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HomeMy WebLinkAboutBPMC Meeting January 19, 2012Bradley Lake Project Management Committee Meeting ALASKA ENERGY AUTHORITY Regular Meeting Public Notice Bradley Lake Project Management Committee Notice is hereby given that the Bradley Lake Project Management Committee will hold a regular meeting on Thursday, January 19, 2012 at 10:00 a.m. For additional information contact Brad Evans, Chairman. This meeting will be conducted by electronic media pursuant to AS 44.62.310 at the following location: Alaska Energy Authority Boardroom, 813 West Northern Lights Boulevard, Anchorage, Alaska. A teleconference line has been set up for those unable to attend in person. Dial 1-800-315-6338 and enter code 3074#. The public is invited to attend. The State of Alaska (AEA) complies with Title ll of the Americans with Disabilities Act of 1990. Disabled persons requiring special accommodations to participate should contact AEA staff at (907) 771-3000 to make arrangements. Attachments, History, Details Attachments Details None Department: Revision History Category: Created 1/4/2012 6:05:55 AM by smhowell Sub-Category: Modified 1/4/2012 3:05:55 PM by smhowell Location(s): Project/Regulation #: Publish Date: Archive Date: Events/Deadlines: Commerce, Community and Economic Development Public Notices Anchorage 1/4/2012 1/20/2012 1/19/2012 1:00am BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE MEETING REGULAR MEETING (via electronic media at the Alaska Energy Authority’s Aspen Room) Anchorage, Alaska January 19, 2012 — 10:00 a.m. MINUTES 1. CALLTO ORDER Chair Brad Evans called the regular meeting of the Bradley Lake Hydroelectric Project Management Committee to order at 10:00 a.m. on Thursday, January 19, 2012, from the AEA Aspen Conference Room, Anchorage, Alaska to conduct the business of the Committee per the agenda and public notice. 2. ROLL CALL Roll was called by May Clark. The following members were present: John Foutz City of Seward (teleconference) Joe Griffith Matanuska Electric Association Brad Evans Chugach Electric Association Harvey Ambrose Homer Electric Association Henri Dale Golden Valley Electric Association Jim Posey Anchorage Municipal Light & Power Bryan Carey Alaska Energy Authority 3. PUBLIC ROLL CALL Burke Wick, CEA Arthur Miller, CEA Bob Day, HEA Larry Jorgensen, HEA Rick Miller, AML&P Jeff Warner, AML&P Don Zoerb, MEA (teleconference) Kirk Gibson, McDowell, Rackner & Gibson PC (teleconference) Landis Erwin, UA Local 367 Gary Dixon, Swalling & Associates Brian Bjorkquist, Department of Law Kelli Veech, AEA May Clark, AEA 4. PUBLIC COMMENT There were no public comments. ree Page 1 of 4 BPMC Minutes 1/19/2012 5. AGENDA COMMENTS / MOTION FOR APPROVAL The agenda was approved as amended. Mr. Ambrose added Item 7E “Bradley Lake loss compensation.” 6. APPROVAL OF MEETING MINUTES — JUNE 8, 2011 and JULY 25, 2011 The June 8, 2011 and July 25, 2011 meeting minutes were unanimously approved. 7. NEW BUSINESS 7A. Approval of FY11 Audit Report and Refund Fy11 Budget Surplus to Utilities MOTION: Mr. Posey moved that the Bradley Lake Project Management Committee approve the FY 11 Audit Report and Refund FY11 budget surplus of $1, 183,102.03 to the utilities. Seconded by Mr. Griffith. A roll call vote was taken: City of Seward: Yes Matanuska Electric Association: Yes Chugach Electric Association: Yes Homer Electric Association: Yes Golden Valley Electric Association: Yes Anchorage Municipal Light & Power: Yes Alaska Energy Authority: Yes The motion passed unanimously. 7B. Adopt Proposed Wheeling Rate Change MOTION: Mr. Posey moved that the Bradley Lake Project Management Committee adopt the proposed wheeling rate change as described in the memorandum and work papers for bills effective January, 2012. Seconded by Mr. Ambrose. A roll call vote was taken: City of Seward: Yes Matanuska Electric Association: Yes Chugach Electric Association: Yes Homer Electric Association: Yes Golden Valley Electric Association: Yes Anchorage Municipal Light & Power: Yes Alaska Energy Authority: Yes The motion passed unanimously. ae Emly Page 2 of 4 BPMC Minutes 1/19/2012 7C. Update on FERC Land Use Fees Mr. Gibson said the Group (that represents 35-43 percent of all hydroelectric land for dams in the US) filed Reply Comment to FERC on its federal land use fees proposed rule. He provided copies of the Group comment as well as a copy of comments to FERC from the Alaska delegation, Senators Murkowski and Begich — and from Governor Parnell. He said the BPMC has saved well over $100,000 in land use fees not paid to FERC while the matter was pending. The FERC final ruling should be issued by August 2012. Chairman Evans said if the ruling is successful, a thank you letter would be in order to the Alaska delegation on behalf of AEA. 7D. Update on Battle Creek Diversion Mr. Carey said we recently received R&M Consultants’ Preliminary Design Report and 65% level drawings. The diversion dam is 20’ tall and water could be diverted from about May 15 to the end of October to capture 92% of the water. ADF&G’s main concern is the winter flows, which will not be affected. Estimated total cost of project is about $43.5 M. Chair Evans asked Mr. Carey to work up an annual estimated cost for the project. Mr. Carey said the estimated interest rate is 4% and based on gaging data from USGS, HDR estimates 36,000 acre-feet or 36,000-42,000 MWh. The fisheries report will be out and sent to the agencies tomorrow, they have already attended one presentation on it; we have received no negative comments. Following issuance of the fisheries report and as part of the FERC licensing process, an agency meeting will be held February 14, 2012 at HDR’s offices and utility personnel are invited to attend. A helicopter recon will be conducted this summer to identify bear den, goat and eagles nest surveys. A geotechnical investigation (rock drilling) will also be conducted this summer, as well as gathering final terrestrial information. State and federal agencies are working well together on the project. No dwellings will be affected by the project. We should be able to file for the License Amendment in January 2013 and hopefully receive it by mid-2013. 7E. Bradley Lake Loss Compensation - HEA Mr. Day said the contract between Bradley Lake and HEA provides for compensation to HEA for losses of Bradley transmission in the HEA system beginning at project onset. They have issues with the existing methodology; therefore, Electric Power Systems has begun a study which should be available in two weeks. He requested O&D Committee review the study and make recommendations to the BPMC. 8. Committee Reports / Comments A. Operator’s Report — Bob Day Mr. Day introduced Larry Jorgensen, Bradley’s new Power Plant Superintendent, who took questions from the written report provided to the BPMC. Chair Evans asked how the unit responded to the numerous recent intertie trips. Mr. Jorgensen said the new exciters in the power system stabilizers were installed last fall and were also tuned. The unit responded well with no issues and was able to pick up and drop load as needed. Tuning also showed improved unit response. Mr. Day said Bradley’s response to a Beluga trip in November was excellent. The November disaster declaration did not affect the project, plenty of snow will be good for the water pack next year. Mr. Day said LL EEE EEEEEEEEEEEE—————————————————————————————_ Page 3 of 4 BPMC Minutes 1/19/2012 rebuilding the transmission line between Anchorage and Quartz Creek will cause numerous extended outages, but all parties are working to coordinate that. Mr. Day referred to the Operator’s Report and the problems with the powerhouse overhead bridge crane. Bringing the crane controls into compliance may cost about $400,000, bids are currently being received and they are working with the budget subcommittee on this. Chair Evans suggested budget subcommittee work with the O&D Committee also. The Operator’s Report is part of these minutes. B. Next Meeting Date The FY 2013 Budget must be adopted before the end of March, 2012; therefore, a tentative meeting date of March 16, 2012 will be scheduled. 9. Adjournment The meeting adjourned at 10:43 a.m. ATTEST: aw, Alaska Energy PEROT, Cretary ———E——EEEEE——EE EEE Page 4 of 4 BPMC Minutes 1/19/2012 y= ALASKA. QD ENERGY AUTHORITY BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE REGULAR MEETING AGENDA Thursday, January 19, 2012 — 10:00 a.m. via electronic media at the Alaska Energy Authority’s Aspen Room 813 West Northern Lights Boulevard, Anchorage, AK 1-800-315-6338 Code 3074# Ue CALL TO ORDER Evans 2: ROLL CALL (for Committee members) 3: PUBLIC ROLL CALL (for all others present - phone) 4. PUBLIC COMMENT 5. AGENDA COMMENTS / MOTION FOR APPROVAL 6. APPROVAL OF MEETING MINUTES -— June 8, 2011 and July 25, 2011 ic NEW BUSINESS A. Approval of FY11 Audit Report and Refund FY11 Budget Surplus to Utilities (ACTION ITEM) Cunningham B: Adopt Proposed Wheeling Rate Change (ACTION ITEM) Cunningham C. Update on FERC Land Use Fees Gibson D. Update on Battle Creek Diversion Project Carey 8. COMMITTEE REPORTS / COMMENTS A. Operators Report Day B. Next Meeting Date Evans 9. ADJOURNMENT 813 West Northern Lights Boulevard Anchorage, Alaska 99503 T 907.771.3000 Toll Free (Alaska Only) 888.300.8534 F 907.771.3044 Bradley Lake Project Management Committee Meeting Thursday, January 19, 2012 Agenda Item: 7A MOTION: Move that the Bradley Lake Project Management Committee approve the FY 11 Audit Report and Refund FY11 budget surplus of $1,183,102.03 to the utilities. Move: Second: Refund of FY11 Budget Surplus by Utility Percent Power Purchasers Share Refund Total Chugach Electric 30.4% $ 359,663.02 Municipality of Anchorage 25.9% $ 306,423.43 AEG&T - HEA 12.0% $ 141,972.24 AEG&T - MEA 13.8% $ 163,268.08 Golden Valley Electric 16.9% $ 199,944.24 City of Seward 1.0% $ 11,831.02 Total 100% $ 1,183,102.03 Audited Financial Statements and Other Financial Information BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS Years ended June 30, 2011 and 2010 SWALLING & ASSOCIATES Cortified Public Accountants & Business Advisers BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS Financial Statements and Other Financial Information Years ended June 30, 2011 and 2010 Contents Page Report of Independent Auditor 1 Balance Sheets 2 Statements of Revenues and Expenses 3 Statements of Cash Flows 4 Notes to Financial Statements . 5-10 Report of Independent Auditor on Additional Information 11 Statements of Expenses 12 SWALLING & ASSOCIATES Certified Public Accountants & Business Advisers REPORT OF INDEPENDENT AUDITOR Bradley Lake Project Management Committee Anchorage, Alaska We have audited the accompanying special-purpose balance sheets of the Bradley Lake Project Management Committee (a project management committee) Operating and Revenue Funds as of June 30, 2011 and 2010, and the related special-purpose statements of revenues and expenses, and of cash flows for the years then ended. These financial statements are the responsibility of the Bradley Lake Project Management Committee. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying special-purpose financial statements were prepared for the purpose of complying with, and in conformity with the accounting requirements specified in Note A, and are not intended to be a presentation in conformity with generally accepted accounting principles. In our opinion, the special-purpose financial statements referred to above present fairly, in all material respects, the assets, liabilities and surplus of the Bradley Lake Project Management Committee Operating and Revenue Funds as of June 30, 2011 and 2010, and its revenue and expenses and its cash flows for the years then ended, on the basis of accounting described in Note A. This report is intended solely for the information and use of the Bradley Lake Project Management Committee and is not intended to be and should not be used by anyone other than this specified party. antlig FE Qeeecul, B FC. December 15, 2011 3201 C Street, Suite 405 : Anchorage. Alaska 99503 Independent member of DFK International - o worldwide association of independent accounting firms and business advisers Ph 907.563.7977 - Pax 907.561.7683 + www.swallingepas.com BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS BALANCE SHEETS June 30, 2011 and 2010 ASSETS Current assets: Investments (Note B) Other receivable (Note A) Prepaid expense Total assets LIABILITIES AND SURPLUS Current liabilities: Due to AEA (Note D) Accounts payable Payable to utilities (Note E) R & C repayment (Note A) Total liabilities See accompanying notes to the financial statements. 2 $ 3,169,225 190,270 5,640 $3,365,135 $ 710,685 743,177 15373,372 537,901 $_ 3,365,135 $ 3,122,820 5,640 $_ 3,128,460 $ = 1,414,920 280,994 1,432,546 $_3.128,460 BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS STATEMENTS OF REVENUES AND EXPENSES Years ended June 30, 2011 and 2010 See accompanying notes to the financial statements. 3 2011 Variance Favorable 2010 Budget Actual (Unfavorable) Actual Revenues: Utility contributions, net of surplus refund $ 16,997,417 $15,814,310 $ (1,183,107) $ 16,989,106 Interest receipts 1,904,508 1,905,127 619 1,780,630 Other miscellaneous - - - 700 Total revenue 18,901,925 17,719,437 (1,182,488) 18,770,436 ’ Expenses, fixed asset replacements, transfers and debt service: Operations and maintenance 5,479,525 4,976,939 502,586 5,396,561 Debt service 12,273,150 12,105,450 167,700 12,402,072 Arbitrage transfer 250,000 229,976 20,024 216,349 Fixed asset replacements 802,000 _ 309,822 492,178 689,454 Interfund transfer 97,250 97,250 - 66,000 Total expenses, fixed asset replacements, transfers and debt service 18,901,925 17,719,437 1,182,488 18,770,436 Excess of revenues over expenses, fixed asset replacements, transfers and debt service $ - § - gf - $ i: BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS STATEMENTS OF CASH FLOWS Years ended June 30, 2011 and 2010 2011 2010 Cash flows from operating activities: Excess of revenues over expenses, fixed asset replacements, transfers and debt service $ - $ - Adjustments to reconcile excess of revenues over expenses, fixed asset replacements, transfers and debt service to net cash provided by (used in) operating activities: Decrease (increase) in accounts receivable (190,270) 68,204 Decrease in prepaid expense - 560 (Decrease) increase in accounts payable (671,743) 594,021 (Decrease) increase in amounts due to other funds 710,685 (79,892) Increase (decrease) in payable to utilities 1,092,378 (3,751) Increase (decrease) in R & C repayment (894.645) 131,086 Net cash provided by operating activities 46,405 710,228 Available cash and cash equivalents, beginning of year 3,122,820 2,412,592 Available cash and cash equivalents, end of year $ 3,169,225 $3,122,820 Supplemental disclosure of cash flows information: Interest paid $5,944,722 $6,127,050 See accompanying notes to the financial statements. 4 BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS June 30, 2011 and 2010 NOTE A: SIGNIFICANT ACCOUNTING POLICIES Description of Business: The Bradley Lake Project Management Committee (the Committee) was established pursuant to Section 13 of the Agreement for the Sale and Purchase of Electric Power (Power Sales Agreement) dated December 8, 1987. The purpose of the Committee is to arrange for the operation and maintenance of the Bradley Lake Hydroelectric Project (the Project), which became operational in September 1991, and the scheduling, production and dispatch of power. The members of the Committee include the Alaska Energy Authority (AEA) and the five purchasers under the Power Sales Agreement - Chugach Electric Association, Inc.; Golden Valley Electric Association, Inc.; the Municipality of Anchorage (Municipal Light & Power); the City of Seward (Seward Electric System); and the Alaska Electric Generation & Transmission Cooperative, Inc. (AEG&T). AEG&T assigned its rights pertaining to Homer Electric Association, Inc. (HEA) under the Power Sales Agreement to Alaska Electric and Energy Cooperative, Inc. (AE&EC) in 2003. HEA and the Matanuska Electric Association, Inc. (MEA) are additional parties to the Power Sales Agreement but are included as power purchasers for purposes of representation while AEG&T and AE&EC have no direct vote as a consequence of the individual representation of HEA and MEA. Section 13 of the Power Sales Agreement delineates other Committee responsibilities, including: establishing procedures for each party's water allocation, budgeting for annual Project costs and calculating each party's required contribution to fund annual Project costs. Committee approval of operations and maintenance arrangements for the Project, sufficiency of the annual budgets and wholesale power rates and the undertaking of optional Project work requires a majority affirmative vote and the affirmative vote of AEA. The Power Sales Agreement extends until the later of: 1) 50 years after commencement of commercial operation or 2) the complete retirement of bonds outstanding under the AEA Power Revenue Bond Resolution along with the satisfaction of all other payment obligations under the Power Sales Agreement. Renewal options for additional terms exist. Establishment of Trust Funds: Article V, Section 502 of the Alaska Energy Authority's Power Revenue Bond Resolution established a Revenue Fund and an Operating Fund, including an Operating Reserve account, to be held by AEA. In actuality these funds, along with the Debt Service, Excess Investment Earnings (arbitrage), and various construction funds related to the Bradley Lake Hydroelectric Project are all held by the Corporate Trust Department of US Bank in Seattle, Washington. BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS (Continued) June 30, 2011 and 2010 NOTE A: SIGNIFICANT ACCOUNTING POLICIES (Continued) All deposits, including utility contributions and interest transferred from other funds, are made into the Revenue Fund, which transfers amounts approximately equal to one-twelfth of the annual operating and maintenance budget into the Operating Fund on a monthly basis. Additional transfers are made from the Revenue Fund to the Debt Service Fund in order to satisfy semiannual interest payments and annual principal payments on the Project's outstanding bonds payable. Interest earnings available for operations and maintenance are derived from the following funds: Debt Service Fund; Operating Reserve Fund; Operating Fund; Revenue Fund; Capital Reserve Fund; and the Renewal & Contingency Fund when the fund balance is $5,000,000 or greater. Revenue and Expense Recognition: Utility contributions are recognized as revenue when due to be received under the terms of the Power Sales Agreement. Transfers from other funds are recognized when the transfer is made and interest earnings are recognized when received. Operating and maintenance expenses are recognized when incurred, while transfers to Debt Service Fund and Excess Earnings Funds are recognized when the transfer is made. At the end of June 2010 an additional transfer of $131,922 was made to the Debt Service Fund for July 2010 interest on Series 5 Bonds defeased in early August 2010 with proceeds of Series 6 Bonds issued in early July 2010. The transfer was made per a Committee approved budget amendment. Purchases of fixed asset replacements are expensed when purchased. The Operating Fund reimburses the Renewal and Contingency Reserve Fund (R & C Fund) for capital costs over a four year period. Transfers to the R & C Fund for repayment of funds withdrawn for capital costs are equal to the cumulative total of one-fourth of the amount of expenditure incurred each year. The balance due to the R & C Fund at June 30, 2011 and 2010 is $1,127,757 and $2,022,296, respectively. Estimates: The preparation of the special-purpose financial statements of the Operating and Revenue Funds requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In fiscal year 2009, the Federal Energy Regulatory Commission (FERC) land use fee increased significantly due to a new methodology for estimating the fee. The increased 2009 fee of $378,141 was paid to FERC and the Committee participated in litigation to dispute this new methodology. In fiscal year 2010, $380,000 was accrued for the fee, but was not paid pending an outcome of the litigation. During fiscal year 2011, the dispute was settled and the new land use fee methodology was discontinued. The fees for fiscal years 2009, 2010 and 2011 were estimated to be the same amount billed prior to the new methodology resulting in a refund receivable of $190,270 at June 30, 2011 that was received in September, 2011. Additional information regarding the refund of FERC fees is contained in footnote E, Surplus Refund. 6 BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS (Continued) June 30, 2011 and 2010 NOTE A: SIGNIFICANT ACCOUNTING POLICIES (Continued) Income Taxes: The Bradley Lake Project Management Committee is exempt from income taxation under Section 501 (a) of the Internal Revenue Code. Therefore, the Committee had no deferred tax liabilities or assets or tax carryforwards as of June 30, 201 1 and 2010 and no current or deferred tax expense for the years then ended. NOTE B: INVESTMENTS Substantially all of the balances in the following funds are invested in collateralized investment agreements with JP Morgan Chase Bank through the trust department of US Bank. The specified interest rate for monies from the Operating and Revenue Funds invested in the agreements is 7.38% per annum. Balances at June 30, 2011 and 2010 are as follows: 2011 2010 Operating Fund $ 944,100 $ 972,947 Revenue Fund 2225125 2,149,873 Total investments $3,169,225 $_3,122,820 Investments are sold as needed to cover operating requisitions submitted to the trustee and are therefore considered to be short-term and available for sale. Investments are presented at aggregate cost. For purposes of the cash flow statements, management considers the full amount of the investment balance to be cash available for operations. NOTE C: MAJOR CONTRACTS AND AGREEMENTS During May 1994, the Alaska Energy Authority entered into the Master Maintenance and Operating agreement with the Committee. The purpose of the agreement is to establish contract administration and budgeting procedures for maintenance and operation contracts of the Bradley Lake Hydroelectric Project and to provide for the lease or other use of facilities and equipment in a manner consistent with the requirements of the Power Sales Agreement. The term of the Master Agreement is indefinite, remaining in effect until termination of the Power Sales Agreement or until AEA no longer legally exists. This agreement authorizes AEA to enter into any contracts necessary to perform operating or maintenance-type services to the Project, subject to the approval of the Committee. BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS (Continued) June 30, 2011 and 2010 NOTE C: MAJOR CONTRACTS AND AGREEMENTS (Continued) On behalf of the Committee, the AEA entered into an agreement with Chugach Electric Association, Inc. (CEA) in August, 1996, for the provision of all services necessary to dispatch the Bradley Project's electric power output. The dispatch agreement runs concurrently with the wheeling and related services contract entered into by and among the parties to the Power Sales Agreement in December 1987 and remains in effect for the term of the wheeling agreement unless CEA ceases to be the output dispatcher. In August 1996, the Alaska Energy Authority entered into an agreement with CEA on behalf of the Committee for the provision of maintenance services for the Daves Creek and Soldotna SVC Substations. An operation and maintenance agreement dated February 11, 1994, was executed between Homer Electric Association, Inc, and the Alaska Energy Authority. This agreement provides for the operation and maintenance of the Bradley Lake Hydroelectric Project by Homer Electric Association, Inc. The agreement, as amended effective July 1, 2008, is through June 30, 2013 and automatically continues in successive five year terms thereafter unless terminated by either party as set forth in the amended agreement. Generally, to avoid an automatic, successive five year term extension, notice of termination by either party must be given two years in advance of the termination date. HEA is to be reimbursed for costs associated with the operation, maintenance and repair of the Project as determined in advance through the submission of an annual budget based upon prudent estimates and anticipated operation and maintenance costs. In August, 1996, the agreement was amended to separate the maintenance of the transmission facilities from the hydroelectric project. The transmission agreement continues from year to year, except upon written notice to terminate by either party. Notice of termination must be given six months in advance of termination dates. In June, 1999 the transmission agreement was again amended to require HEA to provide communication services in addition to the other services. BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS (Continued) June 30, 2011 and 2010 NOTE D: RELATED PARTY TRANSACTIONS During the years ended June 30, 2011 and 2010, costs incurred under the various contracts with related parties described in Note C were as follows: 2011 201 Homer Electric Association, Inc. — operation, maintenance, communications and fixed asset replacements $ 2,406,762 $ 2,571,939 Chugach Electric Association, Inc. — substation service maintenance $ 361,591 $ 181,933 Alaska Energy Authority — administrative fees $ 200,000 $ 200,000 For the years ended June 30, 2011 and 2010, Chugach Electric Association, Inc. provided dispatch services to the Committee at the agreed upon amount which is zero. Amounts payable to related parties at June 30, 2011 and 2010 were as follows: 2011 2010 Included in accounts payable: Homer Electric Association, Inc. $ 375,194 $ 638,763 Chugach Electric Association, Inc. $ 5,514 $ 73,594 Due to others: Alaska Energy Authority — short-term borrowings for vendor payments $ 710,685 $ - BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS (Continued) June 30, 2011 and 2010 NOTE E: SURPLUS REFUND AND UTILITY CONTRIBUTIONS RECEIVABLE The $280,994 surplus at June 30, 2010 was refunded to member utilities in fiscal year 2011 pursuant to the Power Sales Agreement and direction of the Committee. During fiscal year 2011, the Committee approved a fiscal year 2011 budget amendment and refund to the utilities of $360,000 as a result of increased interest earnings, reduction of the FERC land use fee, and net of an increase of expenses to the Daves Creek SVC Cooling System repair. An additional refund of $442,623 was paid during fiscal year 2011 and a refund of $190,270 was payable at June 30, 2011 for overcharges of FERC land use fees in prior years. The $1,183,102 surplus at June 30, 2011 will be refunded to member utilities in fiscal year 2012 pursuant to the Power Sales Agreement and direction of the Committee. NOTE F: SUBSEQUENT EVENTS The Committee has evaluated subsequent events through December 15, 2011, the date the financial statements were available to be issued, and did not identify anything requiring additional disclosure. 10 SWALLING & ASSOCIATES Certified Public Accountants & Business Advisers REPORT OF INDEPENDENT AUDITOR ON ADDITIONAL INFORMATION Bradley Lake Project Management Committee Anchorage, Alaska Our report on our audits of the special-purpose financial statements of the Bradley Lake Project Management Committee Operating and Revenue Funds for the years ended June 30, 2011 and 2010 appears on the page preceding the balance sheets. Those audits were conducted for the purpose of forming an opinion on the special-purpose financial statements taken as a whole, The supplemental special-purpose Statements of Expenses are presented for purposes of additional analysis and are not a required part of the basic financial statements. Such information has been subjected to the auditing procedures applied in the audits of the special-purpose financial statements and, in our opinion, is fairly stated in all material respects in relation to the special- - purpose financial statements taken as a whole. Giuotling f Asaeeinly, PC. December 15, 2011 3201 C Street, Suite 405 . Anchorage, Alaska 99503 Independent member of DFK International -a worldwide association of independent accounting firms and business advisers Ph 907.563.7977 - Fax 907.561.7683 + www.swallingepas.com BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS STATEMENTS OF EXPENSES Years ended June 30, 2011 and 2010 2011 Variance Favorable 2010 Budget Actual (Unfavorable) Actual Expenses: Generation expense: Operation supervision , and engineering $ 250,283 $ 226,863 $ 23,420 §$ 232,929 Hydraulic operation 92,619 88,703 3,916 71,844 Electric plant operation 201,203 180,216 20,987 164,045 Hydraulic power generation operation 567,785 434,727 133,058 489,116 FERC land use fees 62,623 62,623 - 380,000 Structure maintenance 276,339 266,257 10,082 209,292 Reservoir, dam, and waterway maintenance 97,498 198,343 (100,845) 50,032 Electric plant maintenance 369,824 242,543 127,281 264,320 Hydraulic plant maintenance 173,909 104,058 69,851 119,394 System control and load dispatching 376,984 501,615 (124,631) 339,665 Substation operation and maintenance 313,249 361,591 (48,342) 181,933 Overhead line maintenance 313,610 289,202 24.408 177,768 Total generation expense 3,095,926 2,956,741 139,185 2,680,338 Administrative, general and regulatory expense: Insurance 615,340 563,516 51,824 570,411 AEA administrative fee 200,000 200,000 - 200,000 PMC costs 65,950 79,157 (13,207) 62,028 Regulatory commission: FERC administrative fees 277,674 291,640 (13,966) 186,766 FERC licensing and study 136,000 82,960 53,040 48,306 Total administrative, general and regulatory expense 1,294,964 1,217,273. 77,691 1,067,511 Total operations and maintenance expenses, before capital project reimbursement 4,390,890 4,174,014 216,876 3,747,849 R&C Fund repayment 1,088,635 802,925 285,710 1,648,712 Total operations and maintenance expenses $_5,479,525 $_4,976,939 $502,586 $_5,396,561 12 Bradley Lake Project Management Committee Meeting Thursday, January 19, 2012 Agenda Item: 7B MOTION: Move that the Bradley Lake Project Management Committee adopt the proposed wheeling rate change as described in the memorandum and work papers for bills effective January, 2012. Move: Second: Chugach Electric Association, Inc. Anchorage, Alaska November 14, 2011 To: Mike Cunningham, Senior Vice President, Finance and Chief Financial Officer Burke Wick, Director, System Control From: Arthur Mitt tBirectr, Regulatory Affairs and Pricing Subject: Bradley Lake Wheeling Rate Change: January 1, 2012 The Bradley Lake wheeling rate has been updated based on operating results for the test period ending June 30, 2011. The updated rate is $0.0057 per kWh, an increase of $0.0026 over the current wheeling rate of $0.0031. The attached calculations, including supporting work papers, can be provided to the Bradley Lake Operations and Dispatch Committee for review. If approved by the Bradley Lake Project Management Committee, the rate will be applied on February 2012 invoices for wheeling services beginning January 1, 2012. As a result of the change, annual revenue generated from the wheeling of Bradley Lake energy will increase from about $0.5 million to $0.9 million. At this time, there is no impact to Chugach system base rates. Revenue received from non-firm wheeling services are treated as an offset to fuel and purchased power costs recovered from firm retail and wholesale customers. The updated rate reflects adjustment of the wheeling rate phase-in factor pursuant to Amendment No. | to the 1993 Alaska Intertie Project Participants Agreement. Amendment No. | set the wheeling rate phase-in factor at 0.50 for Bradley Lake wheeling transactions through December 31, 2011. After this period, the phase-in factor increases to 0.90. Without adjustment to the phase-in factor, the rate would have been $0.0032. The updated rate is based on the revenue requirement and cost of service calculations contained in Chugach’s June 30, 2011 Simplified Rate Filing, which was approved by the Regulatory Commission of Alaska earlier this month. Exhibits 1 through 4 contain the wheeling rate calculations. Supporting source documents can be provided if needed. Attachments Wheeling Rate Variable A Chugach Electric Association, Inc. Anchorage, Alaska Calculation of Bradley Lake Wheeling Rate: Rate Effective January 1, 2012 Test Period Ended June 30, 2011 Description Transmission O&M Expense: Dispatch Expenses Transmission O&M Transmission A&G Expense Transmission Taxes Transmission Depreciation & Amortization Expense Long-Term Interest Expense - Transmission Transmission TIER (1.10) Total Interest plus Margins Total Transmission Expense Chugach Generation & Purchases (kWh) Less Economy Sales Net Generation and Purchases Plus Bradley Lake Energy - Wheeling Utilities Total kWh Wheeling Rate Wheeling Phase-in Factor Basic Wheeling Rate (Non-Firm) Account Majors 556.000 - 556.990 560.000 - $73.992 920.000 - 932.000 408.200 - 408.600 403.500 - 405.000 Transmission Capital Costs $6,095,497 $609,550 2,854,075,671 (251,997,000) Beluga to Point MacKenzie Total _ (Exhibit 1, p.2) | $o 19.52% $6,536,822 | 19.52% $2,742,013 19.52% $30,272 19.52% $5,566,505 19.52% $6,705,046 19.52% $21,580,659 2,602,078,671 158,947,520 __ 2,761,026,191 | $0.0078 Wheeling Rate Dollars $0 $5,260,892 $2,206,796 $24,363 $4,479,973 $5,396,281 $17,368,305 2,761,026,191 $0.0063 0.9000 $0.0057 Source TY Ending June 2011 SRF TY Ending June 2011 SRF TY Ending June 2011 SRF TY Ending June 2011 SRF TY Ending June 2011 SRF TY Ending June 2011 SRF TY Ending June 2011 SRF Exhibit 3, Chugach Generation & Purchases Exhibit 3, Chugach Generation & Purchases Exhibit 4, Bradley Lake Wheeling Appendix A, Services Agreement for Bradley Lake Energy; Amendment |, 1993 Alaska Intertie Project Participants Agreement Exhibit 1 Page | of | Account No. Transmission Gross Plant 1061100000-2101 1062500020-2101 3500000000-2101 3500032700-2101 3500061900-2101 3520000000-2101 3520032700-2101 3520061900-2101 3530000000-2101 3530030400-2101 3530032700-2101 3530033000-2101 3530033100-2101 3530061900-2101 3540000000-2101 3550000000-2101 3550032700-2101 3550061900-2101 3560000000-2101 3560032700-2101 3560061900-2101 3570032700-2101 3580032700-2101 3580032800-2101 3580032900-2101 3590000000-2101 Total Transmission Plant Chugach Elec association, Inc. Anchorage, Alaska Calculation of Bradley Lake Wheeling Rate Determination of Transmission Gross Plant Associated with Beluga to Point MacKenzie Account Description b CUTRANSPRJ/GENERAL/OTHR/G&A CUSUBTRNPJ/GENERAL/PTCE/CORPORATE TRNLDLDRTS/GENERAL/OTHER/CORPORATE TRNLDLDRTS/SUBTRNS/OTHER/CORPORATE TRNLDLDRTS/EKLUTNA/OTHER/CORPORATE TRNSTRIMPV/GENERAL/OTHER/CORPORATE TRNSTRIMPV/SUBTRNS/OTHER/CORPORATE TRNSTRIMPV/EKLUTNA/OTHER/CORPORATE TRNSSTAEQ/GENERAL/OTHER/CORPORATE TRNSSTAEQ/LDSRVMT/OTHER/CORPORATE TRNSSTAEQ/SUBTRNS/OTHER/CORPORATE TRNSSTAEQ/MICROWV/OTHER/CORPORATE TRNSSTAEQ/SCADA/OTHER/CORPORATE TRNSSTAEQ/EKLUTNA/OTHER/CORPORATE TRNTWRFXT/GENERAL/OTHER/CORPORATE TRNPOLES/GENERAL/OTHER/CORPORATE TRNPOLES/SUBTRNS/OTHER/CORPORATE TRNPOLES/EKLUTNA/OTHER/CORPORATE TRNOHCONDU/GENERAL/OTHER/CORPORATE TRNOHCONDU/SUBTRNS/OTHER/CORPORATE TRNOHCONDU/EKLUTNA/OTHER/CORPORATE TRNUGCONDT/SUBTRNS/OTHER/CORPORATE TRNUGCONDU/SUBTRNS/OTHER/CORPORATE, TRNUGCONDU/NSUBCBL/OTHER/CORPORATE TRNUGCONDU/SSUBCBL/OTHER/CORPORATE TRNRDSTRLS/GENERAL/OTHER/CORPORATE Test Year Ending June 30, 2011 Test Year Jun-11 $16,686,378 $8,545,458 $1,004,816 $684,690 $32,371 $5,668,753 $2,744,834 $15,910 $74,937,721 $349,369 $14,232,690 $195,459 $940,523 $24,986 $33,965,967 $16,338,207 $4,059,049 $346,351 $16,490,556 $3,514,278 $41,514 $2,984,488 $5,028,081 $42,071,564 $22,856,551 $79,143 $273,839,705 Percent of Chugach Transmission System Associated with Beluga to Point MacKenzie (total col f / total col e) ' Beluga to Point MacKenzie adjustment includes plant in complete unclassified. Removal of Sub-transmission d (8,545,458) ($684,690) ($2,744,834) ($14,232,690) ($4,059,049) ($3,514,278) ($2,984,488) ($5,028,081) ($41,793,568) Adjusted Gross Transmission Plant ce $16,686,378 (S0) $1,004,816 So $32,371 $5,668,753 so $15,910 $74,937,721 $349,369 so $195,459 $940,523 $24,986 $33,965,967 $16,338,207 $0 $346,351 $16,490,556 so $41,514 $0 $0 $42,071,564 $22,856,551 $79,143 $232,046,137 Gross Plant - Beluga to Point MacKenzie ' it $1,895,328 $1,465,764 $17,314,998 $19,742,727 $317,823 $4,477,571 $79,143 45,293,354 19.52% Exhibit 2 Page 1 of 1 Chugach Electric Association, Inc. Anchorage, Alaska Generation & Purchased Power (MWh) July 2010 - June 2011 Description Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Total a b ¢c d e f g h i j k 1 m n Central Station Generation Beluga Unit No. I 4,845.0 5,171.0 3,260.0 1,853.0 517.0 623.0 862.0 87.0 0.0 1,380.0 2,014.0 4,322.0 24,934.0 Unit No. 2 5,856.0 6,097.0 3,519.0 2,385.0 117.0 552.0 601.0 449.0 36.0 1,906.0 3,232.0 4,716.0 29,466.0 Unit No. 3 42,209.0 41,783.0 25,991.0 37,579.0 38,145.0 43,584.0 43,326.0 35,051.0 30,830.0 34,660.0 31,930.0 35,759.0 440,847.0 Unit No. 5 40,434.0 39,792.0 36,696.0 28,492.0 22,622.0 29,652.0 36,830.0 24,844.0 25,399.0 38,160.0 8,807.0 0.0 331,728.0 Unit No. 6 10,510.0 0.0 21,163.0 49,793.0 55,456.0 59,615.0 58,515.0 53,753.0 57,076.0 51,803.0 52,480.0 48,840.0 519,004.0 Unit No. 7 27,037.0 48,953.0 47,183.0 49,042.0 54,794.0 58,346.0 57,316.0 52,669.0 55,743.0 51,129.0 51,058.0 47,971.0 601,241.0 Unit No. 8 11,644.0 15,160.0 19,701.0 27,927.0 35,142.0 38,445.0 38,084.0 34,653.0 35,203.0 12.0 31,377.0 30,854.0 318,202.0 Gross Generation 142,535.0 156,956.0 157,513.0 197,071.0 — 206,793.0 —-230,817.0 —-235,534.0 = 201,506.0 —-204,287.0 179,050.0 — 180,898.0 172,462.0 —2,265,422.0 Station Service (1,163.0) (1,214.0) (1,510.4) (1,881.2) (2,077.2) (2,155.0) (2,196.0) (2,548.0) (1,726.0) (818.0) (1,445.0) (1,430.0) (20,163.8) Net Generation 141,372.0 155,742.0 156,002.6 195,189.8 204,715.8 — 228,662.0 —-233,338.0 198,958.0 — 202,561.0 178,232.0 179,453.0 171,032.0 —_2,245,258.2 Bernice Lake Unit No. 2 128.0 0.0 0.0 1,092.0 0.0 0.0 0.0 158.0 395.0 431.0 0.0 5,478.0 7,682.0 Unit No. 3 0.0 0.0 0.0 0.0 151.0 0.0 682.0 3.0 3.0 0.0 0.0 129.0 968.0 Unit No. 4 59.0 5,447.0 103.0 0.0 0.0 89.0 5.0 34.0 38.0 0.0 0.0 8,549.0 14,324.0 Gross Generation 187.0 5,447.0 103.0 1,092.0 151.0 89.0 687.0 195.0 436.0 431.0 0.0 14,156.0 22,974.0 Station Service (12.7) (73.0) (45.6) (82.7) (106.9) (106.9) (104.4) (104.4) (97.0) (77.3) (51.5) (58.4) (920.7) Net Generation 174.3 5,374.0 57.4 1,009.3 44.1 (17.9) 582.6 90.6 339.0 353.7 (51.5) 14,097.7 22,053.3 Cooper Lake Unit No. 1 4,384.0 4,623.0 2,960.0 555.0 1,104.0 2,600.0 1,505.0 773.0 980.0 1,075.0 1,098.0 1,292.0 22,949.0 Unit No. 2 3,840.0 4,418.0 2,555.0 456.0 1,140.0 2,121.0 1,600.0 352.0 671.0 751.0 358.0 0.0 18,262.0 Gross Generation 8,224.0 9,041.0 5,515.0 1,011.0 2,244.0 4,721.0 3,105.0 1,125.0 1,651.0 1,826.0 1,456.0 1,292.0 41,211.0 Station Service (74.7) (66.7) (75.2) (93.6) (79.8) (97.0) (73.7) (70.8) (81.2) (87.0) (90.4) (87.0) (976.9) Net Generation 8,149.4 8,974.3 5,439.8 917.4 2,164.3 4,624.0 3,031.3 1,054.2 1,569.9 1,739.1 1,365.6 1,205.0 40,234.1 Eklutna - Chugach Gross Generation 4,487.0 4,312.2 7,328.2 2,078.1 2,460.4 2,582.0 2,954.8 1,984.8 2,637.6 3,700.9 3,048.5 3,75837) 41,328.2 Station Service (14.3) (13.8) (13.7) (15.7) (15.7) (18.6) (18.5) (16.6) (17.5) (14.6) (14.5) (13.6) (187.1) Net Generation 4,472.7 4,298.4 7,314.5 2,062.4 2,444.7 2,563.4 2,936.3 1,968.2 2,620.1 3,686.3 3,034.0 3,740.1 41,141.0 International Unit No. | 89.0 206.0 0.0 0.0 45.0 66.0 0.0 0.0 169.0 0.0 15.0 0.0 590.0 Exhibit 3 Page | of 3 Chugach Electric Association, Inc. Anchorage, Alaska Generation & Purchased Power (MWh) July 2010 - June 2011 Description Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-I1 Jun-11 Total a b c d e f g h ih 1 k 1 m n Unit No. 2 132.0 402.0 16.0 22.0 155.0 15.0 0.0 0.0 188.0 0.0 10.0 18.0 958.0 Unit No. 3 0.0 328.0 0.0 0.0 264.0 0.0 0.0 0.0 262.0 116.0 9.0 0.0 979.0 Gross Generation 221.0 936.0 16.0 22.0 464.0 81.0 0.0 0.0 619.0 116.0 34.0 18.0 2,527.0 Station Service (38.8) (42.2) (14.1) (67.2) (97.5) (148.4) (116.8) (121.3) (113.0) (81.6) (45.2) (36.2) (922.4) Net Generation 182.2 893.8 Ve (45.2) 366.5 (67.4) (116.8) (121.3) 506.0 34.4 (11.2) (18.2) 1,604.6 Total Central Station Generation Gross Generation 155,654.0 176,692.2 170,475.2_201,274.1 212,112.4 — 238,290.0 —-.242,280.8 = 204,810.8 —-209,630.6 185,123.9 185,436.5 191,681.7 —-2,373,462.2 Station Service (1,303.5) (1,409.7) (1,659.0) (2,140.5) (2,377.1) (2,525.9) (2,509.3) (2,861.1) (2,034.6) (1,078.5) (1,646.7) (1,625.1) (23,170.9) Net Generation 154,350.6 175,282.5 168,816.2 199,133.6 — 209,735.3 235,764.1 239,771.4 — 201,949.7 — 207,596.0 184,045.4 — 183,789.8 190,056.6 ——.2,350,291.2 Purchased Power Bradley Lake Bradley Lake - Chugach 17,116.9 15,890.0 12,012.0 8,681.0 7,706.0 6,536.0 6,997.0 9,189.0 11,633.0 8,820.3 9,064.1 6,581.0 120,226.3 Bradley Lake - MEA 7,769.6 7,213.0 5,453.0 3,941.0 3,498.0 2,967.0 3,176.0 3,168.0 2,847.0 3,997.6 4,114.6 2,967.0 S1,N1.9 Bradley Lake - SES 562.7 523.0 395.0 286.0 253.0 215.0 230.0 230.0 206.0 289.7 298.2 215.0 3,703.6 Total 25,449.2 23,626.0 17,860.0 12,908.0 11,457.0 9,718.0 10,403.0 12,587.0 14,686.0 13,107.6 13,476.9 9,763.0 175,041.7 Other Purchases AML&P 12,810.0 0.0 0.0 0.0 2,740.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 15,550.0 AEG&T - Nikiski 20,324.0 16,666.0 25,416.0 25,141.0 29,055.0 30,768.0 27,391.0 24,741.0 28,756.0 24,924.0 27,140.0 8,911.0 289,233.0 Eklutna - MEA 2,484.9 2,388.0 4,071.2 1,145.8 1,358.1 1,424.1 1,641.5 1,093.4 1,455.6 2,056.1 1,693.6 2,085.4 22,897.7 GVEA 0.0 0.0 0.0 0.0 1,062.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1,062.0 Total 35,618.9 19,054.0 29,487.2 26,286.8 34,215.1 32,192.1 29,032.5 25,834.4 30,211.6 26,980.1 28,833.6 10,996.4 328,742.7 Total Purchased Power 61,068.1 42,680.0 47,347.2 39,194.8 45,672.1 41,910.1 39,435.5 38,421.4 44,897.6 40,087.7 42,310.5 20,759.4 503,784.4 Bradley Lake Power Exchange Bradley Lake Schedule 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Bradley Lake Credit 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Bradley Lake Balance 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 Chugach System Generation and Purchased Power 215,418.6 — 217,962.5 —_216,163.4 238,328.4 = 255,407.4 =. 277,674.2, —.279,207.0 =. 240,371.1 252,493.6 224,133.1 —-226,100.3. -210,816.0 —-2,854,075.7 Exhibit 3 Page 2 of 3 Chugach Electric Association, Inc. Anchorage, Alaska Generation & Purchased Power (MWh) July 2010 - June 2011 Description Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Total a b c d e f . g h i j k 1 m n Less Economy Sales (20,292.0) — (17,667.0) — (21,719.0) — (22,936.0) — (23,420.0) —(12,595.0) — (23,141.0) —(17,441.0) — (21,411.0) (2,787.0) (27,001.0) —_(22,587.0) (251,997.0) Adjusted Net Generation and Purchased Power 195,126.6 200,295.5 194,444.4 215,392.4 231,987.4 265,079.2 256,066.0 222,930.1 231,082.6 202,346.1 199,099.28 188,229.0 2,602,078.7 Exhibit 3 Page 3 of 3 Year Jul-10 Aug-10 Sep-10 Oct-10 Noy-10 Dec-10 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Total Calculation of Bradley Lake Wheeling Rate Wheeling of Bradley Lake Energy (kWh) GVEA 4,927,520 5,701,000 5,061,000 7,802,000 8,237,000 10,677,000 6,158,000 4,020,000 6,440,000 6,005,000 3,094,000 4,405,000 72,527,520 Chugach Electric Association, Inc. Anchorage, Alaska MEA na na na na na na na ML&P 5,038,180 6,554,820 4,923,000 6,238,000 7,435,000 15,296,000 9,806,000 6,603,000 10,008,000 2,911,000 7,543,000 4,064,000 86,420,000 SES BBEEBBEBBBBSBEEBS Total 9,965,700 12,255,820 9,984,000 14,040,000 15,672,000 25,973,000 15,964,000 10,623,000 16,448,000 8,916,000 10,637,000 8,469,000 158,947,520 Exhibit 4 Page | of | May Clark From: Kirk Gibson <kirk@mcd-law.com> Sent: Thursday, January 12, 2012 6:43 AM To: May Clark Ce: Jocelyn Pease; Bryan Carey Subject: RE: BPMC Meeting - January 2012 Attachments: Memorandum to BPMC from Kirk Gibson re FERC Land Use Fees Update 1-12-11.docx; Sen Murkowski.pdf; 2011Begich_ 12_15 Wellinghoff FERC AK land use fees.pdf; Governor's comments.pdf,; AEA Comments FERC Docket No RM11-6-000.pdf; NOPR comments_2.pdf May — Please see memorandum and 5 attachments. Please let me know if you have any questions. Thanks! Best, Kirk From: May Clark [mailto:MClark@aidea.org Sent: Wednesday, January 11, 2012 12:24 PM To: Kirk Gibson Cc: Bryan Carey Subject: RE: BPMC Meeting - January 2012 Importance: High I'd like to send out the packet information tomorrow morning! Waiting on you and Bryan’s reports. Thanks! From: Kirk Gibson [mailto:kirk@mcd-law.com Sent: Monday, January 09, 2012 11:19 AM To: May Clark Cc: Jocelyn Pease Subject: BPMC Meeting - January 2012 May - Please put an item on the agenda for me to [provide an update on the FERC Land Use Fees. Also, please let me know when my materials should be provided to you in time for distribution. Thanks! Best, Kirk Kirk Gibs McDowell ate - oe Avenue, Suite 400 Rackner & Portland, OR 97205 e Direct: (503) 290-3626 Gibson PC Mobile: (503) 708-4344 Faoc (503) 595-3928 @ @ @ @ @ kirkimecdtaw.com Please visit our website to learn more: http://www.mcd-law.com PRIVILEGE AND CONFIDENTIALITY NOTICE: THE INFORMATION CONTAINED IN THIS MESSAGE MAY BE ATTORNEY PRIVILEGED AND CONFIDENTIAL INFORMATION INTENDED ONLY FOR THE USE OF THE INDIVIDUALS OR ENTITIES NAMED ABOVE. IF THE READER OF THIS MESSAGE IS NOT THE INTENDED RECIPIENT, YOU ARE HEREBY NOTIFIED THAT ANY DISSEMINATION, DISTRIBUTION OR COPYING OF THIS COMMUNICATION IS STRICTLY PROHIBITED. IF YOU RECEIVED THIS COMMUNICATION IN ERROR, PLEASE IMMEDIATELY NOTIFY ME BY TELEPHONE OR E-MAIL, AND DESTROY THIS MESSAGE. McDowell Rackner & Gibson PC Memorandum To: BPMC From: Kirk H. Gibson Date: January 12, 2012 Re: FERC Land Use Fees Update On January 6, the Group filed Reply Comment to FERC on its federal land fees proposed rule. The next step in the process is for FERC to review all comments filed. A copy of the comment filed by the Group which Bradley Lake is part of is attached to this memorandum.' There are also copies of the comments filed by Senator Murkowski, Senator Begich, Governor Parnell, and the Alaska Energy Authority attached for your review. An article also appeared in Environment & Energy Daily (E&E) this week summarizing the comments coming out of Alaska on the FERC land use fee issue.” Next Steps If FERC, based on comments received and its own internal review, determines that it has sufficient information to issue a final rule, it will make any changes to the proposed rule it deems appropriate, obtain any other required governmental reviews or approvals (e.g., Office of Management and Budget), and issue a final rule that will be published in the Federal Register. It's possible, however, that * The comments submitted by the Group included several lengthy attachments which are not included with this memorandum. The attachments include, among other things, pictures and descriptions of the facilities that made up the Group. You can download the entire filing by Clicking this link: http://remote.vnf.com/docs/NOPR_ comments 01062012.pdf * E&E is a the leading source for daily news about energy and environmental legislation in the US Congress. Phone: 503.595.3922 » Fax: 503.595.3928 » www.mcd-law.com 419 SW 11" Avenue Suite 400 « Portland, Oregon 97205 MEMORANDUM January 12, 2012 Page 2 FERC could determine that additional procedures or fact gathering are necessary before issuing a final rule. While there's no timetable for FERC's issuance of a final rule, we understand that FERC's intent is to have the final rule in place, such that it can begin implementing the new annual charges program in the current fiscal year. To do this, FERC's final rule should be issued well before the September 30; the end of the fiscal year. Analysis of Participation in Group | will provide a more detailed analysis of the cost-benefit to the BPMC of the BPMC joining the group of hydro-project owners that fought FERC on the implementation of its rule when the matter is finally resolved. To date, | estimate that the BPMC has spent roughly $65,000 for its share of the costs of the FERC attorneys and the BPMC has saved well over $100,000 in land use fees not paid to FERC while the matter was pending. | also think there is a fair chance that Bradley Lake may even see a reduction going forward given the interest of the delegation. Of course, time will tell. As always, please do not hesitate to contact me if you have questions related to this or any other matter. We) |e | |e COMMITTEE ON ARMED SERVICES MARK BEGICH COMMITTEE ON COMMITTEE ON THE BUDGET ALASKA COMMERCE, SCIENCE, AND TRANSPORTATION CHAIRMAN, SUBCOMMITTEE ON OCEANS, oases ON . ATMOSPHERE, FISHERIES AND COAST GUARD. ‘URITY AND Seer Wnited States Senate CONTIN eRTaiRET EIU WASHINGTON, DC 20510 December 15, 2011 Mr. Jon Wellinghoff, Chairman Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 Re: Docket No. RM11-6-000/Item No. H-1 Dear Chairman Wellinghoff: I respectfully ask that the Federal Energy Regulatory Commission (FERC) modify the proposed rule revising the methodology for calculating annual charges for the use of federal lands by hydropower projects in Alaska. It is my understanding that the rule, which is an effort to address a U.S. Court of Appeals decision earlier this year, proposes to use county land values from the USDA National Agricultural Statistics Service (NASS) Census to establish a fee schedule. I have been contacted by a number of Alaska electric utilities who have expressed concern over the severe increase in annual charges under the proposed rule. For example, the Sitka electric utility would see charges for one of its projects increase from $18,547 under current methodology to $1,906,627 under the proposed rule. Similarly, another utility in Southeast Alaska, which currently makes annual payments of $20,142 and $17,553 for two hydropower projects, would see an increase to $2,248,464 and $2,234,341 respectively. This is an order of magnitude increase in usage fees without a change in the underlying land values. These dramatic increases in cost have an even more crippling effect in Alaska. The majority of affected Alaska utilities serve remote and isolated communities. This means they have an extremely low customer density and a small number of ratepayers to share additional costs. The underlying problem is related to the use of the NASS Census data. While in other states the NASS Census provides an average per-acre value of agricultural land for each county, application of the NASS Census to Alaska simply does not work. As you may know, Alaska is divided into political subdivisions called boroughs in lieu of counties. Unlike counties in other states, the boroughs are not contiguous. Further complicating the application of NASS Census data to Alaska is that the census does not provide borough-level data in Alaska. Additionally, in much of the United States, agricultural land is synonymous with rural land. This is not the case in Alaska. The federal lands subject to these charges in Alaska are both distinct and distant from agricultural land. ‘SUITE 750 SUITE 328 SUITE 308 SUITE 101 ‘SUITE 230 SUITE 309 SUITE SR-111 510 STREET 101 1274 AVENUE ONE SEALASKA PLAZA ‘805 FRONTAGE ROAD 1900 FIRST AVENUE 851 EAST WESTPOINT DRIVE RUSSELL BUILDING ANCHORAGE, AK 99501 FAIRBANKS, AK 99701 JUNEAU, AK 99801 KENAI, AK 99611 KETCHIKAN, AK 99901 WASILLA, AK 99654 WASHINGTON, DC 20510 (907) 271-6915, (907) 456-0261 (907) 586-7700 (907) 283-4000 (907) 225-3000 (907) 357-9956 (202) 224-3004 Chairman Jon Wellinghoff December 15, 2011 Page 2 The NASS Census has divided the state into five areas. Using these areas for the purpose of calculating fees has created significant disparities throughout the state due to a wide range of land values, a circumstance further complicated by the application of data from one borough to hydropower projects located in other boroughs. For example, the NASS Census uses the Juneau Area to cover all of Southeast Alaska. The $54,518 per acre value of land for the Juneau area, largely determined on land close within an urban area, was then applied to hydropower projects physically located in remote areas within other boroughs. To expand on that point, land holds this value in the Juneau area precisely because it is some of the only relatively flat and habitable ground in an otherwise rugged mountainous landscape consisting of glaciers and the largest rainforest in North America. Therefore, applying those values to lands supporting hydropower, typically high alpine lakes fed by snowfall, is to apply a value derived from the very thing it is not. Let me now move to a solution. A number of the Alaska utilities subject to the new rule are proposing that FERC consider a single per-acre rate that would apply to the eatire state. It is my understanding that the NASS Census includes a statewide average value. I have been advised that all of these utilities, including those who annual fees would be larger under a single per-acre rate than under the proposed rule, agreed that a single per-acre rate would make the most sense for Alaska. This proposal appears to solve the land value conundrum identified above. At minimum, I respectfully request you review the impact of the proposed rule on affected Alaska utilities and have a dialogue with them, extending the public comment period if necessary. I further request FERC consider the single per-acre rate for the entire state as suggested by these utilities. I look forward to working with you on this and other issues important to Alaska. Thank you for your consideration of this request. Please do not hesitate to contact me or Michael Johnson in my office at (202) 224-5728 on this issue. Sincerely, Mark Begic United States Senator ce: Sara Fisher-Goad, Alaska Energy Authority Executive Director Marilyn Leland, Alaska Power Association Executive Director @ ALASKA... @@lmmD ENERGY AUTHORITY January 5, 2012 Mr. Jon Wellinghoff, Chairman Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 RE: Docket No. RM11-6-000 Dear Chairman Wellinghoff: The Alaska Energy Authority (AEA) is a public corporation and agency of the State of Alaska whose mission is to reduce the cost of energy in Alaska. AEA respectfully requests that the Federal Energy Regulatory Commission (FERC) adopt a methodology in the above-referenced rulemaking docket for calculating annual charges for the use of federal lands that meets both FERC’s standards and the unique circumstances that apply to hydropower projects in Alaska. Specifically, we request that FERC adopt a single per-acre rate to be applied statewide in Alaska that is based on the U.S. Department of Agricultural (USDA) National Agricultural Statistics Service (NASS) Census statewide average value for agricultural land, with further downward adjustments as recommended by various commenters, rather than using the county- by-county approach described for the proposed rule. This Alaska specific approach will meet FERC’s statutory obligations related to Alaska hydropower projects that FERC establish “reasonable” annual charges that avoid increasing the cost of power to consumers. The approach will also support the State of Alaska’s energy policy goal to obtain 50 percent of Alaska’s electrical generation from renewable and alternative energy sources by 2025. AEA understands that FERC is proposing to revise the methodology for calculating annual charges for the use of federal lands by hydropower projects throughout the United States. FERC proposes to create its own fee schedule based upon the methodology developed by the Bureau of Land Management (BLM) in 2008 when BLM promulgated a new methodology for its charges for the use of federal lands. While the BLM approach relies upon a zone system from county-level agricultural land value estimates from the NASS census, FERC proposes to modify BLM’s approach by establishing fee schedules based directly on the county-level NASS census data. The NASS census data approach to developing a FERC federal land fee schedule on a county- by-county basis will not provide “reasonable” annual charges when applied to Alaska hydropower projects. Most significantly, the 2007 NASS census data for the entire State of Alaska is based upon only 686 farms. More farms are included in NASS census data for most counties in the lower 48 states than to the entire State of Alaska, a state more than double the 813 West Northern Lights Boulevard Anchorage, Alaska 99503 T 907.771.3000 Toll Free (Alaska Only) 888.300.8534 F 907.771.3044 Mr. Jon Wellinghoff, Chairman January 5, 2012 Page 2 of 3 size of the next largest state. Yet, because Alaska has no counties, NASS census data subdivides Alaska into five geographic regions: Alaska Area NASS Census Data # of Farms at # of Acres Alaska- statewide 686 881,585 Aleutian Islands 35 693,611 | Anchorage 278 38,391 Fairbanks 212 110,780 Juneau 37 514 Kenai Peninsula 124 38,289 It is inherently unreliable to develop a schedule of estimated land fees based upon the very limited number of farms and farm acreages in any one of these geographic regions of Alaska. AEA believes that using the statewide per-acre rate derived from the NASS census data for the entire State of Alaska will provide a more reasonable estimate of land values. Alaska is a unique state in that most of the geographic area is remote and difficult to access. Using the NASS geographic regions of Alaska as proposed by FERC will result in a schedule of unreasonably excessive land values. Many areas of Alaska are not accessible by road, but rather require travel by plane or boat. Land values tend to be significantly lower in these remote, less accessible areas. Most of Alaska’s hydropower projects are located in these more remote portions of Alaska. In stark contrast, the majority of the farms depicted in the NASS census data are located “on the road system” in the more developed parts of Alaska. 614 of Alaska’s total 686 farms are located in the Railbelt region encompassing Anchorage, Fairbanks and the Kenai Peninsula. The Railbelt region has the most developed road system in Alaska, and also offers railroad transportation. The farming areas are within this developed road system area. An additional 37 farms are located in Juneau, another significantly developed area of Alaska. The land values in these developed areas of Alaska will tend to be significantly greater than land values in the more remote, less accessible areas. Using NASS geographic regions which focus on farms in developed areas of Alaska will result in an unreasonable schedule of federal land values for Alaska hydropower projects. Using the statewide average will provide a more reasonable and consistent approach. Finally, AEA requests that FERC consider the impact of its proposed rule on the State of Alaska’s energy policy. In 2010, the Alaska State Legislature passed legislation establishing a State energy policy and expressing intent that the State by 2025, obtain fifty percent (50%) of its electrical generation from renewable and alternative energy sources. Hydropower is the largest renewable source and lowest cost energy for Alaska consumers. Hydropower currently generates approximately nineteen percent (19%) of the electrical energy used in Alaska. Mr. Jon Wellinghoff, Chairman January 5, 2012 Page 3 of 3 Adopting a land fee schedule for Alaska which establishes excessive land fees will discourage the further development of these renewable resources. Alaska’s energy policy is particularly important to the unique circumstances regarding Alaska. Unlike most of the lower 48 states, most geographic areas of Alaska are isolated in terms of energy, as well as to transportation. Excluding the Railbelt region of Alaska, most areas of Alaska lack transmission systems which could provide for the easy transfer of energy from one region to another. A rule which discourages the development of hydropower in the lower 48 states merely tends to encourage the local utilities to purchase power from another power producer down the road. A rule which discourages hydropower in Alaska, in contrast, will tend to subject the local utility and its ratepayers to power that can be generated locally — most frequently power generated with high priced diesel fuel. Alaska is unique in several ways. The Alaska Energy Authority respectfully requests that FERC consider and accommodate these unique Alaska circumstances in adopting rules related to establishing a schedule for federal land fees to be charged to Alaska hydropower projects as FERC has historically done. We suggest that FERC adopt for Alaska a single per-acre rate to be applied statewide in Alaska that is based on the U.S. Department of Agricultural, National Agricultural Statistics Service Census statewide average value for agricultural land, with further downward adjustments recommended by various commenters in this rulemaking proceeding. Thank you for your consideration of my request. Sincerely, ALA ENERGY AUTHORITY , Cov ees Fishe -Goad Executive Director United States Senate January 6, 2012 Mr. Jon Wellinghoff, Chairman Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 Re: Docket No. RM11-6-000, Comments on Notice of Proposed Rulemaking Regarding Annual Charges for Use of Government Lands Dear Chairman Wellinghoff: I write in response to the Federal Energy Regulatory Commission’s (FERC or Commission) proposal to revise the methodology used to assess annual charges on hydropower licensees for the use of government lands as set forth in its November 17, 2011 Notice of Proposed Rulemaking (NOPR) in the above referenced docket. Hydropower supplies almost 25 percent of Alaska’s electricity needs and with over 200 promising sites identified for further development has the potential to provide hundreds, if not thousands, of additional megawatts. Given this tremendous potential, and with 52 Alaskan projects already subject to FERC fees, including some where the federal land in question has actually been transferred to the state but for a power reservation, the Commission’s proposed rulemaking on federal land use fees for hydropower licensees is extremely important to my home state. The Federal Power Act (FPA) requires hydropower licensees to recompense the United States for the use, occupancy, and enjoyment of its federal lands.' While the Act authorizes the Commission to adjust such charges from “time to time,” the resulting annual fees must be "16 U.S.C. § 803(e)(1) (2005). “reasonable.”? Indeed, Section 10(e)(1) of the FPA specifically states that the Commission must “seek to avoid increasing the prices to the consumers of power by such charges.” This statutory directive to maintain reasonable fees and consumer rates is imperative for Alaska where sparsely populated communities already pay as much as $0.64/kWh for electricity. Imposing significant fee changes on towns and municipalities with low population densities and small rate bases will represent a substantial hardship and jeopardize Alaskans’ access to affordable and reliable baseload hydropower. With its NOPR, the Commission now proposes to revise the methodology used to compute these annual land use charges. Pursuant to the proposed rulemaking, FERC would create a fee schedule based on the U.S. Bureau of Land Management’s (BLM) 2008 methodology for calculating rental rates for linear rights of way. The proposed FERC methodology would not use the zone system adopted by the 2008 BLM rule. Instead, this Commission-created fee schedule would base county land values on average per-acre values from the National Agricultural Statistics Service (NASS) Census. Using the NASS Census Data to Determine Land Use Fees is Inappropriate in Alaska I have serious concerns with applying the NASS Census data in Alaska for use in determining appropriate federal land use fees for hydropower projects in the State. As you know, the NASS Census data provides an average per-acre value for agricultural lands for counties in the Lower 48 States, focusing largely on traditional crops and livestock production and only taking average timber land values into consideration. Because the data set has never worked in Alaska, FERC has not previously considered its use for setting hydropower land use fees for the State. One obvious flaw is that there are no counties in Alaska. Instead, the State utilizes 16 discontiguous “boroughs” for local government purposes. Notably, it is the large areas of the “unincorporated boroughs” — lands that lie in between the designated boroughs — that actually contain most of the State’s pending hydroelectric project sites. In fact, a full 94 percent of the State, including most hydropower site locations, falls outside of the traditional NASS agricultural land classifications. 2 “Id. The utilization of an agricultural index that assigns the fair market value of lands that are suitable for agriculture could significantly overvalue lands used for hydropower purposes. The Department of Agriculture has historically equated agriculture with rural lands, a process that works reasonably well in valuing lands in the continental United States but not in Alaska. Of Alaska’s 365 million acres, the Department of Agriculture classifies only about 18 million acres or 6 percent as capable of producing crops and as land suitable for grazing. Currently only 900,000 acres in the State produce crops.* With regard to timber values it is important to note that the value of timber in the Tongass National Forest varies wildly between the northern and southern sections of the forest and bears no relationship to the value of timber in the Chugach National Forest on the Kenai Peninsula — the NASS census tract that staff is apparently considering basing such land use fees on as noted below. * Moreover, the NASS data likely overstates the value of Alaskan timber lands overall since it standardizes timber values nationally. Not only are many of the federal lands within Alaska unsuitable for agricultural uses, other federal prohibitions, such as the Roadless Rule, block both access and the opportunity for economic activity on these lands. The Commission Should Clarify its Treatment of Alaskan Entities Because FERC’s proposed treatment of the State of Alaska is not clarified in the NOPR, many hydropower licensees in the State fear that the Commission will impose federal land use fees based on the value of the land in the Juneau area. Pursuant to the NASS Census data, land in Juneau is valued at an astounding $54,518 per acre (which results in BLM assessing rents of $1,171.07 per acre) because of the capitol’s significant population density. However, in * Of that land, 61 percent is located in the Matanuska Valley that has only one proposed hydropower site and in the Tanana Valley that sports few such sites. * The disparity in timber appraisals is partially caused by the fact that in 2010 the U.S. Forest Service reports that 35.65 million board feet was harvested from the Tongass National Forest in Southeast, while only 155,000 board feet was harvested from the Chugach National Forest on the Kenai. * According to the U.S. Forest Service, wood exported from the Anchorage Customs District in the third quarter of 2010 sold for 47 percent less than timber exported from the Columbia-Snake River Customs District that covers Oregon and 65.5 percent less than timber from the Seattle Customs District that covers the northern Pacific Northwest. ° According to the 2009 Census Bureau estimates, Juneau has a population density of 11.2 people per square mile, compared to just 2.2 people per square mile in the Wrangell-Petersburg region, 2.6 people per square mile in the Ketchikan region, or 3 people per square mile in the Sitka area — all areas where the bulk of pending hydroelectric projects are located. conversations with Commission attorneys John Katz and Kimberly Ognisty, my staff has learned that the Commission does not intend to apply the downtown Juneau rate to any hydropower projects in the State. Instead, under the proposed rulemaking, all FERC projects in Alaska would be charged either the BLM “Fairbanks Area” rate of $16.69 per acre or the “Kenai Peninsula” rate of $28.50 per acre. While I believe the Commission should adopt a single per-acre rate for all federal lands in Alaska, at the very least FERC should clarify that the NASS Census Juneau rate is not applicable for hydropower land use fees in the State of Alaska. The Commission Should Adopt a Single Per-Acre Rate for All Federal Lands in Alaska Even with the Juneau rate off the table, FERC’s proposed methodology revision leaves Alaskan ratepayers faced with potentially onerous cost increases. For example, the current annual fees for Sitka’s Green Lake Project of $15,090 would increase by a stunning 142 percent to $36,508 per year under FERC’s proposed revision. Another example can be found at the Blue Lake Project where the current $23,598 in annual fees would increase by 97 percent to $46,398.’ On its face, such staggering land use fee increases cannot be considered “reasonable” as required by the Federal Power Act and the Commission should seek to avoid such a burdensome result for Alaskan ratepayers. Using the NASS Census data to determine land use fees is inappropriate and unworkable in Alaska and utilizing the BLM Alaska “areas” results in untenable consumer price increases. In light of FERC’s mandate to impose only “reasonable” fees and avoid consumer price increases, the Commission should instead adopt a single per-acre rate for all federal lands in Alaska. This single per-acre rate concept has been laid out for the Commission by the Federal Land Use Charges Group® and is similar to the single zone rate FERC currently charges hydropower licensees within the State. 7 According to FERC attorneys, projects near Sitka would be charged the “Kenai Peninsula” rate of $28.50 per acre of federal land. The Green Lake Project has 1,281 federal acres so its 2012 federal land charge under the NOPR would be $36,508. The Blue Lake Project has 1,628 acres so its 2012 federal land charge under the NOPR would be $46,398. * The Federal Land Use Charges Group members are: Bradley Lake Project Management Committee; the City of Idaho Falls, Idaho; City of Seattle, Washington; City and Borough of Sitka, Alaska; City of Tacoma, Washington; El Dorado Irrigation District; Eugene Water and Electric Board; PacifiCorp; Portland General Electric Company; Public Utility District No. 1 of Chelan County, Washington; Puget Sound Energy, Inc.; Sacramento Municipal Utility District; Public Utility District No. 1 of Snohomish County; Southeast Alaska Power Agency; Kodiak Electric Association; and Turlock Irrigation District. The Commission Should Implement a Phase-In Period I also agree with the Federal Land Use Charges Group’s petition for the Commission to implement a phase-in period for the anticipated higher rates that will result for FERC’s final rule revising its land use fee methodology. Such a phase-in period is a common-sense approach that will help the Commission to meet its consumer-protection obligations by avoiding draconian rate increases. The Commission Should Allow a Licensee the Opportunity to Challenge the Application of a Land Use Fee Formula Although I can appreciate the Commission’s desire to lessen its administrative burdens, I believe it is appropriate for FERC to allow a licensee the opportunity to challenge the application of a land use fee formula if it results in significant fee increases. As the Federal Land Use Charges Group has called for, FERC could provide a limited opportunity for a licensee, at its own expense, to demonstrate through periodic, independent appraisals the actual fair market value of federal lands at a project. The National Hydropower Association has also suggested that the Commission provide a licensee the flexibility to seek relief on a case-by-case basis under an alternative valuation mechanism. | ask the Commission to consider these requests. Conclusion As the Commission seeks to revise its methodology to assess annual charges on hydropower licensees for the use of federal lands, I ask the Commission to clarify its intended treatment of Alaskan entities. In keeping with its statutory obligations to ensure reasonable fees and avoid consumer rate increases, I believe FERC should adopt a single per-acre rate for all federal lands in Alaska and specify that the NASS Census Juneau rate is not applicable for Alaskan hydropower licensees. Moreover, | ask the Commission to consider implementing its new land use fees on a phase-in basis to better protect consumers and to provide licensees with the opportunity to challenge the application of a land use fee formula that results in unreasonable fee increases for the project. I thank the Commission for this opportunity to present my views on its proposed rulemaking on federal land use fees for hydropower projects. Should you have any questions or require additional information, please contact Kellie Donnelly or Chuck Kleeschulte of my staff at 202- 224-4971. Sincerely, Lisa A. Murkowski Ranking Member STATE CAPITOL Seas eN 550 West 7th Avenue #1700 PO Box 10001 i aL Anchorage, Alaska 99501 Juneau, Alaska 9981! -0001 Wet oy) 907-269-7450 907-465-3500 Ee fax: 907-269-7463 fax: 907-465-3532 www. gov.alaska. gov Governor Sean Parnell Goverhior@alaska.gov STATE OF ALASKA January 4, 2012 Mr. Jon Wellinghoff Chairman Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 Re: — Docket No. RM11-6-000 Dear Chairman Wellinghoff, It has come to my attention that the Federal Energy Regulatory Commission (FERC) is proposing to revise the methodology for calculating annual charges for the use of federal lands by hydropower projects in Alaska. I understand FERC proposes to create its own fee schedule based upon the methodology the Bureau of Land Management (BLM) developed in 2008 to value land when BLM charges for the use of federal land. I respectfully request FERC to modify its proposed rule and adopt a single per-acre rate to be applied statewide in Alaska that is based on the United States Department of Agricultural (USDA) National Agricultural Statistics Service (NASS) Census statewide average value. ‘The BLM methodology uses NASS census data that divides Alaska into five geographic and administrative areas. These areas include the Aleutian Islands (which also covers Kodiak Island and the Alaska Peninsula), Anchorage, Fairbanks, Juneau (which also covers all of Southeast Alaska), and the Kenai Peninsula. While the BLM approach relies upon a zone system from county-level agricultural land value estimates from the NASS census, FERC proposes to modify BI.M’s approach by establishing fee schedules based directly on the county-level NASS census data. I am concerned that there are an insufficient number of Alaska farms to provide an accurate land value for any of the five diverse and very large areas of the state. Dividing Alaska into an area based methodology with an insufficient data set does not reflect reasonably accurate land valuations, as required by FERC’s statutory obligations under the Federal Power Act. Given the limited number of Alaska farms and land associated with farming in this state, a single per-acre rate to be applied statewide in Alaska makes the most sense. In 2010, I signed legislation passed by the Alaska State Legislature establishing a State energy policy and expressing intent that the State obtain 50 percent of its electrical generation from renewable and alternative energy sources by 2025. Hydropower is the largest renewable source and lowest cost energy for Alaska consumers, currently generating approximately 19 percent of the electrical energy Mr. Jon Wellinghoff January 4, 2012 Page 2 used in Alaska. Adopting a land fee schedule for Alaska which establishes excessive land fees will discourage the further development of these renewable resources. ‘Thank you for your consideration of my request. I look forward to continuing to work with you on issues of importance to Alaska and our nation. Sincofely, atl f Sean Parnell Governor oc: The Honorable Lisa Murkowski, United States Senate The Honorable Mark Begich, United States Senate The Honorable Don Young, United States House of Representatives The Honorable Susan Bell, Commissioner, Alaska Department of Commerce, Community, and Economic Development Kip Knudson, Director of State/Federal Relations, Office of the Governor UNITED STATES OF AMERICA BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION Annual Charges for Use ) Docket No. RM11-6-000 of Government Lands ) FEDERAL LAND USE CHARGES GROUP’S COMMENTS ON NOTICE OF PROPOSED RULEMAKING REGARDING ASSESSMENT OF ANNUAL CHARGES FOR USE OF GOVERNMENT LANDS The Federal Land Use Charges Group (“FLG”)! appreciates the Federal Energy Regulatory Commission’s (“Commission”) request for comments on its proposed methodology for assessing annual charges for the use of government lands in the Notice of Proposed Rulemaking (“NOPR”) issued on November 17, 2011.2 FLG supports the Commission’s efforts to reform its federal land use charges program, and the methodology proposed in the NOPR goes a long way to meeting the Commission’s statutory obligation to establish “reasonable” annual charges,* which the Commission has long held to be met through charges that are based on the fair market value (“FMV”) of the occupied federal lands.4 FLG is concerned, however, that implementation of the 1 The FLG members are: Bradley Lake Project Management Committee; the City of Idaho Falls, Idaho; City of Seattle, Washington; City and Borough of Sitka, Alaska; City of Tacoma, Washington; El Dorado Irrigation District; Eugene Water and Electric Board; PacifiCorp; Portland General Electric Company; Public Utility District No. 1 of Chelan County, Washington; Puget Sound Energy, Inc.; Sacramento Municipal Utility District; Public Utility District No. 1 of Snohomish County; Southeast Alaska Power Agency; Kodiak Electric Association; and Turlock Irrigation District. 2 Annual Charges for Use of Government Lands, Notice of Proposed Rulemaking, 137 FERC § 61,139 (2011), 76 Fed. Reg. 72,134 (Nov. 22, 2011) [hereinafter, “NOPR”]. 2 16 U.S.C. § 803(e)(1). * Order No. 469, Revision of the Billing Procedures for Annual Charges for Administering Part I of the Federal Power Act and to the Methodology for Assessing Federal Land Use Charges, FERC Stats. & Regs., methodology proposed in the NOPR will significantly overvalue federal lands associated with hydropower projects above their FMV, and as such result in annual charges that are per se unreasonable. For this reason, any final rule adopted by the Commission should adjust the methodology in the NOPR to ensure that annual charges are based on an accurate FMV estimation of federal lands associated with hydropower projects, thereby meeting the reasonableness requirement of Section 10(e)(1) of the Federal Power Act (“FPA”). FLG’s comments, which are supported by detailed analyses and project-specific data originally provided to the Commission in FLG’s comments on the Commission’s Notice of Inquiry (“NOI”).6 demonstrate that a reduction of at least 50 percent of the average county per-acre land value from the “land and buildings” category of the Census of Agriculture of the National Agricultural Statistics Service (“NASS Census”) is necessary to accurately use the NASS Census data as a FMV estimate of federal lands associated with hydropower projects. The Commission’s final rule, which must be based on substantial evidence in the record,2 should address this information, which FLG has again submitted to the record as an attachment to this comment. In addition, the final rule should implement other changes to the methodology described in the NOPR. The encumbrance factor should reflect the degree to which hydroelectric projects actually encumber the federal lands to the exclusion of other uses, Regs. Preambles 1986-1990 30,741, at pp. 30,587-88 (1987) (“Order No. 469”). See City of Idaho Falls v. FERC, 629 F.3d 222, 229 (D.C. Cir. 2011). 2 16 U.S.C. § 803(e)(1). & Federal Land Use Charges Group’s Comments on Notice of Inquiry Regarding Assessment of Annual Charges for Use of Government Lands, Docket No. RM11-6-000 (filed Apr. 29, 2011) [hereinafter, “FLG NOI Comments”). ZT 16 U.S.C. § 825K(b). and should recognize the significant contribution that many projects make, in the public interest, to the achievement of the land managing agency’s objectives—all at the licensee’s expense. Given the paucity of NASS Census data in Alaska, moreover, the final rule should adopt a single per-acre rate for all federal lands in Alaska. Finally, the final rule—recognizing the Commission’s statutory obligation to “seek to avoid increasing the price to the consumers of power” when setting annual charges*—should implement a phase-in 25 percent reduction for the first year in which the new rule becomes effective. IL COMMUNICATIONS All correspondence and communication concerning this request should be directed to: Charles R. Sensiba John H. Clements Sharon L. White Van Ness Feldman, P.C. 1050 Thomas Jefferson Street, N.W. Seventh Floor Washington, DC 20007 (202) 298-1800 (phone) (202) 338-2416 (fax) crs@vnf.com jhc@vnf.com slw@vnf.com Il. INTERESTS OF FEDERAL LANDS GROUP FLG consists of 16 owners and/or operators of 37 licensed projects located in whole or in part on federal lands in Alaska, California, Idaho, Oregon, Utah, and Washington. These projects collectively occupy 62,082 acres of federal lands, which amount to nearly 40 percent of the total federal acreage subject to the Commission’s § Id. § 803(e)(1). federal lands annual charges under FPA Section 10(e)(1)2 Collectively, FLG members pay millions of dollars annually in these charges—a substantial portion of the total fees that the Commission collects under this program. FLG members will be directly affected. by any final rule issued by the Commission with respect to the assessment of charges for the use of federal lands and have a substantial interest in the issues presented in the Commission’s NOPR. Ill. COMMENTS ON NOPR A. Summary of FLG Comments By proposing to eliminate the Commission’s practice of doubling the per-acre rate for non-transmission lands and to use county-specific values from the NASS Census instead of the Bureau of Land Management’s (“BLM”) zone system, FLG believes that the NOPR goes far in helping to ensure that the Commission meets its obligation under FPA Section 10(e)(1) to assess reasonable annual charges. FLG continues to have concerns, however, that the Commission’s proposed methodology fails to adequately account for the significant disparity in FMV of the types of lands included in the NASS Census—which are exclusively agricultural lands—and the types of federal lands associated with hydropower development. Without further downward adjustments, use of NASS Census land values would result in a significant overvaluation of FMV for federal lands, thereby leading to annual charges that are per se unreasonable. Other elements of the methodology in the NOPR would result in unreasonable annual charges as well. To address these concerns, FLG recommends the following revisions to the Commission’s proposed methodology: 2 Collectively, hydroelectric licensees’ projects occupy 166,156 acres of federal lands. See Attachment G: Federal Energy Regulatory Commission; U.S. Federal Lands; Licensee, Project, State, Counties, Acres (FERC 2011). 1) Reduce land values by 50 percent instead of BLM’s 20 percent reduction. While BLM reduced land values in recognition that its permittees should not be billed for land value enhancements such as buildings and irrigated lands, this downward adjustment does not take into account the fundamental difference in character and quality between agricultural lands and hydropower lands. FLG believes, as demonstrated herein, that a further downward adjustment is warranted. 2) Set an encumbrance factor of 30 percent for all projects. Unlike other energy infrastructure, hydroelectric projects encumber federal lands minimally, while substantially enhancing the management objectives of the federal land management agency to manage the land in the public interest by providing recreation facilities, fish and wildlife protection and enhancement, cultural resources management, and other public benefits—all at the licensee’s expense. A 30 percent encumbrance factor better represents the actual, physical encumbrance of federal lands, the multiple, non-project uses of federal lands at licensed projects, and the immense public benefits licensees provide at their projects. 3) Apply a State-Wide Average Per-Acre Land Value for Alaska Lands. Due to the lack of robust data in the NASS Census for Alaska, and the skewed results that would result from adopting either the BLM Alaska “areas” or the NASS Census Alaska “areas,” the Commission should use the NASS Census’s Alaska state average per-acre land value for all federal lands in Alaska. Such an approach is consistent with the Commission’s current practice for calculating these charges in Alaska. 4) Institute a Phase-In Period for New Fee Schedule. Because implementation of the final rule, even with the modifications recommended by FLG, will result in substantially increased charges in most cases, the Commission should implement a phase-in 25 percent reduction of annual charges for the first year in which its final rule becomes effective, which is consistent with the 2008 BLM Rule.” 5) Apply Specific County Values for Projects Occupying Federal Lands in Multiple Counties. The Commission should clarify that if federal lands at a project fall in two or more separate counties, the Commission will calculate the annual charge on a county-by-county basis, and not simply apply the highest county value to all federal lands at the project. Thus, with FLG’s proposed modifications to the NOPR, the formula for determining the per-acre rental fee would be: 1 Update of Linear Right-of-Way Rent Schedule; Final Rule, 73 Fed. Reg. 65,040, 65,045-46 (Oct. 31, 2008) [hereinafter, “BLM Final Rule”). Annual Per-Acre Rent = (50% of NASS Census Average County Agricultural Land and Buildings Value)" x (30% encumbrance factor) x (5.27% rate of return, which is the 1998-2008 average of the 30-year and 20-year Treasury bond yield rates) x (the average annual change in the Implicit Price Deflator-Gross Domestic Product for the 10-year period immediately preceding the year that the NASS Census data becomes available) FLG is confident that, in all but a few instances, implementing the Commission’s proposed method with FLG’s adjustments set forth above will result in a more accurate FMV approximation of federal lands associated with hydropower projects, and otherwise meet the Commission’s statutory obligation to ensure reasonable annual charges./ Nonetheless, as with any index methodology or other approximation, there may be instances in which use of the Commission’s formula with the FLG adjustments could result in charges that do not reasonably capture the FMV of federal lands at a given project. Thus, FLG continues to recommend, as it did in its NOI comments, that the Commission provide a limited opportunity for a licensee, at its own expense, to demonstrate through periodic, independent appraisals the actual FMV of federal lands at its project. FLG incorporates by reference its rationale and justification for a limited right to an independent appraisal set forth in its NOI comments. FLG also is attaching proposed revised regulatory text for 18 C.F.R. Part 11 to ensure that the regulatory text fully reflects the final rule and is consistent with the Commission’s obligations under Section 10(e)(1). FLG’s proposed regulatory text appears in Section V of these comments. i For Alaska, this figure would be 50 percent of the NASS Census Average Alaska State Land and Buildings Value. 2 16 U.S.C. § 803(e)(1). The inconsistent values for Alaska federal lands discussed infra section III.B.3 is a good example of how a NASS Census valuation is not always appropriate. 4 FLG NOI Comments at pp. 30-36. B. FLG Comments on NOPR 1. Adjustment to Land Values FPA Section 10(e)(1) requires the Commission to assess federal land use charges that are reasonable, which the Commission has determined are charges based on the FMV of the federal lands. In Order No. 469, the Commission found that because agricultural lands are higher in value than lands associated with hydropower projects, the use of an index of agricultural land values would overstate the FMV of federal lands associated with hydropower projects.“4 The Commission, therefore, chose to adopt a method developed by the U.S. Forest Service (“FS”) based on values of federal lands subject to FS and BLM permits. Currently, the Commission proposes to assess federal land use charges using a formula based largely on the method for calculating rental payments for linear rights-of- way (“ROWs”) adopted by BLM in 2008 (“2008 BLM Method”).* The 2008 BLM Method uses agricultural land values in the NASS Census as the basis for assessing charges for linear ROWs, and reduces the land values by 20 percent to remove valuation effects of buildings and irrigated farmland. Despite the Commission’s own finding in Order No. 469 regarding the disparity in value between agricultural and hydropower lands, the Commission proposes to follow BLM’s lead in using NASS Census land values to calculate federal land use charges. While the Commission, like BLM, seeks to downwardly adjust NASS Census values by 20 percent to account for buildings, irrigation, and other improvements, that adjustment does not address at all the fundamental difference between the value of agricultural lands and the value of lands 14 Order No. 469 at p. 30,589. 4 BLM Final Rule, 73 Fed. Reg. 65,040. suitable for hydropower development—as recognized by the Commission in Order No. 469. The evidence submitted by FLG in this regard in response to the NOI supports a downward adjustment of 50 percent. Absent such an adjustment, the land use charges assessed by the Commission will be per se unreasonable, as they will be based on estimations that far exceed FMV. a. The Agricultural Lands Valued in the NASS Census Are Fundamentally Different from, and More Valuable than, Lands Suitable for Hydropower Development. As explained in FLG’s comments in response to the NOI, FLG members’ projects occupying federal lands are a robust, highly representative sample of federal lands at hydropower projects generally.° The FLG’s comments on the NOI included a comprehensive review and analysis of all federal lands at their projects, which demonstrates that the vast majority of these lands are completely unsuitable for agricultural development and use2 When BLM developed the 2008 BLM Method, it found that the linear ROW lands administered by BLM and FS have “many of the same agricultural values (grazing, commercial timber production, woodland and vegetative sales (Christmas trees, firewood, mushrooms, pine nuts, seed crops from native species, etc.))” as the agricultural lands covered by the NASS Census.!® The Commission simply cannot support this same 18 See FLG NOI Comments at 10-11 & n.29 and Attachment G. Two hundred forty-five projects are currently subject to federal land use charges, of which 177, or 70 percent, are located in the same six states as the FLG member projects. The federal project lands in these states total 143,957 acres, or 86.6 percent of the total federal acreage. 2 See Attachment A: Qualitative Assessment of Agricultural Feasibility of FLG Member Federal Project Lands — Description and Supporting Materials. ‘8 BLM Final Rule, 73 Fed. Reg. at 65,043. The agricultural activity tracked by the NASS Census on these lands is the kind of agricultural production one would expect to find on cleared, arable, and generally level ground; e.g., grains, vegetables, orchards, and livestock. 3 finding here.”® As it observed in Order No. 469 and as confirmed in the evidence adduced in this proceeding, agricultural lands are characteristically different than hydropower lands, and due to these differences, the raw land value of agricultural lands is much higher. As documented in Attachment A, the federal lands associated with these projects have steeply sloped and rugged terrain; occupy narrow river valleys or canyons; have poor quality, easily erodible, or unstable soils; are located above timberline; or are underlain by bare rock. In some cases, the project reservoir includes lands that, prior to the project, were occupied in whole or part by a natural lake. In some cases in Alaska and the high Sierra Mountains of California, harsh climatic conditions, as well as remoteness, also make the federal project lands completely unsuitable for any kind of agriculture. The vast majority of federal lands at FLG member projects consist of the project reservoir and lands occupied by non-transmission line project works, which are concentrated in the river valleys and canyons that make hydroelectric generation possible and agriculture unsustainable.” In contrast, the NASS Census captures the FMV of generally level, arable, private agricultural lands. As the Commission concluded in Order No. 469," and as confirmed by the current day evidence presented by FLG in Attachments C and D, such lands are much more valuable than lands associated with hydropower projects. + There may be some instances in which agricultural values are present at federal lands within hydropower projects — particularly timber harvesting. The NASS Census, however, does not track commercial timber harvest, as discussed in the FLG’s NOI comments and, to the extent that other woodland crop sales are tracked, they constitute a tiny percentage of the total value of agricultural products. Thus, woodland crop sales have virtually no value in establishing the FMV of lands in the NASS Census in counties where FLG member projects are located. See FLG NOI Comments at 13-14 and Attachment B. 22 See generally Attachment A. 21 Order No. 469 at p. 30,589. b. A 50 Percent Downward Adjustment of NASS Census County Land Values Is Needed to Ensure that Federal Land Use Fees are Based on FMV. Because the land values included in the NASS Census are based on higher valued agricultural lands, a downward adjustment (in addition to the 20 percent reduction to account for buildings, irrigation, and other improvements) is necessary to ensure that annual charges are based on a reasonably accurate FMV estimate of federal lands at hydropower projects. To ascertain an approximate value of hydropower project lands, FLG members gathered information on the sale or appraisal of lands comparable to hydroelectric project lands in counties where their projects are located. The county agricultural land values in the NASS Census are significantly higher than these actual appraisals—even when applying the 20 percent discount under the 2008 BLM Method. As shown in Appendix | to Attachment C, the average per-acre appraisal or sale data available to FLG members is 59 percent lower than the equivalent county agricultural land value under the NASS Census. As a further test, FLG compared the lowest value agricultural land, pastureland, to the land values used under the 2008 BLM Method. The pastureland value was, on average, 59 percent lower than the equivalent county agricultural land value under the NASS Census, and far lower than the land values BLM used, even with the 20 percent reduction for buildings and irrigated farmland. Finally, FLG compared agricultural land rental fees under the 2008 BLM Method to: (1) recent average NASS Survey pastureland rent for each of the agricultural districts in which FLG member projects are located; and (2) recent average NASS Survey county 2 See FLG NOI Comments at 15. -10- pastureland rents by County. The results are shown in Attachment D.~ Under the 2008 BLM Method, the average agricultural land rental payment across all counties in which FLG member projects are located is almost six times the rate for pastureland rental. And since lands at hydropower projects are more comparable to non-irrigated pasturelands, a significant reduction in value of the NASS Census data would be required if the Commission were to adopt the NASS Census as its index for estimating values of lands at hydropower projects. In sum, the Commission’s NOPR uses land values from the NASS Census that grossly overstate the FMV of federal lands associated with hydroelectric projects, even with the proposed 20 percent downward adjustment, which accounts only for improvements. The evidence submitted by FLG warrants a downward reduction of 60 percent or more, yet the NOPR does not address or discuss FLG’s extensive data, which was prepared based on specific facts at licensed projects. Recognizing that land characteristics at hydropower projects across the United States may vary, and to ensure that the United States is reasonably compensated for the use of its lands based on FMV, FLG recommends that the Commission reduce the NASS Census land values by 50 percent in its final rule. 2. Adjustment to Encumbrance Factor The Commission’s proposal in the NOPR to eliminate its current practice of doubling the encumbrance factor for non-transmission federal lands, and instead using a single encumbrance factor for all federal lands within the project boundary, is appropriate and warranted. As FLG demonstrated in its NOI comments, the premise that 2 Attachment D: NASS Pastureland Rental Charges Versus Forest Service Fee Schedule Rental Charges. -ll- hydroelectric projects, and particularly non-transmission lands, fully encumber non- transmission line lands has no evidentiary support.* However, FLG believes that the NOPR’s proposal to use a 50 percent encumbrance factor for all federal lands fails to recognize the limited physical encumbrance of hydropower projects on federal lands, as well as the multiple, non- project uses of federal lands within project boundaries and the enhanced public recreation and other access provided by hydroelectric licensees. The FLG continues to believe that the Commission should adopt an encumbrance factor of 30 percent, rather than the 50 percent encumbrance factor proposed in the NOPR. Because the NOPR includes no discussion of the evidence submitted by FLG with regard to this matter, that evidence is summarized again below. There are many reasons why a 30 percent encumbrance factor is justified. First, the FPA requires that projects are licensed in a manner that ensures the adequate protection and utilization of the federal reservations they occupy. When licensing a project, the Commission must determine whether the project, as licensed, will not interfere with the purposes for which the federal reservation was created.2> Moreover, pursuant to FPA Section 4(e),”° the Commission must include in the license for each such project all conditions that the Secretary of the department under whose supervision the reservation falls deems necessary for the adequate protection and utilization of the reservation. Thus, a license cannot be issued unless the federal land managing agency is satisfied that the project will not interfere with the land managing agency’s management iz FLG NOI Comments at 21. 16 U.S.C. § 797(e); e.g., El Dorado Irrigation Dist., 117 FERC § 62,044 (2006). 16 U.S.C. § 797(e). RB Ik ED plan. The vast majority of licensed projects occupying a federal reservation occupy National Forest or BLM lands, which are managed for multiple uses.22 Indeed, FLG’s analysis of multiple, non-project uses on federal lands at its members’ projects—which appears in Attachments E and F*®—demonstrates that at a substantial majority of projects, the hydroelectric project does not detract at all from the land managing agency’s ability to manage its lands for non-project purposes in accordance with its statutory requirements and management plans. To the contrary, these projects are an integral part of the achievement of the agency’s management objectives, which enhances public access consistent with those objectives and even makes possible recreational opportunities and access that would not exist if the project did not exist. Second, there is no basis for the NOPR’s assumption that all federal lands within licensed projects are physically encumbered by the project at the 50 percent level. The information presented in Attachment E72 demonstrates plainly that federal lands are physically encumbered only to the very limited extent that generation and transmission facilities preclude any other use of the lands. Such lands constitute a miniscule portion of the vast federal acres that are often included within project boundaries.* 22 Indeed, in Federal Power Commission Order No. 560, where the Commission established the charge for transmission line lands based on a 50 percent encumbrance, it observed that “the physical nature of a transmission line and its appurtenant structures makes the lands utilized as right-of-way especially susceptible to multiple use.” Order Prescribing Amendment to Section 11.21 of the Regulations Under the Federal Power Act, Order No. 560, 56 FPC 3860, 3866 (1976). 28 Attachment E: Encumbrance Analysis for FLG Member Federal Project Lands; Attachment F: Federal Project Lands and Waters Closed to the Public for Safety and Security Reasons. 2 See FLG NOI Comments at 21-27 and Attachment E. 30 Attachment F: Federal Project Lands and Waters Closed to the Public for Safety and Security Reasons. =13< Third, unlike the permitted uses subject to fees under the 2008 BLM Method, such as “fiber optic lines, pipelines, roads, and ditches”! and Commission-issued certificates for natural gas pipelines that cross federal lands, hydropower licensees are required to be licensed in a manner that meets a variety of public interest objectives—all at the expense of the licensee. This includes recreation, fish and wildlife protection and enhancement, cultural resources management, water supply, irrigation, and numerous other public benefits.*2 While FLG acknowledges the benefits its members receive from their licenses, the Commission’s annual charges program should recognize the immense public benefits provided by licensees by reducing the encumbrance factor in its annual charges calculation.*2 Lastly, the Commission’s own license articles specifically contemplate and accommodate many other, non-project uses of the federal lands they occupy, consistent with the use of project lands, waters, and facilities for various other uses by the land managing agency and third parties, including siting of energy facilities and other utility and transportation infrastructure, placement of agency fish and wildlife enhancement facilities and changes in project operations to accommodate such actions.*# The NOPR states that the public benefits provided by hydropower licensees, such as Commission-required recreation facilities, cannot completely offset the rental fee for the use of federal lands.2= FLG agrees. However, the evidentiary submissions 4. BLM Final Rule, 73 Fed. Reg. at 65,040. 2 See 16 U.S.C. §§797(e), 803(a). Indeed, it is inappropriate for the Commission to use the same encumbrance factor as BLM, when ROW permittees are not required to provide recreation facilities or other public benefits as contemplated under the FPA. 34 See FLG NOI Comments at 28-29. 3 NOPR at P 58. Is 33 -14- discussed above demonstrate that an encumbrance factor of 50 percent is unsupportable and unreasonable. Also, discontinuing the practice of doubling the charges for non- transmission line lands does not, as the NOPR asserts,** constitute appropriate recognition of the multiple non-hydropower uses of project lands. Rather, such discontinuation merely recognizes the long-incorrect assumption that non-transmission line lands are encumbered to the exclusion of all non-hydropower uses. For these reasons, the Commission must use an encumbrance factor substantially lower than 50 percent for all project lands. FLG recognizes that every project involves some degree of encumbrance, however slight, and that the degree of encumbrance may vary based on project location, type and location of project works, and individual license requirements. Based on the information and analyses prepared by FLG, the final rule should adopt a 30 percent encumbrance factor, rather than the 50 percent proposed in the NOPR. 3: Use a Single State-Wide Average Land Value for Projects in Alaska FLG strongly supports the Commission’s proposal to use an average per-acre land value by county instead of the zone system employed in the 2008 BLM Rule. Such an approach will yield a much more accurate estimate of federal land values, thereby allowing the Commission to meet its obligation to assess reasonable annual charges. The NOPR does not specifically address, however, how the Commission proposes to deploy the NASS Census data in Alaska, as Alaska has no counties, and the NASS Census data is not compiled by boroughs. Rather, the NASS Census defines five separate Alaska mais “areas.”*2 To add to this uncertainty, the 2008 BLM Rule uses the NASS Census data in Alaska, but redefines the boundaries of these “areas.”*® So, as an initial matter, the Commission in its final rule should clarify how it intends to apply the NASS Census data in calculating annual charges for hydropower projects in Alaska. More fundamentally, FLG does not believe that any division of Alaska into “areas” would produce annual charges that reflect a reasonable estimate of FMV. To begin with, there simply is insufficient data in any individual Alaska “area” to produce a fair estimate of land values within the area. Unlike the Continental United States, very few farms (and associated acreage) contribute to the NASS Census, as demonstrated in Table 1. Table 1 Comparison of Alaska Area NASS Census Data with Other States # of Farms # of Acres Alaska- statewide 686 881,585 Aleutian Islands 35 693,611 Anchorage 278 38,391 Fairbanks 212 110,780 Juneau a7 514 Kenai Peninsula 124 38,289 Washington- statewide 39,284 14,972,789 Snohomish County 1,670 76,837 Cowlitz County 481 30,702 Grant County 1,858 1,087,952 Yakima County 3,540 1,649,281 Oregon- statewide 38,553 16,399,647 Klamath County 1,207 675,127 Clackamas County 3,989 182,743 Baker County 688 711,809 2 See 2007 Census of Agriculture, Vol. 1, Ch. 2, County Level Data, Alaska, available at http://www.agcensus.usda.gov/Publications/2007/Full_Report/Volume_1, Chapter_2 County Level/Alaska/akrefmap.pdf. 38 BLM Final Rule, 73 Fed. Reg. at 65,044. -16- Columbia County 805 57,758 California- statewide 81,033 25,364,695 El Dorado County 1,268 107,080 Humboldt County 852 597,477 Kern County Z117 2,361,765 Placer County 1,488 132,221 Siskiyou County 846 597,534 Idaho- statewide 25,349 11,497,383 Butte County 222 121,176 Jefferson County 826 325,380 Washington County 594 417,092 Kootenai County 826 130,851 As demonstrated in Table 1, even though Alaska’s land mass is approximately one-fifth the size of the entire Continental United States, it has by far fewer farms and acreage represented in the NASS Census than any other state in the Pacific Northwest. The paucity of data for any single Alaska area renders the area-specific data in the NASS Census an inherently unreliable FMV estimate for federal lands at hydropower projects. For example, the “Kenai Peninsula Area” under the NASS Census occupies an area of approximately 37,000 square miles—about half the size of Washington State. Yet, the NASS Census includes only 124 farms occupying 38,289 acres in this area. By contrast, the NASS Census includes 39,284 farms in Washington State, covering nearly 15 million acres. In Snohomish County alone—an area 1,575 percent smaller than the Kenai Peninsula Area—the NASS Census includes 1,546 more farms, covering 38,548 more acres (i.e., twice as many acres) as the Kenai Peninsula area. In addition to this, neither the NASS Census designation of Alaska areas, nor the 2008 BLM Rule’s adjustment of these areas, would produce reasonable annual charges for hydropower projects. If the final rule were to use the Alaska areas as defined by the NASS Census, all projects in Southeast Alaska would incur crippling annual charges— “NF = particularly because these small projects serve sparsely populated community loads in isolated, rural areas of the State. This increase, which is attributable to the extraordinarily high $54,518 per-acre land value in the “Juneau Area” (that encompasses the entire Southeast under the NASS Census), is demonstrated in Table 2. Table 2 Fee Increases in Southeast Alaska Under the NASS Census “Juneau Area” 2012 Annual Charge : 2011 Annual Charge Project No. (NOPR Methodology, u (FERC 1987 Methodology) NASS Census Map) 2230 $18,544 $1,942,853 2818 $14,591 $1,528,650 2911 $21,869 $2,291,185 3015 $21,731 $2,276,793 The 2008 BLM Rule’s approach apparently attempted to limit the applicability of the more extreme land values in the NASS Census “Aleutian Islands Area,” “Anchorage Area,” and “Juneau Area” by redefining—and significantly reducing—the geographic boundaries of these areas.*2 While this approach does limit the more extreme land values of the NASS Census to smaller areas, it has the negative consequence of placing nearly the entire State of Alaska—and, to FLG’s knowledge, al/ areas where hydropower projects are located—into a single area: the Kenai Peninsula Area“? Application of the Alaska areas as defined by the 2008 BLM Rule, therefore, would have the unintended consequence of using a limited dataset collected in a relatively small area of the State, 32 Under the BLM rule, the Aleutian Islands Area is limited to the Aleutian Islands Chain; the Anchorage Area is limited to the corporate limits of the Municipality of Anchorage; and the Juneau Area is limited to downtown Juneau. BLM Final Rule, 73 Fed. Reg. at 65,044-45. 4° Under the BLM rule, the Fairbanks Area consists of all lands within the BLM’s Fairbanks District. Id. FLG is unaware of any Commission-licensed projects in central and northern Alaska. =18- and applying that data to the entire State—while ignoring the rest of the NASS Census data collected in Alaska. For these reasons, the best approach for applying the NASS Census data to the Commission’s final rule would be for the Commission to adopt a single per-acre rate that applies to the entire State of Alaska—using data collected throughout the State. This approach would better reflect the diversity of sub-climates and topography throughout the State. Such an approach also would rely on a greater number of farms and acreage than any single Alaska “area” under either the NASS Census or the 2008 BLM Rule approach for dividing the State. Fortunately, the NASS Census already includes an average per- acre value for the State—which is included in the exact same table as the county-level data for other states. Thus, adopting a single per-acre rate for the entire State of Alaska would not impose any additional administrative burden on Commission Staff and would result in a more accurate estimation of FMV. Such an approach also would be consistent with the Commission’s current practices for calculating annual charges in Alaska, as FLG understands that the Commission currently has a single zone rate that applies throughout the State. 4. Institute a One-Year Phase-In Period for New Fee Schedule In the NOPR, the Commission declined the recommendation of numerous commenters on the NOI to adopt a short phase-in period for the generally higher rates that would result from adoption of a new methodology“! However, there can be no question that a phase-in period is well justified, as federal land fee charges will increase significantly, given that land fees under the currently applicable regulations have 41 NOPR, 137 FERC § 61,139 at P 44. HT oe remained unchanged since 1987. Indeed, if the Commission were to adopt a final rule as proposed exactly in the NOPR, FLG group members’ fees would increase as stated in Table 3. Table 3 Increase in Annual Charges in First Year of NOPR Implementation Project No. = (FERC 1 er Caio noe Percent Increase Methodology) 20 $22,733 $11,878 -47.75% 184 $171,649 $507,396 195.60% 308 $364 $305 -16.37% 477 $4,053 $21,570 432.27% 553 $1,049,022 $4,717,868 349.74% 935 $8,321 $40,015 380.88% 943 $490 $5,354 992.64% 1744 $689 $1,824 164.69% 1862 $1,009 $5,788 473.59% 1927 $96,236 $193,421 100.99% 2016 $3,598 $8,267 129.74% 2030 $98,221 $62,121 -36.75% 2071 $12,315 $59,221 380.88% 2082 $14,530 $26,523 82.54% 2101 $344,545 $1,092,748 217.16% 2111 $21,633 $69,289 220.30% 2144 $38,535 $62,085 61.12% 2145 $2,960 $26,140 783.08% 2150 $231,253 $940,242 306.59% 2157 $209,421 $823,085 293.03% 2195 $137,431 $727,965 429.70% 2230 $18,547 $47,290 154.98% 2242 $31,241 $91,811 193.88% 2299 $361,292 $357,151 -1.15% 2381 $25 $25 0% 2705 $359 $1,606 347.23% 2743 $48,375 $124,376 157.11% 2818 $14,706 $37,208 153.02% ® For projects in Alaska, this chart assumes that FERC will use the Alaska “areas” as defined in BLM’s Final Rule. 220i- Project No. il (FERC 1 a7 i Teron Percent Increase Methodology) 2842 $447 $437 -2.20% 2911 $20,142 $55,769 176.88% 2952 $95 $139 46.84% 3015 $17,553 $55,418 215.73% 5264 $1,533 $8,563 458.74% 6842 $65,666 $68,587 4.45% 8436 $1,006 $1,860 84.81% 8221 $62,623 $159,696 155.01% 10888 $403 $3,278 713.18% Total $3,113,020 $10,416,320 234.60% As demonstrated by the table, FLG members will incur, on average, an increase of nearly 235 percent in the first year of the NOPR’s implementation—with individual increases of nearly 1,000 percent. These are substantial increases that will require licensees to make fiscal adjustments in order to pay. For this reason alone, a phase-in 25 percent reduction in annual charges for the first year of the final rule’s implementation is warranted. This approach, moreover, would be exactly consistent with the Commission’s actions in Order No. 469 and the 2008 BLM Rule. In Order No. 469, the Commission recognized that the transition year bills would be onerous unless phased in over time* Similarly, the 2008 BLM Rule noted that almost all commenters favored some type of phase-in provision to allow sufficient time to absorb the additional fee increases.“ In response, BLM allowed a one- year phase-in period consisting of a reduction of the per acre rent by 25 percent to ease the burden of the new fees.*® It also provided for a limited two-year phase-in period if i is “= Order No. 469 at p. 30,591. BLM Final Rule, 73 Fed. Reg. at 65,060. Id. ie ie Die payment of the new rent caused the entity undue hardship and it is in the public interest to approve the phase-in period.“® Given the immense increase in annual fees contemplated by the NOPR, the Commission should follow its own precedent and BLM’s recent actions by implementing a one-time, phase-in 25 percent reduction in annual charges for the first year in which the final rule becomes effective. 5, Clarify Policy on Valuation for Projects in Multiple Counties FLG requests the Commission to clarify that where federal lands at a licensed project occur in two or more separate counties, the Commission will calculate the annual charge on a county-by-county basis. FLG understands that for projects occupying federal lands in multiple counties, the Commission currently uses the highest zone value for all federal acreage, unless the licensee provides Commission staff a listing of the federal acres in each county. Now that the Commission proposes to use county-level NASS Census data (and not a zone system), FLG requests the Commission’s final rule to provide that the Commission will allocate federal acreage according to the specific county as a matter of course. V. PROPOSED REVISIONS TO REGULATORY TEXT Finally, FLG believes that the Commission’s proposed revisions to its regulations set forth in the NOPR do not precisely capture the proposed new methodology for valuing federal hydropower lands. Because the NOPR proposes to adopt a precise methodology—and not simply to mimic BLM’s methodology as it could change over time*2—FLG has drafted recommended regulatory text that clearly and specifically describes the method the Commission will use to assess annual federal land use charges Id. {2 See City of Idaho Falls v. FERC, 629 F.3d 222 (D.C. Cir. 2011). -22- based on FLG’s proposed modifications, including the phase-in period and the average per-acre valuation for Alaska projects. Regardless of what specific components the Commission ultimately decides to include in the final rule, the regulation text should very specifically describe the method that will be applied. FLG’s recommended regulatory text appears below: In consideration of the foregoing, the Commission amends Part 11, Chapter I, Title 18, Code of Federal Regulations, as follows: PART 11 —- ANNUAL CHARGES UNDER PART I OF THE FEDERAL POWER ACT 1. The authority citation for part 11 continues to read as follows: Authority: 16 U.S.C. 791a-825r; 42 U.S.C. 7101-7352. 2. Amend section 11.2 by revising paragraph (a) to read as follows: “(a) Reasonable annual charges for recompensing the United States for the use, occupancy, and enjoyment of its lands (other than those lands adjoining or pertaining to Government dams or other structures owned by the United States Government) or its other property will be fixed by the Commission. Such charges shall reasonably reflect the fair market value of the lands or other property used or occupied by the licensed project.” 3. Amend section 11.2 by revising paragraph (b) to read as follows: “(b)(1) Annual charges for the use of government lands will be payable in advance, and will, for all federal lands other than lands in Alaska, be calculated using the following formula: Annual Per-Acre Rent = (50% of U.S. National Agricultural Statistics Service Census Average County Agricultural Land and Buildings Value) x (30% encumbrance factor) x (5.27% rate of return, which is the 1998-2008 average of the 30-year and 20-year Treasury bond yield rates) x (the average annual change in the Implicit Price Deflator-Gross Domestic Product for the 10- year period immediately preceding the year that the NASS Census data becomes available.) (b)(2) Annual charges for the use of government lands in Alaska will be calculated using the following formula: WOR. Annual Per-Acre Rent = (50% of the U.S. National Agricultural Statistics Service Census Alaska State Average Agricultural Land and Buildings Value) x (30% encumbrance factor) x (5.27% rate of return, which is the 1998-2008 average of the 30-year and 20-year Treasury bond yield rates) x (the average annual change in the Implicit Price Deflator-Gross Domestic Product for the 10- year period immediately preceding the year that the NASS Census data becomes available.) (b)(3) The Commission, by its designee the Executive Director, will update its fees schedule annually, to reflect the application of the annual adjustment factor, changes in land values established by the U.S. National Agricultural Statistics Service Census, and update the annual adjustment factor, as provided in Paragraphs (b)(1) and (b)(2). The Executive Director will publish the updated fee schedule in the FEDERAL REGISTER.” 4. Amend section 11.2 by revising existing paragraphs (c)(1) and (c)(2) to read as follows: “(c)(1) Ifa licensed project occupies federal lands in two or more counties, the formula for set forth in paragraph (b)(1) shall be applied separately to the federal lands in each county. (c)(2) Annual federal land use charges for the first fiscal year in which the formula set forth in Paragraphs (b)(1) and (b)(2) is effective shall be reduced by 25 percent.” 245 VI. © CONCLUSION WHEREFORE, for the reasons set forth above, FLG requests that the Commission consider its comments set forth above, and adopt its proposed revisions to Title 18 of the Code of Federal Regulations. Dated: January 6, 2012 Respectfully submitted, (MARGL Charles R. Sensiba_) John H. Clements Sharon L. White Van Ness Feldman, PC 1050 Thomas Jefferson Street, N.W. Seventh Floor Washington, DC 20007 Telephone: (202) 298-1800 Facsimile: (202) 338-2416 Counsel to the Federal Land Use Charges Group at25 = ATTACHMENT A Qualitative Assessment of Agricultural Feasibility of FLG Member Federal Project Lands ATTACHMENT B Woodland Crop Sales as a Percentage of Total Agricultural Sales in Counties Where FLG Member Projects Are Located ATTACHMENT C NASS Census County Farm Land and Building Values Compared to BLM-Adjusted Values, FLG Proposed Adjusted Values, and NASS Survey Pastureland Values ATTACHMENT D NASS Pastureland Annual Rental Charges Versus Forest Service Fee Schedule Rental Charges ATTACHMENT E Encumbrance Analysis for FLG Member Federal Project Lands ATTACHMENT F Federal Project Lands and Waters Closed to the Public for Safety and Security Reasons ATTACHMENT G Federal Energy Regulatory Commission Chart of U.S. Federal Lands by Licensee Project, State, Counties, Acres Alaska Energy Authority 813 West Northern Lights Boulevard Aiichorage, AK 99503 907-771-3000 September 2, 2011 Via Electronic Submittal (eFile) Honorable Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 Subject: Initial Consultation Document for a Non- Capacity Amendment to the Bradley Lake Project: Proposed Battle Creek Diversion and Notice of Joint Meeting to Be Held September 20, 2011 FERC Project No. 8221 Dear Secretary Bose: The Alaska Energy Authority (AEA) owns the Bradley Lake Hydroelectric Project (FERC No. 8221). AEA is proposing a new water diversion system on Battle Creek as a supplemental source of water for Bradley Lake, the Project reservoir. Battle Creek is located approximately two miles west of Bradley Lake, near the head of Kachemak Bay and approximately 20 miles east of Homer, Alaska. AEA intends to file an Application for a Non-Capacity Amendment to the Bradley Lake Project (P-8221) in accordance with 18 CFR §4.201. AEA’s proposal will provide a supplemental water source for the Bradley Lake Project by diverting water from the adjacent Battle Creek watershed, but will not modify the Project’s installed capacity, maximum hydraulic capacity, or installed nameplate capacity. Pursuant to 18 CFR §4.38(a)(6), a three-stage consultation process is required for non-capacity license amendments involving the construction of a new dam or diversion. AEA notes the intent of 18 CFR §4.38(a)(7) and related regulations and will provide for substantive three-stage consultation with agencies and other stakeholders. During consultation with agencies, AEA may identify opportunities for, and request waiver of, portions of the three-stage consultation process. With this Initial Consultation Document (ICD), AEA is initiating first-stage consultation for a proposed non-capacity license amendment application for the Bradley Lake Project. AEA’s proposal would allow the construction, operation, and maintenance of a new diversion system on Battle Creek and a cross-basin transfer of water to Bradley Lake for use in normal operations. No changes to the authorized operational range or licensed reservoir elevations at the Bradley Ms. Kimberly D. Bose, Secretary Federal Energy Regulatory Commission September 2, 2011 Page 2 Lake Project are proposed. The new diversion system and all associated structures would be entirely on lands managed by the Alaska Department of Natural Resources (ADNR). The proposed road access may connect with an existing road on Bureau of Land Management (BLM) lands already reserved for hydropower operation under the existing Bradley Lake License. JOINT MEETING AND SITE VISIT This transmittal also serves as notice to FERC of an agency site visit on September 20, 2011. The required Joint Meeting will also be held from 3:00 — 5:00 pm (Alaska Daylight Time), following the site visit. AEA consulted with agencies more than 30-days prior to the site visit date to ensure their availability. The Joint agency and public meeting also will be held September 20, 2011 in Homer, Alaska to provide information and receive public input regarding AEA’s proposal to amend the license for the Bradley Lake Hydroelectric Project. Joint Meeting details include: Tuesday, September 20, 2011 3:00 — 5:00 pm. Homer Electric Association Board Room 3977 Lake Street Homer, AK 99603-7680 The agenda for the Joint Meeting is to discuss information in the ICD and to receive feedback from resource agencies and members of the public on the proposed amendment. Information to be presented includes: energy benefits of the proposed project, project details including proposed diversion and new road access locations, hydrology of the basin, baseline information on fisheries downstream of the proposed diversion, and potential environmental effects of the proposed diversion system, including effects of reduced flows on stream habitat and effects of project construction and operation on terrestrial wildlife and wetland habitats. INITIAL CONSULTATION DOCUMENT DISTRIBUTION AEA will make the ICD available to all interested parties by: e providing electronic notice to the attached distribution list of the document’s availability on the www.ferc.gov website e making a hardcopy available to the public during regular business hours at AEA’s place of business: Alaska Energy Authority 813 West Northern Lights Boulevard Anchorage, AK 99503 Ms. Kimberly D. Bose, Secretary Federal Energy Regulatory Commission September 2, 2011 Page 3 ® making a hardcopy available at the following public library in the Project region: Homer Public Library 500 Hazel Avenue Homer, AK AEA will also submit for publication a notice of the availability of the ICD and notice of a public meeting in the following newspapers of general circulation: * Anchorage Daily News = Homer Tribune = Homer News Affidavits of publication will be provided to FERC following publication. Questions regarding this transmittal or availability of the ICD may be directed to Mr. Bryan Carey, AEA Project Manager, at 907-771-3000. Sincerely, /s/ Bryan Carey Project Manager co: Steve Hocking, FERC Project Coordinator FERC Project No. 8221 Battle Creek Distribution List (via electronic mail) FERC Project No. 8221 Service List (via electronic mail) Ms. Kimberly D. Bose, Secretary Federal Energy Regulatory Commission September 2, 2011 Page 4 Anderson, Jeff U.S. Fish and Wildlife Service _| jeffry_anderson@fws.gov Bristol, Tim Trout Unlimited tbristol@tu.org Carey*, Bryan AEA dcarey @aidea.org Coumbe, Mike _| Alaska Conservation Alliance | mike@akvoice.org Gates, Kenneth USFWS Kenneth Gates@fws.gov _ Kahn, Lynnda U.S. Fish and Wildlife Service _| Lynnda_Kahn@fws.gov Kenai USACE Kenai USACE cepoa.co.t.s.k@usace.army.mil Kerkvliet, Carol ADFG carol.kerkvliet@alaska.gov Klasner, Fritz National Park Service fritz_klasner@nps.gov Klein, Joseph ADFG -Klei OV Konigsberg, Jan lydropower Reform Coalition | jan@hydroreform.org Hy BLM Lee Koss@blm.gov Koss, Lee Litchfield, Virginia P ADFG _| ginny. litchfield@alaska.gov Inletkeeper sue@inletkeeper.org ADFG thomas.mcdono jaska.gov Meyer, David F USGS dfmeyer@usgs.gov Miller, Monte ADFG monte.miller@alaska.gov Mohorci, John Kenai River Center jmohorci@borough.kenai.ak.us i c/o susan. walker@noaa.p Mouw, Jason E B ADFG jason.mouw@alaska.gov United States Environmental | North, Phil Protection Agency north. phil@epa.gov O'Meara, Michael Sierra Club mikeo@horizonsatellite.com Opheim, Michael Seldovia Village Tribe Rome k Otis, Ted ADFG p Plett, Kristina A _| ADNR Prokosch, Gary ADNA Rothwell, Eric NOAA Selinger, Jeff | ADF&G Shavelson, Bob Inletkeeper Thrall*, Jim Consultant thrallinak@yahoo.com Walker, Susan NOAA susan. walker@noaa.gov * Indicates parties on the FERC Service List for P-8221 Initial Consultation Document for Amendment to Bradley Lake Project (FERC No. 8221) Proposed Battle Creek Diversion Submitted by Alaska Energy Authority 813 West Northern Lights Boulevard Anchorage, AK 99503 September 2011 Battle Creek Diversion Initial Consultation Document Table of Contents Acronyms and Abbreviations 1.0 Introduction and Background.. 1.1 Project Location D2, | | Project Sumitnary oo ssss-s-5:cccsccevesosscsconsacsesuesosscsavasuvettecvassteenstaecesirctevesssteudeabexeses 1-1 2.0 License Amendment Process and Schedule.............scsssssssssssssessssssseressnessscseosesesssses 2-1 2.1 Amendment Process and Schedulle...............ssssssssscesssssssssssssesseseesssesnesssaseasene 2-1 2.2 Summary of Consultation to Date 2.3 Expected Application Contents and License Modifications . 2.4 Other Permitting Efforts 3.0 Proposed Action........... essasaceseteneseses¥inesscesersn onsdoueudsissbsostusoenbdetectosceheossbonre ssedsssssueseceevee 3-1 3.1) “Existing Project Description ..cciccccsccitcccesessesooensvesssscvenssnssneteteersssstteassoocrecescene 3-1 3.2 | New Project Features. coiscsccsssisscsesscescanssuresssssonsossnescartivsztecaschunsacessssbeusenssussunseee 3-1 3.2.1.Primary Battle Creek Diversion... 3.2.2.Secondary Diversion... 3.2.3.Access Roads 3:24. Conveyance Structtes cc ssecscestcccusnsasssesorcdsscoespavessescescoseascsansesvetsveers 313 Project Operations oo... eo. ..sscsscsnssessseesescesesosnsseasoutssarcansusssassancsusvenssssarosesosensas 3.3.1.Proposed Diversion Operations 3.3.2.Energy Generation Changes 4.0 Affected Environment 4.1 Description of Project Locale di. .sc.ccc<c:scscsscsessoseaveseccatisuatesecoscossssoesssosdsssssetscoeea 4-1 4.2 Geology and Soils ...ccccessssssssscsesesesecssssssecesesesesessssenesesssssssssseenstsnsnensesseeaseees 4-1 4.3 Water Resources.......s.scscesssssssssesesesesesssssssnsesesssnsnsesesssnssnscaeecensceesnenseseeeseseeseses 4-1 4.3.1.Water Rights 4.3.2.Hydrology .. 4.3.3, Water Quality... esseeeee 4-8 4.4 Fish and Aquatic Resources ........sscssssssssssesessssesessssssessnsnsessneeseeesssneseseeaentessess 4-9 AA 1 Sturdy Area cssssccscosssecosssesvetsnssvonsestvonssussstsosscsssesanvasetvesatastedesesesencsians 4-10 4.4.2.Habitat 4.4.3.Resident and Rearing Fish Presence and Distribution... Battle Creek Diversion Initial Consultation Document 4.4.4.Spawning Timing and Distribution estimates for Salmoniand Dolly’ Vatd61ts..:..-.-.cscfsssclssssscvessesuscsonsvesssusiccusevacossesnses 4.4.5.Macroinvertebrate diversity and abundance... 4.4.6.Stream channel geometry... ; 4.5 Wildlife and Botanical Resources 4,5.) Botatiical ReSOUnCOS sisi ssssscsthssscccessscassssosenptevancteitbsascisavessssarosssceses 45-2. Wildlife RESQUICES.......2t.rssecitssoreconsonsesasoresttsitenttleritveriecsareesnsusnsasese 4.6 Threatened, Endangered, and Candidate Species............:cccsccecesesesesteeseeees 4.7 Historical and Archaeological Resources. 4.8 Recreation, Land Use, and Aesthetics... 4.8.1.Recreation Ns ee iielnielin 4B 3 ACSC csc scscss sccsrcacsigosssrestesasevesoscscscascsSvesersesadepeserseliaeesoterszezeense 4.9 Subsistence Resources and SOciOeCONOMICS........ccsessseseseesteeeeseeesecesesessenees 4.9.1.Subsistence Resources .... 4.9.2.Socioeconomics 5.0 Potential Effects and Anticipated Studies..............ccssssesssssssesessensssecceeeeenesnessenseees 5.1 Potential Resource Eiects. sz sascsccieccecscssocsssscccososevsasnseveeepssaceusvsnstgsiviccsnecuensaveoss 5.2 Proposed atid Ongoing Studies..4.....-cgsssnssersssersenssssesncossnsestobassessreesesetoeserseseoed 5.2.1.Fish and Aquatic Studies ... 5.2.2.Terrestrial Studies ... 5.2.3.Cultural Resources Studies .... 6.0 References.......cccrcrsscrcscsecrovorosrersoerseosererorsevoeceseresororeroesseserevecececesorcesecesesesesesesoseceseccsees Om, ii Battle Creek Diversion Initial Consultation Document List of Tables Table 2-1. Anticipated schedule for the Battle Creek Amendment process..............+2++++# 2-1 Table 4-1. 2010 USGS stream gage discharge measurements, measured manually by the USGS on specified Ipates <..cccssc.sscreicecetcsscstscopsecescaconscscssesootucoses 4-2 Mable 4-2.) Waterson CHAPACeriStiCe .c.cscctececsecscqseececsssscerovesencesacarccsescseovseeces sgevereeasrecsetesetes Table 4-3. Battle Creek Water Quality Data, 1980 Table 4-4. Battle Creek Water Quality Data, August 30 — September 1, 2010... Table 4-5. Mesohabitat type and description used to classify habitat units on Battle Creek during the September survey (adapted from the USDA Forest Sety ice 2001). crasecssesssccorscsoesocesnsseoncssesseseieestincstedeeescnecvatseutrestsars 4-12 Table 4-6. Taxa metrics of Surber subsamples collected in representative riffles by reach in Battle Creek, August 31, 2010. Table 4-7. Macroinvertebrate taxa of Surber subsamples collected in representative riffles by reach in Battle Creek, August 31, 2010... 4-20 Table 4-8. Vegetation types that may be affected by construction and operation of the proposed diversion and access road.... Table 4-9. Riparian vegetation types in lower Battle Creek Table 4-10. Terrestrial and freshwater birds known to occur in the area as of 1982 (selected from APA 1984, Table E 3.4-1). ...csssssssessessssessesseseesssseesens 4-24 Table 4-11. Mammal species known or likely to occur in the project area. ..........sessessesses 4-27 Table 4-12. Potential bird and mammal habitat in the Battle Creek Diversion ZPE...........4-29 Table 4-13. Population demographics of communities near Homer, Alaska. ...........--++0++++ 4-32 Table 5-1. Initial list of potential project effects related to the Battle Creek Diversion. amendment to the Bradley Lake Project license. .............::sssssssssesssssesssseseeeeeeeses 5-1 List of Figures Figure 4-1. Project vicinity and fisheries and aquatics study reaches. ..........:sscsssssserseseeseeseee 4-3 Figure 4-2. Subwatersheds in Battle Crock si......:csssccscsstssnscesccss-ossssssctsssasassncttrectessesenenssnsnesnss 4-5 Figure 4-3. Mean Daily Discharges for Battle Creek Gages, 1992-1993........s.ssseseesesesneeeee 4-7 Figure 4-4. Mean Daily Runoff for Gaged Watersheds, 1991-1993. ........ssssessesnesnseneeneeneene 4-7 Figure 4-5. Estimated Mean Flows at approximately 2,100 feet elevation. Estimated flows added to the gaged flows are shown in blUC..........::::::s:ssssse+0+ 4-8 Figure 4-6. Length frequency histogram for coho salmon (n=53) in Battle Creek during the July to September 2010 field events...........s:sessssessererseseseees 4-15 iii Battle Creek Diversion Initial Consultation Document Figure 4-7. Average sample composition of five Surber subsamples collected in representative riffles by reach in Battle Creek, August 31, 2010.0... 4-18 Figure 4-8. Average population densities of five Surber subsamples collected in representative riffles by reach in Battle Creek, August 31, 2010..............00+ 4-18 Figure 4-9. Average taxa richness of five Surber subsamples collected in representative riffles by reach in Battle Creek, August 31, 2010.0... 4-19 Figure 4-10. ADF&G Game Management Unit in the project Vicinity. .........ccccssesseseees 4-28 List of Appendices Appendix A. Diversion Location Appendix B. Area Photos Battle Creek Diversion Initial Consultation Document Acronyms and Abbreviations ADCP Acoustic Doppler Current Profiler ADF&G Alaska Department of Fish and Game ADLWD Alaska Department of Labor and Workforce Development ADNR Alaska Department of Natural Resources AEA Alaska Energy Authority APA Alaska Power Authority AWC Anadromous Waters Catalog BLM Bureau of Land Management BOF (Alaska) Board of Fish Cc Celsius cfs Cubic feet per second DEIS Draft Environmental Impact Statement DO Dissolved oxygen EPT Ephemeroptera, Plecoptera and Trichoptera ESA Endangered Species Act FERC Federal Energy Regulatory Commission FR Federal Register GMU Game Management Unit GWh Gigawatt Hour ICD Initial Consultation Document LWD Large woody debris Battle Creek Diversion Initial Consultation Document MW SHPO USACE USFS USFWS USGS ZPE Megawatts Milligrams per liter Millimeters Nephelometric turbidity unit River mile State Historic Preservation Officer U.S. Army Corps of Engineers USS. Forest Service U.S. Fish and Wildlife Services U.S. Geological Survey Zone of Potential Effect vi Battle Creek Diversion Initial Consultation Document 1.0 Introduction and Background The Alaska Energy Authority (AEA) owns the Bradley Lake Hydroelectric Project (FERC No. 8221), which is operated on behalf of AEA by Homer Electric Association. AEA is investigating a new water diversion system on Battle Creek as a supplemental source of water for Bradley Lake. Battle Creek is located approximately two miles west of Bradley Lake, near the head of Kachemak Bay and approximately 20 miles east of Homer, Alaska. 1.1. Project Location The location of the proposed new Battle Creek diversion system is in Sections 17, 18, 19 and 20 of TSS ROW, Copper River Meridian, as shown in Appendix A, Figure 1. In this figure, the general location of the diversion system is indicated by dashed red lines; access road corridor and conveyance corridor are each shown by dashed blue lines. Appendix B provides photographs of Battle Creek from its mouth at the tidewater area upstream to the general area in which diversion structures would be installed. 1.2 Project Summary With this Initial Consultation Document (ICD), AEA is initiating first-stage consultation for a proposed non-capacity license amendment application for the Bradley Lake Project. AEA’s proposal would allow the construction, operation, and maintenance of a new diversion system on Battle Creek and a cross-basin transfer of water to Bradley Lake for use in normal operations. No changes to operations or licensed reservoir elevations at the Bradley Lake Project are proposed. The new diversion system and all associated structures would be entirely on lands managed by the Alaska Department of Natural Resources (ADNR). The proposed road access may connect with an existing road on Bureau of Land Management (BLM) lands already reserved for hydropower operation. With the exception of this existing road, no federal reservations would be affected by this proposal. AEA’s proposal currently includes the following elements, which may be adjusted during stakeholder consultation and additional field investigations: © Construction and operation of a primary concrete diversion and intake structure on Battle Creek, including a main diversion dam 20-30 feet high and 55-75 feet long; ° Construction and operation of up to approximately 2.2 miles of main water conveyance, including a combination of open-channel, pipe, and tunnel structures; e Construction and operation of secondary diversion, intake, and control structure at a drainage channel along the main conveyance route; e Construction of approximately 1.5 miles of new diversion access road, constructed from the terminus of the access road to the existing Upper Battle Creek Diversion structure (a current component of the Bradley Lake Project, and the subject of license amendment proceedings in 2004); 1-1 Battle Creek Diversion Initial Consultation Document e Construction of approximately 2.2 miles of conveyance access and maintenance roads. In following FERC regulations requiring three-stage consultation for this effort, AEA intends to fully engage interested stakeholders and provide detailed analysis of the potential effects of the new proposed diversion system in its amendment application. This analysis will focus on the lands and habitats potentially affected by construction, operation, and maintenance of the diversion system, including access roads. Collectively, these areas are referred to as the “Zone of Potential Effect” (ZPE); this ZPE will be refined into a formal amended Project Boundary for the Bradley Lake Project in an amendment application. AEA’s initial list of potential effects within the ZPE that warrant analysis includes the following: © Reduced flows in Battle Creek below the proposed diversion e Temperature changes related to flow e Potential effects from project construction and operation on terrestrial habitats and wildlife e Potential effects from project construction and operation on wetlands e Effects associated with the construction of a new access road These and other potential effects within the ZPE are presented briefly in Section 5 of this document, and will be examined in detail in AEA’s Application for License Amendment for the Bradley Lake Project, which will be submitted in early 2013. 1-2, Battle Creek Diversion Initial Consultation Document 2.0 License Amendment Process and Schedule 2.1 Amendment Process and Schedule AEA’s proposal will provide a supplemental water source for the Bradley Lake Project, but will not modify the Project’s installed capacity, maximum hydraulic capacity, or installed nameplate capacity. FERC regulations 18 CFR §4.38(a)(6) specify a three-stage consultation process for non-capacity license amendments involving the construction of a new dam or diversion, AEA notes the intent of 18 CFR §4.38(a)(7) and related regulations and will provide for substantive three-stage consultation with agencies and other stakeholders in the Bradley Lake Project and the Battle Creek Amendment. Consultation began with agency meetings and aquatic resource and hydrology studies during 2010 and 2011 and is formally initiated by this Initial Consultation Document. Consultation will continue through the three-stage process as outlined by AEA in Table 2-1. The process culminates in AEA’s filing of a non-capacity license amendment application for the Battle Creek Diversion that meets FERC regulations at 18 CFR §4.201. Expected milestones and consultation stages are presented below. Battle Creek Diversion Initial Consultation Document Table 2-1. Anticipated schedule for the Battle Creek Amendment process. Begin pre-filing fisheries, aquatics, and hydrology 2010 studies (completed) en Agency meetings and consultation regarding results of 2010 pre-filing study efforts and to April — July 2011 discuss 2011 studies (completed) First Stage Consultation Submittal and distribution of Initial Consultation Document AEA, Joint agency and stakeholder consultation Stakeholders meeting and site visit Agency and stakeholder comments on ICD due | November 21, 2011 Second Stage Consultation Filing and distribution of Technical Memos December describing results of 2010-2011 pre-filing studies | 2011/January 2012 January 2012 February 2012 September 2, 2011 September 20, 2011 AEA, stakeholders , Stakeholders | Agency and stakeholder consultation meeting Conduct and complete 2012 studies (if necessary) Filing and distribution of Draft Amendment Application stakeholders | Agency and stakeholder consultation meeting August 2012 Stakeholders Comments on Draft Amendment Application September 2012 Third Stage Consultation aca Filing and distribution of Amendment Application; Third Stage Consultation FERC issues License Amendment (estimated) | July 2013 May — August 2012 June 2012 4 3 5 January 2013 2-2 May Clark From: Bryan Carey Sent: Thursday, January 12, 2012 8:42 AM To: May Clark Subject: RE: BPMC - Draft Minutes from 2011 Attachments: ICD Abbrev. pdf Please send out the attached abbreviated Battle Creek Initial Consultation Document. From: May Clark Sent: Monday, January 09, 2012 12:01 PM To: Bryan Carey Subject: FW: BPMC - Draft Minutes from 2011 Importance: High Here are the draft minutes again, I sent them to you on 1/3. Also attached are the motions. (Take off that SuWa hat for a few minutes!) © Thanks! From: May Clark Sent: Tuesday, January 03, 2012 2:27 PM To: Bryan Carey; Linda MacMillan Cc: Kelli L. Veech; Shauna Howell Subject: BPMC - Draft Minutes from 2011 Importance: High Several months have gone by so I am resending you the draft minutes from the two meetings held in 2011 that will be up for approval at our next meeting, which will probably be held this month. Please glance at them again and let me know if there are any corrections before they are sent out in the packets. Thanks, May Clark Administrative Assistant ALASKA ENERGY AUTHORITY mclark@aidea.org 907.771.3074 Bradley Lake BPMC Meeting June 8“ 2011 - January 19%, 2012 Operators Report Unit Statistics: Generation Unit 1 (MWhrs) Unit 2 (MWhrs) Total (MWhrs) Jun. 2011 10,490 10,590 21,080 Jul. 2011 12,590 9,970 22,560 Aug 2011 11,020 10,560 21,580 Sep. 2011 10,880 10,940 21,820 Oct. 2011 9,680 9,720 19,400 Nov. 2011 16,780 9,850 26,630 Dec. 2011 17,810 11,460 29,270 Hydraulics Lake Level (ft) Usage (ac ft) Fishwater (ac ft) Jun. 2011 1111.80 22,399 1,040.0 Jul. 2011 1126.64 23,597 33303.7 Aug 2011 1143.83 22513 4,094.9 Sep. 2011 1165.23 22,149 1,912.5 Oct. 2011 1167.83 19,476 162.8 Nov. 2011 1T61 12 26,877 1,424.5 Dec. 2011 1154.42 30,119 1,216.8 Current Status: Lake level peaked at 1168.09 on October 28th. Lake Level at 1,150.8 as of 1/11/2012. Summer cleaning of road areas proceeded well. Removal of alders and other growth completed two-thirds the way to the dam. We plan on completing the rest this coming summer. The Powerhouse bridge crane has experienced increasing issues with crane speed and brake control. KoneCranes spent a week before the fall outage trying to work through the problems. Numerous problems were found and several cards are bad. Parts had to be borrowed from the auxiliary hoist controls to repair the main hoist. The problems were too extensive to repair at this time due to the lack of spare parts. Presently there is no brake on the auxiliary hook and the brake does not release on the main hook. The main hook has no variable speed control and only has slow single speed drive available. Bradley Lake Operator Report Page 1 e We supported on going work for Battle Creek project, surveying, and fish studies. e We supported USGS stream studies and gauge work. e¢ Completed network and phone upgrades. Installed new network server. e New Personnel in September. Tim Quirk as a new Plant Operator, and Larry Jorgensen as the new Plant Superintendent. ¢ Completed diversion inspections at Nuka, Middle Fork, and Battle Creek with John Magee and Jim Thrall on Oct 10th. No significant issues identified. Jim Thrall conducted training on fish water release using the modified flow limits with the operators as requested by Bryan Carey. e There was a Fish Water Flow deviation on Sept 11th due to improper gage corrections provided by USGS that resulted in the SCADA Lower Bradley River readings indicating low by 15-19cfs. Operators corrected Fish Water Flows. We worked with USGS to correct flow readings. USGS will include the cause of the deviation in their report and it should not result in a violation. e Fall Outage saw replacement of both unit exciters and PSS tuning. The new exciters are performing well and PSS tuning showed the units to be able to respond well to system disturbances. No unusual items were found during the outage and maintenance proceeded as scheduled. ¢ Completed installation of new fiber cable at the dam for the DCS project is in progress. Completed fiber pull between the PT Gate House, DT Gate House, and on to Fish Water Portal. Terminations will be completed with installation of DCS hardware. e A problem was found during the Outage on Unit #1. When the station service transformer was switched out for maintenance, Unit #2 tripped. The tripped showed up as a low governor oil tank level low. In order to reset the level indication, the level had to be drained down to a low level and then restored to normal operating level. We reviewed switching procedures and could not find an issue as the system was designed to withstand short interruption of power. What was found is that when the level indication was updated, it was wired to normal station power not UPS. When power to it was interrupted, it would default to a low level state. The governor controls seeing a low level would then trip the unit. The solution was to rewire the power supply to the level indication from a UPS source. Spare UPS power supply connections were found in the new exciter cabinets, which were used to power the level indications. This change was completed on both units. e Prior to Unit #2 startup, during plant rounds water was found dripping down on the governor oil reservoir. The breather on the top of the reservoir is recessed such that the water was entering the reservoir through it. We pulled the vent and found that the oil was emulsified. We pumped out all the oil into drums and replaced it with new oil we had on site. We put the oil filter with a water filter on the reservoir to clean any remaining water from the system. The oil in the barrels will be cleaned and stored so as to be available for use. Bradley Lake Operator Report Page 2 e On Nov. 9th, USGS stations showed to be iced in. Fishwater valve #5 was opened with a flow of 43.9 cfs indicated. The winter requirement is 40 cfs. e PT Gatehouse UPS system. Parts here to be assembled in spring. e Installed new Cascade maintenance management system. Received training for system setup. Started entering in equipment and maintenance procedures. Based on progress made during December, the PM work orders should be in place and running by the end of January. We will be pulling all the old records from the Mapcom system so it can be moved to the Cascade system over the next few months. e Unit #2 trip on faulty thermal sensing indication on Main Transformer #2. Repaired failed sensing wire and performed RCA. Developed report for reporting future incidents. e Lost phone communications to Barge Dock building. Testing has not found any pairs that are good to the building. Instead of replacing the buried cable, will transition to a wireless network system this spring. e New Trainee program was authorized. Working with HR on pre- employment aptitude testing, GPi Learn setup and Bismarck College program for Operators. e New Operator Union contract ratified. e Working on draft budget for FY 2013. Getting bids and prices from vendors for various projects and items. Bradley Lake Operator Report Page 3 FEET 1190 1180 1170 1160 }-— 1150 -e 1140 |= 1130 1120 + 1110 1100 1090 | 1080 +} 1070 + 1060 —— 04-05 = = = HISTORICAL AVERAGE BRADLEY LAKE LEVEL June 2001 - January 2012 ————='02-03 03-04 05-06 06-07 08-'09 ——= 08-10 10-11 oe 11-12 Homer Electric Association, Inc. A Touchstone Energy" Cooperative ah» pial LARRY JORGENSEN Bradley Lake Hydro Power Plant Soper rmegiient ljorgensen@homerelectric.com Homer Office 3977 Lake Street (907) 235-4401 Homer, Alaska 99603 Cell: (907) 399-1241 www.homerelectric.com Fax: (907) 235-4445 Jeff Warner Acting Chief Power Dispatcher MUNICIPAL LIGHT & POWER orn 201 East First Avenue O nchorage, Alaska MEP SS yh xX 0 © Wane eee Org www.mlandp.com