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HomeMy WebLinkAboutBradley Lake PMC Meeting Teleconference Tuesday 03-20-2001Shauna Dean From: Dianne Hillemeyer [Dianne_Hillemeyer@chugachelectric.com] Sent: Thursday, May 25, 2000 3:05 PM To: sdean@aidea.org Subject: Re: Hi, Shauna - | guess Gene talked to most of the guys and they were okay with 6/20 (and now Brian will be here). So would you like to notice the meeting for 6/20 at 10:00 a.m. in Chugach's training room? Thanks much f ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY {= ALASKA @@E ~=ENERGY AUTHORITY 480 WEST TUDOR ANCHORAGE, ALASKA 99503 907 / 561-8050 FAX 907 /561-8998 TOOK KIRK KK KKK KKK TOTAL 355 PAGES: 2 0100000000000 10010101 010110101 000000000 OOOO COCO OK k P, O01 x k TRANSACTION REPORT k x a JUN-09-00 FRI 03:13 PH x x x k SEND (M) : x k DATE START — RECEIVER TX TIME PAGES TYPE NOTE Mt DP x ._ EE ee | x JUN-09 03:13 PM 92798170 35” 2 “SEND (M) OK 124 ' X X X x XK x X X Xx ALASKA INDUSTRIAL DEVELOPMENT > AND EXPORT AUTHORITY a> ALASKA @m™ ENERGY AUTHORITY eee $$$ —$— LL A 480 WEST TUDOR ANCHORAGE, ALASKA 99503 907 / 269-3000 FAX 907 / 269-3044 June 9, 2000 FAXED: 06/09/00 2 PAGES Anchorage Daily News 1001 Northway Drive Anchorage, Alaska 99508 ATTENTION: Ms. Eva Alexie Legal Classified Subject: Public Notice Account # ALASO709 Enclosed is an advertisement for the Alaska Energy Authority, which is to be published under “PUBLIC NOTICE” in the Legal Classified section in column format. This notice needs to be published for one day: Monday, June 12, 2000. r ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY / = ALASKA @™ =ENERGY AUTHORITY 480 WEST TUDOR ANCHORAGE, ALASKA 99503 907 / 269-3000 FAX 907 / 269-3044 June 9, 2000 FAXED: 06/09/00 2 PAGES Anchorage Daily News 1001 Northway Drive Anchorage, Alaska 99508 ATTENTION: Ms. Eva Alexie Legal Classified Subject: Public Notice Account # ALASO709 Enclosed is an advertisement for the Alaska Energy Authority, which is to be published under “PUBLIC NOTICE” in the Legal Classified section in column format. This notice needs to be published for one day: Monday, June 12, 2000. After the publication date, please provide an Affidavit of Publication. If you have any questions, please do not hesitate to call me. Thank you, hum Dew Shauna Dean Admin. Assistant Attachment Shauna Dean From: Shauna Dean Sent: Friday, June 09, 2000 3:13 PM To: Cindy Crago Subject: Ad for Journal/Web Page Importance: High Admin Journal Ad.doc Here is an ad for the Admin Journal/Web Page. Title: Bradley Lake Project Management Committee Meeting Archive Date: June 19, 2000 Category: Committee Meeting Location: Anchorage, Alaska Bradley Lake Proof of Concept/Design & Studies ID | Task Name Duration Start Finish Jun Jul Aug | Sep | Oct | Nov | Dec aa Feb | Mar | Apr | May | Jun Jul Aug _| Sep | Oct_| Nov 1 Bradley Proof of Concept/Design & Studies 367 days Thu 07/06/00 Fri 11/30/01 ae a 2 Design & Implementation of Interim Instability Mitigati 8wks Thu07/06/00 Wed 08/30/00 Project Team,Dispatchers 3 Enhance/Harden Instrumentation System 6wks Thu 08/31/00 Wed 10/11/00 R. Johnson em 4 Governor Control Algorithm Design 25 wks Thu 10/12/00 Wed 04/04/01 Project Team a 5 Develop Functional Specification 5wks Thu 04/05/01 Wed 05/09/01 Consultant 6 Identify Source of Turbine Pit Mitigation Devices 12 wks Fri09/01/00 = Thu 11/23/00 Consultant 7 Design Turnine Pit Mitigation Devices 24 wks Fri 11/24/00 = Thu 05/10/01 Consultant iia “3 | Railbelt Peak Mode Droop Coordination Design 4 wks Tue 08/01/00 Mon 08/28/00 Machine Rating Subcommittee,Consultant 9 Integrated Exciter Power Sys Stabilizer Design 3wks Wed 11/01/00 Tue 11/21/00 Consultant 10 Design a Dual Rate Servo Motor System 25 wks Mon 06/11/01 Fri 11/30/01 Consultant Li 11 Design External Intelligence & SCADA Interface 12wks Tue 05/01/01 Mon 07/23/01 Consultant - SCADA Analyst 12 Design Condense to Generate Logic 8wks Tue 07/24/01 Mon 09/17/01 Consultant - SCADA Analyst ciate 13 Design of POD Installation of Soldotna Bradley Lines 12wks Thu 03/01/01 Wed 05/23/01 ABB 14 Develop Project Implementation & Const Plan 2wks Thu 11/01/01 Wed 11/14/01 Consultant 15 Design Fiber Optic Shaft Speed Transducer 8wks Wed 11/15/00 Tue 01/09/01 Consultant oo 16 Review & Testing of Manufacturer Supplied Models 367 days Thu 07/06/00 Fri 11/30/01 Consuitant,Project Team | - Task Milestone r Rolled Up Split ee External Tasks Ree Project: Bradley Laka Proof ofConce | gp eee Summary Qa ole Up Milestone Project Summary Progress Rolled Up Task Rolled Up Progress Page 1 Design Condense to Generate Logic $ 33,600 Design logic to issue a setpoint to the governor when tripped from condense to generate an under frequency event. 2 month @ $105/hr Develop Project Implementation and Construction Plan $ 8,400 2 weeks @ $105/hr Page 15 of 15 Enhance and Harden Instrumentation System Upgrade I/O & triggering capability $ 40,200 COM Port & Software 15,000 Materials 25,200 Labor Duration 6 weeks Review and testing of Manufacturer Supplied Models $ 40,000 Review and testing of the vendor models supplied In response to the RFQ Duration 2 months 125/hr Design of POD Installation of Soldotna Bradley Lines $ 70,000 Quote from ABB — $10,000 Duration 3 months Integrated Exciter Power System Stabilizer Design $ 15,000 Evaluate replacement of Fuji Exciter/PTI PSS with Integrated Exciter/PSS Duration 3 weeks _$125/hr Railbelt Peak Mode Droop Coordination Design $ 20,000 Quantify peak-mode capacity contribution and duration for all Railbelt combustion turbines and design a coordinated Droop setting plan to maximize this value. Duration 1 month $125/ hr Design a Dual Rate Servo Motor System $125,000 Design dual rate hydraulic servo motor system for Needle operation. The system will provide faster speeds on opening than on closing. Duration 6 months_$125/hr Design and Implementation of Interim Instability Mitigation $ 33,600 Design and implement jet edge trigger to SCADA and SCADA response. Implement a Dispatch unit trip” hot button”. Optimize gains and develop interim operating guideline for the power system dispatchers . 2 month @ $10S5hr Page 14 of 15 Appendix A Rates used in these estimates are $125/hour for consultants and $105/hour for utility employees. Shaft Speed Transducer Design fiber-optic shaft speed transducer $ 80,000 Consultant Duration 2 months $125/hr Governor Control Algorithm Design $105,000 Performed primarily by 50% utility personnel 50% consultant Includes: e Efficiency and support needle mode. e Deflector control with droop and speed reference feedback. e Elimination of MSR chatter. e Provisions for real time gain optimization. Duration — 6 months $105/hr Develop a Functional Specification $ 25,000 Develop a functional specification from the Governor control algorithm design. Consultant w/Utility Review Duration 5 weeks 200 MH @ 125/m Design of External Intelligence and SCADA Interface $ 50,400 Design of a PLC or microprocessor based system that monitors Power System quantities, unit status, import/export values, unit Loading, system frequency etc. and can modify governor gains And issue instructions to master station equipment. Duration 3 months $105/hr Identify the Source of Turbine PIT Turbulence 5 days on site testing 2000/day 10,000 $ 20,000 Report 80 hrs @ 125/hr 10,000 $ 10,000 $ 30,000 Duration 3 months Design Turbine Pit Mitigation Devices $120,000 6 months @ $125/hr Page 13 of 15 Interim Mitigation In the interim between today and completion of the proposed enhancement the following measures will be taken to minimize the likelihood of additional unstable oscillations. Short Term i Deflector derivative gains set to zero in deflector. 2 Unit operated in inflexible AGC mode. a: Alarm generated when deflector is suspected of being in stream. 4. Dispatchers 1" priory response to alarm, is to lower unit output and system frequency if necessary at the expense of load shed. Ds Man the Bradley Lake Control Room whenever units are loaded above 30 MW. 6. Develop Interim Dispatch Operating Guide Long Term ITs Install unit trip hot button in Dispatch 2: Automate frequency reduction algorithm 8: Telemeter jet edge trigger to Dispatch 4. Optimize Gains to minimize instability Page 12 of 15 ¢ Where appropriate models will be required for each design. These models will be critiqued by the team for validity and practicality. Each model will be tested against the power system utilizing MATLAB and PSS/E. e Where appropriate, designs will be translated into functional specifications with typical design drawings attached. e Requests for quotation will be issued to appropriate vendors. ¢ RFQs will require the vendor to respond with control design, vendor model and quotation. e These vendor models will be critiqued and tested against the power system. e Upon completion of testing and cost benefit analysis the team will return to the BPMC to authorize funding for construction. e All final designs will be provided with an appropriate test plan. These test plans will provide measurable performance criteria to which financial penalties will be attached. Penalties will be implemented if enhancements fail to meet specification. This process provides the utilities with the opportunity to review, comment on, and test designs prior to construction. If modeling provides unacceptable results, or the cost- benefit ratio of the enhancement is inadequate this process provides an opportunity for the BPMC to cancel construction funding. The Project Team recommends the Operations and Dispatch Subcommittee, and subsequently the Bradley Lake Project Management Committee, authorize funding in the amount of $796,200 to complete proof of concept design and testing on the following enhancements to the Bradley lake Project. Further detail on these enhancements can be found in Appendix A. e Design Fiberoptic Shaft Speed Transducer $ 80,000 e¢ Governor control algorithm design $105,000 e Develop functional specification of design $ 25,000 e Design external intelligence and SCADA interface $ 50,400 e Identify the nature of the Turbine Pit turbulence $ 30,000 e Design Turbine Pit turbulence mitigation $120,000 e Enhance and harden Instrumentation System $ 40,200 e Review and testing of vendor supplied models $ 40,000 e Design Power Oscillation Damper for Soldotna-Bradley Lines $ 70,000 e Evaluate replacement of Exciter and PSS with integrated model $ 15,000 e Railbelt Peak Mode droop coordination design $ 20,000 e Design dual rate Hydraulic Servo motor system $125,000 e Design and implementation of interim instability mitigation $ 33,600 e Design condense to generate logic and SCADA interface $ 33,600 e Develop an project implementation and construction plan $ 8,400 Total Funding Requirement: $796,200 Page 11 of 15 can virtually eliminate instability and potentially provide the current 27 MW of non-responsive spin. 5: In addition to number two, install dual-rate hydraulic servomotors and increased needle speeds. Implement a dual mode algorithm, “efficiency” verses “system support”. Efficiency mode would maintain needle equalization and System Support mode would trip to six needles open as fast as possible. The economic analysis of these alternatives was performed independently by John Cooley of Chugach and Bob Price of AML&P utilizing each companies respective production costing model. Each analyst made his own assumptions as to how the system would operate under each alternative. In this way we were able to demonstrate qualitatively the magnitude of the variation in cost/benefit depending on system operating assumptions. System operating assumptions are assumptions such as: When and if Healy Clean Coal is returned to service, how much silos GVEA arms, or when Nikiski Cogen becomes base loaded etc. These costs and benefits are strictly operating costs, fuel and O & M. No value was placed on spilled water, increased reliability, reduction in wear & tear or potential catastrophic damage resulting from instability. Alternative one as compared to current operating practice costs the interconnection between $689,000 & $1,200,000 annually. Alternative two, utility costs remain the same as today. Alternative three shows an annual savings of $1,400,000 to $2,000,000 over alternative one and $711,000 - $800,000 over current operating practice. We have estimated that a complete rework of the Governor electronics, hydraulics, and needle orifices would not cost no more than 5 million dollars. Assuming the worst case benefit of $711,000 annually and 5 million dollar investment the pay back period on this investment would be approximately 7 years, well short of the remaining life of the Bradley plant. Recommendations The Project team recommends completing proof of concept designs and studies for the enhancements required to achieve alternative three. We propose that upon completion of these designs, we request firm quotations from vendors on each enhancement. At that time, we will perform a more detailed cost benefit analysis of each alternative. This will allow the BPMC to selectively fund enhancements in order to maximize benefits. We propose the following process to insure that the proof of concept designs are valid. Page 10 of 15 The question was posed: Why is Bradley’s control response significantly slower than predicted in the 1990 Load Acceptance study and final Bradley Operating Studies? What is Bradley’s maximum response rate? Answering the second question first, for the current governor the maximum obtainable open/close rate via AGC is approximately 8 minutes. Under some conditions the opening rate can be as slow as 25 minutes. Why the slow response? The answer lies in the needle scheduling logic of the Woodward 501 Governor. The governor is designed to minimize water usage and therefore schedules the six Bradley needles in 3 pairs. The needles transition from 2 needles to 4 @ 18 MW & from 4 needles to 6 @ 36 MW. At each transition point needle equalization logic takes control. For example, at the 2-4-needle transition the two fully open needles transition closed, while the 2 fully closed needles transition open, until the needle opening for all needles is equal. No additional power output is generated during the equalization period. The slow control response is exacerbated by the inability of speed error to schedule needle transitions. Needle transitions can only be scheduled by needle speed reference changes initiated by AGC or the plant operator. The gist of this is that, the capacity that the unit can provide in droop response is limited to the difference between its energy output and the next needle transition. For example, a single unit loaded at 16 MW can provide 2 MW ( 18MW-16MW) of response without AGC or operator intervention. In summary the control response problem is a function if the Woodward 501 control algorithms. These control algorithms are the first barrier to improved control response. The next barrier is the 90 sec needles and closely interrelated to that is the tunnel hydraulics. Control response can be improved; however, not with the current version governor electronics. Alternatives The project team has settled on three potential alternatives to provide the O&D and subsequently the BPMC with cost benefit evaluation information. The alternatives are: A. Do nothing to the plant and adjust operating guidelines to minimize the potential of instability This option provides no spinning reserve individual unit out limits of 30 MW with the total plant out put limited to 60 MW. 2. Replace Governor electronics to reduce time delays. If possible, dampen turbine PIT noise, add external intelligence to optimize gains based on power system conditions. Successful implementation of these concepts Page 9 of 15 speed, compared to desired speed, is translated into a new physical deflector position. The gain settings within the controller aggravate this condition. The overall delay is approximately 370 milliseconds. To put this in context, a controller delayed by 370 milliseconds is controlling oscillations with periods ranging from 560 to 750 milliseconds. Components that contribute to this delay are: 1. Speed transducer 200ms 2: Governor Processing 010ms 3: Hydraulic Servos 160ms The non-linearity of the deflector vs power curve and the speed of the deflectors (1.5 seconds from 0 deflection to full deflection) aggravate this problem. The problem is further aggravated by the fact that the control scheme for the deflector contains no droop nor is there any needle speed reference (NSR) feedback when deflectors are in stream and the unit is in needle mode (the typical overspeed scenario). Zero droop causes the machine to operate isochronously and without NSR feedback the deflectors remain in stream indefinitely or until Automation Generation Control (AGC) or the dispatcher schedules a new, lower, set point. Finally, so long as the deflectors are in stream, Turbine Pit turbulence creates random power system noise. This noise is approximately 4-6 MW in magnitude per generator and is sufficient to perturb the unstable reaction. In summary the problem is a result of control response time delay, non-optimal gains and is aggravated by a lack of droop, a lack of power system feedback, and small signal noise generated by turbulence within the turbine pit and caused by the deflectors. Question Why doesn’t the PTI PSSE Model allow us to reproduce the oscillations? Answer The original PTI Model did not accurately represent the Woodward 501 Governor or tunnel. The EPS Model accurately represents the 501 Governor and tunnel. Tuning performed by the project team, following machine testing has allowed us to recreate oscillations and is as accurate a digital representation of an analog system as is practical. Control Response Problem Bradley Lake was designed with 72 seconds (90s nominal) needle opening and closing times. This means that the needles are capable of fully loading or unloading the unit in 72 seconds. Based on an analysis performed in 1990 by Stone and Webster/PTI, the project was designed to provide 27 MW of responsive spinning reserve when operated in conjunction with the Railbelt combustion turbines. Bradley was designed to provide 27 MW of spinning reserve in 15-18 seconds. It was intended that the Railbelt combustion turbines would cover the Bradley spin response deficiency by operating in peak mode (10% above thermal limit) for this 15-18 second period. Page 8 of 15 Twenty-five gigabytes of raw data were collected over the five days of testing. Over the past year the project team has developed analysis algorithms, correlated and collated the data, and has arrived at answers to each of the questions the test plan was developed to answer. In addition, the team benchmarked all stability-related components of the PSS/E model by isolating & modeling each governor sub-component in MATLAB (a GUI Control Algorithm modeling program). Actual system data, gathered from the machine tests has been streamed into the model sub-component and the output of the sub-component subtracted from the actual output of that sub-component during testing. This function represents the error for a given sub-component, for that input function. Numerous representative input functions were run through each sub-component and the worst case errors were identified. Current Status of the Project We have pinpointed the nature and cause of both the instability and control response problems at the plant. In addition, we have identified what we believe are methods to resolve these problems. We have identified three alternatives to mitigate the problems. And have evaluated the Railbelt wide fuel, and O&M costs and benefits of these alternatives. Finally, we have prepared our recommendation as to where we should go from here. The following is a list of answers to questions we set about to answer in this investigation: Question From a power system perspective does Bradley initiate the instability, or does the Kenai Power System or some other external entity initiate the instability? Answer The Bradley Instability is a classic case of small signal instability. The Bradley Control System causes the instability. The system is perturbed by Turbine Pit turbulence aided at times by Kenai power system load variations. Question If Bradley is the source of instability what control system components contribute to or cause the instability? Answer Instability is a complex phenomenon, however in short, it is caused by positive feed back & excessive gain in a control system. In the Bradley Plant the positive feed back is caused by time delays between the time that the rotor speed is captured by the turbine shaft speed transducer and the time that this Page 7 of 15 Concurrently, the project team developed a detailed Bradley Turbine-Governor Test Plan. This plan was reviewed and approved by Woodward Governor , Electric Power Systems and Stone and Webster. The test plan was structured to answer the following questions: 1 Bs Is the Bradley Instability a classic case of small signal instability? If 1 is true, what is the source of the small signal perturbations: Governor/Plant Electronics? Tunnel Pressure Waves? Turbine Pit Turbulence? Deflector Vibration? Governor Hydraulic System Transients? Kenai Power System Noise? moaesp What, if any, are the contributions of the following components to instability and if contributions are made, what causes the perturbation or time delays? Speed Transducer Time Delay? Deflector PID Gain Settings? Governor Processing Time Delay? Hydraulic Servomotor Time Delay? Deflector Speed Variations Due to Hydraulic Pressure Variations? Deflector Position Telemetry Error? Exciter Interaction? Power System Stabilizer Interaction? SVC Power Oscillation Damper Interaction? Deflector position error? eae orp Sone tt (es: 0)! to Can a more accurate deflector verses power curve be derived? Does the new EPS tunnel model more accurately reflect the physical tunnel? Can the instability be reproduced routinely? What is the maximum rate at which needles can be pulsed full open to full closed and vise versa? In May of 1999 testing was performed on the Bradley Plant and data was collected utilizing the IS system. Woodward Governor was on site to assist in connecting the IS system to the governor and to reconfigure governor algorithms to export real time data from the 501 controller directly to IS data collection channels. Stone and Webster and EPS were on-site to provide assistance on Plant and power system technical issues. Page 6 of 15 3: Why doesn’t our PSS/E model replicate these oscillations? And, can they be made to do so? Regarding Control Response: 15 Why is Bradley’s control response significantly slower than predicted in the 1990 Load Acceptance study, the 1992 Dispatch Operations Summary, and the 1993 Final Operating study? What is the plants actual maximum response rate in needle mode? De What control components contribute to the under performance of the plant? 35 Can control response be improved, if so how and what is the cost? Regarding system operation: The action plan details studies to be performed at the conclusion of the project to provide accurate operating guidelines to system operators; and to modify existing power system protection and reliability schemes to optimize plant performance and system reliability. One of the key challenges in answering the questions posed was the apparent inconsistency between the 1990 Bradley Lake PSS/E Tunnel-Hydro-Turbine-Generator Model developed by PTI and the actual Bradley Lake Tunnel-Hydro-Turbine-Generator control system. The project team engaged EPS to review and document the actual plant control system, to evaluate the PTI model, and to develop and bench mark a new more accurate Bradley Governor model. This project was completed in January of 1998. The model was able to reproduce the instability with the observed modes of oscillation; however, the project team determined that additional tuning was required to accurately predict instability and to better understand governor control quantities. Additionally, as a result of the EPS modeling evaluation several revisions were made to the railbelt PSS/E model to more accurately reflect actual power system devices external to Bradley. Another key challenge to understanding the Bradley electrical instability phenomenon was the time synchronized acquisition of a relatively large number of data points. The railbelt utilities did not possess an instrument of sufficient bandwidth to gather this data and were unable to locate one commercially. Therefore, the project team designed and built the device utilizing “off the shelf’ components and commercially available software. The device, known as “The Instrumentation System”(IS) samples 72 channels of data 2000 times per second, with less than .006milliseconds (ms) of phase shift between channel 1 and channel 72. The system is used to record power quantities, internal governor quantities and other physical parameters of the plant. The device was installed, commissioned and tested at Bradley in May of 1999. Page 5 of 15 Background In January 1996 at the request of Chugach Electric, the Bradley Lake dispatcher, the Bradley Lake Operations & Dispatch subcommittee (Bradley O & D) recommended and the Bradley Lake Project Management Committee (BPMC) subsequently authorized an investigation into the cause of numerous electrical instability events and control response problems that had been occurring since the commissioning of the Bradley Lake project. A project team consisting of Larry Hembree (AMLP), Randy Johnson (AML&P), Brian Hickey (Chugach), was assembled. The team was supported by Andi Hamilton, Budget and Project Coordinator (Chugach); Don Stead, Bradley Project Manager(Homer); Stan Sieczkowski,AEA representative and numerous consultants including Electric Power Systems (EPS), Woodward Governor Co. Inc., Stone & Webster Inc., Power Technologies, Inc. Initially the investigation consisted of compiling a comprehensive review of Bradley Project documentation related to technical design and commissioning notes and a review and analysis of all electronic power system data related to system disturbances since Bradley commissioning (1993). The systematic review Bradley documentation validated the two premises of the investigation. First, that the measured control response of the plant is significantly poorer than that predicted in the design studies and second that electrical instability had been identified documented and not resolved during commissioning. The review of power system data involved analysis of 90 disturbance events and from them identified approximately 30 oscillations. This review empirically quantified the period of the oscillations as 560-750 ms and validated that they did in fact exist and that Bradley was always a significant participant if not driver of them. These results led to the development of the action plan for correction of the Bradley Lake Project instability and control problems. The action plan was submitted to the O & D and subsequently authorized and partially funded by the BPMC in January of 1997. The action plan detailed a series evaluations studies, and modeling projects intended to answer several key questions raised in validating the suspected causes of the electrical instability and control response problem. These questions are: Regarding Electrical Instability: i From a power system perspective, does the Bradley Project initiate instability or does the Kenai Power System or some other external sources (Static VAR Compensator, CEA-SCADA etc.) excite the Bradley Project into instability? 2. If Bradley is the source of instability, what control system or systems cause, or contribute to the cause, of the instability? Page 4 of 15 Upon completion of the project enhancements, underfrequency loadshed and final operating guides, and tuning of the existing Static Var Compensator Power Oscillation Damper will be required. Funding for these studies is not included in this request. Page 3 of 15 Executive Summary The Bradley Lake Instability Project Team has completed its analysis and identification of the instability and control response problems at the Bradley Lake Project. We have identified the source of both problems and are recommending that the O & D and the PMC fund proof of concept designs on a number of proposed modifications to the plants control systems. These concepts are explained in the following report. The project team has determined that the Bradley Plant is the source of the 560-750ms oscillations identified in the 1997 Kenai disturbance review. We have determined that the oscillations are the result of small signal instability in the Bradley control system. This instability is caused by time delays, gain mismatches, system non-linearity’s, and poor governor control algorithm design. The team has determined that the control response problems are a result of control algorithms that focus on minimizing water usage over performance. These algorithms were not modeled in the studies that were used to predict the plants response and develop the final operating guidelines. The project team believes it is technically possible to eliminate these shortfalls. And, that plant performance can be improved by replacing the electronic governor hardware and software, mitigating turbine pit turbulence, adding dual rate servo motors, and adding external plant intelligence to allow real-time optimization of gains. The team has completed preliminary cost benefits analysis on the economics of three alternatives: 1. Do nothing, limit plant output to 0 MW spinning reserve and 60 MW capacity. No greater than 30 MW per unit. 2. Fix instability and accept the plants current non-responsive spinning reserve contribution. 3. Fix the instability and improve control response. Assuming a worst case cost for alternative three of $5 million dollars, the fuel and O & M benefits alone provide a seven year payback. Seven years is well short of the remaining life of the plant. The project team recommends that we proceed with alternative three. The team recommends that we proceed with funding for proof of concept designs and request quotations on these designs. Upon receipt of these quotations additional cost benefit analysis will be performed and construction funding will be requested for those options with positive cost benefit ratios. The project team request funding in the amount of $796,200 to complete project design and enhancement tasks identified in appendix A of the report. Page 2 of 15 Bradley Lake Instability Study Final Report June 9, 2000 Prepared by: Brian Hickey Randy Johnson Larry Hembree Page 1 of 15 CF a¢ Mecussiim > Mike Scstt 4 bh PU (b \MCrease e => pi Steel om eames ad bol . thet | yw 6 gosto. + lod Ch Al) Bern Lacte rs frusa|* [tw pat. spas Duda ( peed ‘ (er ie “ap d ( bass ( Couged.. VTE OE Re, I VUntinn LEP a Dia! Sg Dim fall oped to ld. pee cs | el EA Zon \ iavadad fy lexan er tis Hake Mickels — havvis Systm Compo ible itt arPe MLks+P [ee A dota info. 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BRADLEY LAKE BUDGET ACTIVITY BY ACCOUNT Rey Fund O&M Fund Debt Fund Op Reserve R&C Cap Reserve Total 6/30/2000 Balance 158,076 997,420 7,007,037 535,000 5,000,010 12,834,000 26,531,543 (1) (0) oI 0 a (1) FY2001 Projected = Debt Payment 7/1/00 (7,373,552) (7,373,552) Revenues 12,488,023 12,488,023 Interest 1,775,871 - - 1,775,871 Transfers to O&M (1,719,000) 1,719,000 - Transfers to Debt Service (12,639,715) 12,639,715 - - - 00 O&M Requisitions (918,610) (918,610) 2001 O&M Reauisitions (1,899,480) (1,899,480) Reimbursement for refundi 130,207 - 130,207 Renewals/Replacements : : To Excess Earnings fund (19,327) (19,327) Reduction in Capital Res - - Debt Payments (12,273,200) (12,273,200) 6/30/2001 Projected Balance 174,134 (101,670) 535,000 5,000,010 12,834,000 18,441,474 FY2002 Budget = Revenues 12,963,621 12,963,621 Interest 1,714,000 1,714,000 Transfers to O&M (2,315,804) 2,315,804 - Transfers to Debt Service (12,273,450) 12,273,450 - Transfer to R&C Fund (62,500) 62,500 2001 O&M Requisitions - - 2002 O&M Requisitions (2,214,134) (2,214,134) Reimbursement for refunding - Renewals/Replacements - (250,000) (250,000) To Excess Earnings fund (200,000) (200,000) Reduction in Capital Res - Debt Payments (12,273,450) (12,273,450) 6/30/2002 Projected Balance 1 - 535,000 4,812,510 12,834,000 18,181,511 A 24% of Annual O&M Budget Page 1 of 1 3/14/01/3:51 PM, 2002 Bradley Budget.xls BRADLEY LAKE OPERATIONS & MAINTENANCE, 2/16/01 CHANGE CHANGE FYO1 FY2001 FROM FY01 FROM ‘01 FY2002 Refunding Costs TOTAL FERC 920 FERC 924 - Property Insurance Insurance Premiums Homer Electric Insurance RSA with Risk Management FERC 928 - Regulatory Commission Expenses FERC administrative fees Contractual Engineer - FERC license issues Reimb from Construction Fund (prior year) 5 Year Inspection & Follow-up 112,359 TOTAL BRADLEY LAKE BUDGET 1,887,784 1,899,480 326,350 314,654 2,214,134 Page 2 of 2 3/14/01/4:10 PM, 2002 Bradley Budget.xls BRADLEY LAKE OPERATIONS & MAINTENANCE 2/16/01 CHANGE CHANGE FYOt FY2001 FROM FYO1 FROM ‘01 FY2002 BUDGET PROJECTED BUDGET PROJECTED BUDGET FERC 535 - Operation Supervision & Engineering HEA O&M Contract 78,500 79,000 Other oO 73,000 FERC 537 - Hydraulic Expenses HEA O&M Contract Other FERC 538 - Electric Expenses HEA O&M Contract 135,000 135,000 241.800 241.800 FERC 539 - Misc. Hydraulic Power Generation Expenses HEA O&M Contract 110,500 84,600 1,400 27,300 111,900 DIS Voice/Data Circuits (inc. space & power) 0 10,332 o (10,332) 0 DIS 2-way Radio Circuits & radio maint. o 6,439 o (6,439) 0 HEA Circuits and Radio - To Bemice Lake 90,000 90,000 0 0 90,000 CEA Circuits -Bemice Lake to Anchorage 27.684 27,684 228.184 219,054 FERC 540 - Rents Bradley Lake FERC land use fees (5% increase b 69,279 69.279 FERC 542 - Maintenance of Structures HEA O&M Contract Boat Dock Repairs FERC 543 - Maintenance of Reservoirs, Dams & Waterways HEA O&M Contract 5,000 NUKA Diversion FERC 544 - Maintenance of Electric Plant HEA O&M Contract HEA - Transformer Fire FERC 545 - Maintenance of Misc. Hydraulic Plant HEA O&M Contract Misc. FERC 556 - System Control & Load Dispatching HEA O&M Contract 6,000 2,000 (400) 3,600 5,600 CEA Dispatch & Software oO oO O O O NOAA Weather Service 6,400 6,400 36,100 36,100 42,500 SCS Snow Measurement 10,500 12,350 1,850 oO 12,350 UAA Seismic monitoring 57,000 56,500 (500) 0 56,500 USGS Streamguaging 130,000 132,850 9,000 6,150 139,000 USGS Minimum Flow Study oO oO oO oO 209.900 210,100 46.050 45.850 255.950 FERC 562 - Station Expenses CEA SVC/Substation Maintenance Contract 47,000 73,000 47,000 73,000 FERC 571 - Maintenance of Overhead Lines HEA Overhead Line Maintenance 20,000 20,000 oO oO 20,000 z 20,000 20,000 oO oO 20,000 FERC 920 - Administrative Expense Payroll Cost for CO! AEA Admin Fee 200,000 200,000 O 0 200,000 Workers comp refund 0 0 AEA Administrative Costs 200,000 200,000 O 0 200,000 PMC Costs Bradley Lake Audit fees 8,500 8,500 oO oO 8,500 Bradley Lake PMC Legal 30,000 30,000 (20,000) (20,000) 10,000 Bradley Lake Arbitrage Report 1,800 7,681 2,700 (3.181) 4,500 Miscellaneous PMC Expenses oO Budget. recording, courier 0 0 0 0 0 Bradley Lake Trustee fees 20,000 20,000 oO o 20,000 PMC Costs 60,300 66,181 (17,300) (23,181) 43,000 Bond Refunding Costs Costs to be reimbursed at closing 0 0 0 0 Page 1 of 2 3/14/01/4:10 PM, 2002 Bradley Budget.xIs BRADLEY LAKE OPERATIONS & MAINTENANCE 2/16/01 CHANGE CHANGE FY01 FY2001 FROM FY01 FROM '01 FY2002 BUDGET PROJECTED BUDGET PROJECTED BUDGET SUMMARY HEA O&M Contract Total 716,500 727,260 292,800 282,040 1,009,300 CEA Substation/SVC Maintenance 47,000 47,000 26,000 26,000 73,000 Other O&M 416,584 431,833 44,450 29,201 461,034 Insurance Costs 303,900 314,847 900 (10,047) 304,800 Regulatory Costs 143,500 112,359 (20,500) 10,641 123,000 1,627,484 1,633,299 343,650 337,835 1,971,134 Administrative Costs 260,300 266,181 (17,300) (23,181) 243,000 1,887,784 1,899,480 326,350 314,654 2,214,134 Bond Refunding Costs 0 0 0 0 0 1,887,784 1,899,480 326,350 314,654 2,214,134 Page 1 of 1 3/14/01/4:17 PM, 2002 Bradley Budget.xls BRADLEY LAKE HYDROELECTRIC PROJECT REVENUES, EXPENSES & CHANGES IN SURPLUS REVENUES UTILITY CONTRIBUTIONS INTEREST INCOME EXCESS FROM BOND PROCEEDS REFUND OF COST OF ISSUANCE FROM BONDS SALE OF VEHICLE AEA SETTLEMENT PRIOR YEAR CORRECTIONS EXPENSES OPERATIONS RENEWALS/REPLACEMENTS TRANSFER TO OPERATING RESERVE BOND REFUNDING COSTS DEBT SERVICE (net of Capital Reserve Reductions) ARBITRAGE TRANSFER CURRENT YEAR SURPLUS (DEFICIT) BEGINNING SURPLUS ENDING SURPLUS (DEFICIT) BALANCE SHEET ASSETS REVENUE FUND OPERATING FUND LIABILITIES & SURPLUS LIABILITIES SURPLUS OTHER INFORMATION OPERATING RESERVE * MONTHLY CONTRIBUTIONS 2/16/01 FY98 FY99 FY00 FY2004 FYO1 FY2002 ACTUALS ACTUALS ACTUALS BUDGET EQRECAST BUDGET 13,210,675 13,843,841 11,813,741 12,488,023 12,488,023 12,963,621 1,845,862 1,837,883 1,801,425 1,744,000 1,775,871 1,714,000 37,008 130,207 1,477 ° 0 0 0 ° 0 o 0 0 15,058,014 15,681,724 13,652,174 14,232,023 14,394,101 1,748,691 1,905,324 2,399,919 1,887,784 1,899,480 23,832 25,764 0 0 ° 0 0 0 294,124 (283,289) (10,836) ° 0 13,017,785 13,746,181 11,779,859 12,273,200 12,639,715 12,273,450 27.976 34,110 20,600 30,000 19.327 200,000 15,112,408 15,428,090 14,189,542 14,190,984 14,558,522 14,750,084 (54,384) 253,634 (537,368) 41,039 (164,421) (72,463) 575,012 520,618 774,252 (41,039) 236,884 72,463 520,618 774,252 236,884 0 72,463 0 481,136 135,622 158,075 - - 296,292 1,099,686 997,420 : 72.463 777,428 1,235,308 1,155,495 : 72,463 256,810 461,056 918,611 a 7 520,618 774,252 236,884 - 72,463 777,428 1,235,308 1,155,495 Required to be 20% of budgeted operating expense 535,000 535,000 1,100,890 1,153,653 535,000 984,478 535,000 535,000 1,040,669 1,040,669 535,000 1,080,302 3/14/01/3:44 PM, h:all\elaine\bradley2002 Bradley Budget.xls BRADLEY LAKE MONTHLY UTILITY CONTRIBUTION POWER PURCHASER CHUGACH ELECTRIC MUNICIPALITY OF ANCHORAGE AEG&T GOLDEN VALLEY ELECTRIC CITY OF SEWARD POWER PURCHASER CHUGACH ELECTRIC MUNICIPALITY OF ANCHORAGE AEG&T GOLDEN VALLEY ELECTRIC CITY OF SEWARD COMPONENTS OF CHANGE IN CONTRIBUTION FY2001 ANNUAL CONTRIBUTION PERCENT DECREASE IN BUDGETED INTEREST EARNINGS INCREASE IN BUDGETED O&M COSTS INCREASE IN ARBITRAGE REBATE PAYBACK FOR R&C EXPENSE (REPLACED SCADA SYSTEM) INCREASE IN DEBT SERVICE DECREASE IN BUDGETED USE OF PRIOR YEAR ACCUMULATED SURPLUS FY01 PROJECTED SURPLUS FY2002 ANNUAL CONTRIBUTION FY98 FY99 FY2000 FY2001 FY2002 FY2002 SHARE TOTAL TOTAL TOTAL TOTAL TOTAL TOTAL TOTAL INCREASE 30.4% 3,968,670 «3,947,190 4,016,052 4,208,532 «3,591,372 3,796,356] 3,940,943 144,587 25.9% 3,381,203 3,362,902 3,421,560 «3,585,552 «3,059,748 «3,234,396 | —3,357,576 123,180 25.8% 3,368,148 = 3,349,918 3,408,360 3,571,704 3,047,940 3,221,916] 3,344,616 122,700 16.9% 2,206,267 2,194,326 «2,232,600 «-2,339,604 «1,996,512 2,110,476] —2, 190,882 80,376 1.0% 130,548 129,842 132,108 138,444 118,140 124,884 129,636 4,752 700.0% —19.054.836 12,984,178 19.210.600 19,040,606 11,010,712 12,408,028) 12,963,623 475,595 PERCENT ——FY96 FY97 FY97 FY99 FY2000 FY2001 FY2002 FY2002 SHARE MONTHLY MONTHLY MONTHLY MONTHLY MONTHLY MONTHLY MONTHLY INCREASE 30.4% 330,723 328,933 334,671 350,711 299,281 316,363 328,412 12,049 25.9% 281,767 280,242 285,130 298,796 254,979 269,533, 279,798 10,265 25.8% 280,679 279,160 284,030 297,642 253,995 268,493 278,718 10,225 16.9% 183,856 182.861 186,050 194,967 166,376 175,873 182,571 6,698 1.0% 10,879 10,820 11,009 11,537 9,845 10,407 10,803 396 7,087,904 1,082,016 _1,100.690 1,153,653 964.476 1,040,669] 1,080,302 12,488,028 30,000 326,350 170,000 62,500 250 se (72.463) \ “j (41,044) “A 72,963,621 3/14/01/3:45 PM,h;all\elaine\bradley\ 2002 Bradley Budget.xis BRADLEY LAK ROJECT MANAGEMENT COMMIT] E OPERATING AND REVENUE FUNDS STATEMENTS OF EXPENSES June 30, 2000 and 1999 2000 Variance Favorable 1999 Budget Actual (Unfavorable) Actual Expenses: Generation expense: Operation supervision and engineering $ 93,000 $ 77,372 = $ 15,628 = $ 66,746 Hydraulic operation 15,000 3,500 11,500 4,932 Electric plant operation 144,500 132,711 11,789 135,801 Hydraulic power generation operation 365,303 381,069 (15,766) 248,830 FERC land use fees 75,000 69,933 5,067 71,242 Structure maintenance 126,000 17,209 108,791 74,643 Reservoir, dam, and waterway maintenance 8,000 235,852 (227,852) 37,566 Electric plant maintenance 257,000 472,567 (215,567) 220,494 Hydraulic plant maintenance 92,000 67,580 24,420 74,536 System control and load dispatching 225,112 189,301 35,811 247,397 Substation operation and maintenance 47,000 103,526 (56,526) 23,624 Overhead line maintenance 20,000 14,670 5,330 20,139 Total generation expense 1,467,915 1,765,290 (297,375) 1,225,950 Administrative, general and regulatory expense: Insurance 303,900 298,367 5,533 293,559 AEA administrative fee 200,000 200,000 - 200,000 PMC costs 60,300 40,115 20,185 40,193 Arbitrage expense 40,000 20,600 19,400 34,110 Regulatory commission: FERC administrative fees 93,500 83,859 9,641 104,451 FERC licensing 28.500 12,287 16,213 41,170 Total administrative, general and regulatory expense 726,200 655,228 70.972 713,483 Total operating and maintenance expenses 2,194,115 2,420,518 (226,403) 1,939,433 Less nonrecurring expenses - (499,375) 499.375 - Total operating and maintenance expenses less nonrecurring expenses $2,194,115 $___1.921.143 $ 272,972 $ 1,939,433 11 INDEPENDENT AUDITOR'S REPORT ON ADDITIONAL INFORMATION Bradley Lake Project Management Committee Operating and Revenue Funds Anchorage, Alaska Our report on our audits of the special purpose financial statements of the Bradley Lake Project Management Committee Operating and Revenue Funds for June 30, 2000 and 1999, appears on the page preceding the balance sheets. Those audits were made for the purpose of forming an opinion on the special purpose financial statements taken as a whole. The supplemental Statements of Expenses are presented for purposes of additional analysis and are not a required part of the basic financial statements. Such information has been subjected to the auditing procedures applied in the audits of the special purpose financial statements and, in our opinion, is fairly stated in all material respects in relation to the special purpose financial statements taken as a whole. Parisena, Stromberg & Company, APC Anchorage, Alaska November 15, 2000 10 BRADLEY LA — PROJECT MANAGEMENT CON [TTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS (Continued) June 30, 2000 and 1999 NOTE E: COMMITMENTS AND CONTINGENCIES Forward Delivery Bond Purchase Agreement: In December, 1997, Bradley Lake Project Management Committee entered into a forward delivery bond purchase agreement providing for the issuance of two series of Power Revenue Refunding Bonds in April of 1999 and 2000. The costs associated with the refunding were expensed in the year ended June 30, 1998 and repaid by funds provided by the bonds during the years ended June 30, 2000 and 1999. NOTE F: NONRECURRING ITEMS During the year Bradley Lake required fire repairs at a total cost of $265,326. There was also storm damage to a dike that resulted in repair costs totaling $234,049. The insurance deductible for these events is $50,000 for equipment and $2,000,000 for cleanup so there will be no recovery of costs. BRADLEY LA___ PROJECT MANAGEMENT CON TTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS (Continued) June 30, 2000 and 1999 NOTE C: MAJOR CONTRACTS AND AGREEMENTS (Continued) An operation and maintenance agreement dated February 11, 1994, was executed between Homer Electric Association and the Alaska Energy Authority. This agreement provides for the operation and maintenance of the Bradley Lake Hydroelectric Project by Homer Electric Association. The agreement is through June 30, 2004 and continues from year to year thereafter, except upon written notice to terminate by either party. Notice of termination must be given one year in advance of the termination date. HEA is to be reimbursed for costs associated with the operation, maintenance and repair of the Project as determined in advance through the submission of an annual budget based upon prudent estimates and anticipated operation and maintenance costs. In August, 1996, the agreement was amended to separate the maintenance of the transmission facilities from the hydroelectric project. The transmission agreement continues from year to year, except upon written notice to terminate by either party. Notice of termination must be given six months in advance of termination dates. In June, 1999 the agreement was again amended to require HEA to provide communication services in addition to the other services. NOTE D: RELATED PARTY TRANSACTIONS During the years ended June 30, 2000 and 1999 the Committee paid the following amounts to related parties for costs incurred under the various contracts described in Note D: 2000 199 Homer Electric Association — operation, maintenance and communications $1,207,068 $ 753,962 Chugach Electric Association - substation service maintenance $ 103,526 $ 23,624 For the years ended June 30, 2000 and 1999, Chugach Electric Association provided dispatch services to the Committee for no charge. BRADLEY LA___ PROJECT MANAGEMENT CO)N_ _[TTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS (Continued) June 30, 2000 and 1999 NOTE B: INVESTMENTS (Continued) Investments are sold as needed to cover operating requisitions submitted to the trustee and are therefore considered to be short-term and available for sale. Investments are presented at aggregate cost, which approximates market value. For purposes of the cash flow statements, management considers the full amount of the investment balance to be cash available for operations. NOTE C: MAJOR CONTRACTS AND AGREEMENTS During May 1994, the Alaska Energy Authority entered into the Master Maintenance and Operating agreement with the Committee. The purpose of the agreement is to establish contract administration and budgeting procedures for maintenance and operation contracts of the Bradley Lake Hydroelectric Project and to provide for the lease or other use of facilities and equipment in a manner consistent with the requirements of the Power Sales Agreement. The term of the Master Agreement is indefinite, remaining in effect until termination of the Power Sales Agreement or until AEA no longer legally exists. This agreement authorizes AEA to enter into any contracts necessary to perform operating or maintenance-type services to the Project, subject to the approval of the Committee. On behalf of the Committee, the Alaska Energy Authority entered into an agreement with Chugach Electric Association, Inc. (CEA) in August, 1996, for the provision of all services necessary to dispatch the Bradley Project's electric power output. The dispatch agreement runs concurrently with the wheeling and related services contract entered into by and among the parties to the Power Sales Agreement in December 1987 and remains in effect for the term of the wheeling agreement unless CEA ceases to be the output dispatcher. In August 1996, the Alaska Energy Authority entered into an agreement with Chugach Electric Association, Inc. on behalf of the Committee for the provision of maintenance services for the Daves Creek and Soldotna SVC Substations. BRADLEYLA PROJECT MANAGEMENT CON [TTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS (Continued) June 30, 2000 and 1999 NOTE A: SIGNIFICANT ACCOUNTING POLICIES (Continued) All deposits, including utility contributions and interest earnings, are made into the Revenue Fund, which transfers amounts approximately equal to one-twelfth of the annual operating and maintenance budget into the Operating Fund on a monthly basis. Additional transfers are made from the Revenue Fund to the Debt Service Fund in order to satisfy semiannual interest payments and annual principal payments on the Project's outstanding bonds payable. Interest earnings available for operations and maintenance are derived from the following funds: Debt Service Fund; Operating Reserve Fund; Operating Fund; Revenue Fund; Capital Reserve Fund; and the Renewal & Contingency Fund. Estimates: The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expense during the reporting period. Actual results could differ from those estimates. Revenue and Expense Recognition: Utility contributions are recognized as revenue when due to be received under the terms of the Power Sales Agreement. Transfers from other funds are recognized when the transfer is made and interest earnings are recognized when received. Operating and maintenance expenses are recognized when incurred, while interest and principal transfers to Debt Service Fund are recognized when paid. Purchases of fixed asset replacements are expensed when purchased. Income Taxes: The Bradley Lake Project Management Committee is exempt from income taxation under Section 501 (a) of the Internal Revenue Code. NOTE B: INVESTMENTS Substantially all of the balances in the following funds are invested in collateralized investment agreements through the trust department of US Bank. The specified interest rate for monies from the Operating and Revenue Funds invested in the agreements is 7.38%. Balances at June 30, 2000 and 1999 are as follows: 000 1999 Operating Fund $ 997,420 $ 1,099,685 Revenue Fund 158,075 135,622 Total investments $ 1,155,495 $1,235,307 6 BRADLEY LA PROJECT MANAGEMENT CON (TTEE OPERATING AND REVENUE FUNDS NOTES TO FINANCIAL STATEMENTS June 30, 2000 and 1999 NOTE A: SIGNIFICANT ACCOUNTING POLICIES Description of Business: The Bradley Lake Project Management Committee (the Committee) was established pursuant to Section 13 of the Agreement for the Sale and Purchase of Electric Power (Power Sales Agreement) dated December 8, 1987. The purpose of the Committee is to arrange for the operation and maintenance of the Bradley Lake Hydroelectric Project, which became operational in September 1991, and the scheduling, production and dispatch of power. The members of the Committee include the Alaska Energy Authority (AEA) and the five purchasers under the Power Sales Agreement - Chugach Electric Association, Inc.; Golden Valley Electric Association, Inc.; the Municipality of Anchorage (Municipal Light & Power); the City of Seward (Seward Electric System); and the Alaska Electric Generation & Transmission Cooperative, Inc. (AEG&T). The Homer Electric Association, Inc. (HEA) and the Matanuska Electric Association, Inc. (MEA) are additional parties to the Power Sales Agreement but are included as power purchasers for purposes of representation while AEG&T has no direct vote as a consequence of the individual representation of HEA and MEA. Section 13 of the Power Sales Agreement delineates other Committee responsibilities, including: establishing procedures for each party's water allocation, budgeting for annual Project costs and calculating each party's required contribution to fund annual project costs. Committee approval of operations and maintenance arrangements for the Project, sufficiency of the annual budgets and wholesale power rates and the undertaking of optional Project work requires a majority affirmative vote and the affirmative vote of AEA. The Power Sales Agreement extends until the later of: 1) 50 years after commencement of commercial operation or 2) the complete retirement of bonds outstanding under the AEA Power Revenue Bond Resolution along with the satisfaction of all other payment obligations under the Power Sales Agreement. Renewal options for additional terms exist. Establishment of Trust Funds: Article V, Section 502 of the Alaska Energy Authority's Power Revenue Bond Resolution established a Revenue Fund and an Operating Fund, including an Operating Reserve account, to be held by AEA. In actuality these funds, along with the Debt Service, Excess Investment Earnings (arbitrage), and various construction funds related to the Bradley Lake Hydroelectric Project are all held by the Corporate Trust Department of US Bank in Seattle, Washington. BRADLEYLA PROJECT MANAGEMENT CON [TTEE OPERATING AND REVENUE FUNDS STATEMENTS OF CASH FLOWS YEARS ENDED June 30, 2000 and 1999 2000 1999 Cash flows from operating activities: Excess (deficiency) of revenues over expenses, fixed asset replacements and debt service $ (537,367) $ 253,634 Adjustments to reconcile excess of revenues over expenses, fixed asset replacements and debt service to net cash provided by operating activities: Increase in accounts payable 91,247 94,310 Increase in amounts due to AIDEA 366.308 109.935 Net cash provided by operating activities (79,812) 457,879 Available cash and cash equivalents at beginning of year 1,235,307 777, 428 Available cash and cash equivalents at end of year $ 1.155.495 $ 1,235,307 Supplemental disclosure of cash flows information: Interest paid $_7.639.859 $10,136,181 See accompanying notes to the financial statements. 4 BRADLEY LA___ PROJECT MANAGEMENT CON __ OPERATING AND REVENUE FUNDS [TTEE STATEMENTS OF REVENUE, EXPENSES AND CHANGES IN SURPLUS YEARS ENDED June 30, 2000 and 1999 2000 1999 Budget Actual Variance Actual Revenue: Utility contributions $ 11,813,712 $11,813,741 $ 29 = $ 13,843,841 Interest receipts 1,775,000 1,801,425 26,425 1,837,883 Excess from bond proceeds - 37.008 38.008 - Total revenue 13,588,712 13,652,174 63,462 15,681,724 Expenses, fixed asset replacements and debt service: Operations and maintenance 2,194,115 1,921,143 (272,972) 1,939,433 Debt service 12,393,675 11,779,859 (613,816) 13,746,181 Bond refunding costs (reimbursement) (Note E) - (10,836) (10,836) (283,288) Fixed asset replacements - - - 25,764 Nonrecurring items (Note F), - 499.375 499.375 - Total expenses, fixed asset replacements and debt service 14,587,790 14,189,541 (398.249) 15.428.090 Excess (deficiency) of revenue over expenses, fixed asset replacements and debt service (999.078) (537,367) (461,711) 253.634 Surplus, beginning of year 999.078 774,252 520.618 Surplus, end of year $ - $ 236,885 $774,252 See accompanying notes to the financial statements. 3 BRADLEY LA PROJECT MANAGEMENT CON OPERATING AND REVENUE FUNDS BALANCE SHEETS June 30, 2000 and 1999 ASSETS Current assets: Investments (Note B) _ Total Assets LIABILITIES AND SURPLUS Current liabilities: Due to AIDEA Accounts payable Total Liabilities Surplus Total liabilities and surplus See accompanying notes to the financial statements. (TTEE 2000 $1,155,495 $_ 1,155,495 $ 492,419 426.191 918.610 236.885 $_1,155.495 $_ 1.235.307 $_ 1,235,307 $ 126,111 334.944 461,055 774,252 $_1,235,307 Independent Auditor's Report Bradley Lake Project Management Committee Anchorage, Alaska We have audited the accompanying balance sheets as of June 30, 2000 and 1999, and the related statements of revenues, expenses and changes in surplus and of cash flows for the years then ended, of the Bradley Lake Project Management Committee Operating and Revenue Funds (a project management committee). These special purpose financial statements are the responsibility of the Bradley Lake Project Management Committee. Our responsibility is to express an opinion on these special purpose financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. The accompanying special purpose financial statements were prepared to present revenue and expenses on an accrual basis with the exception of interest income and fixed asset replacements, which have been presented on a cash basis in order to conform to the fiscal year operations and maintenance budget. In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and surplus of the Bradley Lake Project Management Committee as of June 30, 2000 and 1999 and its revenue, expenses and changes in surplus and cash flows for the years then ended, in conformity with generally accepted accounting principles. This report is intended for the information and use of the Bradley Lake Project Management Committee and should not be used for any other purpose. Parisena, Stromberg & Company, APC Anchorage, Alaska November 15, 2000 Audited Financial Statements BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE OPERATING AND REVENUE FUNDS Anchorage, Alaska Independent Auditor's Report Balance Sheets Statements of Revenue, Expenses and Changes in Surplus Statements of Cash Flows Notes to Financial Statements Independent Auditor's Report on Additional Information Statements of Expenses 10 11 AUDITED FINANCIAL STATEMENTS AND OTHER FINANCIAL INFORMATION BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE : OPERATING AND REVENUE FUNDS JUNE 30, 2000 AND 1999 ¢ The Bradley lake Operations and Subcommittee recommends that the Bradley Lake Project Management Committee fund Proof of Concept designs and studies for alternative three in the amount of $856,200* * This number represents a correction in the amount of $60,000 over the total request for the estimated cost of the Droop Coordination Study found in the draft final report dated June 9, 2000. Net Present Va Discounted Cash Flow Analysis Alternative 1 Alternative 2 Alternative 3 Improve Governor Change Operating Improve Governor Controls & Procedures Controls Enhance Response Net Present Value $60.4 $87.3 $95.6 Cost Benefit Cost Benefit Cost Benefit Present Value $0.1 $60.5 $3.0 $90.3 $5.0 $100.6 Year 2000 $0.1 $3.0 $5.0 2001 aril $4.9 a $7.4 HIT $8.2 2002 $5.0 $7.5 $8.4 2003 $5.1 $7.7 $8.6 2028 $8.9 $13.2 $14.7 - Early in the project we estimated a worst case cost for replacement of the governor, servomotors and needle orifices at approximately 5 million dollars. We have used this value as a worst case cost to perform a net present value analysis on each of the alternatives. ¢ Alternative three — In addition to number two, install dual-rate hydraulic servomotors to increase needle speeds. Change Needle Orifices.Implement a dual mode algorithm, “efficiency” verses “system support”. Efficiency mode would maintain needle equalization and System Support mode would open six needles, as fast as possible. ¢ Alternative two — Replace Governor electronics to reduce time delays. If possible, dampen turbine pit turbulence, and add external intelligence to optimize gains based on power system conditions. Successful implementation of these concepts can virtually eliminate instability and potentially provide the current 27 MW of non- responsive spin. e Alternative one — Involves limiting plant operating output such that the units operate low on thier deflector verses power curve (below 30 MW). This implies a two unit plant limit of 60 MW and a single unit plant limit of 30 MW. What can we do aboutsit? ¢ We have developed three alternative — Make no physical modifications and mitigate the instability problem by altering allowable operating limits. — Replace and upgrade electronics and virtually eliminate the instability. — In addition to alternative two, add mechanical equipment to improve control response. ¢ The “do nothing” option is not an alternative, eventually it will result in severe damage to Bradley Lake and potentially other rotating equipment. Questions that we set out to answer in the stuc Q. ¢ What is the maximum response rate of the plant? A. — For the current governor the the maximum open close rate via AGC is approximately eight minutes. — The response can be as long as 25 minutes for a speed error input. Questions that we set out to answer in the ¢ The answer lies in the needle scheduling logic of the Woodward 501 controller. The algorithm contains needle equalization logic that severely limits response time. ¢ In addition speed error is incapable of scheduling additional needles, thus limiting capacity Questions that we set out to answer in the study. ¢ Regarding the Control Response Problem: Q. — Why is Bradley's Control response significantly slower than was predicted in the Bradley commissioning and operating studies? Questions that we set out to answer in the study. Q. — Why doesn't the PTI PSS/E model replicate this problem? A. ¢ The PTI model did not accurately represent the Woodward 501 governor nor the power tunnel. ¢ The EPS model accurately represents the governor and tunnel and the tuning performed following machine testing has allowed us to accurately reproduce the oscillations Questions that we set out to answer in the — The time delay/positive feed back prob aggravated by several factors: ¢ Zero droop when the deflectors are in stream, in needle mode. ¢ Lack of a speed reference input to the deflector circuit in needle mode, causes the deflectors to remain in stream indefinitely. ¢ Non-optimal gains cause exaggerated control response ¢ The non-linear relationship of the deflector verses power curve. Transient phase shift in the shaft speed transduce a i i i i ii i i i OE sega ee a ta ig Se Questions that we set out to answer in the study. Q. — If Bradley is the source of the instability, what control system components contribute to or cause the instability? A. ¢ The instability is caused by positive feedback in the governor deflector controls. ¢ The positive feedback is a result of a dynamic time delay in the shaft speed transducer combined with time delays in the governor logic and hydraulic servomotor system. Questions that we set out to answer in the study. A. ¢ Bradley Lake is the source of the instability problems observed on the Kenai Peninsula. ¢ Bradley Lake instability is a classic case of dynamic instability. ¢ The small signal perturbations that initiate the instability are generated by deflector turbulence in the turbine pit, at times aided by the Kenai load variations. Questions that we set out to Answer in the Stt ¢ Regarding Dynamic Electrical Stabi ity Q. — From a Power System perspective, does the Bradley Project initiate instability, or is Kenai Power System or some other external system the source of the problem ? Bernice Lake and Bradley Lake Besparse to University - Daves Creek line trip 7z WS2: Bradley MW vs BLPP 3 MW 7/18/96 event 0455390452500 O° _ la __ 800 800 - 4000 4200 1400 1600 BLPP 3 MWi(grn) 30 /| 60 A pp? | \ 0 — oth Bernice Lake Response to University to Daves Creek line trip 728=96 W29: BLPP 3 MW vs BLPP Hz 7/18/96 event 045539 200 400 600 200 1000 1200 1400 1600 | esr git eee ere ober ee ees Foe 60 | 60 | n BLPP 3 MW(red) | ° eat er a ee ' Be hale alliemae tia 34 MW lb: ae oe a pn “stem | ye MA [72 Le re " ae 20 i BLPP Hz(grn) | _ 10 50 a — 0 | | | to 300———~COOS*~*«iROS*«~«iSCSC«O 1200 (1400 1600 ZS Kenai frequency after the University to Daves Creek line trip 72R8=96 Hz eve ee ) even 048539 ve Ba Bradley Hz(grn) | 56 Bradley isolates from Kenai at | 54.8 Hz — i | f ee —T | } | | 54 ». ~ fof BLPP Hz(red) Se 62 | intaingeeiria as | 200 400 600 800 4000 1200 1400 1600 Bradley Lake unit 1 & 2 power swings, 5-24-00 instability Why did we begin to study the ¢ Severe power swings, unstable oscillations at Bradley following minor power system deviations. ¢ Control response problems that led to load shed or blackouts on the Kenai Peninsula. ¢ Dynamic Electrical Stability: — Negative Feedback — Positive Feedback — Proportional, Integral, Derivative Gains ¢ Dynamic Electrical Stability: — Steady State Events — Natural frequency — Damped Oscillation — Under Damped Oscillation — Unstable Oscillation Dynamic instabilit ¢ The Narrows Bridge, Tacoma Washington = November 7, 1940 under 40 mph wind load. cot our L — — position lorerncte tworrs) feedbock} FIG.9-25 Schematic diagram of ciectric-hydraulic governor. ¢ Generator Control: — Speed Error — Speed Reference — Automatic Generation Control (AGC) — Over Speed - t — Under Speed - — Generator Droop ¢ The Kenai Power System: — The Daves Creek-University Line — Daves Creek SVC — Soldotna SVC — Soldotna One — Bernice Lake Power Plant — Soldotna- Bradley Line — Dimond Ridge Line Typical diagram of a Pelton Typical plan and profile of a High Head hydro power development ¢ Review of the Bradley Plant: — Lake & Dam — Turbine Pit — Power Tunnel — Buckets — Needles — Turbine Shaft — Deflectors — Generator — Jet Brake — Deflector vs. Power Curve Introduetio The project team has completed our = analysis of the problems associated with the Bradley Lake Plant. We have developed three alternatives to mitigate the problems. We’ve completed a preliminary economic analysis of the alternatives And, we’ve have a recommendation on how to proceed Bradley Instabil ity Study Final Report June 20,2000 Prepared by: Brian Hickey Randy Johnson Larry Hembree Agenda Item No. FL at Call yo t YES NO ABS CITY OF SEWARD 01% [1b MATANUSKA ELEC ASSOC 14% Tort CHUGACH ELEC ASSOC 30% [Z]_]_] HOMER ELEC ASSOC 1% (Z| GOLDEN VALELEC Assoc. 17% [7] 1] MUNI LIGHT & POWER 26% [i ALASKA ENERGY AUTHORITY A=4+ OVER 51% B=AEA CONCUR With A BRADLEY PMC VOTING == AS ars a iE] Te C = UNANIMOUS D= MAJORITY VOTING METHOD A: Requiring four yeas with 51% of utilities, with no AEA vote: 1) Procedures for scheduling, production and dispatch of project power. 2) Establishment of procedures for use of each purchaser's water allocation (AEA assent required for license requirements). 3) Selection among alternative methods that do not involve AEA for funding required project work. VOTING METHOD B: Requiring 4 yeas with 51% of utilities and AEA concurrence: 1) Arranging operation and maintenance of project. 2) Adoption of budget of annual project costs. VOTE(93Q3/BC5272) 3) Establishment of FY estimated annual payment obligation and schedule of each purchaser. 4) Determination of annual project costs after each FY. 5) Evaluation of necessity for and scheduling of required project work. 6) Determination of appropriate amount of insurance. 7) Adoption of additional minimum funding amounts for renewal and contingency reserve fund above that required by bond resolution. 8) Selection among alternate methods that involve AEA for funding required project work. 9) Adoption or amendment of procedural committee rules (except dispute resolution). 10) Adoption of project maintenance schedules. 11) Determination of rules, procedures and accounts necessary to manage project when no bonds outstanding. 12) Evaluation and approval of optional project work and compensation for such work. 13) Application of insurance claims proceeds not governed by bond resolution. 14) Approval of procedures and any individual utility agreements relating to electric power reserves for project. 15) Approval of consultants. VOTING METHOD C: Unanimous vote by all (including AEA) VOTING METHOD D: Majority vote (including AEA) Election of Officers Bradley Lake PROJECT MANAGEMENT COMMITTEE MEETING Tuecda de OL, (Date) Fek eConfevence. ~ dl3 Oy. Wort we Aipbs (Location) PLEASE SIGN IN No. NAME. | REPRESENTING S4ace LLL a Der. ANE AA DEA 5 Bi AAs pp Cc CHUGAC HE 6 ie L Loans Ohad 7 John S Coole Chugach | 8 | 9 | 10 11 12 13 ap 15 16 17 18 eel 19 | 20 1 | _— 22 92Q2\IT9884 ALASKA INDUSTRIAL DEVELOPMENT > ¢ AND EXPORT AUTHORITY {= ALASKA @e™ =ENERGY AUTHORITY 813 WEST NORTHERN LIGHTS BLVD. =¢ ANCHORAGE, ALASKA 99503 © 907/269-3000 © FAX 907/269-3044 TOLL FREE (ALASKA ONLY) 888 / 300-8534 BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE MEETING TELECONFERENCE AGENDA Tuesday, March 20, 2001 — 10:00 a.m. (Via electronic media at AIDEA/AEA — 813 W. Northern Lights Boulevard) 1. CALL TO ORDER \~ 7 Bjornstad 2. ROLL CALL (for Committee members) «~~ 3 PUBLIC ROLL CALL (for all others present) -~ 4, PUBLIC COMMENT - 5. AGENDA COMMENTS 6. | APPROVAL OF MEETING MINUTES — June 20, 2000 ~~ “4plowk oy <f Pow [S- 7. NEW BUSINESS ™ : orp B®. K-O¥07 2 Fivonciels 7 . —Pudeet ‘be ler we Bjornstad 8. COMMITTEE COMMENTS .—— =f A. Next Meeting Date —->, M+ver / | Ln Bjornstad w Ji 9. ADJOURNMENT Bradley Lake PMC Meeting Page 4 of 4 Tuesday, March 20, 2001 of the CRTs is no longer possible, thus, the recommendation that it receive a complete replacement. Telegear last year told HEA they would no longer provide replacement parts, and they don’t have any technicians to speak with. Mr. Nikkels asked if the replacement system would be a Harris system compatible with the Chugach/ML&P system? Mr. Stead stated that he didn’t think they had picked one, but HEA can write one in there as to what was wanted. MOTION: Don Stead motioned for the approval of the Fiscal Year 2002 budget, seconded by Michael Scott. A roll call vote was taken and the motion passed unanimously. 8. COMMITTEE COMMENTS A. Next Meeting Date = Bjornstad Next meeting date is at the call of the Chair, sometime in mid-June. 9. ADJOURNMENT MOTION: Mr. Scott moved to adjourn. Seconded by Mr. Stead. There being no objection and no further business of the Committee, the meeting was recessed at 11:00 a.m. —— ee 5 > A Tae -- — Bradley Lake PMC Meeting Page 3 of 4 Tuesday, March 20, 2001 software for CEA, GVEA, and ML&P will be implemented to return frequency to normal after an over-frequency event. Discussion followed on scheduling practices. There is a need to return to an agreement that was in place 4 or 5 years ago, where the participants did not make schedule changes beyond a half hour before the top of the hour. Chugach has relaxed scheduling requirements to allow schedule changes right before the top of the hour, and what that tends to do is have a number of dispatchers in the system trying to schedule units at the last minute causing the system to go into over-frequency events more frequently because of the lack of coordination. Chair Bjornstad asked if the O&D Committee had already discussed these items. Currently EPS is formally writing up the plan and then will send it to the O&D Committee for their approval and implementation. Chair Bjornstad said he wanted to see a write-up of what was just explained. Discussion followed on more technical concerns and operational procedures. Chair Bjornstad restated that he wanted to see a report in writing to better provide information to the PMC. Mr. Sieczkowski stated that at the February 26" teleconference, the O&D Committee discussed and recommends to the Budget Subcommittee and the Bradley PMC, that the fiscal year 2001 budget be adjusted by including an amount of $20,000 for replacing the three existing programmable logic controllers. It was also recommended that the fiscal year 2002 budget include an amount of $250,000 for replacing the existing Bradley Lake SCADA system to include new software, hardware, and installation of the SCADA system. 7B. Fiscal Year 1999 and Year 2000 Audited Financials - Applegate MOTION: Chair Bjornstad entertained a motion of the committee members to approve the Fiscal Year 1999 and Year 2000 Audited Financials. Michael Scott moved, seconded by Don Stead. Chair Bjornstad also noted that they will spend $20,000 additional in the Fiscal Year 2001 for three PLCs. Hearing no objection, the financials were unanimously approved. 7C. Budget 2002 — Sieczkowski Chair Bjornstad asked Mr. Sieczkowski if the O&D Committee is requesting an additional $250,000 to replace the SCADA system software and hardware. Mr. Sieczkowski noted that was correct. Mr. Sieczkowski noted that it is a total replacement of the SCADA system. Don Stead stated that Telegear, who provided the system originally, has ceased production of all spare parts. The only way to get spares now for that system is through salvaging them from other used systems. The Bernulli drives, a tape drive used to transfer data, are no longer manufactured; and in fact, HEA has to go to surplus sites to ask them if they have Bernulli tapes. Replacement Bradley Lake PMC Meeting Page 2 of 4 Tuesday, March 20, 2001 4. PUBLIC COMMENT There were no public comments. 5. AGENDA COMMENTS Chair Bjornstad added the two items to the agenda. Item A will be a report and recommendation from Stan Sieczkowski from the O&D Committee. Item B will be the Fiscal Year 99-2000 Audited Financials and Item C will be the Budget for 2002. There was no objection to adding these items to the agenda. 6. APPROVAL OF MEETING MINUTES ~ June 20, 2000 MOTION: Mr. Stead moved to approve the meeting minutes of June 20, 2000. Mr. Sieczkowski seconded the motion. Mr. Hickey noted a change on page 3 of 7, paragraph 4, change the third sentence to read — Units with small droop percentages will pick up more load faster than units with large droop percentages. Page 4 of 7, paragraph 1, the last three words “where it was,” should be “nominal.” The end of paragraph 6, titled Answers, should read “generated by the deflector and turbulence in the turbine pit.” Page 5 of 7, the first paragraph should begin “...The original PTI model...”. Paragraph 5, titled Answers, should end “... for a step speed error input.” A voice vote was taken and the minutes were unanimously approved as amended. 7. NEW BUSINESS 7A. O&D Committee Report — Sieczkowski Mr. Sieczkowski stated that the Bradley O&D Committee met on September 27, 2000, February 14, 2001, and February 26, 2001. Mr. Stead noted that all the maintenance is current on the unit and are currently preparing for the outage, which will occur on April 6". Mr. Cooley added that both units are operating normally. HEA had repaired a PLC in one unit about a month ago. There was a reduction in the allocations in October of about 45,000 MWH for the project. Mr. Sieczkowski also noted that at the February 26" meeting the O&D Committee discussed the governor instability project. FERC has requested us to file an amendment to the project license to the Nuka Diversion repairs. A letter was sent back to FERC asking them to reconsider. Brian Hickey spoke on the governor instability project. He noted that the last quarterly update he did for the project was the one that occurred on the 2™ of January. There will be another update to the schedule and the actual accounting side of it at the end of this month. The major issue that has come up is Item #1, Design and Implementation of the Interim Instability Mitigation. Last August a decision was made by the O&D Committee to not proceed with it. In the interim, the cost of manning the plant has become unacceptable. By the end of May, HEA should be able to stop manning the plant. Brian Hickey and the project consultant (EPS) came up with several measures that the O&D Committee believe will allow HEA to stop manning the plant. Three modifications to the AGC BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE MEETING MINUTES TELECONFERENCE Via Electronic Media @ AIDEA 813 W. Northern Lights Boulevard Anchorage, Alaska Tuesday, March 20, 2001 — 10:00 a.m. 1. ALL TO ORDE Chairman Eugene Bjornstad called the meeting of the Bradley Lake Hydroelectric Project Management Committee to order at 10:00 a.m. on Tuesday, March 20, 2001, from the Alaska Industrial Development and Export Authority's Board Room, Anchorage, Alaska, to conduct the business of the Committee per the agenda and public notice. 2. ROLL CALL Roll was called by Shauna Dean. The following members were present: Gene Bjornstad Chugach Electric Association Wayne Carmony Matanuska Electric Association (teleconference) Norm Story Homer Electric Association (teleconference) Steve Haagenson Golden Valley Electric Association (teleconference) Stan Sieczkowski Alaska Energy Authority Michael Scott Anchorage Municipal Light & Power (teleconference) Dave Calvert City of Seward (teleconference) 3. PUBLIC ROLL CALL Shauna Dean, Alaska Energy Authority Brenda Applegate, Alaska Energy Authority Don Stead, Homer Electric Association (teleconference) Brian Hickey, Chugach Electric Association John Cooley, Chugach Electric Association Mike Cunningham, Chugach Electric Association Hank Nikkels, Anchorage Municipal Light & Power (teleconference) Kate Lamal, Golden Valley Electric Association (teleconference) Ron Saxton, AterWynne LLP (teleconference) i ALASKA INDUSTRIAL DEVELOPMENT =, AND EXPORT AUTHORITY {= ALASKA @@m =ENERGY AUTHORITY 813 WEST NORTHERN LIGHTS BLVD. ¢ ANCHORAGE, ALASKA 99503 ¢ 907/269-3000 ¢ FAX 907 / 269-3044 TOLL FREE (ALASKA ONLY) 888 / 300-8534 ALASKA ENERGY AUTHORITY/ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY Public Notice Bradley Lake Project Management Committee Notice is hereby given that the Bradley Lake Project Management Committee will hold a regular meeting VIA TELECONFERENCE on Tuesday, March 20, 2001, at 10:00 a.m. This meeting will be conducted by electronic media at the following location: Alaska Industrial Development and Export Authority, 813 W. Northern Lights Boulevard, Anchorage, Alaska. For additional information, contact Eugene Bjornstad, Chairman, Chugach Electric Association, 5601 Minnesota Drive, Anchorage, Alaska 99503. The State of Alaska (AIDEA), complies with Title II of the Americans with Disabilities Act of 1990. Disabled persons requiring special modifications to participate should contact AIDEA staff at (907) 269-3000 to make special arrangements. /s/ Alaska Energy Authority Project Management Committee Publish: Thursday, March 15, 2001