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Home My WebLink AboutBPMC August 23, 1991 3TO: FROM: DATE: SUBJECT: RECORD UOPY FILE NO Alaska Energy Authority MEMORANDUM L Bradley Lake Project Management Committee Charlie Busskil_ \\ = Secretary, ll a August 20, 1991 August 23, 1991 Bradley Lake PMC Meeting Enclosed for your review is a copy of the Draft Agenda for the August 23, 1991 meeting of the PMC. Please provide any corrections or additions to Chairman Kelly. The meeting place will be at Chugach Electric Association in the Training Room at 10:00 a.m. Also enclosed for your review is a copy of the draft meeting minutes of the July 2, 1991 meeting and the pertinent back-up material distributed at the meeting, which will be considered at the August 23, 1991 meeting. An executed copy of the March 5, and June 6, 1991 meeting minutes are enclosed for your records. DS/CB/ds 10. 12. 13, 14. BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE August 23, 1991 CHUGACH ELECTRIC ASSOCIATION TRAINING ROOM - 10:00 A.M. CALL TO ORDER 10:00 A.M. ROLL CALL PUBLIC COMMENT AGENDA COMMENTS APPROVAL OF MINUTES July 2, 1991 TECHNICAL COORDINATING SUBCOMMITTEE REPORT INSURANCE SUBCOMMITTEE REPORT BUDGET SUBCOMMITTEE REPORT OPERATION AND DISPATCH SUBCOMMITTEE REPORT REVIEW OF PROJECT STATUS NEW BUSINESS a. Dispatch Agreement b. Approval of Committee Expenses COMMUNICATIONS a. Schedule Meeting ADJOURNMENT Kelly Burlingame Petrie Ritchey Sieczkowski Eberle Sieczkowski Saxton DRAFT BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE JULY 2, 1991 CALL TO ORDER Chairman Kelly called the Bradley Lake Project Management Committee to order at 10:08 a.m. in the Training Room at Chugach Electric Association in Anchorage, AK to conduct the business of the Committee per the agenda and the public notice. ROLL CALL Alaska Energy Authority Charlie Bussell, Representative Brent Petrie, Alternate Chugach Electric Association David L. Highers, Representative Joe Griffith, Alternate Golden Valley Electric Association Mike Kelly, Representative and Chairman City of Seward E. Paul Diener, Representative Homer Electric Association Norman L. Story, Representative Matanuska Electric Association Ken Ritchey, Representative Municipal Light and Power Thomas Stahr, Representative Hank Nikkels, Alternate Other Present: Ron Saxton, Purchasing Utilities Moe Aslam, Municipal Light and Power Dave Calvert, City of Seward Bradley Evans, Chugach Electric Association Tim McConnell, Municipal Light and Power Bob Hufman, Alaska Electric Generation & Transmission David Fair, Homer Electric Association David Burlingame, Chugach Electric Association Tom Lovas, Chugach Electric Association John Cooley, Chugach Electric Association David Eberle, Alaska Energy Authority Stanley Sieczkowski, Alaska Energy Authority DeAnna Scott, Alaska Energy Authority Patti Harper, Alaska Energy Authority Mark Harris, ARECA PUBLIC COMMENT There being no public comment, Chairman Kelly proceeded to agenda item 4. AGENDA COMMENTS Chairman Kelly asked if there were any additions to the agenda. Under number 13, New Business; Item A to reflect Election of Officers and Item 13 e added to include discussion on the Dedication Services of the Bradley Project. APPROVAL OF MINUTES Chairman Kelly asked for corrections or additions to the June 6, 1991 meeting minutes. Mr. Story corrected, Dave Fair is now with Homer Electric and not Chugach Electric. Mr. Saxton corrected under Bradley start-up and commercial operation "the life of operation is 9OMW level and should say although length operation at the 90 MW level is not covered under the Power Sales Agreement. Reasonable operation and scheduling output on a commercial basis is required." On page 8, "delete the PMC tax exempt status and insert, "bonds tax exempt status". On page 8, under CHAIRMAN KELLY instruction to the TCS it should read Chairman Kelly instructed the TCS, through Mr. Burlingame, to develop operating scenarios with 80 MW and 90 MW caps. Mr. Highers stated again on page 8, starting with "MR. HIGHERS stated this turbine would be on-line due to the absence of the second transmission line", add, "prior to Bradley Lake operation". The June 6, 1991 meeting minutes were approved with these modifications by acclamation. TECHNICAL COORDINATING SUBCOMMITTEE REPORT Mr. Burlingame reported there was one full committee and one subcommittee meeting. The full committee has requested SWEC to put together the operating guidelines, reports, and studies that have been completed and accepted for the use of the PMC. The Subcommittee of the TCS met to discuss the start-up and testing requirements. Mr. Burlingame stated there is an advisory memo attached to the TCS report which seeks guidance from the PMC, because the minimum operating criteria has the TCS bogged down. The Long Term Operating Limits study will be started after the Interim Operating and Import Study has been completed by PTI. Mr. Burlingame asked that the PMC refer to the memo addressing the Kenai Import Levels - Advisory Item. He stated the TCS is requesting future direction to properly address the acceptable level of load shedding and avoid contractual obligations. The TCS took eight cases out of the twelve months and evaluated what the limits of Bradley Lake would have to be to achieve the same risk of load shedding. This issue needs to be addressed. The TCS is asking for specific directions as to what percentage or stage of load shedding should HEA be subject to. Chairman Kelly asked that this subject be suspended and address Mr. Highers letter that was circulated between HEA and CEA that dealt with Bernice turbine. Mr. Highers stated that his staff along with Mr. Story and staff met and discussed at length the obligations of what would happen as far as running the turbine on the Kenai after Bradley is on line. Mr. Highers stated the letter signed by both he and Mr. Story gives basically the position that the TCS is in now. Mr. Highers suggested the letter be read because it may answer some of the questions. Mr. Highers stated that the last paragraph is a recommendation to the PMC for the Operations and Dispatch Subcommittee to have an assignment over this. Mr. Highers recommended the assignment to the TCS on the Minimum Operating Criteria not deal with contractural matters but to deal specifically with the issues that have been presented. Mr. Stahr suggested that a complete full load operation curve for Homer be develop and applied against the total energy on Bradley and looking at the Dispatch and Scheduling Committee. and applying that against the total energy on Bradley and looking at the Dispatch and Scheduling. Mr. Highers moved, seconded by Mr. Story that the TCS sets the operating criteria for Bradley based on Homer Electric and Seward being subject to no more than stage two load shedding for any single contingency event. . Mr. Stahr moved that this motion be tabled until the results from the other study are available. Mr. Stahr's motion failed for the lack of a second. - Mr. Highers amended the motion to this operating criteria shall be used until such a time as that the final operating conditions are adopted by the PMC. Chairman Kelly asked the roll to be called. The motion with its amendment passed unanimously. Mr. Burlingame stated that there was one motion for the Operations and Dispatch Subcommittee. Mr. Highers_moved, Mr. Stahr_ seconded that the PMC direct the Operations and Dispatch Subcommittee to development a procedure to identify the system operating conditions that allow the Bradley participants to readily note or record Chugach's service needs for Kenai area combustion turbine versus those conditions of providing combustion turbine to support the operation of Bradley Lake. The roll was called and this motion passed unanimously. INSURANCE SUBCOMMITTEE REPORT Mr. Petrie stated that the Insurance Subcommittee had nothing to report at this meeting. BUDGET SUBCOMMITTEE REPORT Mr. Ritchey reported the Budget Subcommittee met and will be meeting on July 22, 1991. Mr. Ritchey stated the Budget Subcommittee members are in the process of reviewing the latest information distributed by Chugach Electric addressing the wheeling charges. 10. The subcommittee has looked at the Homer Electric O&M expenses for the transmission line and had no problem with the numbers. The subcommittee has sent a letter to HEA and ask for a calculation under their wheeling agreement. The Budget Subcommittee recommends to the PMC the monthly payments be made at the beginning of the month to meet the mid-December obligation. The Subcommittee is working to delay as many expenses as possible in the first year. The committee is looking at reducing the reserve account to help pay the debt service. Mr. Saxton stated that the easy way to solve the cashflow problem would be to have higher payments for the first few months of the first year and anything left that would be left would stay to the benefit of the utilities which would be applied to the second year budget. Another suggestion was to have uneven payments for the first year operation. Both suggestions are at odds with the instructions the PMC gave to the Budget Subcommittee by having the absolute lowest payment possible for the first year. The uneven payments, however, are at odds with the language for 12 month payments. It is within the PMC’s power to change both of those. The payments for the first four months would be about $100,000 higher and then the second 6-months the payment would be leveled but a lower cost. Chairman Kelly asked if the PMC had any objections to the first payments being higher for four months. No objections were stated. Chairman Kelly gave the subcommittee two directives from the PMC: 1) the first four months of FY92 the ents to the trustee would be higher to eliminate the cashflow problem and 2) the payments will be due on the first of each month. OPERATION AND DISPATCH SUBCOMMITTEE REPORT Mr. Sieczkowski reported that the Operation and Dispatch Subcommittee met on June 20, 1991. There were no conclusions or decision coming out of that meeting. - AEA is working on updating the allocation information developed by SWEC. Mr. Evans stated that CEA has submitted test power cost information for combustion turbines related to testing. CEA has agreed to certain conditions on test power and agreed to some fundamental load restoration. Work has been completed on dispatching to the Homer system to Dimond Ridge. Interchange schedules have been developed and passed out to all of the participants for comments. Station service accounting for the power plant was suppose to be submitted by Homer. A loss table for HEA is still pending so the subcommittee can schedule the project and know what losses to allocate to Homer BRADLEY LAKE AGREEMENT SUBCOMMITTEE REPORT Mr. Sieczkowski reported the Subcommittee met on June 13, 1991 and reviewed the existing agreements and went over the assignments. Future agreements that may need to be develop for the Bradley Project such as a Memorandum of Understanding for the interconnecting utility operation between CEA and Homer to direct them to perform switching. Another draft was received from CEA on June 21, 1991 for the Dispatch Agreement and it is being reviewed. The Subcommittee looked at the other agreements for consolidation and coverage. AEA will contact Homer Electric to pursue the AEG&T Transmission Line Agreement. Chairman Kelly asked if there were any comments or questions. The Dispatch Agreement is to be submitted to the Operations and Dispatch Subcommittee and the PMC for review. 11: 12. 13. REVIEW OF PROJECT STATUS Mr. Eberle reported the General/Civil contractor is complete. There is some minor painting, guard rail repairs, and miscellaneous punch list items left to be done. The Construction Camp was closed July 1, 1991 and is in the process of being demoblized. The powerhouse construction is physically complete., Clean-up and on-staff support is all that is on-site. Synchronized test was completed a couple of weeks ago and units loaded to ten percent power. The week of June 24, 1991 there was no active testing, they were working on some punch list work. The week July 1, 1991, remote start and stop testing will begin and the week of July 8, 1991 we will get into the serious loading of the units and load rejection tests. The target date for utility testing is set for July 26, 1991. Water in the reservoir, on July 2, 1991, was at level 1121. The run off should continue very heavy throughout July and August. If there is not a tremendous amount of water used during the testing phase, we should have a full pool by September 1, 1991. UNFINISHED BUSINESS A. Bernice Lake Gas Turbine Generator Operation Costs This item was addressed under Item number 6, Technical Coordinating Subcommittee Report. NEW BUSINESS A. Election of Officers Chairman Kelly appointed Mr. Diener, Mr. Ritchey and Mr. Story to serve on the nominating Committee for the Bradley Lake PMC offices. The PMC recessed at 11:50 a.m. in order to allow the Nominating Committee to meet and select their nominees. The Bradley Lake PMC meeting reconvened at 12:00 p.m. Chairman Kelly asked for a report from Mr. Diener Chairman of the Nominating Committee. Mr. Diener reported the Nominating Committee agreed unanimously to moved that the current office holders be extended for the next term.:Chairman,Mike Kelly; Golden Valley Electric, Vice-Chairman, David Highers; Chugach Electric and, Charlie Bussell Secretary/Treasure, Alaska Energy Authority. Mr. Highers seconded. The roll was call. This action passed unanimously. B. Resolution Regarding Project Completion and Commercial Operation Mr. Saxton reported that this resolution was completed on July 1, 1991. This resolution restates the cost of acquisition and construction will continue until the project is completed which will be after commercial operation. Mr. Saxton requested the PMC to review the resolution. The resolution was reviewed by the PMC members and Mr. Stahr moved, Mr. Ritchey seconded that the Bradley Lake PMC adopt the Bradley Lake Project Management Committee Concerning the Alaska Energy Authority Obligation to Complete the Bradley Lake Hydroelectric Project and to Share the Cost of Acquisition and Construction With the Power Purchasers Until the Project is Complete Resolution. The roll was called. This action passed unanimously. 14. Upper Battle Creek Diversion Mr. Eberle reported he is awaiting some detailed survey information. Mr. Eberle went to the area the week of June 24, 1991 and thinks the scope of work can significantly reduced. He would hope to do it for $250,000 or less based on what was seen. AEA should have more information the week of July 8, 1991. Allocation and Scheduling Procedure Mr. Sieczkowski reported that the Operation and Dispatch Subcommittee recommended the Allocation and Scheduling Agreement be adopted subject to the completion of Exhibits A and B. Mr. Ritchey moved, Mr. Highers seconded the recommendation. Mr. Sieczkowski stated that on Exhibit A is a description of the reservoir operation model and as it was explained, this was the model to be used by the dispatchers. Exhibit B is a description of the project operating criteria and will define operational issues. Mr. Fair stated that HEA propose to make the change to delete the $5.00 per MWH at this point. Chairman Kelly asked if this was being made in the form for of an motion or to amend the motion. Chairman Kelly asked if there was a second to the motion to amend? Hearing no second the motion to amend dies for the lack of a second. Considering the main motion, Chairman Kelly asked if there were further comments or questions. Mr. Highers asked if it was appropriately stated as a procedure? Mr. Saxton stated, back in December this document was changed from an Agreement to a Procedure to be adopted by the PMC. Mr. Story stated that under Section 1 (aa) to add systems condition. Mr. Story moved seconded by Mr. Highers to amend the motion to include under a_on page 3 (aa) to add language after account to state as system conditions, equipment and project administration. Chairman ask if there was any discussion on the motion to amend, being none the roll was called. The roll was called with Messrs. Story, Kelly, Bussell, Diener, Ritchey voting yes and Mr. Stahr voting no. The motion passed. With the main motion being on the floor, Chairman Kelly asked there was further discussion on the main motion, being none the roll was called. This motion passed unanimously. Bradley Lake Dedication Mr. Eberle stated that August 23, 1991 is the date preferred by the Governor's Office. Mr. Bussell stated that AEA is developing the program around August 23, 1991. The list is being developed to determine and define details. As soon as AEA has ironed out the detains, we will have a draft to the PMC for review. COMMUNICATIONS A. Scheduled Meeting August 16, 1991 Chugach Electric Association Training Room - 10:00 A.M. 15. ADJOURNMENT Having no further business to bring before the Committee, the meeting was adjourned at 1:10 p.m. Chairman Kelly Attest: Charlie Bussell, Secretary Approved at the August 23, 1991 PMC Meeting \ ’ CHUGACH ELECTRIC > ASSOCIATION, INC. in gaa ASSOCIATION INC July 2, 1991 Mike Kelly, Chairman Bradley Lake PMC Alaska Energy Authority 701 E. Tudor Road Anchorage, Alaska 99519 Mr. Chairman: The Bradley Lake Project Management Committee (BPMC) discussed the conditions under which a combustion turbine located on the Kenai Peninsula would be operated. As Chairman, you suggested that the utilities, Chugach Electric Association and Homer Electric Association, who have generation assets on the Kenai Peninsula coordinate a joint position on this issue. The general managers of both utilities met subsequent to the meeting of June 6, 1991 and have agreed on the following items: 1 After Bradley Lake has been declared commercially operable, during periods when Bradley generation is not scheduled by any of the participants, operation of a Kenai located gas-fired turbine will be used as required to meet the same quality of service as historically experienced by Homer. If Bradley Lake is scheduled by any or all participants, then the capacity available within the stability and reliability limits during that scheduled period shall be shared by participants in accordance with their respective shares as defined by the Bradley Lake Power Sales Agreement and the Scheduling Agreement. tu Neither Chugach nor AEG&T will solely absorb any costs associated with the operation of a gas-fired turbine located on the Kenai Peninsula which enhances the output or stability of Bradley Lake and provides benefits to each of the participants. All scheduling participants benefit from the increased output and/or capacity available from Bradley Lake as a result of the operation of a gas-fired turbine. Each scheduling participant must pay its fair share of the costs of making additional capacity available through the use of a gas-fired turbine. 3. We specifically reject the notion that operation of a gas-fired turbine located on the Kenai is necessary at all times and that others may enjoy the benefits of increased Bradley output at no cosi. Cnugach, AEG&T and HEA have not made any contractual commitments to operate a combustion gas-fired turbine on the Kenai Peninsula after Bradley Lake becomes operational. 5604 Minnesota Drive ¢ P.O. Box 196300 « Anchorage, Alaska 99519-6300 Phone 907-563-7494 # FAX 907-564-8406 or 907-562-0027 Mike Kelly, Chairman -2- July 2, 1991 We base these positions on the following known or calculated technical aspects of Bradley Lake. L The voltage on the HEA system can be supported by Bradley Lake when it is on line, or by any other means available to Chugach or AEG&T to meet the service requirements of the Peninsula. The specific geographic location of any added, shared resource does not alter the expected quality of service for any service area. Ds To maintain required stability of the interconnected systems when Bradley Lake is operating at full capacity, the installation of SVS components is required. The SVS is currently scheduled to be in operation by December 1992. Until this installation is complete and proven effective, export of Bradley Lake energy above the level of approximately 2 MW in winter and 16 MW in summer is not possible without a gas- fired turbine operating on the Peninsula if Cooper Lake generation is on line. Measures to enhance the performance or flexibility of Bradley Lake above these levels, such as concurrent operation of a Kenai area gas turbine, must be considered by the Committee as integral parts of the costs of operating the project. 3. The operating levels of Bradley Lake during the interim operating period have not been set to date, but are expected to be approximately 30 MW minimum to 60 MW maximum without the operation of a Kenai located gas turbine. If such a turbine is operated, then the minimum level of Bradley Lake is approximately 10 MW and the maximum is between 65 and 75 MW. No operation above 65 to 75 MW is prudent due to the instability of the interconnected systems if a single contingency event occurred. We suggest that the BPMC direct the Operations and Dispatch Subcommittee to prepare recommendations concerning the allocation of costs to the project participants utilizing Bradley energy or capacity made available solely by the running of gas-fired generation exclusively to improve the flexibility or performance of Bradley Lake. These recommendations should be developed and presented to the participants before the next scheduled BPMC meeting. Final resolution of this issue must be adopted prior to July 26, 1991. Sincerely, CHUGACH ELECTRIC ASSOC., INC. Ld INC. ~ -/ David L. Highe N. L. Story Cu General Manager General Manager JUL 31 “91 3a 12PM re IMER Ps Homer Electric Association, Inc. CENTRAL OFFICE: 3977 LAKE STREET @ HOMER, ALASKA 99603 @ (907) 235-8167 July 1, 1991 ae | | (3S 4 Lat Mr. Charlie Bussell ; Executive Director = Alaska Energy Authority pe P.O. Box 190869 N Anchorage, AK 99519-0869 Proposed Bradley Lake Allocation and Scheduling Procedures Dear Mr. Bussell: We have completed management review of the subject procedures being considered for adoption on July 2 and have the following comments: 1) 2) Section 4 (d) (ii) specifies that when a monthly Net Allocation is estimated to be less than the previous forecast that the negative adjustment be carried forward to the following water year. It is our understanding that the intent of the participants under these procedures is to balance all accounts at the end of the water year. Carrying an estimated negative balance forward to the following water year would geem to be contrary to that intent. Also it would allow a participant who happened to be overdrawn at this point to delay paying back the other participants until the following water year. It would appear that there should be an intent to keep the accounts as current as possible so one participant cannot use someone else's water and wait until next water year to pay it back. This could be especially detrimental to a participant saving up to use a large block later in the water year. Section 5 (g) (ii) sets a fixed contractual compensation of $5/Mw/Hr by a Purchaser scheduling another Purchaser's Project Capability. We believe this compensation should be a market transaction made at the time of purchase scheduling because the value of this will vary over time. Presumably we want to adopt these procedures and have them serve for an extended period of time. Therefore we should not set specific values for something that will surely vary over time, and could vary with each transaction. se tees ———- . weeevedekanrrreeee reeks y FAX RANSM! TAL MEM T to: Charlie ell pet. AER eax: SG/- 9584 Paces rROW-_Dave Fair _owone aas-$ssp | 2 co: FAX a: ASS“ 3313 Peat-tt~brand fax tranamittat memo 7671 wit: Cc XC Stan S < Dave TE. sien JUL 31°91 34:13PM HES MER P.4 Mr. Charlie Bussell July 1, 1991 Page 2 The Operations and Dispatch Subcommittee has put a great deal of effort into this document, and overall it will serve the purpose intended. We believe, however, the above two issues should be reviewed and modified by the PMC. Sincerely yours, HOMER ELECTRIC ASSOCIATION, INC. 4S N. L. Story General Manager NLS/ js CHUGACH ELECTRIC ASSOCIATION, INC. Anchorage, Alaska July 2, 1991 TO: Bradley Lake Project Management Committee FROM: David Burlingame, TCS secretary J? SUBJECT: TCS Report The following items are a brief synopsis of the activities of the TCS since the last PMC meeting: Operating Guidelines - SWEC has begun gathering all of the reports and recommendations made concerning the operation of Bradley Lake and the Kenai system. This together with certain plant operating procedures will be distributed to all of the participants for their use in scheduling their allocation. The TCS will not review each of the studies prior to their incorporation if they have previously been accepted by the TCS. Start-Up and Testing Program - A subcommittee to the TCS has met and agreed on the tests required for Bradley Lake. Some of the tests will not be performed until after the SVS systems are installed. The program has not been ice are | to the T¢cs, but its, approval is expected. wy OS fe yo te fr «enw Minimum Operating Limits - The determination of the minimum operating limits for Bradley Lake has bogged down and is awaiting direction from the PMC. A separate advisory item has been prepared and is attached. A 5 Long Term Operating Limits - eae which is to define the operating limits of Bradley Lake after the installation of the SVS systems has not been started to date. It will not be started until after the interim operating and import study have been completed. DWB/pna DWB5-JLYPMC Attachment CHUGACH ELECTRIC ASSOCIATION, INC. Anchorage, Alaska July 2, 1991 TO: Bradley Lake Project Management Committee FROM: David Burlingame, TCS Representative 77 SUBJECT: Kenai Import Levels - Advisory Item The PMC has asked the TCS to determine the level of Kenai imports which should be allowed based on a reasonable degree of loadshedding in the HEA system. The TCS was directed to determine what level of loadshedding was considered reasonable without discussion of contractual agreements or understandings. The PMC reserved the exclusive right to interpret these matters. The TCS approach to this matter was to study Kenai area dispatch cases over the past year and to assess the risk of loadshedding the Kenai has experienced on a historical basis. The risk of historical loadshedding would then be selected and the risk of loadshedding after Bradley Lake would be set to match the historical risk as much as possible. PTI has completed the original studies set forth by the TCS and made a global recommendation that without a gas turbine, Bradley Lake should not be operated at a MW level which is below the load left on the Kenai after the desired loadshedding has occurred. Operating Bradley Lake below this minimum load level will result in a blackout of the Kenai following the loss of the 115 kV system to Anchorage. The committee basically bogged down at this point discussing contractual agreements and commitments between the participants. Some of the members felt that even though these issues were reserved to the PMC level, they should be discussed and possible solutions outlined at the TCS. The final agreement of the committee was to recommend to the PMC that Bradley Lake not be operated at a level below the load level left on the Kenai after the final stage of desired loadshedding has occurred. Based on the historical risk of loadshedding as outlined in the PTI report, the majority of the committee felt the second stage of loadshedding for the HEA system would be appropriate after the completion of Bradley Lake. The amount of load to be shed by HEA in the first two stages may be different than exists today as PTI revises the loadshedding schedule to reflect a hydro based system. Some members of the TCS did not want to adopt an operating criteria which would restrict the operation of Bradley Lake to this degree without specific direction from their General Managers. Bradley Lake Project Management Committee Kenai Import Levels - Advisory Item July 2, 1991 Page 2 If the minimum operating point for Bradley Lake is set such that during most instances, the Kenai will not experience more than the 2nd stage of loadshedding for any single contingency, Bradley Lake would be limited to a minimum output of 27-30 MW in the summer and 35-40 MW in the winter, whenever it is operated without a gas turbine and connected to the Anchorage system. In an islanded condition Bradley Lake would be restricted to no more than a 32 MW output, with gas fired turbines on-line. PTI has verified that operating a gas turbine on the Kenai will eliminate most of the minimum operating restrictions on the Bradley Lake units. The TCS has asked PTI to perform some additional studies to bracket the historical risk of loadshedding and the expected risk of loadshedding for the Kenai area. The TCS would like the PMC to review the philosophy of determining the historical risk of Kenai loadshedding and using this assessment to determine the acceptable risk of Kenai loadshedding after the incorporation of Bradley Lake into the railbelt used by the TCS and provide further explicit direction to the TCS in regards to this issue. Other options would be to set no restrictions on the minimum operation of Bradley Lake, which puts the Kenai at risk of a blackout, allow more loadshedding on the Kenai which effectively opens the operating window for Bradley Lake, or reduce the amount of loadshedding on the Kenai which would further restrict the operation of Bradley Lake. For reference in assessing the risk to the Kenai system, in the current loadshedding system for the Railbelt, each utility is scheduled to shed the following percentage of their loads for single contingency events (only system Stage #1 is shown). ML&EP - 11% Chugach - 13% GVEA - 32% HEA and MEA do not presently shed on the system Stage #1. PTI has recommended that HEA's loadshedding point be no higher than it presently exists at 59.0 Hz. The loadshedding study being performed under the IOC would therefor be restricted that unless the first system loadshedding point was lowered, HEA would not be subject to the first stage of loadshedding for interconnected system trouble, such as normal unit trips. Bradley Lake Project Management Committee Kenai Import Levels - Advisory Item July 2, 1991 Page 3 HEA would shed approximately 57% of their load if the operating guideline was based on Stage #2 loadshedding and during system scheduling to match this case, the 115 kV line to Anchorage was lost. The following are some general guidelines or possibilities for the minimum operation of Bradley Lake without a gas turbine based on various Kenai load levels and loadshedding. Kenai Kenai % Loadshed Bradley Minimum Load Loadshedding Operating Point 80 MW 20 MW 25% 60 MW 80 40 50% 40 80 60 75% 20 80 80 100% Oo 50 MW 10 MW 20% 40 MW 50 20 40% 30 50 30 60% 20 50 50 100% 0 It is requested that each of the General Managers provide direction to their TCS representatives as to what level of loadshedding is appropriate for the Kenai system such that each TCS representative can comfortably set the acceptable loadshedding level and consequently the operating criteria for Bradley Lake. DWB/pna DWB5-PMCJLYAD 5/17/91 BRADLEY LAKE HYDROELECTRIC PROJECT ALLOCATION AND SCHEDULING PROCEDURES adopted by the BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE on , 1991 These Procedures dated , 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. (£) Chugach Services Agreement. The Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric Power 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. (g) Dispatch 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. (1) Effective Date. 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 this Agreement. Page l - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES (k) FERC License. License No. 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 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. (©) 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). (rc) MEA. Matanuska Electric Association, Inc. (8) ML&P. Anchorage Municipal Light & 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) t Dis c - 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. Page 2 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES (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 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. (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 Model. (££) 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, such of the Municipality of Anchorage d/b/a Municipal Light and Power, Chugach Electric Association, Inc., Golden Valley Electric Association, Inc., the City of Seward as have executed this Agreement, and the Alaska Electric Generation & Transmission Cooperative, Inc. ("AEG&T). The Page 3 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES 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. (33) 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. (11) 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. This Agreement 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 into this Agreement: (a) Exhibit "A", Description of Reservoir Operation Model, and (b) Exhibit "B", Description of Project Operating Criteria. 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. Page 4 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES (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, estimates of runoff available from snowpack, precipitation for the May-October period equal to 80 percent of the long-term average, 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 the 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 (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 Operation Model are equal to one another and Project Spill potential is Page 5 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES 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, the Authority shall determine the amount of Revised Project Energy for each Purchaser 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 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 Page 6 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES 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 the 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 of 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 recommendations 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 any 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 Model. 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. No later than 5:00 p.m. on Thursday of each week (or the preceding day if Thursday is a holiday), each Purchaser shall provide to the Dispatcher a schedule of hourly Project Generation for its use for the following week commencing with 12:01 a.m. Sunday. (c) Minimum Scheduling. If the combined scheduled Project Generation from Purchasers scheduling generation is less than 10.0 megawatts in any one hour, the Purchasers shall be notified no later than 10:00 a.m. on the following Page 7 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES 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 10.0 megawatts. If such revisions still result in a combined scheduled Project Generation of less than 10.0 megawatts, 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 shall be obligated to take more than its Percentage Share of Project Capability. (e) Reductions in Schedules. If the combined scheduled Project Generation 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 5(e)(i) to an amount less than each respective Purchaser’s Percentage Share of Project Capacity. (ii) If after making such reductions in 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. (£) Schedule Modifications. In the event that a Purchaser experiences a Forced Outage on its own system, the Purchaser shall have the following rights and obligations: (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. Page 8 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES Page 9 (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 ina 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 5(a). (g) Schedules ve Participant’s 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 Purchaser’s 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 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 Fiscal Year. Using the amounts so determined, the Dispatcher shall submit a schedule of payments to the affected Purchasers which will reduce the amounts - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES 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. (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. Schedules 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. Section 6. Project Operation. The Project shall be operated by the Dispatcher pursuant to the terms and conditions of the Dispatch Agreement and consistent with that set forth in Exhibit B. Section 7. Project Spill. The parties to this Agreement recognize that from time to time water from the Project Reservoir Page 10 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES may be spilled 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, and (b) 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. 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. Page 11 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES (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). Page 12 (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. (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; vided, 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 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 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES 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 such 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 of Project operations to provide additional flexibility 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. Page 13 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES EXHIBIT A Description of Reservoir Operation Model (To Come) Page 14 - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES EXHIBIT B Description of Project Operating Criteria Number of Turbines. Based on the Project Generation scheduled pursuant to Section 5, the turbines shall be operated in the following manner: Less than 10.0 megawatts - Project not operated 10.0 - 20.0 megawatts - One turbine operated Greater than 20.0 megawatts - Both turbines operated Qperating Mode. Based on the information known at the time this Agreement is entered into, the Project shall be operated in the manner described below. The parties to this Agreement recognize that the guidelines set forth below will be modified from time to time to incorporate the findings of the Technical Coordination Subcommittee and others. Condition Mode Page 15 Islanded Grid Deflector - BRADLEY LAKE ALLOCATION AND SCHEDULING PROCEDURES RL8\der700B. doc POWER DEVELOPMENT REVOLVING LOAN FUND ESTIMATED vs ACTUAL ESTIMATED gacTuag 10-Sep-90 AU Variance | Balance, July 31, 1990 $666,058 $734,764 $68,706 FY9L Debt Service On Sales 8,867,230 9,431,328 564,098 FY9L Investment Income From Dept Of Revenue 250,000 466,273 216,273 FY 91 Interest Income From Investment 200,000 367,927 167,927 Settlemet of Four Dam Pool Lawsuit on Facilities Betterments Loan Fund (1,100,000) (825,000) 275,000 Settlement Due By Pmc 0 120,000 120,000 Reserverd For Equipment Renewal & Replacement (700,000) (700,000) 0 FY92 Fund Availability $8,183,288 $9,595,291 - $1,412,003 Less: FY 92 Appropriations To AEA Capital Appropriation (SLA9I Ch96 p38, 70-71) (7,520,0H)) (6,075,000) 1,445,000 i Operating Appropriation (SLA9L Ch73 p37) (661,800) (583,600) 78,200 AEA Cost Of Living Salary Adjustment 0 (11,700) (11,700) Reapropriation From the Fund (SLA91 Ch96 p30) 0 (825,000) (825,000) Reapropriation From the Fund (SLA91 Ch73 p3) (1,175,000) (1,175,000) Subtotal $1,488 $924,991 $923,503 Funding RPL for Tyee Lake - Swan Lane Intertie (340,000) (340,000) Projected Available Balance $1,488 $584,991 $583,503 8/19/91 ‘ t Pot td CHUGACnh ELECTRIC > ASSOCIATION, INC. in ae ASSOCIATION INC July 2, 1991 Mike Kelly, Chairman Bradley Lake PMC Alaska Energy Authority 701 E. Tudor Road Anchorage, Alaska 99519 Mr. Chairman: The Bradley Lake Project Management Committee (BPMC) discussed the conditions under which a combustion turbine located on the Kenai Peninsula would be operated. As Chairman, you suggested that the utilities, Chugach Electric Association and Homer Electric Association, who have generation assets on the Kenai Peninsula coordinate a joint position on this issue. The general managers of both utilities met subsequent to the meeting of June 6, 1991 and have agreed on the following items: iL After Bradley Lake has been declared commercially operable, during periods when Bradley generation is not scheduled by any of the participants, operation of a Kenai located gas-fired turbine will be used as required to meet the same quality of service as historically experienced by Homer. If Bradley Lake is scheduled by any or all participants, then the capacity available within the stability and reliability limits during that scheduled period shall be shared by participants in accordance with their respective shares as defined by the Bradley Lake Power Sales Agreement and the Scheduling Agreement. N Neither Chugach nor AEG&T will solely absorb any costs associated with the operation of a gas-fired turbine located on the Kenai Peninsula which enhances the output or stability of Bradley Lake and provides benefits to each of the participants. All scheduling participants benefit from the increased output and/or capacity available from Bradley Lake as a result of the operation of a gas-fired turbine. Each scheduling participant must pay its fair share of the costs of making additional capacity available through the use of a gas-fired turbine. Bs We specifically reject the notion that operation of a gas-fired turbine located on the Kenai is necessary at all times and that others may enjoy the benefits of increased Bradiey output at no cost. Chugach, AEC&T and HEA have not made any contractual commitments to operate a combustion gas-fired turbine on the Kenai Peninsula after Bradley Lake becomes operational. 5601 Minnesota Drive ¢ P.O. Box 196300 « Anchorage, Alaska 99519-6300 Phone 907-563-7494 ¢ FAX 907-564-8406 or 907-562-0027 Mike Kelly, Chairman -2- July 2, 1991 We base these positions on the following known or calculated technical aspects of Bradley Lake. IL The voltage on the HEA system can be supported by Bradley Lake when it is on line, or by any other means available to Chugach or AEG&T to meet the service requirements of the Peninsula. The specific geographic location of any added, shared resource does not alter the expected quality of service for any service area. 2. To maintain required stability of the interconnected systems when Bradley Lake is operating at full capacity, the installation of SVS components is required. The SVS is currently scheduled to be in operation by December 1992. Until this installation is complete and proven effective, export of Bradley Lake energy above the level of approximately 2 MW in winter and 16 MW in summer is not possible without a gas- fired turbine operating on the Peninsula if Cooper Lake generation is on line. Measures to enhance the performance or flexibility of Bradley Lake above these levels, such as concurrent operation of a Kenai area gas turbine, must be considered by the Committee as integral parts of the costs of operating the project. 5: The operating levels of Bradley Lake during the interim operating period have not been set to date, but are expected to be approximately 30 MW minimum to 60 MW maximum without the operation of a Kenai located gas turbine. If such a turbine is operated, then the minimum level of Bradley Lake is approximately 10 MW and the maximum is between 65 and 75 MW. No operation above 65 to 75 MW is prudent due to the instability of the interconnected systems if a single contingency event occurred. KWe suggest that the BPMC direct the Operations and Dispatch Subcommittee to prepare recommendations concerning the allocation of costs to the project participants utilizing Bradley energy or capacity made available solely by the running of gas-fired generation exclusively to improve the flexibility or performance of Bradley Lake. These recommendations should be developed and presented to the participants before the next scheduled BPMC meeting. Final resolution of this issue must be adopted prior to July 26, 1991. Sincerely, CHUGACH ELECTRIC ASSOC., INC. HO LECTRIC INC. d ta a ||eudp- Ci N. L. Story David L. Higher: General Manager General Manager BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE MARCH 5, 1991 CALLED TO ORDER Chairman Kelly called the Bradley Lake Project Management Committee to order at 10:05 a.m. in the Training Room at Chugach Electric Association to conduct the business of the Committee per the agenda and the public notice. ROLL CALL The roll call was taken and a quorum was established. In attendance were the following: Alaska Energy Authority Robert E. LeResche - Representative Brent Petrie - Alternate Chugach Electric Association David L. Highers - Representative Tom Lovas - Alternate (joined 10:20 a.m.) City of Seward E. Paul Diener - Representative Golden Valley Electric Association Michael Kelly - Representative and Chairman Homer Electric Association Norman L. Story, Representative Matanuska Electric Association Ken Ritchey - Representative Municipal Light and Power John Cooley - Alternate Others Present: Stanley Sieczkowski - Alaska Energy Authority Dave Eberle - Alaska Energy Authority Ron Saxton - Purchasing Utilities DeAnna Scott - Alaska Energy Authority Joe Griffith - Chugach Electric Association Bob Hufman - Alaska Electric Generation & Transmission Pete Fraser - Municipal Light and Power Dave Burlingame - Chugach Electric Association (joined at 10:45 a.m.) PUBLIC COMMENT There were no public comments offered. Page 2 of 8 MODIFICATION OF AGENDA Under Item No. 12, New Business A, 1) CEA Dispatching Cost and 2) FY92 O&M Budget were addressed in Item 8, Budget Subcommittee Report. APPROVAL OF MINUTES November 28, 1990 Chairman Kelly asked if there was any objection approving the November 28, 1990 meeting minutes as distributed. Hearing none, Mr. Cooley motioned, Mr. Ritchey seconded that the November 28, 1990 meeting minutes be approved as distributed. The roll was called and the motion passed unanimously. TECHNICAL COORDINATING SUBCOMMITTEE REPORT Mr. Burlingame reported the Technical Coordinating Subcommittee (TCS) met on February 21, 1991. He stated that Stone and Webster Corporation (SWEC) distributed the SVS specifications and they are currently out to bid. March 15, 1991 is the deadline date for the SVS specification comments and the technical proposals are due April 4, 1991. The price proposal will be due May 9, 1991. Chugach and GVEA are on the evaluation committee to review the technical proposals. Mr. Burlingame reported the TCS approved the use of overfrequency tripping for Cooper Lake to try and control the frequency during times of high Kenai energy export. The TCS approved unanimously that CEA would install an overfrequency tripping unit for a cost not to exceed $13,500 pending approval by the PMC. Mr. Highers moved seconded by Mr. Ritchey that authorization be given to Chugach to_ install overfrequency tripping at Quartz Creek not to exceed $13,500 to mitigate overfrequency excursions. The roll was called and the motion passed unanimously. Mr. Burlingame reported Power Technologies, Inc. (PTI) was proposing to use the existing 115 KV capacitor on the Kenai, however, after reconsideration, it would be more economical to remove the SVS capacitor bank in its entirety and delete it from the contract. Mr. Burlingame reported that AEA distributed a revised start-up and testing schedule. Unit #2 will be synchronized onto the system June 10-14 and Unit #1 will follow June 12-17. Tests are schedule to be completed July 4-15 for Unit #2 and July 6-18 for Unit #1. There would be a 30-day testing period for each unit. After acceptance, the units will be turned over to AEA for CEA to dispatch and control until commercial operation. He further reported that AEA intends to bring the plant to 120 MW output or as much as water availability would allow. The TCS stated that if the units were to be run above their stability limits, it would be at the utilities discretion and only after sufficient studies have been performed to verify the results of planned tests. Mr. Burlingame reported that Chugach has provided AEA a system maintenance schedule and AEA is going to coordinate the start-up and testing. AEA requested a similar schedule from HEA. Mr. Burlingame reported that the TCS will continue to move to include ML&P and Chugach as the Bradley Lake DECNET interface points as approved by the Intertie Operating Committee, even though GVEA has since changed its position and wants to be an interface point. Relative to dispatching of SVSs from Soldotna, Chugach needs to decide how they want this to be handled. Page 3 of 8 Mr. Burlingame reported that Power Technologies, Inc. (PTI) gave a two fold verbal presentation of the proposed operating limits for Bradley Lake during the first year of operation. The maximum levels were as previously adopted by the TCS with the following exception. PTI proposed alternative outputs which would allow higher unit capacity outputs by subjecting the Kenai systems to higher voltages than those previously established by the TCS. PTI will issue a final report in March, 1991. The second issue discussed was the minimal operation limits of Bradley. Without the operation of a gas turbine on the Kenai, if there was a loss of the line to Anchorage, the result could be cascading blackout along the Kenai. PTI has been requested to issue a second report addressing the minimal operation level Mr. Burlingame stated the TCS appeared to bog down when discussing contractual commitments or obligations of various utilities as opposed to outlining the parameters of operation. Direction was asked from the PMC. PTI has been requested to issue a second report addressing the minimal operation levels. Mr. Highers moved that the PMC direct the TCS to determine the maximum Kenai_import, i.e., minimum Bradley Lake operating limit without _a gas turbine on-line, assuming that any single contingency event will not result in more than a reasonable loss of load as determined by the TCS. The roll was called and the motion passed unanimously. Mr. Highers stated that he has been talking with Mr. Burlingame about this issue and spinning reserves and if there are concerns in the TCS regarding responsibilities, he would like them to be moved out of the TCS. He stated that any cost allocations or utility responsibilities associated with providing any required reserves will need to be decided by the PMC at the conclusion of the TCS report. Chairman Kelly stated that without objection the record would reflect that any situation with the reserves or load shed would be decided by the PMC. There were no objections. INSURANCE SUBCOMMITTEE REPORT Mr. Saxton reported that all of the insurance quotes explored by the Subcommittee came in less than expected which will be discussed as part of the Budget. Mr. Saxton stated that there is one insurance issue that is not part of the Budget, which is, business interruption insurance. Mr. Saxton asked Mr. Petrie to further explain. Mr. Petrie stated that for the first time in years there is an option to purchase business interruptible insurance. The Subcommittee asked the Division of Risk Management to find a carrier that would cover one year of debt service, O&M and fuel replacement costs for a value of $21 million. The property insurance underwriters would be interested in writing such coverage but only for the perils covered by the property insurance which is fire, earthquake, flood, etc. The premium for the business interruption insurance would be $116,000 per year. Mr. Petrie stated that some direction is needed from the PMC if there is still an interest in exploring this insurance. The Subcommittee has requested the Division of Risk Management to check and see if this could be extended to the Boiler and Machinery perils i.e., substation equipment, rotating equipment, etc. because exposures to Boiler and Machinery risks may represent a greater likelihood for a business interruption. The Insurance Subcommittee’s recommendation is to explore the insurance and see exactly what is covered and make an additional recommendation to the Budget Subcommittee. Mr. Saxton stated the business interruption insurance is budgeted at zero in the FY92 Budget Proposal. If the PMC would like for the Insurance Subcommittee to further explore the business interruption insurance, direction would be needed. Chairman Kelly directed the Subcommittee to look further into the business interruption insurance but not include it into the budget. Page 4 of 8 BUDGET SUBCOMMITTEE REPORT Mr. Ritchey reported that the deadline to adopt a budget is April 1, 1991 for FY92. Mr. Ritchey stated each member should have received a narrative from AEA that included a 10-month fiscal year budget, a cash flow analysis and Mr. Saxton’s analysis of issues related to Chugach’s dispatching cost. A yellow budget sheet was distributed to reflect the new budget number of $2,206,998 as opposed to the budget total that was attached with the narrative of $2,231,998. The difference of this is the elimination of the business interruption insurance in the budget. Mr. Ritchey noted that the dispatching cost of $150,000 proposed by CEA have been included as part of the Bradley Lake O&M budget. Mr. Saxton’s ties stated that the Transmission Services Agreement defines dispatcher as_an individual or individuals employed by Chugach, but is silent on compensation. There are a couple of issues regarding this. MC&P feels that it was the intent of the parties at the time the Power Sales Agreement and Transmission Services Agreement were executed that the cost of dispatch by CEA was included as part of transmission services. Also, if the PMC determines that payment of the dispatching cost incurred by CEA is appropriate, the Budget Subcommittee requested that the PMC direct the Operations and Dispatch Subsomniiies to review the activities and level of funding proposed by CEA, including labor, training and software costs, and provide a recommendation to the Budget Subcommittee. Mr. Cooley proposed that if the CEA Economic Dispatch Pro po is required to operate Bradley, it should be funded as a project cost which would reduce the O&M Budget and proposed $100,000 for CEA dispatching. Mr. LeResche inquired about the budgeted $20,000 Economic Dispatch Program. Mr. Lovas stated it is a CEA software package with a portion allocated to Bradley. He also stated that the total package cost is $200,000 and is amortized over a ten year period. This software is necessary and is directly tied to the operation, scheduling and disp: pa’ Bradley power. Mr. Lovas further stated if CEA was not dispatching Bradley Lake Power the Fadditional software would not be needed. Chairman Kelly asked the PMC if there was objection to the software being a project cost. Chairman Kelly also presented two additional related points: 1) He understood that CEA was going : take a look at the incremental cost for dispatching Bradley Lake power, and 2) CEA was also going to review a possible lower figure as a settlement amount. Genres Kelly asked Mr. Higher if CEA had a chance to look at this and if a settlement on the order of $100,000 would cover the cost. Mr. Highers stated that CEA has looked at this issue and their incremental cost was substantial higher than $150,000. CEA views this as compensation not reimbursement. Mr. LeResche stated, referring to Mr. Cooley’s amendment, the dispatching cost would not be allowed as a capital expense because it is a cost related to the Service Agreement and dispatching should be an O&M expense. Chairman Kelly suggested either putting a dollar amount in the budget; or putting the number to zero; but strongly recommended against holding up the budget. Mr. Story moved that the FY92 Bradley Lake O&M Budget be approved as submitted. Mr. Cooley moved to amend the motion to change the FERC Account number 561 from $150,000 to $100,000. This amendment died from_a lack of a second. The main motion being on the floor, Chairman Kelly asked if there was any discussion. Mr. Ritchey went through the budget a page ata time. He explained that the FERC account numbers 132 and 174 are initially completely funded by bond proceeds and in future years may need replenishing. He also stated that some items are based on specific values, AEA’s experience with the Four Dam Pool and other projects. Chairman Kelly asked about the CEA’s training cost of $36,000 in FERC account number 561. Mr. Loves responded that the $150,000 in FERC account Page 5 of 8 561 that includes the $36,000 for training costs was based on one years worth of expenses. FERC account 561 was reduced from $150,000 to $131,000. Mr. Ritchey noted the FERC account number 923 are estimates from AEA. FERC account number 924 Insurance, is for all of the insurance plus approximately a 10% contingency due to the possibility of the insurance inflating before the policies are actually placed. The property insurance was quoted $215,000 with a $25,000 contingency. The Boiler and Machinery was quoted at $60,000 with $5,000 contingency. The General Liability and Watercraft and Aviation Insurance is one-sixth of the State policy distributed over the Energy Authority’s six projects at $10,000 per project. Director’s and Officers Liability Insurance was estimated at $15,000. Mr. Ritchey stated that Fuel Spill coverage is not in the Budget. Mr. Ritchey stated that the regulatory expenses in FERC account 928, land use fees of $45,000 and administrative fees of $95,000 are well established. Mr. Saxton further stated these are the fees the Four Dam Pool PMC has filed a lawsuit to be exempt from paying. Mr. LeResche suggested that because the dispatch item was reduced by $19,000 and there are some concerns regarding the inspection and transportation charges, he would like to see a line item having the $19,000 dedicated for contingency for allocation per the PMC’s approval. Chairman Kelly asked if there were any objections to this amendment. Being none, it was included as part of the main motion. Mr. Ritchey then referred to the cash flow analysis. Mr. Ritchey stated the debt service payments are equal each month except for February which is less. Each utility would pay their percentage and the first 10 months of payment will total $12,764,098. Mr. Ritchey directed the PMC to refer to the bottom under Balance in operating reserve. He stated if the budget worked as projected, at the end of June there would be $164,525 left in the operating fund for the next fiscal year. Mr. Ritchey stated the total budget number for approval, after rounding up the total, is $2,207,000 and asked if there were any additional questions. Being none, the roll was called and the motion passed unanimously. OPERATING AND DISPATCH SUBCOMMITTEE REPORT Mr. Sieczkowski reported that there are several issues to come before the Operating and Dispatch Subcommittee which will be meeting at AEA on March 27, 1991. The Subcommittee will discuss the Allocation and Scheduling Draft Agreement, the operation of the transmission line after Homer Electric has completed their construction, and formulation of an agenda for any other items that need to be resolved in the near future. Chairman Kelly asked if there were any questions, being none, Chairman Kelly asked if Mr. Story would give an update on the transmission line construction. Mr. Story reported that the 6 mile section being constructed in-house by HEA was complete. IRBY was behind the curve and has increased the number of people and are now ahead. HEA was predicting three weeks before the two ends could be tied in and ready for energization. Chairman Kelly asked Mr. Hufman to brief the PMC on his discussions with Mr. Lovas since the last meeting relative to the issue of how to handle the spinning reserves and the overspeed peaking operation of gas turbines to develop Bradley’s spinning reserve capabilities. Mr. Hufman stated that he and Mr. Lovas had just started talking about this issue and wondered what the PMC’s position was, and whether the utilities allow such peaking. Chairman Kelly asked Mr. Burlingame to discuss this matter in the TCS. Mr. Burlingame suggested that this issue should more appropriately be referred to the Operating and Dispatch Subcommittee to work out the details. Chairman Kelly stated without objection he would ask the Operating and Dispatch Subcommittee to look at 10. at Page 6 of 8 this matter. He further stated that if there are technical or design elements that need to be addressed, he would request that Operating and Dispatch Subcommittee to put together an outline of such items and get it to the TCS. REVIEW OF PROJECT STATUS Mr. Eberle reported that as of February, 1991, the project was 91 percent complete. Mr. Eberle stated that the tunnel and all of the high pressure grouting is complete. The steel liner is complete with the exception of the 60 foot closure piece which will be put together in another week. They anticipate to be completed with all of the tunnel work and bolting on the spherical head at the end of the tunnel about the first of April. The contractor has completed the concrete work in the diversion tunnel at the dam and is in the process of installing the — housing. The diversion tunnel work is scheduled to be completed by May, 1991. e contractor anticipates demobilization by June 1, 1991. With respect ta the reservoir, since the bulkhead gates were installed irisely all flows that have entered the lake have been released to accommodate fish flows, with only ice build up in the reservoir. This is the driest year AEA has seen since the start of the project. Mr. Eberle stated that he has looked at historical records and what we are experiencing this winter is parallel to a record low year in terms of the winter precipitation. If we do not get snow this spring and a lot of rain this summer we will have less than a full reservoir. Back feed power to the power house was completed in January and we are now on HEA’s meter. The spherical valve and governor control systems for Unit #2 are completed. The contractor is in the process of filling Unit #1 to begin testing and will be done by the middie of March. The control panel for SCADA is complete. The contractor was at the project site testing the equipment. The spinning of the units (dry) will begin in April and they should be able to spin wet in May. Mr. Eberle stated that a Testing and Start-up Subcommittee of the TCS has been formed and will be meeting on March 14, 1991 at the project site with representatives from Chu: rea Homer and ML&P. The SVS contract status was previously mentioned in the TCS report and the Site Restoration Contract will go out to bid on March 18, 1991 and the bids will be due April 25, 1991. OLD BUSINESS A. Test Period Power Mr. Lovas reported the group that was originally assembled as fashioned in the September 21, 1990 minutes never met. This issue was however, discussed with the Railbelt Rate Committee. The consensus of this group was to bring the test period power in at a zero rate. Mr. Lovas stated that it should reflect no energy from Bradley, which would result in keeping the cost down. Mr. Saxton noted that this is an issue which should be addressed by individual utilities and is not a PMC issue. Chairman Kelly stated if that is the recommendation, without objection, each utility will handle the test period power on their own. Mr. Highers stated that CEA is faced with export limits and this is a more complex issue than introducing free power. There is also a question of allocations and the cost of running turbines to support testing. The PMC directed the Dispatch Subcommittee to determine the allocation method to be used for Bradley Lake power prior to commercial operation. The Subcommittee was asked to specifically address two instances: 1) when Bradley Page 7 of 8 Lake is providing power into the system for AEA’s testing purposes and as such, some utilities may actually incur increased costs associated with the power by providing the generation required to perform any commissioning tests, and 2) for that period when Bradley Lake is supplying power to the system under utility controlled dispatching schedules prior to commercial operation. 12. NEW BUSINESS A. Approval of PMC Expenses Mr. Saxton distributed to the PMC a copy of the schedule of Unreimbursed Bradley Lake Costs - As Submitted to Ater Wynne March, 1990. The following costs were identified: PROJECT COSTS Chugach Finance Team Activities $ 2,044.60 Homer Electric Association TCC Expenses 2,186.68 Seward Electric TCC Expenses 201.67 TOTAL $ 4,432.93 SECTION 31 COSTS - Bradley Organization Chugach $ 33.45 GVEA 498.10 Seward 311.26 Ater Wynne 21,139.42 TOTAL $21,982.23 Mr. Saxton stated that AEA’s staff is concerned with the lack of back-up information that has been sent with the request for reimbursement. On the last page of this handout, Ms. Rawistcher prepared a list that reflects the dollar amounts requested for reimbursement and it also has a column stating if additional information is needed. If there is a yes in that column, additional oon documentation will need to be submitted before reimbursement can e made. Mr. LeResche moved, seconded by Mr. Highers to approve the Section 31 Cost as reported. The roll was called and the motion passed unanimously. Mr. LeResche also stated that AEA will provide a procedure to the utilities for the supporting documentation that will be needed for reimbursement of their costs. FY92 Budget This was discussed in detail under the Budget Subcommittee Report, Item 8. 15. Page 8 of 8 E. SCHEDULE NEXT MEETING April 12, 1991 Chugach Electric Association Training Room 10:00 a.m. ADJOURNMENT There being no further business before the Committee, the Committee adjourned by acclamation at 11:56 a.m. Approved by PMC at meeting held June 6, 1991. BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE JUNE 6, 1991 1. CALL TO ORDER CHAIRMAN MIKE KELLY called the Bradley Lake Project Management Committee to order at 10:10 a.m. in the Training Room at the offices of Chugach Electric Association to conduct the business of the Committee per the agenda and the public notice. 2. ROLL CALL Roll was called and a quorum was established. The following individuals were present: Alaska Energy pues Charlie Bussell, Representative Brent Petrie, Alternate Chugach Electric Association David L. Highers, Representative Tom Lovas, Alternate Golden Valley Electric Association Mike Kelly, Representative and Chairman City of Seward E. Paul Diener, Representative Homer Electric Association Norm Story, Representative (arrived at 10:20 a.m.) Matanuska Electric Association Ken Ritchey, Representative Municipal Light & Power ‘om Stahr, Representative Hank Nikkels, Alternate Others present: Tim McConnell, Municipal Light & Power Bob Hufman, Alaska Electric Generation & Transmission John Cooley, Chugach Electric Association Jim Woodcock, Matanuska Electric Association Ron Saxton, Purchasing Utilities Terri Ganthner, Alaska Energy Authority Stan Sieczkowski, Alaska Energy Authority Dave Eberle, Alaska Energy Authority 91q3/skb1203(1) Dave Fair, Homer Electric Association Gene Borjnstead, Chugach Electric Association Mo Aslam, Municipal Light & Power Dave Burlingame, Chugach Electric Association Joe Griffith, Chugach Electric Association 3. PUBLIC COMMENT There was no public comment. 4. MODIFICATION OF AGENDA Under Item 8, Budget Subcommittee, Item b, Chugach Wheeling was modified to read "Chugach Dispatch." The modified agenda was approved without objection. D2 APPROVAL OF MINUTES - March 5, 1991 CHAIRMAN KELLY asked for objections to the approval of the March 5, 1991, minutes. Hearing no objection, CHAIR) KELLY stated the meeting minutes were approved as distributed. 6. TECHNICAL COORDINATING SUBCOMMITTEE REPORT MR. DAVID BURLINGAME, Technical Coordinating Subcommittee (TCS representative, stated that the TCS ras met twice since the last SPM meeting and distributed copies of a summary meeting report for the benefit of Committee members. MR. BURLING. addressed items covered in the report: Bradley Lake Constraints: Power Technologies, Inc., (PTI) has completed their study of operating restraints for the testing and commissioning phase for Bradley Lake. recommends that the system remain interconnected, with no testing to be completed while the system is islanded. During the smaller load rejection tests of up to 60 megawatts, the system should have twice the expected load rejection th (Mw). reserves. At the higher load rejections of up to 90 megawatts which AEA proposes to do, PTI has recommended at least 3 Gres ne level of spinning reserve than the expected load rejection which is roughly 2 % times what would normally be carried by the utilities. Normal allocations would be shifted between the utilities, with Chugach, ML&P and AEG&T carrying all of the spinning reserve prior to the test. Verification of sufficient machines available to supply spinning reserve would need to be made by the utilities. MR. BURLINGAME recommended that the PMC direct the Dispatch and Scheduling Subcommittee develop a method for tracking and accounting for costs associated with dispatching during generation tests from Bradley Lake. 91q3/skb1203(2) Interim Operating Study: PTI has completed the first phase of the interim operating study. This study sets the upper limits for operation of Bradley Lake at 80 MW, with three turbines on-line at Bernice Lake. These restrictions were adopted by the TCS Subcommittee. Operation of the ee ae at 80 MW is below the planned testing level by the Authority of 90 . The TCS has requested that Stone and Webster Engineering Corporation (SWEC) gather all operating restrictions and recommendations related to Bradley Lake within the past 2-3 years into one document for reference. Bradley Lake Minimums: MR. BURLINGAME related that at a prior PMC meeting, the TCS had been directed to establish Bradley Lake minimums (i.e., maximum Kenai imports without a gas turbine on-line) for an expected reasonable level of load shedding. The TCS has agreed on the test cases required to develop those minimums. PTI will complete the study with the existing load shedding schedule and present the results to the TCS at a later date. Islanded Operation: Studies determining constraints on Bradley Lake during an islanded operation have not been started by PTI. It was noted that operation of all four Kenai area turbines would not prevent Kenai load shedding over 32 MW with the loss of one Bradley unit. The TCS will be addressing these operating constraints over the next few weeks. Transfer Tripping Installation: The TCS has approved the installation of transfer tripping at Soldotna, Quartz Creek and Bernice Lake. Transfer tripping was also approved from Dave's Creek to Soldotna which would allow a higher operating limit for Bradley Lake prior to the SVS systems going on- line. Testing/Commercial Operation: The TCS has requested that the PMC address or ia to a subcommittee the issue of commercial operation. CHAIRMAN LLY questioned DAVE EBERLE, Bradley Project Manager, if a start-up and test plan was being discussed at this time with the TCS. MR. DAVE EBERLE stated that the TCS has been briefed on the planned tests and progress of the testing. There has been no feedback regarding additional tests from the utilities. MR. BURLINGAME stated the utilities would need to develop operating or reliability criteria to schedule the units at various loads and for certain periods of time. The Authority's planned tests deal only with commissioning and verification of control and are not considered normal utility operation. CHAIRMAN KELLY questioned MR. EBERLE as to the intended declaration of commercial operation dates, transmission capabilities and further testing of the units. MR. EBERLE stated that the current plan is to synchronize the units the week of June 10. Load rejection tests will not be completed until July. Based on the current schedule, all tests will be completed by July 26 and in terms of the Power Sales Agreement, the project could be declared commercially operational on July 26. AEA's intent, 91q3/skb1203(3) however, is to allow the utilities to test the system for 30 days and declare it commercially operational on September 1. Status Transfer Tripping Installation: MR. BURLINGAME briefed the Committee on the remaining TCS items. Transfer tripping of the 115 lines which has basically kept Homer from energizing the line from Soldotna to Bradley Junction bas been delayed due to wrong and/or broken parts. These parts are expected to be in the week on June 10. ees ig of the line, RTU and Bradley will be energized in the same week. The Bradley Lake RTU for Chugach dispatching is installed and os the Diamond Ridge RTU installed by Homer and monitored by Chugach should be operational by the end of the week of June 3. The SVS systems proposals have been received and are under review. MR. STORY joined the meeting at 10:20 a.m. 7. OPERATION AND DISPATCH SUBCOMMITTEE REPORT MR. STAN SIECZKOWSKI stated that the Operation and Dispatch Committee met March 27, April 11 and May 16, to discuss issues and develop plans for the following: Load restoration procedures have been discussed with no resolution at this time. A proposal from Chugach is currently under review by the Subcommittee regarding loss and billing procedures. MR. SIECZKOWSKI distributed copies of an Agreement Schedule showing assignments and eres dates for review of various agreements related to Bradley Lake. The ubcommittee is recommending the acceptance of the Allocation and Scheduling Agreement dated May 17, 1991, subject to completion of the reservoir operation model and project operating criteria relating to unit condition mode _ operation, islanding and _ deflector modes. CHAIRMAN KELLY stated that this item would be placed on the agenda for discussion at the July 2 BPMC meeting. Spinning reserves and peaking operation has been tabled until more information is available. MR. DAVE HIGHERS Chugach Electric, questioned MR. SIECZKOWSKI as to the current level of water and levels predicted for the remainder of the ra MR.SIECZKOWSKI deferred the question to MR.EBERLE. . EBERLE stated that the reservoir level was at 1,093 feet and gaining between 3-5 feet a week. Significant run-offs begin the end of June and continue through July, with peak at the end of July and early August. The snow pack is within 10; ariel of the normal range; however, the Homer area is below the normal average and the far side of t * Kenai mountains is above normal. MR. EBERLE stated staff is continuing to monitor the situation and will have more information at the end of the month. 91q3/skb1203(4) 8. BUDGET SUBCOMMITTEE MR. KEN RITCHEY stated that the operating budget, to include a cash flow analysis for the projection of debt service payments, was approved at the February 1991 meeting. At a meeting on May 29, Subcommittee members noted that the cash flow analysis overstated the operating reserve fund by $300,000. MR. RITCHEY stated that a recommendation of the Committee would be to use funds in the Operating Fund; another recommendation may be to delay payment of certain expenses until a second issue facing the Subcommittee is payment dates; MR. RON S ON stated that the Committee is obligated to have funds available to make debt service payments and operating payments when they are due and that the time of payment should be optional. An option for the Committee would be to have each utility make an advance payment. MR. RITCHEY stated that this item would be on the July 2 agenda for further discussion by the PMC. MR. RITCHEY discussed the Chugach Wheeling rates and cost components that make up the wheeling rate as proposed by Shagach, A handout of the rates set by Chugach were distributed to Committee members. The second age of the handout was a worksheet used in a February 1988 analysis of radley Lake costs. This document was used as a reference by Budget Subcommittee members in forecasting future rates and calculations. Discussion on segregation of Beluga and Point McKenzie costs, applicability of the inflation rate for transmission services agreements and application of wheeling rates were discussed. MR. RITCHEY stated that it was the feeling of the Subcommittee that the wheeling rate adjustment should be calculated and implemented on each filing that Chugach makes with the Alaska Public Utilities Commission which ultimately leads to a rate change, with a test adjustment made each quarter. The Subcommittee would be able to track these costs easier on a quarterly basis. MR. RITCHEY stated the Homer Wheeling and Chugach Dispatch items would be discussed at the July 2 meeting. 9. INSURANCE SUBCOMMITTEE REPORT MR. BRENT PETRIE stated that the Subcommittee, with the assistance of the Division of Risk Management, is looking to Corroon & Black for a provider interested in providing Boiler and Machinery as well as Business interruption insurance. The current insurance company would provide coverage for flood, fire, earthquakes, etc. The Subcommittee will be responding to two major questionnaires regarding this insurance; copies of the questionnaires were distributed to the Insurance Subcommittee at this time. MR. PETRIE went on the say that the drought coverage had been discussed by the Subcommittee, with information to be provided to the interested providers. MR. PETRIE was questioned as to whether this insurance included payment of debt service payment in the event of a loss at the project. MR. PETRIE stated that the Subcommittee is looking at coverage of debt service payment and operation and maintenance debt 91q3/skb1203(5) service payment for at least one year. The company apparently is interested in wae a policy for 10 years that could be renewed on a year-to-year basis, applicable to each occurrence. 10. © REVIEW OF PROJECT STATUS MR. EBERLE stated that overall, the project is 94 percent complete. This percentage includes the remaining site rehabilitation contract and SVS equipment purchase and installation. The work that controls commercial operation is actually 99 percent complete. The general civil contractor is completing the diversion tunnel, gatehouse and fish water by-pass system. Punch list items and general clean-up of the site is also underway. Start-up testing of the units is continuing, with both units having been rolled and the first synchronization of the units is planned for the week of June 10. The units will be loaded at 5 percent, and upgraded at 5 percent increments. Unit rejection tests will take place July 8; PTI will be on-site and will have equipment in place to measure the response. The Authority's anticipated date for completing all tests is July 26. A falling head test to verify the integrity of the tunnel and leakage was completed on May 22. Over a 12 hour peuoe, the average leakage from the tunnel was only 5 -fallons per minute. : ere are no plans at this time to dewater the tunnel. e reservoir filling progressed slowly over the winter; after shutting down the fish water by-pass system on April 26, the reservoir has been filling fairly rapidly. The current level of water in the reservoir is 1, 093 feet, filling a little over 20 feet since last fall. = at level is 1,180 feet; an additional 87 feet will bring the reservoir to normal spill level. 11. NEW BUSINESS A. CHAIRMAN KELLY introduced MR. BUSSELL as the Authority's Executive Director and welcomed him to the PMC meeting. B. Bradley Agreements Committee Appointments CHAIRMAN KELLY stated that a committee would be selected to identify all agreements that must be in place, set a time table and assign to certain individuals the responsibility of completion of these agreements. Individuals selected for this committee included Stan Sieczkowski, Marv Riddle, Ron Saxton and Tom Lovas. CHAIRMAN KELLY charged this committee to meet as soon as possible in order to consolidate these agreements. CG Bradley Start-Up and Commercial Operation MR. BURLINGAME stated two issues regarding commercial start-up and operation included 1) operation of the plant at 90 MW without stability aids, with the risk of system losses to be shared by all the participants and 2) development of proposed operating scenarios from a utility standpoint by the TSC to insure the unit is available for 91q3/skb1203(6) 91q3/skb1203(7) commercial operation. CHAIRMAN KELLY stated he had asked MR. RON SAXT ‘ON to look at this issue for timing of commercial operation and what the PMC and AEA have agreed to. MR. SAXTON stated that the water level is not clear under the Power Sales Agreement (PSA), but that commercial operation is the date the engineers reasonably declare the project is fully available to the operators at not less than 90 MW. Length of operation at the 90 MW level, reasonable operation and scheduling output on a commercial basis is required although the length of operation at the 90 MW level is not covered under the PSA. . EBERLE stated that the lack of water should not be an issue relative to commercial operation - commercial operation states the unit must run at 90 MW. The PSA recognizes that there may be variability in water over the years, but that the price paid for the energy is fixed regardless of the amount of energy provide by the project. MR. SAXTON also stated that under the revenue bonds, September 1 was listed as the date of convenience for payments to begin by the utilities to meet the debt obligations and service obligations. The bond issuance did not include funds for capitalizing any further interest after September 1 and if the payments are not made by the utilities, there is no source of revenue other than the reserve funds. Second, there is the danger of cannes the bonds tax exempt status. MR. SAXTON reiterated that the Authority's engineers have the right to declare the project commercially operational, and once declared, the contract expressly states the utilities are obligated to begin making their payments. CHAIRMAN KELLY stated he was concerned with limiting the project at 80 MW or having a potential out-of-step problem with the loss of a unit and questioned the risk to the utilities above 80 MW. MR. BURLINGAME stated that two utilities would primarily be affected, but that the TCS should not decide on the amount of risk allocation to the various participants. He stated the TCS should be involved in defining the operating and testing restraints they want the project to perform under to satisfy their general managers. KELLY questioned the method used by the Authority in testing the units; MR. EBERLE stated the Authority will test each unit separately to its full output (63 megawatts) and then load them in combination to the extent that the utilities are able to take the power. CHAIRMAN KELLY instructed the TCS. through MR. BURLINGAME, to develop operating scenarios with 80 MW and 90 MW caps. There was no objection by the Committee. Discussion began on commercial output to be scheduled from Bradley. CHAIRMAN KELLY questioned the operation of the Bernice Lake turbine under an obligation by Chugach to Homer Electric. MR. HIGHERS stated this turbine would be on-line due to the 91q3/skb1203(8) absence of the second transmission line prior to Bradley Lake operation. MR. BURLINGAME stated that this turbine was not required with the operation of Bradley; this turbine is only required to expand the operating limits of Bradley. MR. STAHR stated that he does realize that the lack of an intertie limits output from the project, however, stressed that the cost of burning fuel as opposed to using the spinning reserves was just as valuable and he expected his utility to receive this spin reserve. MR. BURLINGAME stated that the TCS has yet to establish the value of how much spinning reserve is available from Bradley Lake during normal operation of gas turbines but that Bradley was essentially able to contribute up to the 120 MW capacity at peak for spinning reserve, limited only by transmission line constraints. After installation of the SVS', the project can be scheduled at 120 MW. The minimum operating limit will not go away for the life of the project. CHAIRMAN KELLY adjourned the meeting for a short break at 12:20 p.m. The meeting reconvened at 12:30 p.m. CHAIRMAN KELLY restated the issues as discussed previously by the Committee. Additional comments regarding load shedding, response time of the turbines and additional funds to correct any design flaws were also discussed at length by the Committee. MR. TOM STAHR stated that once the project is declared operational, the utilities would be responsible for projects costs after that point and suggested that a limited agreement between the Authority and the utilities be researched and/or implemented until installation of the SVS system. MR. CHARLIE BUSSELL stated that per the bonds, partial en of the facility can not and would not be declared. . HIGHERS stated that the Authority has indicated they will provide funding for the SVS system and attempt to solve any stability problems perceived by the utilities, but questioned support from the Authority through encumbrance of funds to be held for completing any additional required project construction. MR.S ON stated that there two separate concepts - the declaration of the commercial operation date of the project and 50-50 matching funds tied to the cost and acquisition and construction which are considered construction costs until the $350,000,000 limit is reached. MR. PETRIE stated the earlier these project construction funds could be released would be December 1992, and this must be completed through legislative action. MR. STAHR requested that a resolution to encumber these funds as related to the commercial Sacre date be prepared by the Committee. MR. PETRIE and . SAXTON were tasked with the resolution, with MR. SAXTON to prepare the first draft of the resolution for discussion at the next meeting. The Committee also discussed briefly the cost of operating gas turbines to support project testing. Chugach will continue to run the turbine at Bernice Lake during the test period and should be reimbursed for operating costs during this time frame. CHAIRMAN KELLY stated this issue should be placed on the July 2 agenda for further discussion. iD Approval of PMC nses MR. SAXTON stated that some utilities had not turned in the necessary backup for unreimbursed costs. MR. SAXTON handed out a memorandum from Marcey Rawitscher which stated that backu documentation is required and reimbursement will be made to Seward, Golden Valley and Ater Wynne. MR. HIGHERS moved, seconded by MR. DIENER for approval of PMC expenses. Roll was called and the motion passed unanimously. E. Two additional items were added to the agenda at this time. MR. BURLINGAME distributed a memorandum stating these items for the benefit of the Committee. MR. HIGHERS summarized the first motion for the benefit of Committee members. Motion 1 requests that the PMC authorize Chugach to install transfer tripping of its capacitor bank at Soldotna from Dave's Creek at a cost not to exceed $30,000. Transfer tripping of the capacitors will enable a higher output of Bradley Lake during the interim operating period. MR. HIGHERS moved for adoption of motion 1; MR. ‘CHEY seconded _the motion. Roll was called and the motion was approved without objection. The second item was a motion for the PMC to authorize the installation of transfer tripping on the Bernice Lake-Soldotna, Soldotna-Quartz Creek 69 kV circuits at a cost not to exceed $100,000 for HEA at Soldotna and not to exceed $30,000 total for Chugach at Bernice Lake and Quartz Creek. MR. STORY moved adoption of the motion; MR. RITCHEY seconded. MR. HIGHERS amended the motion to table this item to the next meeting. MR. RITCHEY agreed to second the motion to table. F. Schedule Next Meeting July 2, 1991 Chugach Electric Association Training Room 10:00 a.m. 12. COMMUNICATIONS MR. EBERLE distributed handouts to members of the Committee, informing them of the ible construction of an additional diversion in the Upper Battle Creek Drainage Basin. The benefit/cost ration of the small diversion looks very favorable, and could potentially be constructed this summer. A Federal Energy Regulatory Commission (FERC) license amendment is required and AEA is proceeding with this request to FERC. The diversion will be discussed further at the July 2 meeting. 91q3/skb1203(9) 13 ADJOURNMENT Having no further business to bring before the Committee, the meeting was adjourned at 1:55 p.m. [ Secretary noel Approved by PMC at meeting held July 2, 1991. 91q3/skb1203(10) BRADLEY PROJECT MANAGEMENT COMMITTEE RESOLUTION NO. 91-09 A RESOLUTION of the Bradley Lake Project Management Committee Concerning the Alaska Energy Authority's Obligation to Complete the Bradley Lake Hydroelectric Project and to Share the Cost of Acquisition and Construction With the Power Purchasers Until the Project is Complete. WHEREAS, the members of the Project Management Committee for the Bradley Lake Hydroelectric Project and the Alaska Ener, — have heretofore entered into a Power Sales Agreement dated as af Deceiiber , 1987, which — a form of Bond Resolution as an attached Exhibit A, whereby the Alaska Energy Authority agreed to take all actions required to construct and complete the Bradley Lake Hydroelectric Project expeditiously and in accordance with sound engineering practices; and WHEREAS, in the Power Sales Agreement, the Alaska Energy Authority and the Power Purchasers agreed that the Alaska Energy Authority would issue long- term bonds in an amount not exceeding the lesser of one-half of the Project's cost of acquisition and construction or $175,000,000, to be repaid by the Power Purchasers, with the Alaska Energy Authority to fund the remaining cost of acquisition and construction with direct State appropriations; and WHEREAS, the Bond Resolution defines "Cost of Acquisition and Construction" to include costs and expenses required to construct and complete the Project; and WHEREAS, the Power Sales Agreement and Bond Resolution defines the term "date of commercial operation" in reference to the date on which the Project is declared to be available for commercial operation at not less than 90 MW, and not in reference to the date on which the Project construction is complete in all respects; and WHEREAS, it has always been expected that project completion and site renovation work would be completed after commercial operation, and furthermore that due to the delays in award and construction of the Static Var Compensation Systems to provide stability support for the existing Kenai Transmission System, the date on which the Project will be declared to be available for commercial operation will precede the date on which Project construction will be complete; and WHEREAS, the Project Management Committee deems it appropriate to clarify that the obligation of the Alaska Energy Authority to complete the Project remains unaffected by the Project's date of commercial operation, and that the agreement between the Alaska Energy Authority and the Power Purchasers to share the cost of acquisition and construction includes costs required to complete the Project, regardless of when the date of commercial operation is declared; 1J1066(1) NOW THEREFORE, BE IT RESOLVED, by the Bradley Lake Project Management Committee that the obligation of the Alaska Energy Authority to complete the Project remains unaffected by the project's date of commercial operation, and that the agreement between the Alaska Energy Authority and the Power Purchasers to share the cost of acquisition and construction includes costs required to complete the Project, regardless of when the date of commercial operation is declared. FURTHERMORE, be it resolved that Project Construction shall not be deemed complete until such time that the planned pape rapper systems have been constructed, tested and operate as designed, and that the plant continues to be capable of commercial operation. ADOPTED by the Bradley iss Management Committee at a regular meeting of said Committee held this ay of Hi 7 —___, 1991. BRADLEY PROJECT MANAGEME COMMITTEE BY: MJ Michael P. Kelly, Chaifman A BY: - : e Charlie Bussell, Secretary TJ1066(2) TO: FROM: DATE: SUBJECT: RECORD LOPY FILE NO [Ro 3-7)! mw Alaska Energy Authority — —— 2/23/91 oo MEMORANDUM Bradley Lake Prpject Management Committee Members Bradley Lake PMC Meeting Charlie Bussel July 31, 1991 This is to inform you that the August 16, 1991 Bradley Lake PMC Meeting has been cancelled and tentatively rescheduled for August 23, 1991. The meeting place will be at Chugach Electric Association and will begin at 10:00 a.m. If there is a conflict in your schedule, please contact Chairman Kelly at Golden Valley Electric Association. DS/CB/ds STVLR2E & FORWARD REPL.2T DATE/TIME LOCAL TERMINAL ID. 8- 1-91 3:22PM 907 561 8584 LOCAL NAME AK ENERGY AUTHORITY COMPANY LOGO AK ENERGY AUTHORITY No. REMOTE STATION START TIME DURATION | #PAGES MODE RESULTS oo1 SEWARD} 8- 1-91 3:06PM oles 7 i 2/ 2\|SF COMPLETED 9600 002 MEA 3:08PM 1°06" 2/ 2)|SF COMPLETED 9600 003 CEA 3:10PM 0°50" 2/ 2\|EC SF COMPLETED 9600 004 HEA 3:11PM 0°56" 2/ 2|SF COMPLETED 9600 005 GVEA 3:17PM 1°00" 2/ 2\|EC SF COMPLETED 9600 006 ML&P 3:18PM Liz" 2/ 2\|SF COMPLETED 9600 007 AWHD&S 3:20PM 0°57" 2/ 2\|EC SF COMPLETED 9600 TOTAL 0:07°23" 14 DIAL GROUP a No. DIRECTORY NUMBERS 008; 001 002 003 004 005 006 007 NOTE: No. + DIRECTORY NUMBER 48 4800BPS SELECTED EC ERROR CORRECT G2 : G2 COMMUNICATION PD : POLLED BY REMOTE SF STORE & FORWARD RI RELAY INITIATE RS RELAY STATION MB : SEND TO MAILBOX PG POLLING A REMOTE MP MULT I -POLLING RM RECEIVE TO MEMORY State of Alaska Waiter J Hickel, Governor Alaska Energy Authority A Public Corporation 7 8 iG G0) Py (ANCHORAGE Telecopy Phone No. (907) 561-8584) (JUNEAU Telecopy Phone No. (907) 465-3767) Dave th: hees , Joe Ge Gt C&A SP 5U2 - 0627 TELECOPY SENT To: JOM FORK Abnk Diklel , mee? 0003 ~ 50H RIC Sen aired» (ois ENO net IBS S49 NAME OF COMPANY: EL Dune, Coty of Sevdee JI.2 4 -Z245 Pon Saxo, file, W = G03-.226-06 79 COMPANY ADDRESS: , YS1-5033 ¢ 5 TUS —-G3a6 TELECOPY PHONE NUMBER: SENDER: L Je th Ma len TELEPHONE NUMBER: » | - 1050 CHARGE CODE: DATE SENT: Ladd. IF YOU DO NOT RECEIVE ALL OF THIS TELECOPY PLEASE CALL: (907) 261-7240-Anchorage (907) 465-3575-Juneau SPECIAL INSTRUCTIONS: PO. Box AM Juneau, Alaska 99811 (907) 465-3575 3 PO. Box 190869 701 East Tudor Road Anchorage, Alaska 99519-0869 (907) 564-7877