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HomeMy WebLinkAboutCopper Valler Negotiations 1995nil NUV7U9790 IMU VOI4 INSIDE PAGE 2 A win-win deal Safety Bear Buddy Indian transformer PAGE 3 Board viewpoint a ny 2 AW YuVI News notes *Do we have your number? Chugach is increasingly taking advantage of new technologies to provide better outage Teporting and other customer services. However, in order for these systems to work for you, Chugach needs to have your current phone number. Check the number we have printed on your bill. If it’s not right (or blank) please provide an updated number on the portion of the bill you return with your payment. *The regulatory cost charge reappears effective with October bills. This is the fee collected from customers of all Tegulated Alaska utilities (not just electric utilities) to fund the operations of the Alaska Public Utilities Commission. The RCC adds 24 cents to the average bill for 750 kwh of residential service. * The retail and wholesale fuel surcharges decreased with October bills. The quarterly adjustment recovers the costs (both actual and anticipated) of fuel and purchased power expenses over and above the amounts recovered in the basic kilowart-hour rate. The fuel adjustment can (and usually dees) vary each quarter. The October decrease means that for the next three months the average monthly residential bill for 750 kwh of service will see News notes, page 2 | norrnifh rna We OU Chugach and Copper Valley Electric Association have been working out the details of a power sales agreement which would provide a firm, reliable source of economical electricity for CVEA customers well into the next century, Economical electric service is important to Copper Valley customers, who pay approximately twice as much for power as Railbelt Alaskans. The proposal would also benefit current retail and wholesale Chugach customers by spreading costs over a larger customer base. Still, before any power can flow from the Railbelt to the Copper River Basin, a transmission line must first be completed between Sutton and Glennallen, At the end of September, CVEA‘s plans to build a 138,000-volt transmission line to link its customers to the state’s major power grid were on hold while a panel appointed by Gov. Tony Knowles reviewed the project. In 1993, the Legislature authorized and appropriated $35 million to be used as a 2ero-interest, 50-year loan to CVEA to help construct the line, The Legislature also authorized the Alaska Industrial Development and Export Authority to issue up to $25 miilion in bonds to provide additional funding for the project. The legislation made the loan subject to an independent feasibility study of the project, which was completed in April 1994 for the Department of Community and Regional Affairs, Division of Energy. In July 1994, the DCRA Commissioner cvo 4910 reuc | @Q=". Chugach and Gopper Valley developing power sales agreement Chugach and C Association have { arrangemest to lin Railbelt po arid. found the project could be financed and was economically bl However, to date the loan been made. In May 1995, Gov. Tony Knowles appointed an Interagency Review Pane! to take another look at the feasibility study. The three-agency panel is comprised of the commissioners of DCRA and the Department of Natural Resources and the executive director of AIDEA. The InU UIelV Md NUV~US~ 90 tad Working on a win-win deai For the past year, Chugach’s Management team has been discussing how to provide electrical power to Copper Valley Electric Association in Glennallen. Today, Copper Valley has the highest unsubsidized retail electric rates in the state and doés not receive any power cost equalization funds from the State. During the 1993 legislative session, Copper Valley was authorized to receive an interest-free $35 million loan to construct an intertie between the Railbelt electrical system and the Glennallen-Valdez network. Clearly, connecting Copper Valley to ny Oo MU UUVI Manager's message norrninw rnaA NU the Railbelt grid will be a great benefit to their area. However, you may wonder what it does for Chugach customers. The easy answer is that we sell more power and spread costs over a greater number of kilowatt-hours; hence, the cosi-burden per unit of output is less. A broader perspective would see greater economic activity as a result of cheaper energy prices. More economic activity contributes to the overall good of Alaska’s citizens. This is why this intertie project takes good sense. While Chugach and Copper Valley are in the final stages of consummating a gUI CUO News notes, continued from page 1 be $1.84 lower than it has been during the past quarter. * October is national cooperative month. Chugach is organized as an electri¢ cooperative, owned by its more than 50,000 members, There are approximately 1,000 electric cooperatives nationwide, As co-op members. Chugach customers elect a board of directors to set policy for the Uaceenenene a utility and share in any margins earned by the organization through the “capital credits” pragram, «Remember, Outlet readers can ean $50 if they find their member number in the newsletter. Each month three member numbers are inserted into the copy. Ifyou find a member number in brackets {} which matches the member number on your bill, call our service center at 563-7366. Safety Bear Buddy Chugach is one of several utilities participating in a statewide Safety Bear Buddy program. The program lets kids in trouble know they can approach specially-marked, radio-equipped utility vehicles and ask for help. Utility employees will radio for assistance and stand by until the proper authorities arrive. The Safety Bear Buddy program started in 1989 and now has 33 companies statewide participating using special {76137} vehicles which are on the streets every day to help out kids, and sometimes adults. This past January an Anchorage People Mover bus driver helped two young children who had been locked out of their home. Children in trouble should think of safety first when looking for help. Stress these safety tips to your child: Safetye Fy Bear ay Buddy: Never dash across the street without looking for oncoming traffic. Obey traffic safety rules. Stop. Look left, Tight, left and make sure it’s clear before crossing the street. Utility workers in the field or on the roadside may be in a potentially dangerous area. Be aware of your surroundings before approaching them. Be careful when you're in construction sites or around utility operations. Do not touch the utility truck. It may be attached to a high voltage line. Call the driver and wave your arms over your head to get their attention —— approaching. Always use common sense. I pays to be careful, especially during times of emergency. | \ i | | | i | | | | 4910 power sales agreement that would involve the construction of the intertie to Glennalien, the project still needs a final review. The governor has convened a group of knowledgeable people to take another look ar the viability of the projeut before tne loan is made. Tam optimistic thet the governor will make the right decision and allow the project to proceed. Certainly, it cannot fail to contribute favorably to Alaska’s economy: Bre MN. sc ine Making a move Chugach cr , along with Revmolds Rigging and Lynden Transport, moved a new 58,000-pound transformer into the India: Substation in August. Tests had shown the old transformer in the substation wes failing and it was necessary 10 replace it, Crews installed a mobile sisbstirtion ro provide electrical s whiig the transformer exchange took place. NUV-UY-¥YO IHU UY! lo AM Power sales, continued from page 1 panel is reportedly nearing the end of its review. In the meantime, Chugach and Copper Valley have been working out the details of a contract to ensure a long-term, reliable source of reasonably-priced power for CVEA. Chugach was selected as the preferred provider for CVEA after a review of power supply proposals submitted last year. Here are some of the points Contained in the preliminary power sales agreement: *Chugach would supply all the power required by CVEA over and above the output of the Solomon Gulch hydroelectric project at Valdez. While CVEA is obligated by contract to take the output of the State-owned hydro facility, Solomon Gulch only provides about 60 percent of the power required by CVEA in an average year. Wholesale power from Chugach would be much cheaper than the supplemental power CVEA now produces with its diesel generators. *CVEA could buy as much power as it wants from Chugach, subject to the carrying capacity of the planned transmission line, *A portion of the cost of the transmission line would be shared by Chugach and its other wholesale customers, Individual wholesale customers would have the option to opt out of the shared costs of the line, but in so doing would also forfeit the savings {167106} realized by adding CVEA as another Chugach customer. *CVEA would have the option of becoming an “all-requirements” customer of Chugach‘s at some point in the future. Under that arrangement Solomon Gulch would be pooled with other Chugach generation resources and Chugach would plan for and instal! generation (if necessary) to meet all of Copper Valley's needs. *CVEA would be eligible to earn capital credits on its power purchases from Chugach. In the past two years Chugach has returned nearly $5 million in capital credits to its wholesale customers. Chugach is Alaska’s largest Au’ > ANU LUV] APFALKS FAX NU. YUS cob 49/8 P, U4 COMPETITION! Everyone knows that competition is what gets consumers the best deal in their purchases whether it be groceries or airline tickets. What would happen to food prices if there was only one grocery store? What about electric service? Presently, you have no choice but to buy your power from Chugach Electric Association if you live in the service area. There is little competition for your consumer dollar. Lacking that competition, your board of directors is the group of men and women who represent you, the ratepayer, ina “watchdog” capacity in the effort to keep rates down while providing safe, reliable power. Because our fuel is ' some of the least expensive in the | country, Chugach rates are essentially the lowest in Alaska. However, they are only at about the national average. If there were retail competition, would these rates be lower? Are you teceiving the best VALUE from YOUR | cooperative when you pay your electric bill? To answer these questions, Chugach has joined a group of 24 of the largest electric co-ops in one of the most extensive “benchmarking” efforts ever done. Benchmarking is a reliable way of measuring our ! performance against the best practices of other electric utilities. This study is being performed by a leading utilities | management consultant for NRECA, | the National Rural Electric Cooperative electric supplier, providing wholesale and economy energy power to utilities from Homer to Fairbanks and retail electric service to 65,000 metered locations from Anchorage to the northern Kenai Peninsula. Chugach owns and operates three natural gas- fired power plants and one hydroelectric facility, and also takes power under conuact from two additional hydro projects. LT Ch ee a" Pend (gest Prete Association, It will give us detailed information on where we are and where we need to improve in order 16 achieve the new joint staff-board goal of being at the top of all-electric co-ops and investor-owned utilities in economic efficiency. Results and progress will be shared with you in future Outlets. COST SAVING MEASURE - Your board is working with management in many areas to lower costs and your rates. Recently Chugach was faced with two alternatives in the disposal of obsolete turbines at Beluga and at Bernice Lake. If we removed the units and disposed of them through surplus means, we would likely have expended numerous resources and expense in the disposal process. On the other hand, Chugach chose to advertise the retired units for sale, and ended up receiving $60,000 for the units. The buyer also agreed to remove the units and be responsible for asbestos abatement. These innovative methods benefit the cooperative and help keep your rates low. As a result of this action, the IBEW Union has filed a grievance alleging violation of their Chugach labor contract. An arbitrator has been selected who may ultimately decide the issue. We'll keep you posted. Pay Kop CVEA is also a member-owned electric cooperative, It provides service to 3.000 metered locations serving approximately 8,000 people from Valdez north past Glennallen and west along the Glenn Highway. CVEA currently uses the Solomon Gulch project and aging diesel generators at Valdez and Glennallen to meet the demands of its customers. af’: Ae rp PETRO T rPAR VALDEZ RI INERY ~~ A JOINT VENTURE Telephone. (907) 344-2601 201 Arotio Slope Avenue, Suite 200 Fax (907) 267-6479 Anchorage, Alaska 89518-3030 November 8, 1995 Mr. William R. Snell Director AIDEA 490 W. Tudor Rd. Anchorage, AK 99503-6690 Re: Intertie Negotiations Dear Riley: I am pleased to confirm that Petro Star Valdez Refinery has finalized the attached Memorandum of Understanding with Copper Valley Electric Association, Inc., and Chugach Electric Association, Inc. As stated in the Memorandum itself, the agreement is subject to approval by the boards of directors of the two utilities. However, I am at the present time optimistic that these approvals will be forthcoming later this month. We are confident that the Sutton-Glennallen intertie will achieve substantial benefits for the Copper Valley basin and Alaska and that it is necessary for the orderly development of the region as we move into the twenty-first century. Consequently, we strongly support approval of the intertie loan by the Governor. Please give me a call if you have any comments or questions. Sincerely, eel Stephen T. Lewis Chairman of the Management Committee Petro Star Valdez Refinery ce: Mr. Jim Ayers The Hon. Ramona Barnes The Hon. Georgiana Lincoln The Hon. Gene Kubina Mr. Clayton Hurless (w/o attachment) Mr. Eugene N. Bjornstad, P.E. (w/o attachment) Sas) SEDs ) Talephone: (907) 244-2001 Arctic Slope Avanuc, Suite 200 vy ” Fax (807) 267 uaag whnraye, Alasks GU518-aQU0 STEPHEN T. LEWIS Chairman / G F.O. October 25, 1995 Mr. Clayton Hurless General Manager Copper Valley Electric Ass’n P.O. Box 45 Glennallen, Alaska 99588 Mr. Eugene N. Bjornstad, P.E. General Manager Chugach Electric Ass‘n, Inc. P.O. Box 196300 Anchorage, AK 99519-6300 Re: ntertie Ne ns Gentlemen: My recent conversations with Riley Snell indicate that the Governor may reach a decision regarding the Sutton - Glennallen intertie this week. My staff has advised me of the status of discussions between your utilities and Petro Star, and I am heartened that it appears that there are no obstacles in principle to an agreement. However, I am not at all satisfied with the progress that has been made towards a concrete agreement that will protect Petro Star’s interests. Our companies have been meeting for well over a month, and we have yet to see any numbers attached to the proposal that you made in mid-September. As the issues have been outlined to me, there does not seem to be any reason that an agreement cannot be reached at the meeting now scheduled for this coming Monday afternoon. It will greatly facilitate matters if you can provide us with your projections of future power costs in advance of the meeting. My staff will have full authority at the meeting and will be directed to exert themselves to reach a satisfactory agreement. I am hopeful that the Governor’s decision can be put off until after the Monday meeting, and that our discussions can be brought A Subsidiary of Arctic Slope Megronal Compurarion - Mr. Eugene N. Bjo: tad Mr. Clayton Hurle October 25, 1995 Page 2 of 2 to a successful conclusion. It continues to be my desire to work as closely as possible with you in support of the ints+tie. However, I am concerned about misleading Mr. Snell and the Governor about Petro Star’s intentions. Therefore, I want to be on record that unless an agreement can be reached on Monday, Petro Star will move forward and install cogeneration capability in Valdez to produce all of its current and future power needs. Please give either me or Mike Craig a call if you have any comments or questions. ‘ Sincerely, Stephen Ts Chairman of the Management Committee Petro Star Valdez Refinery cc: Mr. Riley Snell, AIDEA Mr. Jim Ayers The Hon. Ramona Barnes The Hon. Georgiana Lincoln The Hon. Gene Kubina MEMORANDUM OF UNDERSTANDING AMONG COPPER VALLEY ELECTRIC ASSOCIATION, INC. PETRO STAR VALDEZ REFINERY AND CHUGACH ELECTRIC ASSOCIATION, INC. A. PARTIES The Parties to this Memorandum Of Understanding ("MOU") are Copper Valley Electric Association, Inc. ("CVEA"), Petro Star Valdez Refinery ("PSVR"), and Chugach Electric Association, Inc. ("Chugach") . B. PURPOSE The purpose of this MOU is to set forth an agreement in prin- ciple among the Parties on the basic terms of two contracts: (1) a Power Sales Contract ("Power Contract"), under which CVEA will deliver and sell, and PSVR will receive and purchase, electric power at PSVR's facilities in Valdez, Alaska, and (2) a Cogenera- CHUGACH/CVEA/PETROSTAR MEM. OF UNDERSTANDING -- PAGE 1 tion Deferral Contract, under which CVEA and Chugach will share the cost of assuring PSVR of the rates specified under the terms and conditions, and for the purposes, described in this MOU. Cc. CONTEXT OF MOU & CONDITION PRECEDENT TO ITS EFFECTIVENESS The power sales transaction contemplated by this MOU depends on construction of an electric power transmission line (the "CVEA Intertie") between Sutton, Alaska, and Glennallen, Alaska. The CVEA Intertie is necessary in order to allow electric power gener- ated on Chugach's system to be delivered to CVEA for resale to CVEA's consumers, including PSVR. Purchasing power from Chugach will reduce CVEA's power costs substantially. Such purchases are necessary if CVEA is to sell power to PSVR at rates acceptable to PSVR. If the CVEA Intertie is built, then PSVR will be able to purchase electric power from CVEA and meet its load requirements under the terms of the Power Contract, as further described below. If the CVEA Intertie is not built, however, then it is PSVR's intention to proceed immediately with installation of its own cogeneration equipment at its Valdez facilities in order to meet all or a portion of its electric power load requirements from its own generation in the reasonably near future. CHUGACH/CVEA/PETROSTAR MEM. OF UNDERSTANDING -- PAGE 2 Currently, the State of Alaska is formally reviewing whether to proceed with a legislatively approved $35,000,000 loan to aid construction of the CVEA Intertie. The Parties agree that the CVEA Intertie will not be built in time to allow PSVR to defer installa- tion of its cogeneration equipment unless the State decides to proceed with this loan. The State's decision is expected no later than November 1, 1995. PSVR cannot reasonably delay beyond December 31, 1995 its own commitment to begin the process of in- stalling its cogeneration equipment. Consequently, the Parties agree that the State's decision, on or before December 31, 1995, to proceed with the legislatively approved $35,000,000 loan for the CVEA Intertie shall be a condi- tion precedent to the obligations of any Party under this MOU. No Party will otherwise be bound by this MOU beyond that date. If the State does decide by such date to proceed with the loan, then the Parties will be bound by the MOU and will proceed promptly and in good faith to draft, execute, and seek any neces- sary approvals of the contracts that the MOU contemplates. 1. From and after the date on which the CVEA Intertie com- mences commercial operation, and for a period of ten years thereaf- ter, the Power Contract will obligate CVEA to deliver and sell, and CHUGACH/CVEA/PETROSTAR MEM. OF UNDERSTANDING -- PAGE 3 PSVR to receive and purchase, electric power to meet one hundred percent (100%) of PSVR's electric power load requirements for its facilities at Valdez. 2. The Power Contract will obligate CVEA to make rates for PSVR on a Chugach system average cost of power pass-through basis (for energy and demand) as described below. The Power Contract will specify separate charges for demand (capacity) and energy, in order to give PSVR the financial benefit of its own load factor. In particular: (a) CVEA's "base cost" for ratemaking purposes for electric capacity (kilowatts) sold to PSVR will be CVEA's cost of capacity purchased from Chugach but will not include any special initial demand ramp to which CVEA and Chugach may agree. (b) CVEA's "base cost" for ratemaking purposes for electric energy (kilowatthours) sold to PSVR will be CVEA's cost of energy (including the Chugach Fuel Surcharge and MEA wheeling rate) purchased from Chugach. (c) The margin or markup that CVEA adds to the base costs of capacity and energy in making retail rates for PSVR will Pere kur be 2.1 cents,in 1995 dollars. Ex oe CHUGACH/CVEA/PETROSTAR MEM. OF UNDERSTANDING -- PAGE 4 Br In addition to the foregoing economic terms and condi- tions, the Power Contract will also contain provisions governing all other matters customarily dealt with in contracts between utilities and major industrial customers. E. 1. The CVEA Intertie will allow PSVR to achieve cost savings under the terms of the Power Contract once Chugach power begins to flow to CVEA. The Parties currently estimate that the CVEA Inter- tie will require at least three years to complete, however. In the interim, the difference between PSVR's current costs of electric power from CVEA and the cost at which PSVR could cogenerate and meet its own power supply needs is such that PSVR would otherwise proceed to install cogeneration equipment, but for the Cogeneration Deferral Contract described herein. If PSVR's cogeneration equip- ment is installed, the opportunity to make significant power sales to PSVR (and hence to use the CVEA Intertie to produce additional economic benefits for other CVEA and Chugach ratepayers) will almost certainly be lost. 26 The purpose of the Cogeneration Deferral Contract is therefore to create conditions under which it will be in PSVR's interest not to install cogeneration equipment, at least until the CVEA Intertie is complete. Under the Cogeneration Deferral Con- CHUGACH/CVEA/PETROSTAR MEM. OF UNDERSTANDING -- PAGE 5 tract, CVEA will provide electric power, the average cost of which per kwh will not exceed 8 cents while the CVEA Intertie is under construction. (The existing CVEA-PSVR power sales agreement will be extended, if necessary, until the CVEA Intertie is completed.) PSVR will be entitled to this rate beginning August 1, 1996 but not sooner than Necessary Approvals have been obtained. However, CVEA and Chugach shall have the right to terminate this rate reduction for PSVR by notifying PSVR that CVEA and Chugach no longer wish for PSVR to defer cogeneration or by notifying PSVR of their intent to abandon construction of the CVEA Intertie, in which event the rate reduction to PSVR shall cease on the earliest of: 1) 9 months after the first November 1st date after notice is given of intent to abandon construction of the CVEA Intertie; or 2) the date PSVR installs its cogeneration project which PSVR has a duty to attempt to install as soon as reasonably possible after notice. hie PSVR shall provide acceptable guarantees from the parent company of its majority shareholder to guarantee its obligations under this Memorandum of Understanding, the Power Contract, and the Cogeneration Deferral Contract. E. RIGHT TO CALL’ ON PSVR TO INSTALL COGENERATION The parties agree that development of cogeneration at the PSVR site may be desirable at some future date,’and agree that prior to CHUGACH/CVEA/PETROSTAR MEM. OF UNDERSTANDING -- PAGE 6 PSVR proceeding to develop any cogeneration, CVEA and Chugach shall have a first right of refusal to participate in such cogeneration facility on a basis in which CVEA and Chugach shall receive the benefits of such facility in proportion to any investment. G. NECESSARY APPROVALS Both the Power Contract and the Cogeneration Deferral Contract will be subject to all necessary approvals, including but not limited to that of the Alaska Public Utilities Commission ("APUC"). CHUGACH/CVEA/PETROSTAR MEM. OF UNDERSTANDING -- PAGE 7 This MOU represents the position of the representatives of the Parties, which such representatives agree to recommend to their respective governing boards for approval. The MOU shall not bind any Party until that Party's governing board has approved it. IN WITNESS WHEREOF the Parties hereto have executed this Memorandum of Understanding on October 3\, 1995. CHUGACH ELECTRIC ASSOCIATION, COPPER VALLEY ELECTRIC INC. ASSOCIATION, INC. By: : - Title: PETRO STAR VALDEZ REFINERY CHUGACH/CVEA/PETROSTAR MEM. OF UNDERSTANDING -- PAGE 8 WHITEWATER ENGINEERING CORPORATION aH 1050 RRABEE AVE., SUITE 1€ 707 BELLINGHAM, WA 98225 Ph. (360) 733-3008, FAX (360) 733-3056 DATE: October 30, 1995 FE A x FROM: Thom A. Fischer COVER SHEET TO: Dennis McCrohan COMPANY: AIDEA PHONE: 1-907-561-8050 NOTE: Enclosed is a proposal to have your consultant, CH2M Hill look at Silver Lake. If it is determined that the intertie is not feasible. then the $35,000,000 should stay in the Copper Valley/Cordova region for energy projects and not dispersed throughout the State. I-feel that if the intertie fails to be determined feasible. then the Legislature might move in favor of spending the $35,000,000 in committed funds on constructing Silver Lake for CVEA. wt “an / Ne [craw Wa\l NUMBER OF PAGES (including this one): 2) RECEIVER'S FAX NUMBER: 1-907-561-8998 10590 October 30, 1995 Mike Irwin, Commissioner of DCRA W. Riley Snell, Director AIDEA John Shively, Commissioner DNR SUBJECT: Sutton-Glennallen Intertie - Energy for CVEA Over the past 3 years, our company, Whitewater Engineering Corporation, has been observing with great interest the on-going studies conducted on the Sutton- Glennallen Intertic. We have been supportive of the intertie as an effective way of supplying energy to the Copper Valley region. However, as construction and environmental costs escalate, the benefits of developing local hydropower at Silver Lake are fast outweighing the benefits of the intertie. We now strongly believe that Silver Lake would provide the lowest cost energy and also be the most reliable energy source for Copper Valley. We urge you to extend the CH2M Hill report for 30 days to give this alternative due consideration. We have recently concluded that it will cost $40,000,000 to license, design and construct the Silver Lake Hydroelectric Project including the submarine transmission line, contingencies and interest during construction. The Project will produce about 45,000,000 kilowatt hours per year, utilizing Silver Lake almost exclusively as storage for winter energy for CVEA, while Solomon Gulch produces the summer energy. The Project would produce more energy than 45,000,000 kWh under a more level load condition. If the Silver Lake Project were funded with a $35,000,000 zero interest, 50 year loan, and a $5,000,000 seven percent interest, 20 year loan for the balance, the energy rate from the Project would be $.049/kWh (4.9 cents per kilowatt hour), including debt service and annual operations & maintenance. This $40,000,000 figure is about 35% less than the figures published in recent CVEA energy related studies. This is due to references back to the 1982 Stone and Webster study on Silver Lake, which concluded it would cost $64,000,000 to construct the project. Unfortunately, the 1992 Allison Lake study by HDR Engineering, Inc. and the soon to be published study by CH2M Hill essentially uses cost estimates from the Stone and Webster study. We find it important that CH2M Hill have the opportunity to not only look at the true cost of constructing the intertie, but also look at the true cost of constructing Silver Lake. engineering W H I al EWAT E R corporation LARRABEE AVENUE © SUITE #104-707 * BELLINGHAM, WA * 98225 C3603) (7353/0089) PAX!) | 03/610!) 7353056 ik as Cveeke : Frkau Pew corte 4 CRE Lp vt yop Tow Sotlon IC bennett “ \0 el cealwer © Qa panne _ prt % rPUC opened - sebjet % — lov sfhe os Some tg - ten f anhead op Gea, hf Sete . patio Sm ~ eT por qanbere 2¢ -weh 7F ry nad Qa} reer rtrd CG) Tend) Sore HO ere The Stone and Webster study was performed in the early 1980’s when the state of Alaska had excess oil revenues, and was constructing large hydropower projects such as the Four Dam Pool and Bradley Lake. Silver Lake and Black Bear Lake were two of the projects the State proposed to build. At that time, Silver Lake was estimated at $64,000,000 and Black Bear Lake was estimated at $30,000,000 to $60,000,000. Our firm just completed the final civil design and construction of the Black Bear Lake Hydroelectric Project for Alaska Power and Telephone. The 5 MW Black Bear Lake project cost under $12,000,000 including licensing, design, construction, 15 miles of transmission and interest during construction. This new project has the same plant capacity as the more expensive State proposals, but it was designed with cost in mind, Silver Lake is no different. Our firm can construct a project at Silver Lake that can produce 45,000,000 kWh of firm winter energy for $40,000,000. Other alternatives include eliminating the 100° high dam and utilizing a siphon similar to the Black Bear Lake Project. We estimate that Silver Lake would produce 36,000,000 kWh without the dam, but will cost substantially less. Silver Lake could also be constructed in phases to meet CVEA’s energy requirements (construct the dam later). We believe that Silver Lake would cost less to construct than the intertie, and at the same time, there would not be the added cost of purchasing energy from the Rail Belt. We understand that this information is coming to you at a late date with regard to your decision process. -This decision will significantly affect the Copper Valley region over the next 50 years. Therefore, we are requesting that you extend the CH2M Hill report for 30 days and have either CH2M Hill or R.W. Beck perform an in-depth construction cost study on Silver Lake utilizing current construction methods. Sincerely, Te dV. ~ Thom A. Fischer, P.E. President, WEC cc Clayton Hurless, General Manager CVEA Dennis McCrohan, AIDEA Dave Gray, CH2M Hill Page 2 of 2 TOTAL P.@3 i ALASKA INDUSTRIAL DEVELOPMENT AND EXPORT AUTHORITY {= ALASKA @@E™_ ENERGY AUTHORITY 480 WEST TUDOR ANCHORAGE, ALASKA 99503 907 / 561-8050 FAX 907 /561-8998 MEMORANDUM TO: Riley <AihsD FROM: je Dennis DATE: August 31, 1995 SUBJECT: | Comments on CEA/CVEA Proposed Agreement The Agreement simply states some general terms for a Power Sales Agreement between CVEA and CEA. It also defines similar terms which both CEA and CVEA agree for a Power Sales Agreement between CVEA and Petro. Star. It provides several critical agreements as follows: defines the 80/20 sharing of supplemental costs between CEA and CVEA. ee a deferral payment scheme to Petro Star which provides incentive for Petro Star to remain on the system during the interim until Pain is complete. e integrates CVEA, excluding Solomon Gulch, into the Railbelt rate structure and allows for a future option to include Solomon Gulch. Specific comments are provided below. The items numbered refer to notes on the attachment. Contract Proposal 1. Rates. This clause allows CVEA to participate in the overall Railbelt rate structure, excluding Solomon Gulch, which is covered by the Four Dam Pool structure. It gives CVEA standing in the Railbelt. 2. Net Requirements. This clause sets out the CEA obligation to provide energy to the CVEA, excluding what energy is provided by Solomon Gulch. 3. All Requirements(Option). This option appears to allow Solomon Gulch to be included in the overall Railbelt rate structure at the option of CVEA. This would be beneficial if energy were to be flowing to the Railbelt from Solomon Gulch. 4. Wheeling. I do not understand this clause which states CVEA will provide power to CEA. I would anticipate that CEA would provide energy to CVEA at Glennallen. If this is the intent, it appears that wheeling losses are to CEA’s account which makes sense, particularly if CEA is to Operate and Maintain the line. 5. Point of Delivery. Delivery at Glennallen makes most sense if CEA is the O&M contractor for the line. Is this their intent? Letter of Understanding 1. Page 2. Paragraph 3. The letter names 8 cents per KWH as the trigger point. 2. Page 3. Paragraph 3. The letter provides for Petro Star to sell power which is certain to be uneconomic at the avoided cost levels if the Intertie is built. 3. Page 3. Paragraph. 4. This paragraph memorializes that Petro Star will receive the benefits of the Railbelt rates if the Intertie is built. 4. Page 3. Paragraph 5. This is the “bone to Petro Star’. It says that a deferral payment will be agreed, presumably based on Petro Star cogeneration plant costs, which will be provided to Petro Star during the interim between January 1, 1998 and when the Intertie is complete. Petro Star will want an earlier date since their generation could be on line by the end of 1996. Second, Petro Star may not agree to the basis for calculation of the deferral payment. h:\all\dennis\aidea\cvea 1 = Rods CHUGACH ELECTRIC ASSOCIATION, INC. ASSOCIATION, INC. EUGENE N. BJORNSTAD, P.E. General Manager August 30, 1995 Mr. Dennis McCrohan AIDEA 480 West Tudor Anchorage, Alaska 99503 Dear Mr. McCrohan: Chugach and Copper Valley Electric Association (CVEA), have been discussing and negotiating a possible powers sales agreement. Critical to this power sales agreement is the proposed Sutton to Glennallen Intertie. It is our understanding that a report will be completed in the very near future and transmitted to the committee composed of officials from Department of Community and Regional Affairs (DCRA), Department of Natural Resources (DNR) and Alaska Industrial Development and Export Authority (AIDEA). The report will contain a recommendation and new review of the feasibility of the intertie. Chugach and CVEA have also been discussing the future power supply options for Petro Star’s refinery in Valdez. We believe there can be significant progress in the discussions between our utilities and Petro Star, which will strengthen the rationale and need for the intertie. To demonstrate the seriousness of our respective utilities’ interest in entering into a contractual agreement, the outline of principles of a contract and a memorandum of understanding between Chugach and CVEA regarding service to Petro Star and the utilities, are attached for your review and consideration. It is our intent to incorporate more details into a draft agreement which would be submitted to our respective Boards of Directors for approval and then to the Alaska Public Utilities Commission. We respectfully urge consideration of the progress we have made and recommend that the report being finalized support the intertie connection between the consumers of Copper Valley Electric Association and the Anchorage utility grid. Sincerely, Teg pp set Kip Moh — Eugene N. Bjornstad Clayton Hurless General Manager General Manager Chugach Electric Association, Inc. Copper Valley Electric Association, Inc. 5601 Minnesota Drive ¢ P.O. Box 196300 * Anchorage, Alaska 99519-6300 Phone 907-563-7494 © FAX 907-562-0027 LETTER OF UNDERSTANDING August 30, 1995 PURPOSE This Letter of Understanding (LOU) is to memorialize the understanding between Chugach Electric Association, Inc. (Chugach) and Copper Valley Electric Association, Inc. (CVEA) relative to the purchase by Petro Star and the sale by CVEA of the electric power requirement of Petro Star’s Valdez oil refinery. PARTIES PETRO STAR Petro Star owns and operates a 30,000 barrel per day oil refinery located on Dayville Road near Valdez, Alaska. Petro Star is owned by Arctic Slope Regional Corporation and Harbor Enterprises, a.k.a. Petro Marine Services. CVEA CVEA is a member-owned electric cooperative that provides central station electric service to the Valdez and Copper Basin areas of the state of Alaska. CVEA is the power supplier for all of Petro Star’s requirements in accordance with a five-year power sales agreement executed May 2, 1992. The effective date of the five year term began on January 1, 1993, and will expire December 31, 1997. CHUGACH Chugach is a member-owned electric cooperative headquartered in Anchorage, Alaska. Chugach is Alaska’s largest Generation, Transmission (G&T), and Distribution utility. Chugach is the prospective future power supplier to CVEA subsequent to the construction of the proposed Sutton to Glennallen 138 kv Transmission Line (SGL) which will interconnect CVEA’s isolated system to the integrated Railbelt G&T system. HISTORICAL SUMMARY CVEA is proposing to construct a 138 kv transmission line from Sutton to Glennallen to provide for its supplementary power requirement to the Solomon Gulch Hydroelectric project. The Alaska Legislature, 1993, authorized and appropriated, subject to an independent feasibility study to be conducted by the State’s Energy Authority, $35 million from the Railbelt energy reserve fund to be used as a 50 year, zero interest loan to CVEA as partial funding for the project. Letter of Understanding August 30, 1995 Page 2 The Legislature also authorized the Alaska Industrial Development and Export Authority (AIDEA) to issue up to $25 million of bonds to provide for the balance of the funding. The Department of Community and Regional Affairs’ (DCRA) Division of Energy (DOE), successor to the Alaska Energy Authority, completed the feasibility study in April of 1994. In July 1994 the Commissioner of DCRA found the project could be financed and was economically feasible. Petro Star and CVEA entered into a power sales/purchase agreement on May 2, 1992, that provides Petro Star will purchase all of its electric power requirements from CVEA for a period of five years. The five-year period would begin on the date of full-time refinery operation. To date, Petro Star’s monthly peak demand has varied from 1600 kw to 1920 kw. Petro Star is currently planning an expansion to approximately 50,000 barrels per day. The schedule for the expansion is uncertain at this time. Subsequent to the expansion Petro Star’s peak demand is expected to be at least 2500 kw. In November of 1994 Petro Star notified CVEA that is was considering the installation of one and possibly two 3.9 mw combustion turbines to generate its own power and wanted to discuss the possibility of selling the excess to CVEA to displace its existing diesel generation. By utilizing the exhaust gas in the crude heater, Petro Star believes it could substantially reduce the Refinery’s cost of power. Petro Star has essentially completed the necessary engineering studies for the project but has delayed the final decision, pending further internal review and the results of discussions between Petro Star and CVEA relative to an effort to identify a method to reduce Petro Star’s rates in the interim period until the transmission line is completed. If a method can be identified and implemented to lower Petro Star’s rate to approximately 8 cents kwh, it would displace Petro Star’s need to install the turbine or turbines. In May of 1995 Governor Tony Knowles appointed an Interagency Review Panel (IRP) to review the SGL feasibility study. The panel is chaired by and consists of the Commissioner of DCRA, the Executive Director of AIDEA, and the Commissioner of the Department of Natural Resources (DNR). The IRP retained CH2M Hill to perform the review to assist in making their determination whether or not the project is still feasible. The review process is in the final stage of completion. There has been considerable discussion between the parties relative to the significance of Petro Star’s final decision and whether or not their load would remain on CVEA’s system. Since late 1993 Chugach and CVEA have had ongoing discussions of a participatory agreement embodied in a power sales/purchase agreement that would involve Chugach in the ownership and operation of the SGL. Such an agreement would include Chugach delivering power to CVEA’s Pump Station 11 substation at or near the same price for capacity and energy that Chugach charges its other wholesale customers. Those discussions have resulted in the July 1995 decisions of both the Chugach and CVEA Boards of Directors to pass strong companion resolutions authorizing their management staffs to enter into substantive negotiations. Chugach Letter of Understanding August 30, 1995 Page 3 and CVEA are currently negotiating the terms and conditions of a contemplated power sales/purchase agreement that would initially provide for all of CVEA’s power requirements supplemental to the production capability of the State-owned Solomon Gulch Hydroelectric project. Chugach has recently proposed an outline to establish basic principles and provisions of a contractual agreement under which 80% of the net cost to the utility of owning and operating the SGL would be included in Chugach’s overall G&T system costs. Chugach’s other wholesale customers would have the choice of opting in or opting out of their share of the benefits and burdens of the CVEA sale. CVEA would be responsible for the 20% balance of the costs. Preliminary calculations indicate such an arrangement could deliver benefits to both CVEA and Chugach over a period of years. Petro Star’s final decision could impact this conceptual arrangement. UNDERSTANDING CVEA and Petro Star currently have a contract under which CVEA is obligated to sell and Petro Star is obligated to buy, power to meet Petro Star’s electric power load requirements. That contract expires in 1997. Petro Star is investigating whether to install its own generation equipment to meet its load requirements, and potentially to produce excess power for sale to others, after that date. Under proposals that CVEA and Chugach have recently made to Petro Star, however, if the SGL is built it might be less expensive for Petro Star to purchase from CVEA electric power generated by Chugach and transmitted to Petro star’s facilities over the SGL and CVEA’s system. Alternatively, if Petro Star ultimately decided to install its own generation, construction of the SGL could still potentially benefit Petro Star by allowing Petro Star to have access to the entire Railbelt energy market for purposes of selling any excess power. Because construction of the SGL may produce these potential power purchase and power sales benefits, Petro Star may conclude that, so long as construction of the SGL remains viable, Petro Star should defer making any irrevocable commitment to install its own generation. In return for assurance that Petro Star would defer such a commitment, Chugach and CVEA have stated their willingness to make rates for power delivered to Petro Star over the SGL, in accordance with the alternatives that Chugach and CVEA have presented to Petro Star (or other mutually acceptable alternatives that reduce Petro Star’s power costs). CVEA and Chugach have also agreed that if the SGL is under construction but not completed by January 1, 1998, and if Petro Star has not committed itself to install its own generation by that time, then, in return for Petro Star’s continuing to await completion of the SGL rather than installing its own generation, the two utilities and Petro Star will negotiate in good faith in an effort to agree upon reasonable “co-generation deferral” payments by one or both of the utilities to Petro Star to help cover any net excess of Petro Star’s power costs over the co-generation Letter of Understanding August 30, 1995 Page 4 alternative during the period between January 1, 1998, and the date of completion of the SGL. COST ACCOUNTING To ensure a fair and equitable comparison of costs to effect the project’s generation termination when power is available from CVEA via the intertie that is competitive with the project’s cost, it would be imperative that the accounting methods used by Petro Star for the calculation of the cost of generation for the cogeneration project be compatible with standard utility accounting procedures in order to assure that such an equitable comparison can be achieved, the parties will agree, prior to the construction of the Petro Star cogeneration project, to the accounting method or system to be applied. AGREEMENT It is agreed by the parties that by signing this letter, there is an agreement that an understanding is established as set out in the preceding paragraphs. If CVEA decides not to construct the SGL, Petro Star would be notified at the earliest practical date and would be released from the provisions of the agreement. COPPER VALLEY ELECTRIC ASSOCIATION, INC. ITs CHUGACH ELECTRIC ASSOCIATION, INC. 7 . CONTRACT PROPOSAL between CHUGACH ELECTRIC ASSOCIATION, INC. and the COPPER VALLEY ELECTRIC ASSOCIATION, INC. Parties: Copper Valley Electric Association, Inc. and Chugach Electric Association, Inc. Recitals: © History and Contract Form. @ Intertie Agreements. Agreement: e Sale and Purchase of Electric Power. e System Sale (non-designated sources). e@ Net Requirements (net of Solomon Gulch, not demand limited). e Net Billing of up to 80% of costs of Sutton-Glennallen Intertie. Term: e Twenty years, effective upon completion of Sutton-Glennallen Intertie. Rates: e@ CVEA subject to demand and energy allocation of costs determined on a “pooled” G&T resource basis. Wholesale power rates as authorized by APUC or successor. POWER SUPPLY PROVISIONS Net Requirements: @ Chugach supplies requirements of CVEA service area (at Glennalien terminus of Sutton-Glennalien line) net of Solomon Gulch generation up to capacity of transmission system east from Sutton. (All Requirements Option): CVEA Generation: @ CVEA has the option to transition to all requirements and pool Solomon Gulch with all other Chugach G&T resources after the average costs of Chugach resources is within a negotiated range of the cost of Solomon Gulch power. e@ CVEA provides power to Chugach, under terms of cooperative agreement exhibit, for emergencies, maintenance or other requirements, from generating resources of CVEA at costs to be determined and delineated by schedule provided to dispatch center. Non-Exclusivity: @ CVEA may schedule Solomon Gulch as necessary to meet CVEA loads. All Solomon Gulch output is anticipated to go to CVEA. @ CVEA may generate from own resources during transmission line outages, or if Chugach generation otherwise unavailable. Resale: @ CVEA shall use Chugach-supplied power to serve retail load as ultimate consumers and end-users, and may not resell capacity or energy to others. RATEMAKING PROVISIONS G&T Cost Basis: e@ Rates to be based on cost of all G&T resources available to deliver capacity and energy from Chugach G&T system. Up to 80% of the costs of the Sutton-Giennallen Intertie will be pooled and considered a part of the Chugach G&T system. Revenue requirement as determined by APUC or other regulatory authority. Cost of Service: e@ Capacity and Energy rates as determined by traditional or non-traditional methods, including fixed/variable, embedded or marginal cost, subject to approval of APUC or other regulatory authority as may exist. Allocated Demand: e An allocated demand shall be used in the cost of service to determine CVEA's share of capacity costs and will equal to the greater of 1) CVEA's non-coincident peak demand reduced by 70% of the then-current capacity of Solomon Guich or 2) CVEA's coincident peak demand placed on the Chugach system. Fuel, Purchase Surcharges:e Applies per regulatory actions. Wheeling: ¢ CVEA provides power to Chugach at Giennallen (e.g. net of losses). For Chugach resources or generation provided by third party to CVEA for the Chugach system (e.g., cogenerated power sold to Chugach or sold to CVEA for assignment to Chugach) requiring wheeling services for ultimate disposition, wheeling terms, conditions and rates to be based on principles, practices and agreements as approved by APUC or other regulatory authority, if any. Capital Credits: @ CVEA eligible for capital credits resulting from purchases on patronage and cost-of-service basis, on an equal basis with other wholesale customers. Regulation: e By the APUC or other regulatory authority, if any. In the absence of regulatory authority, per the negotiated contract provisions subject to dispute resolution by binding arbitration. BILLING AND PAYMENT Monthly Bills: @ Rendered on or before 10th of month for preceding month usage; delay acceptable when notice given. Payment: ¢ Payment by no later than 25th of the month the bill was rendered, unless delayed, but no later than 15 days following receipt of bill. Late payments subject to interest charges. Billing Disputes: ¢ Disputed amounts paid, with notice of dispute. Dispute resolution to be specified. POWER PLANNING Joint Planning: @ Annually, CVEA and Chugach shall meet to discuss power supply issues, contract modifications, operation and maintenance issues, and other issues at request of either party. Agree to exchange information on matters of power sale and purchase agreement at all times. Points of Delivery: © Delivery at Glennallen e Add or remove delivery points upon mutual agreement of parties. PROVISIONS RELATING TO ELECTRICAL SERVICE Continuity: @ Chugach agrees to make capacity and energy continuously available, subject to Uncontrollable Forces, in the amount required at all current or future delivery points net of generation from Solomon Gulch. Restoration of Service: @ Chugach agrees to restore service with reasonable best efforts, and provide notice of determination of continuing problems and estimated time to repair. Third Parties: @ Standard “no third-party beneficiary” clause. Facilities and Equipment: e Both parties agree to maintain facilities in accordance with Prudent Utility Practices to prevent or minimize failures and provide for prompt repair and return to service. Load Characteristics: e@ Standard utility and interconnected system terms, including power quality, phase balance limitations, power factor correction, load shedding relay equipment and participation in interconnected system loadshedding schedules. Metering: @ Each party responsible for tests, calibration, restoration of commercial accuracy of metering equipment necessary to meet the contract terms. Normal accuracy 1%, adjustments to billing amounts for errors determined in metering since prior test. Legal Matters: (to be delineated) Good Faith Performance Force Majeure (Uncontrollable Forces) Responsibilities of Parties - Emergency and Otherwise Indemnification Arbitration and Legal Proceedings Insurance Provisions Approval Requirements Non-severability Successors and Assigns Assignments to Secured Lenders Rights of Access and Removal Notifications Access to Records and Information Mutual Covenants and Warranties Other Legal Provisions, as required Exhibits: 1) Definitions 2) Points of Delivery 3) Incorporation of Solomon Gulch and transition to All Requirements (CVEA option after certain trigger) 4) Cooperative Agreement - Power Resources 5) Coordination of Operations 7) Opinions of Counsel COPPER VALLEY ELECTRIC ASSOCIATION, INC. P.O. Box 45, GLENNALLEN, ALASKA 99588 (907) 822-3211 FAX 822-5586 VALDFz (907) 835-4301 PAX 835-4328 September 22, 1995 Mr. Dennis MeCrohan Deputy Director of Energy Alaska Industrial Development and Export Authority 480 West Tudor Road Anchorage, Alaska 99503-6690 Dear Dennis: In ongoing discusstons with CH2M Till, we have learned there are some concerns with respect to diesel expansion cases included in DCRA's Copper Valley Intertie Study and (VEA’s Interim Final Report, specifically the observation has been made that the two cases are quite different in their basic assumptions, and accordingly, we would like to respond to that statement. The two cases are in fact, similar in that both provide CVEA's supplemental power requirements with diesel fired generation yet they are very different in approach. The DCRA diesel expansion case represents a continuation of the existing mode of operation. The basic assumption is that new units are added to replace existing worn out units and that manpower requirements are increased as load increases require that the Valdez diesel plant be manned for 24-hour a day operation (The current generation scheme calls for 12-hour a day operation.) On the contrary, the CVIEA diesel expansion case represents an aggressive approach to expansion which is highly dependent on efficient utilization of SCADA controlled operation and dispatch and, in addition, repowering and refurbishment of existing units, Presently, CVEA has minimal SCADA control of its generation resources. Serving the Copper River Basin and Valdez Gan a ( Lay September 22, 1995 tage 2 Vhe CVLEA case was borne out of a desire by our Board of Directors to take a hard look at whether a minimal cost diese! expansion case could compete with the SGL integrated case The integrated case, as discussed in the Interim Final Report, is an alternative SGL case whereby Chugach Ulectric Association absorbs the cost of developing the SGL and recovers that cost through sales to all wholesale and retail customers. As you are aware, the Interim Vinal Report clearly concluded that the least cost power supply alternative is the SGL integrated case. and on that basis our Board of Directors has elected to pursue that alternative In examining the differences between the DORA and CVEA cases, certain specific issues concerning the CVEA case would lend further explanation as to the basic approach taken, as well as explain the resultant different economics of the two cases. Please understand that although CVEA‘’S management staff and John Heberling, of RW Beck, believe the plan presented is achievable, detailed analysis of the technical aspects of the case have not been fully explored and subjected to the same scrutiny and review that has been given the DCRA case. Kor example, manpower requirements represent the most significant difference between the DCRA and CVEA cases. DCRA assumes three operators will be added to the Valdez. diesel plant at the time 24-hour operation is necessitated by load growth. In the case of CVEA's SCADA controlled expansion case, it is assumed that up to five operator positions can be reduced by employing new remote controlled technology. CVEA has not conducted a detailed study of manpower requirements tor this scenario and it is conceivable that such a study could conclude our estimate of a reduction of five positions is overly optimistic. Additionally, CVEA’s plans for personnel reduction involve eliminating positions as attrition and retirement of existing personnel create opportunitics to do soa, and as such, immediate reductions may not occur Finally, plans for reorganization of plant personnel are subject to the approval of the Board of Directors and any such plans would necessarily have to fit within the Association’s goals for managing our workforce. Such a reduction in foree could prove very difficult, from the Board’s perspective, if CVEA were to continue to supply all of its power requirements from diesel sources Another major ditference between the two cases is the planning horizon. The DCRA case looked out 20 years with regard to specitic costs then projected those results out through the end of a $0-year period. On the contrary, the CVEA case had only a 20-year planning horizon and as a resull, CVEA’s study does not take into consideration several items which conceivably could result in cost increases in future years, September 22, 1995 Page 3 First, the life cycle of a diesel unit is approximately 20 years compared to a SO-year life cycle (much longer in reality) for the intertic. The CVEA study does not account for capacity additions (new diesels) beyond the 20-year period. Accordingly, comparing the CVEA 20-year case to the DCRA 50-year case is like comparing apples and oranges In order to make any meaningful comparison, the CVEA case would necessarily have to be put on a comparable basis with respect to capacity additions and the planning horizon. Likewise, from a labor standpoint, as the life cyele of the diesels in CVIEA's study matures, and as load requirements increase, it is conceivable additional maintenance, including labor, on the units will be required. This is expected to occur in the last ten years of their life cycle and has not been provided for in CVEA’s diesel case. Another issue which has not been addressed on the CVEA’s diesel case is whether or not this particular investment can be successfully financed. CVA is a Rural Utilities Service (RUS) financed cooperative and as such is subject to technical and financial requirements of that federal agency. No effort has been made, to date, to seck financing from RUS for the CVEA diesel case. Should RUS financing be unavailable, then the cost of this alternative would be significantly increased. In addition, RUS may choose to impose additional personnel requirements conditional to providing financing for a SCADA controlled diesel plant. To summarize the discussion, | would like to re-state the point made carlier that although CVEA management is of the opinion the diesel case as outlined in the Interim Final Report might be achievable, this scenario has not received the refined study necessary prior to proceeding with such a project. As has been pointed out in this letter, such refined study could well lead to an alteration of some of the basic assumptions, particularly with respect to manpower requirements Dennis, there is one final point with regard to CVEA making substantial future investment in diesel facilities, and that is that } sense extreme reluctance on the part of our Board to make this type of investment, which as you well know may loreclose other future power supply opportunities Thank you for the opportunity to provide these comments. If] can provide additional information about our position on this issue, please call me. Yours truly, fr~- Clayton Hurless General Manager w:\word\cdh\95- 1 4onh.doe 7 COPPER VALLEY ELECTRIC ASSOCIATION, INC. P.O. Box 45, GLENNALLEN, ALASKA 99588 (907) 822-3211 FAX 822-5586 VALDEZ (907) 835-4301 Fax 835-4328 July 10, 1995 430 West Tudor Road Anchorage, Alaska 99503-6690 SUBJECT: Interim Final Report Dear Dennis: As you requested, I have enclosed a copy of the Interim Final Report - June 1995 prepared by RW Beck. If you have-any questions about the report you may contact either John Heberling or me. For your information, the report has been provided to Dave Gray of CH2M Hill. Sincerely, Lptuf- Robert A. Wilkinson, CPA Manager, Administration and Finance Enclosure w:\word\raw\95-166nh.doc Serving the Copper River Basin and Valdez Interim Final Report Evaluation of Power Supply Alternatives ; r i June 1995 es Rs Be | OH Interim Final Report Evaluation of Power Supply Alternatives ox alley Hectic Associa cot , Lae Fee Sj in, ae ¥ the Copper River Basin #%* June 1995 0 etl 2 INTERIM FINAL REPORT EVALUATION OF POWER SUPPLY ALTERNATIVES TABLE OF CONTENTS Section 1- INTRODUCTION IINTRODUGTIOIN ce enczccccceszsscrsccscrersucsenonssrctt-seescsncececestensssusvesrasenezssetvearoesteseess SCOPE OF SERVICES Section 2 - REVIEW OF POWER SUPPLY PROPOSALS INTRODUCTION. «:.2:<::-cecececececenosesececcsnessuscuautssvete seu suris¥ssiesrersisseronsworsusesissesss 2-1 DESERIPTION'IOPPROROSAUS sesrssesseccscncserescncrsceesrcrccessnessnstccszccescesnsetaseesesess= 2-4 Anchorage Municipal Light & Power w 2-4 Chugach Electric Association, Inc.............++ . 2-6 PROJECTION OF PURCHASED POWER COSTS ... 2-8 IINTEGRATIED: CASE rotecceccecocercreesenssssecneastovscaneceetsssercasecsaceesesssssserscsyacessecesesneees 2-9 Section 3 - POWER SUPPLY AND ECONOMIC ANALYSIS INTIRODUGCTION Sikes cccnss.cuscsccaceesossvovestonscnccoreccoverenesesessstonssscnsuscensonesereceessretees 3-1 ASSUMPTIONS .......:sessesesesssseeeseseenees oad ALTERNATIVE RESOURCE SCENARIOS 22329 Diesel ‘Generation. .........:..-.csc-necssecsoebeasensescscsussnssesessssesewsusvsronssssoressseserssares 3-4 Sutton to Glennallen Transmission Line Option ...........scsseseseseesesesessseseneeees 3-5 INTEGRATED CASE xs EVALUATION OF CASES AND COMPARISON OF RESULTS.......:s:esesesseseseeees 3-6 Section 4 - SUMMARY AND FURTHER CONSIDERATIONS SUMMARY Asia cots ctexostsacs screzea svevscsasctewsustoevesnssssressnsesoveessusesttsectessesoneecstessesnens 4-1 BURTHER CONSIDERATIONS |.:<.2.<--2.002-ceoc-acezeceascssvoncecasssessvessnsassususasewsesorstres 4-3 This report has been prepared for the use of the client for the specific purposes identified in the report. The conclusions, observations and recommendations contained herein attributed to R. W. Beck constitute the opinions of R. W. Beck. To the extent that statements, information and opinions provided by the client or others have been used in the preparation of this report, R. W. Beck has relied upon the same to be accurate, and for which no assurances are intended and no representations or warranties are made. R. W. Beck makes no certification and gives no assurances except as explicitly set forth in this report. Copyright 1995, R. W. Beck All rights reserved. AUT WS6-95\3945\CVEA_RPT.DOC Section 1 INTRODUCTION INTRODUCTION As part of its continuing effort to reduce its overall cost of power, Copper Valley Electric Association, Inc. (CVEA) has undertaken a study of alternative power supply options presently available. CVEA provides electric service to approximately 3,000 member-consumers in Valdez, Glennallen and the Copper River Basin with power purchased from the State-owned Solomon Gulch hydroelectric project supplemented with diesel generation. In April 1994, the State of Alaska, through the Department of Community and Regional Affairs (DCRA), Division of Energy, completed a Feasibility Study of a 138-kV transmission line to interconnect CVEA’s electric system with the Railbelt system. This transmission line, to be constructed between Sutton and Glennallen (the “SGTL”), would make power generated from natural gas-fired combined-cycle combustion turbines operated by Chugach Electric Association (CEA) and Anchorage Municipal Light & Power (ML&P) available to CVEA. Power production costs for both CEA and ML&P are significantly less than the cost of power produced by CVEA’s diesel generators. In May 1993, the State legislature appropriated $35 million for payment as a 50-year, zero-interest loan, pending completion of a feasibility study (the “Feasibility Study”), to be used for the construction of the SGTL. Upon completion of the Feasibility Study, DCRA accepted the Feasibility Study and began negotiations with CVEA on the terms of the State loan. Subsequently, a preliminary injunction was issued by U.S. federal court halting issuance of the State loan. The preliminary injunction was dismissed on February 25, 1995. In August 1994, CVEA issued a request for proposals for firm power to be supplied to CVEA over the SGTL. Two proposals were received in October 1994, one each from CEA and ML&P. The proposals identified general terms and conditions of the proposed power sales and indicated the projected cost of power to CVEA over a 20-year period based on certain assumptions of general inflation, increases in the cost of fuel, future power requirements and other factors. CVEA has retained R. W. Beck, Inc. (R. W. Beck) to review the power supply proposals from CEA and ML&P and to provide a comparable analysis of the cost that CVEA could expect to pay for power to be purchased over the SGTL. In addition, CVEA requested that the study effort be extended to provide an economic evaluation of the comparable costs associated with two other alternative INTRODUCTION power supply options: continued diesel generation and potential integrated operation with CEA. Several alternative power requirement, fuel cost, construction cost and other scenarios were developed to evaluate the impact of future conditions which vary from the base case assumptions. This report summarizes the results of the power supply proposal review and the expanded power supply and economic analysis. Section 2 of the report discusses the two power supply proposals from CEA and ML&P and provides direct comparison. The economic analyses of the alternative power supply options is described in Section 3. Overall conclusions of the analysis are summarized in Section 4. It should be noted that although this study follows closely after the completion of the SGTL Feasibility Study, several of the basic assumptions and power supply options used in this analysis vary from those used for the Feasibility Study primarily because many conditions have changed in recent months. In particular, the specification of when, where and at what cost diesel generators are to be added in the future has been refined significantly by CVEA and the projection of future diesel fuel prices has been adjusted to reflect CVEA’s recent fuel purchase history. CVEA’s diesel fuel costs have dropped significantly since the Feasibility Study analysis was conducted. The cost of power to be purchased over the SGTL as used in the economic analysis has been adjusted to reflect the projections included in the power supply proposals received from CEA and ML&P. The base case projection of power requirements for CVEA and the estimated cost of construction of the SGTL used in this analysis are the same as used for the Feasibility Study. Alternative low and high power requirement forecasts have been developed for this study, however. With regard to the economic analysis, this study varies significantly from the SGTL Feasibility Study. In the Feasibility Study, the economic analysis evaluated the costs and benefits associated with the development of the SGTL from the perspective of the State’s potential investment in the SGTL. This study performs all economic analyses from the perspective of CVEA. The projections of the costs of power included in this study for the various power supply scenarios include all costs associated with power supply for CVEA and consequently, represent the actual cost of power production and purchases to CVEA. Further, the economic analysis has been extended to include the projection of CVEA revenue requirements for the alternative scenarios. This provides for a straight-forward comparison of the impact on the cost of power to CVEA’s member-consumers associated with each of the power supply cases. R. W. Beck 1-2 INTRODUCTION SCOPE OF SERVICES The scope of services for this study was initially defined in a letter proposal to CVEA dated November 3, 1994. Since that time adjustments have been made to the scope to address circumstances that have changed with CVEA’s power supply options in recent weeks. The scope of services as agreed upon by CVEA and R. W. Beck is as follows: 1. Provide a complete review of the two power purchase proposals received from CEA and ML&P using the basic data included in the proposals augmented with additional information obtained from CEA and ML&P. Provide a side-by-side comparison of the cost of power as proposed in the two proposals on a comparable basis for the proposed term of the contracts and include a description of the underlying principals used in the calculations. Determine the basic assumptions of capacity availability used by both CEA and ML&P, particularly with regard to when new generating resources are expected to be included in the ratebase. Review the impacts on CVEA if CEA were to include the costs of the SGTL as a CEA system cost and subsequently sell power to CVEA. Identify cost impacts on CEA’s existing customers resulting from this “integrated case”. Develop an economic analysis model for the purpose of estimating the cost of power to CVEA for a 20-year period for two primary power supply plans as follows: m Diesel expansion case m SGTL case with power purchases from the lowest cost provider, either ML&P or CEA. Work with CVEA staff to develop the timing of retirements and additions and costs to be associated with the diesel expansion case. Perform the economic analysis for a set of base case assumptions and conditions as well as for alternative assumptions. The alternative assumptions are to be used to estimate the sensitivity of the results primarily to varying power requirements and fuel costs. Conduct a work session with CVEA staff and board members to discuss the study methodology and assumptions and present the preliminary results. Provide a written report summarizing the results of the study. R. W. Beck 1-3 Section 2 REVIEW OF POWER SUPPLY PROPOSALS INTRODUCTION In August 1994, CVEA requested proposals for firm power to be delivered over the SGTL and received responses from ML&P and CEA. Both ML&P and CEA have significant surplus generating capacity available at the present time and both utilities had expressed interest in supplying power to CVEA prior to the issuance of the request for proposals. The power to be sold to CVEA by either ML&P or CEA would be generated by natural gas-fired combustion turbines and combined- cycle combustion turbines. CEA presently sells firm power to its retail customers and three wholesale customers, Matanuska Electric Association, Homer Electric Association and the City of Seward Electric System. In addition, CEA sells non- firm economy energy to Golden Valley Electric Association (GVEA) over the Anchorage-Fairbanks intertie. ML&P sells power to its retail customers and four off-system customers. ML&P also competes with CEA and GVEA for the sale of economy energy to Fairbanks Municipal Utility System. CEA presently has 612 MW of generation capacity of which 148 MW is hydroelectric capacity. In 1993, CEA’s total system peak demand was 356 MW. Approximately 51% of the energy sold by CEA is attributable to CEA’s retail system with the remainder associated with sales to the wholesale customers. Generating utilities in the Railbelt are required to maintain generating reserves equal to 30% of their respective peak demands. With allowances for generating reserves, CEA had approximately 150 MW of surplus generating capacity in 1993. CEA presently forecasts that its total system power requirement will increase at approximately 1.56% per year over the next 23 years. ML&P has 375 MW of generating capacity and had a peak demand of 143 MW in 1993 representing a 189 MW generating capacity surplus after reserve requirements. ML&P’s power requirements are forecasted to increase at 1% per year for ML&P’s medium load growth scenario. ML&P and CEA both have extensive planning efforts underway continuously to evaluate future power requirements and power supply resources. As part of these planning efforts, the need for additional generating resources is being evaluated and the available generating resource options and alternative costs are being investigated. Although the two power supply proposals are different in many ways, they are similar in that both contracts are for up to a 20-year term and CVEA would pay a! w REVIEW OF PO. SUPPLY PROPOSALS both a demand charge and an energy charge for the amount of power purchased. In general, the demand charge would be established based on the allocation of the respective system's fixed power production costs according to the percentage of total system peak demand that CVEA’s load represents. The energy charge is basically the cost of fuel used to generate the power to be sold to CVEA plus variable operations and maintenance costs. Since CEA and ML&P both generate power using natural gas as fuel and the cost of natural gas to both utilities is similar, the energy cost component in both proposals is comparable. Both proposals indicate that the cost of power to CVEA would be adjusted over time to reflect actual costs of power production in the future. Both proposals state that the power to be sold to CVEA is firm, i.e., available at all times, and would be sold on a “take-and-pay” basis. Take-and-pay means that CVEA would pay only for the power it actually uses as opposed to guaranteeing the purchase of a fixed amount of power. CEA’s proposal clearly indicates that all power requirements of CVEA in excess of Solomon Gulch generation will be supplied for the duration of the contract term on a take-and-pay basis. ML&P’s proposal, however, states that power will only be supplied to CVEA as long as ML&P has sufficient power resources available unless CVEA reserves and pays for a fixed amount of power. At the present time it is projected that ML&P will have adequate generating capacity to supply CVEA’s demand for the duration of the contract. If ML&P’s loads grow faster than currently projected or significant amounts of power are sold to other utilities, CVEA may need to reserve a certain amount of power to be purchased and essentially convert its power purchase arrangement to “take-or-pay”. It is expected that the actual terms and conditions of a power purchase contract would be negotiated following selection by CVEA of the chosen provider. A comparison of the principal aspects of the two proposals is shown in Table 2-1. Both ML&P and CEA have provided projections of the cost of power to CVEA under alternative load growth scenarios. We have not duplicated all of these scenarios as part of this study. For the purpose of comparison, however, the base case projections are shown in Table 2-2 under the subheading, Comparison of Proposals. R. W. Beck 2-2 of i Ba 8 t REVIEW OF PO t. SupPLY PROPOSALS TABLE 2-1 COMPARISON OF POWER SUPPLY PROPOSALS PRINCIPAL TERMS AND CONDITIONS Ses ML&P Proposal CEA Proposal ae Years (CVEA Option) 10-20 Years (Negotiated) | Approval CEA Board, APUC } Solomon Gulch No | Banking Delivery Point O'Neill Substation Teeland/Palmer Substations Energy: __Billing Energy Amount Delivered Amount Delivered Specified O&M Rate Average of CEA system Fuel: Heat Rate Incremental Inflation Light Sweet Crude Oil Futures | Beluga Between 88% and 110% of Marathon price Marathon 1/3 Light Sweet Crude Oil 1/3 PPI of Natural Gas 1/3 CPI-U of Fuel Oil Capacity: Billing Demand Greater of: CVEA Actual coincident peak net of 1.) Reserved Capacity Solomon Gulch Allocated Demand __] Billing Demand Greater of: Net CP for previous year Y*(Net NCP-70% S.G. capacity) where Y = 0.0 in 1st year 0.2 in 2nd year 0.4 in 3rd year 0.6 in 4th year 0.8 in 5th year 1.0 thereafter | Reserved Capacity No less than Base Capacity Reserve of capacity not required apacity Increase Reserved Capacity or Requirements above _| purchase non-firm energy Reserved amount jot Applicable continued on following page R. W. Beck 2-3 REVIEW OF PO — R SUPPLY PROPOSALS es ML&P Proposal CEA Proposal Capacity Costs Generation Generation, Transmission, General |} }| Allocated and Administrative | Load Growth Limited by Available Commitment to provide all of Resources. CVEA has right of | CVEA’s net requirements first refusal before AML&P offers capacity to other DESCRIPTION OF PROPOSALS ANCHORAGE MUNICIPAL LIGHT & POWER ML&P has provided a proposal to supply the net power requirements of CVEA for a term of between 10 and 20 years, at the option of CVEA. ML&P would sell power to CVEA generated by ML&P gas-fired generators and would provide delivery at the O’Neill Substation in Sutton. The proposal states that power would be sold on a firm, “take-and-pay” basis and that CVEA would pay only for the power that it takes from ML&P. The amount of power purchased, however, is subject to a minimum purchase requirement if CVEA elects to reserve a certain amount of capacity. The proposal establishes a Base Capacity Amount as an agreed upon minimum capacity to which CVEA would be entitled without reservation and would pay for whether or not it is used. This amount would approximate CVEA’s initial year peak demand over the SGTL coincident with ML&P’s system peak demand. It is not clear if the Base Capacity Amount would become a minimum purchase requirement that CVEA would be obligated to pay for each year even if CVEA’s load decreases. The price of power to be sold to CVEA would include an energy component and a capacity charge. The capacity charge is to be based on CVEA’s contribution to the prior year’s total ML&P system peak demand, or CVEA’s reserved capacity amount, whichever is greater. The capacity charge is structured to compensate ML&P for an allocated share of the annual production costs associated with having generating capacity available to meet the firm requirements of its customers. At the present time, ML&P indicates that these production costs are approximately $9 million per year and include depreciation expense, debt service and ML&P’s allowed return on its equity-in its production plant. CVEA’s firm capacity charge would be calculated each year by multiplying the total ML&P annual capacity cost by the ratio of CVEA’s coincidental peak demand during the year to the total ML&P system peak demand during the same year. The total ML&P system peak demand in this equation would include the demand requirement of CVEA over the SGTL at the time the system peak occurs. If CVEA R. W. Beck 2-4 REVIEW OF PO — R SuPPLY PROPOSALS elects to reserve a capacity amount, the reserved amount is used in the calculation of the capacity charge rather than the actual amount used by CVEA. CVEA will be able to use the Solomon Gulch project to its advantage in establishing the annual capacity charge. Since the capacity charge is based on CVEA’s demand over the SGTL at the time of ML&P’s system peak demand, CVEA may be able to operate the Solomon Gulch project so as to reduce its demand on ML&P at that time. For the purpose of the presentation of estimated power costs, ML&P has assumed that Solomon Gulch will generate 6 MW at the time of ML&P’s system peak demand. From time to time, CVEA may reserve a capacity amount for which it will pay regardless of whether or not the full amount is used. ML&P has not guaranteed that it will maintain adequate generating capacity to supply CVEA’s load in the future unless CVEA actually reserves a capacity amount. At the present time, it is projected that ML&P will have sufficient generating capacity through the possible 20-year maximum term of the contract. In the future, ML&P has indicated that it will notify CVEA if it intends to enter into a power sales contract with another utility which could affect ML&P’s available capacity and allow CVEA to reserve a capacity amount. Figure 2-1 shows ML&P’s existing capacity resources and projected loads, with CVEA’s load, through 2017. The energy component of ML&P’s proposed contract is based on the incremental cost of generating the power to be used by CVEA. The cost will include the incremental cost of fuel, start-up costs (in situations where the incremental load requires starting a generating unit), ML&P’s variable cost of production operation and maintenance (O&M), and wheeling charges for the transmission of power to the O’Neill Substation over transmission lines currently owned by others. The energy charge is designed such that ML&P’s existing customers will realize no negative cost impacts from the sale of power to CVEA. Over time, the energy cost will be adjusted to account for actual costs. ML&P’s natural gas fuel prices are to be adjusted in proportion to the rate of increase (or decrease) in Light Sweet Crude Oil Futures, an index that is similar to the index for the West Texas Intermediate Crude Oil for which the State of Alaska Department of Revenue (DOR) has developed projections. Presently, ML&P’s variable O&M charge is 2.26 mills per kWh. This charge is projected to increase over time at the general rate of inflation. Wheeling charges for transmission are estimated by ML&P to be 0.06 cent per kWh between ML&P’s Plant No. 2 and Palmer over Alaska Power Administration lines and 0.1 cent per kWh between Palmer and the O'Neill Substation over MEA lines. ML&P has developed projections of the cost of power to CVEA under various load scenarios. These projections show that under certain CVEA load conditions, higher than the base or medium load growth scenario, the energy charge to R. W. Beck 2-5 REVIEW OFPO — . SuPPLY PROPOSALS CVEA is slightly higher. This is because of the incremental nature of the charge and with higher loads, ML&P expects to need to operate slightly less efficient generating units. As shown in Figure 2-1, ML&P has sufficient generating capacity to supply all of its load requirements through 2017 based on current load projections. ML&P does not intend to install any new generating resources during this time period, however, it does expect to repower and refurbish some of its existing resources. In its projection of the cost of power to CVEA, ML&P has included the expected costs of these production plant improvements. ML&P’s proposal indicates that Solomon Gulch energy can be “banked” by CVEA. This would permit CVEA to utilize the full output of the Solomon Gulch project rather than spill water in the summer as is presently done because the energy generation capability of the project exceeds CVEA’s present loads. The present pricing structure of Solomon Gulch power would probably not make banking of the energy economically attractive to CVEA since power could be purchased from ML&P at a lower rate than the Solomon Gulch purchase power rate. ML&P has further indicated that if it were allowed to dispatch the Solomon Gulch project, the net cost of power sold to CVEA may be 2-4 mills per kWh less than if CVEA dispatches Solomon Gulch. CHUGACH ELECTRIC ASSOCIATION, INC. CEA’s proposal is to supply firm power in the amount of CVEA’s net requirements on a take-and-pay basis with no minimum purchase amount. Unlike ML&P, CEA will provide for the full power requirements of CVEA, net of Solomon Gulch generation, regardless of how CVEA’s or CEA’s loads change over time. CEA would deliver power to CVEA at the O’Neill Substation, however, CEA has not included the cost of wheeling the power over MEA transmission lines between Palmer and the O’Neill Substation, estimated to be 0.1 cent per kWHh, in its proposed rates to CVEA. The proposed term of the contract is 10 to 20 years beginning at the completion of the SGTL. The power sales rate for power purchased from CEA will be tariffed rates subject to approval by the Alaska Public Utility Commission. Similar to the proposal from ML&P, the actual cost that CVEA pays for power will change over time depending on CEA’s actual cost of power production. CEA presently sells firm power to three other utilities. The terms and conditions of the power sales contracts between CEA and its other utility customers may factor in to the terms and conditions that CEA would eventually negotiate with CVEA. The price of power to CVEA would include a monthly customer charge (currently $150), a demand charge and an energy charge. The demand charge is related to CVEA’s allocated share of CEA’s total fixed generation, transmission, and R. W. Beck 2-6 aus (Bx Uta REVIEW OF PO -—t SUPPLY PROPOSALS administrative and general costs, which include depreciation, interest expense and other fixed costs. Each year, CEA would determine the total allocated demand charge on a pro rata basis based on CVEA’s contribution to CEA’s total coincidental peak demand. CVEA could use Solomon Gulch to its advantage in lowering the demand charge by operating Solomon Gulch at or near its full capacity at the time of CEA’s peak demand. Although the demand charge is established once per year, it would be charged on a monthly basis for the total monthly demand that CVEA places on CEA. During the first five years of the proposed contract, CEA would establish the CVEA demand charge as discussed above except that the CVEA demand factor to be used in the allocation of fixed costs would be based on the greater of the following: 1. CVEA coincidental peak demand at the time of CEA’s system peak, and 2. A factor Y multiplied by (CVEA’s non-coincidental peak demand less 70% of the capacity of Solomon Gulch), where Y equals 0, .2, .4, .6, .8 and 1.0 in the first through sixth years, respectively. The adjustment in Item 2, above, allows a phasing in of the total demand charge to CVEA but whether or not it in itself will provide benefits to CVEA, as compared to the straight coincidental peak allocation for Item 1, depends on how CVEA will operate Solomon Gulch. Although Item 2 would be the lower of the two alternatives in the first year, if Solomon Gulch is operated at or near full capacity at the time of CEA’s system peak Item 2 could become the larger of the two alternatives within a year or two. CEA has indicated that it could dispatch Solomon Gulch as a CEA system resource. Under this scenario it is not known how the demand allocator would be established since the use of Solomon Gulch would be at the discretion of CEA. CEA’s demand charge is expected to increase during the proposed contract term primarily because of the planned addition of new generating units to supply CEA’s total system requirements. CEA is currently planning to retire several of its Beluga generating units beginning in 2005. In addition, CEA has an agreement with Alaska Electric Generation and Transmission Cooperative, Inc. (AEG&T) and Homer Electric Association for the use of the 40 MW Soldotna #1 gas-fired combustion turbine that is expected to terminate in 2005. New generators are planned by CEA to be added in 2006, 2007, 2008, 2011, 2014 and 2016. Figure 2-2 shows CEA’s existing and planned generating capacity as it compares to CEA’s projected system load requirements, including the load of CVEA. As can be seen in Figure 2-2, CEA expects its current generation surplus to decrease significantly in approximately ten years but the addition of new generating units will provide sufficient capacity to supply projected load requirements. R. W. Beck 2-7 REVIEW OF Po’: SuPPLY PROPOSALS The new generating units presently planned by CEA contribute significantly to the increase over time in CEA’s projected cost of power to CVEA. If CEA were to refurbish its existing units rather than replace them with new units, cost savings may be realized that could lower the projected cost of power. CEA’s energy charge is established based on the cost of fuel, variable production O&M and the variable cost of power purchases. The energy charge is projected to increase over time with assumed increases in general inflation and in fuel costs. CEA purchases natural gas from three sources, the Beluga River Field Producers (Arco, Shell and Chevron), Marathon Oil Company and Enstar Natural Gas Company. The price of natural gas to CEA is established by contract and adjusted over time according to certain indices generally tied to oil prices. PROJECTION OF PURCHASED POWER COSTS In projecting the cost of power from each of the two proposers, ML&P and CEA, we have relied upon the projections provided by ML&P and CEA with certain modifications to these projections which were made at our request. In their respective proposals, each utility made various assumptions with regard to inflation and fuel cost escalation. We requested and ML&P and CEA provided modified power rate projections using common assumptions for these variables. The projections made by ML&P and CEA were developed using their respective in-house financial and power supply modeling capabilities. In addition to the inflation and fuel cost assumptions, it was also noticed that CEA had used different CVEA power requirements projections in its rate projections than ML&P had used beginning in 2006. There was also a difference in the assumed operation of the Solomon Gulch project that was noticed between the two proposals. In order to compare the two proposals, we developed alternative projections of the total cost of power to be incurred by CVEA using the same power requirements and Solomon Gulch operation. For the projections, CVEA’s purchased power requirements are based on the medium load growth scenario from the load forecast developed for the SGTL Feasibility Study, less Solomon Gulch annual energy generation. The Solomon Gulch project is further assumed to be generating 6 MW at the time the coincidental peak demand occurs. Three separate projections of the total power cost to CVEA from CEA and ML&P are provided. Table 2-2 shows the comparison of power costs from ML&P and CEA using the power rates provided by CEA and ML&P using the same assumptions for inflation and fuel cost escalation. Annual inflation is assumed to be 3.5% for 1994 and 1995, 3.6% for 1996, 3.8% for 1997, 3.6% for 1998 through 2000, and 3.7% thereafter. This is the projection of annual inflation as provided by CEA. Fuel costs have been escalated so as to be consistent with the DOR Fall 1994 base-case projection of West Texas Intermediate Crude Oil prices. The R. W. Beck 2-8 RY REVIEW OF PO' =. SUPPLY PROPOSALS calculations for Table 2-2 use the CVEA load forecast assumptions used by ML&P and CEA which are different. As can be seen in Table 2-2, the ML&P power cost, although higher than the power cost for CEA for the first two years, is lower in the later years when comparing the two original proposals. The total present value savings to CVEA in purchasing from ML&P over the 20-year contract period would be $9,891,000 assuming an 8.5% annual discount rate. Table 2-3 shows the comparison of power costs for the two proposals with the same CVEA power requirements and using the same power rates as used for the case shown in Table 2-2. In this case, the total present value savings to CVEA represented by purchasing power from ML&P is $8,361,000. A third case has also been developed to show the comparable cost of power to CVEA if the demand cost allocator used by CEA in determining its demand charge is based on Solomon Gulch generating only 6 MW at the time of CEA’s system peak. In its base case projections, CEA had assumed that Solomon Gulch would generate approximately 12 MW at the time of system peak thereby lowering the allocated demand cost to CVEA. Table 2-4 shows the results of this case while also employing the comparable fuel, inflation and CVEA load requirement assumptions described for the previous two cases. As can be seen in Table 2-4, the total present value savings to CVEA if power were to be purchased from ML&P is $14,596,000 using an 8.5% discount rate. Figure 2-3 shows the projected cost of power to CVEA on a cents per kWh basis for the three scenarios. Note that the projected cost of power from ML&P is the same for all three scenarios. As can be seen in Figure 2-2, power purchases from ML&P are projected to be lower than from CEA in nearly all years of the contract period. In addition to its proposal for power sales, CEA has approached CVEA with the concept of integrated operations. The integrated case is discussed in detail in the following subsection of this report. INTEGRATED CASE In a letter to CVEA dated March 14, 1994, CEA proposed the concept of including the cost of constructing and operating the SGTL as a CEA system cost. In this letter, CEA indicated that such an arrangement could potentially be beneficial to CVEA, CEA and its wholesale customers. Very little detail was provided with the letter and CEA indicated in subsequent discussions that it was not in a position to provide further analysis for this “integrated case”. Because the integrated case could offer significant benefits to CVEA, it was considered important by CVEA to review this concept further. R. W. Beck 2-9 REVIEW OF PoO\ —_: SUPPLY PROPOSALS In order to evaluate the cost effects of the integrated case on both CVEA and CEA, we relied upon a model that we previously developed to project CEA wholesale power costs. The debt service and operating costs of the SGTL were included as a CEA system cost and allocated over all of CEA’s power sales. The SGTL is assumed to be financed with a $35 million, zero-interest State loan with the remainder of the construction cost financed with a $21.3 million loan with a 7.5%, 30-year term. The basic CEA system costs included in this projection are based on CEA’s 1994 Financial Forecast which are not necessarily consistent with the system costs used by CEA in its projection of power sales rates to CVEA in its proposal as previously described. The analysis as developed, however, is consistent with itself and can be used to determine the cost impacts of the integrated case. The results of the integrated case analysis are shown in Table 2-5. In this table, CEA Base Costs w/o CVEA are the costs of operating CEA’s production and transmission system as currently projected without CVEA. The Additional Costs w/CVEA lines indicate the additional production costs associated with CEA supplying power to CVEA. The Intertie Costs lines show the capital and O&M costs associated with the SGTL. The CEA Costs w/Intertie line totals the costs that CEA will incur if it were to serve CVEA and pay the costs of the SGTL. Finally, Table 2-5 shows the projected revenues that CEA would receive from sales to CVEA and the net benefit or cost to CEA. The two blocks of results on Table 2-5 show the net benefit or cost to CEA for two scenarios. The first scenario uses CEA’s assumption of the CVEA billing demand allocator whereby the Solomon Gulch project generates at near capacity at the time of CEA’s system peak demand. The second scenario allocates demand costs assuming that the Solomon Gulch project is only generating 6 MW at the time of CEA’s system peak demand. Although neither of these two scenarios shows a benefit to CEA, the net cost to CEA is less for the second scenario because CVEA’s share of CEA allocated demand costs would be higher and CVEA would consequently pay more for its power purchases. As can be seen in Table 2-5, the costs to CEA associated with the integrated case exceed the projected power sales revenues from CVEA in all years for the “High Demand Allocation Case”. This implies that CEA would need to raise the cost of power to all of its customers if it were to include the SGTL as a CEA system cost. CEA had originally proposed the integrated case with the intention that system costs would be higher in the early years but that eventually the margins received from the sales to CVEA would exceed the annual costs of supplying CVEA plus the costs of the SGTL. If CVEA loads are higher than assumed in our analysis, the benefits may exceed the costs at an earlier time. It is expected that CEA would not be able to implement the integrated case if the annual costs to its system exceed the benefits for more than a few years because of the impact on CEA’s existing customers. CEA could however establish rates for power sales to CVEA that R. W. Beck 2-10 REVIEW OF PO' ~— SUPPLY PROPOSALS allocated a higher percentage of the SGTL costs to CVEA than to CEA’s other customers. Although CEA system costs may go up with the integrated case, there are obvious benefits to CVEA. If CEA were able to carry the capital repayment and operating costs of the SGTL as a CEA system cost as shown in Table 2-5 and CVEA were able to purchase power from CEA at a wholesale rate comparable to the rate projected for MEA, the cumulative present value of the total power cost to CVEA for the 20- year period 1995 through 2014 is estimated to be $78.2 million. This compares to a total cumulative present value of power costs for the same period of $83.9 million for the base SGTL case representing a present value savings of $5.7 million for the integrated case. The resulting total cost of power to CVEA for the integrated case is 8.3 cents per kWh for the year 2000. This compares to 9.1 cents per kWh for the base diesel case and 9.6 cents per kWh for the base SGTL case for the same year. The wholesale power purchase rate to CVEA is projected to be approximately 6.7 cents per kWh in 1999 increasing to 9.3 cents per kWh in 2014. The wholesale rate projections are based on projections developed by CEA as presented in CEA’s 1994 Financial Forecast with adjustment for including the costs of the SGTL as a CEA system cost. The estimated impact on the wholesale cost of power resulting from the sale of power to CVEA and including the cost of the SGTL in CEA’s ratebase is approximately 0.1 cent per kWh in 2000 decreasing to essentially no impact by 2008. This cost differential will vary depending on how the Solomon Gulch project factors in to the allocation of CEA system demand costs to CVEA. In developing the estimate of the total power cost for the integrated case, it is assumed that CVEA would continue to operate and use the output of the Solomon Gulch project to supply its own loads. Because the cost of Solomon Gulch power is projected to be slightly less than the projected cost of wholesale power purchased from CEA, the net savings of the integrated case would be lower if CVEA were to purchase its full requirements from CEA. Figure 3-1 shows the projected cost of power to CVEA with the SGTL for both a “non-integrated” ML&P purchase case and an integrated CEA purchase case. For the non-integrated case, the annual costs of the SGTL are borne solely by CVEA and power is assumed to be purchased from ML&P, the lower cost provider on a “non-integrated” basis. Both of these cases assume medium load growth, continued sales to PetroStar, medium fuel escalation and the purchase of power to supply loads that are the net of power to be provided by the Solomon Gulch project. R. W. Beck 2-11 700 650 600 550 500 450 400 350 300 250 200 150 100 50 Capacity (MW) 1geak Blue misses EZ, | Bus x sums way me asa Ra ey wept may sp Figure 2-1 Anchorage Municipal Light and Power Projected Loads and Resources 2005 2007 2009 1993 1995 1997 1999 2001 2003 2011 2013 2015 2017 Resources —a— ML&P Load Plus 30% Reserves — ML&P Plus CVEA Figure 2-2 Chugach Electric Association Projected Loads and Resources seo A > Y Yj ] Yj _ _ Yy j YY Le Ll UMdddefldl 2007 2009 2011 2013 2015 2017 7/7, Resources —#— CEA Load Plus 30% Reserves —— CEA Plus CVEA Pm Re | Bed Bai ELE k ed Bu) By RY i we & a a | e r Table 2-2 Copper Valley Electric Association Comparison of Power Supply Proposals Proposed Rates - Minimal Modification (1) Net Delivered Energy e ML&P = CEA CEA (2) CEA ML&P Savings Energy Energy Energy Capacity Average | Energy Capacity Total | Energy Capacity Total | Energy Capacity Total Year| (GWh) _(GWh)__% Dif._| (c/kWh)_(c/kWh)_(c/kWh) | (c/kWh)_$/kW-mo_(c/kWh)__(c/kWh) | ($000) __($000) __—($000)_ | ($000) _ ($000) __—($000) | ($000) _ ($000) __($000) 1998 102 (206) (105) 1999 118 (163) (45) 2000 147 (46) 100 2001 133 221 ‘ 2002 156 478 ‘ 2003 165 812 977 2004 159 841 1,000 2005 158 922 1,079 2006 369 934 1303 2007 376 980 1356 2008, 271 1,019 1,291 2009 358 1,130 1,488 2010 451 1,228 1,679 2011 544 1,407 1,951 2012 647 1,436 2,083 2013 770 1,443 2,213 2014 878 1514 2,392 2015 1,073 1,544 2,617 2016 1,240 1,648 2,888 2017 1,450 1,661 3,112 Present Value (1998 - 2017) @ 8.5% 19,387 29,278 9,891 Note: (1) Rates pursuant to projections provided by AML&P and CEA revised for consistent fuel escalation and inflation. (2) CEA's rates do not include potential wheeling costs over MEA's system of approximately 1 mill per kWh. at WR ‘ 2010 2011 2012 2013 2014 2015 2016 2017 Loo La i a8 8 \ w@ & wake mos iy CSA) Reid i woe musty e: . * Table 2-3 Copper Valley Electric Association Comparison of Power Supply Proposals Proposed Rates - Revised CEA Loads led Rates (2) Projected Costs Projected Sales (1) CEA (3) ML&P CEA (4) ML&P Savings et Delivered Billing Energy Net Peak Demands’ Energy Capacity Average Energy Capacity Total Energy Capacity Total Energy Capacity Total (GWh) __ (MW) __(MW-mo) | (¢/kWh)_(¢/kWh)_(c/kWh) | (c/kWh)_ $/kW-mo (c/kWh)_(c/kWh)|]_ ($000) ($000) __—($000)_| ($000) _ ($000) _($000) | ($000) _ ($000) __($000) 36.4 94 108.7 917 541 1,458 1,019 335 1,354 102 (206) (104) 37.3 9.5 111.0 973 544 1,517 1,092 381 1,472 118 (163) 38.2 9.7 117.9 1,033 549 1,582 1,181 502 1,683 147 (46) 1 39.1 99 128.4 1,097 556 1,653 1,231 77 2,008 134 221 355 39.8 10.0 133.9 1,162 562 1,724 1319 1,040 2,360 157 478 635 40.4 10.1 139.0 1,230 567 1,797 1395 1379 2,774 166 812 977 41.1 10.2 139.0 1,299 571 1,870 1,458 1412 2,870 159 841 1,000 41.7 10.3 140.0 1371 575 1,946 1,530 1,497 3,026 158 922 1,080 42.3 10.4 141.5 1,448 578 2,026 1771 1,516 3,287 323 938 1,262 42.9 10.5 142.9 1,528 579 2,107 1811 1,564 3375 283 985 1,268 43.6 10.6 144.4 1,614 579 2,193 1,749 1,602 3,351 136 1,023 1,159 44.2 10.7 145.9 1,704 578 2,282 1,869 1,700 3,570 166 1,122 1,288 44.9 109 . 147.5 1,794 577 2371 1,989 1,789 3,778 195 1,212 1,407 45.5 11.0 149.0 1,890 576 2,466 2,110 1,940 4,050 220 1365 1,584 46.2 111 150.6 1,991 575 2,566 2,238 1,970 4,208 247 1395 1,642 46.9 11.2 152.2 2,097 574 2,671 2,382 1,980 4362 285 1,406 1,691 46.5 13 153.8 2,162 561 2,723 2,423 2,032 4,454 261 1471 1,732 46.2 114 155.4 2,230 549 2,778 2,526 2,054 4,580 296 1,506 1,802 45.9 11.6 157.0 2,299 536 2,836 2,600 2,118' = 4,718 300 1,582 1,883 45.6 n7 158.7 2,372 524 2,896 2,698 2,102 4,800 326 1,578 1,904 Present Value (1998 - 2017) @ 8.5% 19,387 27,748 8, Note: (1) Adjusted CEA projected energy to be consistent with CVEA's medium-high load forecast. The percentage increase in net peak was applied to the projected billing demands for the period 2006-2 (2) Rates pursuant to projections provided by AML&P and CEA revised for consistent fuel escalation and inflation. (3) CEA's rates do not include potential wheeling costs over MEA's system of approximately 1 mill per kWh. (4) The projected demand and energy rates provided by CEA were applied to the adjusted demand and energy to calculate the expected demand and energy revenues. Table 2-4 Copper Valley Electric Association Comparison of Power Supply Proposals Proposed Rates - Revised CEA Loads and High CEA Demand Allocator Proje ted Rates (2) CEA (3)(4) Energy Capacity Total ($000) __ ($000) __ ($000) Energy Capacity Total ($000) _ ($000) __ ($000) Energy Net Peak Demands} Energy Capacity Average} Energy Capacity Average|} Energy Capacity Total (GWh)___ (MW) __ (MW-mo) | (c/kWh)_(c/kWh)_(c/kWh) | (c/kWh) $/kW-mo (c/kWh)_(c/kWh)}] ($000) ($000) __($000) Year 1998 917 541 1,458 1,019 326 1346 102 (215) (113) 1999 973 544 1517 1,092 350 1,441 118 (194) 2000 1,033 549 1,582 1,181 nr 1,907 147 178 ‘ 2001 1,097 556 1,653 1,231 1,202 2,433, 134 646 780 2002 1,162 562 1,724 1319 1,644 2,963 157 1,082 1,239 2003 1,230 567 1,797 1395 2,093 3,488 166 1,526 1,692 2004 1,299 571 1,870 1,458 2,136 3,594 159 1,565 1,724 2005 1371 575 1,946 1,530 2,334 3,864 158 1,759 1,917 2006 1,448 578 2,026 1771 2,468 4,238 323 1,890 2,213 2007 1528 579 2,107 1811 2,603 4414 283 2,024 2,307 2008 1,614 579 2,193 1,749 2,732 4,482 136 2,153 2,289 2009 1,704 578 2,282 1,869 2,696 4565 166 2,118 2,284 2010 1,794 577 2371 1,989 2,697 4,687 195 2,120 2315 2011 1,890 576 2,466 2,110 2,848 4,958 220 2,272 2,492 2012 1,991 575 2,566 2,238 3,056 5,294 247 2,481 2,728 2013 2,097 574 2,671 2382 3,012 5394 285 2,438 2,723 2014 2,162 561 2,723 2,423 3,102 5,525 261 2,542 2,802 2015 2,230 549 2,778 2,526 3,040 5,566 296 2,492 2,788 2016 2,299 536 2,836 2,600 3,114 5,714 300 2,578 2,879 2017 2372 524 2,896 2,698 3,092 5,790 326 2,568 2,894 Present Value (1998 - 2017) @ 8.5% 19,387 33,983 14 Note: (1) Adjusted CEA projected energy to be consistent with CVEA's medium-high load forecast. The projected demand was estimated as CVEA NCP less 6 MW of Solomon Gulch. The billing demands were adjusted for the expected usage of Solomon Gulch. (2) Rates Tenors to projections provided by ML&P and CEA revised for consistent fuel escalation and inflation. (3) CEA demand rates were adjusted for the potential high demand allocator assuming the same demand as for the ML&P rate. This reflects an upper range of the CEA proposal. (4) CEA's rates do not include potential wheeling costs over MEA's system of approximately 1 mill per kWh. Table 2-5 Copper Valley Electric Association Estimated Effect of Intertie Case on CEA's System Costs ($000) 199 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2001 2012 2013 2014" 2015 2016 2017 CEA Base Costs w/o CVEA $180,740 $188,569 $199,544 $206,980 $214,437 $221,288 $233,949 $252,313 $261,259 $266,787 $274,587 $282,778 $296,887 $315,371 $323,812 $338,571 $349,159 $364,924 $375,571 Additional Costs w/CVEA Fuel Cost Increase 916 1,094 1,085 11s 1,196 1,229 1,219 1,658 1,786 1,682 1,724 1,923 2,088 2,271 2523 2,139 2,295 2,465 2,703 Other Costs 0 0 (25) 1 (25) 1 0 1 0 2 1 1 1 (24) 1 2 (23) (22) (24) Total CEA Costsw/CVEA 181,656 189,663 200,604 208,096 9 215,608 222518 235,168 253,972 263,045 268,471 276,312 284,702 298,976 §=— 317,618 + 326,336 340,712 351,431 367,367 378,250 Intertie Costs Capital Costs 2503 2503 2,503 2,503 2,503 2,503 2,503 2503 2,503 2503 2,503 2,503 2,503 2,503 2503 2503 2,503 2,503 2 O&M Costs 270 280 290 300 310 321 332 344 356 369 381 395 409 423 438 453 469 485 502 Total Intertie Costs 2,774 2,783 2,793 2,803 2,814 2,825 2,836 2,848 2,860 2,872 2,885 2,898 2,912 2,926 2,941 2,957 2,972 2,989 3,006 CEA Costs w/Intertie $184,430 $192,446 $203,397 $210,899 $218422 $225,343 $238,004 $256,820 $265,905 $271,343 $279,197 $287,600 $301,888 $320,544 $329,277 $343,669 $354,403 $370,356 $381,256 Net Costs to Serve CVEA $3,690 $3877 $3853 $3,919 $3,985 $4,055 $4,055 $4507 $4646 $4556 $4610 $4,822 $5,001 $5,173 $5465 = $5,098 = $5,244 = $5,432 $5,685 Cents per KWh 9.90 10.16 9.86 9.85 9.85 9.87 9.73 10.65 10.82 10.46 10.43 10.75 10.99 11.20 11.66 10.73 10.88 Ml 11.47 Net Benefit or (Costs) to CEA Based on Adjusted Loads CEA Revenues from CVEA = $1,477_— «$1,752, $2,158 = $2,584 $3,002 $3,091 $3,282, $3,635 $3,720 $3,686 §=— $3,729 $3,799 $3,975 $4,216 «= $4,270 $4356 = $4392 $4503 $4,579 459 5.52 6.49 7A2 753 787 8.59 8.66 8.46 B44 8.47 8.73 9.13 O11 9.17 ol 9.21 9.24 1,335) __($983)_—($963)_—($773)_($871)__—($926)_—($870)__($881) _($1,024)__($1,026)__ ($958) __($1,195)_($742)_—($853)__—($929)__ ($1,106) Based on High Demand Allocation : | CEA Revenues from CVEA 1477 1,931 2446 2971 3,486 3,580 3,809 4,186 4,293 4,281 4311 4374 4576 4852 4891 4,988 5,005 5,125 5,190 Cents per KWh 3.96 5.06 6.26 747 8.62 872 9.14 989 10.00 9.82 975 975 1005 1051 1044 1050 1039 1049 1047 Net CEA Benefit (Cost 213) ($1,946) __ ($1,407) __ ($948) __($499)__ ($474) __($246)__($321)_($353)_($276)_ ($299) __($448)_($425)__—($321)__—($575)_—($109)_—($239)~—($307)~—($495) Note: All costs are based on the information provided in CEA's proposal and not adjusted for fuel price escalation and inflation. CVEA demand and energy assumed to be delivered at O'Neil Substation. cm ke au ee ’ te ‘ we We Sam oe © “ ” om - Figure 2-3 CVEA Power Supply Comparison Proposed Power Purchase Rates 14 _ _ ~o Oo to Cents per KWh a 0-4 eaggunee oggnead | t | t + 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 —2- ML&P _ —*- CEA Base —>< CEA Adj Loads —m™- CEA High Demand = \ Section 3 POWER SUPPLY AND ECONOMIC ANALYSIS INTRODUCTION In order to evaluate the costs and benefits associated with the alternative resource options available to CVEA, a detailed power supply and economic analysis has been conducted. This analysis evaluates CVEA’s capacity loads and resources, energy loads and resources and power supply costs for each year of a 20-year period, 1995 through 2014 for two primary resource options: = Diesel generation = Implementation of the SGTL with power purchases from the lowest cost Anchorage-area provider. Alternatively, another option for evaluation, as previously described, is integrated operation with CEA. Each of these resource scenarios was established with a base case of assumptions. Additional cases were then developed for alternative assumptions for load growth, fuel costs, and new development capital costs. An analytical model was developed to evaluate the alternative cases. This model evaluates the need for additional CVEA capacity resources to supply load and maintain sufficient generating reserves, determines what resources are used to generate the energy requirements, and accumulates all costs associated with power production, including capital and operating costs. All costs in the analysis are shown in nominal (inflated) dollars. ASSUMPTIONS Principal assumptions used in the power supply and economic analysis are summarized as follows: 1. Annual inflation is assumed to be 3.5%. 2. For the purpose of present value calculations, the annual discount rate is 8.5%. 3. Future CVEA generation additions will be financed with Rural Utility Service (RUS) debt at a 5.0% annual interest rate. Repayment periods are 20 years for diesel generators and 30 years for the SGTL. Ae i POWER SuPPLY Al =CONOMIC ANALYSIS 10. 11. The SGTL will be financed with a $35 million, zero interest, 50-year State loan and $20.2 million of RUS debt. The total construction cost of the SGTL, $47.6 million in 1993 dollars, is the same as estimated in the SGTL Feasibility Study. For the SGTL resource option, the initial year of operation of the SGTL is 1999. Diesel fuel prices in 1995 are $0.63 and $0.65 per gallon in Valdez and Glennallen, respectively. Fuel prices are escalated at the general rate of inflation plus two-thirds of the real annual escalation in oil prices of 1.1%, 2.0% and -1.5% for the medium, high and low fuel price cases, respectively, as forecast by DOR in its Fall 1994 projections. The two-thirds factor is used to represent the portion of delivered oil prices that would be tied to the cost of oil as opposed to delivery cost. CVEA future power requirements are based on the medium case forecast provided in the SGTL Feasibility Study. For the high load forecast case, an estimated load of 50,000 MWh per year is added to represent assumed energy sales to the Alyeska Marine Terminal Facility. For the low load forecast case, the estimated load of the PetroStar refinery is removed from CVEA’s total energy requirement. CVEA will maintain generating capacity in each of its load centers capable of supplying the full peak demand of the particular load center with the largest generating unit in that load center unavailable. With the SGTL, Glennallen will only need to maintain generating capacity sufficient to supply its own peak demand because there will be two transmission feeds available to supply power. Transmission losses over the SGTL are 5.0%. Transmission losses between Valdez and Glennallen are 3.0%. The total annual energy generation capability of the Solomon Gulch hydroelectric project is 54,500 MWh of which 25,900 MWh would be generated in the winter (October through May) and 28,600 MWh would be generated in the summer (June through September). This is a maximum energy generation capacity which would decrease if loads are not sufficient to use all of the Solomon Gulch output. The Solomon Gulch project will be operated so as to retain the capability to generate 6 MW at any time during the winter months. Fuel usage of CVEA’s diesel generators is 13.5 kWh per gallon for existing units, 15.0 kWh per gallon for new units and 14.5 kWh per gallon for the most efficient existing unit that is planned to be transferred from Glennallen to Valdez in the diesel resource option. R. W. Beck 3-2 POWER SupPLY At =CONOMIC ANALYSIS 12. Variable O&M costs for diesel generators is 1.25 cents per kWh in 1995 dollars. Costs will increase at the rate of general inflation. 13. The annual labor and benefits cost for a generator operator is $101,000 in 1995 dollars. 14. The cost of power purchased from the Solomon Gulch hydroelectric project is 6.6 cents per kWh of which 4.0 cents per kWh is a fixed debt service component and 2.6 cents per kWh is the O&M component that will increase over time at the assumed rate of general inflation. 15. Operating costs of CVEA, other than power production costs, will increase at the assumed rate of general inflation. ALTERNATIVE RESOURCE SCENARIOS At the present time, CVEA has two primary resource scenarios that have been identified as its principal future power supply options. Both scenarios provide power sufficient to meet CVEA’s power supply requirements that are in excess of the generating capability of the power from the Solomon Gulch hydroelectric project. The SGTL however, will be capable of transmitting up to 40 MW which is more than the forecasted power requirements of CVEA during the analysis period. In developing each of the resource scenarios, consideration was given for both the capacity and energy requirements of CVEA’s total power requirements. The coincidental maximum or peak electrical demand of CVEA’s consumers plus the need to maintain some generating capacity in reserve establishes the capacity requirement. Since it is not practical for CVEA to install or remove generating capacity each year as the capacity requirement changes, new generating resources are usually sized to fulfill the projected capacity increases for several years in to the future. Upon establishment of the timing of new resource additions, the energy resources needed to supply the total energy requirements are determined. CVEA is obligated to use the energy output of the Solomon Gulch project before using other resources. Solomon Gulch is not capable of supplying the full energy requirement, however, which means that other energy resources are needed. In the case of diesel generation, this additional generation requirement will be further assigned to the most efficient diesel generators that CVEA has in its system. In the analytical model developed for this study, the need for energy generation is determined each year and the supply of this generation requirement is then specified based primarily on a comparison of costs of the available resources. The two primary resource scenarios are described as follows: R. W. Beck 3-3 hi a A tt Gi POWER SupPLy A! =CONOMIC ANALYSIS DieESEL GENERATION In this scenario, diesel generators are proposed to be used to fulfill the capacity and energy requirements of CVEA net of Solomon Gulch. This is the Base Case because it represents the present situation. Several modifications are proposed to be made to CVEA’s diesel generating plants over the next few years in order to improve the operation of these facilities and to lower overall operating costs. In general, CVEA plans to automate the diesel plants by installing supervisory control and data acquisition (SCADA) controls on several of the existing diesel generating units and on all units installed in the future. All diesel generators would then be able to be remotely controlled from a single dispatch control center at the Solomon Gulch powerhouse reducing the need for operators at both the Glennallen and Valdez diesel plants. Other plans involve the removal and replacement of the two 2,500 kW Enterprise units presently located in the Glennallen power plant with two SCADA-controlled 2,865 kW units in 1996. A 4,000 kW oil-fired combustion turbine is also planned to be installed in Glennallen in 1997. This turbine would be used primarily as backup and as a quick-start peaking unit. One of the diesel generators removed from Glennallen would be moved to Valdez in 1997, installed in the power plant and retrofitted with SCADA controls. With the completion of these improvements, CVEA expects to be able to reduce its diesel O&M staff by five employees, four in Glennallen and one in Valdez. R. W. Beck 3-4 Bu J he ad ub POWER SUPPLY At =CONOMIC ANALYSIS The following table shows the planned diesel case improvements and additions. TABLE 3-1 DIESEL SCENARIO PROPOSED ADDITIONS AND IMPROVEMENTS Estimated Cost Action ($000) Install two new 2,865-kW diesel generators in GDP $2,699 Remove Units 6 and 7 from GDP included above | Add SCADA controls to new GDP diesel generators $164 Add SCADA controls to VDP 4 and 5 Install GDP Unit 7 in VDP Add SCADA controls to “new” VDP diesel generator Install new solar turbine in GDP SUTTON TO GLENNALLEN TRANSMISSION LINE OPTION For the purpose of this analysis, the SGTL is projected to be available in 1999 at the earliest. It would be capable of delivering up to approximately 40 MW of power to CVEA although it will be necessary to install static VAR compensation for system reliability purposes if power deliveries exceed approximately 15 MW. If development of the SGTL were to proceed, it is not expected that CVEA would pursue any of the diesel generator improvements indicated in the diesel option. Rather, CVEA would continue to operate the system as it is presently operated until the SGTL became operational. With the SGTL, the generation reserve requirement in Glennallen is reduced because there would be two independent transmission feeds in to Glennallen, one from Valdez and one from Sutton. It is still expected that adequate generating capacity would be maintained in Valdez by CVEA to supply the full local load requirement in the case of a transmission failure. With installation of the SGTL, CVEA expects to reduce its diesel O&M staff by a total of seven employees leaving two operators to keep the diesel generation system maintained and in standby mode. Power is to be purchased from Anchorage area utilities and delivered over the SGTL to CVEA. Since it is estimated that ML&P would provide the lowest cost power sale to CVEA, the estimated cost of purchased power included in the analysis is based on the provisions of the ML&P power purchase proposal described in Section 2 of this R. W. Beck 3-5 au re S82 ibe L POWER SUPPLY A! =CONOMIC ANALYSIS report. The cost of the SGTL is based on the cost estimate included in the Feasibility Study. It is assumed that the SGTL will be funded with the $35 million state loan with the remainder funded with RUS loans. Following is the estimated financing requirement of the SGTL. TABLE 3-2 ESTIMATED FINANCING REQUIREMENT AND SOURCES OF FUNDS FOR THE SGTL Project Cost (1993$) $47,600 Inflation to Completion 6,200 Interest During Construction 1,400 Total Cost $55,200 Sources of Funds: State Loan(1) $35,000 RUS Loan(2) 20,200 Total Financing Requirement $55,200 (1) 50-year, zero interest loan. (2) 5 percent interest, 30-year repayment. a ee INTEGRATED CASE As previously described in Section 2 of this report, an alternative SGTL case whereby CEA bears directly the cost of the SGTL has been developed. In the integrated case, CEA is assumed to recover the costs of the SGTL through power sales to all of its wholesale and retail customers. In developing this case, it was assumed that the $35 million State loan would be made available to CEA for construction of the SGTL. Remaining costs of the SGTL would be financed with long-term debt at an assumed 7.5% annual interest rate. EVALUATION OF CASES AND COMPARISON OF RESULTS Each of the two basic resource options have been evaluated to determine the cost of power that CVEA would incur if the options were implemented. The Base Case assumptions, which include the medium load forecast and medium fuel escalation, have also been varied to show the impact of the assumptions on the results of the analysis. R. W. Beck 3-6 w E.2 BY POWER SUPPLY AS ==CONOMIC ANALYSIS The alternative variables used in the analysis are described as follows. Unless indicated otherwise, all variables, other than the specifically identified changed variable for a case, remain the same as for the Base Case. = Low and High Fuel Escalation - All fuel costs are assumed to escalate at the DOR low and high fuel cost escalation rates, respectively. = Low Load Case - The PetroStar refinery load is assumed to be supplied by PetroStar itself beginning in 1996. CVEA loads, excluding PetroStar, are assumed to increase at the rate of increase in the medium load forecast scenario. For the diesel option, all improvements and additions defined for the Base Case are assumed to be implemented. m= High Load Case - CVEA is assumed to sell power to the Alyeska Marine Terminal Facility beginning in 1999. All other CVEA loads, including those of PetroStar, are assumed to increase in accordance with the medium load forecast. Power sales to Alyeska are assumed to be made at the average system power sales rate. For the diesel option, this case is not considered applicable. = Two-year SGTL Delay - The SGTL is assumed to be delayed two years and begin operation in 2001. Costs of the SGTL are increased to include two additional years of inflation applied to the total construction cost. CVEA is assumed to supply all loads prior to operation of the SGTL with its existing resources. m Five-year SGTL Delay - The SGTL is assumed to be delayed five years and begin operation in 2004. Costs of the SGTL are increased to include five additional years of inflation applied to’ the total construction cost. CVEA is assumed to supply all loads prior to operation of the SGTL with its existing resources although two additional diesel power plant operators are assumed to be needed in the Valdez diesel plant beginning in 1997. At the time the SGTL becomes operational, these two operators as well as seven other operators are to be released. = 10% Cost Overrun - All construction costs are assumed to be increased by 10%. The analytical model used to evaluate the alternative cases projected the total costs of power supply for each year of a 20-year study period, 1995 through 2014. The annual costs were then discounted to January 1995 and accumulated to establish a single value for comparison. Another value used for comparison is the levelized cost of power. Figure 3-1 shows the projected annual cost of power to CVEA for the base case diesel and SGTL options and for the CEA integration case. As can be seen in Figure 3-1, CVEA’s cost of power in 1995 is estimated to be 8.6 cents per kWh. R. W. Beck 3-7 eg ae wy ae ue. POWER SUPPLY A! CONOMIC ANALYSIS This is the cost associated with power purchases from Solomon Gulch and the costs of fuel, operation, maintenance, depreciation and interest expense associated with the existing diesel generators. The cost of power for the three cases diverges slightly in 1996 with the assumed addition of a new diesel generator for the diesel alternative. The cost of power further diverges in 1999 with the addition of the SGTL. At that time, the cost of power for the SGTL case becomes the higher of the three alternatives and the cost of power for the CEA integration case becomes the lowest. Figure 3-1 shows that, for the base case assumptions, the CEA integration case would provide the lowest cost power to CVEA through 2014. Although the base SGTL case would provide higher power costs than the diesel case in the first few years of the SGTL’s operation, it crosses below the diesel case in 2004. For the base case assumptions, the cumulative present value of the total cost of power through 2014 is projected to be $85.1 million, $83.9 million and $78.2 million for the diesel, SGTL and CEA integration cases, respectively. This indicates that in present value terms, if CVEA were to construct the SGTL and purchase power from ML&P, CVEA would save $1.2 million in power costs over the 20-year period when compared to the diesel case. The savings over the cost of diesel generation would increase to $6.9 million for the CEA integration case. For the low load case where PetroStar is assumed to supply its own power requirements beginning in 1996, the results of the analysis are shown in Figure 3-2. As can be seen in Figure 3-2, the CEA integration case still provides the lowest cost of power in each year of the analysis following the assumed installation of the SGTL in 1999. The cost of power for the SGTL case is higher than the cost of power for the diesel case until 2013 because the fixed costs of the SGTL must be allocated over fewer kWh if PetroStar is not being served by CVEA. In 1999, the estimated cost of power is 10.9 cents per kWh for the SGTL case without PetroStar as compared to 9.5 cents per kWh for the SGTL case with PetroStar. The cost of power in 1999 for the diesel case is not as drastically affected by the loss of the PetroStar load, being 9.5 cents per kWh for the low load case without PetroStar and 9.0 cents per kWh for the base case. For the diesel case, CVEA would not incur as much investment in new diesel generation plant if the PetroStar load were not served. Because the CEA integration case assumes that the cost of the SGTL is borne by CEA, CVEA’s power costs under this alternative are the least affected by the loss of the PetroStar load. In 1999, the cost of power is estimated to be 8.1 cents per kWh for the base case CEA integration case as compared to 8.5 cents per kWh if the PetroStar load is not served. The actual impact on CEA wholesale power rates of not serving PetroStar was not estimated as part of this study. The impact on a cost per kWh basis is not expected to be overly significant, however. Nevertheless, CEA should be consulted further on this matter. R. W. Beck 3-8 POWER Supply Ai ECONOMIC ANALYSIS For the low load case without PetroStar, the cumulative present value of CVEA’s cost of power is $68.7 million, $72.3 million, and $63.0 million for the diesel, SGTL, and CEA integration cases, respectively. For this case the cumulative present value of the cost of power for the SGTL alternative is greater than that for the diesel case by $3.6 million. The CEA integration case would provide savings of $5.7 million when compared to the diesel case and $9.3 million when compared to the SGTL case. The 2-year and 5-year delay cases for the SGTL do not significantly affect the resulting cost of power to CVEA. It is important to note for the delay cases, however, that it is assumed that CVEA would hold off on any generation improvements or additions through the entire delay period. This could result in slight reductions in service quality and reliability to CVEA’s consumers until the SGTL was completed. If CVEA were to construct the SGTL and could sell power to the Alyeska terminal facility, as assumed for the high load case, CVEA’s levelized cost of power would be approximately 1.2 cents per kWh or 12% lower than it would be for the base case load forecast. This is because the fixed costs of the SGTL are allocated over additional kWh sales. For the CEA integration case, higher loads would not significantly affect the cost of power to CVEA because the fixed costs of the SGTL are not a direct obligation of CVEA. As can be expected, lower assumed future fuel prices lowers the estimated cost of power to CVEA for both the diesel and SGTL cases since the cost of power production for both cases is tied to oil prices. Higher assumed fuel prices would increase the cost of power for both resource alternatives. R. W. Beck 3-9 Cost of Power (cents/KWh) “~ Bus Bik) BL Eb! Bay ERE eae! BAK Esa K Bd key Ky E Figure 3-1 Projected CVEA Total Cost of Power 180 Base Case Resource Options 12.0 10.0 8.0 - 6.0 fone eee ee ee eee ee eee ee nee a SO 7 wo \o N eo an oc Nn oO 3 wo xo tS oc a oO a N oO s an an an n QQ So So So a a x = a 2 8 § £8 28 8 8 8 € £8 & €§ FR RRR Year —Case 1 - Base Diesel —™— Case 2 - Base SGTL —t— Case 2H - SGTL (CEA Integration) et on hse Figure 3-2 Projected CVEA Cost of Power Low Load Case (Less PetroStar) 14.0 S N al 10.0 +----------«-. 6.0 4.0 ((M>1/S1U29) IaMog JO SOD 2.0 FOZ £107 cL0z TLOZ OL0z 6007 8007 £002 9007 S007 $007 €007 7007 1007 0007 6661 8661 Z66T 9661 S661 Year —*-— Case 2I - SGTL (CEA Int., Low Load) —#-SGTL —— Diesel eug 7 Bn t Section 4 SUMMARY AND FURTHER CONSIDERATIONS SUMMARY This study had two primary components. The first dealt with the evaluation of the two power supply proposals received by CVEA in response to its request for proposals. The second component estimated the total cost of power that would be incurred by CVEA over a 20-year period for alternative power supply development options. The content of the second part of the study is typical of an integrated resource planning study although somewhat limited in that not all power supply and conservation options potentially available to CVEA were investigated. In order for CVEA to purchase power from either CEA or ML&P, the SGTL will need to'be constructed. The power supply proposals received by CVEA provide information that was not available at the time of the SGTL Feasibility Study to further evaluate the economic feasibility of the SGTL. Consequently, CVEA decided to include the additional comparative evaluation of CVEA’s two primary resource alternatives, diesel generation and power purchases over the SGTL, as part of the overall study effort. The power supply proposals received by CVEA from CEA and ML&P are similar in that both would provide power for a 20-year term and CVEA would be required to pay a demand charge and an energy charge for the amount of power purchased. The cost of power purchased would be based on the cost of power production (e.g., fuel and variable operations and maintenance costs) plus an allocated share of the fixed generation costs (e.g., depreciation, interest expense, insurance). Since both ML&P and CEA generate power with natural gas-fired combined-cycle combustion turbines and fuel costs are comparable between the two utilities, the energy cost component of the purchase power rate will be similar from either CEA or ML&P. At the present time, however, CEA estimates that its need for replacement of existing generation plant beginning in 2006 will significantly affect its demand charge component to all of its customers, including CVEA if CVEA were to purchase power from CEA. ML&P does not project that it will have the same need for significant investment in its generation plant within the 20-year contract term. In order to directly compare the two power supply proposals, the proposals were reviewed and standard assumptions were established from which the cost of power to CVEA over the 20-year term could be estimated. For the most aT ws SUMMARY AND FU ER CONSIDERATIONS comparable set of assumptions, it is estimated that the power supply proposal from ML&P would result in present value savings to CVEA of $14.6 million in total over the 20 years when compared to the proposal from CEA. It is important to note that although both proposals state that power to be sold to CVEA is firm, power will only be made available to CVEA by ML&P as long as ML&P has sufficient power resources available unless CVEA reserves and pays for a fixed amount of power. This means that ML&P’s contract does not fully meet with CVEA’s request for a firm, net requirements, “take-and-pay” power supply. The specific terms of any contract with CEA or ML&P would need to be negotiated so it may be possible to establish contractual provisions that would more fully meet with CVEA’s needs. The evaluation of alternative power supply options determined the present value of CVEA’s total power supply costs over the 20-year evaluation period. For the base case assumptions of medium load growth and medium fuel price escalation, it is estimated that if CVEA were to construct the SGTL and purchase power from ML&P, CVEA would realize present value savings of $1.2 million in power supply costs when compared to diesel generation. If CVEA were to lose the PetroStar load, however, the present value power supply costs for the SGTL/ML&P case would be $3.6 million higher than the comparable costs for the diesel generation case. The PetroStar load is a very significant factor to the results of the analysis. Another case evaluated in the study was the CEA integration case whereby it was assumed that CEA would construct the SGTL and include the costs of the SGTL as a CEA system cost. The SGTL costs would then be borne by all CEA customers. CEA would sell power to CVEA over the SGTL on a similar basis to power sales CEA makes to its other wholesale customers. For the CEA integration case it is estimated that CVEA would realize present value savings of $6.9 million in its total power supply costs over the 20-year study period when compared to diesel generation. The impact to CVEA of the loss of the PetroStar load would be much less for the CEA integration case than it is estimated to be for the base SGTL case. It is estimated that CVEA would still realize present value savings of $5.7 million for the CEA integration case when compared to diesel generation if the PetroStar load were not served by CVEA. An important aspect of the CEA integration case is the impact on CEA revenue requirements that would result from CEA incurring the cost of constructing and operating the SGTL. For the base case load assumptions, it is estimated that CEA’s costs to serve CVEA (which include the costs of the SGTL) would exceed the benefits from the sale of power in all years of the analysis. Although the total cost impacts on CEA’s total unit revenue requirement are relatively small on a cost per kWh basis, it still may be difficult for CEA to implement the integrated case if costs R. W. Beck 4-2 Bris SUMMARY AND Ft ER CONSIDERATIONS exceed benefits for more than a few years. With the CEA integration case, CEA is assumed to take the risk associated with significant changes in CVEA’s power requirements. If the PetroStar load were not served, CEA’s unit revenue requirement would increase because the fixed costs of the SGTL would be allocated over fewer kWh sales. On the other hand, if CVEA’s power requirements were to expand as could happen if power were sold to the Alyeska terminal facility, CEA and all of its customers would benefit from the integration case. FURTHER CONSIDERATIONS As with any study of this kind, there are many other issues to consider when reviewing the study results. In addition, during the course of the study several issues became known that could significantly affect CVEA’s power supply situation in the future. Principal among these issues are: = .The possibility that PetroStar may choose to develop an electrical generating plant at its Valdez refining facility to generate power for its own use and potentially sell power to CVEA. PetroStar has proposed to use an off-product of its refining process to fuel a cogeneration power plant that CVEA may be obligated to purchase power from if offered by PetroStar. m The possibility that the Alyeska marine terminal may want to purchase power to supply all or a portion of its power supply needs, or conversely, may want to sell surplus power from its generating plant to CVEA. Alyeska recently evaluated the feasibility of using hydro-carbon vapors recovered from tankers as a generating fuel. m= The Governor has requested an interagency review of the issues related to the feasibility of the SGTL. The outcome of the review committee’s investigation is not known at this time but it could have a profound impact on CVEA’s power supply planning effort. = The overall implications of the CEA integration case. The information used in this study to estimate the cost impacts of the CEA integration case was very limited. CEA indicated that it was not in a position to provide further information at the time the study was conducted. CEA’s 1995 financial forecast should be considered in any subsequent analysis. CEA’s position on the concept of integrated operation with CVEA should also be further investigated, particularly with regard to recent changes on the CEA board. In addition, possible alternative pricing structures, such as a Copper Valley surcharge, should be discussed with CEA to R. W. Beck 4-3 SUMMARY AND FUE :R CONSIDERATIONS determine what impacts these alternative structures may have on the ability of CEA to implement the integration case. All of these issues could significantly impact CVEA’s power supply situation. Unfortunately, many of the issues cannot be quantified for analysis at the present time. Although CVEA may have some opportunity to influence some of the potential outcomes, for the most part the issues are out of CVEA’s control. All of these issues are currently ongoing and new information may be available at any time. CVEA should continue to monitor each and all of the foregoing issues in anticipation of additional power supply cost evaluation. R.W. Beck 4-4 CC Dennrs CHUGACH “LECTRIC Rend ASSOCIATION, INC. L Plan, associarion, INC, EUGENE N. BJORNSTAD, P.E. General Manager August 1, 1995 Mr. William R. Snell, Executive Director FAX: 561-8998 AIDEA Hard Copy to Follow 480 W. Tudor Road Anchorage, AK 99503 Subject: Copper Valley Intertie Dear Mr. Snell: Chugach Electric Association (Chugach) and the Cooper Valley Electric Association (CVEA) are steadfast in our support of the Copper Vallcy Intertic. We believe that the Intertie is a viable and appropriate project that will assist in reducing electric power costs for the residents and businesses of the Copper Valley and Valdez and contribute to the economic development of Alaska. We have affirmed our joint intcrests in seeing this project move forward, The Board of Directors of both Chugach and CVEA have recently adopted the attached resolutions that direct each utility to commence negotiation of a firm power agreement. A firm power agreement will assure that a supply of low-cost energy will be continuously available to the electric customers of CVEA when the Intertie is complete. The negotiations will explicitly consider possible ways Chugach could participate in Intertie construction, operation and maintenance. We are committed to working together on a long-term power supply arrangement for CVEA, and urge you and the other members of the Review Committee to assist us in this beneficial undertaking. The Intertie will provide significant benefits to all Alaskans by enhancing the economic potential of . a vital region of the state, A favorable review by the committee will help us obtain those benefits and lower costs to users of electricity. Thank you for your consideration. Sincerely, Zed oo Eugene N . Bjornstad General Manager ENR: TLicah:95026gb.11 Attachment ce: J. Shively, Departinent of Natural Resources M. Irvwin, Department of Community and Regional Altairs T. Knowles, Governor, State of Alaska C. Lurless, Copper Valley Electric Association, Inc. 5601 Minnesota Drive ¢ P.O. Box 196300 ¢ Anchorage, Alaska 99519-6300 Phone 907-563-7494 » FAX 907-562-0027 A ELECTRIC ASSOCIATION. INC. Anchorage. Alaska RESOLUTION WHEREAS, providing electric power by Chugach Electric Association, Inc. (Chugach) to Copper Valley Electric Association, Inc. (CVEA) has the potential to reduce the costs of service to Chugach members by spreading fixed costs over a larger customer base: WHEREAS, CVEA can substantially reduce its power supply costs through purchases from Chugach; WHEREAS, The Copper Valley Intertie (Intertie) may provide mutual savings to both Chugach and CVEA members; WHEREAS, Chugach supports environmentally sound construction of basic infrastructure which facilitates economic development; WHEREAS, electrical interconnection of the Railbelt with Valdez and Copper Valley offers the potential for long term system growth; and WHEREAS, Chugach’s participation in construction, ownership or maintenance of the Intertie may facilitate interconnection of the Valdez and Copper Valley regions with the Railbelt; WHEREAS, Chugach’s wholesale customers will have the option to include or exclude the costs and benefits of the transaction in their rates; NOW, THEREFORE BE IT RESOLVED that Chugach supports the construction of the Intertie and urges the State of Alaska to facilitate and expedite development of the Intertie; IT IS FURTHER RESOLVED that the General Manager is directed to commence negotiation of a power sale arrangement with CVEA for a sale of firm power net of Solomon Gulch output which ensures that benetits accrue to all Chugach members and which may include: - Pooling the costs of the Copper Valley Intertie with other Generation and Transmission expenses on the Chugach system; ° Participation in construction, ownership or maintenance of the Intertie: . Other services or assistance to CVEA in aid of either interconnection or provision of power to CVEA. CERTIFICATION L Patricia B. Jasper . do hereby certify that [ om vesessnsanea—-—-. SOerevary of gach Electric Assoctation. lnc., lactric non-profit cooperauve membership corporation organited and existing under the laws Sie geal Atala idvat lie' lesgaane tae] ossiplows ena carved! (apy alle resokatians eee 19th July 1095; Directors of thie corporation, duly and properly called and held on the... el raed oat ee ee elon oes os idee otek te ex ad box not been rescinded * 19th IN WITNESS WHEREOF, I bave hereunto subsctibed my name and ctfixed the seal of this corporation this...“ —.... a aT = COPPER VALLEY ELECTRIC ASSOCIATION, INC. GLENNALLEN, ALASKA RESOLUTION 95-15 POWER SUPPLY NEGOTIATIONS WITH CHUGACH ELECTRIC ASSOCIATION WHEREAS, Copper Valley Electric Association, Inc. is a rural electric cooperative serving the resideats of the Copper River basin and the City of Valdez; and WHEREAS, CVEA’s members pay among the bighest unsubsidized eclectic rates in the staic of Alaska, and WHEREAS, CVEA's Board of Directors have been striving to find the Most cost effective power supply alternative for its members, and WHEREAS, it appears CVEA can substmtially reduce is power supply costs through purchases from Chugach; aod WHEREAS, the Sutton co Glennaiien intestie may provide montal savings to both CVEA and Chugach members; and WHEREAS, an electrical intercounection of the Raifbek with Valdez ad Copper Valicy offers the potential for long-term system growth; and WHEREAS, Chugach’s participation m construction. ownership or maintenance of the intertie may facilitate imtercomnection of the Valdez and Copper Valley ‘regions with the Railbelt; now thezefore BE IT RESOLVED, the Copper Valley Electric Board of Directors 3upporta the construction of the Sutton to Giennallen imtertic and urges the Statc of Alasica to facilitate and expedite development of the intertic; and 07/21/95 08:09 TX/RX NO. 1472 P.002 Resolution 95-15 Page 2 BE [fT FURTHER RESOLVED, that the Copper Valley Electric Association Board of Directors directs the General Manager to commence negotiations of a power sale arrangement with Chugach Electric Association for the purchase of fim power nct of Solomon Gulch output which ensures that benefits accrue to all Copper Valley Electric members and which may include: * Pooling of costs of the Copper Valley Intertie with other Generation and Transmission expenses on the Chugach system; e Participation in construction, ownership or maintenance of the Intertie; ¢ Other services or assistance to CVEA in aid of either interconnection of provisions of power to CVEA. Approved and signed this 20th day of July, 1995, in Valdez, Alaska. 7A 7 Paul S. Holland, President (seal) 07/21/95 08:09 TX/RX NO.1472 P.003 a Copper Valley Intertie June 29, 1995 hugach' one eg [\ Topics Overview General Manager Chronology State Loan R W Beck Study RFP Discussion Benefits Limiting Factors © Recommendation Sutton- Glennallen 138 KV Line John S. Cooley Manager, Planning June 29, 1995 lide 3 Qe ae Chronology e 12/92 Power supply feasibility ¢ 5/93 Legislature authorizes $35 million loan e 12/93 Offer to be a resource to CVEA e 3/94 Power supplier affirmation e 7/94 DCRA determines line was feasible e 9/94 Chugach proposal in response to RFP e 2/95 Expanded proposal e 3/95 Blue Ribbon Committee formed © 4/95 Joint Chugach/CVEA board meeting ¢ 6/95 Closure of CVEA RFP process Grieg IN State Loan lectric e CVEA has highest non-PCE rates ¢ Scaled down version of Northeast Intertie ¢ CVEA lobbied for interties ¢ Loan part of 1993 legislative interties package - $35 million - 50 year term - No interest payments - Feasibility Study required Gucci R W Beck Study ¢e Economic Feasibility per State standards - transfer payments ignored e Multiple Load Forecasts - Low, Medium-Low, Medium-High, High e Alternate Resource Plans - All Diesel, Intertie, Allison Lake, Silver Lake, Coal Gimig RW Beck Economic Analysis Cumulative Present Value of System Costs (millions) re a Mn ae aol All Diesel Intertie Allison Lake fugachyan RFP Process and Proposals ¢e Requested 10 to 20 yr Power Supply Proposal - for delivery at Sutton e ML&P and Chugach responded ¢ Chugach Proposal - Firm Power Requirements net of Solomon Gulch - Negotiated 10-20 yr Contract - Take-and-pay System sale delivered at Sutton - Tariff rates approved by APUC - 1998 estimated cost 4 cents per kWh - Offer to negotiate additional benefits for CVEA ¢ CVEA closed out process hugach Ss | Qe Discussions Chugach staff has met with: e Clayton Hurless, CVEA General Manager e CVEA Board of Directors e Chugach Board of Directors e Valdez city officials e Petro Star Refinery officials e Alyeska Pipeline officials e Blue Ribbon Panel ¢ Economics Annual Benefit to Chugach Beaute eke | “= CVEA pays 4% of Line Costs Te = Woy OTA La ==“CVEA pays 20% of Line eS CO mM © © Oo ©& oO — Oo SF oS CO a oy ™ Cw Intertie cost based on State loan plus 12.6 $million RUS loan Chugach Estimate & of Projected CVEA Total Cost of Power Base Case Resource Option cents/kWh 14 | 12 § LO i Oo > 7 oF ti OD - “a D ® sae Base Diesel -CEAIntegration & o Oo _ — “_ j NY os OM oN ™ Evaluation of Power Supply Alternatives, R W Beck, June 1995 Slice 14 hugach) Teetriclgi Relevant Factors and Politics ¢ Benefits directly proportional to load - Petro Star Refinery: purchase, self-generate, co-generate? - Alyeska Terminal: isolated, co-generate, purchase? - Affect of low cost power on Copper Valley economy? - TAPS: shutdown when? effect on economy? ¢ Governor reviewing loan authorization - Blue Ribbon report in August ¢ Strength of CVEA commitment ¢ Sutton residents opposition to intertie ¢ Cost/Benefit sharing among Chugach/MEA/HEA/SES Slide 12 Gisci@y Recommendation ¢ Demonstrate support for intertie ¢ Commence negotiating Power Sale Arrangement with CVEA - Firm, Requirements net of Solomon Gulch - Pool cost of intertie with Chugach G&T assets - Participate in construction with CVEA - Otherwise aid CVEA intertie activities as necessary ¢ Ensure benefits accrue to Chugach customers Shde 13