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HomeMy WebLinkAboutBPMC Meeting May 13, 1993 210. tt. 12; 13. 14. BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE MEETING AGENDA May 13, 1993 Chugach Electric Association, Inc. Training Room 10:00 a.m. CALL TO ORDER 10:00 a.m. ROLL CALL PUBLIC COMMENT AGENDA COMMENTS APPROVAL OF MEETING MINUTES - March 3, 1993 March 30, 1993 April 16, 1993 TECHNICAL COORDINATING SUBCOMMITTEE REPORT BUDGET SUBCOMMITTEE REPORT A. Bradley Lake Construction Cost Audit Update B. Bradley Lake O&M Cost Audit Update AGREEMENTS SUBCOMMITTEE REPORT OPERATION AND DISPATCH SUBCOMMITTEE REPORT REVIEW OF PROJECT STATUS OLD BUSINESS A. Spinning Reserves/Under Frequency Load Shedding Update B. Bradley Scheduling vs. Spin Requirement Update Cc. Fritz Creek Segment Funding D. Fish Water Bypass Update IE; BPMC Control Over O&M Decisions and Agreements Master Agreement NEW BUSINESS A. Operations Budget Contingency Fund Resolution B. Diamond Ridge Relaying Cost ic RvsdD. BL. BvdcEe7T— COMMUNICATIONS A. Schedule Next Meeting ADJOURNMENT RECORL UOPY FILE NO Ro Btu) mind me ete Highers Burlingame Ritchey Sieczkowski Sieczkowski Eberle Lovas Saxton Eberle Eberle Saxton Saxton Eberle ATTACHHENT 1 WOHLFORTH, ARGETSINGER, JOHNSON & BRECHT ~ PETER ARGETSINGER A PROFESSIONAL CORPORATION TELEPHONE JULIUS J. BRECHT ATTORNEYS AT LAW (907) 276-6401 CYNTHIA L. CARTLEOGE ROSERT > ee 900 WEST STH AVENUE, SUITE 600 TELECOPY @RAOLEY E. MEYEN ANCHORAGE, ALASKA 99501-2048 (S07) 2782 C82 KENNETH E VASSAR ERIC E. WOHLFORTH RECEIVED MEMORANDUM APR 15 1993 ALASKA ENERGY AUTHORITY. TO: Brent Petrie Director of Operations ‘ RECORD vor Alaska Energy Authority FILE NO FROM: Thomas F. Klinkner _7RO Bit bmi : 5/13)43 DATE: April 13, 1993 uW SUBJECT: Payment of Cost of Accelerating Construction of Fritz Creek Transmission Line Segment from Proceeds of Power Revenue Bonds, First and Second Series (Bradley Lake Hydroelectric Project); Our File No. 3610.2024 You have asked that we advise the Alaska Energy Authority (the “Authority") concerning a proposal by the purchasers of power (the "Purchasers") from the Bradley Lake Hydroelectric Project (the "Project") to capitalize the costs of accelerating construction of the Fritz Creek transmission line segment (the "Fritz Creek Line") under Section 31 of the Agreement for the Purchase and Sale of Electric Power (the “Power Sales Agreement") among the Authority and the Purchasers. We conclude that the Authority may do so, with the requisite approval of the Purchasers under Section 31 of the Power Sales Agreement. Our answer involves the following analysis of the agreements between the parties and federal tax law. |. Background. We understand that an Amendment to Agreement for Sale of Transmission Capability dated March 7, 1989 obligates the Purchasers other than Homer Electric Association, Inc. ("HEA") to pay HEA $600,000 (the "Fritz Creek Payment") in exchange for HEA accelerating the construction of the Fritz Creek Line to transmit power from the Project. To capitalize the Fritz Creek Payment, the Purchasers propose that the Authority pay HEA $600,000 from amounts held under the Power Revenue Bond Resolution, adopted September 7, 1989 (the "Bond Resolution"), securing the Authority’s Power Revenue Bonds, First and Second Series (Bradley Lake Hydroelectric Project) (the “Bonds"), and that the Purchasers other than HEA Memo to Brent Petrie Alaska Energy Authority April 13, 1993 Page 2 pay, as a portion of Annual Project Costs under the Power Sales Agreement, debt service on the Bonds allocable to this reimbursement. ll. ion 31 of the Power Sales Agreement. Section 31 (a)(ii) of the Power Sales Agreement provides for the capitalization of certain costs of the Purchasers as follows: (a) Promptly after the Committee is formed, and before the Authority first issues Bonds, the Purchaser members of the Committee shall determine by the affirmative vote of members whose Percentage Shares equal or exceed eighty percent (80%) of Project Capacity and of Annual Project Costs: * * * (ii) whether and to what extent the costs incurred by the individual Purchasers in conjunc- tion with this Agreement prior to the Date of Commercial Operation should be capitalized and reimbursed through issuance of additional Bonds, and whether and to what extent the costs of debt service on those additional Bonds should be added to Annual Project Costs and allocated among Purchasers either in accor- dance with their respective Percentage Shares or in some other manner. Section 31(b) of the Power Sales Agreement states that if the Purchasers provide the Authority with a determination under Section 31(a)(ii), the Authority shall issue additional bonds in the requisite principal amount and include debt service on the additional bonds in Annual Project Costs, allocating that debt service among the Purchasers in the manner specified in such determination. The literal terms of Section 31 of the Power Sales Agreement do not apply to the present proposal of the Purchasers. The Purchasers’ proposal fails the condition in Section 31(a)(ii) that the Purchasers determine whether to capitalize costs before the Authority issued the Bonds. Similarly, the proposal provides for capitalization with amounts presently held under the Bond Resolution, rather than Memo to Brent Petrie Alaska Energy Authority April 13, 1993 Page 3 with the proceeds of additional bonds. Therefore, a Section 31(a)(ii) determination based upon the Purchasers’ proposal would not invoke the Section 31(b) obligation of the Authority to capitalize the Purchasers’ costs by issuing additional bonds. However, we see no reason why the Authority could not elect to waive the conditions in Section 31(a)(ii) and accept the Purchasers’ proposal, provided, (i) the capitalization of the Fritz Creek Payment would have no adverse effect on the security for the Bonds and is authorized under the Bond Resolution; (ii) the capitalization of the Fritz Creek Payment would have no adverse effect on the tax exemption of interest on the Bonds; and (iii) the Purchasers’ proposal is duly adopted by the Purchasers under Section 31(a) of the Power Sales Agreement. We next address each of these issues. lll. Security of the Bonds. The funds held under the Bond Resolution that have been suggested as sources for the Fritz Creek Payment are the Renewal and Contingency Reserve Fund and the Construction Fund. Under Section 509 of the Bond Resolution, amounts in the Renewal and Contingency Reserve Fund are committed to payment of the costs of capital improvements to the Project, extraordinary operation and maintenance costs, and contingencies. Owners of the Bonds are entitled to the security provided by the restrictions on the used of amounts in this fund, and such amounts cannot be applied to the Fritz Creek Payment. Section 503 of the Bond Resolution provides that amounts in the Construc- tion Fund shall be applied to the Cost of Acquisition and Construction of the Project. The Bond Resolution defines "Cost of Acquisition and Construction" to include “all costs and expenses...of placing the Project...in operation." This definition further provides that "such costs shall include amounts required to be paid to any other party which are applied or to to be applied under agreement to the payment of Costs of Acquisition and Construction." The definition of "Project" in the Bond Resolution incorporates by reference the description of the Project in Exhibit C to the Power Sales Agreement. That description specifically excludes the Fritz Creek Line. However, the costs that are to be reimbursed with the Fritz Creek Payment were incurred to accelerate the construction of the FritZ Creek Line, which was necessary to place the Project in operation. Thus the definition of Cost of Acquisition and Construction appears to be broad enough to include the Fritz Creek Payment. Memo to Brent Petrie Alaska Energy Authority April 13, 1993 Page 4 The principal reason for a narrower interpretation of the definition of Cost of Acquisition and Construction would have been that a narrower interpretation was necessary to assure there were sufficient funds in the Construction Fund to bring the Project to commercial operation, at which time the Purchasers’ take-or- pay obligations under the Power Sales Agreement would commence under Section 2(b) of the Power Sales Agreement and became the principal security for the payment of debt service on the Bonds. Now that the Date of Commercial Operation has passed, making the Fritz Creek Payment from the Construction Fund would have a de minimis effect on Bondowner security. In our opinion it is a properly authorized payment from the Construction Fund. IV. Tax Exemption. No original proceeds of the Bonds were deposited in the Construction Fund under the Bond Resolution. The amounts in the Construction Fund consist of (i) moneys transferred from funds and accounts held under the Indenture securing the Authority's Variable Rate Demand Bonds (Bradley Lake Hydroelectric Project) (the "1985 Bonds"), upon the retirement of all outstanding 1985 Bonds in 1990; and (ii) proceeds from the investment of such moneys. A portion of these moneys have become transferred proceeds of the Bonds under former Treas. Reg. § 1.148- 4T(e). The Bonds were issued as tax-exempt private activity bonds for a facility for the local furnishing of electricity, under Section 142(f) of the Internal Revenue Code of 1986 (the "Code") as modified by the transition rule in section 645 of the Deficit Reduction Act of 1984 (See 1986 Tax Reform Act Blue Book, p. 1170). Section 142(a) of the Code provides that the Bonds qualify as tax-exempt private activity bonds if 95 percent or more of their net proceeds are used to provide a facility for the local furnishing of electricity. Section 150(a)(3) of the Code defines “net proceeds" of an issue as the proceeds of the issue reduced by amounts in a reasonably required reserve or replacement fund. The Code and Treasury Regulations no not specifically address whether "net proceeds" as defined in Section 150(a)(3) of the Code include transferred proceeds. The definitions of "proceeds" in former Treas Reg §1.148-8T(d)(2) and current Treas. Reg. §1.148-8(d)(2), which include transferred proceeds, apply be their terms only for purposes of arbitrage rebate, or arbitrage rebate and other arbitrage requirements relating to refundings, respectively. However, for purposes of this analysis, we will assume that expenditures of transferred proceeds of the Memo to Brent Petrie Alaska Energy Authority April 13, 1993 Page 5 Bonds must be taken into account in determining whether 95 percent or more of the net proceeds of the Bonds are used to provide an exempt facility in accor- dance with Section 142 of the Code. We will assume further that all of the moneys remaining in the Construction Fund under the Bond Resolution must be allocated to transferred proceeds of the Bonds. Section 645 of the Deficit Reduction Act of 1984 provides for the tax exemption of the Bonds notwithstanding the "two-county rule" in Section 142(f)(1) of the Code, if they were issued to finance the facility described in Section 645. This description is intended to identify the Project.' Section 645 of the Deficit Reduction Act of 1984 does not define in detail the precise scope of the facility to which its terms apply. The only basis for determining the scope of the facility appears in Section 645(i), which states, "the facility was initially authorized by the Federal Government in 1962." The reference to federal approval in this statute has caused us to consider the scope of the facility that is made eligible for tax exempt financing under this provision to be determined by the FERC license for the Project. The description of the Project in the FERC license does not include the Fritz Creek Line. Thus the expenditure for the Fritz Creek Line may come only from the five percent of net proceeds of the Bonds that may be expended other than for exempt facility purposes. The Authority has determined that an additional $4,312,192 of proceeds could be expended for non-exempt facility purposes within the five percent of net proceeds limit of Section 142(a) of the Code. This amount is sufficient to provide for the $600,000 expenditure for the Fritz Creek Line. Section 57(a)(5)(A) of the Code identifies interest on a "specified private activity bond" as an item of tax preference subject to alternative minimum tax under Section 55 of the Code. However, Section 57(a)(5)(C)(iii) of the Code excludes ‘Section 645 provides in relevant part: ...facilities for the local furnishing of electric energy also shall include a facility that is part of a system providing service to the general populace-- (i) if the facility was initially authorized by the Federal Government in 1962; (ii) if the facility receives financing of at least 25 percent by an exempt person; (iii) if the electric energy generated by the facility is purchased by an electric cooperative qualified as a rural electric borrower under 7 U.S.C. §901 et. seq. and; (iv) if the facility is located in a noncontiguous State. Memo to Brent Petrie Alaska Energy Authority April 13, 1993 Page 6 from the term "private activity bond" for purposes of the alternative minimum tax any refunding bond if the refunded bond was issued before August 8, 1986. The 1986 Tax Reform Act Blue Book, at p. 443, states that "refunding bond" as used in Section 57(a)(5)/(iii) of the Code refers to bonds issued exclusively to refund an issue of bonds. At the time the Bonds were issued, we determined that the Bonds were refunding bonds for this purpose because we understood that all original proceeds of the Bonds would be used either to refund the bonds issued for construction of the Project or for the ancillary purposes enumerated in Treas. Reg. § 1.103-15(b)(1) that would not cause those proceeds to be “excess proceeds" for purposes of Treas. Reg. §1.103-15(a). The proposed expenditure for the Fritz Creek Line would not come within the purposes listed in Treas. Reg. §1.103- 15(b)(1). However, this expenditure would be an expenditure of transferred proceeds, rather than original proceeds, of the Bonds. We do not believe that the requirement under Section 57(a)(5)(iii) that the proceeds of the Bonds be issued exclusively to refund an issue of bonds imposes any restriction on the expenditure of transferred proceeds of the Bonds. Therefore, an expenditure of $600,000 from transferred proceeds of the Bonds for the Fritz Creek Line would not cause interest on the Bonds to be subject to alternative minimum tax. V. Procedure. While Section 31 of the Power Sales Agreement does not obligate the Authority to accept the Purchasers’ proposal, Section 31 provides the basis for the Purchasers’ payment of debt service on the Bonds allocable to the Fritz Creek Payment. To establish the basis for this payment, the Purchasers’ proposal to make the Fritz Creek Payment from amounts held under the Bond Resolution and to apportion among the Purchasers responsibility for debt service on the Bonds allocable to that payment, should be adopted by the procedure established in Section 31(a). This procedure requires (i) action of Purchaser members of the Committee whose Percentage Shares equal or exceed 80% of project capacity and of annual project costs, (ii) determining that the Fritz Creek Payment should be capitalized and reimbursed from amounts held under the Bond Resolution, and (iii) determining that debt service on the Bonds allocable to the Fritz Creek Payment should be included in Annual Project Costs, and (iv) prescribing the manner in which that debt service should be allocated among the Purchasers. RECORD VOPY FILE NO - Mn EUSHLIATOR. Bavess 5NW93 ) Ow ARID AnArepee Dice CorlrAad” zo AriTeawyyy TO Kémové DeSbris Freon seve MeGill zo g BéCar Work on Mar 25, Z. Due 7O ExrtemE over froW conpinevs of seek CB of Srvow, stusp ere} fesseess was V&rq Show , Narth6& Te mav€& EZrvavoH Degree To svwstrAl WVenzICH THRASH YACES pre RE-ESTHSLISH Fra. 3. Comrrert Rimevat of Disew proves wave 4E MEALELY sar/fastiBle DE Te 26£ Conwir2Gn 27 DELAY FuetHee work Unit Surew4Oe ap. wext ger. 4, Rear work ! —-ReravE £57, 200 Cw Lowe mare Fro Rack out Rar (ABE Ware tint) -— Reravse 25%% 69069 pen frm IATAEE CHArvel ~Rrea (sito warér) 5. @) Ae warer wotle FHIS svamer—,.. Cosy EsTimare zr Frieay of Rom 2a APIA Conmnctor) (2) vratkuersr (dD erat WAG Sf AEE _@ Leté eens ¢ Chamiyere ,_ * poy THA Svemor | * MAIVBE NWEXP FZ TEE ee faoek 7. Kittommernte TREAT AS rover cosr TT « Const BEF cher , AI 2 1ATL CrrerE Prenqg Cosnvtt7e .,) per H Bt030N J verealieiwt ef Keck ovicker , iT tH Ss tt tT a BRADLEY LAKE HYDROELECTRIC PROJECT SUMMARY OF OF FINANCING COSTS THROUGH JUNE 30, 1993 Variable Rate Power Revenue State Total Demand Bond Bonds Fund Costs Interest Expense 65,251,362 18,973,652 84,225,014 Interest Revenue (96,571,980) (12,529,503) (109,101,483) Issuance Costs At Bond Closing: Program Fee/Insurance 7,714,588 1,302,839 9,017,427 Cost of issuance at Closing 1,523,041 8,500 1,531,541 Underwriter's Discount 2,006,250 2,155,662 4,161,912 11,243,879 3,467,001 14,710,880 Cost of issuance paid through Trustee 353,797 879,744 1,233,541 Sub-total 11,597,676 4,346,745 15,944,421 Reserve Funds Capital Reserve Fund 13,393,000 0 13,393,000 Operaung Reserve Fund 0 625,000 625,000 Renewal & Conungency Reserve Fund 1,607,908 3,392,092 5,000,000 Sub-total 0 15,000,908 4,017,092 19,018,000 Bond Discount Bond Discount 3,842,140 3,842,140 Bond Premium (179,533) (179,533) Sub-total 0 3,662,607 3,662,607 Total Financing Costs (19,722,942) 29,454,408 4,017,092 13,748,559 Projected Financing Costs (January 1991) 15,249,000 1,500,441 Favorable Variance FINCOST7.XLS, 4/1/93: 2:41 PM, Page 1 of 1 anaes a a b(ti/a VOW LYRe. Oot ON 312 AdO” MHOOSY 2 LNSWHOVILY BRADLEY LAKE HYDROELECTRIC PROJECT RECONCILIATION OF PROJECT COSTS Construction Cost Financing Cost Total Project Cost Less Section 31 Cost Net Dividable Project Cost Net Project Cost (50/50) Section 31 Costs Total Share Appropriations Bond Proceeds Surplus (Shortage) dburgerlexcellmiscel\CONCOST.XLS (Estimate as of May 12, 1993) $314,500,000 $13,750,000 $328,250,000 $2,255,000 (Includes Fritz Creek Costs) $325,995,000 (50% State/50% Utility) Utility Share $162,997,500 ___ $2,256,000 _ $165,252,500 $0 $165,260,000 $7,500 Page 1 State Share $162,997,500 $0 $162,997,500 $175,080,000 $0 $12,082,500 ATTACHMENT 3 RECORD UOPY FILE NO Pro 8-t./ mii 5113/93 a 5/12/93 4:45 PM DATE: TO: FROM: SUBJECT: Alaska Energy Authority RECORD UOPY FILE NO MEMORANDUM eek So May 13, 1993 Bill Sobolesky Accountant Ww Stanley E. Sieczkowski ht Director Facilities Operations & Engineering Bradley Lake Hydroelectric Project Approved Legal Expenses Please process payment of the attached attorney invoices. Payment of these invoices for Ron Saxton's legal services to the Bradley Project Management Committee was approved at the May 13, 1993 Committee meeting. DB:SES PIPROPC OF SRYTOMIS = aneance S FEL 14, Lat, oF mpc) t LF, sz. GY APRIL 1S ed Ol time wy? FILE NO Alaska Energy Authority BR Feo 3-hl awd DATE: owe BRADLEY PMC VOTING ee fete cARL WG 12.13 - ae YES NO ABS YES NO ABS YES NO ABS YES NO ABS CITY OF SEWARD 01% M1) Zo Vw MATANUSKAELECASSOC =m §«=©6 (YT ) WIT) YLT) WT CHUGACH ELEC ASSOC 30% MO YO wo HOMER ELEC ASSOC 12% Vi TI YT GOLDEN VALELECASSOC 17% Pt ee A= 4+ OVER 51% use eon vase 7 woo oo eo O = MAJORITY VOTING METHOO A: 9} ADOPTION_OR AMENOMENT OF PROCE- VOTING METHOO 8: REQUIRING 4 YEAS W/ 51% OF UTILITIES, WITH NO APA voTe; 1) PROCEDURES FOR SCHEDUUNG, PRODUCTION ANO DISPATCH OF PROJECT POWER. 2) ESTABUSHMENT OF PROCEDURES FOR USE OF EACH PURCHASER'S WATER ALLOCATION (APA ASSENT REQUIRED FOR FERC UCENSE REQUIREMENTS). 3) SELECTION AMONG ALTERNATIVE METHOOS THAT (00 NOT INVOLVE APA FOR FUNDING REQUIRED PROJECT WORK. YOTING METHOD C: UNANIMOUS VOTE BY ALL (INCLUDING APA): ADOPTION OF PROCEDURES FOR DISPUTE RESOLU- TION. MAJORITY VOTE (INCLUDING APA). ELECTION OF OFFICERS. REQUIRING 4 YEAS W/ 51% OF UTILITIES, AND APA CONCURRENCE; 1) ARRANGING OPERATION ANO MAINTENANCE OF PROJECT. 2) ADOPTION OF BUOGET OF ANNUAL PROJECT costs. 3) ESTABLISHMENT OF FY ESTIMATED ANNUAL PAY- MENT OBLIGATION AND SCHEDULE OF EACH PUR- CHASER. 4) DETERMINATION OF ANNUAL PROJECT COSTS AFTER EACH FY. 5) EVALUATION OF NECESSITY FOR AND SCHEDUUNG OF REQUIRED PROJECT WORK 6) DETERMINATION OF APPROPRIATE AMT. OF IN- SURANCE. 7) ADOPTION OF ADO’L MIN. FUNDING AMTS. FOR RENEWAL AND CONTINGENCY RESERVE FUNO ABOVE THAT REQ. BY BOND RES. 8) SELECTION AMONG ALT. METHOOS THAT INVOLVE APA FOR FUNDING REQ. PROJECT WORK DURAL COMMITTEE RULES (EXCEPT DiS- PUTE RES) 10) ADOPTION OF PROJECT MAINTENANCE SCHEDULES. 11) DETERMINATION OF RULES, PROCE- DURES AND ACCOUNTS NECESSARY TO MANAGE PROJECT WHEN NO BONDS OUT- ‘STANDING. 12) EVALUATION AND APPROVAL OF OPTION- AL PROJECT WORK AND COMPENSATION FOR SUCH WORK 13) APPUCATION OF INSURANCE CLAIMS PROCEEDS NOT GOVERNED BY BOND: RESOLUTION. 14) APPROVAL OF PROCEDURES ANO ANY WNOMOUAL UTILITY AGREEMENTS RELATING TO ELECTRIC POWER RESERVES FOR PROJECT. 15) APPROVAL OF CONSULTANTS. Bradley Lake PROJECT MANAGEMENT COMMITTEE MEETING RECORD VOPY MAY 131993 FILE NO (Date) geo Slut Ms w cer 13/93 (Location) PLEASE SIGN IN No. NAME REPRESENTING 1 <tr ete oe atK _| A (aoe O rccay Aree, be 2 en te ke en YP. : 3 TJehn ae) Chesgack 4 Lex. L ale ld ce ack ee Bie Te ed Augech 6 | Jom LOUAS © CH-OEACHE 7 oe fo Rrchevny UAbhey 8 LIAVE LTIEHELES Ohunacs 9 “aie tKx<ell QV ERK 10 J] diet ri Chapa h | Pencbleng Corears ivEA 12 | Moe Asean) | ae 13 a SHO L102 4 | Zz dh “al ll Elo 15 By [rice LLL 5 P 118 | Afgoum esti, TTA 16 | Janus Drensr >é5 17 DAVE ( ALVERT SEéS 92Q2\IT9884 | 19 | Dove. Ea Ce AEA 20 | Dave LeeRve [AGA a | me (cenzin' AEA [22 | Dewiggs “Birr cee BELO Mr. Everett P. Diener City of Seward 5th & Adams P.O. Box 167 Seward, Alaska 99664 Mr. David L. Highers Chugach Electric Association 5601 Minnesota Drive P.O. Box 196300 Anchorage, Alaska 99519-6300 Mr. Michael P. Kelly Golden Valley Electric Association 758 Illinois P.O. Box 1249 Fairbanks, Alaska 99707 Mr. Fred Arvidson Perkins Coie 1029 W. 3rd Avenue, Suite 300 Anchorage, Alaska 99501 Mr. James Hall Matanuska Electric Association 163 Industrial Way P.O. Box 2929 Palmer, Alaska 99645-2929 Mr. S.C. Mathews Homer Electric Association 3977 Lake Street Homer, Alaska 99603 Mr. Ron Saxton Ater Wynne Hewitt Dodson & Skerritt aes SW. Columbia, Suite 1800 Portland, OR 97201-6618 90Q1UD0068L(1) Mr. Ken Ritchey Matanuska Electric Association 163 Industrial Way P.O. Box 2929 Palmer, Alaska 99645-2929 Mr. N. L. Story Homer Electric Association 3977 Lake Street Homer, Alaska 99603 Mr. Thomas R. Stahr Municipal Light and Power 1200 E. 1st Avenue Anchorage, Alaska 99501-1685 Mr. Eugene N. Bjornstad Chu Electric Association 560f Minnesota Drive P.O. Box 196300 Anchorage, Alaska 99519-6300 Mr. John Cooley Chugach Electric Association 560I Minnesota Drive P.O. Box 196300 Anchorage, Alaska 99519-6300 Mr. Bob Hansen Golden Valley Electric Association 758 Illinois P.O. Box 71249 Fairbanks, Alaska 99707 Mr. Kurt Dzinich 4511 N. Riverside Drive Juneau, Alaska 99801 Mr. Robert Hufman Utilities Consulting Services 1018 Galena Street Fairbanks, Alaska 99709 Mr. David Burlingame Chugach Electric Association, Inc. P.O. Box 196300 Anchorage, Alaska 99519-6300 Mr. Tom Lovas Chugach Electric Association, Inc. P.O. Box 196300 Anchorage, Alaska 99519-6300 90Q1\D0068L{1) Legislative Research Agen PO. Box Y — Juneau, Alaska 99811-3100 Mr. Hank Nikkels Anchorage Municipal Light & Power 1200 East 1st Street Anchorage, Alaska 99501 Mr. eee Evans Golden Valley Electric Association 758 Illinois P.O. Box 71249 Fairbanks, Alaska 99707 Alaska Energy Authority MEMORANDUM RECORD uopy FILE NO DATE: April 28, 1993 i Vi Ma TO: Bradley Lake Project Management Committee Vv David L. Highers, Chugach Electric Association Norm Story, Homer Electric Association Ken Ritchey, Matanuska Electric Association Paul Diener, City of Seward Tom Stahr, Anchorage Municipal Light & Power Mike Kelly, Golden Valley Electric Association Ron Saxton, Ater Wynne Hewitt Dodson & Skerritt FROM: Brent N. Petrie BM. Rb Secretary - SUBJECT: Project Management Committee Meeting Notice of Meeting - May 13, 1993 The next meeting of the Bradley Lake Project Management Committee is scheduled Thursday, May 13, 1993. The meeting will begin at 10:00 a.m. in the Training Room at Chugach Electric Association, Anchorage. The following items are enclosed for your information, review, and or files: ° Agenda, May 13, 1993 BPMC Meeting ° Draft Minutes - March 3, 1993 BPMC Meeting March 30, 1993 BPMC Teleconference April 16, 1993 BPMC Teleconference ° Approved Minutes - January 14, 1993 ° Revised Scheduling & Allocation Procedures, March 3, 1993 ° AEA Memorandum, Diamond Ridge Relaying, April 1, 1993 Please provide any comments regarding the upcoming May 13, 1993 BPMC meeting agenda items to Chairman Highers. DB:BNP:db cc: Ronald A. Garzini, Alaska Energy Authority Stanley E. Sieczkowski, Alaska Energy Authority Larry Wolf, Alaska Energy Authority David R. Eberle, Alaska Energy Authority BRADLEY LAKE HYDROELECTRIC PROJECT ALLOCATION AND SCHEDULING PROCEDURES As Revised by the BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE on March 3, 1993 These Procedures dated July 2, 1991, have been approved and adopted by the Bradley Lake Project Management Committee to govern the allocation and scheduling of electric capacity and energy available to the Purchasers from the Project under the Project Power Sales Agreement. Section 1. Definitions. For the purposes of these Procedures, the following definitions apply; (a) AEA or Authority. The Alaska Energy Authority (b) AEG&T. The Alaska Electric Generation and Transmission Cooperative, Inc. (c) Basic Agreements. The agreements entered into and amended from time-to-time for the sale, purchase and transmission of Bradley Lake power and includes the Power Sales Agreement, the Chugach Services Agreement, and the HEA Transmission Sharing Agreement. (d) Bradley River Minimum Flow Releases. Those minimum amounts of water (flows) that are required to be released into the Bradley River under the FERC license. (e) Chugach. The Chugach Electric Association, Inc. (f) Chugach Services Agreement. The Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric and for Related Services dated December 8, 1987, between Chugach and ML&P, HEA, GVEA, MEA, SES and AEG&T providing for Chugach's transmission and other services. h Agreement. The agreement between the Authority and Chugach for the day-to-day operations of the Project. (h) Dispatcher. The Chugach Electric Association, Inc., or its successor. (i) Effective Date. September 1, 1991, the date of Commercial Operation of the Project as provided in the Power Sales Agreement. (j) Energy Account. The account maintained by the Authority to record the amount of Initial Project Energy and Revised Project Energy each Purchaser is entitled to schedule under these Procedures. (k) | FERC License. License No. 8221 that has been issued by the Federal Energy Regulatory Commission to the Authority for the construction and operation of the Project. (1) Fiscal Year. As defined in Section 1(r) of the Power Sales Agreement. (m) Forced Outage. An outage due to any failure of a generating facility, related auxiliaries, or a transmission facility which a Purchaser relies upon to supply firm power to meet its firm load obligation and which causes a deficiency in power resources available to meet the Purchaser's load. (n) GVEA. Golden Valley Electric Association, Inc. 92Q4\NK3849(2) (0) HEA. Homer Electric Association, Inc. (p) HEA Transmission Sharing Agreement. The Bradley Lake Hydroelectric Project Transmission Sharing Agreement dated December 8, 1987 and as amended March 7, 1989, for wheeling of power over the HEA system entered into by and among Chugach, GVEA, ML&P, and AEG&T. (q) _ Initial Project Energy. The amount of Project Generation expected during the Project Water Year, as computed prior to the beginning of the Project Water Year pursuant to Section 4(c). (r) MEA. Matanuska Electric Association, Inc. (s) ML&P. Anchorage Municipal Light and Power. (t) Net Allocation. The monthly energy from the Project available to a Purchaser in establishing the Initial Project Energy and Revised Project Energy(s) under Section 4 from the beginning of the Project Water Year through the end of the current month less the total Project Generation for that Purchaser from the beginning of the Project Water Year to date plus any debits or credits from the previous Project Water Year. (u) Operation and Dispatch Committee. The Committee appointed by the PMC to address technical issues related to the operation and dispatch of the Project. (v) | PMC. The Project Management Committee established pursuant to the Power Sales Agreement. (w) Percentage Share. The fraction expressed as a percent and set forth for each Purchaser in Exhibit D of the Power Sales Agreement. (x) Power Sales Agreement. The Agreement for the Sale and Purchase of Electric Power from the Project entered into by and among the Authority and the Purchasers dated December 8, 1987, and as may be amended from time-to- time. (y) Procedures. These Allocation and Scheduling Procedures. (z) Project. The Bradley Lake hydroelectric generating Project as described in Exhibit C of the Power Sales Agreement. (aa) Project Capability. The amount of electric capacity capable of being produced by the Project at any given time taking into account system conditions, equipment and Project transmission availabilities and limitations. (bb) Project Capacity. The amount of electric power capable of being produced by the Project at the then current reservoir level with all generating and transmission facilities of the Project fully operational. (cc) Project Generation. That amount of energy produced by the Project recorded on an hourly basis. 92Q4\NK3849(3) (dd) Project Reservoir. The body of water held behind the dam of the Project used for Project Generation, Bradley River Minimum Flow Releases, and Project Spill. (ee) Project Spill. The water released from the Project Reservoir into the Bradley River in excess of Bradley River Minimum Flow Releases and in excess of that which has already been accounted for in the Reservoir Operation Mode. Project Water Year. The twelve-month period starting on June 1 and ending on May 31. (gg) Prudent Utility Practice. The practice defined in Section 1(x) of the Power Sales Agreement. (hh) Purchaser. Purchaser means, as of any particular time, the Municipality of Anchorage d/b/a Municipal Light and Power, Chugach Electric Association, Inc., Golden Valley Association, Inc., the City of Seward and the Alaska Electric Generation & Transmission Cooperative, Inc. ("AEG&T). The term "Purchaser" includes Homer Electric Association, Inc., and Matanuska Electric Association, Inc., only to the extent specified in Section 30 of the Power Sales Agreement. (ii) | Reservoir Operation Model. The model described in Exhibit A used to determine the Initial Project Energy and Revised Project Energy. (ij) | Revised Project Energy. The amount of Project Generation for the remaining portion of the Project Water Year calculated under Section 4(d) if actual operating conditions significantly change the expected amount of total Project Generation for the Project Water Year from previous forecasts. (kk) SES. Seward Electric System (ll) | Spinning Reserves. The amount of on-line capacity available from the Project from time-to-time which is available to meet Purchasers' loads, minus actual Project output, in accordance with Section 9 of these Procedures. (mm) Termination Date. The date the PMC adopts revised procedures pursuant to the terms of the Power Sales Agreement which replace these Procedures. Section 2. Term. These Procedures shall become effective upon the Effective Date and shall continue in force until the Termination Date. Section 3. Exhibits. The following exhibits are incorporated by reference in these Procedures: (a) Exhibit "A", Description of Reservoir Operation Mode; (b) Exhibit "B", Description of Project Operating Criteria; (c) Exhibit "C", Scope of the Project Dispatch Duties; and 92Q4\NK3849(4) (d) Exhibit "D", Transmission System Dispatch and Clearance Procedures. Section 4. Project Allocation. (a) General. Nothing in these Procedures shall cause the Project to be operated or maintained in a manner that is not consistent with Prudent Utility Practice nor shall it be operated or maintained in a manner that is not consistent with the FERC License and other permits and licenses. The PMC recognizes that the method of operating the Project may change from time-to-time in order to accommodate modifications to such licenses and permits. (b) Relationship to Basic Agreements. In the event that any provisions in these Procedures conflict with provisions in any of the Basic Agreements, the provisions in the Basic Agreements shall prevail. (c) Initial Allocation. The Initial Project Energy shall be determined prior to the beginning of each Project Water year based on known operating limitations, forecasted estimates of runoff available from snowcap and precipitation by the National Weather Service (NWS) for the 50% exceedance probability and/or the mean monthly discharge (depending upon availability of the information), and other pertinent factors, and in a manner consistent with the following: (i) On or before March 1 of each year, the PMC shall meet and establish a coordinated maintenance schedule for their transmission facilities and the Project for the 12-month period commencing with the ensuing June 1. (ii) On or before April 15 of each year, the Authority shall transmit to the Purchasers a preliminary estimate of the amount of capacity and preliminary Initial Project Energy available for the upcoming Project Water Year. (iii) On or before May 1, each Purchaser shall submit to the Authority its forecasted monthly use of its Percentage Share of Initial Project Energy. The monthly energy requirements will be based on the expected Initial Project Energy, as estimated under Section 4(c)(ii), and coordinated maintenance schedule established in Section 4(c)(i). (iv) Based on the total monthly energy requirements from the Project for all Purchasers, the Authority shall perform the Reservoir Operation Model as outlined in Exhibit A and compare the resulting Initial Project Energy with the preliminary Initial Project Energy estimate in Section 4(c)(ii). The Authority shall transmit to each Purchaser the results of the Reservoir Operation Model by May 15. (v) If the results of the Reservoir Operation Model performed above show the expected Initial Project Energy to be different than that assumed in Section (oN) ii) above or there is potential for Project Spill, the Authority and the Purchasers shall work together in revising monthly energy requirements such that Initial Project Energy and the sum of the Purchasers' monthly energy requirements assumed for the Reservoir 92Q4\NK3849(5) Operation Model are equal to one another and Project Spill potential is minimized. (d) Revised Allocation. Each month the Authority shall estimate the amount of energy available from the Project for the remainder of the Project Water Year and determine the amount of energy which should be added or subtracted from each Purchaser's Net Allocation of energy for each month in the remainder of the Project Water Year. In the event the amounts to be added or subtracted from the total Net Allocation then in effect for the Purchasers exceeds 15, 000 mWhs and on November 1 of each year, the Authority shall determine the amount of Revised Project Energy for each Purchase in the following manner: (i) The Authority shall transmit to the Purchasers a preliminary estimate of the Revised Project Energy for the remainder of the Project Water Year and the Project Generation to date. (ii) Each Purchaser shall be allocated its Percentage Share of any difference between the new Revised Project Energy, and the then in effect estimate of Project Generation for the Project Water Year. If the result of such allocation is negative, the Purchaser's Net Allocation shall be reduced by such amount in the next Project Water Year. (iii) |The Purchaser shall submit to the Authority its forecasted monthly requirements of the Revised Project Energy. (iv) Based on the total monthly requirements of Revised Project Energy, the Authority shall perform the Reservoir Operation Model as outlined to verify the Revised Project Energy. (v) If the results of the Reservoir Operation Model performed show the Revised Project Energy to be different than that assumed in Section 4(d)(i) or there is potential for Project Spill, the Authority and the Purchasers shall work together in revising monthly energy requirements such that Revised Project Energy and the sum of the Purchasers’ monthly energy requirements assumed for the Reservoir Operation Model are equal to one another and Project Spill potential is minimized. (e) Status of Energy Account. As soon as practicable after the end of each month, the Authority shall provide each Purchaser an accounting of the amount of Initial Project Energy or Revised Project Energy available to each Purchaser in its Energy account for the remainder of the Project Water Year, along with its best estimate of the potential availability of additional Revised Project Energy and potential for Project Spill in the ensuing month. If an event occurs during any month which requires the Authority to increase or decrease the amount of Revised Project Energy available to a Purchaser or increases the potential of spill, the Authority shall use its best efforts to provide each Purchaser an interim accounting of the Initial Project Energy or Revised Project Energy available and the amount of such energy which could be subject to spill in the next 30 days. (f) Failure to Refill. If the Revised Project Energy is expected to be 90 percent or less than previous estimates or Project Generation for the Project Water Year, the Authority shall notify the PMC and the Operation and Dispatch Committee. The Operation and Dispatch Committee shall recommend whether to alter the scheduled operation of the Project and the PMC shall then consider the 92Q4\NK3849(6) recommendation and adopt, if appropriate, a revised schedule of Project Generation. Any disputes shall be resolved in accordance with the by-laws established by the PMC. (g) Review of Reservoir Operation Model. The methodology and inputs of the Reservoir Operation Model shall be reviewed by the Operation and Dispatch Committee at least every five (5) years and recommendations for changes to the Model provided to the PMC. The Reservoir Operation Model shall be modified, if required, to reflect the changes to the permits and licenses that the Project is operated under. The PMC shall have the right to approve any changes made to the Reservoir Operation Mode. Section 5. Project Scheduling. (a) General. Each Purchaser shall have the right to schedule during any month an amount of Project Generation not to exceed its Net Allocation for that month. (b) Hourly Schedules. The utilities' weekly schedule shall be submitted to the dispatcher no later than 1400 hours on Tuesday; a preliminary summary of schedule requests shall be distributed to all utilities no later than 1400 hours on Wednesday for review; the schedule shall be confirmed by the dispatcher no later than 1400 hours on Thursday; and implemented at 0001 hours on Saturday. (The energy week is established to be Saturday through Friday.) Daily schedule changes shall be allowed, subject to procedures implemented by the O&D Subcommittee. (c) Minimum Scheduling. If the combined scheduled Project Generation from Purchasers scheduling generation is less than 10.0 mW in any one hour, the Purchasers shall be notified no later than 10:0 a.m. on the following day. The Purchasers shall have until 5:00 p.m. of that day to revise their schedules such that the combined Project Generation is equal to or greater than 10. mW. If such revisions still result in a combined scheduled Project Generation of less than 10.0 mW, such Project Generation shall not be scheduled for Project output. (d) Minimum Operations. If, due to operating constraints included in the various permits and licenses that the Project is operated under, the Project must be operated in a manner such that Project Generation is greater than that amount scheduled by all the Purchasers, the amount of Project Generation in excess of that amount scheduled shall be allocated on a pro rata basis to each Purchaser based on its Percentage Share. No Purchaser shali be obligated to take more than its Percentage Share of Project Capability. (e) Reduction in Schedules. If the combined scheduled Project Generation than is greater than Project Capability in any hour, each Purchaser's request shall be reduced during that hour in the following manner: (i) For those Purchasers who have scheduled more Project Generation than their respective Percentage Shares of Project Capability in any hour, the amount scheduled for such Purchasers shall be reduced on a pro rata basis based on the amount scheduled Project Generation exceeds Project Capability. The amount of scheduled Project Generation for any Purchaser shall not be decreased pursuant to this Section 5(e)(i) to an 92Q4\NK3849(7) Forced and obli 92Q4\NK3849(8) amount less than each respective Purchaser's Percentage Share of Project Capacity. (ii) If after making such reductions in Section 5(e)(i) the combined scheduled Project Generation still exceeds Project Capability in any hour, Project Generation for each Purchaser scheduling Project Generation in such hour will be reduced on a pro rata basis based on the respective Percentage Shares. (f) Schedule Modifications. In the event that a Purchaser experiences a Outage on its own system, the Purchaser shall have the following rights igations: (i) The Purchaser, subject to the limitations of the Basic Agreements, shall have the right to notify the Dispatcher and schedule on an immediate basis an amount of Project Generation for its use different than its schedule in effect for the week. Such revisions can be either upward or downward. (ii) Within four hours of such notification, the Purchaser shall submit to the Dispatcher a revised schedule of Project Generation for its use for the remaining portion of the week. If such revision is not submitted, the Dispatcher will operate the Project in a manner consistent with the schedule already in effect for that week. (iii) The right of the Purchaser to schedule Project Generation up to its Percentage Share of Project Capability shall not be limited by other Purchasers scheduling Project Generation in an amount greater than their Percentage Share of Project Capability. (iv) Nothing in this section shall allow a Purchaser to schedule more Project Generation than is allowed pursuant to Section S(a). (g) Schedules Above Participants Share. (i) A Purchaser, upon obtaining permission from another Purchaser that is not scheduling all of its Participant Share of Project Capability, may schedule its Net Allocation or Revised Project Allocation by using Project Capability of such other Purchaser. The scheduling by a Purchaser of another Purchaser's Project Capability shall include all the benefits, rights and obligations related to such schedule as provided in this Section. (ii) The scheduling Purchaser, as compensation for the right to schedule a portion of its Net Allocation or Revised Project Energy by use of another Purchaser's Share of Project Capability in any hour, shall be obligated to pay such other Purchaser at $5/mW ($.005/kW) for each hour that such Purchasers share is used. (iii) The Dispatcher shall establish an account for each Purchaser in which the debits and credits (in Dollars) for use of a Purchaser's Share of Project Capability under Section 5(b) will be accounted. As soon as reasonably practicable after the close of each Fiscal Year (as defined in the Power Sales Agreement), the Dispatcher shall determine the amounts which each Purchaser owes or is entitled to be paid as of the end of such a comp; Fiscal Year. Using the amounts so determined, the Dispatcher shall submit a schedule of payments to the effected Purchasers which will reduce the amounts credited or debited to each Purchaser to zero at the end of such Fiscal Year. Payments under such schedule shall be made by the owing Purchaser to the indicated Purchaser(s) within 30 days after receipt of the schedule of payments. (iv) Each Purchaser is allocated by ownership share Project Energy for a given Project Water Year. The Purchaser can utilize their allocation within the respective Project Water Year or under-utilize their allocation for later use (ponding). However, no Purchaser shall knowingly schedule above their allocation or borrow into the next Project Water Year. If a Purchaser has used their allocation by May 31, then scheduling in the next Project Water Year may be limited by inflows during June. Upon agreement, any Purchaser limited in June may borrow from another Purchaser. (h) Scheduling During Periods of Pending Spill. (i) Whenever the reservoir level reaches an elevation of 1,175 feet, the Authority shall notify each Purchaser that the Reservoir has the potential of spilling water unless additional energy is scheduled by the Purchasers. (ii) The Authority shall develop a methodology for declaring and terminating periods of pending spill, which is agreed upon to the PMC in accordance with its procedures. (iii) Whenever the Authority declares that the Project is in pending spill condition, the Purchasers, to the extent system reliability and operating conditions allow, shall use their best efforts to reduce system generation to allow the Dispatcher to schedule the Project at its full available capability. The energy realized during periods of pending or immediate spill shall be allocated, to each Purchaser based upon its Purchaser's Share. If a Purchaser is unable to schedule its full Purchaser's Share of Project Capability, the energy which is not scheduled shall be made available to the other remaining Purchasers for scheduling pro rata based on their Purchaser's Share. (iv) Once a pending spill period is suspended by the Authority, the energy scheduled and generated from inflows in excess of forecast inflows under this subsection shall be added to each Purchaser's Net Allocation or Revised Project Energy for the month. Schedule of energy by a Purchaser during the pending spill period shall then be credited against the resulting Revised Project Energy total for each Purchaser for such month. (i) End of Water Year Procedures. At the end of the Project Water Year, arison of allocation to scheduled through May 31 will be made for each Purchaser as well as for the Project as a whole. The total Project Allocation minus the total Scheduled will equal the total Project Pond. Likewise, a Purchaser Allocation minus the actual Purchaser's Scheduled will equal the Purchaser Pond. 92Q4\NK3849(9) EXAMPLE Water Year '91-'92 Pond CEA MEA SES GVEA HEA AMLP_ TOTAL Allocation 116,432 52,854 3,830 64,727 45,960 99,197 383,000 Scheduled 103,846 47,059 3,394 53,501 28,992 99.175 335,967 Pond 12,586 5,795 436 11,226 16,968 __22 47,033 Another step in the end of the Project Water Year is to True the Initial Project Allocation. On June 1, all available data will be used to determine what the Actual Project Allocation should have been. Next, a comparison is made between the two Allocations. The difference of the Allocations is added to or subtracted from the Next Year Project Allocation and distributed to each Purchaser by ownership share. The Authority will rerun the Allocation model when the error is plus or minus 15,000 MWH or more. Water Year '91-'92 True Up The Lake was 1104.6 feet on June 1, 1992 with a storage of 311,126 Ac-Ft. This is 47,808 Ac-Ft above the 1080 feet storage. This indicates that we have a positive carry over of 775 MWH after Pond accounting. The amount is proportioned below to each Utility's Water Year '92-'93 Allocation. EXAMPLE CEA MEA SES GVEA HEA AMLP TOTAL '92-'93 Allocation* 122,512 55,614 4,030 68,107 48,360 104,377 403,000 Carry Over 8 131 93 201 775 New '92-'93 122,747 55,721 4,038 68,238 48,453 104,578 403,775 Allocation* * Not including Pond Scheduling Limitations. As previously agreed, all Purchasers will schedule to avoid or minimize Project Spill. The Authority shall provide to all Purchasers all relevant data to achieve this goal. If a Project Spill is anticipated, the Authority will provide a projected Spill Date and a Minimum Use Allocation to avoid Spill. The Minimum Use Allocation will be based on reservoir elevation level beginning at 1080 on June 1. To prevent a Spill, all Purchasers will schedule their ownership share of the Minimum Use Allocation prior to the projected Spill Date. *NOTE* The Minimum Use Allocation does not take Project Pond into account. Each 92Q4\NK3849(10) Purchaser will have MWH at Risk of Spill equal to their Minimum Use Allocation plus Purchaser's Pond. The MWH at Risk value will decrease as a Purchaser schedules during the Project Water Year. The MWH at Risk will also change if the projected Spill Date is different from an actual Spill Date. EXAMPLE MWH at Risk CEA MEA SES GVEA HEA AMLP TOTAL Min Use Allocation 16,112 7,314 530 8,957 6,360 13,727 53,000 Prior to Sept. '92 Pond* 12,586 5:795 436 _ 11,226 _ 16,968 22 47,033 MWH at Risk 28,698 13,109 966 20,183 23,328 13,749 100,033 * Pond as of June 1, 1992 MWH at Risk on August 1, 1992 CEA MEA SES GVEA HEA AMLP Revised Min Use 10,683 4,850 351 5,939 4,217 9,102 Allocation** Pond* 12,586 5,795 436 _ 11,226 _ 16,968 22 Subtotal 23,269 10,645 787 «17,165 21,185 9,124 Scheduled 20,190 9,150 660 _ 15,000 _ 20,000 _ 10,000 MWH at Risk 3,079 1,495 127 2,165 1,185 0 * Pond as of June 1, 1992 ** Based on 61 day availabili A second scheduling limitation is imposed to prevent over-scheduling within the Project Water Year in case the Project Allocation was over-estimated. Based upon previous analysis completed by Stone & Webster Engineering Corporation it has been determined that the minimum amount of energy that is obtainable from the Bradley Lake Hydroelectric project in any given year would be approximately 260,000 MWH. Based upon this amount and the requirement that no Utility over schedules their proportionate share of Bradley power, a maximum energy use between June 1 and November 1 needs to be established. The maximum energy use between June | and November 1 is equal to each Utility's proportionate share of the 260,000 MWH as illustrated on the next page. After November 1 each utility may take 100% of its proportionate share of the project (remaining balance as reallocated on November 1.) 92Q4\NK3849(11) EXAMPLE Max Ener. throu: ill CEA MEA SES MAX Energy 79,040 35,880 2,600 43,940 Section 6. Project Operations. The Project shall be operated by the Dispatcher pursuant to the terms and conditions of the Dispatch Agreement and consistent with those set forth in Exhibits B, C, and D. Section 7. Project Spill. The Purchaser recognizes that from time-to- time water from the Project Reservoir may be spill which does not result in Project Generation. If this occurs, then: (a) | The Authority shall measure the quantity of Project Spill and convert the amount of spill over and above the amount of the Bradley Minimum Flow Releases to energy, utilizing the appropriate conversion factors. Each Purchaser with a Net Allocation greater than zero during a spill period shall have its Net Allocation as adjusted in Section 5(g) reduced pro rata based upon each such Purchaser's Net Allocation, such that the total reduction for all Purchasers is equal to the amount of energy in the Project spill. (c) In the event of Project Spill, the Authority will provide a conversion of Water Spill into Energy. If MWH at Risk exist at Spill, then the Project Spill will be subtracted from each Purchaser's Pond and Allocation by proportionate share of MWH at Risk. If the spill energy exceeds the amount of risk (i.e. if spill is 10,000 MWH and 8.051 MWH was at risk) then all energy generated during spill and prior to spill could not be counted in the utility allocation for that year. A new allocation for each utility would be developed at the end of the spill based upon each utility's project share and a full reservoir. ill on Ai 1, 1992 E 5,000 rs from MWH at Risk on Ai 199; Previous Example CEA MEA GVEA HEA AMLP TOTAL MWH at Risk 3,079 2,165 0 8,051 Ratios at Risk 0.382 0.269 0. 0 1.000 Spill Distribution _1,910 1,345 0 5,000 92Q4\NK3849(12) EXAMPLE ill on A 1, 1992 Equ: 10,000 Using Numbers from MWH at Risk on August 1, 1992 Previous Example CEA MEA SES GVEA HEA AMLP_ TOTAL MWH at Risk 3,079 1,495 127 2,165 1,185 0 8,051 Ratios at Risk 0.382 _0.186 _0.016 _0.269 _0.147 0 1.000 Spill Distribution _3,079 __1,495 127 2,165 __1,185 0 8,051 Section 8. Losses. (a) General. The losses provided for in this Section 8 shall be accounted for in kind by reducing the amount of energy delivered to each Purchaser and not by direct monetary compensation. (b) — Losses on Project Transmission. Losses on the transmission lines of the Project shall be determined pursuant to load flow studies. (c) Losses_on the HEA System. Losses on the HEA transmission system under various operating conditions shall be determined by the PMC in accordance with load flow studies. The studies shall be performed with and without the Project, and a matrix of loss factors developed for various projects. HEA load levels and transmission system operating conditions. The loss factor matrix shall be of a form and format suitable for hourly accounting of losses. If actual operating and dispatch experience indicates that the loss factors may need adjustment, further studies under the above conditions shall be done, taking into account any adjustments that experience may dictate. (i) The Dispatcher shall maintain records adequate to determine the relevant HEA load levels and transmission conditions when particular deliveries of Project power are accomplished. Such records shall be made available to the parties in the HEA Transmission Sharing Agreement upon reasonable request. (ii) Deliveries under the HEA Transmission Sharing Agreement shall be reduced for line losses as appropriate under the matrix of line losses developed under this subsection. (d) Losses on the Chugach Electric System. Deliveries by the Chugach Electric System over its transmission facilities may be accomplished by Direct Transmission (as defined in the Chugach Services Agreement) or through Offsetting Flows (as defined in the Chugach Services Agreement). (i) The Dispatcher shall maintain records adequate to determine the extent to which particular deliveries are accomplished in whole or in part by each of these means. Such records shall be made available to the Wheeling Utilities (as defined in the Chugach Services Agreement) upon reasonable request. 92Q4\NK3849(13) (ii) If and to the extent deliveries are accomplished by Direct Transmission, such deliveries shall be reduced for line losses. The reduction shall be by a percentage equal to the average percentage line losses on Chugach's wholesale system, such wholesale system line losses to be determined in Chugach's periodic rate adjustment proceedings or (in the absence of such a proceeding) through reasonable line loss studies prepared by Chugach not less frequently than once every two years; provided, that if, after a reasonable period of experience in actual operation under the Services Agreement, Chugach's system line loss studies prepared for use in Chugach's periodic wholesale and/or retail rate adjustment proceedings demonstrate that Chugach's wholesale system line losses have increased as the direct result of Bradley Lake Energy (as defined in the Chugach Services Agreement) delivered by Direct Transmission, then deliveries of such energy through Direct Transmission shall thereafter be further reduced for line losses to the extent of the increase in Chugach wholesale system line losses attributable thereto. (iii) If and to the extent deliveries are accomplished through Offsetting Flows as defined in the Chugach Services Agreement, such deliveries shall not be reduced for line losses; provided that if , after a reasonable period of experience in actual operation under the Services Agreement, Chugach's system line loss studies prepared for use in Chugach's periodic wholesale and/or retail rate adjustment proceedings demonstrate that Chugach's wholesale line losses have increased as the direct result of Bradley Lake Energy delivered through Offsetting Flows, then deliveries of such energy through Offsetting Flows shall thereafter be reduced for line losses, but only to the extent of the increase in Chugach wholesale system line losses attributable thereto. Section 9. Spinning Reserves. The Operation and Dispatch Committee shall recommend to the PMC a method for allocation of Spinning Reserves in each hour under various system operating conditions. Once approved by the PMC such Spinning Reserves shall be made available in accordance with sch method as follows: (a) Spinning Reserves shall be allocated to each Purchaser on a pro rata basis based on its Percentage Share of Project Capability net of any Project Generation scheduled by the Purchaser. (b) Any additional Spinning Reserves that can be made and are available at the Project in addition to Spinning Reserves normally available in any hour as a result of operating other resources shall be allocated on a pro rata basis to each Purchaser in proportion to that Purchaser's contribution of such other resources. Section 10. | Amendment or Replacement of Procedures. Upon the request of any Purchaser or the AEA, the Operation and Dispatch Committee shall review any proposal to amend or replace these Procedures at the Committee's next meeting and make a recommendation regarding such proposal to the PMC as soon as practicable thereafter. It is the intent of the PMC that the Operation and Dispatch Committee monitor the application of these Procedures and periodically recommend changes which improve overall administration to the Purchasers, and reduce, where practicable, the obligation of the Authority to provide information or revised data which is not useful to the Parties. 92Q4\NK3849(14) EXHIBIT A Description of Reservoir Operation Model (To Come) 92Q4\NK3849(15) E ITB TURBINE OPERATION The following schedule shall be used to determine the operation of the Bradley Lake generators, assuming both units are available for operation: Pl hedul Speed Mode Condense Mode Note Schedule< 10 MW No Units None, One or Both Units #1 10 MW<Schedule <20 MW One Unit One Unit #2 20 MW<Schedule <30 One Unit One Unit/No Unit #3 Schedule > 30 MW Both Units No Units Note #1 - If any participant could utilize the spinning reserve from a unit or a second unit in the condense mode, one or both units will be operated in condense. If no utility requests the additional spinning reserve, only one unit will be operated in condense if required for voltage control unless a unit is changed to condense to avoid a shutdown. Note #2 - Depending on spin requirements, either one unit will be operated alone in the speed mode or both units will be operated, one in speed and one in the condense mode. A utility can request the unit be operated in the condense mode as opposed to altering its schedule if in conflict with the minimum four hour down time. Note #3 - Any scheduling utility can require both units to be placed on-line between 20 and 30 MW if desired by that utility, although it would be possible to operate one unit in speed and one unit in condense mode at these levels to obtain the entire spinning reserve allocation for the plant, the more efficient operation would be for both units to be operated above 10 MW each in speed mode. Minimum Unit Shut Down Each unit scheduled for shutdown shall be shut down for a minimum of four hours. Operation of a unit in the condense mode will not constitute a shut down and does not have a four hour minimum time associated with it. The following criteria shall generally govern the operation of the plant during islanded and non-islanded conditions: 92Q4\NK3849(16) ISLANDED OPERATION nschei Islandin; If the Kenai is operating with only Bradley Lake or Bradley Lake and Cooper Lake prior to islanding, on Bradley Lake unit will automatically be placed in deflector by the Chugach SCADA system upon detection of islanding. The unit will remain in deflector until a Kenai area gas turbine has been synchronized with the islanded Kenai system. After a gas turbine has been synchronized with the Kenai system the unit will be changed to the speed mode from the deflector mode. During load restoration on the Kenai, one unit may be placed in deflector control to aid the gas turbine in load pickup and frequency restoration. The unit will be returned to speed mode after restoration has been completed. heduled Islandin Prior to scheduled islanding a Kenai area gas fired generator will be synchronized with the Kenai system. Bradley generation will remain in the speed mode. Isl ration - St While running islanded, a gas-fired generator shall be operated in conjunction with Bradley Lake. The Bradley Lake units shall be operated in the speed mode. If an on-line gas-fired turbine suffers a forced outage and it is the only gas-fired unit on-line in the islanded system, one Bradley Lake unit shall be placed in deflector mode and operated in deflector until a gas-fired generator is placed on-line in the islanded area. INTERCONNECTED OPERATION - STEADY STATE While Bradley Lake is interconnected to the Anchorage system, its normal mode of operation shall be the speed mode for both units. During times of system load restoration, one Bradley Lake unit may be placed in the deflector mode if the amount of load to be restored will not exceed the export or operating limits of the Kenai system. EM:nk 92Q4\NK3849(17) DATE: TO: FROM: SUBJECT: Alaska Energy Authority MEMORANDUM April 1, 1993 aoe COPY Bradley Lake Hydroelectric Project sR EL Project Management Committee 5/13/93 Ronald A. Garzini c he Executive Director Alaska Energy Authority Diamond Ridge Relaying Homer Electric Association Billing Attached is a letter dated January 4, 1993 from Homer Electric Association (HEA), which outlines their costs associated with the installation of the Diamond Ridge transfer trip relays. The total installed cost is $107,115.45. This work was required as part of the protective relaying for Bradley Lake and, as such, is an appropriate project cost. Although the work was discussed and recommended by the Technical Coordination Committee, our records do not reflect any formal action having been taken by the PMC. Construction funds for this work were included as part of the project budget for Utility Support Cost. HEA's previous billings for this work contained several errors which have now been corrected. Accordingly, it is recommended that the PMC approve payment in the final amount of $107,115.45 for this work. DE:RAG:jd Attachments as stated. 93Q1\JD4567(1) Homer Electric Association, Inc. CORPORATE OFFICE Central Peninsula Service Center 3977 Lake Street 280 Airport Way Homer, Alaska 99603-7680 Pouch 5280 Phone (907) 235.8167 Kenai, Alaska 99 FAX (907) 235-3333 Phone (907} 28: FAX (907) 283-7122 January 4,1993 RECEIVED JAN 5 1998 bave Eberle ajaske Energy Authority Alaska Energy Authority 701 East Tudor Road P.O. Box 190869 Anchorage, AK 99519-0869 Re: Bradley Relaying at Diamond Ridge Billing of 9/30/91 Letter of 3/23/92 Dear Dave: In accordance with your request, we gave the following breakdown of the costs for the billing of 9/30/91. In addition, at your request we again reviewed the billing and made some further modifications to the relay portion of the billing. The following is a recap of the original breakdown and modifications in my letter of March 23,1992 and the additional modifications for the relaying portion. These represent the final amounts we desire to collect for the work done, and this letter supersedes the letter of March 23,1992. For the first item, the RTU adjusted costs, we will adjust to the maximum amount approved by the Project Management Committee. Amount approved by PMC $31,000.00 Less prior payment ($29,570.00) Balance Due $ 1,430.00 The second item billed was for 1/2 the cost of the telephone switch that was anticipated to be used by the project for interrogating the relaying and microwave sites. You have advised that your research has revealed that this item was never approved by the TCS with some other items in 1988. It had been our previous understanding that this had been submitted by Tom Small and approved. If this is not the case, we stand corrected, and will drop this portion of the billing. The third item was related to installation of the Transmission Line Transfer Trip relaying system to match those installed at Bradley and Soldotna. The basic relays and tone gear was furnished to Homer Electric by the project. However, we had to purchase the panels and remaining equipment necessary for a Dave Eberle January 4,1993 Page 2 complete installation. The bill has been adjusted to reflect that two invoices were received after:the bill was rendered, items were discovered to be related to SCADA rather than the relaying. In addition, we have adjusted the amount of overhead charged to be consistent with the ratio used for the remaining transmission line work which was done for this project and for and some which the other participants have paid. These adjustments result in the total being different than the original bill. Labor (including HEA Eng. and Inst'l) $36, Overhead $24, Equipment and Transportation $5, Material: Transfer Trip Relaying and tone gear. Furnished by Project $ Relay Modems and Telco PBX eq. Ue Control Panel Fabrication including equipment mounting $18, Satellite Clock 3 47; SEL-Metering and Cabling $ 5, Synchrocloser Unit and Relay $.6, Total Material $40, Total Installed Cost $107, If you need further information, please advise. Sincerely yours, HOMER ELECTRIC ASSOCIATION, 270.07 765.20 543.93 0.00 995.00 967.00 147.00 777.25 650.00 536.25 115.45 -.C. Watthirng S. C. Matthews Major Projects Engineer scM/js CC: RF - SCM Fair Story INC.