 62.67 | 1.11} 1.15 16.25 11.00 12.53 4.00 4.88 4.00 3.50 | 56.16 3 1,466,813) 145,000, 16,000 | Full 145,000, 145,000, 643 |Marshall Wind Feasibility Alaska Village Electric Cooperative, Inc. Utility Wind 60.00 | 0.74] 0.85 19.53 8.00 12.00 4.00 1.13 5.00 4.50 | 54.16 38 2,000,000) 111,150) 5,850 Full 111,150) 111,150) 646 |Scammon Bay Wind Feasibility Alaska Village Electric Cooperative, Inc. Utility Wind 63.83 | 0.91| 0.99 19.41 8.00 12.77 2.00 2.25 4.00 4.50 | 52.92| 42 2,000,000) 142,500, 7,500) Full 142,500) 142,500, Lower Yukon-Kuskokwim | 650 |Chefornak Wind Feasibilitly City of Chefornak Local Governmt ‘Wind 50.00] 0.53| 062| 20.31 9.00] 10.00 2.00 0.38 5.00 4.00| 50.69| 49 4,198,905) 250,000] 15,000| _ Partial 136,750 136,750, 669 [Akiachak Wind Feasibility & Conceptual Design ‘Akiachak Native Community/Akiachak Ltd. Utility Governmt Entity |Wind 55.33 | 0.83| 083| 19.69 8.00| 11.07 4.00 0.38 2.00 4.00| 49.13| 52 4,250,000 110,000) 15,000 Full 110,000 110,000. 600 |AVCP Housing Wind Turbine Project AVCP Regional Housing Authority ‘Governmt Entity ‘Wind 0.61| 0.57 3,795,000) 3,045,000) 750,000| Not Recom 677 _|Akiak Hydro Study City of Akiak Local Governmt ‘Ocean/River 350,000 Not Recom 697 |Napakiak Wind Design & Construction Planning Napakiak Ircinraq Power Company Utility Wind 1.39 | 262 302,395) 282,395) 20,000) Not Recom 698. |Kongiganak Flywheel Energy Storage Puvurnag Power Company Utility Other | 0.55] 1.14 - 1,561,368 1,395,231 166,137| Not Recom 699 | Akiak Integrated Renewable Energy Projects City of Akiak Local Governmt Other 142,000 142,000) Not Pass S1 700 |High Penetration Wind Diesel Power and Heat Kipnuk Light Plant Utility ‘Wind 1.24| 1.12 4,624,041 3,424,041 1,200,000] Not Recom 703 |Tuntutuliak Wind Energy Storage Tuntutuliak Community Services Assn., Inc. Utility Other 1.02 | 1.42 708,162 3,200,000! Not Recom 704 |Kwigillingok Wind Energy Storage Kwig Power Company Utility Other 1.07 | 1.42 708,162 3,200,000] Not Recom Lower Yukon-Kuskokwim Total 37,098,272 19,383,054) 1,463,369) _ 1,222,815 240,554! |Atqasuk Transmission Line North Slope Borough Local Governmt ‘Wainwright Wind Turbine Design North Slope Borough Utility Local Governmt Kaktovik Wind Diesel North Slope Borough Utility Local Governmt Point Hope Wind Turbine Design North Slope Borough Utility Local Governmt Point Lay Wind Generation Design North Slope Borough Utility Local Governmt 668 |Upper Kobuk River Biomass Northwest Inupiat Housing Authority Governmt Entity Biomass 7467 | 3.01| 4.23 24.97 9.00 14.93 4.00 12.75 5.00 3.00 | 73.65 3 2,200,000 250,000) 20,000 Full 250,000 250,000 Northwest Arctic 667 | Kotzebue Paper & Wood Waste to Energy City of Kotzebue Local Governmt Other 67.83 | 1.49] 1.49 14,50 10.00 13.57, 0.00 10.13, 5.00 3.67 | 56.86) 30 2,500,000 85,000 9,250 Full 85,000 85,000 647 |Selawik Hybrid Wind Diesel System Turbine Upgrade Alaska Village Electric Cooperative, Inc. Utility Wind 49.00 | 0.52| 0.87 20.47 10.00 9.80 3.33 0.50 3.00 4.33 | 51.44| 45 2,500,000 85,000 8,500 Full 85,000) 85,000 614 |NWAB School Altermate Energy Solar Awareness Project Northwest Arctic Borough Local Governmt Solar 0.54] 0.44 149,709) 137,209 12,500| Not Recom Northwest Arctic Total 7,349,709 557,209 50,250 420,000 170,000 250,000 R4 RankedReg $36.5M Page 1 of 2 Alaska Renewable Energy Fund Ranking and Funding Allocation Round 4 Preliminary - 1/5/2011 Cost Cost and Request Recommendation = a i ENERGY AUTHORITY Development Phase Project Name Applicant Type Appl B/C Project Cost Match Offered Reconn/ Feasibility Permitting /Final Design Construct 675 [Battle Creek Diversion Project Chugach Electric Association, Inc. Utility Hydro 90.33| 1.94] 194] 619] 1800] 1807| 6.00] 11.88] 3.00] 5.00] 6813| 10 34,530,000 500,000! 500,000| Full 500,000! 500,000 616 |GVEA Eva Creek Wind Turbine Purchase Golden Valley Electric Association Utility Wind 78.83| 1.25| 1.60| 525] 20.00] 15.77| 800] 800| 200| 467| 6368| 14 93,300,000 1,463,200! 36,329,400) Full 1,463,200 1,463,200 652_|Mount Spurr Geothermal Project /Ormat Nevada, Inc. IPP (Geothermal 75.17| 1.08| 067] 4.72] 19.00| 15.03] 600| 638| 500] 417| 6029| 21 300,000,000} 1,999,972 3,882,298] Full 1,999,972 1,999,972 615_|CEA Transmission Line to Renewable Energy Resources ‘Chugach Electric Association, Inc. Utility Transmission | 88.33 | 10.21| 1074] 4.72] 9.00] 17.67| 400] 1413] 5.00| 4.00] 5851| 25 61,780,000 1,700,000] 80,000] Partial 600,000] 600,000) 693 [Fourth of July Creek Hydroelectric Project Independence Power, LLC IPP Hydro 75.33| 2.14| 225] 394] 1500] 1507| 6.00] 11.75| 300] 267| 57.42| 29 16,700,000) 136,500 61,500 Full 136,500 136,500 674 |Stetson Creek Diversion/Cooper Lake Dam Facilities ‘Chugach Electric Association, Inc. Utility Hydro 87.17| 029| 029] 472] 2000] 11.43| 600] 1.13] 400| 5.00/ 5228| 43 23,900,000 2,000,000) 21,900,000] Partial 576,080! 30,000 546,080) 635 [Grant Lake Hydroelectric Facility Kenai Hydro LLC IPP Hydro 6283| 140| 132] 550| 1400| 1257| 600] 7.13] 200] 5.00] 5219| 44 27,160,000 1,500,000] 375,000] _ Partial 1,184,000] 1,184,000 657 |AVTEC Hydro Training Facility Alaska Vocational Technical Center Governmt Entity Hydro 90.33] 2.15| 156] 394] 200] 1807/ 600| 1338| 300] 450| 5088| 47 720,388 703,800 16,588| Partial 67,500 67,500 660 [Cook Inlet TidGen Project ORPC Alaska, LLC IPP (Other 37.83] 0.01{ 018] 472] 2000] 7.57| 6.00| 1.50] 5.00] 200| 4679| 54 8,459,989 2,000,000) 6,050,538] Full 2,000,000 2,000,000] 690 Hunter Creek Hydroelectric Project Eklutna, Inc. IPP Hydro 68.17| 1.47| 205| 5§28| 1300| 1163/ 0.00] 825| 200| 217| 4233| 58 25,000,000 84,000 16,000 Full 84,000 84,000 689 |Port Graham Biomass Waste Heat Demo Project Port Graham Village Council Local Governmt Biomass 42.50| 0.30| 038] 628] 1400] 850/ 400| 1.38] 400] 383] 41.99] 59 845,805 697,475 148,330| Partial 75,000 75,000 Rial 676 |Eska Creek Hydroelectric Project Bering Pacific Engineering IPP Hydro §267| 1.34[ 1.03/ 528] 1200] 1053/ 0.00/ 675| 200] 1.83] 3840] 63 5,800,000 37,000 7,400 Full 37,000 37,000 606 | Jack River Hydro Project Native Village of Cantwell Local Govermt Hydro 36.00 5.25| 800] 7.20| 200] 063| 500/ 250] 30.58| 69 200,000 190,000 10,000] Partial 30,000 30,000 623 |Susitna Valley High School Wood Heat Matanuska Susitna Borough Local Governmt Biomass 0.75] 079 755,500 750,000 5,500| Not Recom 634 | Nikiski Combined Cycle Conversion (NCCC) Alaska Electric & Energy Cooperative Utility Heat Recovery 1.37 | 1.79 85,000,000 2,000,000) 500,000| Not Recom 659 |Kachemak Bay Tidal Power City of Homer Local Govemmt (Other 6,452,000 620,811 706,424] Not Recom 661 | Tumagain Arm Tidal Electrical Generation Project ‘Tumagain Tidal Energy Corporation IPP (Other 0.87 | 4.30 2,500,000,000 2,000,000) Not Recom 663 |lonia Renewable Energy Training Center Alaska Mental Health Trust Authority Governmt Entity Biomass 053] 0.43 274,623 241,623 33,000] Not Recom 666 _|Kenai Winds Expansion Kenai Winds LLC. IPP Wind 10,200,000 2,000,000) 8,000,000| Not Pass S1 683 | Cook Inlet Tidal Hydrokinetic Power Generation Baker Hughes, Inc. IPP Other 0.03 | 0.19 3,600,000 400,000 1,960,000] Not Recom 691 |Glacier Fork Hydroelectric Project Glacier Fork Hydro, LLC Utility Hydro 1.07 | 1.09 370,000,000 210,000 40,000| Not Recom 694 |Southern Railbelt Small Hydro Reconn. Study Polarconsult Alaska, Inc. IPP Hydro 175,000,000 1,375,000 80,000] Not Pass S1 696 |Merrill Field Landfill Gas Heating/Energy Project Municipality of Anchorage Local Governmt Other 0.22] 0.27 2,200,000] 2,000,000! 200,000] Not Recom 701 |Palmer Ice Arena Geothermal & Heat Recovery Improvements City of Palmer LocalGovermmt _ |Geothermal 1,344,695 1,094,695 250,000 Not Recom Railbelt Total 3,753,223,000 25,704,076 81,151,978 8,753,252) _2,601,500. 687 [Hoonah Heat Recovery Project Inside Passage Electric Cooperative, Inc. Utility 1 1,005,000 475,000] 530,000] Full 475,000) 636 _| Thome Bay School Wood Fired Boiler Project ‘Southeast Island School District Governmt Entity z z : ; ! r . 4 580,179) 300,000 60,000 Full 300,000 670-1 | Thayer Lake Hydropower Development Generation - Transmission _|Kootznoowoo, Inc. IPP Hydro 75.00| 1.77| 165| 1319] 1300] 1500] 600] 1213| 5.00] 4.33| 6865| 7 30,402,216 8,000,000) 1,956,000] Partial 1,060,500 1,060,500 672_|Snettisham Transmission Line Avalanche Mitigation Alaska Electric Light & Power Company Utility Transmission | 89.67| 256| 3.14| 347| 1400] 1793] 600] 1200| 5.00| 4.67| 63.07| 15 4,019,600 3,215,680) 803,920] Partial 2,000,000 268,000] _ 1,732,000] 688 |Pelican Hydroelectric Upgrade Project City of Pelican Local Governmt Hydro 6667| 1.42] 350| 1356| 1300] 1333| 800| 9238| 300] 233| 6260| 16 5,520,836| 1,896,836 3,624,000] Full 1,896,836 1,896,836 695 | Indian River Hydroelectric Project City of Tenakee Springs Electric Department Utility Local Governmt [Hydro 80.67| 1.84{ 2.01| 922] 11.00] 1613] 600] 1200] 200| 5.00| 61.35| 17 2,711,000 203,000! 26,000 Full 203,000) 203,000! 605 [Biomass Fuel Dryer Project City of Craig, Alaska Local Govermmt Biomass 66.00] 1.04] 433| 616] 1800] 1320| 900| 338] 400] 417| 5790| 28 600,000) 350,000 250,000] Full 350,000! 350,000] 692 Elfin Cove Hydroelectric Project Community of Elfin Cove Utility Commission Utility Hydro 2.17| 1.16| 147| 1634] 11.00] 1043] 600] 488] 5.00| 3.00| 5665| 33 3,100,000] 347,000 48,000] Full 347,000) 347,000) 620 [Whitman Lake Project City of Ketchikan dba Ketchikan Public Utilities Utility Local Governmt [Hydro 68.50 330| 3.00] 2000] 1370] 767| 225] 5.00| 5.00| 5662| 34 19,150,000) 2,000,000! 14,500,000| Partial 700,000! 700,000} 705 |Japonski Island Boathouse Heat Pump City and Borough of Sitka Local Governmt Geothermal 73.00 | 1.52 288| 13.00| 1460| 4.00| 10.00] 5.00| 5.00| 5448| 37 165,000 125,000 40,000] Full 125,000 25,000 100,000 629 |Reynolds Creek Hydroelectric Project Transmission Line Alaska Power Company Utility Transmission | 46.83| 1.09| 084] 1003] 1400] 937| 600] 5.00] 200] 5.00| 51.40| 46 3,000,000] 2,000,000) 400,000] Full 2,000,000! 2,000,000] Southeast 627 _|Connelly Lake Hydroelectric Project Alaska Power Company Utility Hydro 0.67| 0.81| 211| 663] 1400] 1013] 600] 1.38] 5.00| 3.50| 4663| 55 33,300,000 1,040,000 260,000| Partial 468,000) 468,000) 630 |Schubee Lake Hydroelectric Project Alaska Power Company Utility Hydro 51.33| 0.25| 164] 663] 1300] 1027| 200| 038| 4.00| 300| 3927| 61 40,200,000 160,000 40,000] Partial 80,000 80,000 656 |Metlakatla-Ketchikan Intertie Metlakatla Indian Community Governmt Entity Transmission | 41.67| 0.13| 360| 288] 1400| 833| 400] 0.38| 200] 383] 35.42| 67 12,725,200 9,405,200) 3,320,000] Partial 1,180,000 750,000 430,000] 625 _|Excursion Inlet Hydro Project Phases | and Il Haines Borough Governmt Entity Hydro 37.67| 0.05| 138/ 663| 7.00| 753| 167| 1.00] 500| 283] 31.66| 68 15,500,000 317,130 10,000] __ Partial 93,593 93,593 624 |Wrangell Electric Vehicle Feasibility Study City & Borough of Wrangell Local Governmt Other 47.00| 039| 027| 413] 1000] 940| o67| 1.00] 200| 3.33] 30.53| 70 125,000 112,500 12,500| Partial 25,000 25,000 707 |Sitka Renewable Energy Feasibility for Centennial Hall & Library City & Borough of Sitka Local Governmt Geothermal 51.67 | 0.76 288| 1200] 1033/ 0.00] 075| 0.00| 400| 299| 71 39,000 30,000 9,000) Full 30,000 30,000 706 |Sitka Renewable Energy Feasibility for Wastewater Treatment Plant _|City & Borough of Sitka Local Governmt Geothermal 50.33| 080] o00| 288] 1200] 1007| 0.00] 075| 0.00| 4.00| 2969| 72 26,000 20,000 6,000 Full 20,000 20,000 632_ |Reconnaissance Study of Tenakee Inlet Geothermal Resource Inside Passage Electric Cooperative Utility Geothermal 34.00] 032] 066] 1200] 0.00] 680| 1.00] 1.50| 400] 250| 27.80| 73 27,000,000 2,579,200 o| Partial 599,200 599,200] 655 | Triangle Lake Hydroelectric Project Metlakatla Indian Community Governmt Entity Hydro 49.33| 013| 360| 288| 000| 987| 600| 038/ 200/ 450| 2562| 74 18,530,700 500,000 Full 500,000 500,000] 603 | Takatz Lake Hydroelectric Feasibility Analysis City & Borough of Sitka Utility Local Governmt |Hydro 226,000,000 2,000,000 0| Not Recom 619 |Port St. Nick Fish Enhancement Hydropower City of Coffman Cove Local Governmt Hydro 198,000 158,400 39,600| Not Recom Neck Lake Hydroelectric Project ~__ [Alaska Power Company Utility Hydro 2,440,000) 1,844,000 596,000| Not Recom-W! [Southeast Total 446,337,731 37,078,946 26,531,020 12,453,129, _ 1,815,793, 665 [Upper Tanana Biomass CHP Project ‘Alaska Power & Telephone Company Utility ; 1627| 3.67] 13.50| 5.00] 233] 6836| 8 18,000,000) 380,000) 45,000| Full 380,000] 380,000 658 | Organic Rankine Cycle Field Testing University of Alaska Fairbanks ACEP Governmt Entity Heat Recovery| 77.17| 221| 2.00| 1759] 200| 1543| 567| 1288| 400| 367| 61.24| 18 472,787 472,787| Full 472,787 | 472,787 608 [Renewable Energy Feasibility Study Louden Tribal Council Local Governmt Biomass 7467| 297| 327| 1759] 0.00] 1493] 433] 1425| 400| 3.50| 5861| 24 11,000,000} 100,000 49,300] Full 100,000| 100,000) Yukon-Koyukuk/Upper [es7 Feasibility Assessments for Wood Heating in Interior AK Communities _ Interior Regional Housing Authority Governmt Entity Biomass 1.00] 1.12| 1.12] 2166| 0.00| 1620| 400| 750/ 5.00] 367| 58.02| 26 154,477 Full 154,477 154,477 Tanana 641 |Kaltag Solar Construction Alaska Village Electric Cooperative, Inc. Utility ‘Solar 60.33| 067| 056] 1969| 10.00| 1207| 200| 075| 400| 467| 53.17| 41 100,000 90,000 10,000] Full 90,000 90,000 617 | Tok School Biomass Heating Project Alaska Gateway School District Local Governmt Biomass 0.47 | 0.69 4,560,000 754,651 560,000| Not Recom 631 _|Yerrick Creek Hydroelectric Project Alaska Power Company Utility Hydro 14,500,000 4,000,000] 8,725,000| Not Pass S1 ‘Yukon River Debris Mitigation Project Alaska Power & Telephone Company 1,190,876 1,190,876 Not Recom 7,142,791 9,389,300) 1,197,264) _ 1,107,264. 90,000] R4 RankedReg $36.5M Page 2 of 2 4,722,246,520 123, 170,405] 145,141,762) 36,507,731] 9,887,364) 8,396,134]18,224,233] Alaska Renewable Energy Fund = ALASKA Regional Summary Round 4 Ranking heswarstudasinddostabstaid $36.5 million Allocation Preliminary 1/04/2011 Rounds 1-3 % of Rounds 1-3 Total Grant Funding ‘Aleutians 11,593,784 Bering Straits 11,997,448 Bristol Bay 7,431,915 Copper River/Chugach 14,057,970 Kodiak 4,973,160 Lower Yukon-Kuskokwim 24,064,078 North Slope 1,266,912 Northwest Arctic 22,117,405 Railbelt 19,193,454 Southeast 20,211,588 'Yukon-Koyukuk/Upper Tanana 12,128,901 Statewide 565,439 149,602,054 Recommendation Cost of Power Population Even Split Additional Average Allocation funding Allocation Grant cost power cost of power needed to per capita Energy Region Funding reach 50% % total basis Aleutians 2,962,225 : 4,505,837 (709,306) 1% 479,090 3,318,885 Bering Straits 1,753,217 X 4,456,992 475,279 1% 534,711 3,318,885 Bristol Bay 724,950 i 4,274,680 1,412,390 1% 365,077 3,318,885 Copper River/Chugach 1,554,985 : 2,227,543 (441,213) 1% 365,077 3,318,885 Kodiak 3,989,340 ; 1,530,723 (3,223,978)| 1% 365,077 3,318,885 Lower Yukon-Kuskokwim 1,463,369 ; 5,335,412 1,204,337 4% 1,362,969 3,318,885 North Slope 1,236,000 ; 1,220,045 (625,978)| 1% 434,074 3,318,885 Northwest Arctic 420,000 ; 5,195,452 2,177,726 1% 383,932 3,318,885 i 8,753,252 E 1,414,032 (8,046,236)| 75% 27,380,798 3,318,885 12,453,129 : 1,359,666 (11,773,296) 11% 4,015,850 3,318,885 1,197,264 ; 4,987,349 1,296,411 1% 543,962 3,318,885 36,507,731 100% 0.20 36,507,731 100% 36,507,731 36,507,731 Recommendation Cost of Power Population Even Split Additional % of Average Allocation funding Allocation Allocation Total Rounds Total cost power cost of power needed to per capita per region 1-3 Funding Funding |($/kWh basis reach 50% % total basis basis 14,556,009 0.51 20,967,940 (4,072,039) 1% 2,442,312 | 16,919,071 Bering Straits 13,750,665 0.51 20,740,637 (3,380,347) 1% 2,725,861 | 16,919,071 Bristol Bay 8,156,865 0.49 19,892,248 1% 1,861,098 | 16,919,071 Copper River/Chugach 15,612,955 0.25 10,365,887 (10,430,012) 1% 1,861,098 | 16,919,071 Kodiak 8,962,500 0.17 7,123,229 (5,400,886) 1% 1,861,098 | 16,919,071 Lower Yukon-Kuskokwim 25,527,447 0.61 24,828,373 (13,113,261) 4% 6,948,168 16,919,071 North Slope 2,502,912 0.14 5,677,485 |) 335831] 1% 2,212,829 | 16,919,071 Northwest Arctic 22,537,405 0.59 24,177,065 (10,448,872) 1% 1,957,213 | 16,919,071 Railbelt 27,946,706 0.16 6,580,206 (24,656,603)} 75% 139,582,339 | 16,919,071 Southeast 32,664,717 0.15 6,327,214 (29,501,110) 11% 20,472,076 16,919,071 'Yukon-Koyukuk/Upper Tanana 13,326,165 0.57 23,208,660 (1,721,835) 1% 2,773,019 | 16,919,071 i 565,439 0.20 8,110,421 186,109,785 0.20 186,109,785 100% —_ 186,109,785 | 186,109,785 (Highlighted in blue indicates additional allocations (icra as ee needed to reach the 50% goal of regional spread) Alaska Renewable Energy Fund = Regional Summary Round 4 Ranking TTT MELEET $25 million Allocation Preliminary 1/04/11 Rounds 1-3 % of Rounds 1-3 Total Grant Funding Funding ‘Aleutians 11,593,784 Bering Straits 11,997,448 Bristol Bay 7,431,915 Copper River/Chugach 14,057,970 Kodiak 4,973,160 Lower Yukon-Kuskokwim 24,064,078 North Slope 1,266,912 Northwest Arctic 22,117,405 i 19,193,454 20,211,588 12,128,901 565,439 149,602,054 Cost of Power Additional Average Allocation funding cost power cost of power needed to basis reach 50% 3,085,536 1,344,618 0.51 3,052,087 57,827 Recommendation Population Even Split Allocation Allocation per capita per region % total basis basis 1% 328,074 2,272,727 1% 366,163 2,272,727 Grant Bering Straits 21 Bristol Bay — 619,900 2% 0.49 2,927,243 843,721 1% 250,000 2,272,727 Copper River/Chugach 914,500 4% 0.25 1,525,392 (151,804) 1% 250,000 2,272,727 Kodiak 3,989,340 16% 0.17 1,048,218 (3,465,231) 1% 250,000 2,272,727 Lower Yukon-Kuskokwim 1,216,619 5% 0.61 3,653,618 610,190 4% 933,343 2,272,727 North Slope 210,000 1% 0.14 835,470 207,735 1% 297,248 2,272,727 Northwest Arctic 420,000 2% 0.59 3,557,775 1,358,887 1% 262,911 2,272,727 Railbelt 6,459,752: 26% 0.16 968,310 (5,975,597)} 76% 18,939,765 2,272,727 Southeast 8,306,258 33% 0.15 931,081 (7,840,718) 11% 2,750,000 2,272,727 ‘Yukon-Koyukuk/Upper Tanana 1% Statewide 1,197,264 3,415,269 510,371 372,498 2,272,727 25,000,000 100% 0.20 25,000,000 100% 25,000,000 —-25,000,000 Cumulative Rounds 1-4 Cost of Power Additional Average Allocation funding cost power cost of power needed to '$/kWh basis reach 50% 0.51 20,567,744 (1,508,062) Recommendation Population Even Split % of Total Rounds Total 1-4 Funding Funding 11,791,934 7% Allocation per region basis 15,872,914 Allocation per capita % total basis 1% 2,291,296 Bering Straits 13,465,665 8% 0.51 20,344,779 (3,293,275) 1% 2,557,313 | 15,872,914 Bristol Bay 8,051,815 5% 0.49 19,512,583 1% 1,746,021 | 15,872,914 Copper River/Chugach 14,972,470 9% 0.25 10,168,043 (9,888,449) 1% 1,746,021 | 15,872,914 Kodiak 8,962,500 5% 0.17 6,987,274 (5,468,863) 1% 1,746,021 | 15,872,914 Lower Yukon-Kuskokwim 25,280,697 14% 0.61 24,354,496 (13,103,449) 4% 6,518,541 | 15,872,914 North Slope 1,476,912 1% 0.14 5,569,124 1% 2,076,003 | 15,872,914 Northwest Arctic 22,537,405 13% 0.59 23,715,620 (10,679,595) 1% 1,836,193 | 15,872,914 Railbelt 25,653,206 15% 0.16 6,454,616 (22,425,898)| 76% 132,276,875 | 15,872,914 Southeast 28,517,846 16% 0.15 6,206,452 (25,414,620) 11% 19,206,226 | 15,872,914 Yukon-Koyukuk/Upper Tanana 13,326,165 8% 0.57 22,765,697 (1,943,316) 1% 2,601,555 | 15,872,914 Statewide 565,439 0% 0.20 7,955,624 174,602,054 100% 0.20 174,602,054 [100% 174,602,054 (Highlighted in blue indicates additional allocations rae needed to reach the 50% goal of regional spread) 174,602,054 — ————- Biopower Technical with Ofte Assessment: State of the |2¢' Industry and Technology R.L. Bain and W.A. Amos * National Renewable Energy Laboratory M. Downing and R.L. Perlack Oak Ridge National Laboratory a « pNe=L + National Renewable Energy Laboratory 1617 Cole Boulevard Golden, Colorado 80401-3393 NREL is a U.S. Department of Energy Laboratory Operated by Midwest Research Institute ¢ Battelle e Bechtel Contract No. DE-AC36-99-GO10337 6. ENVIRONMENTAL PERFORMANCE Two primary issues that could create a tremendous opportunity for biomass are global warming and the implementation of Phase II of Title IV of the Clean Air Act Amendments of 1990 (CAAA). Biomass offers the benefit of reducing NO,, SO,, and CO, emissions. The environmental benefits of biomass technologies are among its greatest assets. Global warming is gaining greater salience in the scientific community. There now appears to be a consensus among the world’s leading environmental scientists and informed individuals in the energy and environmental communities that there is a discernable human influence on the climate, and that there is a link between the concentration of carbon dioxide (i.e., greenhouse gases) and the increase in global temperatures. Biomass use can play an essential role in reducing greenhouse gases, thus reducing the impact on the atmosphere. Cofiring biomass and fossil fuels and using integrated biomass gasification combined cycle systems can be an effective strategy for electric utilities to reduce their emissions of greenhouse gases. The use of biomass crops also has the potential to mitigate water pollution. Since many dedicated crops under consideration are perennial, soil disturbance, and thus erosion can be substantially reduced. The need for agricultural chemicals is often lower for dedicated energy crops as well leading to lower stream and river pollution by agrichemical run-off. Air Pollution Biomass power has long been a source of heat and power in the United States and throughout the world. and is unique among renewables because it is a combustion technology that releases air pollutants. This environmental overview reviews air emissions from traditional biomass (wood and agriculture residues) and landfill methane biomass projects, and compares those emissions with conventional fossil-fuel generating plants. Greenhouse gas emissions will be discussed in the life cycle analysis section. Major emissions of concern from traditional biomass power plants are particulate matter (PM), carbon monoxide (CO), volatile organic compounds (VOC), and nitrogen oxides (NO,). Biomass releases very little sulfur dioxide because of the low amount of sulfur typically found in biomass. Actual amounts and the type of air emissions depend on several factors, including the type of biomass combusted, the furnace design, and operating conditions. For larger biomass projects, two types of boilers are commonly used. One boiler type is the spreader stoker. Biomass enters the furnace through a fuel chute and is distributed either pneumatically or mechanically across the furnace, where the biomass burns in suspension. At the same time, larger pieces of biomass are spread on a stationary or moving grate and combusted. A second boiler type used is the fluidized bed combustion (FBC) boiler. The fluidized bed is comprised of inert particles through which air is blown so that the fluidized bed behaves as a fluid. The biomass is combusted faster and more completely because of the immediate contact with the hot bed material, and uncontrolled air emissions are correspondingly lower. Table 6.1 compares air emissions from biomass facilities, using different feedstocks and boilers, with representative coal and natural gas systems. The table illustrates that biomass FBC boilers, as presently permitted, have lower emissions than biomass systems with stoker boilers. Biomass systems using stoker 6-1 boilers emit less SO, than coal and natural gas units (except for natural gas combined cycle units, which are characterized by extremely low SO, emissions), and less NO, than stoker boilers combusting coal and reciprocating engines burning natural gas. Biomass systems with FBC boilers are even cleaner, with lower SO, and NO, emissions than coal and natural gas combustion turbines and lower PM-10 emissions than coal systems. When comparing emissions, it is very important to understand that all the power systems reported—both fossil and biomass—meet the air emission standards governing permitting and operation that were in effect when the facilities were constructed, and represent not only differences in fuel, but also differences in emission control systems. Future systems will meet the emissions standards in place at the time of permitting, and choices of system and fuel will largely be governed by costs associated with meeting those standards. Table 6.1 Direct Air Emissions from Wood Residue Facilities by Boiler Type SOx NOx co PM-10' Comments Biomass Technology Stoker Boiler, 0.08 2.1 12.2 0.50 Based on 23 California grate Wood Residues (1,4) (biomass type (biomass type (total particulates) boilers, except for SO, not specified) not specified) (biomass type (uncontrolled) not specified) Fluidized Bed, 0.08 0.9 0.17 0.3 11 FBC boilers in California Biomass (4) (biomass type (biomass type (biomass type | (total particulates) not specified) not specified) not specified) (biomass type not specified) Energy Crops 0.05 1.10 to 2.2 0.23 0.01 Combustor flue gas goes (Poplar) (suggested value | (0.66 to 1.32 w/SNCR; (total through cyclone and Gasification based on SOx numbers | 0.22 to 0.44 with SCR) particulates) baghouse. Syngas goes (a,b) for Stoker and FBC, through scrubber and . adjusted by a factor of baghouse before gas turbine. 19,180/13,800 to account| No controls on gas turbine. for heat rate improvement) Coal Technology Bituminous Coal, 20.2 5.8 27 0.62 PM Control only Stoker Boiler (f) 1 wt% S coal (baghouse) Pulverized Coal 14.3 6.89 0.35 0.32 Average US PC boiler Boiler (d) (total particulates) (typically:baghouse, limestone FGC) Cofiring 15% Biomass, 12.2 6.17 0.35 0.32 (total z (d2) particulates) Fluidized Bed, 3.7 (1 wt% S coal 2.7 9.6 0.30 Baghouse for PM Control, Ca Coal (f) CalS = 2.5) sorbents used for SO, Natural Gas Technology 4-Stroke NG 0.006 7.96-38.3 2.98-35.0 0.09-0.18 ‘No control except Reciprocating (depends onload | (depends onload | (depends on load POC at high-end of Engine (g) and air‘fuel ratio) | andair-fuel ratio) | and air-fuel ratio) PM-10 range Natural Gas 0.009 72 | 09 Water-steam Turbine (e) (0.0007 wt% S) (total particulates) injection only Natural Gas 0.004 0.91 0.06 0.14 Water-steam Combined Cycle (c,e) (0.21 w/ SCR) (total particulates) injection only Sources: a. Spath and Mann (2000), "ASummary of Life Cycle Assessment Studies Conducted on Biomass, Coal, and Natural Gas Systems." NREL b. Spath and Mann (1997), "Life Cycle Assessment of a Biomass Gasification Combined-Cycle System." NREL. c. Spath and Mann (2000), "Life Cycle Assessment of a Natural Gas Combined-Cycle Power Generation System.” NREL. d. Spath, Mann, and Kerr (1999), "Life Cycle Assessment of Coal-Fired Power Production." NREL. 2. Mann???!5% wood residue on a heat basis (on Exh3 cofire sheet) e. AP-42 Chapter 3.1 f. AP-42 Chapter 1.1 g. AP-42 Chapter 3.2 1 & 4 from References Notes: 'PM10 emission factors are not always available. Total particulates are specified in some cases (includes PMlarger than 10 microns). Condensible PMis included in the direct emissions factors for Bituminous Coal Stoker Boiler, Fluidized Bed Coal Boiler, NG Reciprocating Engine, and the NG Turbine. In general, all particulates from 6-2 Additional emissions data for wood combustion systems from the Environmental Protection Agency, 5” Edition of AP-42, Compilation of Air Pollution Emission Factors are given in Appendix 4. Table 6.2 presents averaged permitted and actual emission levels from 34 operating wood-fired generating plants in California. Of these, 23 are spreader stoker facilities and 11 are FBCs . These facilities were built prior to the new emissions standards. New facilities are subject to the new and much stricter Clean Air Act emissions standards. Air emission standards for the most recently constructed stand-alone biomass plant in the New England region, Pine Tree Power in Westminster, Massachusetts, are included for comparison. This facility was permitted to burn clean construction/demolition wood and has the most restrictive permit conditions of any wood-fired power plant in New England. The facility can meet these requirements using a high-efficiency fluidized bed boiler (low CO and VOC emissions), an SNCR system for NOx reduction, and a mechanical collector and baghouse for particulate control. No SO, controls are required. Table 6.2 Air Pollutant Emissions Limits for Biomass Power Plants (Ib/MWh) Boiler $02 NOx co PM Type _|Permitted|Measured|Permitted |Measured|Permitted|Measured|Permitted|Measured All 1.0 0.08 2.2 1.7 9.6 8.6 0.7 0.4 Existing California * soma’ | Stokers | 0.8 0.08 2.6 2.4 13.6 12.2 0.8 05 Biomass Facilities FBCs 1.4 0.08 1.3 0.8 1.7 0.2 0.5 0.3 new 0.78 0.74 0.88 0.20 Massachussetts FBC (BACT) N/A (LAER) NA (BACT) N/A (BACT) N/A Biomass Facility” ‘[4air] Data averaged for 34 California biomass facilities (23 stokers and 11 FBCs). Based on a heating value for biomass of 8,293 BTU/Ib, and an average heat rate of 13,800 BTU/kWh. 2[2air]Permitted emissions levels for new Pine Tree Biomass Pow er Plant in Westminster, MA. BACT=Best Available Control Technology; LAER=Low est Achievable Emissions Rate A number of states—including Texas, California, and Connecticut-have enacted or are considering type certification standards for distributed generation units less than 50 MW, to ensure that emissions from small electric generating units to do not exceed BACT standards for central generating stations, and to simplify and reduce the time and cost of permitting such units. The majority of existing biopower plants would be covered by such standards if permitted today. The Texas air quality standard became effective in 2001 for distributed generation units less than 50 MW, installed or permitted after June 1, 2001, to provide a streamlined permitting method to encourage the use of clean electric generating units. The standard provides a certification method for emissions based on test results from EPA reference methods, California Air Resources Board methods, or equivalent testing to verify certification, and requires re-certification of the unit after 16,000 hours, or three years, of operation. The standard only requires certification of NO, under the decision that CO and VOC emissions will be controlled if the NO, limits are reached. To control SO,, only gases containing less than 10 grains total sulfur per 100 standard cubic feet are allowed. Systems are required to display the certification on the unit, much like an automobile emissions sticker. Certification permit costs are $450 for units larger than 1 MW,, and $100 for units smaller than 1 MW.,. Units that use combined heat and power may take credit for heat at a rate of 1 MWh for each 3.4 million Btu if the heat recovered is greater than 20% of the total CHP output. Emissions have been established for ozone attainment (West Texas) and non- 6-3 attainment (East Texas) areas, for units larger and smaller than 10 MW.,, for units that operate less than 300 hours per year, and for certain gases that would otherwise be vented to the atmosphere. A summary of emission limits are given in Table 6.3. Table 6.3: Texas Distributed Generation Certification Standards Area > 300 hours per year < 300 hours per year Landfill gas, digester gas All 0.14 Ib NO/MWh 0.38 Ib NO/MWh 1.77 Ib NO/MWh (a) East Texas 0.44 Ib NO./MWh (b) 0.14 Ib NO./MWh (c) West Texas 1.6 Ib NO/MWh 21 Ib NO/MWh (a) must contain less than 1.5 grains of H,S or 30 grains of total sulfur (b) prior to December 31, 2004 (c) after January 1, 2005 California has issued a draft standard, to become effective January 1, 2003, for any distributed generation system sold, leased, or offered for sale or lease, for use or operation in the State of California. CHP units may take credit for heat recovery if the unit achieves a minimum efficiency of 60 percent (useful energy out/fuel in). Unit emissions must be certified by California Air Resources Board reference methods; and the certification fee is $500 (60 day processing period). Units must meet the emission standards for 15,000 hours of operation when operated and maintained according to the manufacturer’s instructions; and must be re-certified every 4 years. A summary of the proposed standard is given in Table 6.4. Table 6.4: Proposed California Distributed Generation Certification Standards. Pollutant Emission Standard (1b/MWh) Power Only CHP All Units Jan 2003 - Dec 2006 Jan 2003 - Dec 2006 After Jan 1, 2007 0.5 0.7 0.05 6.0 6.0 0.08 1.0 1.0 0.02 To evaluate the potential of biopower systems, a simple analysis has been performed to compare existing and potential biopower system performance relative to the proposed standards. NO, emissions for existing systems are given in Figure 6.1' on both a life cycle and point-source plant emission basis. A national average coal station has NO, emissions of about 6.75 lb NO,/MWh, a NSPS coal plant emits 'Mann, M.K.; Spath, P.L. (2001). Comparison of Environmental Consequences of Power from Biomass, Coal and Natural Gas. Kyritsis, S., et al., eds. 1* World Conference on Biomass for Energy and Industry: Proceedings of the Conference held 5-9 June 2000, Sevilla, Spain. London, UK: James & James Ltd.; Vol. I: pp. 65- 68; NREL NICH Report No. 31172. 6-4 Bitotal NOx | Eoperating plant NOx | ~ a e NOx emissions (Ib/MWh) y = BIGCC direct coal - avg co-firing coal - NSPS NGCC Figure 6.1: NO, Emissions-Life Cycle Total and Plant Operating Emissions about 4.5 Ib NO,/MWh, a natural gas combined cycle plant emits about 0. 2 lb NO,/MWh, and a biopower direct combustion system emits about 1.2 lb NO,/MWh. Figure 6.2 gives a comparison of four existing biopower direct combustion plant emissions relative to the proposed standards for East and West Texas. CHP emissions have also been estimated, assuming that the existing systems could be modified to give a 60% CHP efficiency. Two out of the four operating biopower plants meet the West Texas standard. All CHP systems meet the West Texas standard, but additional NO, control would be required for the systems to meet the East Texas standard. td Existing [COCHP (60%) NOx (Ib/MWh) Traveling Suspension- FluidBed- Traveling NSPS -Coal East Texas - West Texas - Grate - 50 29 MW 25 MW Grate - 40 DG-2005 DG MW MW Figure 6.2: Biomass Combustion -Comparison of NO, Emissions to 2001 Texas DG Standard 6-5 NOx (Ib/MWh) The potential for a CHP system to meet standards is shown in Figure 6.3. A existing system with flue gas recycle (FGR) has emissions of about 1.4 Ib NO,/MWh. Since FGR and selective catalytic reduction (SCR) are additive, SCR is also used, assuming an additional 80% reduction. This lowers the NO, to about 0.25 lb NO/MWh. CHP is then assumed (60% total efficiency), bringing the level down to 0.12 Ib NO,/MWh. The existing system meets the West Texas standard, and the CHP system with both FGR and SCR meets the East Texas standard. The system with FGR and SCR meets the 2003 California standard, but additional optimization would be required for the CHP system to meet the 2007 California standard. Figure 6.3: Biomass Combustion - Potential for NO, Reduction 1.80 1.60 1.40 1.20 1.00 0.80 0.60 0.40 0.20 0.00 Existing - FGR Future - FGR+SCR Future with CHP East Texas Standard West Texas Standard (80%) There are about 2,500 active landfills in the United States that receive over 200 million tons of municipal solid waste every year, with 55 to 60 percent from household waste, and 35 to 45 percent as commercial waste. Landfill gas is produced during the bacterial decomposition of this waste. The amount of landfill gas that is generated depends on the composition of waste in the landfill, the age of the landfill, the moisture content in the waste, pH levels, oxygen availability, and the temperature in the landfill. Air emissions from landfills consist of roughly 50 percent methane, 48 percent carbon dioxide, small amounts of hydrogen, oxygen and nitrogen, and trace amounts of more than 100 non-methane organic compounds (NMOCs) like ethane, toluene, and benzene. The NMOC emissions include VOCs, hazardous air pollutants (HAPs), and odorous compounds. The VOCs present in NMOC emissions from landfills contribute to the formation of ozone that can reduce or damage growth in vegetables as well as exacerbate respiratory problems in humans. The health effects of HAPs include cancerous and non- cancerous illnesses like respiratory irritation and damage of the central nervous system. In 1996, the EPA issued New Source Performance Standards (NSPS) under the Clean Air Act for landfills with a capacity 6-6 of greater than 2.75 million tons that emit more than 50 Mg/year of NMOC emissions. These landfills have to install gas collection and combustion systems capable of controlling 98 percent or more of the NMOC emissions. The landfill gas can either be flared or converted to direct energy use or electrical energy. Nationwide, there are over 325 landfill gas projects, with about two-thirds generating electricity for sale. The other one-third is for direct use, particularly for heating. Air emissions from landfill gas electric generating projects include CO, NO,, SO,, hydrogen chloride (HCI), PM, and other combustion products. Representative emissions are given in Table 6.5. PM emissions may also result from fugitive dust created by garbage trucks traveling along paved and unpaved roads. Gas collection systems are typically 60 to 85 percent efficient, so emissions of methane and NMOCs still occur. SO, emissions are site-specific and depend on the sulfur content of the waste in the landfill, and so are not included in the table. Table 6.5: Air Emission Rates from Landfill Gas Combustion and Electric Generation (Ib/MWh) Flare (Btu Equivalent) 0.38 7.13 0.16 Internal Combustion 2.37-4.73 4.45-8.9 0.45-0.91 Engine Gas Turbine 0.98-1.93 2.55-5.10 0.24-0.49 Gas Boiler with low- 0.33-0.66 0.06-0.11 0.08-0.16 NOx burners Landfill gas systems with internal combustion (IC) engines generally have lower emissions than coal with stoker boilers, but higher emissions than most natural gas systems (except with reciprocating engines) and coal with FBC boilers. Landfill systems with gas turbines tend to have lower NO, and CO emissions than coal systems with stoker boilers and natural gas combustion turbines, but higher NO, and CO emissions than natural gas combined cycle systems. Landfill gas systems using gas turbines with low-NO, burners have lower NO, emissions than most of the generating technologies except natural gas combined cycle plants. All three landfill gas systems have relatively low levels of PM-10 emissions that are comparable to natural gas systems and lower than most coal systems. ; o Air emissions for landfill gas tend to be higher from facilities using IC engines, which are used at about 75 percent of the landfill gas electric facilities in the country. Because of tighter air emission, standards, future landfill gas systems may need to use low-NO, engines or gas turbines and may need CO and NO, removal systems as well. Air emissions from landfill gas can be reduced through selective catalytic reduction to reduce NO, emissions by injecting ammonia into the exhaust stream. Significant fuel pretreatment must be done at landfill gas generators to remove trace contaminants that can ruin the catalyst. Some concern has been raised about possible dioxin production from landfill gas facilities. However, the EPA believes the potential is small for dioxin emissions from the combustion of landfill gas. Previous EPA analysis found that dioxin emissions from the combustion of landfill gas are comparable to dioxin emissions from oil or coal combustion, and significantly less than dioxin emissions from municipal waste combustion. LIFE CYCLE ANALYSES’ The generation of electricity, and the consumption of energy in general, result in consequences to the environment. Using renewable resources and incorporating advanced technologies such as integrated gasification combined cycle (IGCC) may result in less environmental damage, but to what degree, and with what trade-offs? Life cycle assessment studies have been conducted on various power generating options in order to better understand the environmental benefits and drawbacks of each technology. Material and energy balances were used to quantify the emissions, energy use, and resource consumption of each process required for the power plant to operate. These include feedstock procurement (mining coal, extracting natural gas, growing dedicated biomass, collecting residue biomass), transportation, manufacture of equipment and intermediate materials (e.g., fertilizers, limestone), construction of the power plant, decommissioning, and any necessary waste disposal. The systems chosen are: . a biomass-fired integrated gasification combined cycle (IGCC) system using a biomass energy crop (hybrid poplar) . a direct-fired biomass power plant using biomass residue (urban, primarily) . a pulverized coal boiler with steam cycle, representing the average for coal-fired power plants in the U.S. today . a system cofiring biomass residue with coal (15% by heat input will be presented here) . a natural gas combined cycle power plant. Each study was conducted independently and can therefore stand alone, giving a complete picture of each power generation technology. However, the resulting emissions, resource consumption, and energy requirements of each system can ultimately be compared, revealing the environmental benefits and drawbacks of the renewable and fossil based systems. System Energy Balance The total energy consumed by each system includes the fuel energy consumed plus the energy contained in raw and intermediate materials that are consumed by the systems. Examples of the first type of energy use are the fuel spent in transportation, and fossil fuels consumed by the fossil-based power plants. The second type of energy is the sum of the energy that would be released during combustion of the material (if it is a fuel) and the total energy that is consumed in delivering the material to its point of use. Examples of this type of energy consumption are the use of natural gas in the manufacture of fertilizers and the use of limestone in flue-gas desulfurization. The combustion energy calculation is applied where non-renewable fuels are used, reflecting the fact that the fuel has a potential energy that is being consumed by the system. The combustion energy of renewable resources, those replenished at a rate equal to or greater than the rate of consumption, is not subtracted from the net energy of the system. This is because, on a life cycle basis, the resource is not being consumed. To determine the net energy balance of each system, the energy used in each process block is subtracted from the energy produced by the power plant. The total system energy consumption by each system is shown in Table 6.6. "Excerpted from Mann, M.K.; Spath, P.L. (2000). A Comparison of the Environmental Consequences of Power from Biomass, Coal, and Natural Gas. First World Conference and Exhibition on Biomass for Energy and Industry. June 5-9, Seville, Spain. 6-8 Table 6.6: Total System Energy Consumption System Total energy consumed (kJ/kWh) Biomass-fired IGCC using hybrid 231 poplar Direct-fired biomass power plant 125 using biomass residue Average coal 12,575 Biomass / coal cofiring (15% by 10,118 heat input) Natural gas IGCC 8,377 To examine the process operations that consume the largest quantities of energy within each system, two energy measurement parameters were defined. First, the energy delivered to the grid divided by the total fossil-derived energy consumed by each system was calculated. This measure, known as the net energy ratio, is useful for assessing how much energy is generated for each unit of fossil fuel consumed. The other measure, the external energy ratio, is defined to be the energy delivered to the grid divided by the total non-feedstock energy to the power plant. That is, the energy contained in the coal and natural gas used at the fossil-based power plants is excluded. The external energy ratio assesses how much energy is generated for each unit of upstream energy consumed. Because the energy in the biomass is considered to be both generated and consumed within the boundaries of the system, the net energy ratio and external energy ratio will be the same for the biomass-only cases (biomass-fired IGCC and direct-fired biomass). In calculating the external energy ratio, we are essentially treating the coal and natural gas fed to the fossil power plants as renewable fuels, so that upstream energy consumption can be compared. Figure 6.4 shows the energy results for each case studied. As expected, the biomass-only plants consume less energy overall, since the consumption of non- renewable coal and natural gas at the fossil plants results in net energy balances of less than one. The direct-fired biomass residue case delivers the most amount of electricity per unit of energy consumed. This is because the energy used to provide a usable residue biomass to the plant is fairly low. Despite its higher plant efficiency, the biomass IGCC plant has a lower net energy balance than the direct-fired plant because a significant amount of energy was required to grow the biomass as a dedicated crop. Resource limitations, however, may necessitate the use of energy crops in the future. Cofiring biomass with coal slightly increases the energy ratios over those for the coal-only case, even though the plant efficiency was derated by 0.9 percentage points. In calculating the external energy ratios, the feedstocks to the power plants were excluded, essentially treating all feedstocks as renewable. Because of the perception that biomass fuels are of lower quality than fossil fuels, it was expected that the external energy ratios for the fossil-based systems would be substantially higher than those of the biomass-based systems. The opposite is true, however, due to the large amount of energy that is consumed in upstream operations in the fossil-based systems. 30 25 20 16 10 The total non-feedstock energy consumed by the systems is shown in Table 6.7. In the coal case, 35% of this energy is consumed in operations relating to flue-gas cleanup, including limestone procurement. Mining the coal consumes 25% of this energy, while transporting the coal is responsible for 32%. Greater than 97% of the upstream energy consumption related to the natural gas IGCC system is due to natural gas extraction and pipeline transport steps, including fugitive losses. Although upstream processes in the |@Net Energy Ratio G External Energy Ratio Dedicated Biomass iGcc Average PC Coal Coal/Biomass Cofiring Direct Fired Biomass Natural Gas Combined Residue Figure 6.4: Life Cycle Energy Balance Cycle biomass systems also consume energy, shorter transportation distances and the fact that flue-gas desulfurization is not required, reduce the total energy burden. (kI/kWh) Biomass-fired IGCC using hybrid 231 poplar Direct-fired biomass power plant 125 using biomass residue Average coal 702 Biomass / coal cofiring (15% by heat 614 input) Natural gas IGCC 1,718 6-10 Table 6.7: Non-feedstock Energy Consumption System Non-feedstock energy consumed Global Warming Potential Figure 6.5 shows the net emissions of greenhouse gases, using the 100-year values from the Intergovernmental Panel on Climate Change. CO,, CH,, and N,O were quantified for these studies. The biomass IGCC system has a much lower GWP than the fossil systems because of the absorption of CO, during the biomass growth cycle. The direct-fired biomass system has a highly negative rate of greenhouse gas emissions because of the avoided methane generation associated with biomass decomposition that would have occurred had the residue not been used at the power plant. Figure 6.5: Net Life Cycle Greenhouse Gas Emissions 1200 1000 200 = Direct-Fired Biomass 0 era Residue Dedicated Average Coal/Biomass Natural Gas Biomass IGCC PC Coal Cofiring Combined Cycle GWP (g CO2-equivalent / kWh) -600 Based on current disposal practices, it was assumed that 46% of the residue biomass used in the direct- fired and cofiring cases would have been sent to a landfill and that the remainder would end up as mulch and other low-value products. Decomposition studies reported in the literature were used to determine that approximately 9% of the carbon in the biomass residue would end up as CH, were it not used at the power plant, while 61% would end up as CO,. The remaining carbon is resistant to decomposition in the landfill, either due to inadequate growth conditions for the microbes or because of the protective nature of the lignin compounds. Sensitivity analyses demonstrated that even moderate amounts of soil carbon sequestration (1,900 kg/ha/seven-year rotation) would result in the biomass IGCC system having a zero-net greenhouse gas balance. Sequestration amounts greater than this would result in a negative release of greenhouse gases, and a system that removes carbon from the atmosphere overall. The base case presented here assumes that there will be no net change in soil carbon, as actual gains and losses will be very site specific. 6-11 The natural gas combined cycle has the lowest GWP of all fossil systems because of its higher efficiency, despite natural gas losses that increase net CH, emissions. Cofiring biomass with coal at 15% by heat input reduces the GWP of the average coal-fired power plant by 18%. Air Emissions Emissions of particulates, SO,, NO,, CH,, CO, and NMHCs are shown in Figure 6.6. Methane emissions are high for the natural gas case due to natural gas losses during extraction and delivery. The direct-fired biomass and coal/biomass cofiring cases have negative methane emissions, due to avoided decomposition processes (landfilling and mulching). CO and NMHCs are higher for the biomass case because of upstream diesel combustion during biomass growth and preparation. Cofiring reduces the coal system air emissions by approximately the rate of cofiring, with the exception of particulates, which are generated during biomass chipping. Figure 6.6: Other Air Emissions 40 20 A co NOx SOx Particulates -20 = < 2 a -40 &BIGCC © Direct Biomass Residue 60 Average PC Coal | 15% Coal / Biomass Cofiring -80 &NGCC | -100 Resource Consumption Figure 6.7 shows the total amount of non-renewable resources consumed by the systems. Limestone is used in significant quantities by the coal-fired power plants for flue-gas desulfurization. The natural gas combined cycle plant consumes almost negligible quantities of resources, with the exception of the feedstock itself. The natural gas consumed in this case includes a 1.4% loss to the atmosphere during extraction and delivery. 6-12 g/kWh 500 300 200 100 Figure 6.7 Resource Consumption Average PC Coal & 15% Coal / Biomass Cofiring 400 ® Direct Biomass Residue © Dedicated Biomass IGCC NGCC Coal Limestone Oil Natural Gas Summary Completing several life cycle assessment studies has allowed us to determine where biomass power systems reduce the environmental burden associated with power generation. The key comparative results can be summarized as follows: The GWP of generating electricity using a dedicated energy crop in an IGCC system is 4.7% of that of an average U.S. coal power system. Cofiring residue biomass at 15% by heat input reduces the greenhouse gas emissions and net energy consumption of the average coal system by 18% and 12%, respectively. The life cycle energy balances of the coal and natural gas systems are significantly lower than those of the biomass systems because of the consumption of non-renewable resources. Not counting the coal and natural gas consumed at the power plants in these systems, the net energy balance is still lower than that of the biomass systems because of the energy used in processes related to flue gas clean-up, transportation, and natural gas extraction and coal mining. The biomass systems produce very low levels of particulates, NO,, and SO, compared to the fossil systems. System methane emissions are negative when residue biomass is used because of avoided decomposition emissions. The biomass systems consume very small quantities of natural resources compared to the fossil systems. Other than natural gas, the natural gas IGCC consumes almost no resources. 6-13 These results demonstrate quite clearly that, overall, biomass power provides significant environmental benefits over conventional fossil-based power systems. In particular, biomass systems can significantly reduce the amount of greenhouse gases that are produced per kWh of electricity generated. Additionally, because the biomass systems use renewable energy instead of non-renewable fossil fuels, they consume very small quantities of natural resources and have a positive net energy balance. Cofiring biomass with coal offers us an opportunity to reduce the environmental burdens associated with the coal-fired power systems that currently generate over half of the electricity in the United States. Finally, by reducing NO,, SO,, and particulates, biomass power can improve local air quality. 6-14 7. POLICY U.S. government policies are used to advance energy strategies such as energy security and environmental quality. In the case of renewable energy, and bioenergy in particular, a variety of policies have been implemented—research, development, and demonstration of new technologies, financial incentives, and regulatory mandates—to advance the use of renewables in the energy marketplace and thus realize the benefits of renewable energy. Many of the benefits of renewable energy are not captured in the traditional marketplace economics. Government policies are a means of converting non-economic benefits to an economic basis, often referred to as “internalizing externalities.” This may be accomplished by supporting the research, development, and demonstration of new technologies that are not funded by industry because of projected high costs or long development time lines. To facilitate the introduction and market penetration of renewable technologies, the government may establish financial incentives such as tax credits for new technology or additional taxes on existing technology to make the product economically competitive. The government may also mandate the use of renewable energy or products through regulatory actions that override market economics. A Renewable Portfolio Standard that requires a given percentage of renewable generation of electricity is an example of regulatory policy. This chapter briefly reviews the pertinent Federal government policies. Research, Development and Demonstration/Deployment' Biomass research, development, and demonstration/deployment (RD&D) power, heat, fuels, and chemicals has been the subject of United States government programs since the early 1970s. In 1972, the Research Applied to National Needs (RANN) Directorate of the National Science Foundation (NSF) held several workshops to define the Fuels from Biomass Program (Ward 1976). In parallel, the Department of Interior had several activities funding urban wastes and industry residues uses, including energy (Phillips 1998). To frame biomass RD&D in the context of the 1970s, the Environmental Protection Agency was formed at the end of 1970: As concern with the condition of our physical environment has intensified, it has become increasingly clear that we need to know more about the total environment--land, water, and air. It also has become increasingly clear that only by reorganizing our Federal efforts can we develop that knowledge, and effectively ensure the protection, development and enhancement of the total environment itself (President Nixon on the establishment of the Agency). At that time, the United States had nearly 200 million inhabitants in 60 million households. Schools had no computers. Each person generated more than 1.5 kg of MSW per day in the United States. Paper companies recycled less than 20% of their fiber. Each person used about 350 GJ y"'; and each dollar of the US GDP required 18 MJ of energy. Vehicles had an average fuel economy of less than 15.7 L per 100 km (15 miles/gallon), and the disposable income used to purchase motor fuels was about 4%. Households spent half of that amount to purchase electricity. A trillion vehicle miles were traveled in the United States in that year (NSTC 1995). 1 Excerpted from Chum, H.C. and R.P. Overend (2002?) “Biomass and Bioenergy in the United States,” Advances in Solar Energy, Volume 15 7-1 The oil embargo and related crises of the 1970s brought urgency to solve energy and security issues. A series of changes in government structure gave energy higher importance and consolidated activities that were previously conducted by a number of agencies. The NSF’s RANN research activities were transferred to the Federal Energy Administration. In Fiscal Year 1974, a comprehensive 5-year plan, “Fuels from Biomass Energy Program,” was developed as part of the Project Independence Blueprint. The early vision, Figure 7.1, presented by Martin Wolf at a Congressional hearing on bioconversion, guided much of the subsequent developments (Wolf 1974). In 1975, biomass energy activities were transferred to the Energy Research and Development Authority (ERDA). The Fuels from Biomass program at ERDA was funded at $600,000 in 1975. Urban waste activities were transferred from the Department of Interior and funded at the level of $400,000. The total funding for these activities corresponds to $3 million in constant 1999$ (we will mainly use year 1999$ and 2000$ to express the expenditures in constant dollars, through a calculation using the GDP deflator). Figure 7.1: The Bioenergy “Vision” in 1974 Biological Technical Processes Processes Biological Technical By 1977, all energy RD&D activities were consolidated in a new cabinet, the U.S. Department of Energy (USDOE). This department had then, and has now, multiple missions, including energy, energy security, defense-related activities such as nuclear weapons development and production, their safety and security, and advancement of the related science and technology (USDOE 2001). Biomass and bioenergy funding from the USDOE can be framed in the context of the overall energy RD&D appropriations since 1978. A comparison of the major energy producing expenditures is shown in Figure 7.2, where funding for each of the technologies is in the order: nuclear>>coal>renewables >>oil, gas, and shale. Renewable RD&D investments over this period have been one-quarter to one-third of those in the nuclear area. Within the renewable energy technologies Figure 7.3, biomass and biofuels represent 12% of the overall investment (1978-2000) or $1.2 billion (2000$). Additional biomass 7-2 investments are found in the industrial activities funded under energy efficiency such as pulp and paper, agriculture, alternative feedstocks to chemicals, etc., as shown in Figure 7.4; energy efficiency activities in transportation, buildings, industry, and the Federal Energy Management Program (FEMP) are also included. For comparison, Figure 7.5 shows related investments in major fossil energy and component areas. Figure 7.2: United States Appropriations for Energy R&D 1978 - 1998 3.0 — = o Billion Dollars (1999) _ a 0.5 | Oil, Gas \and Shale =e 0 1978 1983 1988 1993 1998 Budget Year Figure 7.3: United States Appropriations for Renewable Energy R&D 1978 - 1998 7-3 _ Union of Concerned Scientists FACT SHEET A Balanced Definition of Renewable Biomass INCLUDING BOTH A BROAD DEFINITON AND SUSTAINABLE RESOURCE USE Using biomass to generate renewable electricity can decrease carbon emissions, reduce our dependence on and importation of coal and liquid natural gas, and create new markets for farmers and forest owners. For biomass to deliver these and other benefits, policy must balance the need for efficient biomass harvesting with protecting the capacity of farms and forests to provide biomass and other ecological services. This balance can be struck through enacting a definition of renewable biomass that 1) includes a broad range of biomass resources from federal and non-federal lands and that 2) contains reasonable safeguards to protect critical lands and flexible sustainability standards. Need for woody biomass sustainability standards Markets for agricultural residues like corn stover and wheat straw are common, such as for animal feed and bedding. To reduce erosion and maintain fertility, farmers generally leave a certain percentage of residues on fields, depending on soil and slope. In forestry, where residue or biomass markets are less common, Best Management Practices (BMPs) were developed to address forest management issues, especially water quality, related to traditional products and harvest levels. But the development of new biomass markets will entail larger biomass removals from forests, especially forestry residues and small diameter trees.‘ Current BMPs may not be sufficient under higher levels of biomass harvesting. However, because woody biomass is often a low-value product that can’t even “pay its own way out of the woods,” sustainability standards must be relatively inexpensive to implement and verify. Thankfully, we can improve the sustainability of biomass harvests with little added cost to forest owners. Consensus on a flexible ‘menu’ of options for forest owners In the spring of 2009, UCS and the Southern Alliance for Clean Energy (SACE) convened Southeast stakeholders to find middle ground between the RFS and the “farm bill” biomass definitions, particularly related to woody biomass from private lands. Forest owners, foresters, biomass developers and environmental groups agreed on: a broad range of woody biomass types; safeguards for critical lands; and flexible sustainability standards implemented through a By using existing state- based and private programs, sustainability “aemerorina” Hom Standards can be added arlichtforestowners to the biomass definition would choose, including without significantly 1) biomass BMPs, 2) certification or 3) forest increasing costs on large or small forest owners. management plans. State-based biomass Best Management Practices (BMPs) or guidelines. Missouri, Minnesota, Pennsylvania, Maine and Wisconsin developed biomass harvesting guidelines to avoid negative impacts of biomass removals. Other states and regions, including Southern states, are developing similar biomass guidelines. Developed through collaborative stakeholder processes, BMPs are practical enough to be used by foresters and loggers. Third-party forest certification. Certification can also be used to verify the sustainability of biomass harvests. Between them, the Forest Stewardship Council, the Sustainable Forestry Initiative, and Tree Farm have certified nearly 275 millions of acres of industrial and private forestland in the U.S. Certification programs already address, or are being updated to address, concerns related to biomass harvests. Forest management plans written by professionally- accredited foresters. Foresters can help anticipate and therefore minimize impacts of additional biomass removals. Although a minority of smaller forest owners have management plans, forest owner associations have long recommended that more forest owners have them written to better achieve their financial and other objectives. Forest owners who have management plans stand to make more money than if they lacked such plans. To avoid out-of-pocket costs, proceeds from biomass sales could cover the cost of writing management plans. Key indicators of sustainability Whether implemented through BMPs, certification or management plans, sustainability standards should minimize short-term impacts and avoid long-term degradation of water quality, soil productivity, wildlife habitat, and biodiversity—all key indicators of sustainability. Science and local conditions need to be used in determining the standards. For example, fire-adapted forests will likely require retention of less woody biomass than forests adapted to other disturbances such as hurricanes. Sustainability standards should ensure nutrients removed in a biomass harvest are replenished and that removals do not damage long-term productivity, especially on sensitive soils. Coarse woody material that could be removed for biomass energy also provides crucial wildlife habitat; depending on a state’s wildlife, standards might protect snags, den trees, and large downed woody material. Biodiversity can be fostered through sustainability standards that encourage retention of existing native ecosystems and forest restoration. Lastly, sustainability standards should provide for the regrowth of the forest—surely a requirement for woody biomass to be truly renewable. Taken together, sustainability standards provide assurance that biomass removals will not deplete either above- or below- ground forest carbon stores and reduce biomass’ potential to significantly reduce lifecycle carbon emissions, whether in dedicated combustion or gasification plants or in co-firing with coal." The role of the federal government Forestry on non-federal lands is primarily regulated by the states. New biomass markets should be based on existing relationships between states and federal government. When applied, biomass BMPs, third-party certification and forest management plans should minimize negative ecological impacts of biomass removals. However, if states do not implement their biomass BMPs, the federal government would need to take action—as it does with states that have not implemented water-quality BMPs under the Clean Water Act. Safeguards for critical lands A balanced biomass definition must safeguard critical lands, private and public, that aren’t suited for biomass harvests. Within the federal land system, Wilderness, old-growth, Wilderness Study Areas, Inventoried Roadless Areas, components of the National Landscape Conservation System, National Monuments, National Conservation Areas, Designated Primitive Areas, or Wild and Scenic River corridors should be protected from biomass harvests. On private lands, safeguards are necessary to protect critically imperiled, imperiled, or vulnerable areas (as defined by a State Natural Heritage Program or by Natureserve). Also, native prairies and diverse natural forests should not be converted to grow energy crops or plantations. These critical lands represent a very small percentage of the nation’s land base, contain a small proportion of our biomass resources and would release significant carbon stores if harvested or converted. We can develop a large and growing biomass industry without imperiling critical lands or our carbon-reduction goals. Biomass Removal Can Support Good Forestry and Ecological Restoration Biomass harvests can help land managers restore fire-adapted forests, improve productivity through the removal of low- quality material, and reduce accumulated fuels. Many forest management plans call for the removal of small, unhealthy, or poorly formed trees to open up more growing space for larger, higher-value trees or new seedlings; but these types of removals often cost money rather than generate income. By establishing a market for low-value materials, biomass markets can provide land managers with tools to improve land conservation—while helping reduce carbon emissions and the threat of climate change. More Information UCS Bioenergy Principles online at: http://www.ucsusa.org/assets /documents/clean_energy/ucs- bioenergy-principles.pdf Forest Guild good biomass removal projects online at: http://biomass.forestguild.org/example.html ‘Woody biomass usually refers to material that has a low economic value and cannot be sold as sawtimber or pulpwood. As wood processing technologies and markets change, however, different sizes and qualities of wood will be used for renewable energy. We use “woody biomass” to refer to logging slash, small-diameter stems, tops, limbs, or trees that otherwise cannot be sold as higher-value products, such as sawtimber. i’ RL Bain, et al. 2003. Highlights of Biopower Technical Assessment: State of the Industry and the Technology. NREL. Online at: http:/Avww.nrel.gov/docs/fy03osti/33502.pdf Find additional information online at www.ucsusa.org The Union of Concerned Scientists is the leading science-based nonprofit working for a healthy environment and a safer world. Union of National Headquarters Two Brattle Square Concerned Cambridge, MA 02238-9105 Scientists Phone: (617) 547-5552 Fax: (617) 864-9405 Citazens ang Scientists for Environmental Solutions Washington, DC, Office 1825 K St. NW, Ste. 800 Washington, DC 20006-1232 Phone: (202) 223-6133 : Fax: (202) 223-6162 AD remo ooraed paper using veowiatle Desa ik For more information, please contact Ben Larson, UCS Energy Advocate and Field Manager, 202-331-6941 or blarson@ucsusa.org. © UCS September 2009