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BPMC Meeting March 3, 1993 3
DATE: TO: FROM: SUBJECT: \ Alaska Energy Authority RECORD VOPY FILE NO MEMORANDUM ree February 16, 1993 Bradley Lake Hydroelectric Project Project Management Committee Brent N. Petrie A. NS est Secretary Project Management Committee Meeting Notice of Meeting Change to March 3, 1993 Please note that the next meeting of the Bradley Lake Project Management Committee has been changed to Wednesday, March 3, 1993. The meeting will begin at 10:00 a.m. in the Training Room at Chugach Electric Association, Anchorage. The following items are enclosed for your information and review: ° Agenda - March 3, 1993 BPMC Meeting ° Draft Minutes - January 14, 1993 BPMC Meeting ° Revised Allocation and Scheduling Procedures A copy of the approved November 20, 1992 PMC Meeting Minutes will be distributed at the upcoming meeting. Please provide any comments regarding the March 3, 1993 BPMC meeting agenda items to Chairman Highers. DB:BNP:db BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE MEETING AGENDA March 3, 1993 Chugach Electric Association, Inc. Training Room 10:00 a.m. CALL TO ORDER _ 10:00 a.m. Highers ROLL CALL PUBLIC COMMENT AGENDA COMMENTS APPROVAL OF MEETING MINUTES - January 14, 1993 TECHNICAL COORDINATING SUBCOMMITTEE REPORT Burlingame BUDGET SUBCOMMITTEE REPORT Ritchey A. Bradley Lake Construction Cost Audit Update B. FY93 Budget, AEA Administrative Costs Update Cc. Bradley Lake O&M Cost Audit Update AGREEMENTS SUBCOMMITTEE REPORT Sieczkowski OPERATION AND DISPATCH SUBCOMMITTEE REPORT Sieczkowski REVIEW OF PROJECT STATUS Eberle OLD BUSINESS A. Spinning Reserves/Under Frequency Load Shedding Update Lovas B. Bradley Scheduling vs. Spin Requirement Update Saxton Cc. Fritz Creek Segment Funding Story D. Fish Water Bypass Update Wolf NEW BUSINESS A. Revised Allocation & Scheduling Procedures Sieczkowski B Operations Budget Contingency Fund Resolution Saxton COMMUNICATIONS A. Schedule Next Meeting ADJOURNMENT ho oes LAKE PROJECT MANAGEMENT COMMITTEE MEETING MINUTES January 14, 1993 1. CALL TO ORDER Chairman Highers called the Bradley Lake Hydroelectric Project Management Committee to order at 10:15 a.m. in the Training Room at Chugach Electric Association in Anchorage, Alaska to conduct the business of the Committee per the agenda and the public notice. 2. ROLL CALL Alaska Energy Authority Ronald A. Garzini, Alternate Representative Chugach Electric Association David L. Highers, Designated Representative and Chairman Golden Valley Electric Association Mike Kelly, Designated Representative City of Seward Paul Diener, Designated Representative Homer Electric Association Norm Story, Designated Representative Matanuska Electric Association Ken Ritchey, Designated Representative Municipal Light & Power Tom Stahr, Designated Representative Others Present: Ron Saxton, Ater, Wynne, Hewitt, Dodson & Skerritt David Burlingame, Chugach Electric Association John Cooley, Chugach Electric Association e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutes January 14, 1993 Page 2 p* of 13 Gee é\Bjornstad, Chugach Electric Association ze OF Lovas, Chugach Electric Association Bob Hufman, AEG&T Dave Fair, Homer Electric Association Mike Yerkes, Homer Electric Association Doug Hall, Municipal Light & Power Moe Aslam, Municipal Light & Power Tim McConnell, Municipal Light & Power Bob Price, Municipal Light & Power Dave Calvert, City of Seward David R. Eberle, Alaska Energy Authority Stanley E. Sieczkowski, Alaska Energy Authority Larry Wolf, Alaska Energy Authority Denise Burger, Alaska Energy Authority PUBLIC COMMENT There being no public comment, the meeting continued to the next agenda item. AGENDA COMMENTS Item 12. E, Authority Over Budget Revisions, was added to the agenda. APPROVAL OF MINUTES - October 9, 1992 The minutes of the November 20, 1992 Bradley PMC were approved as submitted (Action 93-161)!. TECHNICAL COORDINATING SUBCOMMITTEE REPORT Mr. Burlingame reported that the TCS had not met since the November Bradley PMC meeting. Mr. Burlingame noted that modifications had been made to the Woodward governor as a result of testing performed in November, and that efforts to resolve the unstable Kenai oscillation problem were in progress. BUDGET SUBCOMMITTEE REPORT Mr. Ritchey informed the BPMC that the Budget Subcommittee would be requesting authorization to make changes to the Bradley O&M budget that were ! To facilitate record keeping, commencing with calendar year 1993, the secretary will assign sequential numbers to all actions taken by the Bradley PMC in accordance with the Committee Bylaws (Article 14.1). e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutcs January 14, 1993 Page 3 of 13 within t petrent of the budget (agenda item 12. E). Changes over ten percent of hbo would be brought before the Bradley PMC. Dp The Budget Subcommittee is currently reviewing the proposed FY94 Bradley O&M Budget. The Subcommittee will be meeting again at the end of February and expects to have a budget ready to present to the Bradley PMC by the March meeting. The BPMC was reminded that the budget needed to be completed and adopted by the first of April. Mr. Ritchey noted that the Bradley PMC had been informed of an O&M budget surplus of $910,411 at the November 20, 1992 meeting. Mr. Ritchey explained that this amount included approximately $450,000 carried forward from FY92 to FY93. To avoid large swings in the utility payments from year to year, the Subcommittee plans to carry the remaining estimated $450,000 into FY94. Mr. Ritchey noted a letter sent by Ron Saxton to Ron Garzini requesting information regarding use of Bradley bond funds. In question is whether a portion of the remaining construction funds could be transferred to Section 31 to cover the HEA Fritz Creek transmission line construction cost. HEA's Fritz Creek transmission line construction costs are considered to be a utility expense and meet the criteria for use of Section 31 funds, however Section 31 funds have been depleted. Mr. Saxton noted that redirecting construction funds to Section 31 funds would not impact the financial obligation of the utilities or the Energy Authority. Mr. Garzini has forwarded the request to Eric Wohlforth, AEA bond counsel, for review and advisement. A. Bradley Lake Construction Cost Review To clarify any previous misunderstanding, Mr. Ritchey noted that the construction cost audit had been approved as a construction cost item and was not an O&M cost. Pending successful completion of reference checks, Metzler & Associates has been tentatively selected by the Subcommittee to perform the construction cost audit. Mr. Ritchey anticipated Metzler & Associates would begin the audit shortly after confirmation. B. FY93 Budget, AEA Administrative Costs Update No comments were made regarding this issue. Cc; Bradley Lake O&M Cost Audit Update e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutes January 14, 1993 Page 4 of 13 8. . Ritchey reported that the O&M audit being performed by Parisena tromberg was more than half way complete. The Budget Dp 5° “subcommittee expects an audit report by February 2, 1993. AGREEMENTS SUBCOMMITTEE REPORT Mr. Sieczkowski reported that changes to the Soldotna Substation Agreement (with HEA) were made at the December 11, 1992 Agreements Subcommittee teleconference meeting. Offering the assistance of the Bradley PMC, Chairman Highers asked if anything could be done to expedite the agreement negotiation process. Mr. Sieczkowski stated that the Subcommittee's comments had been incorporated and that no other issues remained to be resolved. Changes to the Transmission Line Maintenance Agreement made by the Subcommittee at a December 21, 1992 teleconference meeting have been incorporated. Additionally, new drafts of the Daves Creek and Soldotna SVC Facilities Maintenance Agreements were distributed for review on December 18, 1992. Comments are expected from the utilities by January 29, 1993. OPERATION & DISPATCH SUBCOMMITTEE REPORT A summary of the Operation & Dispatch Subcommittee meeting of January 7, 1993 was distributed to the PMC (Attachment 1). Mr. Wolf reported that the Subcommittee reviewed an operations report presented by AEA. Beginning with January 1993 information, the report (a summary of project generation Statistics, reservoir hydrology data, and operations and maintenance events) will be distributed as an attachment to the Subcommittee meeting minutes. DECnet programming was discussed at the meeting. AEA requested AML&P and GVEA develop and implement their own DECnet programming. Updating his report given at the November 20, 1992 BPMC meeting on the progress of the annual maintenance, Mr. Wolf stated that no additional problems were discovered during completion of the maintenance work. However, due to insufficient time during the annual maintenance to repair a transformer nitrogen leak, a one day outage would be needed to perform the repair. Reservoir Draw-down Mr. Wolf reported on the blockage of the Bradley Lake fish water bypass intakes. Early in November, reduced flow was noted through one of the fish e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutvs January 14, 1993 Page 5 ) iftbpec of 13 water b si\yalves. Suspecting a blockage, the operators unsuccessfully tried to cl A intake with a back flow of compressed air. During a visual tion of the area on November 17, 1992, Mr. Wolf noted erosion of overburden and loose fill from the bank above the intakes and suspected that the material was migrating into the intake area. AEA contracted a diver to inspect the intakes on November 19, 1992, however, due to uncooperative weather conditions, the dive was not made until December 8, 1992. The diver reported finding large, smooth rocks, debris and silt. Discrepancies in the diver's report with known information raised some question as to the accuracy of this assessment. Mr. Wolf explained that there were no large, smooth rocks in the area, and stated that the diver's inspection was hindered by inability to see due to the high level of glacial silt in the water. Because of the discrepancies in the initial dive inspection report, AEA is arranging for a second dive inspection by another dive company utilizing hard hat (rather than scuba) gear. If the material causing the blockage can be easily removed, the divers will attempt to clear the intake area. Assessing the currently available information, Mr. Wolf stated that any remaining loose material above the intake area should be removed and the intakes cleaned and modified to avoid a repeat of the problem. In order to minimize the risk of damaging the intakes, Mr. Wolf anticipated that the reservoir would need to be lowered to 1068' to clean and modify the intakes. A request for an engineering proposal to provide a design for modification of the intakes and contract specifications for the removal of the overburden and cleaning and modification work was made to Stone & Webster Engineering the first week of January. The O&D Subcommittee was informed of the situation and discussed associated problems of operating the project at a reservoir level under 1080' at its January 7, 1993 meeting. Mr. Wolf stated that unknown tunnel transient effects could cause a problem when operating the project below 1080' and recommended a transient analysis study be performed. Mr. Wolf explained that, according to the design engineer, a sudden needle closure below this level could cause a vacuum and subsequent tunnel failure. Mr. Wolf noted that, barring a needle closure, the project is capable of generating 105 to 109 megawatt hours between the 1068' and 1080' reservoir level. Additional reservoir storage capacity between 1068' and 1080' is 18,734 acre-feet. In lieu of successful clearing of the intakes by the divers, Mr. Wolf outlined three options to clear and modify the intakes: Option I: At the current reservoir level, either on the ice or on floats, utilize a clam to clear the debris. The work would be done in 70' of water and includes a high risk of damaging the intakes. Modification of e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutes January 14, 1993 Page 6 of 13 t ittakes would have to be done by divers. High repair costs are icipated for this method. vs p Option II: At a reservoir elevation of 1090', access the intake area from the adjacent bank using a hoe or clam. The work would be done in approximately 20' of water. Risk of damaging the intakes would be less, however, modification of the intakes would still have to be done by divers. Anticipated repair costs would be less than Option I. Option I: Lower the reservoir to 1068' to facilitate use of on-site equipment and perform work under dry conditions. Repair costs would be lower, however impact to the utilities schedule would be the highest. Mr. Wolf explained that the fish water bypass was a FERC license requirement. A water release of 40 cfs is required November through April and 100 cfs June through September. Under present conditions (at a reservoir elevation of 1136') the maximum obtainable release is 86 cfs. Release from the blocked intake is limited to a flow of 7 cfs. Mr. Wolf noted that favorable weather conditions could provide the necessary flow to meet the FERC requirement, however, if the requirement was not met, FERC could fine the project up to $10,000/day. Ultimately, the license could be revoked. The Committee elected to discuss agenda item 12. C., Reservoir Draw-down. Chairman Highers initiated the discussion stating that the draw-down would greatly impact CEA's maintenance schedule. Mr. Stahr questioned use of underwater camera equipment to evaluate the situation. Mr. Wolf explained that a camera would not be useful because the glacial silt prevented visibility. It was noted that sonar equipment could be effective under these conditions. Mr. Garzini recommended that the Operation & Dispatch Subcommittee continue to work on the problem until the technical options are defined. If differences develop which cannot be resolved at the Subcommittee level, Mr. Garzini suggested that a special Bradley PMC meeting be called at that time. Mr. Bjornstad reiterated that the problem particularly impacted CEA's maintenance schedule. Mr. Bjornstad requested an immediate second dive inspection and notification of the results to the utilities, stating that this information was critical to CEA's planning. Mr. Stahr asked if enough water could be pumped over the spillway to meet the FERC requirements. Mr. Wolf explained because the 100 cfs was measured down stream of the dam, some greater amount had to be released at the dam in e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutes January 14, 1993 Page 7 of 13 order to gpott phe requirement. Mr. Stahr expressed the need for an expedient assessment of the problem and requested that AEA keep the utilities informed of D changes to the availability of Bradley generation. Warranty coverage of the problem and the possibility of design error were questioned. Mr. Eberle stated that assessment of those issues at this time would be premature because the cause of the problem was unknown. No determination had been made as to how the cost was to be handled (i.e. operation, or construction, or warranty). Chairman Highers concurred with Mr. Garzini's recommendation that the O&D Subcommittee continue to handle the problem. Mr. Wolf noted that the Energy Authority needed to be informed of the utilities' maintenance schedules in order to facilitate planning the maintenance needs of Bradley Lake. Chairman Highers added that maintenance at Bradley Lake should be a coordinated effort between the utilities and AEA to meet the utilities' needs as well. Referring to the January 7, 1993 O&D Subcommittee meeting, Mr. Wolf stated that revisions to the Allocation & Scheduling Procedures had been approved for recommendation to the BPMC. The revised procedures will be forwarded to the general managers in advance of the next Bradley PMC meeting. An additional item of discussion at the Subcommittee has been HEA line losses. Mr. Wolf stated that HEA was in the process of developing their loss numbers for further discussion at the next Subcommittee meeting. Mr. Lovas noted that, in the past, CEA had provided those numbers to HEA. Mr. Burlingame clarified that the "line loss" being discussed was the difference between the total sum of retail kilowatt hours sold by HEA and the total wholesale megawatt hours purchased. 10. REVIEW OF PROJECT STATUS Mr. Eberle reported that AEA had received ten contaminated soil clean-up technical proposals which are currently being reviewed. Price proposals are expected in February. AEA is continuing efforts to obtain a clean-up waiver from the Alaska Department of Environmental Conservation. Mr. Eberle reported that the capacitor bank of the second harmonic filter failed during on-line testing of the Daves Creek Substation Static Var Compensator System (SVC) in December. Initially, the problem was suspected to be a possible harmonics condition that the system was not designed for. However, after studying the problem, ABB concluded the system could handle the harmonics. Subsequent study and inspection of the capacitor bank by ABB identified a combination of several problems which resulted in the failure: use e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutes January 14, 1993 Page 8 of 13 11. 12. of wrong ite fuses, improper attachment of the spring ejectors on the fuse link: is-manufactured (under sized) capacitors. ABB will be replacing the majority of the capacitor bank at the Daves Creek Substation. All fuses will be checked and modifications made to the spring ejectors. ABB also plans to modify the alarm and protection system. In spite of the additional work, ABB expects to be able to maintain its schedule and have the system on line by mid- March. Mr. Eberle noted that a contract was being issued to Woodward Governor to resolve the unstable frequency oscillation problem. Design, testing and implementation of the system modifications is expected to be completed by the end of June. OLD BUSINESS A. Spinning Reserves/Under Frequency Load Shedding Update Tom Lovas reported that the Alaska Systems Coordinating Council (ASCC) Reliability Criteria Committee met with its consultant, Bill Masters, in December. The Intertie Operating Committee (IOC) has received a proposed load shedding schedule (based on current conditions, including Bradley Lake) from its Reliability Criteria Subcommittee. The recommendation includes implementation of a specific load shedding schedule which includes requirements for load shed in lieu of spin. Mr. Lovas stated that the schedule will accommodate the current operating conditions and improve the reliability of the interconnected system. Questions regarding character of the spin, resources of the spin, and the location of the spin remain to be resolved by the IOC. Bradley Scheduling vs. Spin Requirement Update Referring to the November 20, 1992 BPMC meeting, Chairman Highers noted his request that the utilities provide written comments on the spin requirement issue to Mr. Saxton. Chairman Highers urged the utilities to submit written comments as soon as possible, noting that AML&P had already submitted comments. NEW BUSINESS A. Approval of Committee Expenses e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutes January 14, 1993 Page 9 of 13 Mg. Ritchey distributed a chart of Ater Wynne legal fees and expenses AY mpassing August 1992 to January 1993. Mr. Ritchey explained that Dp TS the August and September expenses were included on the chart because they had not been paid (although they had previously been approved). Mr. Ritchey noted that the expenses were well above the budget line item approved for FY93. Mr. Kelly motioned to approve the submitted expenses for payment. The motion, seconded by Mr. Ritchey passed b the following roll call vote (Action 93-162): City of Seward Yes Matanuska Electric Association Yes Chugach Electric Association Yes Homer Electric Association Yes Golden Valley Electric Association Yes Municipal Light & Power Yes Alaska Energy Authority No Mr. Garzini stated his objection to administering payment of legal bills to cover the AEA administrative cost law suit. Mr. Saxton stated that the money paying for the legal expenses was not AEA's money, explaining that the money was only handled by ABA as a result of the technical provisions of the Power Sales Agreement. Mr. Garzini objected to the payment of legal expenses for what he considered an unnecessary law suit. In response to questioning by Chairman Highers, Mr. Garzini stated that the Energy Authority would administer the payment of legal expenses approved by the Committee. Directing his comments to Mr. Garzini, Mr. Kelly recalled the history behind the AEA administrative cost issue. After negotiating with Mr. Bussell, the Committee felt that there was too large a difference to resolve through continued negotiation. The Committee was also concerned that the issue would return every year. It was the consensus of the utilities that the best course was to seek a legal determination in order to put the issue to rest. Mr. Kelly acknowledged Mr. Garzini's desire to work directly with the utilities to resolve the issue, however, stated that changing the present course of action would be difficult. Mr. Garzini expressed hope that future problems could be resolved either technically or through the managerial process. Mr. Garzini added that his ultimate goal was for the utilities to play a greater role in the management of the project. B. Fritz Creek Segment Funding e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutcs January 14, 1993 Page 10 of 13 ps itman Highers noted the January 8, 1993 memorandum prepared by ar Lovas which was previously distributed to the utilities (Attachment 2). Mr. Story stated that repayment of HEA's Fritz Creek transmission line construction costs had been left unresolved. HEA recently invoiced the utilities for the line costs, however, HEA was receptive to other options of payment (i.e. capitalization of costs). Mr. Saxton, referring to his earlier comments on the possible restructuring of the remaining unused bond funds, stated that the Fritz Creek costs met Section 31 qualifications. Mr. Lovas commented that it was unfortunate that the costs had not been submitted under Section 31 prior to bond issue. Mr. Lovas noted that Item 12 of the Transmission Agreement clearly expressed the intent to include the Fritz Creek costs under Section 31. Additionally, in lieu of qualification as a Section 31 cost, Item 12 outlines a mechanism to treat the transmission line cost as a project operation expense during the first 3 years of operation. Mr. Lovas suggested the transmission line could be paid for as a Section 13 (project construction) cost, or, paid for by HEA through a bond issue (to be paid back by the utilities). Mr. Lovas recommended that HEA submit a reimbursement plan to the Bradley PMC. Mr. Story objected to the burden being placed on HEA and requested additional discussion or suggestions. Mr. Kelly suggested that HEA self-finance the cost and the utilities repay HEA by the same terms as if it had been submitted under Section 31. Repayment of the cost as a project operation expense in this manner would have minimal impact on the utilities. Mr. Lovas reiterated that the first step was to determine if bond funds could be used to cover HEA's Fritz Creek transmission line costs. If bond funds cannot be used, Mr. Lovas stated that HEA would then need to provide the BPMC with a mechanism for repayment which would least impact the utilities’ cash flow. Mr. Garzini informed the Committee that AEA was already investigating a variety of options and was willing to assist in resolving the problem. Chairman Highers requested that HEA and AEA work together to find an acceptable method of repayment of HEA's cost. Bradley Draw-down This item was discussed earlier under Item 9, Operation & Dispatch Subcommittee Report. BPMC Control Over O&M Decisions and Agreements Mr. Saxton introduced three issues for discussion: (1) control over O&M, (2) identification of appropriate parties to various agreements; e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutes January 14, 1993 Page 11 of 13 ps been issued. ane @) the relationship of the multiple agreements and contracts that Control Over O&M Referring to the Power Sales Agreement, Mr. Saxton stated that Section 13 created the Project Management Committee, Section 13 (b) established Committee rules, and Section 13 (c) outlined Committee responsibilities. Paraphrasing Section 13 (c) (i), Mr. Saxton stated, "Subject to certain non-delegable rights, the PMC shall be responsible for the management, operation, maintenance and improvement of the project, in recognition that as take-or-pay purchasers of project capacity the purchasers have substantial long term interest..." Additionally, Mr. Saxton stated the Agreement established the Committee's responsibilities as follows: "The Committee is responsible to arrange for the operation and maintenance of the project, and the scheduling, production, and dispatch of project power..." In order to accomplish this, the utilities agreed that AEA would become the project operator. Mr. Saxton pointed out that the contract clearly stated the Committee was ultimately responsible for operation of the project. Identification of Appropriate Parties to Various Agreements Mr. Saxton stated that agreements had been prepared under the authority of ABA with an approval signature of the BPMC, however, the BPMC could retain authority as the principal signer with an approval signature of AEA. Mr. Saxton stated that either case worked, but the ultimate responsibility belonged to the BPMC. It was noted that differences on which way the authority was viewed was causing difficulties in the agreements process. Relationship of Multiple Agreements and Contracts A list of agreements prepared by Tom Lovas (Attachment 3) was distributed to the Committee. Mr. Saxton recommended that the agreements be catalogued and, preferably, reviewed to determine their effect on each other (i.e. potential conflicts). Chairman Highers requested that the utilities review the list to ensure the inclusion of all agreements and submit any changes to Tom Lovas. Mr. Yerkes asked if the BPMC could contract legally. Mr. Saxton could not provide an answer without further investigation, however e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutvs January 14, 1993 Page 12 of 13 p*® s ek that the BPMC could contract in joint venture or partnership. 2 Saxton noted that the same result could be obtained if AEA contracted with the recognition that it was the BPMC who made the decision. Mr. Saxton expressed concern about the introduction by AEA of a potential additional step to the Committee's decision making process wherein AEA assumes that its approval of a decision is required before the decision is carried out. (Mr. Saxton referred to AEA's objection to administering payment of approved Committee legal fees.) Mr. Garzini reiterated his desire for the utilities to control more of the operation and maintenance of the Bradley Lake (and Four Dam Pool) Project(s). However, in addition to ownership of the project, AEA has an obligation to FERC and a bond obligation which must be fulfilled. Mr. Garzini stated that beyond these requirements, all other issues were open to the management of the Committee. Mr. Kelly noted that AEA's responsibilities had been protected by the inclusion of veto rights. Referring to the Power Sales Agreement, Item 13 (b), Mr. Saxton confirmed that AEA had certain non-delegable rights and that in these matters the utilities and AEA had to agree. Mr. Saxton stated, in order to avoid potential problems, it was necessary to clarify who was responsible for contract commitments made by AEA prior to execution of a contract. Mr. Garzini suggested that the BPMC wait until after the Alaska Energy Authority's strategic plan was presented to its Board of Directors on January 22, 1993 before taking any action on the issue. Pending the response of the Board of Directors to the plan, Mr. Garzini hoped to call a meeting of all the utilities (Four Dam Pool and Bradley Lake) to begin discussing the transfer of responsibility. Mr. Saxton stated that the Agreements Subcommittee could not finalize some of the agreements now being worked on without guidance on the authoritative roles of the BPMC and AEA. Mr. Kelly recommended that the Agreements Subcommittee be informed that the BPMC wished to retain the power that was intended by the Power Sales Agreement, noting that, in some respects, AEA's participation was absolute within the BPMC. Chairman Highers expressed the concurrence of the Committee, requesting that it be noted in the minutes. Responding to inquiry by Mr. Lovas, Mr. Kelly confirmed that the existing agreements should be re-opened to "reformulate the participants." It was clarified that the substance of the agreements would not change. Mr. Lovas e:\dburger\word\minutes\pmc\01-93 BPMC Meeting Minutes January 14, 1993 Page 13 of 13 pt i ced the concept of one master Bradley Lake operational procedure Quagreement designed to incorporate all operational issues (rather than the present series of agreements). Mr. Story expressed concern over the potential for further delays to the completion of present draft agreements. Authority Over Budget Revisions Mr. Ritchey moved that the Bradley PMC it authority to the Budget Subcommittee to manage budget line items. However, if the Subcommittee anticipates an inc: to the approved overall operatin budget of more than ten percent, the Subcommittee would seek BPMC approval. The FY93 operating budget is $2,699,928. Therefore any budget changes greater than $269,993 would require approval of the Bradley PMC. Mr. Ritchey noted that the request was, in part, inspired by the need to pay the BPMC legal bills which had exceeded the budgeted line item amount. Mr. Ritchey explained that the Subcommittee wanted to establish a means by which it could make adjustments to the budget (within limitations). It was clarified that the ten percent limit referred to cumulative budget changes. The motion seconded by Mr. Kelly, was approved by a unanimous role call vote (Action 93-163). 13. |. COMMUNICATIONS A. Schedule Next Meeting March 11, 1993 10:00 a.m. CEA Training Room 14. ADJOURNMENT With no further business or communications before the Committee, the meeting adjourned at 12:25 p.m. David L. Highers, Chairman Attest: Ronald A. Garzini, Alternate Secretary e:\dburger\word\minutes\pmc\01-93 DATE: Oz FROM: SUBJECT: Alaska Energy Authority MEMORANDUM February 18, 1993 Bradley Lake Hydroelectric Project Project Management Committee Denise Burger peo Revised Scheduling and Allocation Procedures Attached are the Revised Scheduling and Allocation Procedures as recommended to the Bradley Lake Project Management Committee for adoption by the Operation and Dispatch Subcommittee. Please note that new text has been printed in bold and any original text to be deleted has been lined through. A bar appears in the left margin where any changes have been made. BRADLEY LAKE HYDROELECTRIC PROJECT ALLOCATION AND SCHEDULING PROCEDURES As Revised by the BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE 1993 BRADLEY LAKE HYDROELECTRIC PROJECT ALLOCATION AND SCHEDULING PROCEDURES As Revised by the BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE on 571993 These Procedures dated July 2, 1991, have been approved and adopted by the Bradley Lake Project Management Committee to govern the allocation and scheduling of electric capacity and energy available to the Purchasers from the Project under the Project Power Sales Agreement. Section 1. Definitions. For the purposes of these Procedures, the following definitions apply; (a) AEA or Authority. The Alaska Energy Authority (b) AEG&T. The Alaska Electric Generation and Transmission Cooperative, Inc. (c) Basic Agreements. The agreements entered into and amended from time-to-time for the sale, purchase and transmission of Bradley Lake power and includes the Power Sales Agreement, the Chugach Services Agreement, and the HEA Transmission Sharing Agreement. (d) Bradley River Minimum Flow Releases. Those minimum amounts of water (flows) that are required to be released into the Bradley River under the FERC license. (e) Chugach. The Chugach Electric Association, Inc. (f) Chugach Services Agreement. The Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric and for Related Services dated December 8, 1987, between Chugach and ML&P, HEA, GVEA, MEA, SES and AEG&T providing for Chugach's transmission and other services. 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. (i) Effective Date. September 1, 1992, the date of Commercial Operation of the Project as provided in the Power Sales Agreement. (j) Energy Account. The account maintained by the Authority to record the amount of Initial Project Energy and Revised Project Energy each Purchaser is entitled to schedule under these Procedures. (k) | FERC License. License No. 8221 that has been issued by the Federal Energy Regulatory Commission to the Authority for the construction and operation of the Project. (1) Fiscal Year. As defined in Section 1(r) of the Power Sales Agreement. (m) Forced Outage. An outage due to any failure of a generating facility, related auxiliaries, or a transmission facility which a Purchaser relies upon to supply firm power to meet its firm load obligation and which causes a deficiency in power resources available to meet the Purchaser's load. (n) | GVEA. Golden Valley Electric Association, Inc. 92Q4\NK3849.DOC(2) (0) HEA. Homer Electric Association, Inc. (p) HEA Transmission Sharing Agreement. The Bradley Lake Hydroelectric Project Transmission Sharing Agreement dated December 8, 1987 and as amended March 7, 1989, for wheeling of power over the HEA system entered into by and among Chugach, GVEA, ML&P, and AEG&T. (q) _ Initial Project Energy. The amount of Project Generation expected during the Project Water Year, as computed prior to the beginning of the Project Water Year pursuant to Section 4(c). (r) MEA. Matanuska Electric Association, Inc. (s) ML&P. Anchorage Municipal Light and Power. (t) Net Allocation. The monthly energy from the Project available to a Purchaser in establishing the Initial Project Energy and Revised Project Energy(s) under Section 4 from the beginning of the Project Water Year through the end of the current month less the total Project Generation for that Purchaser from the beginning of the Project Water Year to date plus any debits or credits from the previous Project Water Year. (u) | Operation and Dispatch Committee. The Committee appointed by the PMC to address technical issues related to the operation and dispatch of the Project. (v) | PMC. The Project Management Committee established pursuant to the Power Sales Agreement. (w) Percentage Share. The fraction expressed as a percent and set forth for each Purchaser in Exhibit D of the Power Sales Agreement. (x) Power Sales Agreement. The Agreement for the Sale and Purchase of Electric Power from the Project entered into by and among the Authority and the Purchasers dated December 8, 1987, and as may be amended from time-to- time. (y) Procedures. These Allocation and Scheduling Procedures. (z) Project. The Bradley Lake hydroelectric generating Project as described in Exhibit C of the Power Sales Agreement. (aa) Project Capability. The amount of electric capacity capable of being produced by the Project at any given time taking into account system conditions, equipment and Project transmission availabilities and limitations. (bb) Project Capacity. The amount of electric power capable of being produced by the Project at the then current reservoir level with all generating and transmission facilities of the Project fully operational. (cc) Project Generation. That amount of energy produced by the Project recorded on an hourly basis. 92Q4\NK3849.DOC(3) (dd) Project Reservoir. The body of water held behind the dam of the Project used for Project Generation, Bradley River Minimum Flow Releases, and Project Spill. (ee) Project Spill. The water released from the Project Reservoir into the Bradley River in excess of Bradley River Minimum Flow Releases and in excess of that which has already been accounted for in the Reservoir Operation Mode. Project Water Year. The twelve-month period starting on June 1 and ending on May 31. (gg) Prudent Utility Practice. The practice defined in Section 1(x) of the Power Sales Agreement. (hh) Purchaser. Purchaser means, as of any particular time, the Municipality of Anchorage d/b/a Municipal Light and Power, Chugach Electric Association, Inc., Golden Valley Association, Inc., the City of Seward and the Alaska Electric Generation & Transmission Cooperative, Inc. ("AEG&T). The term "Purchaser" includes Homer Electric Association, Inc., and Matanuska Electric Association, Inc., only to the extent specified in Section 30 of the Power Sales Agreement. (ii) Reservoir Operation Model. The model described in Exhibit A used to determine the Initial Project Energy and Revised Project Energy. (jj) | Revised Project Energy. The amount of Project Generation for the remaining portion of the Project Water Year calculated under Section 4(d) if actual operating conditions significantly change the expected amount of total Project Generation for the Project Water Year from previous forecasts. (kk) SES. Seward Electric System (ll) Spinning Reserves. The amount of on-line capacity available from the Project from time-to-time which is available to meet Purchasers' loads, minus actual Project available to meet Purchasers’ loads, minus actual Project output, in accordance with Section 9 of these Procedures. (mm) Termination Date. The date the PMC adopts revised procedures pursuant to the terms of the Power Sales Agreement which replace these Procedures. Section 2. Term. These Procedures shall become effective upon the Effective Date and shall continue in force until the Termination Date. Section 3. Exhibits. The following exhibits are incorporated by reference in these Procedures: (a) Exhibit "A", Description of Reservoir Operation Mode; (b) — Exhibit "B", Description of Project Operating Criteria; (c) Exhibit "C", Scope of the Project Dispatch Duties; and 92Q4\NK3849.DOC(4) (d) Exhibit "D", Transmission System Dispatch and Clearance Procedures. Section 4. Project Allocation. (a) General. Nothing in these Procedures shall cause the Project to be operated or maintained in a manner that is not consistent with Prudent Utility Practice nor shall it be operated or maintained in a manner that is not consistent with the FERC License and other permits and licenses. The PMC recognizes that the method of operating the Project may change from time-to-time in order to accommodate modifications to such licenses and permits. (b) Relationship to Basic Agreements. In the event that any provisions in these Procedures conflict with provisions in any of the Basic Agreements, the provisions in the Basic Agreements shall prevail. (c) _ Initial Allocation. Fhetnitial Project Energy-prior-to-the beginning ing: The Initial Project Energy shall be determined prior to the beginning of each Project Water year based on known operating limitations, forecasted estimates of runoff available from snowcap and precipitation by the National Weather Service (NWS) for the 50% exceedance probability and/or the mean monthly discharge (depending upon availability of the information), and other pertinent factors, and in a manner consistent with the following: (i) On or before March 1 of each year, the PMC shall meet and establish a coordinated maintenance schedule for their transmission facilities and the Project for the 12-month period commencing with the ensuing June 1. (ii) On or before April 15 of each year, the Authority shall transmit to the Purchasers a preliminary estimate of the amount of capacity and preliminary Initial Project Energy available for the upcoming Project Water Year. (iii) On or before May 1, each Purchaser shall submit to the Authority its forecasted monthly use of its Percentage Share of Initial Project Energy. The monthly energy requirements will be based on the expected Initial Project Energy, as estimated under Section 4(c)(ii), and coordinated maintenance schedule established in Section 4(c)(i). (iv) Based on the total monthly energy requirements from the Project for all Purchasers, the Authority shall perform the Reservoir Operation Model as outlined in Exhibit A and compare the resulting Initial Project Energy with the preliminary Initial Project Energy estimate in Section 4(c)(ii). The Authority shall transmit to each Purchaser the results of the Reservoir Operation Model by May 15. (v) Ifthe results of the Reservoir Operation Model performed above show the expected Initial Project Energy to be different than that assumed in Section 4(c)(ii) above or there is potential for Project Spill, the 92Q4\NK3849.DOC(5) 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 minimized. (d) Revised Allocation. Each month the Authority shall estimate the amount of energy available from the Project for the remainder of the Project Water Year and determine the amount of energy which should be added or subtracted from each Purchaser's Net Allocation of energy for each month in the remainder of the Project Water Year. In the event the amounts to be added or subtracted from the total Net Allocation then in effect for the Purchasers exceeds 15, 000 mWhs and on November 1 of each year, the Authority shall determine the amount of Revised Project Energy for each Purchase in the following manner: (i) The Authority shall transmit to the Purchasers a preliminary estimate of the Revised Project Energy for the remainder of the Project Water Year and the Project Generation to date. (ii) Each Purchaser shall be allocated its Percentage Share of any difference between the new Revised Project Energy, and the then in effect estimate of Project Generation for the Project Water Year. If the result of such allocation is negative, the Purchaser's Net Allocation shall be reduced by such amount in the next Project Water Year. (iii) The Purchaser shall submit to the Authority its forecasted monthly requirements of the Revised Project Energy. (iv) Based on the total monthly requirements of Revised Project Energy, the Authority shall perform the Reservoir Operation Model as outlined to verify the Revised Project Energy. (v) Ifthe results of the Reservoir Operation Model performed show the Revised Project Energy to be different than that assumed in Section 4(d)(i) or there is potential for Project Spill, the Authority and the Purchasers shall work together in revising monthly energy requirements such that Revised Project Energy and the sum of the Purchasers' monthly energy requirements assumed for the Reservoir Operation Model are equal to one another and Project Spill potential is minimized. (e) Status of Energy Account. As soon as practicable after the end of each month, the Authority shall provide each Purchaser an accounting of the amount of Initial Project Energy or Revised Project Energy available to each Purchaser in its Energy account for the remainder of the Project Water Year, along with its best estimate of the potential availability of additional Revised Project Energy and potential for Project Spill in the ensuing month. If an event occurs during any month which requires the Authority to increase or decrease the amount of Revised Project Energy available to a Purchaser or increases the potential of spill, the Authority shall use its best efforts to provide each Purchaser an interim accounting of the Initial Project Energy or Revised Project Energy available and the amount of such energy which could be subject to spill in the next 30 days. (f) Failure to Refill. If the Revised Project Energy is expected to be 90 percent or less than previous estimates or Project Generation for the Project Water 92Q4\NK3849.DOC(6) 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 recommendation and adopt, if appropriate, a revised schedule of Project Generation. Any disputes shall be resolved in accordance with the by-laws established by the PMC. (g) Review of Reservoir Operation Model. The methodology and inputs of the Reservoir Operation Model shall be reviewed by the Operation and Dispatch Committee at least every five (5) years and recommendations for changes to the Model provided to the PMC. The Reservoir Operation Model shall be modified, if required, to reflect the changes to the permits and licenses that the Project is operated under. The PMC shall have the right to approve any changes made to the Reservoir Operation Mode. Section 5. Project Scheduling. (a) General. Each Purchaser shall have the right to schedule during any month an amount of Project Generation not to exceed its Net Allocation for that month. (b) Hoes Schedules. miss tack ines et ota oaks The utilities weddy ochediale sie be submitted to the diubatcher no later than 1400 hours on Tuesday; a preliminary summary of schedule requests shall be distributed to all utilities no later than 1400 hours on Wednesday for review; the schedule shall be confirmed by the dispatcher no later than 1400 hours on Thursday; and implemented at 0001 hours on Saturday. (The energy week is established to be Saturday through Friday.) Daily schedule changes shall be allowed, subject to procedures implemented by the O&D Subcommittee. (c) Minimum Scheduling. If the combined scheduled Project Generation from Purchasers scheduling generation is less than 10.0 mW in any one hour, the Purchasers shall be notified no later than 10:0 a.m. on the following day. The Purchasers shall have until 5:00 p.m. of that day to revise their schedules such that the combined Project Generation is equal to or greater than 10. mW. If such revisions still result in a combined scheduled Project Generation of less than 10.0 mW, such Project Generation shall not be scheduled for Project output. (d) Minimum Operations. If, due to operating constraints included in the various permits and licenses that the Project is operated under, the Project must be operated in a manner such that Project Generation is greater than that amount scheduled by all the Purchasers, the amount of Project Generation in excess of that amount scheduled shall be allocated on a pro rata basis to each Purchaser based on its Percentage Share. No Purchaser shall be obligated to take more than its Percentage Share of Project Capability. (e) Reduction in Schedules. If the combined scheduled Project Generation than is greater than Project Capability in any hour, each Purchaser's request shall be reduced during that hour in the following manner: 92Q4\NK3849.DOC(7) (i) For those Purchasers who have scheduled more Project Generation than their respective Percentage Shares of Project Capability in any hour, the amount scheduled for such Purchasers shall be reduced on a pro rata basis based on the amount scheduled Project Generation exceeds Project Capability. The amount of scheduled Project Generation for any Purchaser shall not be decreased pursuant to this Section 5(e)(i) to an amount less than each respective Purchaser's Percentage Share of Project Capacity. (ii) If after making such reductions in Section 5(e)(i) the combined scheduled Project Generation still exceeds Project Capability in any hour, Project Generation for each Purchaser scheduling Project Generation in such hour will be reduced on a pro rata basis based on the respective Percentage Shares. (f) Schedule Modifications. In the event that a Purchaser experiences a 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. (ii) Within four hours of such notification, the Purchaser shall submit to the Dispatcher a revised schedule of Project Generation for its use for the remaining portion of the week. If such revision is not submitted, the Dispatcher will operate the Project in a manner consistent with the schedule already in effect for that week. (iii) The right of the Purchaser to schedule Project Generation up to its Percentage Share of Project Capability shall not be limited by other Purchasers scheduling Project Generation in an amount greater than their Percentage Share of Project Capability. (iv) Nothing in this section shall allow a Purchaser to schedule more Project Generation than is allowed pursuant to Section 5(a). (g) Schedules Above Participants Share. (i) A Purchaser, upon obtaining permission from another Purchaser that is not scheduling all of its Participant Share of Project Capability, may schedule its Net Allocation or Revised Project Allocation by using Project Capability of such other Purchaser. The scheduling by a Purchaser of another Purchaser's Project Capability shall include all the benefits, rights and obligations related to such schedule as provided in this Section. (ii) The scheduling Purchaser, as compensation for the right to schedule a portion of its Net Allocation or Revised Project Energy by use of another Purchaser's Share of Project Capability in any hour, shall be obligated to pay such other Purchaser at $5/mW ($.005/kW) for each hour that such Purchasers share is used. 92Q4\NK3849.DOC(8) (iii) The Dispatcher shall establish an account for each Purchaser in which the debits and credits (in Dollars) for use of a Purchaser's Share of Project Capability under Section 5(b) will be accounted. As soon as reasonably practicable after the close of each Fiscal Year (as defined in the Power Sales Agreement), the Dispatcher shall determine the amounts which each Purchaser owes or is entitled to be paid as of the end of such Fiscal Year. Using the amounts so determined, the Dispatcher shall submit a schedule of payments to the effected Purchasers which will reduce the amounts credited or debited to each Purchaser to zero at the end of such Fiscal Year. Payments under such schedule shall be made by the owing Purchaser to the indicated Purchaser(s) within 30 days after receipt of the schedule of payments. (iv) | Each Purchaser is allocated by ownership share Project Energy for a given Project Water Year. The Purchaser can utilize their allocation within the respective Project Water Year or under- utilize their allocation for later use (ponding). However, no Purchaser shall knowingly schedule above their allocation or borrow into the next Project Water Year. *NOTE* Accidental over-scheduling is addressed in the Bradley Lake Allocation and Scheduling Procedure. If a Purchaser has used their allocation by May 31, then scheduling in the next Project Water Year may be limited by inflows during June. Any Purchaser limited in June may borrow from another Purchaser, if plausible, according to the Bradley Lake Allocation and Scheduling Procedure. (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. Ifa Purchaser is unable to schedule its full Purchaser's Share of Project Capability, the energy which is not scheduled shall be made available to the other remaining Purchasers for scheduling pro rata based on their Purchaser's Share. (iv) Once a pending spill period is suspended by the Authority, the energy scheduled and generated from inflows in excess of forecast inflows under this subsection shall be added to each Purchaser's Net Allocation or Revised Project Energy for the month. Schedule of energy by a Purchaser 92Q4\NK3849.DOC(9) during the pending spill period shall then be credited against the resulting Revised Project Energy total for each Purchaser for such month. (i) End of Water Year Procedures At the end of the Project Water Year, a comparison of allocation to scheduled through May 31 will be made for each Purchaser as well as for the Project as a whole. The total Project Allocation minus the total Scheduled will equal the total Project Pond. Likewise, a Purchaser Allocation minus the actual Purchaser's Scheduled will equal the Purchaser Pond. Water Year '91-'92 Pond CEA MEA SES GVEA HEA AMLP_ TOTAL Allocation 116,432 52,854 3,830 64,727 45,960 99,197 383,000 Scheduled 103,846 47,059 3,394 53,501 28,992 99,175 335,967 Pond 12,586 5,795 436 11,226 16,968 22 47,033 Another step in the end of the Project Water Year is to True the Initial Project Allocation. On June 1, all available data will be used to determine what the Actual Project Allocation should have been. Next, a comparison is made between the two Allocations. The difference of the Allocations is added to or subtracted from the Next Year Project Allocation and distributed to each Purchaser by ownership share. The Authority will rerun the Allocation model when the error is plus or minus 15,000 MWH or more. Water Year '91-'92 True Up The Lake was 1104.6 feet on June 1, 1992 with a storage of 311,126 Ac-Ft. This is 47,808 Ac-Ft above the 1080 feet storage. This indicates that we have a positive carry over of 775 MWH after Pond accounting. The amount is proportioned below to each Utility's Water Year '92-'93 Allocation. CEA SES GVEA HEA AMLP TOTAL '92-'93 Allocation* 122,512 4,030 68,107 48,360 104,377 403,000 Carry Over 235 8 131 93 201 7715 New '92-'93 122,747 4,038 68,238 48,453 104,578 403,775 Allocation* * Not including 92Q4\NK3849.DOC(10) (i) Scheduling Limitations As previously agreed, all Purchasers will schedule to avoid or minimize Project Spill. The Authority shall provide to all Purchasers all relevant data to achieve this goal. If a Project Spill is anticipated, the Authority will provide a projected Spill Date and a Minimum Use Allocation to avoid Spill. The Minimum Use Allocation will be based on reservoir elevation level beginning at 1080 on June 1. To prevent a Spill, all Purchasers will schedule their ownership share of the Minimum Use Allocation prior to the projected Spill Date. *NOTE* The Minimum Use Allocation does not take Project Pond into account. Each Purchaser will have MWH at Risk of Spill equal to their Minimum Use Allocation plus Purchaser's Pond. The MWH at Risk value will decrease as a Purchaser schedules during the Project Water Year. The MWH at Risk will also change if the projected Spill Date is different from an actual Spill Date. EXAMPLE MWH at Risk CEA MEA SES GVEA HEA AMLP_ TOTAL Min Use 16,112 7,314 530 8,957 6,360 13,727 53,000 Allocation Prior to Sept. '92 Pond* 12,586 5,795 436 _ 11,226 _ 16,968 22 MWH at Risk 28,698 13,109 966 20,183 = 23,328 * Pond as of June 1, 1992 MWH at Risk on August 1, 1992 CEA MEA SES GVEA HEA AMLP Revised Min Use 10,683 4,850 351 5,939 4,217 9,102 Allocation** Pond* 12,586 __ 5,795 436 _ 11,226 _ 16,968 22 Subtotal 23,269 10,645 787 17,165 21,185 9,124 Scheduled 20,190 9,150 660 _ 15,000 _ 20,000 _ 10,000 MWH at Risk 3,079 1,495 127 2,165 1,185 0 * Pond as of June 1, 1992 ** Based on 61 day availability to schedule on and original 92 day forecast to Spi A second scheduling limitation is imposed to prevent over-scheduling within the Project Water Year in case the Project Allocation was over- estimated. Based upon previous analysis completed by Stone & Webster Engineering Corporation it has been determined that the minimum amount of energy that is obtainable from the Bradley Lake Hydroelectric project in 92Q4\NK3849.DOC(11) any given year would be approximately 260,000 MWH. Based upon this amount and the requirement that no Utility over schedules their proportionate share of Bradley power, a maximum energy use between June 1 and November 1 needs to be established. The maximum energy use between June 1 and November 1 is equal to each Utility's proportionate share of the 260,000 MWH as illustrated on the next page. After November 1 each utility may take 100% of its proportionate share of the project (remaining balance as reallocated on November 1.) EXAMPLE Max Energy Use through Spill Season CEA MEA SES GVEA HEA AMLP_ TOTAL MAX Energy 79,040 35,880 2,600 43,940 31,200 67,340 260,000 92Q4\NK3849.DOC(12) Section 6. Project Operations. The Project shall be operated by the Dispatcher pursuant to the terms and conditions of the Dispatch Agreement and consistent with those set forth in Exhibits B, C, and D. Section 7. Project Spill. The Purchaser recognizes that from time-to- time water from the Project Reservoir may be spill which does not result in Project Generation. If this occurs, then: (a) The Authority shall measure the quantity of Project Spill and convert the amount of spill over and above the amount of the Bradley Minimum Flow Releases to energy, utilizing the appropriate conversion factors. (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. (c) In the event of Project Spill, the Authority will provide a conversion of Water Spill into Energy. If MWH at Risk exist at Spill, then the Project Spill will be subtracted from each Purchaser's Pond and Allocation by proportionate share of MWH at Risk. If the spill energy exceeds the amount of risk (i.e. if spill is 10,000 MWH and 8.051 MWH was at risk) then all energy generated during spill and prior to spill could not be counted in the utility allocation for that year. A new allocation for each utility would be developed at the end of the spill based upon each utility's project share and a full reservoir. EXAMPLE Spill on August 1, 1992 Equal to 5,000 MWH Using Numbers from MWH at Risk on August 1, 1992 Previous Example GVEA HEA AMLP TOTAL CEA MEA __ SES MWH at Risk 3,079 1,495 127 2,165 = 1,185 Ratios at Risk 0.382 0.186 0.016 0.269 0.147 8,051 1.000 7) ae Spill 1,910 930 80 = 1,345 735 5,000 Distribution 92Q4\NK3849.DOC(13) EXAMPLE Spill on August 1, 1992 Equal to 10,000 MWH Using Numbers from MWH at Risk on August 1, 1992 Previous Example CEA MEA SES GVEA HEA AMLP TOTAL MWH at Risk 3,079 1,495 127.) 2,165 1,185 0 8,051 Ratios at Risk 0.382 _0.186 _0.016 _0.269 _0.147 0 1.000 Spill 3,079 1,495 127. 2,165 1,185 0 8,051 Distribution 92Q4\NK3849,DOC(14) Section 8. Losses. (a) General. The losses provided for in this Section 8 shall be accounted for in kind by reducing the amount of energy delivered to each Purchaser and not by direct monetary compensation. (b) Losses on Project Transmission. Losses on the transmission lines of the Project shall be determined pursuant to load flow studies. (c) Losses on the HEA System. Losses on the HEA transmission system under various operating conditions shall be determined by the PMC in accordance with load flow studies. The studies shall be performed with and without the Project, and a matrix of loss factors developed for various projects. HEA load levels and transmission system operating conditions. The loss factor matrix shall be of a form and format suitable for hourly accounting of losses. If actual operating and dispatch experience indicates that the loss factors may need adjustment, further studies under the above conditions shall be done, taking into account any adjustments that experience may dictate. (i) The Dispatcher shall maintain records adequate to determine the relevant HEA load levels and transmission conditions when particular deliveries of Project power are accomplished. Such records shall be made available to the parties in the HEA Transmission Sharing Agreement upon reasonable request. (ii) Deliveries under the HEA Transmission Sharing Agreement shall be reduced for line losses as appropriate under the matrix of line losses developed under this subsection. (d) Losses on the Chugach Electric System. Deliveries by the Chugach Electric System over its transmission facilities may be accomplished by Direct Transmission (as defined in the Chugach Services Agreement) or through Offsetting Flows (as defined in the Chugach Services Agreement). (i) The Dispatcher shall maintain records adequate to determine the extent to which particular deliveries are accomplished in whole or in part by each of these means. Such records shall be made available to the Wheeling Utilities (as defined in the Chugach Services Agreement) upon reasonable request. (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 92Q4\NK3849.DOC(15) reduced for line losses to the extent of the increase in Chugach wholesale system line losses attributable thereto. (iii) If and to the extent deliveries are accomplished through Offsetting Flows as defined in the Chugach Services Agreement, such deliveries shall not be reduced for line losses; provided that if , after a reasonable period of experience in actual operation under the Services Agreement, Chugach's system line loss studies prepared for use in Chugach's periodic wholesale and/or retail rate adjustment proceedings demonstrate that Chugach's wholesale line losses have increased as the direct result of Bradley Lake Energy delivered through Offsetting Flows, then deliveries of such energy through Offsetting Flows shall thereafter be reduced for line losses, but only to the extent of the increase in Chugach wholesale system line losses attributable thereto. Section 9. Spinning Reserves. The Operation and Dispatch Committee shall recommend to the PMC a method for allocation of Spinning Reserves in each hour under various system operating conditions. Once approved by the PMC such Spinning Reserves shall be made available in accordance with 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 to the Purchasers, and reduce, where practicable, the obligation of the Authority to provide information or revised data which is not useful to the Parties. 92Q4\NK3849.DOC(16) EXHIBIT A Description of Reservoir Operation Model (To Come) 92Q4\NK3849.DOC(17) EXHIBIT B TURBINE OPERATION The following schedule shall be used to determine the operation of the Bradley Lake generators, assuming both units are available for operation: Plant Schedule (MW) Speed Mode Condense Mode Note Schedule< 10 MW No Units None, One or Both Units #1 10 MW<Schedule <20 MW_ One Unit One Unit #2 20 MW<Schedule <30 One Unit One Unit/No Unit #3 Schedule > 30 MW Both Units No Units Note #1 - If any participant could utilize the spinning reserve from a unit or a second unit in the condense mode, one or both units will be operated in condense. If no utility requests the additional spinning reserve, only one unit will be operated in condense if required for voltage control unless a unit is changed to condense to avoid a shutdown. Note #2 - Depending on spin requirements, either one unit will be operated alone in the speed mode or both units will be operated, one in speed and one in the condense mode. A utility can request the unit be operated in the condense mode as opposed to altering its schedule if in conflict with the minimum four hour down time. Note #3 - Any scheduling utility can require both units to be placed on-line between 20 and 30 MW if desired by that utility, although it would be possible to operate one unit in speed and one unit in condense mode at these levels to obtain the entire spinning reserve allocation for the plant, the more efficient operation would be for both units to be operated above 10 MW each in speed mode. Minimum Unit Shut Down Each unit scheduled for shutdown shall be shut down for a minimum of four hours. Operation of a unit in the condense mode will not constitute a shut down and does not have a four hour minimum time associated with it. The following criteria shall generally govern the operation of the plant during islanded and non-islanded conditions: 92Q4\NK3849.DOC(18) ISLANDED OPERATION Unscheduled Islanding If the Kenai is operating with only Bradley Lake or Bradley Lake and Cooper Lake prior to islanding, on Bradley Lake unit will automatically be placed in deflector by the Chugach SCADA system upon detection of islanding. The unit will remain in deflector until a Kenai area gas turbine has been synchronized with the islanded Kenai system. After a gas turbine has been synchronized with the Kenai system the unit will be changed to the speed mode from the deflector mode. During load restoration on the Kenai, one unit may be placed in deflector control to aid the gas turbine in load pickup and frequency restoration. The unit will be returned to speed mode after restoration has been completed. Scheduled Islanding Prior to scheduled islanding a Kenai area gas fired generator will be synchronized with the Kenai system. Bradley generation will remain in the speed mode. Islanded Operation - Steady State While running islanded, a gas-fired generator shall be operated in conjunction with Bradley Lake. The Bradley Lake units shall be operated in the speed mode. If an on-line gas-fired turbine suffers a forced outage and it is the only gas-fired unit on-line in the islanded system, one Bradley Lake unit shall be placed in deflector mode and operated in deflector until a gas-fired generator is placed on-line in the islanded area. INTERCONNECTED OPERATION - STEADY STATE While Bradley Lake is interconnected to the Anchorage system, its normal mode of operation shall be the speed mode for both units. During times of system load restoration, one Bradley Lake unit may be placed in the deflector mode if the amount of load to be restored will not exceed the export or operating limits of the Kenai system. EM: nk 92Q4\NK3849.DOC(19) ~ STATE i KA NOTICE TO aa ADVERTIGING ORDER NO. 7 own q ADVERTISING Ons s’Seariries Arrioavir OF PUBLICATION | A ORDER 2 OF ‘ FORM) WITH ATTAGHED COPY OF ADVE! O- os-9186 MEN" ST BE SUBMITTED WITH INVOICE. ° Alaska Ener Authority Irene Tomor, February 17 i993 a P.O. Box 190869 oc Anchorage, Alaska 99519-0869 261-7240 ad FAX: 561-8584 ‘ ; LK ONCE: February 24, 1993 | 3 Anchorage Daily News & Se peer ALP oosde=9001 . TRS AATEDVAG ETRMEEN THe Counts Conve 8 PRINTED IN ITS ENTIRETY > FAX: 279-8170 : so AEA_Internal Accounting: Charge to : 81072020 Type of Advertisement: X¥K Legal CO Diepiay CD Classitied © Other (pecity): . RECOR OPY Use the 100" advertising agreement on the following ad: kao vOP’ ALASKA ENERGY AUTHORITY =e STATE OF ALASKA ~ NOTICE pro B-l) | uid ~ peer a Notice is hereby given that the Bradley Lake Project Management Committee will hold a regular meeting to conduct the affairs of the Committee at Chugach Electric a . Association in Ancnorage, Alaska. The meeting will commence at 10:00 a.m., 3/3/§72 on March 3, 1993. For additional information, contact Devid L. Highers,. Chairman, A Cnugach Electric Association, Inc., P.O. Box 196300, Anchorage. AK 99519. Alaska Energy Authority, Secretary “ Project Management Committee rage + or) TOTAL OF maass| act PAGES -S ner [tyes NUMBER AMOUNT DATE COMMENTS >| ven > — > = Fin AMOUNT ey ‘os Pan to Acor ry x o z f E : rei | Irene Tomory,. Admin. Coordinator | = G2-007 (Rev. 6-66) | PUBLISHER TRANSMISSION REPORT THIS DOCUMENT (REDUCED SAMPLE ABOVE) WAS SENT **K COUNT **& # 2 weeK SEND 24k NO REMOTE STATION I.D. START TIME DURATION | #PAGES COMMENT a 1 907 2798170 2-17-93 9:09 1°28" | 2 TOTAL 0:01'28" 2 XEROX TELECOPIER 7020 NOTICE TO PUBLISHER INE MUST BE IN TRIPLICATE SHOWING ADVE] NG ©} —NO., CERTIFIED AFFIDAVIT OF PUBLICATIO _ \RT 2 OF THIS FORM) WITH ATTACHED COPY OF ADVERTISE- A0- 08-9186 MENT MUST BE SUBMITTED WITH INVOICE. STATE OF ALASKA ADVERTISING ORDER SEE BOTTOM FOR INVOICE ADDRESS AGENCY CONTACT DATE OF AO. F Alaska Energy Authority Irene Tomory February 17, 1993 R P.O. Box 190869 PHONE ° Anchorage, Alaska 99519-0869 (907) 261-7240 - FAX: 561-8584 DATES ADVERTISEMENT REQUIRED: 7 ONCE: February 24, 1993 : Anchorage Daily News : ei een CRSA eae gare te DOUBLE LINES MUST.BE PraNTED IN ITS ENTIRETY nl FAX: 279-8170 SPECIAL INSTRUCTIONS: s AEA Internal Accounting: Charge to 4 81072020 R + Type of Advertisement: XXXtegal Display CClassified | O Other (Specify): Use the 100" advertising agreement on the following ad: ALASKA ENERGY AUTHORITY STATE OF ALASKA NOTICE Notice is hereby given that the Bradley Lake Project Management Committee will hold a regular meeting to conduct the affairs of the Committee at Chugach Electric Association in Anchorage, Alaska. The meeting will commence at 10:00 a.m., on March 3, 1993. For additional information, contact David L. Highers, Chairman, Chugach Electric Association, Inc., P.0. Box 196300, Anchorage, AK 99519. Alaska Energy Authority, Secretary Project Management Committee SEND INVOICE IN PAGE 1 0F| TOTAL OF TRIPLICATE TO PAGES| ALL PAGES $ REF | TYPE NUMBER AMOUNT DATE COMMENTS 1 | VEN 2 3 | a1 4 FIN | AMOUNT sY cc PGM Lc ACCT FY bart ts 1 2 3 4 REQUISITIONED BY: DIVISION APPROVAL Irene Tomory, Admin. Coordinator 02-901 (Rev. 6-85) PUBLISHER STATE OF ALASKA ADVERTISING ORDER NO. ADVERTISING ORDER A0- 08-9186 AGENCY CONTACT DATE OF AO. F Alaska Energy Authority Irene Tomory February 17, 1993 R P.0. Box 190869 PHONE ° Anchorage, Alaska 99519-0869 (907) 261-7240 M FAX: 561-8684 DATES ADVERTISEMENT REQUIRED: = ONCE: February 24, 1993 ° Anchorage Daily News 7 P.O. Box 149001 B Anchorage, AK 99514-9001 ri FAX: 279-8170 SPECIAL INSTRUCTIONS: s AEA Internal Accounting: Charge to e 81072020 R UNITED STATES OF AMERICA REMINDER— STATEOF_ ss INVOICE MUST BE IN TRIPLICATE AND MUST REFERENCE THE ADVERTISING ORDER NUMBER. DIVISION. A CERTIFIED COPY OF THIS AFFIDAVIT OF PUBLICATION MUST BE SUBMITTED WITH THE INVOICE. BEFORE ME, THE UNDERSIGNED, A NOTARY PUBLIC THIS DAY PERSONALLY APPEARED WHO, ATTACH PROOF OF PUBLICATION HERE. BEING FIRST DULY SWORN, ACCORDING TO LAW, SAYS THAT HE/SHE IS THE OF PUBLISHED AT IN SAID DIVISION AND STATE OF SSC AND) THAT THE ADVERTISEMENT, OF WHICH THE ANNEXED IS A TRUE COPY, WAS PUBLISHED IN SAID PUBLICATION ON THE sé OFF 19. , AND THEREAFTER FOR CONSECUTIVE DAYS, THE LAST PUBLICATION APPEARING ON THE DAY OF 19 , AND THAT THE RATE CHARGED THEREON IS NOT IN EXCESS OF THE RATE CHARGED PRIVATE INDIVIDUALS. SUBSCRIBED AND SWORN TO BEFORE ME eS LT DAYOR LIT tT et. NOTARY PUBLIC FOR STATE OF MY COMMISSION EXPIRES 02-901 (Rev. 6-85) PUBLISHER