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HomeMy WebLinkAboutCopper Valley Electric Assoc., Inc.-History & Status of Power Generation Resources 1993 | t/a ! ‘| Li Re han COPPER VALLEY ELECTRIC ASSOCIATION, INC. P.O. Box 45 P.O. Box 927 Glennallen, Alaska 99588 Valdez, Alaska 99686 (907) 822-3211 (907) 835-4301 ) HISTORY AND STATUS OF POWER GENERATION RESOURCES October 1993 COPPER VALLEY ELECTRIC ASSOCIATION, INC. P.O. Box 45 P.O. Box 927 Glennallen, Alaska 99588 Valdez, Alaska 99686 (907) 822-3211 (907) 835-4301 HISTORY AND STATUS OF POWER GENERATION RESOURCES October 1993 STATEMENT OF PURPOSE The purpose of this report is to educate the reader as to the history and status of power generation resources at Copper Valley Electric Association. The report will discuss the problem of high rates, existing generation resources, past efforts to develop new, affordable resources, and if successful, will give the reader an objective basis for understanding the Association’s efforts toward promoting the Sutton to Glennallen transmission line. TABLE OF CONTENTS EXECUTIVE SUMMARY BRIEF HISTORY BUSINESS TYPE AND SERVICE TERRITORY CONSUMER CLASSIFICATIONS WEATHER RATES RAILBELT SYSTEM CVEA’S GENERATION SYSTEM MECHANICAL CONDITION OF GENERATION PLANTS Solomon Gulch Glennallen Diesel Plant Valdez Diesel Plant History of the Valdez Diesel Plant LIFE EXPECTANCY OF DIESEL PLANTS CVEA’S CURRENT SITUATION Loads and Resources Power Production Cost THE SEARCH FOR COST-EFFICIENT RESOURCES The Decision to Build the Solomon Gulch Hydro Plant Birth of the Four Dam Pool Organization Conclusion on Solomon Gulch OTHER PROJECTS STUDIED Pressure Reducing Turbine in Alyeska’s Oil Pipeline CVEA Interconnection with Alyeska System Least Cost Planning Allison Lake/Solomon Gulch Integration Project Increasing the Height of Solomon Gulch Dam and Spillway Development of a Hydro Project at Silver Lake Merger with Golden Valley Electric Association Splitting CVEA into Two Systems Based on District Boundaries VIABILITY OF A DEDICATED GENERATION PLANT TO SERVE CVEA’S FUTURE NEEDS Replace Existing Diesel Plants with New, More Fuel-Efficient Diesel Engines Hobbs Industries Coal Plant Natural Gas Generation COMPARISON OF AN ISOLATED GENERATING PLANT TO AN INTERCONNECTION WITH THE RAILBELT TRANSMISSION SYSTEM The Northeast Intertie (Sutton-Glennallen-Delta Junction) Sutton to Glennallen 138 kv Transmission Line Advantage of Interconnection with the Railbelt Transmission System to an Isolated Generating Plant Cost of Railbelt Power at O’Neill Substation 1993 Legislative Action The Feasibility Study Being Prepared by R.W. Beck & Associates What Next SUMMARY INDEX OF ATTACHMENTS 11 12 12 13 13 13 14 16 16 17 18 20 20 21 ACRONYM AIDEA APUC ARECA Beck Chugach CVEA DCRA DNR FDP GDP GVEA HDR KV O&M PEI PMC PRS PSA SGH SGL INDEX OF ACRONYMS MEANING Alaska Energy Authority Alaska Industrial Development & Export Authority Alaska Public Utilities Commission Alaska Rural Electric Cooperative Association R.W. Beck & Associates, Seattle, Washington Chugach Electric Association, Anchorage, Alaska Copper Valley Electric Association Department of Community & Regional Affairs Electric and Magnetic Fields Department of Natural Resources Four Dam Pool Glennallen Diesel Plant Golden Valley Electric Association, Fairbanks, Alaska HDR Engineers Kilovolt Kilowatt Kilowatt Hour Megawatt Operation & Maintenance POWER Engineers, Hailey, Idaho Project Management Committee Power Requirement Study Power Sales Agreement Solomon Gulch Hydro Sutton to Glennallen Line Valdez Diesel Plant COPPER VALLEY ELECTRIC ASSOCIATION, INC. HISTORY AND STATUS OF POWER GENERATION RESOURCES EXECUTIVE SUMMARY Copper Valley Electric Association, Inc., (CVEA) provides central station electric service to a relatively large geographical area in Southcentral Alaska. The service area consists of the Copper River Basin communities, including Glennallen, Gakona, Gakona Village, Gulkana, Gulkana Village, Tazlina, Copper Center, Copperville, Kenny Lake, Tolsona, Mendeltna, Nelchina, Eureka, and Sheep Mountain, and the organized area of the City of Valdez. Administrative headquarters are located in Glennallen, while engineering, operations and production are managed from the Valdez district office. In 1992, residential consumers in the Copper River Basin and Valdez districts paid an average of 20.9¢ and 17.3¢ per kwh respectively. These rates are believed to be the highest unsubidized rates in Alaska. In contrast, the consumers of Matanuska Electric Association (MEA), which joins CVEA on the west, pay an average of about 10.5¢ per kwh. A part of the rate differential is due to the isolated and rural character of CVEA’s system, but the majority of the difference is attributable to the cost of power. MEA is interconnected to the Railbelt generation and transmission system and receives its wholesale power requirements from Chugach Electric Association for approximately 4.5¢ per kwh. CVEA generates all of its own power requirements with the Solomon Gulch hydroelectric plant and two diesel plants. One diesel plant is located in Glennallen (7 mw) and the other in Valdez (10 mw). For the years 1989 through 1992, CVEA generated 20%-35 % of its total power needs with diesel generation at an average cost of 15.24¢ per kwh. The other 65%-80% of the power was derived from the Solomon Gulch hydro and purchased from the State of Alaska for 6.4¢ per kwh. The blended average cost of CVEA’s total power requirement for the years 1989 through 1992 was approximately 10.0¢ per kwh, which is obviously more than double MEA’s cost. Beginning at least as far back as 1970, CVEA’s Board of Directors recognized that the diesel generation system was the major factor in the high retail rates that CVEA has to charge. They also recognized that the inherent volatility of petroleum prices and the high cost of maintaining and operating the diesels would drive rates even higher in the future. Numerous studies were conducted in an effort to identify other generating resources that would displace the need for the diesels and lower the cost of power to the member-owners. One of those studies, conducted by the U.S. Army Corp of Engineers, identified Solomon Gulch as a hydro site that had the potential to achieve the objectives of replacing the diesels and producing power at a lesser cost than the diesels. ES1 Solomon Gulch was constructed and began operation in 1982, but it has not been able to provide for all of CVEA’s needs due to an insufficiency of water beginning in October and lasting until mid to late May of each year. As stated previously, diesel generation provides the supplemental power needed, in addition to Solomon Gulch during the period of water insufficiency, to serve the load. The result is that the low utilization and efficiency factor of using the diesel plants continues to have a significant adverse impact on the overall cost of power. Beginning in 1993 and extending thereafter, Solomon Gulch will essentially be fully utilized and is projected to produce approximately 45,000 mwh annually on a conservative planning basis, requiring that CVEA be prepared to serve all new load growth with supplemental generating resources. Subsequent to Solomon Gulch coming on line and the realization that it would not produce enough power to completely displace the diesel plants, CVEA’s Board again began the search for other resources that would work well with the Solomon Gulch hydro and displace the diesels. A number of additional studies have been made which are described in the main body of this report. Until 1992, all of the projects considered fell short, in one way or another, of achieving the objectives established by CVEA. CVEA’s Board of Directors and staff identified the criteria a project must meet to fulfill the long-term requirements of the Association. The project must be able to supplement Solomon Gulch hydro during inadequate water levels, displace costly diesel generation facilities, be readily available in case of an emergency shut-down of the hydro, provide for future long-term load growth of CVEA and the communities served without periodic generation construction, have the ability to be flexible for base or supplemental loading during cogeneration periods, and provide a means for rate mitigation. In June of 1992, CVEA’s Board of Directors approved retaining POWER Engineers, Inc. (PEI) of Hailey, Idaho, to conduct a preliminary study to determine to what extent a 138 kv transmission line constructed between O’Neill Substation near Sutton to Pump Station 11 Substation near Glennallen would meet the aforementioned objectives. PEI submitted the first draft of the study in August 1992, and the preliminary conclusions were encouraging. The final report was submitted by PEI in December of 1992, and it indicated the line would transfer up to 40 mw of power to Pump Station 11 Substation at a cost of approximately $40.5 million. In January of 1993, CVEA entered into a Memorandum of Agreement with the Alaska Energy Authority (AEA) to conduct an in-depth independent feasibility study of the proposed project. AEA subsequently retained R.W. Beck & Associates of Seattle, Washington, to conduct the study, which is currently in progress. CVEA, with the help of the Alaska Rural Electric Cooperative Association, the City of Valdez, and the Greater Copper Valley and Valdez Chambers of Commerce, and others, launched a concerted lobbying effort in the 1993 session of the Alaska Legislature to obtain State assistance in funding the project. The Legislature approved and appropriated $35 million for a 50-year, zero interest loan, subject to acceptance of the aforementioned detailed feasibility study by the Department of Community and Regional Affairs. The Legislature also approved the issuance of up to $25 million in bonds by the Alaska Industrial Development and Export Authority to fund a supplemental loan to CVEA for the balance of the cost of line. ES2 AEA and R.W. Beck have held two rounds of public meetings in the communities of Sutton, Chickaloon, Glacier View, Glennallen, and Valdez to receive public comment and concerns. Another round of meetings will be held in late October or early November to receive comments on the final draft feasibility study. Significant changes have been made in the routing of the line in response to public concerns. Other changes may be made as a result of the final public meetings. The routing changes made to date have increased the cost of the line substantially; however, CVEA feels they are necessary and justified to demonstrate a good faith effort for public support of the project and to accommodate, where possible, expressed public concerns. The transmission line is the only project considered to date that fundamentally achieves all of the objectives that CVEA has established. It is a large project, but with the State’s help in funding, it is achievable. When completed, it will provide a wide range of long-term benefits to the member-owners of CVEA through expanded economic development opportunities, an improved quality of life by making electricity more affordable, and a long-term, reliable power supply that works well in coordination with the Solomon Gulch hydroelectric plant. When constructed, the Sutton to Glennallen transmission line will not be an end to CVEA’s efforts of providing least-cost central station service to those Alaskans desiring it. Rather, it will be a new beginning for the organization as well as all the communities served. Beginning with rate mitigation, it will provide a cost effective alternative to local residents who currently generate their own power or live without electricity. The expansion and development possibilities could be endless. Communities could begin fulfilling their goals to entice new businesses into the area when electrical costs become more economical. This project could make electricity the power of choice, thereby improving the quality of life for the people living in the Copper River Basin and the City of Valdez. ES3 COPPER VALLEY ELECTRIC ASSOCIATION, INC. HISTORY AND STATUS OF POWER GENERATION RESOURCES BRIEF HISTORY Copper Valley Electric Association, Inc. (CVEA) was organized in the Copper River Basin during the mid-1950’s and was energized in 1959, initially serving 38 consumers over 48 miles of line. Subsequent to the 1964 Alaska Earthquake, CVEA acquired the Valdez Power Co. from a private owner who did not have the means or desire to rebuild the badly damaged system or to construct the new system needed to serve the relocated townsite. CVEA has grown from that very modest beginning to its present size of nearly 3,000 consumers, representing 8,000-9,000 Alaskan residents who, according to CVEA’s Power Requirement Study (PRS) dated January 5, 1993, are projected to use 74 million kwh annually. These consumers are served over 333 miles of distribution line owned by CVEA and 106 miles of 138 kv transmission line owned by the State of Alaska and operated by CVEA. CVEA’s total assets on December 31, 1992, were $20,406,205, with a consumer equity of $7,371,780, or 36.1%. B TYPE AND SERVICE TERRITORY CVEA is a member-owned electric cooperative serving a relatively large geographical area in the Valdez and Copper Basin regions of Southcentral Alaska. CVEA’s service territory is divided into two districts, the Valdez district and the Copper River Basin district (hereinafter referred to as the Copper Basin). The Valdez district boundaries are generally synonymous with the organized area of the City of Valdez. The Copper Basin district covers a relatively large land area within the Copper River Valley and includes the communities of Gakona, Gakona Village, Gulkana, Gulkana Village, Glennallen, Tazlina, Copper Center, Copperville, Kenny Lake, Tolsona, Mendeltna, Nelchina, Eureka, and Sheep Mountain. Administrative headquarters are located in Glennallen in the Copper Basin district. Engineering, operations, and power production are managed out of the Valdez district office. The distribution service area extends from: Alyeska Pipeline refrigeration site number 1, Mile Post 156 Richardson Highway, south to mile 61. All of Valdez and extending north to Mile Post 12 on the Richardson Highway. 80 miles east on the Glenn Highway from Mile Post 109 to Glennallen. East on the Tok Cutoff from Gakona Junction to the Alascom tower at Mile Post 12. East from the Junction of Highways 4 and 10 to Mile Post 18 on the Edgerton Highway near Chitina. CON: SIFICATION, CVEA serves six classes of consumers comprised of residential, small commercial (50 kva or under), large commercial (50-1,000 kva), large power (over 1,000 kva), street lighting systems, and public buildings. A tabulation of the projected number of consumers by rate class and their approximate annual energy requirements as reflected in the PRS are presented in the following table. [_—_cssteson | rotcommmes | x | anmatxon |__| Large Commercial ? 28,278,000 Public Street Lighting j 105,000 Public Buildings i 1,059,000 Petro Star 19,710,000 pee ee i a WEATHER The Valdez district is impacted by a cool, wet, coastal maritime weather system that provides an average of about 65 inches of precipitation annually, mostly in the form of snow which averages 300 to 350 inches of annual accumulation. Temperatures in the Valdez district generally range from +10°F in the winter to the high sixties in the summer. There are temperature variations outside of this range, but winter days below zero and summer days above 75°F are rare. The Copper Basin district is situated approximately 60 miles inland from Valdez and extends into the interior from the coast about 160 miles. The Copper Basin district has a very different weather pattern than the Valdez district. Annual precipitation averages 11 to 12 inches, and temperatures range from -60°F to a high of +95°F. RATES CVEA’s member-owners pay some of the highest unsubsidized retail rates in Alaska. In 1992, residential consumers in the Copper Basin and Valdez districts paid an average of 20.9¢ and 17.3¢ per kwh respectively. Residential rates are approximately double those paid by the consumers of the Alaska Railbelt utilities. A part of the difference in rates is attributable to the low density and isolated nature of CVEA’s system, but the largest factor is the difference in the cost of purchasing and generating power to serve the power requirements of CVEA’s members. RAILBELT SYSTEM The Railbelt utilities (consisting of Chugach, Matanuska, Golden Valley, and Homer Electric Associations, City of Seward Light & Power, and Anchorage Municipal Light & Power) are all cooperative or municipal electrical utility systems that are interconnected to one large transmission and generation system. The interconnected system provides for the efficient scheduling and utilization of available generation and transmission resources. The Alaska Energy Authority (AEA) and each of the utilities own some part of the system. Chugach Electric Association (Chugach) is the largest of the Railbelt utilities and, with one exception, provides all or a part of the power supply requirements to the other participating utilities. The Alaska Systems Coordinating Council reported in its April 1993 “Coordinated Regional Bulk Power Supply Program Report" that the Railbelt utilities have projected a 1994 summer peak hourly demand of 544 mw against a total available summer capacity of 1,176 mw. The report projects a winter peak hourly demand in the winter of 1994/1995 of 649 mw against a total available winter capacity of 1,284 mw (see Attachment A). Cost of generation and purchased power for the Railbelt utilities varies from 314-5¢/kwh. 'VEA’ TION SYSTEM CVEA’s power supply is provided by a stand-alone generation system (not interconnected to any other utility) comprised of two diesel plants owned by CVEA and the 12 mw Solomon Gulch hydro plant (SGH) owned by the State of Alaska and operated by CVEA under a long-term contract. Total prudent operating capacity of the two diesel plants is approximately 14.5 mw. Water, operational, and maintenance constraints reduce the total system installed prudent operating capacity from 26.5 mw to a low of approximately 16 mw in May. CVEA’s projected 1994 peak demand is 12.2 mw. SGH has a nameplate capacity of 12 mw but, due to the low ambient temperatures in Valdez, has the capability of operating 10% over nameplate without any detrimental effects on the generators, thus increasing the capacity of the plant to 13.2 mw, subject to the availability of water in the reservoir. Although the nameplate capacity of SGH exceeds CVEA’s requirements, that capacity is only available for four months out of the year due to the lack of water in the reservoir (see Attachment B). SGH has historically provided all of CVEA’s power requirements from mid to late May until early to mid October. For the four-year period 1989 to 1992, hydro production has varied from a low of 40,000 mwh to a high of 46,700 mwh. As a conservative planning base, CVEA projects that SGH will be able to produce 45,000 mwh annually through various weather and usage patterns. This is estimated to be the maximum dependable production from SGH, which will require CVEA to be prepared to serve all additional new load growth with supplemental generating resources. During the October to May period when SGH will not provide 100% of energy requirements, the two diesel plants meet the balance of CVEA’s requirements. For the past four years, the diesel supplement has ranged from 13,000 mwh to 21,000 mwh. The addition of the Petro Star Refinery in early 1993 is expected to add 19,710 mwh to CVEA’s total load and is projected to increase the diesel supplement to 35,000 mwh. As stated above, from 1993 on CVEA will have to be prepared to serve all new load growth from non-hydro resources. If future load growth tracks CVEA’s 1993 PRS, supplemental requirements will grow to 55,000 mwh in the year 2003 and 72,000 mwh in the year 2013. MECHANICAL CONDITION OF GENERATION PLANTS Solomon Gulch SGH is in excellent condition and can be expected to operate into the indefinite future with normal maintenance. The plant was brought on line in 1982 and has a reasonable life expectancy of 50 to 75 years. Glennallen Diesel Plant The Glennallen diesel plant (GDP) is made up of seven reciprocating diesel engines: two 300 kw, 1959 vintage Fairbanks Morse; one 1963 and two 1966, 600 kw Fairbanks Morse; and two 1975, 2,624 kw Enterprise units. The two 1959 Fairbanks Morse units are not included in the total capacity available. The unavailability of parts and the prohibitive cost of having them special made prompted the decision several years ago not to continue scheduled major maintenance on the units. Both units are operational in an emergency but are not considered to be sufficiently reliable to be classed as a base resource. For the past several years, the GDP has been used as the primary supplemental generating resource and has been maintained to an acceptable standard of reliability, albeit at an increasing cost each year. Valdez Diesel Plant The Valdez diesel plant (VDP) is comprised of six reciprocating diesel engines and one turbine: three 1966, 600 kw Fairbanks Morse; one 1972, 1,900 kw Enterprise; one 1975, 2,600 kw Enterprise; one 1952, 965 kw Enterprise; and one 1976, 2,800 kw SOLAR turbine. The VDP is presently maintained to an acceptable standard of reliability with all units available for base load operation. History of the Valdez Diesel Plant When SGH was brought on line in 1982, the VDP was essentially placed in mothballs. At the time of mothballing, the plant was not in very good condition due to the deferral of maintenance in anticipation of SGH becoming operational. In 1990, Petro Star Valdez, Inc. (a joint venture of Petro Star North Pole, Petro Marine, and Alaska Refining, Inc.) began discussions with CVEA regarding electric service for a 30,000-barrel-per-day refinery they were proposing to build near Valdez. 4 As those discussions progressed, CVEA began assessing its generating resources and how it could meet the additional load should the load materialize. As a result of that assessment, it was determined that the only cost effective method to serve the new load, in the short term, was to bring the VDP back into reliable operating condition. Extensive maintenance was performed on the plant in the summer of 1992, and it was integrated into the generating mix in the fall of 1992. Further maintenance has been performed in 1993. With the addition of the Petro Star load in January of 1993 and other system load growth, the VDP will provide a larger share of the supplemental generation requirement. LIFE EXPECTANCY OF DIESEL PLANTS There are two basic criteria for establishing the life expectancy of any piece of equipment--mechanical and economic. If operating and maintenance costs are disregarded, the mechanical life of a diesel generating plant could theoretically be extended indefinitely. When operational and maintenance costs are plugged into the equation to determine the economic life (the cost viability of continuing to operate the plant), several questions have to be addressed. The first question is how do total costs of operating the diesel plants compare with available alternatives? The answer to this question is straightforward--there is not currently an existing alternative resource available at any price. Secondly, what is the best estimate of future cost, including fuel and maintenance, to operate the plants? The answer to the second question is not so straightforward. Attempts to accurately project future prices, particularly oil prices, are subject to world political stability and unforseen market forces. Prices over time have trended up, and conventional wisdom seems to provide that the upward trend will continue. The possibility of political unrest somewhere in the world causing skyrocketing prices is an ever-present specter. The cost of maintenance on CVEA’s diesel plants will undoubtedly continue to increase. In the past two years, it has been increasingly difficult to find "shelf" parts for the engines. As a result, some parts have to be special made at a cost that is significantly higher, in some cases two or three times higher, than "shelf" parts had they been available. Therefore, it is reasonable to conclude the cost of operating the diesel plants will continue to increase, but to what extent is unknown. In addition to the rising cost of operation and maintenance as the machines age, the risk of a catastrophic mechanical failure increases. Such a failure can render the equipment inoperable for significant periods of time and, depending upon the nature and extent of the failure, can conceivably make a repair uneconomical. In that eventuality, CVEA would be forced to acquire short-term generation capability at a substantially higher cost. The third question is what is the capability of the diesel plants to serve the existing and future loads of CVEA? The answer to this question is relatively straightforward--very limited. CVEA did an in- depth assessment of its generating resources in 1992 and concluded that if the diesel plants were maintained in reliable operating condition, the existing and short-term future loads could be served. This conclusion was based on the assumption that load growth would be within a reasonable variance of the projections of the current PRS and no new large loads (500 kw or above) would come on line. Short-term was defined as not more than five or six years. In summary, the useful life of CVEA’s diesel generating plants will be determined by the availability of more cost-efficient resources. If there is not an available alternative, the diesel plants will have to be maintained and operated. In this instance, the cost of maintenance and fuel become an unavoidable cost CVEA will have to endure in order to meet its “utility responsibility" to serve all existing and future loads within its franchised service area. It is a near absolute certainty that CVEA will make every possible effort to meet its “utility responsibility," which will not only make it necessary to maintain the existing diesel plants but possibly add additional diesel generators in the event of significant unexpected load growth. CVEA’S CURRENT ATION Loads and Resources CVEA’s peak system demand is projected to approach 12 mw in 1993, with total projected sales of approximately 74,000 mwh. It is anticipated that Petro Star will solve their barge loading problem in 1994, and the growth in their load, plus other system load growth, will increase the total demand to 12+ mw in 1994 and to 13.4 mw in 1997. Power Production Cost Power produced at SGH is purchased from the State of Alaska. SGH is operated by CVEA under a long-term contract in coordination with three other state-owned hydro projects through the Four Dam Pool (FDP) Project Management Committee. The FDP is comprised of five purchasing utilities (City of Wrangell, Petersburg Municipal Power & Light, Ketchikan Public Utilities, Kodiak Electric Association, and CVEA) and AEA. The purpose of the FDP is to coordinate the planning, budgeting, operation, and cost pooling of four state-owned hydro projects (Swan, Tyee, and Terror Lakes, and Solomon Gulch). Operation and maintenance (O&M) costs are pooled and averaged for all the projects. The average O&M cost for fiscal year (FY) 1994 is set at 2.4¢/kwh. In addition to the O&M cost, the State of Alaska collects 4¢/kwh "debt service cost," making the total cost of SGH power 6.4¢/kwh. Production costs at the two diesel plants can vary substantially from year to year primarily due to changes in fuel and maintenance costs. The average cost of production of both plants for the four-year period 1989 through 1992 was 15.24¢/kwh. CVEA expects some reduction in this average cost for the next two or three years due to the inherent economies of scale that should result from an increase in production of diesel generated kwh. For the same period, 1989 to 1992, CVEA experienced a blended average cost per kwh sold of 9.99¢ for all power produced with the diesel plants and purchased from SGH. THE SEARCH FOR COST-EFFI RES CVEA’s Board of Directors and management have recognized, since as early as the 1970’s, that at some point it would become necessary to replace the diesel plants. It was inevitable then, as it is today, that the plants would become uneconomical to operate. CVEA has long been aware that alternative generating resources should be identified and integrated into the system if the extraordinarily high rates paid by CVEA’s member-owners were to be reduced or at least stabilized. This awareness was the catalyst that prompted a series of studies beginning in the early 70’s in the search for more cost-efficient resources. Several studies were conducted by the federal government, the State of Alaska, and CVEA. The most comprehensive of those studies was one conducted by the Corp of Engineers titled "Southcentral Alaska Railbelt Area, Hydroelectric Power and related Purposes for Valdez, Alaska" published in 1976. That study identified Solomon Gulch and Allison Lake as the best sites of those investigated for the development of a hydro resource to serve the needs of CVEA’s members. At the time the project was conceived, it was anticipated SGH would meet essentially all of the power requirements of CVEA and the diesel plants could be placed in some degree of standby. The Decision to Build the Solomon Gulch Hydro Plant Based on the aforementioned study and additional engineering and economic studies, CVEA’s Board of Directors made the decision in 1978 to go ahead with the SGH project and applied for a Rural Electrification Administration (REA) loan. The loan was approved, and construction was started in 1980. During the course of construction, the project experienced significant cost overruns, which posed a serious threat to CVEA’s ability to complete it due to the shortage of funds. Birth of the Four Dam Pool Organization Three other hydro projects (Swan, Tyee, and Terror Lakes), which either had been or were being built in the state at the same time the SGH project was being constructed, were also experiencing similar financial problems. To resolve the problems, the State of Alaska intervened. It paid off the accumulated debt, completed the projects, and orchestrated the formation of the FDP organization to coordinate the operation of the projects. Cost of the completed projects totaled $499,987,790, of which the legislature approved $307,987,790 as grants. The balance of $192,000,000 was classified as loans to the projects, which are being repaid over a long period of years by the 4¢/kwh debt service charge. For the first 15 years, the agreements provide the 4¢/kwh is an interest charge only, which means there is not any reduction in the principle. The term of the Power Sales Agreement is 45 years from the execution date in 1985. In addition to the PSA, the participants have entered into a number of other agreements that interpret and define the relationship of the five utilities and AEA. Taken in total, they tie the parties together in a complex legal web until the expiration of the Power Sales Agreement in 2030. Any significant action proposed by one of the members that changes or modifies the PSA requires the unanimous approval of all six parties to the agreement. Conclusion on Solomon Gulch Even though SGH has not lived up to its original expectation in terms of energy production, it is a valuable part of CVEA’s generating resources. It provides a number of important benefits to CVEA’s member-owners. i. When there is sufficient water, it provides lower cost power than can be generated with the diesels. Zs During the period of water insufficiency, it provides some power that has a favorable mitigating effect on the total cost of generation. 3: It provides a very important insurance policy to the Valdez district during the avalanche season if the Glennallen to Valdez transmission line should be out of service. 4. Should the proposed Sutton to Glennallen intertie line (SGL) be put into operation, SGH will provide an invaluable capacity component and voltage support system to assure a high quality of service to the consumers. THER PR‘ TS STUDIED Subsequent to SGH being completed and operational, CVEA’s Board of Directors and Staff continued the search for new cost-effective resources that would integrate well with SGH and replace the diesel plants. For the past ten years, CVEA has committed considerable time and resources to assessing additional projects that would further the ultimate goal of rate reduction. Following is a brief review of those projects and ideas. Pressure Reducing Turbine in Alyeska’s Oil Pipeline At the request of CVEA, Alyeska Pipeline Service Co. and CVEA conducted a joint study on installing a pressure reducing turbine in the pipeline below Thompson Pass. For technical reasons, Alyeska determined it could not permit the turbine to be installed. CVEA Interconnection to Alyeska System There has been ongoing discussion between CVEA and Alyeska for a number of years relative to interconnecting the two systems between SGH and Alyeska’s powerhouse at the TAPS terminal. The discussion period has spanned the terms of at least four CVEA General Managers and three Alyeska Terminal Managers. Alyeska has consistently determined that such an interconnection is not in their best interest, primarily because of their concern that they would be classed as a public utility and be regulated by the Alaska Public Utilities Commission (APUC). In 1988, CVEA and the Alaska Rural Electric Cooperative Association (ARECA) were successful in effecting legislation that specifically exempted Alyeska from the jurisdiction of APUC. Even with that exemption, Alyeska has continued to decide against interconnection on the premise that the State can undo what it has done and, consequently, Alyeska is not willing to run the risk of being regulated as an electric utility. Recently, CVEA obtained an estimate of Alyeska’s generating cost that indicates their cost of generation may be higher than CVEA’s. The information appears to be reasonably accurate because Alyeska generates with three 12'4 mw oil-fired steam turbines, which are known to be fuel inefficient. Assuming the information is accurate, CVEA would not receive any benefit from interconnection unless Alyeska decided to sell power at less than their cost of production. As oil throughput declines in the pipeline, Alyeska has been in the process of cutting personnel and operating costs, which makes it unlikely that they would decide to provide power to CVEA at less than cost. Least Cost Planning In 1990, the Department of Community & Regional Affairs (DCRA) and CVEA jointly retained Stone & Webster Engineering to do an Integrated Resource Study, or "least cost" plan. The study analyzed opportunities to solve CVEA’s problem through both a "demand side" and a "supply side" model. On the demand side, CVEA’s rates are so high that the consumers’ frugality in the use of electric energy has essentially eliminated the opportunity for any measurable additional conservation. On the supply side, the conclusion reached was to research new cost-effective generation or transmission. The study recommended that a rubber dam or a new, more efficient remote-controlled diesel plant were the two options worthy of consideration. From that recommendation, CVEA initiated the studies of those two options. Allison Lake/Solomon Gulch Integration Project In 1992, AEA commissioned HDR Engineers (HDR) to conduct a feasibility study and cost estimate for integrating Allison Lake with SGH by means of a two-mile tunnel to transfer water from Allison Lake to Solomon Lake during the October to May period of water insufficiency. The project cost was estimated to be $30,937,257, not including interest during construction. The project was designed to add a small powerhouse at the Solomon Lake reservoir that would utilize the Allison Lake water as it flows into Solomon Lake to produce 3 mw of capacity and displace an estimated 26,745 mwh of diesel-generated energy annually. The project indicated a benefit to cost ratio of 1.70 over its economic lifetime. The decision was made not to pursue the project based on its inability to produce adequate energy to retire the diesel plants and because the estimated cost of 13¢/kwh was only slightly less than diesel cost. Increasing the Height of Solomon Gulch Dam and Spillway In 1991, CVEA retained HDR to produce a feasibility study and cost estimate to increase the height of the Solomon Gulch dam and spillway to provide increased water storage. The Rubber Dam Option: The study estimated a five-foot rubber dam would cost $1,547,548 and produce an additional 1,702,000 kwh annually. CVEA assessed the project and determined that it would only produce approximately 5-6% of the supplemental generation needed in 1995 at a kwh cost about equal with diesel generation. Based on that finding plus the uncertainty of the Federal Energy Regulatory Commission requirement for amending the project license, it was determined the project should not be pursued. Raising the Dam with Concrete and Earth: The 1992 HDR Allison Lake study commissioned by AEA required the preparation of a cost estimate to raise the Solomon Gulch dam and spillway 32 feet with concrete and earth. HDR estimated this project would cost $27,796,984 and would produce 15,040 mwh of energy at a cost of 15.59¢/kwh. Again, the project was not pursued because it was not capable of producing enough energy to allow the diesels to be retired and the cost was actually higher than the cost of diesel generation. Development of a Hydro Project at Silver Lake As a part of the Allison Lake study, AEA asked HDR to produce a cost estimate for the development of a hydro project at Silver Lake. Silver Lake is approximately 15 miles southeast of Valdez at the head of the Duck River. The extremely rough terrain between Silver Lake and Solomon Gulch would require the use of a submarine transmission line to tie the project to CVEA’s system. Such lines are not only expensive to install but also have inherent maintenance and reliability concerns. HDR estimated the project cost at $70,107,626 in 1995 dollars. They estimated a levelized annual cost of 14.7¢/kwh for the total cost of operation and amortization. The project would be capable of producing 14 mw of capacity and an estimated annual energy of 48,750 mwh. The project would make it possible to retire the diesels in the short term, but its high cost would not provide any opportunity to reduce rates to CVEA’s members. 10 Merger with Golden Valley Electric Association In 1987, Golden Valley Electric Association (GVEA) and CVEA conducted an in-depth study of consolidating the two utilities to determine if the CVEA system could be absorbed into GVEA to facilitate a rate reduction for CVEA’s consumers without a significant adverse impact on the rates of GVEA’s members. After considerable discussions, the negotiations ended in August 1989 when the GVEA Board President, Ronald Bergh, wrote a letter stating, "This is not the time to further pursue a merger of CVEA and GVEA." After surveying the membership, CVEA’s Board concurred with GVEA to discontinue merger negotiations. Splitting CVEA into Two Systems Based on District Boundaries CVEA and the City of Valdez conducted an in-depth study of the beneficial and detrimental aspects of splitting the service territory into two systems based on district boundaries. The study found the duplication of equipment, personnel, and administrative costs that would occur as a result of the split would increase rates for both districts. It also revealed it would be extremely difficult to arrive at a mutually acceptable agreement for the split of existing physical plant and other assets. FA ICA’ TING PLANT TO SERVE CVEA’S NEEDS The numerous studies that have been done by or for CVEA over the past 20 years that have analyzed a significant number of projects and propositions in an attempt to identify a cost-effective alternative to the diesel plants have revealed one very important factor. The construction of a dedicated and isolated generating plant (not able to interconnect to a transmission grid) to meet CVEA’s supplemental requirements, regardless of its fuel type, cannot be used efficiently nor will it provide an immediate or long-term opportunity to mitigate CVEA’s high rate problem, for the following reasons: Le The plant would have to have the capability to produce capacity and energy greater than CVEA’s current peak load requirements in order to meet the peak demand and accommodate some increment of load growth. The capacity required to meet peak load would only be required for a short period of time when SGH reservoir is drawn down, usually in late May. The balance of the year, SGH will provide some amount of power, and for four to five months, as mentioned earlier, it will provide all of CVEA’s current power requirement. 2: A plant that would just meet CVEA’s peak demand, if brought on line in 1995, could be utilized to a maximum of 47% of its production capability in a year of low precipitation. In the more likely year of average precipitation, the plant would experience a utilization factor of 36%. Neither represent an efficient use of capital. As CVEA’s load grows in the future, the situation gets worse rather than better. Additional capacity would have to be added at a higher unit cost. The utilization factor would be further reduced because of the short period of time the full capacity is needed. If new units are not added, it would be necessary to revert back to the old diesels. Either of those actions would inevitably increase the unit cost of production. 11 3: A plant being operated in a subordinate role to SGH needs to have the flexibility to efficiently meet a wide variety of load requirements. At the beginning of the period of hydro insufficiency, a plant has to be able to respond to whatever scheduling requirement is dictated by the weather or inflow into SGH reservoir. Replace Existing Diesel Plants with New, More Fuel-Efficient Diesel Engines In 1990-1991, CVEA assessed the possibility of building a new, expandable diesel plant. The plant would initially have two 3.6 mw Caterpillar or Wartsilla remote-controlled diesel generators. Consideration was given to building the plant next to the new Petro Star Refinery at Valdez with a direct piping connection to the refinery that would save the freight on the fuel. The initial plant was estimated to cost between $10 and $12 million, including land, substation, auxiliary equipment, and buildings. The generator building was designed to add one additional unit at an estimated cost of $3.5 to $4 million. A number of projections were prepared using different assumptions for load growth, increases in fuel cost, maintenance, operation, and the cost of emissions control upgrades that would be required. Of the projections made, the best case predicted a modest increase in rates, and the worst case predicted CVEA’s rates could increase into the mid 30¢/kwh range in ten to 15 years. The phased replacement of the existing diesel units over a considerable period of years would require the existing plants to be kept operational, which would eliminate any opportunity for rate mitigation. Hobbs Industries Coal Plant Hobbs Industries of Anchorage, Alaska, has submitted a proposal to AEA to construct and operate an 11 mw coal-fired plant in Glennallen to provide CVEA’s supplemental power generation requirements. The project has been incorporated in the SGL feasibility study being conducted by R.W. Beck & Associates of Seattle, Washington (Beck). The coal plant proposal has a number of apparent problems in terms of its ability to serve the supplemental power requirements of CVEA. I The original capacity of 11 mw would only be sufficient to serve CVEA’s current requirements. As load grows in the future, it would be necessary to add additional units or revert back to the diesel plants. Neither of these options would meet the long-term goals set by CVEA to eliminate its dependence on the diesel plants in order to reduce its retail rates and provide for future economic development opportunities within the service area. Ds The proposal stipulates the diesel plants would be required to back up the coal plant for up to 200 hours of unscheduled outage time per year. This limitation mandates that the diesel plants be maintained in hot standby readiness. 12 B. The plant has zero diversity, i.e., it originally is comprised of one boiler, one turbine, one generator, etc. Should the smallest component critical to the plant’s operation fail, the entire plant will go down. 4. The plant’s ability to serve the small increments of power needed in the shoulder periods of CVEA’s load shape is questionable, which could cause additional dependence on the existing diesel plants. 5. The boiler unit of the proposed plant would be a "refurbished" unit built in 1956 and used in Chugach’s Ship Creek plant until the late 1970’s. The boiler was initially fired with coal and later converted to natural gas before it was declared obsolete by Chugach and sold in 1986 to Slana Energy. The age and use factors alone create a reasonable question of the unit’s ability to operate efficiently and reliably. Natural Gas Generation A number of statements were received during the public comment meetings on the Sutton to Glennallen line that there is a known large field of natural gas in the Copper Basin. It was suggested that CVEA should develop a natural gas resource not only to generate power but to provide low-cost gas to the residents of its service area. Other comments were made that CVEA should wait until the natural gas pipeline was built from the North Slope to Valdez. In order to respond to those comments, CVEA contacted the Oil and Gas Division of the State Department of Natural Resources (DNR) relative to the possibility of natural gas in the Copper Basin and also met with the Yukon Pacific Corporation, who holds the environmental permits for the gas pipeline. Information received from the Oil & Gas Division of DNR is attached and indicates that no known commercial-quality deposits of natural gas are identified at this time (see Attachment E). Yukon Pacific, while optimistic of their future chances of constructing the gas pipeline, were cautious about how long it would take them to get all of the purchase and sales contracts in place. Their most optimistic forecast would put the line in service in 2002-2005, well beyond the period of time CVEA has to decide how it will improve its power supply resources. CVEA does not believe that either of these two possibilities have sufficient merit to justify any substantive study. MPARISON OF AN ISOLATED GENERATING P. TO AN INTER! TION WITH THE RAILBELT TRANSMISSION SYSTEM The Northeast Intertie (Sutton-Glennallen-Delta Junction) In the late 1980’s, AEA commissioned a major reconnaissance study, published in June of 1989, to determine the feasibility of constructing a large capacity 230 kv intertie line from Sutton to Glennallen and on to Delta Junction. The line was envisioned to accomplish a number of important objectives but primarily to provide loop feed reliability to Fairbanks and other Interior communities. 13 There are other significant benefits to the line, such as providing CVEA with an unlimited supply of much more economically priced power from the Anchorage Bowl, upgrading service to the military installations along the Richardson Highway, and providing the basic electrical infrastructure to encourage future economic development in the resource rich Interior. The study produced a preliminary cost estimate of $156 million in 1989 dollars. In 1990, the Alaska Legislature considered the overall cost and feasibility of the proposed intertie project and decided it would not be possible to fund the entire line in the short term. In view of that decision, the line was divided into two segments, the Southern Leg (Sutton to Glennallen) and the Northern Leg (Glennallen to Delta Junction). For reasons not fully understood, it was decided to concentrate first on the Northern Leg. That segment was estimated to cost $95 to $100 million in 1989 dollars. The project was reintroduced to the 1991 Legislature, and a concerted effort was made to gain legislative support for funding the Northern Leg. However, due to the effect of declining oil revenues on state revenues, the effort was not successful. The State administration and legislators at that time were of the opinion that unless another major windfall in state revenue was forthcoming, it would be unlikely that projects of the magnitude of the Northeast Intertie could be funded anytime in the near future. CVEA renewed the effort to obtain funding in the 1992 legislature, but the effort was also unsuccessful for the same reasons as in 1991. It is widely known that the Northeast Intertie would yield significant future benefits to both the current Railbelt utilities and those utilities that would become a part of the Railbelt, such as CVEA. The additional sales of energy would help keep rates of the existing Railbelt utilities lower than they otherwise would be. The access to lower priced Railbelt power could provide opportunities for the expanded use of electric energy and the resulting improvement in the quality of life for CVEA’s consumers. It would also provide new and expanded economic development opportunities for all the people living in the large geographic area of Southcentral Alaska that would be served by the line. Sutton to Glennallen 138 kv Transmission Line Following the adjournment of the 1992 Alaska Legislature, CVEA elected to reassess its power supply strategy to determine if any option had been overlooked that would meet the necessary criteria to reduce or, at the very least, stabilize CVEA’s rates and provide adequate reserves for reasonable long-term load growth. It was suggested that CVEA look into the cost of constructing a smaller capacity line in lieu of the proposed Northeast Intertie between Sutton and Glennallen. The rational was that such a line could provide for CVEA’s long-term needs and be economical enough to construct and operate. If a meaningful reduction in capital cost of the line could be achieved, it would appreciably improve the possibility that a funding package could be put together. 14 CVEA discussed the concept with other utility directors, managers, engineers, and AEA, who all believed the idea had possible merit. In July of 1992, CVEA’s Board of Directors approved retaining Power Engineers, Inc. (PEI) of Hailey, Idaho, to conduct a preliminary screening study to determine if a smaller line would be feasible. PEI was instructed to consider the following criteria for the study parameters: i Calculate the capacity of the line within acceptable voltage drop limitations to assure it was adequate to allow the diesel generators to be placed in cold standby for emergency use only and ensure the line would have capability to serve the economic development needs and long-term load growth of CVEA’s service area. ae Determine the annual cost to assure it would not impact CVEA’s rates adversely with emphasis on identifying design criteria and construction methods that could possibly reduce rates. 35 Adopt design criteria that would achieve a usable and reliable life expectancy of at least 50 years. 4. A line constructed to a high standard of reliability without losing sight of the cost of construction. The initial draft study indicated the line had the potential to meet this criteria, and in September of 1992, CVEA’s Board of Directors approved extending the study to test the validity of the assumptions used in the preliminary study. CVEA and PEI asked Chugach, Matanuska Electric Association, AEA, and two large general contractors to review the first study and participate in a technical review meeting with the purpose of identifying any errors in assumptions or engineering decisions that would not work in the Alaska environment. The utilities and contractors were very cooperative in their response. The time and effort they put into the review was of invaluable help in objectively assessing the assumptions that were being used to develop the cost estimate. With the data and advice obtained at the meeting, PEI revised the initial draft and published a final study in December 1992. That study has provided the basis upon which CVEA has proceeded to date. The PEI study found that a 138 kv transmission line could be constructed between O’Neill Substation near Sutton to Pump Station 11 Substation near Glennallen at a cost of approximately $40.5 million. The line would be able to transfer up to 40 mw of power. The line would meet all of the criteria established by CVEA. It would be capable of meeting all of the supplemental generation needs and provide for additional load growth into the indefinite future. It would accomplish the major goal of providing reliable capacity, which would allow the existing diesel generators to be placed in cold standby for use only in emergencies. PEI estimated the annual maintenance and operation cost would be approximately 1% of the actual construction cost of the line. Based on their latest cost estimate, that would equate to about $300,000 per year, or less than 1¢/kwh for the anticipated transfer of 39,000 mwh in 1995S. 15 Debt service on the line is the one item that has caused some concern from the outset. Debt service on a $40.5 million loan at the current REA-CFC blended interest rate of 5.8% amortized over 35 years would be $2,728,243 annually, or 7.0¢/kwh for 1995’s supplemental power requirement of 39,000 mwh. Advantage of Interconnection with the Railbelt Transmission System to an Isolated Generating Plant The advantages to CVEA becoming interconnected to the Railbelt transmission system are significant. The following list is not exhaustive but provides a basis for comparing interconnection to other alternatives that have been studied. 1. Depending upon the size, transmission lines can transfer a virtually unlimited amount of power. This is one of the most important considerations of this alternative. A transmission line would not only meet CVEA’s current requirements but would provide for load growth into the indefinite future. Interconnection is the only available option that would provide for essentially immediate service to a new large load which would significantly enhance the opportunity for economic development within the service area. 2 Depending upon the cost and the transfer capability of the transmission line, this alternative may be the most efficient use of capital. When compared to any other alternative studied to date, it is clear that a transmission line is the only project that will meet CVEA’s goal of providing for long-term load growth and an opportunity to reduce rates. 35 As reported earlier in this document, the integrated Railbelt system has summer available peak capacity of 1,176 mw and available winter peak capacity of 1,284 mw. Industry standards recommend 30-40% reserve capacity to serve load growth and for equipment failure. Even after adding an adjustment of 40% to projected Railbelt loads to provide reserve capacity for the above purposes, a surplus of 414 mw in the summer and 375 mw in the winter is available. The reason for this discussion is to point out that a significant surplus of power exists in the Railbelt to serve future load growth without major additional capital expenditures. This factor is very important to understand why Chugach has projected the price of wholesale power should decrease in real terms over the next 15 years (see Attachment C). Cost of Railbelt Power at O’Neill Substation Discussions with two of the Railbelt utilities has determined the cost of power at O’Neill Substation will depend on the quality of power purchased. Power quality ranges from a lower quality "nonfirm," or interruptible, to a high grade of "firm" that would only be interrupted by acts of God, major equipment failure, etc. Current price varies from 2.8¢/kwh for "immediately interruptible nonfirm" to 5¢/kwh for guaranteed "uninterruptible firm." CVEA is currently assessing how SGH can be used to provide the capacity necessary to allow purchasing some grade of nonfirm interruptible power. 16 1993 Legislative Action In cooperation with ARECA, the City of Valdez, the Greater Copper Valley and Valdez Chambers of Commerce, and others, CVEA launched a concerted lobbying effort in the 1993 session of the Alaska Legislature to obtain state assistance in funding the line. The request received an excellent reception by the majority of legislators, and in the final days of the session, legislation was passed approving a $35 million, 50-year, zero interest loan for design and construction of the project. The legislature also authorized the Alaska Industrial Development & Export Authority (AIDEA) to issue up to $25 million in bonds for any additional funding needed over the $35 million loan. The loan is subject to the acceptance, by the State of Alaska Department of Community & Regional Affairs (DCRA), of a complete feasibility study currently being prepared by R.W. Beck & Associates. The final Beck report is due to be published in November with the anticipation that it will be accepted by DCRA relatively soon thereafter. Until the study is complete, it is impossible to formulate the final economic impact, but CVEA is encouraged it will be favorable. Assuming the Beck study verifies PEI’s cost estimate, the 50-year, zero interest loan authorized by the legislature would reduce the debt service to $1,070,497 annually, or 3.2¢/kwh based on 1995’s projected load, a savings of 4.3¢/kwh. The most significant advantage provided by this project that would not be provided by any other project which has been studied is that the kwh cost would decline in the future as CVEA’s load grows. For example, if the load growth tracks the 1993 PRS, the kwh cost would decline to 1.9¢/kwh in ten years and to 1.5¢/kwh in 20 years. This advantage is a result of the relatively large 40 mw transfer capacity of the line. Debt service cost will become fixed in hard dollars in the year of construction. As CVEA’s loads grow in the future, two cost mitigating factors will result. First, as more kwh are transferred over the line, the cost per kwh will decrease because debt service will remain constant (the divisor gets larger, the dividend remains the same). Second, as inflation reduces the value of money, the real cost per kwh for debt service reduces proportionately. There are a number of other apparent advantages of the SGL over any other alternative that has been studied or offered to date. Some of these advantages are: 1. The line has the capability to serve CVEA’s long-term load growth requirements. 2 It has a design life of at least 50 years and a high probability of lasting much longer, assuming proper maintenance. 3: It has an initial capital cost per unit of available capacity that is less than any other alternative studied. 4. It will provide benefits to the Railbelt system by expanding their marketing opportunity for surplus power. li 5: It will provide CVEA with the ability to purchase lower priced power, thus allowing for stable rates and possible rate mitigation, making a crucial step forward in CVEA’s efforts to control rates. 6. Stable or reduced rates would enhance the local economies and support the economic development of the CVEA communities. It would entice new businesses to the areas and encourage existing businesses to expand. ie CVEA’s diesel plants could be maintained in cold standby, thus reducing the consumption of fossil fuels, which would reduce exhaust emissions at the diesel plants. Reducing the burning of fossil fuels also reduces the tractor/trailer traffic on the highways and road system, resulting in reduced wear and tear on the roads. The Feasibility Study Being Prepared by R.W. Beck & Associates In late 1992, CVEA, in consultation with AEA, was informed that Alaska statutes require a detailed feasibility study for a major project to be eligible for state financial assistance. Historically, AEA had funded and conducted the required feasibility studies for major projects of statewide significance. AEA was in the middle of the FY93 budget year and unable to fund the study until the FY94 budget year, assuming the legislature would approve its budget request. In the course of discussing ways to expedite the study, it was agreed that CVEA would fund the study and AEA would request funds to reimburse CVEA in the FY94 budget year. On January 6, 1993, AEA and CVEA executed a Memorandum of Agreement that authorized AEA to conduct an independent study of the intertie project to meet the requirements of state law. CVEA agreed to fund the study in accordance with AEA’s pledge to include a request in its FY94 budget for reimbursement of the study cost. AEA circulated a Request for Proposal to several engineering firms and, based on their assessment of qualifications, awarded the feasibility study contract to Beck. The scope of the feasibility study being conducted by Beck is designed to provide a comprehensive look at the environmental, engineering, and economic factors of the proposed 138 kv line. While the conclusions drawn by the study should outline the viability of the line in more definitive terms than the original screening studies, some aspects of the design criteria adopted by Beck have lead to considerable discussion as to whether they represent the most cost-effective approach to the project. There has also been considerable discussion and some disagreement about the economic approach being applied. According to Richard Emerman, Senior Economist of AEA, the Beck study will take a global economic view of all of the alternatives. In at least some aspects, this method analyzes the "cost to society" which may or may not be consistent with actual market cost. 18 It is the understanding of the author that, in the global context, the study will not take into account any special considerations given one project and not the others, i.e., the 50-year, zero interest loan authorized by the legislature for the SGL. This approach is defended as the standard method of assessing the benefit to cost ratio of a project of this type. CVEA has accepted that argument but cautions it will necessitate looking beyond the economic findings of the Beck study to the plan of finance, which will consider all the factors, both common and project specific, to reach a clear, definitive, comparative value of each of the alternatives. In February 1993, AEA and Beck conducted public meetings in Sutton, Chickaloon, Glacier View, Glennallen, and Valdez to receive public input on the proposed line. CVEA staff and directors attended the meetings and answered questions posed by the attendees. Public response in Glennallen and Valdez was positive. Significant opposition to the project was encountered at the Sutton, Chickaloon, and to some extent, the Glacier View meetings. Dissenting comments were from people concerned that CVEA and AEA had not adequately studied alternative projects that could solve CVEA’s problem without building the line. AEA and CVEA attempted to review the significant work and study that has been done in the past to address the situation. The explanation was generally dismissed by the public as insufficient evidence that, in fact, the matter had had a thorough enough evaluation to justify building the line. Several concerns were raised on the issue of Electric and Magnetic Fields (EMF). While there are no concrete answers to this issue, CVEA and AEA distributed information discussing how people are exposed daily to EMF. Because no one knows precisely what effect EMF has on health, there is no level that can be said to be either safe or unsafe. CVEA and AEA promote prudent avoidance of the source and keeping informed on the issue. Because EMF strength decreases dramatically with distance, moving a few feet away from the source will reduce the EMF exposure. The routing of the proposed line was altered to address local concerns of the proximity and visual impact of the line to private property. The majority of the dissenting comments were made by people who were concerned the line would be routed in view of the highway and/or over private property. AEA, Beck, and CVEA reviewed the public comment and determined that if the project was to receive any acceptance by people living in the Mat-Su Valley, it would require a significant rerouting from the route proposed. Two new routes were selected that would be out of view of the highway and would avoid trespassing private property to the maximum extent possible. Based on the property boundaries that have so far been identified, the reroute completely avoids private property. The rerouting is expected to increase the cost of the line, but in the spirit of being responsive to public concerns, CVEA believes it is justified. AEA and Beck, in concert with CVEA, conducted a second set of public meetings in June in the same communities to explain the rerouting proposal. Again, there were considerable additional comments relative to the availability of other alternatives and the routing of the line. To what extent any progress was made in mitigating public dissent in the Mat-Su Valley by the second set of meetings isn’t known, but it was made very clear that some residents in the Sutton- Chickaloon area are unalterably opposed to the project, regardless of what mitigating measures may be adopted. 19 CVEA continues to be dedicated to the proposition of being as responsive as possible to the public concerns being expressed. What Next A third round of public meetings will be held in late October or early November in the same communities as the first two sets were held. Possible modifications deemed necessary and achievable that result from recommendations of the last public meetings will be incorporated into the study, and a final document will be published in early December. As soon thereafter as possible, the funding for the line will be finalized and the process of beginning the center line location, right-of-way acquisition, and environmental study will proceed. SUMMARY What is the best course of action to provide additional generating capacity, replace the aging diesel units, reduce rates, and assure CVEA’s members of an adequate, reliable, and cost-competitive source of electricity to improve their standard of living and economic development opportunities for the benefit of future generations? Furthermore, how does CVEA acquire additional generation resources without adversely impacting rates that are already among the highest in the United States? CVEA has proposed, studied, and evaluated many alternatives over the past 20 years (see Attachment D). Of the alternatives studied, it appears that interconnection to the Railbelt grid provides the best opportunity for rate mitigation, long-term growth, and economic development for the region. 20 INDEX OF ATTACHMENTS Attachment A Projected Capacity and Demand of the Railbelt System, First Five Years Attachment B CVEA Annual Generation by Month Attachment C Chugach Electric Association 1992 Financial Forecast Estimated Electric Prices Attachment D CVEA Schedule of Efforts Evaluated Attachment E Letter from DNR, Natural Gas Deposits in the Copper Basin 21 WV Quoewyoez aw I-Ve RAILBELT SYSTEMS ITEM 3A CONCIL: ASCC PROJECTED CAPACITY AND DEMAND FIRST FIVE YEARS 1994 sam Tame | Suan) we | 1997 Pa | | we, [FO [ Twin. [ Sum. ] | Win. | Sum.] | Win. | DEMAND IN MW 01 ‘Internal Demand §35 658 544 649 550 661 559 671 566 681 02 Standby Demand (if not included in 01) 0 0 0 0 0 0 0 0 0 0 03 =Total Internal Demand (01+ 02) 535 658 544 649 550 661 559 671 566 681 04 Direct Control Load Management 0 0 0 0 0 0 0 0 0 0 05 Interruptible Demand (Ft. Richardson) 4 4 5 5 5 5 5 5 5 5 06 Net Internal Demand (03-04-05) 531 654 539 644 545 656 554 666 561 676 CAPACITY, NET, INMW 07 =Total Owned Capacity 1,176 1,284 1,176 1,284 1,176 1,284 1,169 1,276 1,169 1,276 08 Inoperable Capacity (if included in 07) 0 0 0 0 0 0 0 0 0 0 09 Net Operable Capacity (07-08) 1,176 1,284 1,176 1,284 1,176 1,284 1,169 1,276 1,169 1,276 10 Non-Utility Generators 0 0 0 0 0 0 0 0 0 0 1 Capacity Purchases (Total) 0 0 0 0 0 0 0 0 0 0 11a Full Responsibility Purchases 0 0 0 0 0 0 0 0 0 0 12 Capacity Sales (Total) 0 0 0 0 0 0 0 0 0 0 12a Full Responibility Sales 0 0 0 0 0 0 0 0 0 0 12b Adjustment to Purchases and Sales 0 0 0 0 0 0 0 0 0 0 13. Net Capacity Resources (09+10+11-12+12b) 1,176 1,284 1,176 1,284 1,176 1,284 1,169 1,276 1,169 1,276 14 Planned Outage 265 0 163 17 163 0 243 17 186 17 15 Net capacity Resources - Planned Outage (13 - 14) 911 1,284 1,013 1,267 1,013 1,284 926 1,259 983 1,259 (Thousands) @ Fuewyoreziy MEGAWATT HOURS VU TI Et VALLE Mowe nNiIv ANNUAL GENERATION BY MONTIT |_—DIESEL 5 -(7GENERATION 4 HYDRO 3 GENERATION 2 1 -_ Ons T T T T T a T T T T A F M A M J ‘J A S 0 N D O TOTAL 1993 BUDGET + TIYDRO-92 PROJIFCTION Oo FuUSUYyoRe ZIV CHUGACH ELECTRIC ASSOCIATION - 1992 FINANCIAL FORECAST Table 6 - Estimated Electric Prices RETAIL WHOLESALB Adjusted for Inflation Adjusted for Inflation Electric Electric Price Percent Price Percent Year Inflation cents/kWh) Chan; 1991 4.2% 46 1992 5.3% 49 5.9% 1993 48% 53 93% 1994 48% 5.6 4.1% 1995 48% 37 2.2% 1996 5.0% 64 13.6% 1997 48% ma 98% 1998 48% 74 5.0% 1999 48% 78 3.7% 2000 ’ $.0% 82 42% 2001 48% 8s 43% 2002 48% 9.0 6.1% 2003 48% 93 28% 2004 48% 99 6.2% 2005 48% 10S 61% 2006 48% 114 9.3% 2007 48% 1s 0.1% 2008 48% Wa -3.2% 2009 48% 11.3 1.9% 2010 48% 115 2.2% 2011 48% 18 2.1% 2012 48% 124 5.0% 2013 48% 13.0 54% 2014 48% 133 18% 2015 48% 13.6 2.3% Growth Rate, 1991 through 2015: MBF ELEC PRC.XLS Page 34 3/92 Revision, Margins on Net Interest COPPER VALLEY ELECTRIC SCHEDULE OF EFFORTS EVALUATED CAPACITY ENERGY USEFUL COST COST YRI$ INMW IN MWH LIFE PER KW SPECIFIC PROJECTS ALLISON LAKE 31,000,000 1992 3 27,396 35 = 10,333 INFLATABLE DAM 1,500,000 1991 1.7 1,702 35 882 SILVER LAKE 70,000,000 1992 10 48,000 24 ~=—- 7,000 NEW DIESEL PLANT 11,000,000 1990 7.2 37,296 15 1,528 COAL PLANT(HOBBS) 35,000,000 1993 11 48,000 20 = (3,182 SGL LINE 40,500,000 1992 40 ? 50 = 1,013 NON PROJECT SPECIFIC EFFORTS ALYESKA PRT ALYESKA INTERCONNECTION MERGER WITH GVEA LEAST COST PLAN SEPARATION OF CVEA BY DISTRICT NORTHEAST INTERTIE NATURAL GAS GENERATION RW BECK STUDY Attachment D STATE OF ALASKA WALTER J. HICKEL, GOVERNOR DEPT, OF NATURAL RESOURCES * po. BOX 107034 ANCHORAGE, ALASKA 99510-7034 DIVISION OF OIL AND GAS Richard Korbrath, Geologist 907-762-2185 March 18,1993 Mr, Clayton Hurless tS General Manager Copper Valley Electric Association Fax: 822-5586 Dear Mr. Hurless: This brief letter is to confirm our conversation this morning with regard to rumors of commercial hydrocarbon deposits in the Copper River basin. 1 will also take this opportunity to describe the basin geology somewhat, and I have attached some sclectcd pages from reports that describe the petroicun potential of the region. First, Ict me assure you that neither myself nor any of the rest of the Division geologic or engincering staff are aware of any commercial gas (or oil) finds in the Copper River Vailey. There has, in fact, been no recent drilling in the basin and it would be virtually impossible for a major discovery to have been made — either in the past or recently ~ without the Division's knowledge. The most recently drilled wells in the basin arc the Amoco AHTNA, INC. No. 1 and No. A-1, completed in 1980 to total depths of 7,928 fect and 5,677 {cct, respectively. ~ T show a record of eleven exploratory wells that have been drilled in the Copper River basin, most having — been drilled in the 1960's. The oldest rocks in the basin are represented by volcanic complexes that were penetrated in several wells, and outcrop in some of the surrounding mountains. Three distinctly differcn: a stratigraphic rock sequences overlie the “bascment rocks", including from oldest to youngest, Middle Jurassic through early Cretaceous sandstone, siltsone, shale and limestone; the late Cretaceous Matanuska Formation; and a Tertiary (approximately 60 million years old) scquence of marine and non-marine sandstones, shales, conglomerates and coal-bearing sandstone. The basin structure includes northeasterly trending, smal! amplitude folds, as well as major thrust faulis, and high-angle block faulting. Generaliy, the commercial hydrocarbon petential of this area is sccn as low to moderate, with the best chance for discoveries being small gas accumulations in the younger Tertiary stratigraphic scquence. Industry has shown little interest in the region in recent ycars, although some ficld efforts along the Attachment E 1 of 2 — = motntain front outcrop belt have been pursued. A proposal for large-block liccnsing by the state is presently under consideraticn for this area. The new legislation would have to be passed by the Alaska State Legislarure. This form of competitive licensing of large areas may, eventually, result in some renewed exploratory activity. I wevld hazard a guess that the “excitement” over a commercial gas find in the basin may be a result of some of the gas shows reported in two of the older exploratory wells and in at least one shallow waiter well. Shows of this type are not unusual, especially in areas of swampy or peat-rich terrain, or where the Stratigraphic units are coal-bearing. The existence of permafrost may also contribute to the trapping of small, shallow gas pockcts. Methane gas flows often are encountered in thess settings. The William Buck well was drilled as a water well and encountered a low volume flow of natural gas at a shallow depth (less than 160 fect). This methane with minor hydrogen sulfide was thought to be a result of decaying vegetation beneath a permafrost trap, and is not considered significant as related to commercial gas production. Also, the Mobil Salmonberry Lake Unit No. 1 in Sec. 24, T6N, R6W flowed salt water and some methane gas at a depth of about 2,443 fect. The flow was controlled using heavier driliing muds. The Pan American Moose Creek Unit No. 1 in Scc. 29, T4N, R5W also encountered a pressured water zone with some gas from fractured bentonitic (volcanic-rich) shale at about 5,430 feet to 5,663 feet. Again, I should emphasize that these types of shows are not an indication of commercial quantities of gas. If I can be of any further assistance in this matter, I can be reached at 762-2185. Sincerely, tbh CLE Richard Kornbrath cc: Mr. Robert Wilkinson enc: various copied pages from geologic reports Attachment E 2 of 2