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HomeMy WebLinkAboutBPMC Meeting January 18, 1990 3STONE & WEBSTER ENGINEERING CORPORATION 9” a 800A STREET, SUITE 211, ANCHORAGE, ALASKA Pr o- 3- ADDRESS ALL CORRESPONDENCE TO P.O. BOX 104479. ANCHORAGE, ALASKA 99510 apavai TELEPHONE 907-276-1583 iN NEW YORK TELECOPY 907-277-7092 CHERRY HILL. NJ. OENVER HOUSTON DALLAS PORTLANO. OREGON RICHLANO. WA WASHINGTON. 0.c. Mr. D. R. Eberle January 17, 1990 Project Manager Alaska Energy Authority J.O. No. 15800.55 701 East Tudor Rd. WP 25A Anchorage, AK 99503 SWEC/AEA/2499 TRANSMISSION SYSTEM CAPABILITIES AND RELIABILITY BRADLEY LAKE HYDROELECTRIC PROJECT In association with the Bradley Lake Project, SWEC and PTI have recently completed several studies involving, in part, the analysis of the existing Kenai to Anchorage transmission systems. These studies involved: (1) Kenai Export Limits, (2) Load Acceptance Analysis and, (3) the ongoing Bradley Lake/Kenai Transmission System Stability Analysis. Although none of these studies were directed specifically at the question of the feasibility of a new transmission line from Kenai to Anchorage, we believe»that»the results of these studies strongly suggest that a_ second AmDDERAABL Ee line from the goigotna.. substation to. the University sation, (plan line being studied by the , ™ S Qeiritie ustified. The primary erred of the new line would be inngaad.reliability.g? servi pal Peninsula and increased. power export capabilities fr aes o Anchorage. As a result of performing the Kenai Export Limits study and other studies we have determined that it is possible to improve the stability of the existing system using stability aids. However, this should not be construed to suggest that a more reliable system will be obtained once the stability aids are installed. The customary economic life for this type of transmission line is between 30 and 40 years. Even though some of the existing line conductors have been restrung, this is an "old" line. A 25 year old single transmission line will still be the same line after the stability aids are installed. The existing line will be stable, but it will still be the cause of relatively frequent customer outages. The number of customer outages can be expected to be over 12 annually. With the existing line and a new line in service, there will be a second line available to maintain the system interconnection if one line trips. Thus there will be a reduction in the frequency of separations of electrical service between Kenai and Anchorage. The sar «stop yo) Nepsten - so 1989 new line will provide an improvement in the supply of reliable power from Kenai to the Anchorage area, and reduce significantly the frequency and duration of Kenai electric customers outages. It would take more study to determine the change in outage duration, but the number of customer outages could be reduced: from over 12 to less than one annually. PTI has advised that "a new line would fix the long and unreliable Soldotna to University line." This existing line has historically experienced outages well above the traditionally accepted design criteria of one event per 100 miles per year. Current transmission planning practice is to determine the most effective transmission upgrade, starting with the least costly approach that meets stability criteria, then building on it or considering other more costly alternatives until a balance is reached between cost (equipment, O&M, losses) and reliability. The recent SWEC/PTI studies have shown that with modern technology, low cost stability aids can provide stable operation right up to (or above) the transmission line thermal limits. Voltage problems, if any, are similarly solvable. Our studies performed to date do not quantitatively address the effect on reliability, the consequences of increasing power transfers, and the associated losses. Even though reliability issues were not studied, there are some obvious benefits to improve the reliability of the interconnection between Soldotna and Anchorage by the installation of a second transmission line between Kenai and Anchorage. It is our understanding that Decision Focus is studying the reliability aspect. We endorse that this study is prudent and necessary. If we can be of further assistance please advise. N.A/ Bishop Deputy Project Manager NAB/JM | 1889+ srofsrer +1989 A BRADLEY LAKE PROJECT SYSTEM CHECKOUT & STARTUP SEQUENCE wOleEs: 1. EVP.S - ELECTRICAL TEST PROCEDURES 2. MIPS - MECHANICAL TES PROCEDURES, 2. TIPS . WIS TRUMENT TEST PROCEDURES 4. PTP'S - PREOPERA TIONAL ‘TEST PROCEDURES §. SIPS - STARTUP TEST PROCEQURES eo /1 pit 3G SE:p t O6. 6B NOL P9SS SEZ 406 NOTLbxOdHOD “T31H EE 'd 1 , ) oa “4 ud ot Tw) \ January 16, 1990 Bradley Lake Hydroelectric Project Gr Proposed Start-Up and Testing Sequence 1991 May 1 * Sept. 1 ** Construction Pre-Operational Start-Up Testing System Operational Commercial Testing Testin (Commissioning) Turnover Test Period Operations (est. 8 weeks) (up to 60 days) ** No later than September 1, 1991 * No earlier than May 1, 1991 @ Contractor System @ CM/Contractor Power Scheduled @ Engineer/Owner Owner/Utilities @ Units Operated on Check-outs Verify Initial Perform Integrated Acceptance Testing and Dispatched on Commercial Basis (meggering, flushing, Operation of System Operations Test Basis etc.) Individual Plant (Turbine/Gen. Unit Systems Testing, On-Line Testing, etc.) @ Operations by @ Operations by Operations by Operations by @ Operations by @ Operations by Contractors Contractors Owner Under Owner/Utilities Owner/Utilities Owner/Utilities Engineer's Direction Contractors Craft @ Final Acceptance @ Project Declared Support on Stand- from Contractors Commercially By Operational at End of Test Period Intermittent On-Line Scheduled Commercial > Test Power Test Power Power Interim Power Project Power > Sales Agreement Sales Agreement Construction Period Warranty Period ¢ - 7 a (1-5 Years) BRADLEY LAKE HYDROELECTRIC PROJECT INTERIM POWER SALES AGREEMENT Proposed Definitions Operational Test Period: A planned functional test period following the final acceptance testing and turn over of the project work from the construction contractors to the owner, wherein project power would be scheduled and dispatched on a test basis to verify and demonstrate that the project is fully operational and capable of generating power on a commercial basis. The operational test period shall begin no earlier than May 1, 1991, and shall end after a period of 60 calendar days or on September 1, 1991, whichever comes first. At the conclusion of the operational test period, and provided the project is capable be generating a minimum of 90 MW, the project shall be declared commercially operational. Interim Power Sales Period: The period prior to the commercial operation date, wherein test power from the project may be available to the purchasers on an intermittent, interruptable or scheduled basis. 9 eer a Revised: January 11, 1990 J.0. No. 15800.52, WP22B RISK ASSESSMENT EVALUATION BRADLEY LAKE HYDROELECTRIC PROJECT Ne Introduction —— Is eis - The Energy Authority wishes to make a risk assessment evaluation for the Bradley Lake Hydroelectric Project, which is scheduled for startup in 1991. This assessment is to be similar to that made by Stone & Webster for five major electric systems (Solomon Gulch, Swan Lake, Terror Lake, Tyee Lake and the Anchorage-Fairbanks Intertie) and is to provide the basic information needed by the Energy Authority in order to include the Bradley Lake Project in its overall risk management program. Stone & Webster Engineering Corporation proposes to perform the work under a separate Work Package for Task 22, Miscellaneous Engineering and Design of our current Bradley Lake professional services contract. We would utilize the services of Stone & Webster Management Consultants, Inc. (SWMCI) for certain parts of the work. SWMCI took the lead in the 1988 risk assessment evaluation of the Energy Authority's five major electric systems. 2. Objective The Bradley Lake risk assessment evaluation will estimate the value, in 1991 dollars, of the losses from insurable risks that could be reasonably expected over the 30 year life of the bonds issued for this project. The risks will include a number of perils which are as follows: Earthquake Flood Wind Fire and Lighting Other Perils - Natural - All others 7845R/0349R/CM -1- The results of the study are intended to be used by the Energy Authority, its financial consultants and the State Division of Risk Management to formulate the optimum overall risk management program. a Approach The approach for the Bradley Lake risk assessment will be similar to that used by Stone & Webster for the Energy Authority's five major electric systems.. The methodology for the Bradley Lake study will differ as listed below from the previous study due to the project not yet being in operation and Stone & Webster's intimate knowledge of the design basis: he Site familiarization visits will not be required. Project cost estimates rather than completion cost reports will be used to develop repair or replacement estimates for damaged structures and equipment. Data obtained in the literature search for the major electric systems evaluation will provide the data base needed for certain parts of the Bradley Lake evaluation. Property insurance evaluation would be done only if the Energy Authority requires more analysis than was provided in Section 5.9 of the major electric systems risk assessment report. Attachment A presents the study methodology in more detail. 4. Work Tasks The work will be subdivided into four tasks as described below. 7845R/0349R/CM -2- Task 1 - Engineering analysis The analysis will estimate the direct annual property damage that could be reasonably expected over the 30 year project bonding period resulting from the following perils: . Earthquake ° Flood e Wind e Fire e Other perils as follows: a. Natural: Ice, hail, subsidence, landslide, avalanche, snow, rain, tsunami, volcanic eruption and lighting. b. Man-made: Pollution, toppling, electrical overload, explosion, sonic boom, chemical leakage, vibration, carelessness, vandalism, sabotage and others. The probability of occurrence of the various perils will be obtained from design criteria or where necessary predicted for use in the risk assessment. Task 2 - Risk Assessment The risk assessment will use appropriate statistical methods to estimate single-year losses from all perils. This calculation will be based on the probability of occurrence of various categories of perils and the loss expected from the occurrences, as determined by the engineering analysis. Probable single-year losses will be totaled over the 30 year period, present worthed, and levelized to produce a value that represents the probable loss that could occur in any one year during the period. The results will be presented in spread sheet format. 7845R/0349R/CM -3- Task 3 - Draft Repo. ~. A comprehensive risk assessment report will be provided setting forth our findings and recommendations. The report will include an executive summary, appendices of mathematical calculations and reference data. Attachment B is the proposed outline. Eight copies of the Draft Report will be provided for Energy Authority's review. Task 4 - Final Report The draft report will be revised to incorporate the Energy Authority's comments. One reproducible original and 10 copies of the final report will be provided. 5. Staffing The proposed Bradley Lake Risk Assessment Study team consists of personnel who worked on the Risk Assessment Evaluation of five major electric systems prepared for the Energy Authority by Stone & Webster in March 1988 plus members of the Bradley Lake design team. This combination of experience will contribute to an efficient and cost effective study effort. The work will be under the general responsibility of Ted Critikos, Bradley Lake Project Manager. Norm Bishop would support requirements for technical information on the project design. Jim Galambas, who led the five major electric system risk assessment evaluation, is the proposed Study Manager. He will be responsible for day-to-day oversight of the work. Other principal contributors and their areas of responsibility are listed below. Name Responsibility *% Leslie A. Buttorff Statistical Analysis we * Kenneth G. Laurence Engineering Analysis we x Charles C. Clark Cost Estimates yw Robert Joyet Geology and Seismicity we = = John B. Yale Electrical and Controls we James B. Nowak Mechanical and Fire Protection % Robert L. Stinnett Structures we Charles F. Giuliani Structures * Major Power Systems Risk Assessment Team we Bradley Lake Design Team 7845R/0349R/CM =4— The proposed organization is shown on Figure 1. As noted above, all of the personnel have experience either on the Energy Authority's major electric systems risk assessment or on the Bradley Lake Project. 6. Schedule The Risk Assessment Evaluation can be completed within twelve weeks after authorization, assuming an allowance of two weeks for review of the draft report by the Energy Authority and discussion of comments. Figure 2 shows the proposed schedule. 7845R/0349R/CM -5- ATTACHMENT A METHODOLOGY The study methodology is designed to develop the value of the reasonably expected annual losses expressed in 1991 dollars. These potential disbursements estimated at low, likely, and high ranges will be based on the results of the peril probability analyses and by the structural, . civil, electrical and mechanical engineering analyses directed to assess property damage loss to the Bradley Lake Project resulting from: 1. Earthquake 2. Flood and Tsunami 3. Wind 4. Fire and Lightning 5. Other Perils - Natural - All Others Analysis will be performed to estimate the total risk to the Energy Authority. Losses will be expressed in 1991 dollars, escalated for each year of the study and discounted to present value utilizing capital budgeting techniques recommended and approved by the Energy Authority. The results will be based upon probability theory and the best information available at the time of the study. Notwithstanding the value of the losses determined by this study, there is always the possibility that a major event will occur sometime within the study period causing catastrophic losses far in excess of those estimated on a probabilistic basis in this study. The step-by-step procedure used to accomplish the study objective is outlined below and further elaborated in the following text. 1. Obtain project data (descriptions, background studies, design criteria, drawings, maps) from SWEC files. 2. Identify all major structures, facilities and equipment, and relevant perils. 7845R/0349R/CM -6- 3. Organize evaluation team effort and assign damage assessment responsibilities. 4. Review project data. 5. Utilize evaluation data from the previous risk assessment of the Energy Authority's five major electric systems for documented damage incidents to hydroelectric facilities from natural and inherent perils and loss statistics and documentation from fire and other perils using power and insurance industry sources. 6. Review and tabulate design criteria for each structure. 7. Assign discrete ranges of peril magnitude and corresponding probability to each structure under consideration. 8. Assess low, likely and high levels of damage for each range of peril magnitude. 9. Estimate dollar cost of each damage level and corresponding downtime for repair or replacement. 10. Tabulate peril magnitudes, probabilities, loss estimates and downtime estimates for each structure. 11. Compute annual probable loss from each peril extended over the study period and present worth to 1991 the low, likely and high loss. The following paragraphs present greater details on the above study procedure outline. Data The project data will be obtained largely from the Stone & Webster's files and will consist mostly of site data, project specifications, drawings, geotechnical studies, design criteria and Federal Energy Regulatory Commission (FERC) License documents. 7845R/0349R/CM Fon Identify Project Facilities The major structures, facilities and equipment for the Bradley Project will be listed and the perils to which the project would be susceptible will be identified in a tabular form. Table 1 is an example of the type of tabulation that will be developed. TABLE 1 Facilities and Perils Structure/ Subsi- Facility/ Earth- Snow/ dence/ Equipment quake Flood Wind Fire Tsunami Avalanche Ice Landslide Other Dam/Spillway Power Intake Power Tunnel Penstock Powerhouse Machinery & Equipment Switchyard & Equipment x x x x xX x Transmission X Line D4 OG OG OO OOS o > * Pe Damage Assessment The assessment of the type and magnitude of damage to each structure will be made by experienced engineers in the geotechnical, civil, structural, electrical or mechanical disciplines, as appropriate. The evaluation of peril magnitude/probabilities for earthquake, flood and tsunami will be developed from the Bradley Lake background studies and design criteria. Other peril magnitude/probabilities will be obtained from published meteorological data, utility forced outage/loss records and insurance industry sources. 7845R/0349R/CM -8- Document Review The engineer responsible for damage assessment of each structure or peril magnitude/probability evaluation will review the appropriate documents and drawings to extract information pertinent to his portion of the work. Evaluation Data A literature search was previously carried out during the five major electric systems risk assessment for documented incidents of damage or failure to dams, powerhouses and associated facilities, their cause and the remedial action taken to return them to service. Evaluation data resulting from this will be used and the documents will be listed in a Bibliography. Fire, lightning and all other perils are not amenable to the kind of probability evaluation which will be applied to the natural perils. Statistical loss data obtained from the literature and from direct contacts with utilities and agencies during the five major electric system's risk assessment will be used for evaluating these perils. Design Criteria Pertinent design criteria for the Bradley Lake Project will be collected and summarized. The assumption will be made that all structures, facilities and equipment have been designed and constructed to the specified criteria, and that the design criteria were appropriately developed. Design criteria reviews will be carried out for the purpose of identifying the peril magnitudes which may be damage causing and to differentiate between these and the threshold magnitudes actually used for design and for which it is assumed no damage will occur. In essence, this assessment will estimate the "residual risk" to the project which has been defined by the United States Bureau of Reclamation (USBR) as - "The risk of adverse consequences that remains after the design loading conditions have been selected, appropriate designs prepared to accommodate the loading conditions, and safety precautions established." 7845R/0349R/CM -9- In addition, the ri 2ws will identify those poten 1 natural hazards for which no design criteria are stated. The need to consider their effects in the assessment will be evaluated and, if so, the magnitudes to be included will be estimated. Design Factors of Safety will be evaluated for applicability to threshold peril magnitude values and for a range of loss values. Damage Losses The risk assessment will adopt a qualitative quasi-engineering approach as distinct from the actuarial approach preferred and most often used by insurance companies. The actuarial approach relies on historical loss data from many events which have occurred and the law of large numbers to evaluate the risk of future loss occurring from specific perils. Unfortunately, we do not have the benefit of extensive historical, documented natural peril loss data for hydroelectric facilities and must utilize engineering judgment in estimating damage loss from perils which have statistically determined probabilities of occurrence in given magnitudes. The repair or replacement cost estimates used in this study will be based on replacement "in kind" costs. The annual value of probable loss is equivalent to the total area under the curve of damage cost versus probability of occurrence for each peril considered. In this approach probable annual loss estimates will be assessed by summing the incremental damage which potentially could occur due to a series of discrete ranges of peril magnitudes. The total single year loss from all perils is obtained by summing the individual peril loss totals. It is assumed that this estimated value of total probable loss is for the entire study period, adjusted for forecasted escalation of labor and materials. The present worth of the estimated probable loss is then computed using an appropriate discount rate to provide the cumulative 1991, present worth of losses that are levelized over the study period so that an "average" loss number can be presented. 7845R/0349R/CM -10- "Average" is in té.uws of a cost that represents tne repair or replacement cost over the study period. A more detailed description of this methodology will be presented in the Risk Assessment Section of the report. 7845R/0349R/CM -l1l1- actachment B REPORT CONTENTS 1.0 Executive Summary 1.1 Introduction 1.2 Engineering Analysis 1.3. Risk Assessment 1.4 Conclusions and Recommendations 2.0 Introduction 2.1 Background 2.2 Objectivity 2.3 Methodology 2.501 Data 3.2 Identify Project Facilities -3.3 Damage Assessment -3.4 Document Review 2 2 2 2.3.5 Literature Search 2.3.6 Other Perils 2.3.7 Design Criteria 2 -3.8 Damage Losses 3.0 Engineering Analysis 3.1 Overview 3.2 Earthquake 3.3 Flood 3.3.1 General 3.3.2 Tsunami Flood 3.3.3 Landslide Induced Wave in Bradley Lake 3.4 Wind 3.4.1 General 3.4.2 Transmission Line 3.5 Other Perils 3.5.1 Internal Failure 3.5.2 Snow/Avalanche 3.5.3 Subsidence, Landslide and Rockfall 3.5.4 Volcanic Eruption 7845R/0349R/CM -12- Attachment B REPORT CONTENTS 3.5.5 Ice 3.5.6 Fire and Lightning 3.6 Cost Estimates 4.0 Risk Assessment 4.1 Data Base 4.2 All Other Perils - Average Number of Occurrences 4.3 Fire and Lightning - Average Number of Occurrences 4.4 Insurance Observations 4.5 Loss Severity 4.6 Fire and Lightning - Losses 4.7 All Other Perils - Losses 4.8 Probability Analyses 4.8.1 Natural Perils 4.8.2 Fire, Lightning and AOP 4.9 Insurance Review 4.9.1 Property Insurance 4.9.2 Boiler and Machinery Insurance 4.9.3 Policy Gaps 5.0 Conclusions and Recommendations 5.1 Conclusions 5.2 Recommendations Exhibits Appendices 7845R/0349R/CM -13- Figure 2 —WEEK | Auth. | | Pa tlo2to3to4testoetisrmt 8 9 tf wy wm tow dt | | | | 1. Engineering Analysis | 2. Risk Assessment | 3. Draft Report ee | Report Review/Discussion See 4. Final Report (eee Progress Report Kf x SCHEDULE RISK ASSESSMENT BRADLEY LAKE HYDROELECTRIC PROJECT 8013R/CM 8013R/CM | | | Alaska Energy| | Authority | IEEE | | WEEEEEULE | | | | Ted Critikos | | Project Manager | | | | | EE Eee | | | James E. Galambas | | Study Manager| HOSES ER EL | | | PERE Eee | | | Leslie A. Buttorff | | Statistical Analysis | | | EEE | SE | | | Kenneth G. Laurence | | Engineering Analysis | Figure 1 JE ECEEEEVEL EE LELEEE || EEE EEE EE | | | | | | | | es | | PECUEELUE EEEEEELEEEY | | nl | | | | | Charles C. Clark | | | M. Gene Yow | | John B. Yale | | | Cost Engineer | | | Geotechnical Engineer | | Electrical Engineer | | eee eee) | eee EEE EEE LT EEE PEELE EEL | | | | PUEEEEEEEEE EEE EEE PE | | James B. Nowak | Mechanical Engineer | Eee | | Robert C. Stinnett | | | Structural Engineer HEEEEEEE ELLER EELS | PROPOSED ORGANIZATION BRADLEY LAKE HYDROELECTRIC PROJECT RISK ASSESSMENT 1001 FourTH AVENUE PLAZA (Szarirst Bipa.), SUITE 8200 SEATTLE, WASHINGTON 98154 (206) 623-471 1225 lorH STREET, N.W. Lrinpsay, HART, NEIL & WEIGLER LAWYERS SvuITE 1800 222 S.W. CoLuMBIA PORTLAND, OREGON 97201-6618 TELEPHONE (503) 226-1101 TELECOPIER (503) 226-0079 TELEX 494-7032 JEFFERSON PLACE 350 N. 9TH, SUITE 400 BorseE, IDAHO 83702 (208) 3936-8844 345 CALIFORNIA STREET Su1TE 200 SuirE 2200 WasutncrTon, D.C. 20036 San FRANCISCO, CALIFORNIA 94104 (202) 303-4460 (415) 984-5858 January 9, 1990 RECEIVED VIA FEDERAL EXPRESS JAN 11 1990 a = Brent Petrie Alaska Energy Authority P.O. Box 190869 Anchorage, Alaska 99519-0869 Dear Brent: Here are the two documents we talked about. I will be talking to Mike about how we wish to proceed with the budget discussion at the BPMC meeting, etc. Very truly yours, (oe Ronald L. Saxton Encls. cv |p a Brea & Ze Ue RLS\der351. ltr A, r Dor Cue Pa vet ins ( G | DAC NON, Alaska Energy Authority MEMORANDUM TO: Bradley Lake aga Wie baw x a Vie ine FROM: Bre s KAS vert Alternate Secretary, PMC DATE: January 3, 1990 SUBJECT: January 18, 1990 Meeting Enclosed for your review is a copy of the draft agenda for the January 18, 1990 meeting of the PMC. Please provide any corrections or additions to Chairman Kelly. Also enclosed for your review is a copy of the draft meeting minutes of the November 30, 1989 meeting. The minutes will be considered at the next meeting. Enclosed for your record is a copy of the executed October 19, 1989 Project Management Committee meeting minutes. Enclosures: as stated i wee Alaska Energy Authority MEMORANDUM TO: Bradley Lake 3 Sie, of ee FROM: BYré ; yee “ Alternate Secretary, PMC DATE: January 3, 1990 SUBJECT: January 18, 1990 Meeting Enclosed for your review is a copy of the draft agenda for the January 18, 1990 meeting of the PMC. Please provide any corrections or additions to Chairman Kelly. Also enclosed for your review is a copy of the draft meeting minutes of the November 30, 1989 meeting. The minutes will be considered at the next meeting. Enclosed for your record is a copy of the executed October 19, 1989 Project Management Committee meeting minutes. Enclosures: as stated a January 3, 1990 * nN 10. 11 12. 13. 14, 15. BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE January 18,1990 AGENDA Chugach Electric Association Anchorage, Alaska . CALL TO ORDER 9:00 a.m. Kelly ROLL CALL PUBLIC COMMENT . MODIFICATION OF AGENDA . APPROVAL OF MINUTES November 30, 1989 BOND FINANCE TEAM REPORT Petrie . TECHNICAL COORDINATING SUBCOMMITTEE REPORT Yerkes INSURANCE SUBCOMMITTEE REPORT Saxton BUDGET AND FINANCE SUBCOMMITTEE REPORT Saxton Presentation of Standardized FY Budget Format Petrie . OPERATING AND DISPATCH AGREEMENT SUBCOMMITTEE REPORT Shira . REVIEW OF PROJECT STATUS Eberle . OLD BUSINESS Report on Surge Tank Analysis SWEC, PTI . NEW BUSINESS Schedule Next Meeting Date, Location, Time COMMUNICATIONS . ADJOURNMENT BPMC Minutes, November 30, 1989 page 1 of 8 BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE NOVEMBER 30, 1989 MINUTES OF MEETING 1. CALL TO ORDER Chairman Kelly called the Bradley Lake Project Management Committee Meeting to order at 9:15 a.m. in the Training Room of Chugach Electric Association, Anchorage. 2. ROLL CALL The roll was called and a quorum established. In attendance were the following representatives: Alaska Energy Authority Brent Petrie - Alternate Chugach Electric Association Tom Lovas - Alternate City of Seward None present. Golden Valley Electric Association Michael Kelly - Representative Homer Electric Association Kent Wick - Representative Sam Matthews - Alternate Matanuska Electric Association Ken Ritchey - Representative Myles Yerkes - Alternate Municipal Light and Power Thomas Stahr - Representative John Cooley - Alternate Others present: Don Shira - Alaska Energy Authority Dave Eberle - Alaska Energy Authority Ron Saxton - PMC Utilities Marcey Rawitscher - Alaska Energy Authority Joe Griffith - Chugach Electric Association Dan Bloomer - Chugach Electric Association Denise Burger - Alaska Energy Authority 3. PUBLIC COMMENT There being no public comment, Chairman Kelly continued on to agenda item 4. BPMC Minutes, November 30, 1989 page 2 of 8 4. MODIFICATION OF AGENDA Mr. Petrie requested an item, 8.d., Stone and Webster Errors and Omission Insurance be added to the agenda. There being no objection, item 8.d. was added to the agenda. 5. APPROVAL OF MINUTES The minutes of the October 19, 1989 meeting were approved as written. 6. BOND FINANCE TEAM REPORT Mr. Petrie reported that closure of the first bond issue was completed. Mr. Petrie explained there is some question of possible tax liability (loss of tax exemption) should the Bradley Lake Project become commercially operational significantly earlier than originally anticipated (September 1991). Mr. Saxton and Ms. Rawitscher further defined the tax issue stating that interest is capitalized up to October 1991 but cannot be capitalized more than a short period of time after commercial operation begins without exceeding the 5 percent limit for non-project costs and threatening the entire transaction. An additional potential problem could also surface if commercial operation began before July 1, 1991, in that the bond resolution would require the final O&M budget to be in place a year earlier (April 1, 1990 rather than April 1, 1991.) Mssrs. Wick and Yerkes explained that the SCADA process and Stability Problem may result in an extended test period, which could delay commercial operation. Mr. Saxton suggested that the test period be defined, which may require an arrangement between the utilities and the Energy Authority. Mr. Griffith suggested discussions with the IRS may be appropriate, however Mr. Petrie commented that such action was premature. Mr. Petrie reiterated Mr. Saxton’s suggestion to establish a definition for "test period" and address arrangements for the use of power generated during the test period. Mr. Petrie further recommended that Bond Counsel, Ron Saxton, Dave Eberle and the Technical Coordinating Subcommittee (TCS) work together to formulate acceptable definitions and solutions to present at the January PMC meeting. Mr. Eberle added it may be necessary to redefine "commercial operation." After further discussion Chairman Kelly summarized by stating the consensus was a preference to stay with the current schedule, with commercial operation after July 1, 1991. Ms. Rawitscher will also be consulting with the tax lawyer on 12/1/89 to determine if it is possible to redefine interest dollars. Mr. Ritchey suggested that the budget process might begin now to avoid a possible bind later. Mr. Petrie commented that a dry run of the budget process has already begun and, if necessary, could be nearing completion by the April 1990 date. Chairman Kelly stated that no action was required at this time and further discussion on the issue should be included in the next PMC meeting after additional information was available. 7. TECHNICAL COORDINATING SUBCOMMITTEE REPORT (TCS) Mr. Yerkes stated that due to a delay by Power Technologies Inc. (PTI) on the Surge Tank Analysis there is no information to report on this item. The TCS is scheduled to meet December 14, 1989 and expects to review the draft report at that time. Mr. Yerkes noted that there was a proposal to reduce the amount of lining in the power tunnel, however upon review by the BPMC Minutes, November 30, 1989 page 3 of 8 contractor, the savings were determined to be insignificant. (Further discussion by Mr. Eberle under item 11.) 8. INSURANCE SUBCOMMITTEE REPORT Mr. Saxton stated the Insurance Subcommittee was directing its emphasis toward preparation of insurance alternatives for the dry run budget. a. Report on Collective Business Interruption Insurance Not addressed at this time. b. Report on Pooled Insurance Coverage Mr. Saxton commented steady progress was being made on the possibility of pooling with the Four Dam Pool. c. Risk Assessment Mr. Petrie stated the Energy Authority was proceeding to use Stone & Webster Engineering Corporation (SWEC) to update estimated damage costs. After discussing the option and added expense (increased amount of time as well as dollars) of hiring an independent consultant, Risk Management agreed that SWEC could best make the required estimates for the necessary “modified risk assessment." The contract does require the retention of an independent consultant for this purpose after project commercial operation begins. Other options for insurance were discussed, Mr. Petrie noting the possibility of self insurance. There being no objection, the PMC supported AEA’s approach to proceed with finalizing a work order for SWEC to perform the task. d. SWEC Errors and Omissions (E&0) Insurance Mr. Petrie stated that E&0 insurance had become an issue the Energy Authority felt should be presented to the PMC for consideration as it would be classified a project cost. Mr. Eberle gave a brief history of the attempts to attain E&O insurance beginning in 1985, stating it was generally not obtainable at all until recently. Mr. Eberle described the proposed coverage as $850,000 for a $10 million policy with $500,000 deductible, pointing out that the deductible was per occurrence and that any problem areas discovered to date would be excluded from coverage. Mr. Eberle noted that given the advance stage of construction, the proposed policy may not be worth the expense. Mr. Eberle suggested self insurance might be an alternative option to consider at this point. Mr. Saxton stated that funds could possibly be made available for this purpose through the issue of additional bonds. After further comments, Mr. Ritchey motioned, seconded by Mr. Stahr, to approve the purchase of E&O insurance. Without further discussion, the motion was defeated in a roll call vote, the vote being as follows: Messrs. Ritchey, Kelly, Highers, Wick, Petrie, Lovas voting NO; Mr. Stahr voting YES; City of Seward representative ABSENT. BPMC Minutes, November 30, 1989 page 4 of 8 9. BUDGET AND FINANCE SUBCOMMITTEE REPORT Mr. Saxton reported the committee has identified a detailed list of the components and sources of the budget, however would like to continue working on it before presenting it to the PMC. Mr. Saxton identified one item for the PMC to consider; the benefit of handling the Chugach and Homer Electric wheeling agreements by the PMC. Chairman Kelly commented there seemed to be notable benefit to design these agreements under the umbrella of the PMC. Mr. Lovas stated that Chugach Electric has already performed a substantial amount of work in regard to the rates and scheduling and would not want to relinquish it to the PMC, rather would prefer to use the PMC to review that work. Mr. Saxton stated it was the committee's intention to finalize the budget items and to present it to the PMC at the January meeting, beginning the gathering of necessary information after that time. 10. OPERATING AND DISPATCH AGREEMENT SUBCOMMITTEE REPORT Mr. Shira distributed copies of minutes for the November 1, 1989 meeting held at the project site (attachment 1). An additional meeting was held November 28, 1989. Mr. Shira stated the committee, working with Frank Moolin & Associates (FMAA) is making good progress on discussions of resolutions for several issues (detailed in the November 1, 1989 meeting minutes.) Chairman Kelly requested continued reports on subcommittee progress at future PMC meetings. Mr. Petrie noted that the Operating and Dispatch Agreement Subcommittee has had need for the services of a consultant. Mr. Petrie suggested that the PMC consider allocating $100,000.00 under Section 31 Costs for continuing consulting needs, as he felt it was to the benefit of the purchasers. Mr. Lovas concurred that some further mechanism should be provided for the committee to retain consultant services to alleviate the necessity for the committee to request funds from the PMC for each task. Mr. Petrie offered the service of AEA as a vehicle for the contracting, as a matter of convenience to the utilities. Chairman Kelly expressed potential concerns he had heard regarding the performance of the current consultant (FMAA). Mr. Shira commented that, in general, FMAA was performing well and recommended FMAA be allowed to continue. Mr. Wick motioned to extend the contract with FMAA for an amount up to $25,000. An amendment offered by Mr. Lovas to increase the amount to $100,000 died for lack of a second. The original motion, having been seconded, passed by a unanimous roll call vote of all those representatives present. Mr. Petrie requested clarification for the source of these dollars, stating preference for Section 31 as utility costs. After some discussion, it was concluded that until the initial O&M agreement has been finalized, such costs should be project costs. Mr. Shira expressed his appreciation for the contribution that Marvin Riddle of GVEA made toward developing the Technical Standards for the Four Dam Pool, noting after the first of the year, work would begin on the Technical Standards for Bradley Lake. 11. REVIEW OF PROJECT STATUS Mr. Eberle reported that the project is about 61 percent complete overall. \ BPMC Minutes, November 30, 1989 page 5 of 8 All tunneling is now complete with the exception of a 15 foot rock plug which will remain in place until the tunnel is ready to be watered-up. The hydrotest of the penstock and manifold is scheduled within the next few days. Mr. Eberle explained the test would be performed to the extreme of 150 percent of working pressure, about 950 psi. Lining has begun in the upper tunnel to be followed by the lower tunnel and vertical shaft this winter. Mr. Eberle added that the powerhouse is enclosed and Unit 2 spiral case for the turbine has been embedded in concrete. Two major shipments for the Turbine/Generator Components are arriving this month. After earlier shipping problems, Mr. Eberle stated Fuji is taking several measures to insure the safe arrival of these shipments. Mr. Eberle suggested the PMC schedule a meeting at the Project site later this winter or early next spring to review the project status. In response to a question on the progress of the transmission line, Mr. Eberle stated currently work is being done on the foundations. Most of the pilings in the Fox River Valley have been driven and the contractor is preparing to move onto the Caribou Lake plateau. Mr. Wick updated the PMC regarding HEA’s progress on their portion of the transmission line. At present, HEA is working south from Bradley Junction to Fritz Creek and has approximately one mile of poles in place on the thirteen mile segment. Mr. Wick noted that mechanical problems with the only helicopter of proper size available in the state may require that the poles be hauled in overland. However, Mr. Wick still anticipates this work will be done by Summer 1990. Mr. Eberle referenced Mr. Yerkes earlier comment on the tunnel lining, explaining the original design was for 100 percent tunnel lining. The better than anticipated geology (rock quality) provided an opportunity to consider deleting some of the liner in hopes of a significant ($2 to $3 million) financial savings. The contractor's estimated cost difference however showed little or no savings due mostly to the added cost of ending and restarting the sections of lining. Mr. Eberle stated the result of the review was to continue with the original plan for full tunnel lining. 12. OLD BUSINESS a. Report By Power Technologies, Inc. (PTI) In reference to the PTI Surge Tank Analysis report previously mentioned by Mr. Yerkes, Mr. Eberle added that he expects to receive the rough draft by December 7, 1989. The TCS will review the draft report at their December 14, 1989 meeting and completion of the final report is anticipated by the next PMC meeting. b. Report on the Four Dam Pool FERC Fee Appeal Mr. Saxton noted that FERC has denied the request by the Alaska Energy Authority and the Four Dam Pool utilities for exemption from annual fees and a motion for reconsideration has been filed. FERC initially denied the request stating that although the Energy Authority was not earning a profit on the sale of the power, it felt the utility companies were. Therefore, the utilities did not meet the required non-profit standard. Mr. Saxton does not expect a positive result on the motion and anticipates the Four Dam Pool to decide next year on BPMC Minutes, November 30, 1989 page 6 of 8 whether or not to continue this process in court. Mr. Saxton noted that if there is a judicial appeal, Bradley Lake may be requested to (or desire to) participate in some way. c. Review of Reimbursable Cost Items by Utilities from Grant Funds or Bond Proceeds Mr. Ritchey motioned that the list of utility costs prepared by Mr. Saxton be released to all PMC members at this time. Mr. Wick seconded the motion. Without discussion, all members present unanimously approved the motion. Prior to passing out the prepared list, Mr. Saxton noted that all costs reported were not entirely comparable. Mr. Saxton reminded the PMC that the purpose for gathering together these (Section 31) costs was to provide the utilities the opportunity for reimbursement from the tax exempt bond proceeds. Mr. Saxton warned the committee that there is current debate on whether there is sufficient money to reimburse all expenses and recommended that as a group the PMC decide which costs are appropriate. Mr. Saxton distributed copies of the list of utility cost items titled "Unreimbursed Bradley Lake Costs, Project Costs" and a second list titled "Section 31 Costs" (Attachment 2) explaining that there were substantial differences of dollar amounts among the utilities. Mr. Saxton noted discrepancies in legal fees were probably due to the amount of legal work each utility required. Mr. Saxton also addressed discrepancies in the TCS cost amounts stating he had received detailed billing from HEA and clarified their cost did not include any staff labor. Responding to a question from Chairman Kelly, Mr. Saxton stated the money for these reimbursements was coming out of the second bond issue and this current review of the costs would help determine how to size it. Again Mr. Saxton expressed doubt that all Section 31 costs could be reimbursed. Ms. Rawitscher requested the committee address the costs of issuance (items Al, A2, and A3 of "Unreimbursed Bradley Lake Costs, Project Costs".) Mr. Petrie motioned, seconded by Mr. Stahr, that the Committee approve the costs of bond issuance, items Al, A2, and A3. Mr. Stahr verified ML&P legal expenses (A2). Mr. Ritchey suggested that the actual cost of in-house legal service be included in this item. There being no objection, the motion passed unanimously by a roll call vote of all those representatives present. Mr. Saxton suggested further discussion of TCS cost items. Mr. Wick clarified HEA’s TCS expenses stating that approximately $18,000 was paid to Black & Veatch for studies on the impact of the Bradley Lake project and approximately $8,000 was paid to Gilbert Commonwealth for evaluation of stability problems. Mr. Wick stated those expenditures were necessary to HEA because of its proximity to the project. Chairman Kelly recommended item AS, TCS expenses, be included in the previous motion approving items Al, A2, A3. There were no objections, however discussion between Mr. Eberle and Mr. Matthews resulted in the determination that the ($18,000) Black & Veatch cost was not a TCS related expense, but rather an O&M cost. Mr. Petrie and Mr. Lovas recommended that the original motion for approval be amended to exclude the ($18,000) Black & Veatch cost. By consensus, the original motion was made to read: Mr. Petrie motioned, seconded by Mr. Stahr, that the committee approve the costs of bond issuance, items Al, A2, A3 and BPMC Minutes, November 30, 1989 page 7 of 8 Ms. the TCS costs, item A5 (having been determined to exclude the Black & Veatch cost.) Further discussion by committee members resulted in the reclassification of HEA’s Black & Veatch cost as a Section 31 cost. Chairman Kelly noted, as a general guideline, future studies to be considered for reimbursement should be approved by the PMC in advance. There was no objection. Section 31 Costs Mr. Stahr motioned, seconded by Mr. Lovas, that the Section 31 costs be approved (as adjusted to include the $18,864.29 HEA Black & Veatch cost previously removed from item A5 of Project Costs.) Concern was expressed by Mr. Ritchey about the negotiation costs. Mr. Saxton stated that 97 percent to 99 percent of the listed amounts were actual attorney fees. Mr. Lovas requested that CEA'’s footnoted cost of $22,700 (in-house attorney fees) be included as part of item Bl, Negotiation Costs. There being no objection or further discussion, the motion was passed unanimously by a roll call vote of all those representatives present. Mr. Petrie requested the Chairman provide a letter to the Energy Authority clarifying the revised numbers for "Section 31 Costs" and "Unreimbursed Bradley Lake Costs, Project Costs." d. Reconsideration of DFI Surge Tank and Intertie Study Costs Mr. Petrie distributed a letter stating the Energy Authority's position after further review of these two items (attachment 3). Mr. Petrie stated the Energy Authority was now agreeable to include the DFI Surge Tank Study (for $10,000) as a project cost. The motion to include the DFI Surge Tank Study was made by Mr. Petrie and having been seconded, passed by a unanimous roll call vote of all those representatives present. It was determined that ARECA should be reimbursed $10,000 for the DFI Surge Tank Study. Rawitscher requested clarification regarding the source of the compensation amount of $600,000 to HEA for the Fritz Creek - Soldotna Transmission Line. Chairman Kelly recommended a review of past meeting minutes to clarify how that cost was intended to be handled. 13. NEW BUSINESS a. Contingency Plan for early Bradley on-line b. Disposition of Bradley Test Power Chairman Kelly noted that these items had been discussed earlier (reference item 6, Bond Finance Team Report.) Mr. Saxton stated his understanding was that the project would not be going on line (as commercially operable) before July 1991. Mr. Eberle added that in the most optimistic scenario, the earliest the project could produce 90 mega watts would be April or May of 1991, however the test period could extend to July 1991. BPMC Minutes, November 30, 1989 page 8 of 8 14. c. Benefits of Coordinated Dispatch Chairman Kelly stated a meeting had taken place between Mr. Brooks, Dr. LeResche, and the railbelt managers at Chugach’s office. The goal being to obtain money through the legislature from the Railbelt Energy Fund, it was determined to send a memorandum of understanding between the Energy Authority and utilities to work toward coordinated dispatch to optimize savings. In addition, it was decided an effort should be made to assure the legislature that this was a one time request for funds. Chairman Kelly stated a third concept discussed was a 2 mil usage toll on the line to produce a repayment stream to the Energy Authority. Mr. Lovas noted that CEA had agreed to prepare the frame work of a wheeling agreement, extension intertie agreement at that meeting. Currently, this work is in the initial draft stage. d. Schedule Next Meeting The next meeting was scheduled for Wednesday, January 17, 1990, 9:00 a.m. in the training room at Chugach Electric. COMMUNICATIONS There being no communications or further comments at this time, Chairman Kelly continued to item 15. 15. ADJOURNMENT All business before the committee being complete, the meeting adjourned at 11:51 a.m. Chairman Kelly Attest: Alaska Energy Authority, Secretary Approved at BPMC meeting held , 1990 ATTACHMENT #1 BRADLEY LAKE OPERATION AND DISPATCH COMMITTEE Meeting Minutes November 1, 1989 A meeting was held November 1 at the Bradley Lake Hydroelectric Project to visit the site and to further discuss the Bradley Lake Allocation and Scheduling Agreement. Present at the meeting were: Don Shira (chairman) - AEA John Cooley - AML&P Dave Fair - CEA Doug Hall - AML&P Mike Hubbard - FMAA Afzal Kahn - AEA Jerry Mackey - CEA Sam Matthews - HEA Marvin Riddle - GVEA John Zidalis - AEA After the site visit was completed, the agreement was discussed. Mike Hubbard gave a quick overview of the agreement that was distributed October 6. Dave Fair stated that CEA's legal department had reviewed the draft and had numerous comments. While he recognized that the agreement was not ready for this type of review, he was concerned by one of Eric Redman's comments that the concepts of rule curves and base energy content curves may be in conflict with the Power Sales Agreement. Dave had not talked to Eric, so he did not know what the exact problem, if any, was. No one else at the meeting understood the concern either, and Dave said he would try and get more details. Everyone recognized that the agreement will need to be reviewed by the attorneys; but in the interest of getting things down on paper, the following was agreed to: + The parties to the agreement should be those of the Power Sales Agreement. * CEA will be scheduling MEA and SES Bradley output, and this should be set forth in the agreement. It was felt that there should be just one rule curve and one energy content curve for all three utilities unless the three utilities agree otherwise. * In the event that a conflict between the Scheduling Agreement and other agreements arises, the language in the other agreements should prevail. ¢ Language on the ability for two or more utilities to coordinate their take of Bradley power should be deleted as it was felt that the language could be confusing. Deletion of the language will not negate any rights of transfer, but will require that a utility laying off its Bradley power still participate fully in the regulation studies and scheduling process. * The requirement that each utility must take its monthly firm energy established during the regulation study was felt to be too restrictive. After some discussion, it was decided that the requirement should be on an annual basis. + Project spill due to transmission limitations should be treated as in the Services Agreement. * During the course of operation, there will be periods of time when some utilities do not want to schedule any Bradley power. The available power could then be utilized by the other utilities as long as their available water is greater than their Energy Content Curve. If there is a conflict for the available excess Capacity, it will be prorated on a Project Percentage Share basis. + Losses over HEA's system were discussed. The PTI studies will be investigated to determine if a loss factor can be utilized that will reflect actual conditions. The PTI load studies should be on a monthly basis, with and without Bradley Lake, and include the second line from Bradley Lake. The consensus of the group was to try and utilize a single loss factor instead of reading meters, etc. * Spinning reserves still need to be addressed in the agreement, but the issue was deferred until efficiency curves and other data was available. Frank Moolin's budget was also discussed. The bulk of the original budget was for Don Gregg's services and that amount for Frank Moolin was for the development of the initial draft. Don Shira indicated that Mike Hubbard had submitted a new budget for continued services through June 1990. Mike told the group that he saw his effort to be fairly concentrated at first but would taper off as the agreement got to the stage where the attorneys worked on it. During that stage, he saw his role as somewhat of a liaison between the technical and legal arenas. He also indicated that there had to be some flexibility on the budget as it was dependent on the length of time all parties could come to an agreement. The utility representatives instructed Don Shira to augment Frank Moolin's budget for the month of November, and the full PMC would take up the long-term budget and source of funding at their next meeting. Mike Hubbard will get the next draft out within a couple weeks; and the next meeting was scheduled for 9:30 a.m., November 28, at AEA. The meeting adjourned at 3:30 p.m. LL aM. Donald L. Shira, Chairman Anchorage Municipal Light & Power 1200 East 1st Avenue Anchorage, Alaska 99501 —, Dear Mr. Gootey: Sohn After our meeting on November 1, 1989 at Bradley Lake, Chugach has expressed some concerns that we are getting ahead of ourselves in the drafting of contract language. Consequently, they have requested that our meeting on November 28, 1969 be devoted to discussing the basic issues to be developed in a contract. Accordingly, Mike Hubbami. dee developed the attached paper which identifies and discusses sc these issues. If you have any questions or comments, please do not hesitate at 261-7261. 1 look forward to meeting with you on November 2 $1 ty. j oor Donald L. Shira, Directer Facilities Operations & Engineering DASi@e J 7038/1018(1) DISTRIBUTION LIST November 13, 1989 7038/1018 Mr. John Cooley Anchorage Municipal Light & Power 1200 East lst Avenue Anchorage, Alaska 99501 Mr. Dave Fair Chugach Electric Association, Inc. P.0. Box 196300 Anchorage, Alaska 99519-6300 Mr. Mike Hubbard Frank Moolin and Associates P.O. Box 7044 Anchorage, Alaska 99501 Mr. Saii Mathews Homer Electric Association, Inc. 3977 Lake Street Homer, Alaska 99603 Mr. Marvin Riddle Golden Valley Electric Association, Inc. P.O. Box 1249 Fairbanks, Alaska 99707 BRADLEY LAKE HYDROELECTRIC PROJECT SCHEDULING AND ALLOCATION AGREEMENT MAJOR ISSUES RULE CURVE/OPERATING CURVE The rule curve and operating curve provide the basis of reservoir management. The rule curve provides assurance that an amount of firm energy can be provided each year during a period of time with runoff conditions similar to those of the critical period. In a multi-year critical period, the reservoir would neither drain or completely refill at the end of the first year. oe The operating curve is based on providing firm energy but attempts to attain a full reservoir at the end of the water year (September 30). It is usually the rule curve in the early part of the water year but is updated as runoff conditions are known with more certainty. The revised operating curve may be above or below the rule curve depending on runoff conditions. In addition to providing a guide for reservoir refill, it also helps to lessen the chance of spill (and therefore provide secondary generation). ISSUE - Should such curves be established and used, or should each utility be allowed to draw its share of water as it sees fit? ADVANCE ENERGY Even if operating curves are utilized, a utility may want to schedule energy that would take it below its operating/rule curve. This deficit could be paid back over any one of numerous time periods. ISSUE - Should a utility be allowed to schedule and take advance energy? If so, over what time period should it be paid back and should there be a maximum deficit? DEFICIT CURTAILMENTS Even if advance energy is not allowed, actual operations may result in deficits. ISSUE - In the event that deficits occur, to what extent should operations be curtailed during the following accounting period? SUBMISSION OF LOADS/COORDINATION OF MAINTENANCE The Regulation Study that establishes firm energy amounts, the rule curve and the operating curve is based in part on power requirements submitted by the utilities. Since the most beneficial use of Bradley Lake will come from coordinating thermal maintenance, the power requirements should be net of some level of expected thermal generation. If too much thermal generation is subtracted, initial simulation runs may show spill, and the optimization process may be lengthy. : ISSUE - What process will minimize the effects on everyone's behalf yet still develop credible results? RESERVES/MINIMUM SCHEDULING During the course of operations, Bradley Lake will undoubtedly be utilized for spinning reserves. However, this may require the operation of two units when one would otherwise suffice. ISSUE - Shall the use of Bradley Lake for spinning reserves be curtailed in any way or should some sort of compensation for any efficiencies be required? HEAD LOSS/EFFICIENCIES As the reservoir elevation is drawn down, generation efficiency decreases. Therefore a utility scheduling generation during periods of high reservoir elevation will obtain more energy per unit of water than a utility scheduling during low reservoir conditions. ISSUE - Should those participants scheduling power during high reservoir conditions be required to compensate the participants scheduling power during low reservoir conditions? LOSSES ON HOMER TRANSMISSION ISSUE - Shall losses over HEA's transmission system be metered or shall a factor (or set of factors) be utilized? What loss factor shall apply to the Bradley - Bradley Junction portion? ATTACHMENT #2 UNREIMBURSED BRADLEY LAKE costs! AS OF NOVEMBER, 19897 PROJECT COSTS? CATEGORY CHUGACH GVEA AEG&T HOMER MEA ML&P aos | __ $$} S E Al FINANCE TEAM ACTIVITIES 0.00 1,396.00 0.00 0.00 0.00 2,057.00 3,453.00 A2 BPMC LEGAL AND FINANCE 16,172.80 8,990.80 13,725.60 a=) Ses 13,778.80 532.00 53,200.00 aS 1989 UTILITY a OPINION LETTERS > OUTSIDE 7,174.01 4,879.00 2,016.65 1,331.84 8,114.00 11,216.05 2,449.50 37,181.05 ms 8 PTI STUDY AS tcc EXPENSES? 0.00 7,629.00 0.00 40,376.87 3,018.00 411.00 51,434.87 A6 INSURAN' STUDI zs a7 STABILITY rl einvile STUDY ag DFI SURGE ,, TANK STUDY A10 OFI IWJERTIE sry 22,894.80 15,742.25 41,708.71 11,132.00 24,994.85 5,449.50 | 145,268.92 UTILITY TOTAL EGW\egw082.doc 1. Only unreimbursed costs are included in this chart. The utilities were instructed not to include those amounts for which they have received reimbursement. 2. The utilities were contacted October 27, 1989 for their final revisions to the chart. Chugach and GVEA responded 11/1, Seward 11/2, Homer and AEG&T 11/14. MEA confirmed in early November that they were still sorting their data. ML&P was contacted by phone on several occasions. The data presented here was given from Claudette Petty, ML&P accountant, and has not been verified by Tom Stahr. 3. These items are treated as "Project" costs, eligible for 50% grant funds. 4. ALL travel and associated costs for members of the Finance Team for all financing trips and meetings. 5. All legal fees and costs for work on finance activities. Includes legal representation through bond sale and preparation of opinion letter for BPMC. 6. ALL legal fees and costs associated with each utility's 1989 opinion of counsel. 7. Chugach has also paid approximately $2,419.20 to $4,200 in “in-house” attorney fees for the preparation of the opinion letter. 8. Final figures not yet available. 9. All travel and other costs associated with meetings of the Technical Coordinating Committee. 10. Studies yet to be completed. Final amount to be forecasted. 11. Final figures not available. 12. Final figures not available. 13. Final figures not available. 14. Final figures not available. EGW\egw082.doc SECTION 31 COSTS 4 r TT eT LL a 1 CATEGORY CHUGACH GVEA AEG&T HOMER MEA ML&P SEWARD TOTAL — ——— $$$ B1 NEGOTIATION costs’ 3 OUTSIDE 285,643.71 391,876.25 0.00 64,535.62 63,097.00} 194,469.00 {11,672.50 |1,011,294.08 B2 BPMC 4 ORGANIZATION 49,131.26 27,313.10 41,696.93 — a 41,858.55 1,616.16 161,616.00 B3 BPMC FUTURE COSTS 6 SMITH BARNEY 16,382.52 9,107.39 13,903.58 — —- 13,957.46 538.89 53,889.84 fa Utility Total | 351,157.49 428,296.74 55,600.51 64,535.62 63,097.00 250,285.01 13,827.55 | 1,226, 799.92 nd a es j \section 31 costs paid from bond proceeds, but not eligible for 50% grant contribution. 2 approval of the Power Sales Agreement, Chugach Services Agreement and Homer Transmission Agreement. 3, ‘Chugach paid approximately $22,700.16 to $39,410.00 for “in-house” attorney fees during the negotiation process. ‘ALL costs including legal fees associated with individual utilities negotiating, amending or obtaining 4epmc costs (including legal costs) for organizing the Committee and conducting Committee meetings and general business. 510 be determined by the Utility Participants and AEA. Scosts associated with the Smith Barney review of financing activities. EGW\egw082.doc ATTACHMENT #3 State of Alaska N Steve Cowper. Governor Alaska Energy Authority A Public Corporation November 30, 1989 Mr. Michael P. Kelly Chairman, Bradley Lake Project Management Committee Golden Valley Electric Association P.O. Box 1249 Fairbanks, AK 99707 Subject: Reconsideration of DFI Surge Tank and DFI Intertie Study Costs Dear Mike: The October 19, 1989 Bradley Lake Project Management Committee (BPMC) considered two actions to categorize certain costs incurred by Decision Focus, Inc. (DFI) for “Surge Tank Analysis" and "Intertie Study Costs" (see pages 7-8 of draft BPMC 10/19/89 minutes) as project costs. The Energy Authority vetoed each action by noting no to each proposal, but was asked to reconsider and respond at the next BPMC meeting. Upon reconsideration of the costs of the DFI "Surge Tank Analysis" of $10,000, we would not object to their inclusion as project costs, since the analysis deals with spinning reserve benefits which were substan- tially directed at operating parameters of Bradley Lake. The study suggested possible benefits that might be realized by varied needle valve opening and closing times on the project turbines. We will not approve DFI Intertie Study as a project cost as the study deals with technical and economic issues substantially beyond the scope of the Bradley Lake Hydroelectric Project, namely a new transmission line between Anchorage and the Kenai Peninsula and a new transmission line between Healy and Fairbanks and the utilization of virtually all existing Railbelt generation resources. The feasibility of these projects depend on dispatch, fuel costs, reliability, and stability of numerous components in the Railbelt energy supply system beyond Bradley Lake. Sincerely, Gurl beet Brent N. Petrie Alaska Energy Authority Alternate Representative Bradley PMC BNP: it — PO.BoxAM Juneau, Alaska 99814 (907) 465-3575 % PO. Box 190869 701 East Tudor Road Anchorage, Alaska 99519-0869 (907) 561-7877 7158/1017(1) BRADLEY PMC (BRADOCT19.CHP) Page 1 of 8 MEETING MINUTES BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE October 19, 1989 1. CALL TO ORDER Chairman Kelly called the Bradley Lake Project Management Committee to order at 9:05 a.m. in the Training Room of Chugach Electric Association in Anchorage, Alaska to conduct the business of the Committee per the agenda and the public notice. 2. ROLL CALL The roll call was taken and a quorum was established. In attendance were the following: Designated Representatives Designated Alternates Representing Brent N. Petrie Alaska Energy Authority Ken Ritchey Myles Yerkes Matanuska Electric Association Dave Highers Tom Lovas Chugach Electric Association Michael Kelly Golden Valley Electric Association Thomas Stahr John Cooley Municipal Light and Power Kent Wick Sam Mathews Homer Electric Association Everett Paul Diener City of Seward Representatives Absent Alternates Absent Representing —ssisiygw Robert E. LeResche Alaska Energy Authority Robert Hansen Golden Valley Electric Association Fred Arvidson City of Seward Others Present Representing Dave Eberie Alaska Energy Authority Ron Saxton PMC Utilities Julie Becker Alaska Energy Authority Marnie Isaacs Alaska Energy Authority Joe Griffith Chugach Electric Association 3. PUBLIC COMMENT There being no public comment, Chairman Kelly proceeded to agenda item 4. BRADLEY PMC (BRADOCT19.CHP) Page 2 of 8 MEETING MINUTES 4. Modification of Agenda Review of Reimbursable Cost Items by the Utilities from Grant Funds or Bond Proceeds was added under item 12., Old Business. 5. APPROVAL OF MINUTES August 21, 1989 The following clarifications were made to the draft August 21, 1989 meeting minutes: "by Eric Wohlforth” was inserted between "It was noted" and "that Section 31 costs..." in the next to the last paragraph on page 4 of 6, and "should" was a fae Sete to" in the one line — ne "Mr. Saxton said that...” on page 6. BOND FINANCE TEAM REPORT Chairman Kelly reported that an enviable interest rate in the investment community had been secured for the Bradley bond financing and that the closing in New York, which some of the members (i.e., Messrs. Highers and Wick) had participated in, had gone smoothly. Mr. Wick said that a blended interest rate of 7.28% had been secured. Chairman Kelly expressed specific appreciation to Ms. Isaacs, Alaska Energy Authority, for her work relative to the investor tour. 7. TECHNICAL COORDINATING SUBCOMMITTEE REPORT a. Report on Four Dam Pool Technical Standards Mr. Yerkes reported that this issue had previously been assigned to the Operating and Dispatch Agreement Subcommittee and that this Subcommittee had requested that Mr. Riddle, GVEA, be the lead person in reviewing the Four Dam Pool technical standards on behalf on the Bradley Lake PMC. b. Report on Stability/Islanded Condition Mr. Yerkes distributed copies of the following three graphs entitled: 1) Costs vs. Needle Opening Time depicting needle opening time in seconds versus order of magnitude costs, 2) Present Value of Bradley Lake Spinning Reserves showing Bradley Lake spinning reserves in MW versus the value in 1989 dollars, and BRADLEY PMC (BRADOCT19.CHP) Page 3 of 8 MEETING MINUTES 3) Present Value of an Optimized Coordination System demonstrating Bradley Lake spinning reserves in MW versus value in 1989 dollars. Discussion on Graph 1; Costs Vs. Needle Opening Time Mr. Yerkes reported that the Technical Coordinating Subcommittee met on October 5, 1989 and that Stone and Webster Engineering Corporation (SWEC) made a presentation to the Subcommittee on surge tanks at that time. Mr. Yerkes noted that the presentation by SWEC was summarized on the hand-out entitled Costs Vs. Needle Opening Time, which depicts costs ranging from $32 Million for a pressurized surge tank to $15 Million for a surge tank in the power tunnel with corresponding governor needle opening times in terms of spinning reserves ranging from 4 to 23 seconds. Mr. Eberle noted that the needle opening time of 4 seconds on the graph might be misleading in that a needle opening time of 4 seconds was in the realm of what had never been done before for units of this size (10 seconds has been achieved). It was noted that without a surge tank, there would be a 90 second needle opening time from no load to full load. Mr. Yerkes added that Power Technologies Incorporated (PTT) has begun base runs of a system model with and without a surge tank to see how real performance would be affected and that the results of their analysis showing costs and benefits are scheduled to be available in 2-3 weeks (i.e., around mid November, 1989). Mr. Eberle was asked, if the decision was made to install a surge tank, when would he recommend installation. Mr. Eberle responded that he would recommend doing it after construction was completed, since it would take a year for the design work and it would be too expensive to maintain existing construction contracts during this year delay. Mr. Eberle said that during a retrofit with surge tanks, the project would need to be shut down; however, this would probably be scheduled during summer months when the current plan by the utilities calls to use the project as little as possible. Mr. Saxton said that if a surge tank was installed after completion of the project work, it might be considered as optional project work, which would mean that only those parties who voted in favor of it would share the cost and benefits (reference Section 4.d of Power Sales Agreement). Discussion on Graph 2; Present Value of Bradley Lake Spinning Reserves Mr. Yerkes said that DFI, who is already doing the Intertie Study, had been asked to do a study of the possible benefits of Bradley Lake spinning reserves, and that the benefits ($50 to $100 Million) were reflected on Graph 2, Present Value of Bradley Lake Spinning Reserves. Discussion on Graph 3; Present Value of an Optimized Coordination System Mr. Yerkes said that the generation schedules for a typical year were used to develop Graph 3; Present Value of an Optimized Coordination System. It was noted that the value of an optimized coordinated system was substantial, ranging from $70 to $90 Million. General Surge Tank Discussion Mr. Stahr said that it was his understanding, although he hadn’t actually reviewed it, that spinning reserve values were part of the project benefits or deliverables in the Bradley Lake License Application. Mr. Stahr said that there were literally hundreds of millions of dollars of potential benefits in spinning reserve and that he thought that those benefits were what the utilities had originally agreed to. Mr. Eberle noted that to date no one, including Decision Focus, has defined spinning reserve. BRADLEY PMC (BRADOCT19.CHP) Page 4 of 8 MEETING MINUTES Mr. Eberle explained that the PTI studies presently being performed are focusing on the ability of Bradley Lake with and without a surge tank to prevent load shedding due to frequency delay in the 1 to 3 second time frame. Mr. Stahr stated that spinning reserve values are not simply limited to avoiding load shedding, and there is significant value for spinning reserves beyond the initial response time. Mr. Eberle asked, if Bradley can’t respond quickly enough to avoid loss of load and prevent collapse of the system, does it really matter if the generation comes on, for instance, in 30 seconds or 60 seconds and how do you differentiate the relative benefits of faster response times once you are beyond the ability to avoid load shedding. Mr. Saxton said that two issues are raised by the surge tank issue: 1) _ the timing of any financing, particularly more favorable tax exempt financing, and 2) how does it affect the date at which the utilities accept the project as commercially operable. Chairman Kelly asked the utilities whether or not they felt the surge tank issue would affect the date at which they accepted the project as commercially operable. The consensus was that they wanted to keep the project on its current schedule, while concurrently investigating any benefits of a surge tank and that this would be a separate issue which would not affect acceptance of the project as commercially operable. The consensus was that PTI be invited to the next PMC meeting to review this issue. Mr. Yerkes asked for an Energy Authority commitment to possibly expand the scope of the current review of this issue; Mr. Eberle concurred however he said that PTI might not be the appropriate party to do so. SCADA/Decknet Discussion Mr. Yerkes said that the SCADA supplier had originally quoted $20,000 for a Decknet option; however, following review and clarification of the requirements by the Technical Coordinating Subcommittee, the system is now being quoted at $200,000. It was noted that control of the plant would be exercised through CEA’s RTU and that this Decknet system is informational. It was further noted that the utilities would be able to receive this information through CEA; however, some of the members had expressed the preference for receiving the information directly through a system such as Decknet. The consensus was that direct access was preferred if the cost was $20,000; however, not at the $200,000 quote. Stability Mr. Yerkes reported that Southern Engineers had said that a second transmission line was necessary for reliability/stability; however, that it was the Energy Authority's position based upon PTI’s work under Phase II that additions to the existing line could provide this reliability. Mr. Yerkes said that $7 Million had been budgeted in the Bradley Lake project budget for this "band-aid fix" and that PTI had been working for the Energy Authority on this issue. Mr. Yerkes said that an additional intertie would require additional funding from the Railbelt Energy Fund. Mr. Yerkes said that the static var system proposed as the stability fix would not be on-line until one year after commercial operation and that this might result in some operational restriction on peak capacity during that year. 8. INSURANCE SUBCOMMITTEE REPORT a. Report on Collective Business Interruption Insurance Mr. Saxton reported that the Insurance Subcommittee will meet to consider collective business interruption insurance in November. BRADLEY PMC (BRADOCT19.CHP) Page S of 8 MEETING MINUTES b. Report on Pooled Insurance Coverage Mr. Saxton said that pooled insurance coverage with the Alaska Intertie and/or Four Dam Pool is being analyzed. Mr. Saxton said that the Alaska Intertie insurance issue, which allows self insurance in the Amendment, must be resolved before the Committee can move ahead with the Bradley insurance issue. There was no objection expressed, therefore, to considering the Alaska Intertie insurance issue before this group. Mr. Saxton noted that during a recent meeting with REA, the attorney for REA said that REA will never accept REA cooperatives being self insured or contracting with others who are self-insured because they do not feel it provides enough security to REA securities. Mr. Saxton said that REA had been provided with an unexecuted copy of the revised Alaska Intertie Insurance Agreement, as the original document is currently being circulated for signature. Mr. Saxton was asked to check on whether Fairbanks Municipal Utility System was going to sign the Amendment. Mr. Saxton said that once the document was signed, it must be formally filed with REA. c. Report on Risk Assessment Mr. Saxton reported that the Insurance Subcommittee will meet to consider this issue in November. 9. BUDGET AND FINANCE SUBCOMMITTEE REPORT Mr. Saxton said that per the terms of the Power Sales Agreement, the first Bradley Lake annual budget is to be completed by April 1, 1991. Mr. Saxton with the Energy Authority said that development of the initial budget may be cumbersome and recommended that the PMC do a "dry run" budget during the beginning of 1990. It was noted that this might require a full day PMC meeting in order to price items out. No objection was expressed to this recommendation and Mr. Petrie said that the Energy Authority would develop and circulate standardized categories of expenses/accounts, in order for the utilities budgets to be consistent and in the same format. 10. OPERATING AND DISPATCH AGREEMENT SUBCOMMITTEE REPORT Mr. Cooley distributed the September 27, 1989 Bradley Lake Operating and Dispatch Committee meeting minutes. Mr. Cooley reported that Mr. Gregg, a consultant, had been working on reservoir management and scheduling problems and that Mr. Hubbard had subsequently developed the first draft of the Bradley Lake Allocation and Scheduling Agreement. Mr. Cooley said that the agreement allows each utility to have its own flexibility and that it has a rule curve, subdivided to each utility's proceeding year. Mr. Cooley said that the allocation of losses on the HEA system remains to be resolved and that Mr. Gregg is no longer available as a consultant due to health considerations. The Bradley Lake Operation and Dispatch Subcommittee may require an additional consultant to complete this work. 11. REVIEW OF PROJECT STATUS Mr. Eberle reported that excavation of the lower tunnel was completed September 5, 1989. The vertical shaft is 60% complete, with completion scheduled for the end of October, 1989 and lining scheduled to begin November, 1989. The dam, including the face, has been completed. The spillway is 40% complete. The roof has been placed on the powerhouse. Construction of the transmission line is underway and should be completed by December of 1990. Mr. Eberle said that the critical areas of the penstock are being repaired and that a study of the non-critical areas showed that these areas should not go into fatigue. The entire penstock and manifold will be hydrostatically tested. Mr. Eberle reported that assuming that no problems are revealed in the hydrostat testing scheduled for November, the project is projected to be on-line 4-6 months early. Mr. Eberle was asked what the worst case impact to the project schedule would be if problems are revealed BRADLEY PMC (BRADOCT19.CHP) Page 6 of 8 MEETING MINUTES in penstock welding. Mr. Eberle responded that under a worst case scenario a new penstock would take one year; however, since this item is not on the critical path and the project is otherwise 6 months ahead of schedule, the project would be delayed 6 months. Mr. Eberle reported that the camp population is approximately 260 and that the winter low population will be approximately 180. Mr. Wick reported that the HEA Board of Directors had previously agreed to split the lower portion of the transmission line work between Irby and HEA. The HEA portion, Bradley junction south, will commence this winter, with completion scheduled during the early portion of next summer (June-July, 1990). The Irby portion is scheduled for the winter of 1990-91. 12. OLD BUSINESS Review of Reimbursable Cost Items by the Utilities by Grant or Bond Proceeds Mr. Saxton reviewed that the PMC had previously adopted categories of costs from bond proceeds and grant funds (reference page 3 of 6 of August 21, 1989 meeting minutes). Mr. Saxton said that the problem at this time is that the utilities have not accounted for these costs in terms of the reimbursement categories. Mr. Saxton said that the PMC needs to consider the following three issues: 1) Identification of costs incurred by the utilities in terms of the reimbursement categories, 2) Estimates of future costs and tracking of such costs in terms of these categories, and 3) Consideration of the process for approval of such costs. Mr. Saxton said that Ms. Rawitscher, Alaska Energy Authority Finance Manager, had directed the trustee to hold some of the bond proceeds for reimbursement of costs incurred by the utilities and that reimbursement could proceed as soon as invoices had been approved. Mr. Saxton noted that reimbursement of some of the costs may be delayed until the final bond issuance. Project Costs Mr. Saxton noted that the PMC had previously agreed that the following costs be treated as Project Costs (i.e., eligible for 50% grant funds), and asked that the utilities provide amounts expended for each of these items, with the understanding that back-up documentation with a fair degree of accuracy should be available: 1) Finance Team Costs (expenses) a. This would include direct out-of-pocket travel costs to New York for the trip in 1988. Mr. Saxton said that all of these costs have probably been reimbursed previously, and b. Out-of-pocket expenses for the trip to New York for the October 5, 1989 closing, which should be directly submitted to the Alaska Energy Authority, and c. Direct out-of-pocket expenses for Finance Team meetings in Seattle and Anchorage during the past year; documentation for these costs should be submitted to Mr. Saxton. 2) Legal costs for finance, which Mr. Saxton already has. BRADLEY PMC (BRADOCT19.CHP) Page 7 of 8 MEETING MINUTES 3) Legal costs for individual 1989 utility opinion letters (probably August, 1989 costs). 4) PTI Study Costs, including utility out-of-pocket expenses (i.c., travel, hotel, meals) for review of this study which was coordinated through the Technical Coordinating Subcommittee. It was noted that the members had previously agreed not to include overhead costs, which would be individually absorbed by the utilities. 5) Technical Coordinating Subcommittee meeting expenses (exclusive of labor) from inception to date plus estimates of future costs. 6) Insurance Studies; estimate by Messrs. Petrie and Saxton of Probable Loss Analysis, which has not yet been done. 7) SCI Study; direct expenses associated with utility representatives’ participation. 8) Allocation Study. Mr. Saxton summarized that the utilities needed to submit their costs for items 1,4,5,7, and 8. Discussion ensued regarding categorization of the cost of the surge tank analysis by DFI in the amount of $10,000. The consensus was that Mr. Saxton would research this item for consideration at the next meeting. Section 31 Costs Mr. Saxton said that the following Section 31 costs (possibly paid from bond proceeds, but not eligible for 50% grant contribution) had been agreed to: 9) Negotiating Costs for the Power Sales Agreement, Services Agreement and Homer Agreement. Mr. Saxton said that it had been agreed that this item included work done by attorneys/other outside consultants, as well as in-house travel, lodging and meals. It had previously been agreed that staff time was not eligible for reimbursement. Mr. Saxton said that a policy decision regarding whether or not the costs for the in- house attorneys utilized by CEA and ML&P would be treated as outside costs. Mr. Saxton suggested that they should be; however, no action was taken at this time. Mr. Saxton said that the intent is to try to pay some of these costs from the short- term bond funds; however, it is likely that these costs will not be reimbursed until late Spring of 1990. 10) Bradley PMC Costs, including out-of-pocket expenses, such as Committee member air- fare. The members agreed that Mr. Saxton should share the numbers for expenses submitted with the other members in order to avoid internal inequity. Other Costs = Smith- — hoe Mr. ro = that the deer aaeaey would not _— to this i item as a project cost. Mt 12) DFI Intertie (Decision Focus, $250,000). Mr. Petrie motioned that the DFI Intertie cost be treated as a Section 31 cost. The motion died for lack of a second. (see below for subsequent action). BRADLEY PMC (BRADOCT19.CHP) Page 8 of 8 MEETING MINUTES Mr. Saxton asked the members to identify any other expenses or costs to be incurred prior to commercial operation for classification. No additional items were identified at this time. Chairman Kelly said that the Budget and Finance Subcommittee should come up with a standard approach for members to use in maintaining their costs in these classifications. The consensus was that the General Managers were to review the costs identified by their accounting staffs and telecopy them to Mr. Saxton. Mr. Saxton was asked to address any questions raised by his review of the costs submitted to the individual utilities, prior to distributing the costs to the PMC for consideration (approval) at the next meeting. 13. NEW BUSINESS a. Report by Power Technologies, Inc. This item was deferred to the next meeting with the understanding that Messrs. Yerkes and Eberle would coordinate this and consider the appropriateness of other reports (i.e., by SWEC). b. Schedule Next Meeting The next meeting was scheduled for November 30, 1989 beginning at 9:00 a.m. in the Training Room of Chugach Electric Association. 14. COMMUNICATIONS Mr. Saxton reported that the Four Dam Pool appeal of Federal Energy Regulatory Commission fees was scheduled for action by FERC on October 25, 1989 and that he would provide a report on this at the next PMC meeting. 15. ADJOURNMENT ‘ee, the PMC adjourned at 12 noon.