-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, V6hv3w3QGOMmx7uH+KEm8fZ1TrnsDhU/I9TFo8eiNS5P4fZSVzZsStT7dJGrlG40 ZI8Z5L2+YMOZN//Zv9N8bg== 0000878004-01-000003.txt : 20010402 0000878004-01-000003.hdr.sgml : 20010402 ACCESSION NUMBER: 0000878004-01-000003 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010330 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CHUGACH ELECTRIC ASSOCIATION INC CENTRAL INDEX KEY: 0000878004 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 920014224 STATE OF INCORPORATION: AK FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 033-42125 FILM NUMBER: 1586664 BUSINESS ADDRESS: STREET 1: 5601 MINNESOTA DR STREET 2: PO BOX 196300 CITY: ANCHORAGE STATE: AK ZIP: 99518 BUSINESS PHONE: 9075637494 10-K 1 0001.txt FORM 10-K FOR CHUGACH ELECTRIC ASSOCIATION, INC. FORM 10-K--ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (As last amended in Rel. No. 34-31327, eff. 10-21-92) UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K (x)Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2000 ( )Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from______________________to_________________________ Commission file Number 33-42125 -------- Chugach Electric Association, Inc. - ------------------------------------------- (Exact name of registrant as specified in its charter) Alaska 92-0014224 - --------------------------------------------------------------------------- (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 5601 Minnesota Drive, Anchorage, Alaska 99518 - ------------------------------------------------------------------------ (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (907) 563-7494 - ----------------------------------------------------------------- Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered - ------------------------------------ ------------------------------------------ - ------------------------------------ ------------------------------------------ Securities registered pursuant to Section 12(g) of the Act: - -------------------------------------------------------------------------------- (Title of class) - -------------------------------------------------------------------------------- (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securites Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. /x/ Yes / / No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. N/A State the aggregate market value of the voting stock held by non-affiliates of the registrant. The aggregate market value shall be computed by reference to the price at which the stock was sold, or the average bid and asked prices of such stock, as of a specified date within 60 days prior to the date of filing. (See definition of affiliate in Rule 405, 17 CFR 230.405). N/A CHUGACH ELECTRIC ASSOCIATION, INC. 2000 Form 10-K Annual Report Table of Contents PART I Page Item 1 - Business 1 Item 2 - Properties 8 Item 3 - Legal Proceedings 15 Item 4 - Submission of Matters to a Vote of Security Holders 15 PART II Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters 15 Item 6 - Selected Financial Data 16 Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations 17 Item 7A - Quantitative and Qualitative Disclosures About Market Risk 26 Item 8 - Financial Statements and Supplementary Data 28 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 51 PART III Item 10 - Directors and Executive Officers of the Registrant 51 Item 11 - Executive Compensation 53 Item 12 - Security Ownership of Certain Beneficial Owners and Management 56 Item 13 - Certain Relationships and Related Transactions 56 Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K 56 SIGNATURES 66 CAUTION REGARDING FORWARD-LOOKING STATEMENTS Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements, that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. Chugach Electric Association, Inc. (Chugach or the Association) undertakes no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this report or the effect of those events or circumstances on any of the forward-looking statements contained in this report, except as required by law. PART I Item 1 - Business General Chugach Electric Association, Inc., is the largest electric utility in Alaska. We are engaged in the generation, transmission and distribution of electricity to approximately 71,800 metered locations in the Anchorage and upper Kenai Peninsula areas. Through an interconnected regional electrical system, our energy is distributed throughout Alaska's Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska's largest cities, Anchorage and Fairbanks. Neither we nor any other electric utility in Alaska has any connection to the electric grid of the mainland United States or Canada. Through direct service to retail customers and indirectly through wholesale and economy energy sales, we provide some or all of the electricity used by approximately two-thirds of Alaska's electric customers. We also supply much of the power requirements of three wholesale customers, Matanuska Electric Association ("MEA"), Homer Electric Association ("HEA") and the City of Seward ("Seward"). In addition, on a periodic basis, we provide electricity to Anchorage Municipal Light & Power ("AML&P"). AML&P has about 30,000 meters. We have approximately 511 megawatts of installed generating capacity provided by 17 generating units at our five owned power plants: Beluga Power Plant, Bernice Lake Power Plant, International Generating Station, Cooper Lake Hydroelectric Plant and Eklutna Hydroelectric Project, in which we own a 30% interest. Approximately 96% (by rated capacity) of our generating capacity is fueled by natural gas, which we purchase under long-term gas contracts. The remainder of our generating resources are hydroelectric facilities. In 2000, approximately 85% of our energy was generated at our Beluga facility. We purchase up to 27.4 megawatts from the Bradley Lake Hydroelectric Project and up to 40 megawatts from the Nikiski power plant on the Kenai Peninsula. We operate 1,602 miles of distribution line and 402 miles of transmission line. For the year ended December 31, 2000, we sold 2.4 billion kilowatt hours ("kWh") of power. We were organized as an Alaska electric cooperative in 1948. Cooperatives are business organizations that are owned by their members. As not-for-profit organizations, cooperatives are intended to provide services to their members at cost, in part by eliminating the need to produce profits or a return on equity. Today, cooperatives operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and credit. All cooperatives are based upon similar principles and legal foundations. Because members' equity is not considered an investment, a cooperative's objectives and policies are oriented to serving member interests, rather than maximizing return on investment. Our members are the consumers of the electricity sold by us. As of December 31, 2000, we had approximately 57,900 retail members receiving service at approximately 71,800 metered locations and three major wholesale customers. No individual retail customer receives more than 5% of our power. Our business and affairs are managed by the General Manager and are overseen by a seven-member Board of Directors. Directors are elected at large by the membership and serve three-year staggered terms. Each member is entitled to one vote. In addition to voting for directors, members have voting rights with respect to mergers and the sale, lease, or other disposition (except by mortgage or deed of trust) of all or a substantial portion of our property. Our customers are billed per a tariff rate on a monthly basis for electrical power consumed during the preceding month. Billing rates are approved by the Regulatory Commission of Alaska ("RCA") (see "Rate Regulation and Rates" below). Rates (derived from the historic cost of service basis) may generate revenues in excess of current period costs (net operating margins and nonoperating margins) in any year and such excess is designated on our Statements of Revenues, Expenses and Patronage Capital as "assignable margins." Retained assignable margins are designated on our balance sheet as "patronage capital" that is assigned to each member on the basis of patronage. We are a rural electric cooperative that is exempt from federal income taxation as an organization described in Section 501(c)(12) of the Internal Revenue Code ("Code"). Alaska electric cooperatives must pay to the State of Alaska, in lieu of state and local ad valorem, income and excise taxes, a tax at the rate of $0.0005 per kWh of electricity sold in the retail market during the preceding year. In addition, we collect a regulatory cost charge of $.000318 per kWh of retail electricity sold. This charge is assessed to fund the operations of the RCA. It is a pass-through and thus does not impact our margins. Our workforce consists of approximately 355 full -time employees. Approximately two-thirds of our employees are members of the International Brotherhood of Electrical Workers ("IBEW"). We have three collective bargaining agreements with the IBEW that are in effect through June 30, 2003. We also have an agreement with Hotel Employees, Restaurant Employees, Local 878 in effect through June 30, 2003. We believe our relationship with our employees is good. Our Service Areas Our service areas and those of our wholesale and economy energy customers are often described collectively as the Railbelt region of Alaska because the three geographic areas (the Southcentral, the Kenai Peninsula and the Interior) are linked by the Alaska Railroad. Anchorage is the trade, service and financial center for most of Alaska and serves as a major center for many state governmental functions. Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, air and rail transportation facilities and headquarters support for the petroleum, mining and other basic industries located elsewhere in the state. The Matanuska-Susitna Borough is immediately north of the Municipality of Anchorage, centered around the communities of Palmer and Wasilla. Although agriculture, tourism, mining and forestry are factors in the economy of the Matanuska-Susitna Borough, the economic well-being of the area is closely tied to that of Anchorage and many Matanuska-Susitna residents commute to jobs in Anchorage. The Kenai Peninsula is south of Anchorage with an economy substantially independent of the Anchorage area. The most significant basic industry on the Kenai Peninsula is the production and processing of petroleum products from the Cook Inlet region. Other important basic industries include tourism and fish harvesting and processing. Principal communities on the Kenai Peninsula are Homer, Seward, Kenai and Soldotna. Fairbanks is the center of economic activity for the central part of the state (known as the Interior). Fairbanks (250 air miles north of Anchorage and about 400 air miles south of Alaska's northern border) is Alaska's second largest city. Basic economic activities in the Fairbanks region include federal and state government and military operations, the University of Alaska, tourism and support of natural resource development in the Interior and northern parts of the state. Recently a major gold mine commenced operation near Fairbanks. The Trans-Alaska Pipeline System (which transports crude oil) passes near Fairbanks on its route from the North Slope oilfield to Valdez. Competition Nationwide, the electric utility industry is entering a period of unprecedented upheaval and restructuring. We have taken several steps to be more effectively positioned to meet the challenge of a competitive market for electricity. We have been active at the Alaska Legislature in support of the customer's right to choose their electric power supplier. For example, we have requested access over a neighboring utility's distribution and transmission system and asked the RCA to enforce the request. The RCA ruled that retail competition is permitted in Alaska only after prior review and approval by the RCA. We are appealing this ruling in the courts. Virtually all other Alaskan utilities have opposed our efforts to develop competition and are treating their service territories as exclusive. At this time no bill relating to customer choice has moved out of legislative committee. It is not possible to predict the outcome of this legislative process. We have made organizational changes in preparation for competition. Recognizing that the new marketplace will probably be "unbundled" along the functional lines of generation, transmission and distribution and retail services, our organizational structure reflects these functions. Operating with three divisions: Finance and Energy Supply, Transmission and Distribution Network Services and Retail Services, we have positioned ourselves to meet competition in the electric industry. We continue to operate a key account program for larger customers and are developing new services to enhance existing customers' satisfaction. It is our objective to continually improve the efficiency and cost effectiveness of our operations. We participate in customer satisfaction surveys, benchmark the performance of system operations against an international peer group and perform studies on how to implement business process best practices. These ongoing programs focus on distribution and transmission lines, substations, power plants, fleet operations and administrative services. Rate Regulation and Rates We are subject to rate regulation by the RCA. We can seek increases in our demand and energy charges by filing general rate cases with the RCA. While the formal ratemaking process typically takes nine months to one year, it is within the RCA's authority to authorize, after a notice period, rate changes on an interim, refundable basis. In addition, the RCA has been willing to open limited reviews of matters to resolve specific issues from which expeditious decisions can often be rendered. The RCA has exclusive regulatory control of our rates, subject to appeal to the Alaska Superior Court and the Alaska Supreme Court under the Alaska Administrative Procedures Act. Under Alaska law, financial covenants of an Alaskan electric cooperative contained in a debt instrument will be valid and enforceable, and rates set by the RCA must be adequate to meet those covenants. We will continue to recover changes in our fuel and purchased power expenses through routine fuel surcharge filings with the RCA. See "Management's Discussion and Analysis - Results of Operations - Rate Regulation and Rates." The 1991 Indenture governing all of our outstanding bonds requires us to set rates designed to yield margins for interest equal to at least 1.20 times total interest expense. The authorized rate-setting Times Interest Earned Ratio ("TIER") level of 1.35 has allowed us to achieve margins for interest greater than 1.20. For the year ended December 31, 2000, our achieved TIER was 1.39. Sales to Customers The following table shows the energy sales to and electric revenues from our retail, wholesale, and economy energy customers for the year ended December 31, 2000: Percent of Total MWh 2000 Revenues 2000 Revenues --- ------------- --------------- Direct retail sales: Residential 509,799 $ 51,288,657 33% Commercial 582,652 47,248,033 31% ---------- -------------- Total 1,092,451 $ 98,536,690 64% Wholesale sales: MEA 549,517 $ 27,252,051 17% Homer 436,112 19,060,244 12% Sewar 59,454 2,369,550 2% ----------- ----------- ---- Total .. 1,045,083 $ 48,681,845 31% Economy energy sales(1) 267,855 $ 7,820,998 5% ---------- ------------- Total sales to customers 2,405,389 $155,039,533 100% ========= ==== Miscellaneous energy revenue $ 2,331,133 ------------ Total energy revenues $157,370,666 ============ (1) All economy sales were made to GVEA. Retail Customers Service Territory Our retail service area covers the populated areas of Anchorage (other than downtown Anchorage) as well as remote mountain areas and villages. The service area ranges from the northern Kenai Peninsula on the south, to Tyonek on the west, to Whittier on the east and to Fort Richardson on the north. Customers. We directly serve approximately 71,800 meters. We have approximately 57,900 members (some members are served by more than one meter). Our customers are primarily urban and suburban. The urban nature of our customer base means that we have a relatively high customer density per line mile. Higher customer density means that fixed costs can be spread over a greater number of customers. As a result of lower average costs attributable to each customer, we benefit from a greater stability in revenue, as compared to a less dense distribution system in which each individual customer would have a more significant impact on operating results. For the past five years no retail customer accounted for more than 5% of our revenues. Wholesale Customers We are the principal supplier of power to MEA, Seward and Homer under separate wholesale power contracts. For 2000, our wholesale power contracts produced $47.4 million in revenues, representing 31% of our revenues and 43% of our total kWh sales to customers. MEA and Homer We have two power sales contracts with AEG&T and each of MEA and Homer. AEG&T is a generation and transmission cooperative formed by MEA and Homer. Under each of these contracts, we sell power to AEG&T, which resells the power to MEA and Homer. Each of MEA and Homer is obligated to pay us for the power sold to AEG&T for its use if AEG&T does not pay. Our contract for the benefit of MEA obligates MEA (through AEG&T) to purchase all of its electric power and energy requirements from us. Contractually, MEA has the right, on advance notice and subject to RCA approval, to convert to a net requirements purchaser of power, and as such MEA would be obligated to buy its needed power from us net of its power needs satisfied from any of its own or AEG&T's resources. The notice period required for such conversion may be up to five years, depending on which non-Chugach resources MEA proposes to use to satisfy its power needs. After conversion to a net requirements purchaser under the contract, MEA cannot reduce the payment for power it purchases from us below a certain minimum amount. If MEA converts to net requirements service, MEA will be required to pay demand charges based upon the highest post-1985 historical coincident peak on the MEA system. Therefore, we will continue to recover fixed costs if MEA converts to net-requirements service. Also, our revenues from energy sales to MEA would partially decline in proportion to the reduction in the energy sold, but this decline would be offset to an extent by savings in the variable costs associated with energy production. MEA also has the right, on seven years advance notice and subject to RCA approval, to convert to a take-or-pay purchase of a fixed amount of power, also subject to minimum payment requirements associated with prior purchases. The MEA contract is in effect through December 31, 2014. This contract does not protect us against loss of load resulting from retail competition in MEA's distribution service territory if retail competition is ever permitted in Alaska. It is not possible at this time to estimate the potential impact on our revenues that could result from such competition. See "Competition" above. During the past several years, we have had numerous disputes and engaged in substantial litigation with MEA regarding many aspects of our contractual relationship with it. For example, in October 1998, the Board of Directors of MEA announced that it had offered to acquire Chugach. Our Board of Directors rejected the MEA acquisition proposal. MEA circulated a petition and gathered a sufficient number of signatures from our members so that a special meeting of our members was called for the purpose of considering MEA's proposal. This meeting was held November 18, 1999, at which time our members overwhelmingly rejected the MEA proposal. No further action regarding this offer has been initiated by MEA. For a discussion of material pending litigation between MEA and us, see "Legal Proceedings." Our contract for the benefit of Homer obligates Homer (through AEG&T) to take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per year. The Homer contract includes certain limitations on the costs that may be included in our rates charged to Homer. The Homer contract expires on January 1, 2014. Homer's remaining resource requirements are provided by AEG&T's Nikiski cogeneration facility and AEG&T's entitlement for power from the Bradley Lake hydroelectric project for the benefit of Homer. In February 1999, we entered into a dispatch agreement with AEG&T to operate the Nikiski unit as a Chugach system resource. The agreement provides that, in addition to the energy that we already sell to AEG&T and Homer, we will sell energy to AEG&T equal to Homer's residual energy requirements less its allocated share of the Bradley Lake project, up to a maximum of 320,000 MWh per year. A portion of the Nikiski unit output may be dispatched for Homer needs in excess of the sum of our contract demand plus Homer's share of energy from the Bradley Lake project. The dispatch agreement will terminate in 2014 coincident with our power supply contract for the benefit of Homer. Seward We currently provide nearly all the power needs of the City of Seward. In February 1998, we entered into a new power sales agreement with Seward that allows us to interrupt service to Seward up to 12 times per year and provides for a 1/3 reduction in the demand charge (approximately $350,000 annually). This agreement expires September 1, 2001, but we have negotiated an amendment to the agreement that will extend its term to January 31, 2006. The amendment was fully executed on December 12, 2000, and subsequently filed for approval with the RCA on February 5, 2001, and will be effective upon approval by the RCA. Economy Customers Since 1988, we have sold nonfirm (economy) energy to Golden Valley Electric Association ("GVEA") under an agreement that expires in 2008. Under the agreement, we use available generating capacity in excess of our own needs to produce electric energy for sale to GVEA, which uses that energy to serve its own loads in place of more expensive energy that GVEA would otherwise generate itself or purchase from other sources. We use gas purchased from Marathon Oil Company ("Marathon") to produce energy for sale to GVEA, and we charge GVEA a rate sufficient to recover the gas cost, the costs of incremental operations and maintenance expense resulting from increased use of our generators for GVEA, and an agreed-upon markup or margin for each kWh sold. In 2000, the RCA approved an amendment to our agreement with GVEA and a settlement of an inter-utility dispute involving it. As a result, the market for economy energy sold to GVEA has now been divided into two parts. The larger part continues to be governed by our agreement with GVEA, which assures us of priority in sales of such energy to GVEA. In general, we are assured of selling to GVEA two-thirds of the first 450,000,000 kWh of economy energy and 80% of the excess over 450,000,000 kWh of economy energy that GVEA purchases each year if we are capable of producing that energy. Remaining economy energy sales to GVEA have now become the "Economy Energy Spot Market." Sales in the Economy Energy Spot Market are completely competitive among potential sellers of economy energy to GVEA. Neither we nor any other seller enjoys a contractual priority in making such sales. One of those sellers, AML&P, is expected to dominate sales to GVEA in the Economy Energy Spot Market for the immediate future, partly because AML&P prices its gas at less than the Marathon gas on which we rely in making such sales. Load Forecasts The following table sets forth our projected load forecasts for the next five years: Load (MWh) 2001 2002 2003 2004 2005 ---------- ---- ---- ---- ---- ---- Retail............ 1,118,259 1,138,639 1,162,634 1,187,001 1,213,582 Wholesale......... 1,114,376 1,179,616 1,206,385 1,234,757 1,263,427 Economy........... 260,000 260,000 260,000 260,000 260,000 Losses............ 138,428 142,505 145,613 148,847 152,218 --------- --------- --------- --------- --------- Total.......... 2,631,063 2,720,760 2,774,632 2,830,605 2,889,227
Sales are expected to increase over the next five years principally due to economic growth in the service sector. Based on a study by University of Alaska, our total energy requirements are expected to grow at an average compounded annual rate of 2.6% from 2001 to 2005--retail sales at 2.1% and wholesale sales at 3.2%. Item 2 - Properties General We have 511 megawatts of installed capacity consisting of 17 generating units at five power plants. These include 368.1 megawatts of operating capacity at the Beluga facility on the west side of Cook Inlet; 67.5 megawatts of power at the Bernice Lake facility on the Kenai Peninsula; 46.7 megawatts of power at International Generating Station in Anchorage; and 17.2 megawatts at the Cooper Lake facility, which is also on the Kenai Peninsula. We also have 11.7 megawatts of capacity from the two Eklutna hydroelectric plant generating units owned jointly with MEA and AML&P. In addition to our own generation, we purchase power from the 126 megawatt Bradley Lake hydroelectric project owned by the Alaska Energy Authority ("AEA") through Alaska Industrial Development and Export Authority. The Bradley Lake facility is operated by Homer and dispatched by us. The Beluga, Bernice Lake and International facilities are all fueled by natural gas. We own our offices and headquarters, located adjacent to our International Generating Station in Anchorage. Warehouse space for some generation, transmission and distribution inventory (including a small amount of office space) is leased from an independent party. Generation Assets We own the land and improvements comprising our generating facilities at Beluga and International. We also own all improvements comprising our generating plant at Bernice Lake, located on land originally leased from Chevron Oil Company and now owned by Homer, and our generating plant at Cooper Lake. The Cooper Lake facility is located on federal land pursuant to a major project license granted to us by the Federal Power Commission in 1957. The Bernice Lake ground lease expires in 2011 and the federal license for the Cooper Lake facility expires in 2007. We have no reason to believe that we will not be able to renew the federal license or the Bernice Lake facility ground lease if desirable. In 1997, we acquired a 30% interest in the Eklutna Hydroelectric Project. The plant is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October 1997. Our principal generation units are Beluga 3, 5, 6, 7 and 8. These units, comprising 334 megawatt capacity, meet most of our load. All other units are used principally as reserve. While the Beluga turbine-generators are fairly old, they have been maintained in good working order with periodic upgrades. Beluga 3 had a major overhaul in 1996. Beluga 5 received a major overhaul in 1997. Beluga 6 was "repowered" in 2000 adding in excess of 25 years to its life. Beluga 7 is slated for repowering in 2001. Beluga 8, a steam turbine, was overhauled in 1994 and is slated for another major overhaul in 2002. The following matrix depicts nomenclature, run hours for 2000 and percentages of contribution and other historical information for all Chugach generation units. Percent of Commercial Operation Rating Run hours Percent of total time Facility Date Nomenclature (MW)(1) (2000) generation available -------- ---- ------------ ------- ------ ---------- --------- Beluga Power Plant (3) 1 1968 GE Frame 5 19.6 1872.2 3.83 93.6 2 1968 GE Frame 5 19.6 2051.3 4.19 98.2 3 1972 GE Frame 7 64.8 7255.2 14.84 90.9 5 1975 GE Frame 7 68.7 8204.5 16.78 95.1 6 1975 ABB 11D-4A 69.4 3719.3 7.61 42.3 7 1978 ABB 11D-4A 71.0 8270.2 16.91 94.2 8 1981 BB DK-21150(2) 55.0 8419.0 17.22 95.8 Bernice Lake Power Plant 2 1971 GE Frame 5 19.0 0 0 N/A 3 1978 GE Frame 5 26.0 4.7 0.01 99.4 4 1981 GE Frame 5 22.5 5953.1 12.17 99.7 Cooper Lake Hydroelectric Plant 1 1960 BB MV 230/10 8.6 1394.6 2.85 21.6 2 1960 BB MV 230/10 8.6 1530.9 3.13 21.6 International Power Plant 1 1964 GE Frame 5 14.1 62.8 0.13 99.5 2 1965 GE Frame 5 14.1 99.2 0.20 99.9 3 1969 Westinghouse 191G 18.5 66.8 0.14 99.9 Eklutna Hydroelectric Plant (4) 1 1955 Newport News 5.8 N/A5 N/A5 N/A5 2 1955 Oerlikon custom 5.9 N/A5 N/A5 N/A5 System Total 48903.8 100.00
(1) Capacity rating in MW at 30 degrees Fahrenheit. (2) Steam-turbine powered generator with heat provided by exhaust from natural-gas fueled Units 6 and 7 (combined-cycle). (3) Beluga Unit 4 and Bernice Lake Unit 1 were retired during 1994. (4) The Eklutna Hydroelectric Plant is jointly owned by Chugach, MEA and AML&P. The capacity shown is our 30% share of the plant's maximum output. (5) Because Eklutna Hydroelectric Plant is operated by MEA and managed by a committee of the three owners, we do not record run hours or in-commission rates. Transmission and Distribution Assets As of December 31, 2000, our transmission and distribution assets included 39 substations and 402 miles of transmission lines, 931 miles of overhead distribution lines and 659 miles of underground distribution line. We own the land on which 20 of our substations are located and a portion of the right-of-way connecting our Beluga plant to Anchorage. In the 1997 Eklutna acquisition, we also acquired a partial interest in two substations and additional transmission facilities. Many substations and a substantial number of our transmission and distribution rights-of-way are the subject of federal or state permits and licenses. Under a federal license and a permit from the United States Forest Service, we operate the Quartz Creek transmission substation, substations at Hope, Summit Lake and Daves Creek, and transmission lines over all federal lands between Cooper Lake on the Kenai Peninsula and Anchorage. Long-term permits from the Alaska Division of Lands and the Alaska Railroad Corporation govern much of the rest of our transmission system outside the Anchorage area. Within the Anchorage area, we operate our University substation and several major transmission lines pursuant to long-term rights-of-way grants from the U.S. Department of the Interior, Bureau of Land Management, and transmission and distribution lines have been constructed across privately owned lands pursuant to easements across public rights-of-way and waterways pursuant to authority granted by the appropriate governmental entity. Title Substantially all of our tangible and some of our intangible properties and assets, including generation, transmission and distribution properties, but excluding all excepted property identified in the 1991 Indenture, are pledged to secure repayment of the 1991 Series A Bonds, the bonds issued to CoBank, and all other bonds that may be issued under the 1991 Indenture. In addition to the lien of the 1991 Indenture, many of our properties are burdened by easements, plat restrictions, mineral reservation, water rights and similar title exceptions common to the area or customarily reserved in conveyances from federal or state governmental entities, and to additional minor tide encumbrances and defects. We do not believe that any of these title defects will materially impair the use of our properties in the operation of our business. Under the Alaska Electric and Telephone Cooperative Act, we possess the power of eminent domain for the purpose and in the manner provided by Alaska condemnation laws for acquiring private property for public use. Other Assets Bradley Lake. We are a participant in the Bradley Lake hydroelectric project, which is a 126 megawatt rated capacity hydroelectric facility near Homer on the southern end of the Kenai Peninsula that was placed into service in September 1991. The project is nominally scheduled at 90 megawatts to minimize losses and insure system stability. We have a 27.4 megawatt or 30.4% share in the Bradley Lake project's output, and take Seward's and MEA's shares which we net bill to them, for a total of 45% of the project's capacity. The project was financed and built by AEA through grants from the State of Alaska and the issuance of $166 million principal amount of revenue bonds supported by power sales agreements with six electric utilities that share the output from the facility (Chugach, AML&P, Homer and MEA (through AEG&T), GVEA and Seward). The participating utilities have entered into take-or-pay power sales agreements under which AEA has sold percentage shares of the project capacity and the utilities have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt-service costs and amounts required to maintain established reserves). We also provide transmission and related services as a wheeling agent (one who dispatches and transmits power of third parties over its own system) for all of the participants in the Bradley Lake project. The length of our Bradley Lake power sales agreement is fifty years from the date of commercialization (September, 1991) or when the revenue bond principal is repaid, whichever is the longer. We believe that, under a worst-case scenario, we could be faced with annual expenditures of approximately $4.1 million as a result of our Bradley Lake take-or-pay obligations. We believe that this expense would be recoverable through a fuel surcharge. The share of Bradley Lake indebtedness for which we are responsible is approximately $44,000,000. Upon the default of a participant, and subject to certain other conditions, AEA is entitled to increase each participant's share of costs and output pro rata, to the extent necessary to compensate for the failure of another participant to pay its share, provided that no participant's percentage share is increased by more than 25%. We negotiated with AEG&T a scheduling agreement whereby we schedule AEG&T/Homer's share of the Bradley Lake project for the benefit of the Railbelt electric system. AEG&T continues to pay its Bradley Lake project costs and receives credit for the Bradley Lake energy generated for Homer. We pay a fixed annual fee of $112,000 to AEG&T for these scheduling rights. This agreement allows us to improve the efficiency of our generating resources through better hydrothermal coordination. Eklutna. We purchased a 30% undivided interest in the Eklutna Hydroelectric Project from the federal government in 1997. MEA purchased a 17% undivided interest in the Eklutna Hydroelectric Project. The power MEA purchases from the Eklutna Hydroelectric Project is pooled with our purchases and sold back to MEA to be used in meeting MEA's overall power requirements. AML&P owns the remaining 53% undivided interest in the Eklutna Hydroelectric Project. Fuel Supply For 2000, 96% of our power was generated from gas, and 85% of that gas-fired generation took place at Beluga. Our primary sources of natural gas are the Beluga River Field producers (Phillips Alaska, Inc. ("Phillips"), AML&P and Chevron USA Inc. ("Chevron"), and Marathon. Phillips, AML&P and Chevron each own one-third of the gas produced from the Beluga River Field and in 2000 provided approximately equal shares of the Beluga gas. We have approximately 378 billion cubic feet ("BCF") of remaining gas committed to us from the Beluga River Field producers and Marathon. We currently use approximately 23 BCF of natural gas per year for firm service. We believe that this usage will increase approximately 0.5 BCF per year and estimate that our contract gas will last 15 to 19 years. The deliverability requirements under the Beluga and Marathon contracts are in excess of the peak winter demand requirements of the Beluga plant. Beluga River Field Producers We have similar requirements contracts with each of Phillips, AML&P and Chevron that were executed in April 1989, superseding contracts that had been in place since 1973. Each of the contracts with the Beluga River Field producers provides for delivery of gas on different terms in three different periods. Period 1 related to the delivery of gas previously committed by the respective producer under the 1973 contracts and ended in June 1996. During Period 2, which began in June 1996 and continues until the earlier of the delivery of 180 BCF of natural gas or December 31, 2013, we are entitled to take delivery of up to 180 BCF of natural gas (60 BCF per Beluga River Field producer). During this period, we are required to take 60% of our total fuel requirements at Beluga from the three Beluga River Field producers, exclusive of gas purchased at Beluga under the Marathon contract for use in making sales to GVEA or certain other wholesale purchasers. The price for gas during this period under the Phillips and AML&P contracts is approximately 88% of the price of gas under the Marathon contract (described below) ($1.8617 per thousand cubic feet ("MCF") on January 1, 2001), plus taxes. The price during this period under the Chevron contract is approximately 110% of the price of gas under the Marathon contract (described below) ($2.3271 per MCF on January 1, 2001), plus taxes. During Period 3 under the Beluga River Field producers' contracts, which begins on the earlier of December 31, 2013, or the end of Period 2, we may become entitled to take delivery of up to 120 BCF of natural gas (40 BCF per producer). Whether any gas will be taken in Period 3, and the price and take requirements with respect thereto, are to be determined in the future based upon then-current market conditions. We have supplemental, annually renewable contracts with the Beluga River Field producers to supply supplemental gas (for peak periods of energy usage) if they have it available in excess of the amounts guaranteed in the basic contracts. The supplemental gas contracts raise the daily deliverability of gas from the Beluga River Field producers to an aggregate of 85,200 MCF per day. The base price of the gas under these contracts is the same as the base price under the Marathon contract (described below), plus taxes. Marathon We entered into a requirements contract with Marathon in September 1988 for an initial commitment of 215 BCF. The contract expires on the earlier of December 31, 2015, or the date on which Marathon has delivered to us a volume of gas in total which equals or exceeds 215 BCF, which we currently expect to occur by mid-2009. The base price for gas under the Marathon contract is $1.35 per MCF, adjusted quarterly to reflect the percentage change between the preceding twelve-month period and a base period in the average prices of West Texas Intermediate Crude Oil (a benchmark of the Light Sweet Crude Oil Futures Index), the Producer Price Index for natural gas, and the Consumer Price Index for heating fuel oil. The price on January 1, 2001, exclusive of taxes, was $2.1156 per MCF. Under the terms of the Marathon contract, Marathon generally provides the primary supply of gas required for sales to GVEA, all of our requirements at Bernice Lake and 40% of the requirements at Beluga. Marathon also has a right of first refusal to provide additional gas under any sales agreements that we may enter into with electric utilities we do not currently serve. ENSTAR We entered into a transportation agreement with ENSTAR Natural Gas Company ("ENSTAR") in December 1992, whereby ENSTAR would transport our gas purchased from the Beluga River Field producers or Marathon on a firm basis to our International Power Plant at a transportation rate of $0.63 per MCF. In addition, ENSTAR agreed to transport gas on an interruptible basis for off-system sales at a rate of $0.30 per MCF. The agreement contains a minimum monthly bill of $2,600 for firm service. We hold a reservation to receive our gas requirements at International Power Plant from ENSTAR under a tariff approved by the RCA in the event that the transportation agreement is subsequently canceled. Under the currently suspended tariff, ENSTAR is obligated to supply all of the gas we require at a price approved by the RCA. There would be a monthly minimum bill of $10,465 but no requirement to actually use any gas at the International Power Plant. The estimated delivered price if the tariff were reinstated is $3.00 per MCF. Environmental Matters Our operations are subject to certain federal, state and local environmental laws, which we monitor to ensure compliance. The costs associated with environmental compliance are included as a component of both the operating and capital budget processes. We accrue for costs associated with environmental remediation obligations when such costs are probable and reasonably estimable. We discovered polychlorinated biphenyls ("PCBs") in paint, caulk and grease at the Cooper Lake Hydroelectric Plant during initial phases of a turbine overhaul. We are implementing a plan approved by the Environmental Protection Agency to remediate the PCBs in the plant. We are also conducting an investigation to determine whether any PCBs released from the plant are present in Kenai Lake. We do not have an estimate at this time of the potential costs involved in the investigation and we do not know whether any additional remediation will be required. Item 3 - Legal Proceedings Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc. On July 7, 1999, MEA filed a complaint against us in Alaska Superior Court in Anchorage, asserting that we violated the Power Supply Agreement between the parties, state statutes and our bylaws in failing to provide MEA with information about several different matters that MEA asserts could affect the cost of the power MEA purchases from us. MEA also asserted that we violated the Power Supply Agreement in our management of our long-term bond indebtedness. On February 8, 2000, MEA added a new claim in this proceeding. MEA asked for an order directing that we be required to present our general rate case filing to the Joint Rate Committee (an administrative body comprised of representatives of Chugach and MEA) prior to presenting it to the RCA. We filed our answer to MEA's Second Amended Complaint on March 10, 2000, opposing the relief MEA requested. Discovery in this matter is still in its preliminary stages. Trial is set for February 2002. Because of the preliminary nature of the case, we are not able to estimate the costs of our participation. We have certain additional litigation matters and pending claims that arise in the ordinary course of our business. In the opinion of management, no individual matter or the matters in the aggregate is likely to have a material adverse effect on our results of operations or financial condition. Item 4 - Submission of Matters to a Vote of Security Holders Not Applicable PART II Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters Not Applicable Item 6 - Selected Financial Data The following tables present selected historical information relating to financial condition and results of operations over the past five years: Balance Sheet Data 2000 1999 1998 1997 1996 ---- ---- ---- ---- ---- Plant net: In service $ 427,127,258 $ 398,544,496 $ 386,235,421 $ 393,228,853 $ 400,052,837 Construction work in Progress 42,027,617 47,257,296 30,405,736 24,664,395 19,826,957 ----------- ----------- ----------- ------------ ------------ Electric plant, net 469,154,875 445,801,792 416,641,157 417,893,248 419,879,794 Other assets 70,591,105 72,553,745 64,450,293 67,674,051 62,608,636 ------------ ------------ ------------ ------------ ------------ Total assets $539,745,980 $518,355,537 $481,091,450 $485,567,299 $482,488,430 ============ ============ ============ ============ ============ Capitalization: Long-term debt 312,219,945 337,150,295 305,917,699 312,006,501 307,905,847 Equities and margins 128,815,340 122,524,645 114,023,296 109,119,697 104,477,942 ----------- ----------- ----------- ----------- ----------- Total capitalization $441,035,285 $459,674,940 $419,940,995 $421,126,198 $412,383,789 ============ ============ ============ ============ ============ Summary Operations Data Operating revenues 158,541,114 142,644,327 141,825,373 143,947,730 134,876,668 Operating expenses 126,430,273 110,456,886 110,737,441 113,070,990 100,913,804 Interest expense 26,158,769 25,228,001 26,011,392 26,661,510 27,052,186 Amortization of gain on Refinancing 1,440,479 1,092,620 1,542,723 1,577,149 1,703,136 ----------- ----------- ----------- ----------- ----------- Net operating margins 7,392,551 8,052,060 6,619,263 5,792,379 8,613,814 Nonoperating margins 2,287,227 1,615,374 2,111,141 1,762,018 1,217,557 ----------- ----------- ----------- ----------- ----------- Assignable margins $9,679,778 $9,667,434 $8,730,404 $7,554,397 $9,831,371 ============ ============ ============ ============ ============
Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations Caution Regarding Forward Looking Statements Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. We undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this prospectus or the effect of those events or circumstances on any of the forward-looking statements contained herein, except as required by law. Results Of Operations Overview Margins. We operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation and principal and interest on our indebtedness and to provide for the establishment of reasonable margins and reserves. Patronage capital, the retained margins of our members, constitutes our principal equity. Rate Regulation and Rates. Our rates are made up of two components: "base rates" composed of demand and energy charges; and a "fuel surcharge" that takes into account the rise and fall of fuel and purchased power costs. The RCA regulates the rates paid by our wholesale and retail customers under base rates and approves the quarterly fuel surcharge filing authorizing rate changes in the fuel surcharge calculations. Base Rates. We recover operating and maintenance and other non-fuel and purchased power costs through our base rate established through a general rate case process or through other normal RCA procedures. While the formal ratemaking process typically takes nine months to one year, it is within the RCA's authority to authorize, after a notice period, rate changes on an interim and refundable basis. In addition, the RCA has been willing to open limited reviews to resolve specific issues from which expeditious decisions can often be generated. Our base rates to our retail customers have not increased since 1994. Our base rates to our wholesale customers have been subject to periodic adjustment based on an order from the RCA. We will file a new general rate case at the end of the second quarter of 2001 that, when adjudicated, may result in a modest rate increase. Our annual base rate changes, excluding fuel surcharges, for retail and wholesale classes, for the years 1998 through 2000 were as follows: 2000 1999 1998 ---- ---- ---- Retail 0.00% 0.00% 0.00% Wholesale: Homer (0.70%) (0.30%) 0.00% MEA (0.80%) (3.80%) (0.20%) Seward 0.00% 0.00% (15.00%) The rate reductions to Matanuska Electric Association ("MEA") and Homer result from the operation of a Settlement Agreement dated effective as of November 21, 1996 as amended, among us, MEA, Homer and AEG&T (the "Settlement Agreement"). The Settlement Agreement was designed to resolve a number of ratemaking disputes and assure MEA and Homer that their base rates through 1999 would be no higher than those based on 1995 costs and would be reduced and refunds given if our 1996, 1997 or 1998 test year costs to serve their needs were significantly reduced. The Settlement Agreement has not operated as we intended, because the RCA has required us to make filings of our cost of service to facilitate determination of over- or under-collection based on the 1996, 1997 and 1998 test years. The rate reductions shown in the table for MEA and Homer in 1999 and 2000 relate to the first filing under the Settlement Agreement based on 1996 costs. Our calculations based on 1996 costs indicated that a rate reduction was required and that a refund was owed for the previous periods. We recorded provisions for wholesale rate refunds that totaled $2,651,361 at December 31, 1999. Early in 2000, we issued refunds of $86,132 to Homer and $1,809,801 to MEA that represented uncontested amounts owed consistent with the 1996 test year filing. In June 2000, the RCA issued a final order approving our 1996 test year cost of service. As a result of this order, we issued additional refunds to MEA and Homer in the amounts of $332,157 and $503,272, respectively, on July 25, 2000. Consistent with the Settlement Agreement, these refunds were based on demand and energy purchases retroactive to January 1, 1997. The rate reduction to Seward in 1998 was the result of a contract renegotiation through which Seward moved from being a firm customer to an interruptible customer. The rate reduction reflects the reduced cost of service to serve Seward since the Seward load can be interrupted. Fuel Surcharge. Fuel and purchased power costs are passed directly to our wholesale and retail customers through the fuel surcharge. Changes in these costs are due to fuel price adjustment mechanisms in our gas supply contracts based on factors like inflation or other market conditions. We pass these costs directly to our retail and wholesale customers, resulting in either a direct increase or decrease to our system revenues. The fuel surcharge is approved on a quarterly basis by the RCA. There are no limitations on fuel surcharge rate changes. Increases in our fuel and purchased power costs result in increased revenues while decreases in these costs result in lower revenues. Therefore, revenue from the fuel surcharge normally does not impact margins. The RCA ordered retroactive refunds in the approximate amount of $1.2 million because of alleged overcollection of fuel surcharges in 1995, 1996 and 1997. We appealed that finding to the Superior Court, which overturned the RCA's ruling. While the RCA did not appeal the decision, our wholesale customer, MEA did appeal that decision to the Alaska Supreme Court. MEA filed a brief in support of its claim in January 2001. We filed our brief on March 14, 2001. No hearing date has been set by the court. Year ended December 31, 2000 compared to the years ended December 31, 1999 and 1998 Revenues Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2000, operating revenues were $159 million, or 11%, higher than in 1999 primarily due to increased sales of economy energy to Golden Valley Electric Association ("GVEA") following the shutdown of the Healy Clean Coal Project (the "Healy Plant") in February 2000, higher recoverable fuel and purchased power costs and increased revenue generated by our non-traditional business ventures. In 1999, operating revenues were $143 million, or 0.57%, higher than in 1998. Retail base rates for demand and energy did not change in 1999 while base rates for demand and energy charged to MEA and Homer decreased slightly. Revenues and power sold were as follows for the years ended December 31: Year MWH Sold Operating Revenues 2000 2,405,389 $158,541,114 1999 2,190,253 $142,644,327 1998 2,055,963 $141,825,373 We make economy sales to GVEA. These sales commenced in 1988 and have contributed to our growth in operating revenues. We do not take such economy sales into consideration in our long-range resource planning process because these sales are non-firm sales that depend on GVEA's need for additional energy and our available generating capacity at the time. In 2000, 1999, and 1998, economy sales to GVEA constituted approximately 5.03%, 0.79%, and 0.92%, respectively, of our sales revenues. The increase in economy sales in 2000 from 1999 is due primarily to the shutdown of the Healy Plant, increasing the need for GVEA to make economy purchases. The Healy Plant is a 50 megawatt demonstration project in Healy, Alaska on the Alaska Intertie between Fairbanks and Anchorage. Following the test period in 1998, GVEA asserted that the demonstration was not successful. Litigation ensued and the Healy Plant has been shutdown since that time pending further analysis of alternatives for its operation. As a result, GVEA began buying economy energy from us at the time of the Healy Plant shutdown. Expenses The major components of our operating expenses for the years ended December 31, 2000, 1999 and 1998 were as follows: 2000 1999 1998 ---- ---- ---- Power production $ 52,726,374 $ 40,301,607 $ 45,261,450 Purchased power 9,152,248 8,581,979 8,462,835 Transmission 3,828,630 3,813,438 2,771,652 Distribution 9,774,860 9,400,618 8,876,890 Consumer accoun 5,275,455 4,387,421 4,177,980 Sales expense 1,112,804 1,227,908 1,125,410 Administrative, general and other 21,343,393 22,892,479 17,592,829 Depreciation 23,216,509 19,851,436 22,468,395 ---------- ---------- ------------ Total operating expenses $126,430,273 $110,456,886 $110,737,441 Power production expense increased in 2000 from 1999 by $12.4 million, or 31%, due primarily to an increase in fuel expense from $29.6 million in 1999 to $42.5 million in 2000, which resulted from an average 40% increase in fuel prices from 1999 to 2000. Power production expense decreased by $4.9 million, or 11%, in 1999 from 1998 due primarily to a decrease in fuel expense. Purchased power costs increased from 1999 to 2000 by $570,000, or 7%. We purchased more power from the Soldotna 1 unit and Anchorage Municipal Light and Power ("AML&P") than anticipated due to avalanche damage to our transmission lines early in the year, the limited availability of Beluga 3 and Beluga 6 units during the summer months and an increase in economy energy purchases for GVEA. Purchased power costs did not vary materially from 1998 to 1999. Transmission expense did not vary materially from 1999 to 2000. Transmission expense increased in 1999 from 1998 by $1 million, or 38%, due to unanticipated transmission line repairs, Y2K preparation and testing and overhead line maintenance activity as a result of outages early in 1999. Distribution expense increased in 2000 from 1999 by $374,000, or 4%, due primarily to an update in allocations of cost related to the information services and garage clearing. This update shifted those costs from the general and administrative category to the appropriate functional areas of the company. Distribution expense increased in 1999 from 1998 by $525,000, or 6%, due primarily to the increased outage activity that occurred early in 1999, which resulted in increased labor costs. Consumer accounts expense increased in 2000 from 1999 by $888,000 or 20%. This was due to less charges to costs for doubtful accounts in 1999 as compared to 2000. In addition, the update to allocations of cost related to information services caused an increase to this category in 2000. The increase in consumer accounts in 1999 from 1998 was not material but resulted from additional allocated marketing costs offset by less charges to costs for doubtful accounts in 1999. Sales expense did not vary materially in 2000, 1999 or 1998. The slight variances are due to more or less allocated marketing cost resulting from changes in the number of employees in the marketing department in these years. Administrative, general and other expense decreased by $1.55 million, or 6.8%, from 1999 to 2000. This decrease was a result of costs incurred in 1999 for outside counsel, consulting, advertising and internal labor costs associated with an unsolicited MEA takeover attempt and resultant special meeting in 1999 and an update in allocations of cost related to information services in 2000. General and administrative expense increased by $5.3 million, or 30%, from 1998 to 1999, primarily due to the costs associated with the MEA takeover attempt, an increase in software amortization expense, increased maintenance costs of the Y2K compliant software implementation completed in 1998, additional expenses associated with our ancillary businesses and multiple insurance settlements paid in 1999. In addition, general plant maintenance expenses were higher due to multiple projects completed in 1999. We use the composite method of depreciation. The increase in depreciation expense from 1999 to 2000 was $3.4 million, or 17%, and was the result of more transmission assets being placed in service in 2000. Depreciation expense decreased in 1999 from 1998 by $2.6 million, or 12%, due to a change in lives of general plant. Interest on long term debt increased for the year ended December 31, 2000 over 1999, by $849,000, or 4%, due to higher amounts of outstanding debt. Our outstanding indebtedness increased due to the issuance of $30 million in bonds to CoBank, ACB ("CoBank") and to increased borrowing under the lines of credit with CoBank and the National Rural Utilities Cooperative Finance Corporation ("CFC") to fund the Beluga 6 re-powering project and the Cooper Lake facility overhaul. Interest on short-term debt increased from 1999 to 2000 by $912,000, or 91%, because of higher balances maintained and higher interest rates. Our weighted average cost of total borrowings for 2000 was 8.06% compared to 8.14% for 1999. Interest on long-term debt was slightly lower in 1999 than 1998 by $1 million, or 4%, due primarily to the refinancing of $34.9 million of Series A Bonds due 2022 in the first quarter of 1999. Our weighted average cost of total borrowings for 1998 was 8.43%. Net interest expense includes interest on long-term debt and short-term debt, reduced by interest charged to construction. Net interest expense is reduced by $1.54 million, $1.09 million and $1.44 million in 1998, 1999 and 2000, respectively, which represents the net effect of the amortization of the gain on refinancing offset by the amortization of losses on refinancing and transaction costs. Margins Our margins for the years ended December 31, 2000, 1999 and 1998, were as follows: Net Operating Margins Nonoperating Margins Assignable Margins 2000 $ 7,392,551 $ 2,287,227 $ 9,679,778 1999 $ 8,052,060 $ 1,615,374 $ 9,667,434 1998 $ 6,619,263 $ 2,111,141 $ 8,730,404
Nonoperating margins include interest income, allowance for funds used during construction, capital credits and patronage capital allocations. Nonoperating margins increased in 2000 over 1999 by $672,000 or 42%. This was due to an allowance for funds used during construction based on higher construction work in progress balances during the year, increased allocations of patronage capital from CoBank, and higher interest earnings in 2000 as a result of increased short-term investment balances. Nonoperating margins decreased in 1999 over 1998, by $496,000, or 23%. The primary contributor to the decrease from 1998 is the gain on the sale of a surplus compressor rotor to GVEA in 1998. The variance is also due in part to higher-than-anticipated patronage capital from CoBank but is offset by a decrease in interest earnings in 1999 as a result of decreased short-term investment balances. Patronage Capital (Equity) Our patronage capital and total equity have shown steady growth. The following table summarizes our patronage capital and total equity position since 1998: 2000 1999 1998 ---- ---- ---- Patronage capital at beginning of year $117,335,481 $109,622,996 $104,800,092 Retirement of capital credits and estate payments (4,090,006) (1,954,949) (3,907,500) Assignable margins 9,679,778 9,667,434 8,730,404 ------------ ------------ ------------ Patronage capital at end of year 122,925,253 117,335,481 109,622,996 Other equity 5,890,087 5,189,164 4,400,300 ----------- ------------ ------------ Total equity at end of year $128,815,340 $122,524,645 $114,023,296 ============ ============ ============
In furtherance of our operations as a cooperative, we credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves. These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of actual capital credit retirements is at the discretion of our Board of Directors. We currently have a practice of retiring patronage capital on a first-in, first-out basis for retail customers. At December 31, 2000, we retired all retail capital credits attributable to margins earned in periods prior to 1984 and approximately 19% of 1985 retail capital credits. Prior to 2000, wholesale capital credits had been retired on a 10-year cycle pursuant to an Equity Management Plan Settlement Agreement despite its expiration in 1995. However, in 2000, there was no wholesale retirement as we implemented a plan to return the capital credits of wholesale and retail customers on a 15-year rotation. The 1991 Indenture includes a covenant restricting the distribution of patronage capital to members. We cannot distribute patronage capital to members if 1) an event of default exists or 2) the aggregate amount of patronage capital distributions after September 15, 1991, exceeds the sum of $7,000,000 plus 35% of the aggregate assignable margins earned after December 31, 1990. At December 31, 2000, we were permitted to distribute $4.14 million to our members under the 1991 Indenture under this formula. We also retire our patronage credits through annual payments to our members. The table below sets forth a five-year summary of anticipated capital credit retirements: Year Ending Wholesale Retail Total 2001 $ 0 $3,500,000 $3,500,000 2002 0 3,500,000 3,500,000 2003 0 3,500,000 3,500,000 2004 1,359,000 3,500,000 4,859,000 2005 1,109,000 3,500,000 4,609,000 Times Interest Earned Ratio (TIER) Alaska electric cooperatives generally set rates on the basis of TIER. TIER is determined by dividing the sum of assignable margins plus long-term interest expense (excluding capitalized interest) by long-term interest expense. Beginning in 1989, our Board of Directors approved an Equity Management Plan that established a schedule for building our equity. Since then we have managed our business with a view toward achieving a TIER of 1.25 or greater. We achieved TIERs for the past five years as follows: Period TIER 2000 1.39 1999 1.40 1998 1.35 1997 1.30 1996 1.39 Sale of a Segment As of March 20, 2001, we sold to GCI Communication Corporation the bulk of our internet service provider assets related to dial-up services (excluding DSL services). The aggregate purchase price was $759,049 at closing, with a potential for additional amounts, not to exceed $85,850, based on the number of subscriber accounts retained during the ninety-day transition period following closing. We are also to receive service fees for technical and other transition services during such period billed on a time-and-materials basis. The transaction will result in a minimal gain. Changes In Financial Condition Total assets increased by $21.4 million, or 4%, from December 31, 1999, to December 31, 2000. The increase was due to an increase in electric plant in service related to the Beluga 6 unit re-powering, the U.S. Postal Service fuel cell project and various distribution projects. This, however, was offset by a decrease in cash and cash equivalents caused by the funding requirements imposed by the above-mentioned projects and a decrease in materials and supplies caused by the writing off of spare generation parts from inventory. There was an increase in accounts receivable caused by the under-collection of the fuel surcharge in the fourth quarter of 2000. Changes to total liabilities include the increase in notes payable due to borrowing activity during the year. There was also an increase in accrued salaries, wages and benefits due to overall increases in company-wide benefits, as well as increases associated with new contracts with the IBEW. Additionally, the fuel liability increased due to rising fuel prices. Liquidity And Capital Resources We satisfy our operational and capital cash requirements primarily through internally-generated funds, a $50 million line of credit from CFC and a $35 million line of credit with CoBank. At December 31, 2000, there was $5 million outstanding with CFC. An additional $5 million was borrowed in January 2001, and an additional $10 million was borrowed in March 2001. The current outstanding balance as of March 2001 is $20 million. This line of credit bears interest at a variable rate, which was 8.550% as of December 31, 2000, and is currently 8.050% as of March 2001. As of December 31, 2000, $35 million was outstanding under the CoBank line of credit. This line of credit bears interest at a variable rate, which was 8.20% as of December 31, 2000, and is currently 7.70% as of March 2001. Additionally, we have negotiated a supplemental indenture with CFC authorizing a series of bonds in an amount of up to $80 million. At December 31, 2000, we had issued no bonds to CFC. On March 22, 2001, Chugach filed a Registration Statement, Form S-1, with the Securities and Exchange Commission in anticipation of Chugach's $150 million public bond offering. Principal maturities and sinking fund payments of our outstanding indebtedness at December 31, 2000 are set forth below: Year Ending December 31 Sinking Fund Requirements Principal maturities Total ----------- ------------------------- -------------------- ----- 2001 $ 6,097,000 $ 333,350 $ 6,430,350 2002 5,232,000 77,677,944 82,909,944 2003 5,041,000 865,821 5,906,821 2004 5,502,000 945,000 6,447,000 2005 6,005,000 11,031,000 17,036,000 Thereafter 147,762,000 52,158,180 199,920,180 During 2000, we spent approximately $46.7 million on capital construction projects, which includes interest capitalized during construction. We develop five-year work plans that are updated every year. Our capital improvement requirements are based on long-range plans and other supporting studies and are executed through a five-year construction work plan. Set forth below is an estimate of capital expenditures for the years 2001 through 2005: 2001 $36.0 million 2002 $42.5 million 2003 $40.2 million 2004 $40.0 million 2005 $40.1 million We are a party to a Treasury rate-lock with respect to the refinancing of a portion of the 1991 Series A Bonds. The settlement date of this contract is March 15, 2002. At December 31, 2000, the Treasury-rate lock agreement had an estimated value of ($8.6) million. At March 29, 2001, the agreement had an estimated value of ($10.37) million. See "Quantitative and Qualitative Disclosures About Market Risk--Interest Rate Risk." We expect that cash flows from operations and external funding sources will be sufficient to cover operational and capital funding requirements in 2001 and thereafter. Changes in Accounting Principles We were required to adopt SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, effective January 1, 2001. This new standard requires all derivative financial instruments to be reflected on the balance sheet. As of January 1, 2001, we have established a regulatory asset for $8.6 million and a liability for the same amount. The regulatory asset and liability will be adjusted for changes in the fair value of a Treasury rate-lock agreement entered into by us. See "Quantitative and Qualitative Disclosures about Market Risk - Interest Rate Risk." Management believes it is probable the regulatory asset will be recovered through rates. Item 7A - Quantitative and Qualitative Disclosures About Market Risk We are exposed to a variety of risks, including changes in interest rates and changes in commodity prices due to repricing mechanisms inherent in gas supply contracts. In the normal course of our business, we manage our exposure to these risks as described below. We do not engage in trading market risk-sensitive instruments for speculative purposes. Interest Rate Risk As of December 31, 2000, except for two bonds issued to CoBank carrying variable interest rates that are periodically re-priced, all of our other outstanding long-term borrowings were at fixed interest rates with varying maturity dates. The following table provides information regarding cash flows for principal payments on total debt by maturity date (dollars in thousands) as of December 31, 2000 and 1999: 2000 Fair Total Debt* 2001 2002 2003 2004 2005 Thereafter Total Value - ----------- ---- ---- ---- ---- ---- ---------- ----- ----- Fixed rate $6,430 $10,410 $5,907 $6,447 $17,036 $199,920 $246,150 $262,655 Average interest rate 8.13% 6.90% 8.62% 8.62% 8.12% 8.22% 8.17% Variable rate $40,000 $72,500 $0 $0 $0 $0 $112,500 $112,500 Average interest rate 8.24% 8.20% -- -- -- -- 8.22% * Includes current portion
1999 Fair Total Debt* 2000 2001 2002 2003 2004 Thereafter Total Value - ----------- ---- ---- ---- ---- ---- ---------- ----- ----- Fixed rate $6,372 $6,430 $10,410 $5,907 $6,447 $235,456 $271,023 $282,034 Average interest rate 8.12% 8.13% 6.90% 8.62% 8.62% 7.95% 7.95% Variable rate $0 $0 $72,500 $0 $0 $0 $72,500 $72,500 Average interest rate -- -- 6.87% -- -- -- 6.87% * Includes current portion
We are exposed to market risk from changes in interest rates. A 100 basis-point change (up or down) would increase or decrease our interest expense by approximately $1,125,000, based on $112.5 million of variable debt outstanding at December 31, 2000. The CoBank and CFC lines of credit, under which we currently have $40 million in short-term debt outstanding, bear interest at variable rates. As of December 31, 2000, the aggregate principal amount of outstanding 1991 Series A Bonds due 2022 was $164,310,000. The 1991 Series A Bonds due 2022 are not callable until March 15, 2002. To manage interest rate exposure for refinancing of these bonds on their first available call date, March 15, 2002, we entered into a Treasury rate-lock transaction with Lehman Brothers Financial Products Inc. ("Lehman Brothers"). Under the Treasury rate-lock contract, we will receive a lump-sum payment from Lehman Brothers on March 15, 2002, if the yield on 10- or 30-year Treasury bonds as of mid-February 2002, exceeds a specified target level (5.653% and 5.838%, respectively). Conversely, we will on the same date be required to make a payment to Lehman Brothers if the yield on the 10- or 30-year Treasury bonds falls below their stated target yields. In each case, the amount of the payment will increase as the difference between the actual yield and the target yield widens. For each basis point (0.01% per annum) by which the yield on 10-year or 30-year Treasury bonds deviates from the stated target level we will receive (if the prevailing Treasury yield exceeds the target yield) or make (if the prevailing Treasury yield falls short of the target yield) a payment equal to the product obtained by multiplying (i) the difference between the prevailing and target yields (expressed in basis points) by (ii) the changes in the prices of $196 million (in the case of 10-year Treasury bonds) and $18.7 million (in the case of the 30-year Treasury bonds) of Treasury bonds, given a one-basis-point change in their respective yields (determined with reference to the Bloomberg Financial Markets Government Yield Analysis Page). In this way, we intend that higher interest costs resulting from any increases in market interest rates between the date of the rate-lock contract and the refinancing of our long-term debt would be mitigated by a lump-sum, up-front payment to us at the time of the refinancing. Conversely, any savings from decreases in interest rates during the same period would be reduced by a payment by us to the rate-lock counterparty. At December 31, 2000 and 1999, the Treasury rate lock agreement had an estimated value of approximately $(8,600,000) and $13,000,000, respectively. The decrease in estimated value is due to the decline on the yield on the 10-year and 30-year Treasury bonds. A 10 basis-point change (up or down) in the prevailing yield on both 10-year and 30-year Treasury bonds would change the value of the rate-lock agreement (up or down) by approximately $1,800,000. Commodity Price Risk Our gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because purchased power costs are passed directly to our wholesale and retail customers through a fuel surcharge, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not normally impact margins. The fuel surcharge mechanism mitigates the commodity price risk related to market fluctuations in the price of purchased power. Item 8 -Financial Statements and Supplementary Data December 31, 2000 and 1999 Independent Auditors' Report The Board of Directors Chugach Electric Association, Inc. We have audited the accompanying balance sheets of Chugach Electric Association, Inc. as of December 31, 2000 and 1999, and the related statements of revenues, expenses and patronage capital and cash flows for each of the years in the three-year period ended December 31, 2000. In connection with our audits of the financial statements, we have also audited the financial statement schedule listed in Item 14 herein. These financial statements and financial statement schedule are the responsibility of the Association's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Chugach Electric Association, Inc. as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein. /s/ KPMG LLP Anchorage, Alaska February 23, 2001, except as to note 17, which is as of March 6, 2001 CHUGACH ELECTRIC ASSOCIATION, INC. Balance Sheets December 31, 2000 and 1999 Assets 2000 1999 ------ ---- ---- Utility plant (notes 2, 6, 13 and 14): Electric plant in service $687,127,130 $ 641,627,328 Construction work in progress 42,027,617 47,257,296 ---------- ---------- 729,154,747 688,884,624 Less accumulated depreciation 259,999,872 243,082,832 ----------- ----------- Net utility plant 469,154,875 445,801,792 ----------- ----------- Other property and investments, at cost: Nonutility property 443,555 413,515 Investments in associated organizations (note 3) 9,857,153 8,946,861 --------- --------- 10,300,708 9,360,376 ---------- --------- Current assets: Cash and cash equivalents,including repurchase agreementsof $3,905,283 in 2000 and $6,574,457 in 1999 1,695,162 4,110,030 Cash-restricted construction funds 378,848 538,404 Special deposits 212,163 182,164 Accounts receivable, less provision for doubtful accounts of $441,933 in 2000 and $389,223 in 1999 19,200,912 17,730,994 Fuel cost recovery 2,915,733 180,755 Materials and supplies 15,357,198 17,180,136 Prepayments 755,276 861,947 Other current assets 332,246 341,702 -------------- -------------- Total current assets 40,847,538 41,126,132 ------------ ------------ Deferred charges (notes 9 and 15) 19,442,859 22,067,237 ------------ ------------ $ 539,745,980 $ 518,355,537 =========== =============
See accompanying notes to financial statements. CHUGACH ELECTRIC ASSOCIATION, INC. Balance Sheets, Continued December 31, 2000 and 1999 Liabilities 2000 1999 ----------- ---- ---- Equities and margins (note 11): Memberships $ 1,009,663 $ 960,808 Patronage capital (note 4) 122,925,253 117,335,481 Other (note 5) 4,880,424 4,228,356 --------- ------------ 128,815,340 122,524,645 ----------- ------------ Long-term obligations, excluding current installments (notes 6, 7 and 11): First mortgage bonds payable 169,542,000 194,139,000 National Bank for Cooperatives bonds Payable 142,677,945 143,011,295 ----------- ------------- 312,219,945 337,150,295 ----------- ------------ Current liabilities: Current installments of long-term obligations (notes 6, 7 and 11) 6,430,350 6,372,405 Short-term borrowings (note 6) 40,000,000 0 Accounts payable 9,493,875 9,508,851 Consumer deposits 1,324,213 1,059,677 Accrued interest 5,861,390 6,066,114 Salaries, wages and benefits 4,586,407 4,053,228 Fuel 8,154,559 4,381,304 Other 1,434,562 2,527,798 --------- ------------ Total current liabilities 77,285,356 33,969,377 ---------- ------------ Deferred credits (note 12) 21,425,339 24,711,220 ---------- ------------ $539,745,980 $518,355,537 ============ ============
See accompanying notes to financial statements. CHUGACH ELECTRIC ASSOCIATION, INC. Statements of Revenues, Expenses and Patronage Capital Years ended December 31, 2000, 1999 and 1998 2000 1999 1998 ---- ---- ---- Operating revenues $158,541,114 $ 142,644,327 $ 141,825,373 ----------- ------------ ------------ Operating expenses: Production 52,726,374 40,301,607 45,261,450 Purchased power 9,152,248 8,581,979 8,462,835 Transmission 3,828,630 3,813,438 2,771,652 Distribution 9,774,860 9,400,618 8,876,890 Consumer accounts 5,275,455 4,387,421 4,177,980 Sales expense 1,112,804 1,227,908 1,125,410 Administrative, general and other 21,343,393 22,892,479 17,592,829 Depreciation 23,216,509 19,851,436 22,468,395 ----------- ------------ ------------ Total operating expenses 126,430,273 110,456,886 110,737,441 ------------ ------------ ------------ Interest: On long-term debt 24,987,033 24,137,593 25,159,660 Charged to construction - credit (2,178,425) (1,000,246) (821,137) On short-term debt 1,909,682 998,034 130,146 ---------- ------------ ------------ Net interest 24,718,290 24,135,381 24,468,669 ----------- ------------ ------------ Net operating margins 7,392,551 8,052,060 6,619,263 Nonoperating margins: Interest income 703,807 592,208 711,155 Other 1,615,161 1,003,029 1,050,899 Property gain (loss) (31,741) 20,137 349,087 --------- ----------- ------------ Assignable margins 9,679,778 9,667,434 8,730,404 Patronage capital at beginning of year 117,335,481 109,622,996 104,800,092 Retirement of capital credits and Estate payments (note 4) (4,090,006) (1,954,949) (3,907,500) ---------- ----------- ------------ Patronage capital at end of year $122,925,253 $117,335,481 $109,622,996 ============ ============ ============
See accompanying notes to financial statements. CHUGACH ELECTRIC ASSOCIATION, INC. Statements of Cash Flows Years ended December 31, 2000, 1999 and 1998 2000 1999 1998 ---- ---- ---- Cash flows from operating activities: Assignable margins $9,679,778 $9,667,434 $8,730,404 Adjustments to reconcile assignable margins to net cash provided by operating activities: Depreciation and amortization 27,575,408 23,563,805 24,605,760 Capitalization of equity allowance (340,838) (151,474) (260,258) Property (gains) losses and obsolete inventory write-off (25,425) 242 (349,087) Other (1,155) (221) 60,734 Changes in assets and liabilities: (Increase) decrease in assets: Special deposits (29,999) (61,000) 30,540 Accounts receivable (1,469,918) (1,049,512) 2,549,024 Fuel cost recovery (2,734,978) 381,029 4,206,848 Prepayments 106,671 55,434 (359,010) Materials and supplies, net 1,822,938 (1,216,702) (344,349) Deferred charges (1,231,531) (14,179,418) (7,898,240) Other assets 9,456 7,328 (43,615) Increase (decrease) in liabilities: Accounts payable (14,976) 670,093 1,800,524 Accrued interest (204,724) (656,211) (182,010) Deferred credits (3,638,491) (2,973,944) (1,829,112) Consumer deposits, net 264,536 66,061 (44,625) Other liabilities 3,213,198 524,833 (3,129,329) --------- ------------ ----------- Total adjustments 23,300,172 4,980,343 18,813,795 ---------- ----------- ---------- Net cash provided by operating activities 32,979,950 14,647,777 27,544,199 ---------- ---------- ---------- Cash flows from investing activities: Extension and replacement of plant (46,736,359) (41,864,828) (20,269,038) Increase in investments in associated organizations (909,137) (590,276) (552,827) ------------ ------------ ------------ Net cash (used) in investing activities (47,645,496) (42,455,104) (20,821,865) ------------ ------------ ------------ Cash flows from financing activities: Transfer of restricted construction funds 159,556 (361,038) 187,412 Proceeds from short-term borrowings 40,000,000 0 0 Proceeds from long-term debt 0 72,500,000 0 Repayments of long-term debt (24,872,405) (40,983,801) (5,913,512) Memberships and donations received 700,923 788,865 80,695 Retirement of patronage capital (4,090,006) (1,954,949) (3,907,500) Net receipts (refunds) of consumer advances for construction 352,610 (384,294) (81,384) --------- ---------- ----------- Net cash provided by (used in) financing activities 12,250,678 29,604,783 (9,634,289) ---------- ---------- ----------- Net change in cash and cash equivalents (2,414,868) 1,797,456 (2,911,955) Cash and cash equivalents at beginning of year $4,110,030 $ 2,312,574 $ 5,224,529 - ---------------------------------------------- ---------- ----------- ----------- Cash and cash equivalents at end of year $1,695,162 $ 4,110,030 $ 2,312,574 - ---------------------------------------- ========== =========== =========== Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized 24,917,014 24,791,592 24,650,680 ========== ========== ==========
See accompanying notes to financial statements. CHUGACH ELECTRIC ASSOCIATION, INC. Notes to Financial Statements December 31, 2000 and 1999 (1) Description of Business and Summary of Significant Accounting Policies Description of Business Chugach Electric Association, Inc. (Association or Chugach) is the largest electric utility in Alaska. The Association is engaged in the generation, transmission and distribution of electricity to directly served retail customers in the Anchorage and upper Kenai Peninsula areas. Through an interconnected regional electrical system, Chugach's power flows throughout Alaska's Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska's largest cities, Anchorage and Fairbanks. Chugach also supplies much of the power requirements of three wholesale customers, Matanuska Electric Association (MEA), Homer Electric Association (Homer) and the City of Seward (Seward). The Association operates on a not-for-profit basis and, accordingly, seeks only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation, and principal and interest on all indebtedness and to provide for reasonable margins and reserves. The Association is subject to the regulatory authority of the Regulatory Commission of Alaska (RCA), (formerly the Alaska Public Utilities Commission (APUC)). Management Estimates In preparing the financial statements, management of the Association is required to make estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the balance sheet and revenues and expenses for the reporting period. Actual results could differ from those estimates. Regulation The accounting records of the Association conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission. The Association meets the criteria, and accordingly, follows the accounting and reporting requirements of Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on the Association's statement of revenues and expenses as assignable margins. Retained assignable margins are designated on the Association's balance sheet as patronage capital, which is assigned to each member on the basis of patronage. This patronage capital constitutes the principal equity of the Association. CHUGACH ELECTRIC ASSOCIATION, INC. Notes to Financial Statements Reclassifications Certain reclassifications have been made to the 1998 and 1999 financial statements to conform to the 2000 presentation. Plant Additions and Retirements Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, and indirect overhead charges. For property replaced or retired, the average unit cost of the property unit, plus removal cost, less salvage, is charged to accumulated provision for depreciation. The cost of replacement is added to electric plant. Operating Revenues Operating revenues are based on billing rates authorized by the RCA which are applied to customers' usage of electricity. Included in operating revenue are billings rendered to customers adjusted for differences in meter read dates from year to year. The Association's tariffs include provisions for the flow through of gas costs pursuant to existing gas supply contracts. Chugach entered into a settlement agreement with MEA and Homer in 1996. The settlement agreement was designed to resolved a number of ratemaking disputes and assure MEA and Homer that their base rates would be no higher than those based on 1995 costs and would be reduced (and refunds given) if our 1996, 1997 or 1998 test year costs to serve their needs were significantly reduced. The RCA has required Chugach to make filings of Chugach's cost of service to facilitate determination of any refunds owed under the settlement agreement. Calculations based on 1996 costs indicated that a rate reduction was required and that a refund was owed for the previous periods. Chugach recorded provisions for wholesale rate refunds that totaled $2,651,361 as of December 31, 1999. Early in 2000, refunds of $86,132 were issued to Homer and $1,809,801 to MEA that represented uncontested amounts owed consistent with the 1996 test year filing. In June 2000, the RCA issued its final order approving the 1996 test year cost of service. As a result of this order, additional refunds were issued to MEA and Homer in the amounts of $332,157 and $503,272, respectively, on July 25, 2000. Consistent with the Settlement Agreement, these refunds were based on demand and energy purchases retroactive to January 1, 1997. The process for RCA, MEA and Homer review of 1997 test year costs is nearly complete. An order from the RCA was received February 27, 2001, and no rate reduction or refunds were required. Both MEA and Chugach have filed petitions for reconsideration of this order. The 1998 test year cost calculation is currently being reviewed by the RCA. Management believes that no rate reduction or refund will be required based on the 1998 test year. The RCA has required that Chugach file a general rate case based on the 2000 test year by June 30, 2001. This filing may request a modest increase in base rates. In 1998 a power sales agreement was negotiated between Chugach and Seward. The contract was approved by the RCA on June 14, 1999 for a three-year term, which expires on September 1, 2001. The parties have recently negotiated and executed an Amendment, extending the term of the contract to January 31, 2006, subject to approval by the RCA. In October 1998 Marathon Oil Company, one of Chugach's natural gas suppliers, notified Chugach that it had reached a settlement with the State of Alaska regarding additional excise and royalty taxes for the period 1989 through 1998. In accordance with the purchase contract, Chugach would be responsible for these additional taxes. The RCA approved Chugach's plan to recover this over 12 months through the Fuel Surcharge mechanism except for the retail portion in the amount of $436,778 that was written-off at December 31, 1998. Recovery of this expense in rates continued from April 1, 1999 through April 1, 2000. Despite RCA approval and subsequent re-confirmation by the RCA, MEA has refused to pay the portion of its monthly bill it considers to be recovery of the Marathon tax. Effective December 20, 2000, by the Superior Court for the State of Alaska, MEA was ordered to pay $298,004, representing the unpaid tax liability and associated litigation costs. MEA has appealed this order to the Alaska Supreme Court. Investments in Associated Organizations Investments in associated organizations represent capital requirements as part of financing arrangements. These investments are non-marketable and accounted for at cost. Deferred Charges and Credits Deferred charges, representing regulatory assets, are amortized to operating expense over the period allowed for rate-making purposes, generally five years. Nonrefundable contributions in aid of construction are credited to the associated cost of construction of property units. Refundable contributions in aid of construction are held in deferred credits pending their return or other disposition. Depreciation and Amortization Depreciation and amortization rates have been applied on a straight-line basis and at December 31, 2000 are as follows: Rate (%) Steam production plant 2.70 - 2.96 Hydraulic production plant 1.33 - 2.88 Other production plant 3.34 - 6.50 Transmission plant 1.85 - 5.37 Distribution plant 2.10 - 4.55 General plant 2.22 - 20.00 Other 1.88 - 2.75 In 1997 an update of the Depreciation Study was completed utilizing Electric Plant in Service balances as of December 31, 1995. Depreciation rates developed in that study were implemented in January, 1998. In 2000 another update of the study was completed. Depreciation rates determined in that study will be implemented upon approval by the RCA. Capitalized Interest Allowance for funds used during construction and interest charged to construction - credit are the estimated costs during the period of construction of equity and borrowed funds used for construction purposes. The Association capitalized such funds at the average rate (adjusted monthly) of 7.9% during 2000, 7.4% during 1999 and 8.3% during 1998. Cash and Cash Equivalents For purposes of the statement of cash flows, the Association considers all highly liquid debt instruments with a maturity of three months or less upon acquisition by the Association (excluding restricted cash and investments) to be cash equivalents. Materials and Supplies Materials and supplies are stated at the lower of cost or market and valued at average cost. Fair Value of Financial Instruments Statement of Financial Accounting Standards 107, Disclosures About the Fair Value of Financial Instruments, requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments: Cash and cash equivalents and restricted cash - the carrying amount approximates fair value because of the short maturity of those instruments. Investments in associated organizations - the carrying amount approximates fair value because of limited marketability and the nature of the investments. Consumer deposits - the carrying amount approximates fair value because of the short refunding term. Long-term obligations - the fair value is estimated based on the quoted market price for same or similar issues (note 7). Forward rate lock agreements - the fair value is estimated based on discounted cash flow using current rates. Financial Instruments and Hedging The Association uses U.S. Treasury forward rate lock agreements to hedge expected interest rates on probable debt refinancings. Under the guidance of SFAS No. 80, Accounting for Futures Contracts, the Association has accounted for the treasury rate lock agreement as a hedge. Accordingly, the unrealized gain or loss has not been recorded and will be treated as a regulatory asset or liability upon settlement (note 6). Income Taxes The Association is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code, except for unrelated business income. For the years ended December 31, 2000, 1999 and 1998 the Association received no unrelated business income. Environmental Remediation Costs The Association accrues for losses associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. Estimates of future costs for environmental remediation obligations are not discounted to their present value. 2) Utility Plant Summary Major classes of electric plant as of December 31 are as follows: 2000 1999 ---- ---- Electric plant in service: Steam production plant $60,392,869 $60,392,869 Hydraulic production plant 8,798,695 8,798,695 Other production plant 106,017,802 104,925,446 Transmission plant 211,860,829 211,881,174 Distribution plant 170,378,081 162,365,836 General plant 45,835,618 47,704,821 Unclassified electric plant in service 77,054,390 38,834,298 Equipment under capital lease 56,323 56,323 Other 6,732,523 6,667,866 ------------- ------------- Total electric plant in service 687,127,130 641,627,328 Construction work in progress 42,027,617 47,257,296 ------------- ------------ Total electric plant in service and construction work in progress $729,154,747 $688,884,624 ============ ============ Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment. (3) Investments in Associated Organizations Investments in associated organizations include the following at December 31: 2000 1999 ---- ---- National Rural Utilities Cooperative Finance Corporation (NRUCFC) $ 6,095,980 $ 6,095,980 National Bank for Cooperatives (CoBank) 3,600,133 2,708,200 NRUCFC capital term certificates 33,733 32,300 Other 127,307 110,381 ------- --------- $9,857,153 $8,946,861 ========== ========== The Farm Credit Administration, CoBank's federal regulators, requires minimum capital adequacy standards for all Farm Credit System institutions. CoBank's loan agreements require, as a condition of the extension of credit, that an equity ownership position be established by all borrowers. The Association's investment in NRUCFC similarly was required by its financing arrangements with NRUCFC. (4) Patronage Capital The Association has an approved Equity Management Plan which establishes in general, a ten-year (for wholesale customers) and twenty-year (for retail customers) capital credit retirement of patronage capital, based on the members' proportionate contribution to Association assignable margins. On January 19, 2000, the Board of Directors passed a resolution putting all members on a 15-year rotation. At December 31, 2000, out of the total of $122,925,253 patronage capital, the Association had assigned $89,432,752 of such patronage capital (net of capital credit retirements). Approval of actual capital credit retirements is at the discretion of the Association's Board of Directors. In December 1998 the Board of Directors authorized the retirement of $2,208,997 of retail capital credits representing the balance of 1984 retail distribution patronage. The Board also authorized the retirement of $1,533,287 of wholesale patronage for 1988. In November 1999 the Board of Directors authorized the retirement of $1,766,000 of retail patronage for 1984. In November 2000 the Board of Directors authorized the retirement of $3,750,000 of retail patronage for 1984 and 1985. Following is a five-year summary of anticipated capital credit retirements: Year ending Wholesale Retail Total ----------- --------- ------ ----- 2001 $ - $3,500,00 $3,500,000 2002 - 3,500,00 3,500,000 2003 - 3,500,00 3,500,000 2004 1,359,000 3,500,00 4,859,000 2005 1,109,000 3,500,00 4,609,000 (5) Other Equities A summary of other equities at December 31 follows: 2000 1999 ---- ---- Nonoperating margins, prior to 1967 $ 23,625 $ 23,625 Donated capital 183,907 183,907 Unredeemed capital credit retirement 4,672,892 4,020,824 ----------- ---------- $4,880,424 $4,228,356 ========== ========== (6) Debt Long-term obligations at December 31 are as follows: 2000 1999 ---- ---- First mortgage bonds of 8.08% maturing in 2002 and 9.14% maturing in 2022 with interest payable semiannually March 15 and September 15: 8.08% $ 11,329,000 $ 17,396,000 9.14% 164,310,000 182,810,000 CoBank 8.95% bond maturing in 2002, With interest payable monthly and Principal due semi-annually 511,295 816,700 CoBank 7.76% bond maturing in 2005, With interest payable monthly 10,000,000 10,000,000 CoBank 5.60% bonds maturing in 2022, with Interest payable monthly 45,000,000 45,000,000 CoBank 5.60% bonds maturing in 2002, 2007 and 2012 with interest payable monthly 15,000,000 15,000,000 CoBank, variable interest, with a rate of 8.20% at December 31, 2000, bonds maturing in 2002, with 42,500,000 42,500,000 interest payable monthly CoBank, variable interest, with a rate of 8.20% at December 31, 2000, bonds maturing in 2002, with 30,000,000 30,000,000 interest payable monthly ----------- ---------- Total long-term obligations 318,650,295 343,522,700 Less current installments 6,430,350 6,372,405 --------------- ------------- Long-term obligations, excluding current installments $ 312,219,945 $337,150,295 ============= ============
Substantially all assets are pledged as collateral for the long-term obligations. Maturities of Long-term Obligations Long-term obligations at December 31, 2000 mature as follows: Year ending Sinking Fund Requirements Principal maturities Total -------------------- ----- December 31 First mortgage CoBank Bonds Mortgage bonds 2001 $6,097,000 $333,350 $6,430,350 2002 5,232,000 77,677,944 82,909,944 2003 5,041,000 865,821 5,906,821 2004 5,502,000 945,000 6,447,000 2005 6,005,000 11,031,000 17,036,000 Thereafter 147,762,000 52,158,180 199,920,180 -------------- ------------- ----------- $175,639,000 $143,011,295 $318,650,295 ============= ============ ============
Lines of Credit The Association had an annual line of credit of $35,000,000 in 2000 and 1999 available with CoBank. The CoBank line of credit expires August 1, 2001 but carries an annual automatic renewal clause. At December 31, 2000 there was $35 million outstanding on this line of credit which carried an interest rate of 8.20%. At December 31, 1999 there was no outstanding balance. In addition, the Association had an annual line of credit of $50,000,000 available at December 31, 2000 and 1999 with NRUCFC. At December 31, 2000 there was $5 million outstanding on this line of credit which carried an interest rate of 8.55%. At December 31, 1999 there was no outstanding balance. The NRUCFC line of credit expires October 14, 2002. Refinancing On September 19, 1991, Chugach issued $314,000,000 of First Mortgage Bonds, 1991 Series A (Bonds), for purposes of repaying existing debt to the Federal Financing Bank and the Rural Electrification Administration (now Rural Utilities Services). Pursuant to Section 311 of the Rural Electrification Act, Chugach was permitted to prepay the REA debt at a discounted rate of approximately 9%, resulting in a discount of approximately $45,000,000 (note 12). The bonds maturing in 2002 (Series A 2002 Bonds) are subject to annual sinking fund redemption at 100% of the principal amount thereof which commenced March 15, 1993. The bonds maturing in 2022 (Series A 2022 Bonds) are subject to annual sinking fund redemption at 100% of the principal amount thereof commencing March 15, 2003. The Series A 2002 Bonds are not subject to optional redemption. The Series A 2022 Bonds are redeemable at the option of Chugach on any interest payment date at an initial redemption price commencing in 2002 of 109.140 of the principal amount thereof declining ratably to par on March 15, 2012. The Bonds are secured by a first lien on substantially all of Chugach's assets. The Indenture prohibits outstanding short-term indebtedness (other than trade payables) in excess of 15% of Chugach's net utility plant and limits certain cash investments to specific securities. In April 1997, Chugach reacquired $5,000,000 of the Series A 2022 Bonds at a premium of 109.7500. Total transaction cost, including accrued interest and premium, was $5,510,350. In February 1999, Chugach reacquired $11,000,000 of the Series A 2022 Bonds at a premium of 117.05. Total transaction cost, including accrued interest and premium, was $13,322,344. In February 1999, Chugach reacquired $14,000,000 of the Series A 2022 Bonds at a premium of 116.25. Total transaction cost, including accrued interest and premium, was $16,868,592. In February 1999, Chugach reacquired $9,895,000 of the Series A 2022 Bonds at a premium of 116.75. Total transaction cost, including accrued interest and premium, was $11,974,467. In March 2000, Chugach reacquired $8,500,000 of the Series A 2022 Bonds at a premium of 104.00. Total transaction cost, including accrued interest and premium, was $9,215,502. In April 2000, Chugach reacquired $10,000,000 of the Series A 2022 Bonds at a premium of 108.875. Total transaction costs, including accrued interest and premium, was $10,953,511. On March 17, 1999, Chugach entered into a Treasury rate-lock transaction with Lehman Brothers Financial Products Inc. (Lehman Brothers) for the purpose of taking advantage of favorable market interest rates in anticipation of refinancing Chugach's Series A Bonds due 2022 on their call date (March 15, 2002). As of December 31, 2000, the aggregate principal amount of Series A Bonds due 2022 was $164,310,000. Under the treasury rate-lock contract, Chugach will receive a lump-sum payment from Lehman Brothers on March 15, 2002, if the yield on 10- or 30-year Treasury bonds as of mid-February 2002, exceeds a specified target level (5.653% and 5.838%, respectively). Conversely, Chugach will on the same date be required to make a payment to Lehman Brothers if the yield on the 10- or 30-year Treasury bonds falls below its stated target yield. The treasury rate lock agreement fair value on December 31, 2000 was $(8,600,000) and on December 31, 1999 was $13,000,000. Chugach will adopt SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, on January 1, 2001. This new standard requires all derivative financial instruments to be reflected on the balance sheet. As of January 1, 2001, Chugach will establish a regulatory asset for $8.6 million and a liability for the same amount. The regulatory asset and liability will be adjusted for changes in the fair value of the treasury rate lock agreement. Management believes it is probable the regulatory asset will be recovered through rates. (7) Fair Value of Long-Term Obligations The estimated fair values (in thousands) of the long-term obligations included in the financial statements at December 31 are as follows: 2000 1999 ---- ---- Carrying Fair Carrying Fair Value Value Value Value Long-term obligations (including current installments) $318,650 $335,155 $343,523 $354,534
Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions. (8) Employee Benefits Employee benefits for substantially all employees are provided through the Alaska Electrical Trust and Alaska Hotel, Restaurant and Camp Employees Health and Welfare Trust Funds (union employees) and the National Rural Electric Cooperative Association (NRECA) Retirement and Security Program (nonunion employees). The Association makes annual contributions to the plans equal to the amounts accrued for pension expense. For the union plans, the Association pays a contractual hourly amount per union employee which is based on total plan costs for all employees of all employers participating in the plan. In these master, multiple-employer plans, the accumulated benefits and plan assets are not determined or allocated separately to the individual employer. Costs for union plans were approximately $2,017,000 in 2000, $1,832,000 in 1999 and $1,805,000 in 1998. In 2000, 1999 and 1998, the Association contributed $1,057,000, $868,000 and $813,000, respectively, to the NRECA plan. CHUGACH ELECTRIC ASSOCIATION, INC. Notes to Financial Statements (9) Deferred Charges Deferred charges consisted of the following at December 31: 2000 1999 ----- ---- Debt issuance and reacquisition costs $ 5,399,282 $ 6,196,555 Refurbishment of transmission equipment 253,087 262,346 Computer software and conversion 10,672,135 12,186,272 Studies 1,724,936 1,880,734 Business venture studies 562,435 273,660 Fuel supply negotiations 346,894 369,609 Major overhaul of steam generating unit 222,198 427,305 Environmental matters and other 261,892 470,756 ------- ---------- $19,442,859 $22,067,237 =========== =========== (10) Employee Representation Approximately 72% of the Association's employees are represented by the International Brotherhood of Electrical Workers (IBEW). The various IBEW contracts expire on June 30, 2003. (11) Return of Capital Under provisions of its long-term debt agreements, the Association is not directly or indirectly permitted to declare or pay any dividend or make any payments, distributions or retirements of patronage capital to members if an event of default exists with respect to its bonds (event of default), if payment of such distribution would result in an event of default, or if the aggregate amount expended for all distributions on and after September 26, 1991 exceeds the sum of $7,000,000 plus 35% of the aggregate assignable margins (whether or not such assignable margins have since been allocated to members) of the Association earned after December 31, 1990 (or, in the case such aggregate shall be a deficit, minus 100% of such deficit). The Association may declare and make distributions at any time if, after giving effect thereto, the Association's aggregate margins and equities as of the end of the most recent fiscal quarter would be not less than 45% of the Association's total liabilities and equities as of the date of the distribution. The Association does not anticipate that this provision will limit the anticipated capital credit retirements described in note 4. (12) Deferred Credits Deferred credits at December 31 consisted of the following: 2000 1999 ----- ---- Regulatory liability - unamortized gain on reacquired debt $18,066,673 $ 21,271,412 Refundable consumer advances for construction 1,771,302 2,123,913 Estimated initial installation costs for transformers and meters 323,821 272,554 Post retirement benefit obligation 286,200 286,200 New business venture 20,254 46,185 Other 957,089 710,956 ------- ---------- $21,425,339 $24,711,220 =========== ============
In conjunction with the refinancing described in note 6, the Association had recognized a gain of approximately $45,000,000. The APUC required the Association to flow through the gain to consumers in the form of reduced rates over a period equal to the life of the bonds using the effective interest method; consequently, the gain has been deferred for financial reporting purposes as required by SFAS 71. Approximately $1,553,000 of the deferred gain was amortized in 2000. Approximately $1,215,000 of the deferred gain was amortized in 1999. Approximately $1,700,000 of the deferred gain was amortized in 1998. (13) Bradley Lake Hydroelectric Project The Association is a participant in the Bradley Lake Hydroelectric Project (Bradley Lake). Bradley Lake was built and financed by the Alaska Energy Authority (AEA) through State of Alaska grants and $166,000,000 of revenue bonds. The Association and other participating utilities have entered into take-or-pay power sales agreements under which shares of the project capacity have been purchased and the participants have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt service costs and amounts required to maintain established reserves). Under these take-or-pay power sales agreements, the participants have agreed to pay all project costs from the date of commercial operation even if no energy is produced. The Association has a 30.4% share of the project's capacity. The share of debt service exclusive of interest, for which the Association has guaranteed is approximately $44,000,000. Under a worst case scenario, the Association could be faced with annual expenditures of approximately $4.1 million as a result of its Bradley Lake take-or-pay obligations. Management believes that such expenditures, if any, would be recoverable through the fuel surcharge ratemaking process. Upon the default of a Bradley Lake participant, and subject to certain other conditions, AEA, through Alaska Industrial Development and Export Authority, is entitled to increase each participant's share of costs pro rata, to the extent necessary to compensate for the failure of another participant to pay its share, provided that no participant's percentage share is increased by more than 25%. On April 6, 1999, AEA issued $59,485,000 of Power Revenue Refunding Bonds, Third Series, for the purpose of refunding $59,110,000 of the First Series Bonds. The refunded First Series Bonds were called on July 1, 1999. The refunding resulted in aggregate debt service payments over the next nineteen years in a total amount approximately $9,500,000 less than the debt service payments which would be due on the refunded bonds. There was an economic gain of approximately $5,900,000. Economic gain is calculated as the net difference between the present value of the old debt service requirements and the present value of the new debt service requirements, discounted at the effective interest rate and adjusted for additional cash paid. On April 13, 1999, AEA issued $30,640,000 of Power Revenue Refunding Bonds, Fifth Series, for the purpose of refunding $28,910,000 of the First Series Bonds. The refunded First Series Bonds were called on July 1, 1999. The refunding resulted in aggregate debt service payments over the next twenty-three years in a total amount approximately $4,400,000 less than the debt service payments which would be due on the refunded bonds. There was an economic gain of approximately $2,900,000. On April 4, 2000, AEA issued $47,710,000 of Power Revenue Refunding Bonds, Fourth Series, for the purpose of refunding $46,235,000 of the Second Series Bonds. The refunded Second Series Bonds were called on July 1, 2000. The refunding resulted in aggregate debt service payments over the next twenty-two years in a total amount approximately $6,400,000 less than the debt service payment which would be due on the refunded bonds. There was an economic gain of approximately $3,500,000. The following represents information with respect to Bradley Lake at June 30, 2000 (the most recent date for which information is available). The Association's share of expenses were $3,696,829 in 2000, $3,902,737 in 1999 and $4,112,292 in 1998 and are included in purchased power in the accompanying financial statements. (In thousands) Total Proportionate Share ----- Plant in service $ 306,872 $ 93,289 Accumulated depreciation (60,567) (18,170) Interest expense 9,938 2,981 Other electric plant in service represents the Association's share of a Bradley Lake transmission line financed internally and the Association's share of the Eklutna Hydroelectric Project, purchased in 1997 (note 14). (14) Eklutna Hydroelectric Project During October 1997, the ownership of the Eklutna Hydroelectric Project formally transferred from the Alaska Power Administration to the participating utilities. This group consists of the Association along with Matanuska Electric Association (MEA) and Municipal Light and Power (AML&P). Other electric plant in service includes $1,956,954 representing the Association's share of the Eklutna Hydroelectric Plant. This balance will be amortized over the estimated life of the facility. During the transition phase and after the transfer of ownership, Chugach, MEA and AML&P have jointly operated the facility. Each participant contributes their proportionate share for operations and maintenance costs. Under net billing arrangements, Chugach then reimburses MEA for their share of the costs. (15) Commitments and Contingencies Contingencies The Association is a participant in various legal actions, rate disputes, personnel matters and claims both for and against its interests. Management believes that the outcome of any such matters will not materially impact the Association's financial condition, results of operations or liquidity. Long-Term Fuel Supply Contracts The Association has entered into long-term fuel supply contracts from various producers at market terms. The current contracts will expire in 15 to 20 years. Significant Customers The Association is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts represented $45.2 million or 28.5% of operating revenues in 2000, and will expire in 2014. Cooper Lake Hydroelectric Plant The Association discovered polychlorinated biphenyls ("PCBs") in paint, caulk and grease at the Cooper Lake Hydroelectric plant during initial phases of a turbine overhaul. The Association is implementing a plan approved by the Environmental Protection Agency to remediate the PCBs in the plant. The Association is also conducting an investigation to determine whether any PCBs released from the plant are present in Kenai Lake. The Association does not have an estimate at this time of the potential costs involved in the investigation and we do not know whether any additional remediation will be required. Management believes costs of this endeavor will be recoverable through rates and therefore will have no material impact on the financial condition or results of operations. Regulatory Cost Charge In 1992 the State of Alaska Legislature passed legislation authorizing the Department of Revenue to collect a regulatory cost charge from utilities in order to fund the APUC. The tax is assessed on all retail consumers and is based on kilowatt hour (kWh) consumption. The Regulatory Cost Charge has decreased since its inception (November 1992) from an initial rate of $.000626 per kWh to the current rate of $.000318, effective October 1, 2000. (16) Segment Reporting The Association had divided its operations into two reportable segments: Energy and Internet service. The energy segment derives its revenues from sales of electricity to residential, commercial and wholesale customers, while the Internet segment derives its revenues from provision of residential and commercial internet services and products. The reporting segments follow the same accounting policies used for the Association's financial statements and described in the summary of significant accounting policies. Management evaluates a segment's performance based upon profit or loss from operations. Jointly used assets are allocated by percentage of reportable segment usage and centrally incurred costs are allocated using factors developed by the Association, which are patterned upon usage. The Internet segment began operations during 1998, the results of which are immaterial to the financial statements. The following is a tabulation of business segment information for the years ended December 31: Operating Revenues 2000 1999 ------------------ ---- ---- Internet $1,170,448 $374,296 Energy 157,370,666 142,270,031 ----------- ----------- Total operating revenues 158,541,114 142,644,327 =========== =========== Assignable Margins Internet (1,505,518) (1,293,388) Energy 11,185,296 10,960,822 ---------- ---------- Total assignable margins 9,679,778 9,667,434 ========= ========= Assets Internet 550,275 564,477 Energy 539,195,705 517,791,060 ----------- ----------- Total assets 539,745,980 518,355,537 =========== =========== Capital Expenditures Internet 163,565 508,082 Energy 46,572,794 41,356,746 ---------- ---------- Total capital expenditures 46,736,359 41,864,828 ========== ========== (17) Sale of Segment On March 6, 2001, the Association entered into an agreement to sell substantially all the assets and customers of the Internet business segment to an unrelated third party. The transaction is expected to result in a nominal gain. (18) Quarterly Results of Operations (unaudited) -------------------------------- 2000 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 ------- -------- ------- -------- Operating Revenue $44,282,842 $37,201,515 $36,185,683 $40,871,074 Operating Expense 36,351,256 31,192,307 29,183,255 29,703,456 Net Interest 6,384,593 6,078,364 6,114,471 6,140,861 --------- --------- --------- --------- Net Operating Margins 1,546,993 (69,156) 887,957 5,026,757 Non-Operating Margins 1,450,456 220,261 267,174 349,336 --------- ---------- ---------- ---------- Assignable Margins $2,997,449 $ 151,105 $1,155,131 $5,376,093 ========== ========= ========== ========== 1999 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 ------- -------- ------- -------- Operating Revenue $38,837,034 $32,075,076 $32,307,980 $39,424,237 Operating Expense 30,637,296 26,163,772 27,033,946 26,621,873 Net Interest 6,148,973 5,905,993 5,949,006 6,131,408 --------- --------- --------- --------- Net Operating Margins 2,050,765 5,311 (674,972) 6,670,956 Non-Operating Margins 1,090,556 199,106 170,377 155,335 --------- --------- --------- --------- Assignable Margins $3,141,321 $ 204,417 $(504,595) $6,826,291 ========== ========= ========== ==========
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None PART III Item 10 - Directors and Executive Officers of the Registrant Management We operate under the direction of a Board of Directors that is elected at large by our membership. Day-to-day business and affairs are administered by the General Manager. Our seven-member Board of Directors sets policy and provides direction to our General Manager. The following table sets forth certain information with respect to our executive officers and directors. Name Age Position Eugene N. Bjornstad......................... 62 General Manager Lee D. Thibert.............................. 45 Executive Manager,Transmission and Distribution Network Services Evan J. Griffith............................ 59 Executive Manager, Finance and Energy Supply William R. Stewart.......................... 54 Executive Manager, Retail Services Pat Jasper.................................. 72 President and Director Christopher Birch........................... 50 Vice President and Director Bruce Davison............................... 53 Secretary and Director Mary Minder................................. 61 Treasurer and Director Elizabeth ("Pat") Kennedy................... 62 Director Jeffrey W. Lipscomb......................... 50 Director H. A. ("Red") Boucher....................... 80 Director
Executive Officers Eugene N. Bjornstad was appointed our General Manager on June 22, 1994. Prior to that he served as Acting General Manager from March 28, 1994, until his permanent appointment. He joined Chugach in 1983 and served as Executive Manager, Operating Divisions from 1988 to 1994. Lee D. Thibert, in a reorganization on June 1, 1997, was appointed our Executive Manager, Transmission & Distribution Network Services. Prior to that he was Executive Manager, Operating Divisions from June of 1994. Before moving up to the Executive Manager position, he served as Director of Operations from May 1987. Evan J. Griffith has been our Executive Manager, Finance and Energy Supply since our internal reorganization on June 1, 1997. Prior to that, he was Executive Manager, Finance & Planning from August 1989 to June 1997. Prior to coming to us, he was Budget/Program Analyst for the Anchorage Municipal Assembly from August 1984 to August 1989. William R. Stewart has been our Executive Manager, Retail Services since the June 1, 1997 reorganization. Prior to that, he was our Executive Manager, Administration from July 1987 to June 1, 1997. He was our Division Director of Administration from January 1984 to July 1987 and Staff Assistant to the General Manager of Chugach from November 1982 to January 1984. He has been employed by us since 1969. Board of Directors Pat Jasper has served as the President of the Board since April 2000. Ms. Jasper was originally elected to the Board in April 1995. Since 1995, she has held several offices including Secretary, Vice President and President. She is a small business owner and has been a computer programmer and systems analyst. Pat Kennedy serves as Vice President of the Board. Ms. Kennedy has served on the board since 1993 and has served as both Secretary and President before holding her current position. She is an attorney who has been licensed to practice law since 1976 and has been in private practice since 1990. Bruce Davison has served as the Secretary of the Board since April 1998. Mr. Davison was first appointed to the Board of Directors in June 1997. Prior to his appointment, he served two years on the Chugach Bylaws Committee. He is a partner in the law firm of Davison & Davison, Inc. Mary Minder has been the Treasurer since April 1997. Ms. Minder was elected to the Board in April 1995 and since then has served as both Treasurer and Secretary. She is a realtor and associate real estate broker. Chris Birch was appointed to fill a Board vacancy in October 1996. Mr. Birch was elected to that seat in April 1997 and since that time has served as a director. He has previously served as Secretary and President. He is a professional engineer for the Alaska Department of Transportation and Public Facilities. Red Boucher was elected to the Board in April 1999. In addition to being a director, Mr. Boucher owns a consulting firm, serves as president of a telecommunication firm and hosts a weekly statewide TV show. He has held many elected offices including Lieutenant Governor of Alaska. Jeff Lipscomb is the newest member of the Board and was elected director in April 2000. Mr. Lipscomb is the principal of JWL Engineering which he founded in 1995. He is a professional civil engineer with over 20 years of experience in Alaskan oil and gas production facility design. Item 11 - Executive Compensation Cash Compensation .........The following table sets forth all remuneration paid by us for the last three years to each of our four executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2000, and for all such executive officers as a group: Name Principal Position Year Salary Bonus Total Eugene N. Bjornstad General Manager 2000 $230,074 $ 01 $230,074 1999 $168,057 $ 36,891 $204,948 1998 $166,427 $ 33,996 $200,423 Lee D. Thibert Executive Manager, 2000 $131,710 $ 01 $131,710 Transmission & 1999 $123,390 $ 12,757 $136,147 Distribution Network Services 1998 $125,880 $ 0 $125,880 Evan J. Griffith Executive Manager, 2000 $131,657 $ 01 $131,657 Finance & Energy Supply 1999 $135,140 $ 12,757 $147,897 1998 $131,634 $ 3,300 $134,934 William R. Stewart Executive Manager, 2000 $134,398 $ 01 $134,398 Retail Services 1999 $137,376 $ 12,757 $150,133 1998 $140,193 $ 3,300 $143,493
1Year 2000 bonuses have not been granted. Our directors are compensated for their services in the amount of $100 per board meeting attended (including committee meetings) up to a maximum of seventy meetings per year for a director and eighty-five meetings per year for the President. Upon termination, Mr. Bjornstad's employment agreement provides that he may receive an amount equal to his salary for the greater of six months or remaining term of his employment agreement (which number shall not be less than six months) plus any accrued annual leave or other compensation then due as of the effective date of the notice of termination. Compensation Pursuant to Plans We have elected to participate in the National Rural Electric Cooperative Association ("NRECA") Retirement and Security Program (the "Plan"), a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. The Plan is intended to be a qualified pension plan under Section 401(a) of the Code. All our employees not covered by a union agreement become participants in the Plan on the first day of the month following completion of one year of eligibility service. An employee is credited with one year of eligibility service if he completes 1,000 hours of service either in his first twelve consecutive months of employment or in any calendar year for Chugach or certain other employers in rural electrification (related employers). Pension benefits vest at the rate of 10% for each of the first four years of vesting service and become fully vested and nonforfeitable on the earlier of the date a participant has five years of vesting service or the date the participant attains age fifty-five while employed by us or a related employer. A participant is credited with one year of vesting service for each calendar year in which he performs at least one hour of service for us or a related employer. Pension benefits are generally paid upon the participant's retirement or death. A participant may also elect to receive pension benefits while still employed by us if he has reached his normal retirement date by completing thirty years of benefit service (as hereinafter defined) or, if earlier, by attaining age sixty-two. A participant may elect to receive actuarially reduced early retirement pension benefits before his normal retirement date provided he has attained age fifty-five. Pension benefits paid in normal form are paid monthly for the remaining lifetime of the participant. Unless an actuarially equivalent optional form of benefit payment to the participant is elected, upon the death of a participant the participant's surviving spouse will receive pension benefits for life equal to 50% of the participant's benefit. The annual amount of a participant's pension benefit and the resulting monthly payments the participant receives under the normal form of payment are based on the number of his years of participation in the Plan (benefit service) and the highest five-year average of the annual rate of his base salary during the last ten years of his participation in the Plan (final average salary). Annual compensation in excess of $200,000, as adjusted by the Internal Revenue Service for cost of living increases, is disregarded after January 1, 1989. The participant's annual pension benefit at his normal retirement date is equal to the product of his years of benefit service (up to thirty) times final average salary times 2%. In 1998, NRECA notified us that there were employees whose pension benefits from NRECA's Retirement & Security Program would be reduced because of limitations on retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA made available a Pension Restoration Severance Pay Plan and a Pension Restoration Deferred Compensation Plan for cooperatives to adopt in order to make employees whole for their lost benefits. In May 1998, we adopted both of these plans to protect the benefits of current and future employees whose pension benefits would be reduced because of these limitations. The following table sets forth the estimated annual pension benefit payable at normal retirement date for participants in the specified final average salary and years of benefit service categories: Final Average Salary Years of Benefit Service 15 20 25 30+ -- -- -- --- $125,000 $37,500 $50,000 $62,500 $75,000 $150,000 $45,000 $60,000 $75,000 $90,000 The annual pension benefits indicated above are the joint and surviving spouse life annuity amounts payable by the Plan, and they are not subject to any deduction for Social Security or other offset amounts. Benefit service as of December 31, 2000 taken into account under the Plan for the executive officers is shown below. Base salary for 2000 taken into account under the Plan for purposes of determining final average salary is also included. Name Principal Position Benefit Service Covered Compensation Eugene N. Bjornstad........... General Manager 16.7 $165,027 Lee D. Thibert................ Executive Manager, Transmission 12.7 $130,790 & Distribution Network ServicesE Evan J. Griffith.............. Executive Manager, Finance & 10.4 $130,166 Energy Supply William R. Stewart............ Executive Manager, Retail 30.0 $130,187 Services
Item 12 - Security Ownership of Certain Beneficial Owners and Management Not Applicable Item 13 - Certain Relationships and Related Transactions Not Applicable PART IV Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K Page Financial Statements Included in Part IV of this Report: Independent Auditors' Report 28 Balance Sheets, December 31, 2000 and 1999 29-30 Statements of Revenues, Expenses and Patronage Capital, Years ended December 31, 2000, 1999 and 1998 31 Statements of Cash Flows, Years ended December 31, 2000, 1999 and 1998 32 Notes to Financial Statements 33-50 Financial Statement Schedules Included in Part IV of this Report: Schedule II - Valuation and Qualifying Accounts, Years ended December 31, 2000, 1999 and 1998 57 Other schedules are omitted as they are not required or are not applicable, or the required information is shown in the applicable financial statements or notes thereto. Schedule II CHUGACH ELECTRIC ASSOCIATION, INC. Valuation and Qualifying Accounts Balance at Charged Balance Beginning To costs at end of year And expenses Deductions of year ------- ------------- ---------- ------- Allowance for doubtful accounts: Activity for year ended: December 31, 2000 $(389,223) $(373,666) $320,956 $(441,933) December 31, 1999 (447,908) (331,895) 390,580 (389,223) December 31, 1998 (368,029) (407,825) 327,946 (447,908)
EXHIBITS Listed below are the exhibits which are filed as part of this Report: Exhibit Number Description (7) 3.1 Articles of Incorporation of the Registrant. (9) 3.2 Bylaws of the Registrant. (1) 4.1 Trust Indenture between the Registrant and Security Pacific Bank Washington, N.A. dated as of September 15, 1991 (including forms of bonds). (1) 4.2 First Supplemental Indenture of Trust between the Registrant and Seattle-First National Bank dated March 17, 1993. (1) 4.3 Second Supplemental Indenture of Trust between the Registrant and Seattle First National Bank dated May 19, 1994. (1) 4.4 Third Supplemental Indenture of Trust between the Registrant and Seattle First National Bank dated June 29, 1994. (1) 4.5 Fourth Supplemental Indenture of Trust between the Registrant and Seattle-First National Bank dated March 1, 1995. (1) 4.6 Fifth Supplemental Indenture of Trust between the Registrant and Seattle-First National Bank dated September 6, 1995. (1) 4.7 Sixth Supplemental Indenture of Trust between the Registrant and Seattle-First National Bank dated April 3, 1996. (2) 4.8 Seventh Supplemental Indenture of Trust between the Registrant and Seattle-First National Bank dated June 1, 1997. (4) 4.9 Eighth Supplemental Indenture of Trust between the Registrant and Security Pacific Bank Washington, N.A. dated February 4, 1998. (9) 4.10 Ninth Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association dated April 25, 2000. 4.13 Form of Debt Security (included in Exhibit 4.1). (1) 10.1 Wholesale Power Agreement between the Registrant and the City of Seward. (1) 10.2 Joint Use Agreement between the Registrant and the City of Seward dated effective as of September 11, 1998. (1) 10.3 Net Billing Agreement among the Registrant and the City of Seward dated effective as of September 11, 1998. (8) 10.4 Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective as of September 11, 1998. (1) 10.5 Agreement for Sale of Electric Power and Energy by and among the Registrant, Homer Electric Association,Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated September 27, 1985. (1) 10.6 Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of January 30, 1989. (1) 10.6.1 First Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of February 10, 1995. (1) 10.6.2 Net Billing Agreement by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 16, 1987. (1) 10.7 Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc. dated May 18, 1988. (11)10.7.1 Amendatory Agreement No. 1 to Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc., dated December 14, 1989. (11)10.7.2 Letter Agreement dated January 18, 1996 between the Registrant and Golden Valley Electric Association, Inc., amending the Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc. (11)10.7.3 Amendatory Agreement No. 2 to Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc., dated February 8, 1999. (11)10.7.4 Settlement Agreement by and among the Registrant, Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Anchorage Municipal Light and Power dated May 6, 1999. (1) 10.8 Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. dated April 21, 1989. (1) 10.8.1 Amendment No. 1 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc., dated August 1, 1990. (11)10.8.2 Letter Agreement dated April 23, 1999, regarding the Registrant's consent to the assignment to ARCO Beluga, Inc. of the Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. (8) 10.8.3 Amendment No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Beluga, Inc., dated May 6, 1999. (1) 10.9 Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and ARCO Alaska, Inc. dated October 3, 1991. (1) 10.10 Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company dated September 26, 1988. (1) 10.10.1 Letter Agreement dated September 26, 1988 between the Registrant and Marathon Oil Company, amending the Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company. (1) 10.10.2 Amendatory Agreement No. 1 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated effective as of February 21, 1990. (1) 10.10.3 Amendatory Agreement No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated effective as of February 21, 1990. (1) 10.10.4 Amendatory Agreement No. 3 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated January 28, 1991. (11)10.10.5 Amendatory Agreement No. 4 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated October 6, 1993. (11)10.10.6 Letter Agreement dated January 18, 1996 between the Registrant and Marathon Oil Company, amending the Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company. (8) 10.10.7 Amendatory Agreement No. 5 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated May 24, 1999. (1) 10.11 Agreement for the Sale and Purchase of Natural Gas between the Registrant and Shell Western E&P Inc. dated April 25, 1989. (1) 10.11.1 Amendatory Agreement No. 1 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc., dated October 1, 1989. (1) 10.11.2 Amendment No. 2 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc., dated June 20, 1990. (1) 10.11.3 Amendatory Agreement No. 3 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc. dated October 14, 1996. (1) 10.12 Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Shell Western E&P Inc. dated November 2, 1990. (1) 10.13 Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron USA Inc. dated April 27, 1989 (including Attachment No. 1 thereto dated December 20, 1989). (1) 10.13.2 Amendment No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron USA Inc., dated June 7, 1990. (8) 10.13.3 Amendment No. 3 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron U.S.A. Inc., dated May 26, 1999. (1) 10.14 Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Chevron USA, Inc. dated September 25, 1990. (1) 10.15 Alaska Intertie Agreement between Alaska Power Authority, Municipality of Anchorage, the Registrant, City of Fairbanks, Alaska Municipal Utilities System, Golden Valley Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 23, 1985. (1) 10.16 Addendum No. 1 to the Alaska Intertie Agreement-Reserve Capacity and Operating Reserve Responsibility dated December 23, 1985. (1) 10.17 Memorandum of Understanding Regarding Intertie Upgrades among Alaska Energy Authority, the Registrant, Golden Valley Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power, and the City of Seward d/b/a Seward Electric System dated March 21, 1990. (11)10.18 Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. (1) 10.19 Intertie Grant Agreement between the Registrant, Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Matanuska Electric Association, Inc. and Homer Electric Association, Inc.), City of Seward, the State of Alaska, Department of Administration and Alaska Industrial Development and Export Authority dated August 17, 1993. (1) 10.20 Grant Transfer and Delegation Agreement between the Registrant and Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc., Matanuska Electric Association, Inc., Homer Electric Association, Inc., Seward, the State of Alaska, Department of Administration, and AMEA dated November 5, 1993. (11)10.21 1993 Alaska Intertie Project Participants Agreement by and among Alaska Power Authority, Municipality of Anchorage, the Registrant, City of Fairbanks, Alaska Municipal Utilities System, Golden Valley Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., City of Seward d/b/a Seward Electric System, Homer Electric Association, Inc. and Matanuska Electric Association, Inc. dated January 24, 1994. (11)10.22 Amendment No. 1 to the 1993 Alaska Intertie Project Participants Agreement dated December 10, 1999. (11)10.23 Grant Administration Agreement by and among the Registrant, Alaska Industrial Development and Export Authority, Golden Valley Electric Association, Inc., Fairbanks Municipal Utilities System, Anchorage Municipal Light & Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Homer Electric Association, Inc. and Matanuska Electric Association, Inc.) and City of Seward dated August 30, 1994. (1) 10.24 Bradley Lake Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated December 8, 1987. (1) 10.25 Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 8, 1987. (1) 10.26 Transmission Sharing Agreement by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power. (1) 10.27 Amendment to Agreement for Sale of Transmission Capability by and among the Registrant, Homer Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power dated March 7, 1989. (1) 10.28 Bradley Lake Hydroelectric Agreement for the Dispatch of Electric Power and for Related Services between the Registrant and the Alaska Energy Authority dated February 19, 1992. (1) 10.29 Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated September 29, 1992. (1) 10.30 Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated December 2, 1983. (1) 10.30.1 Addendum No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated August 8, 1984. (1) 10.30.2 Amendment No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated November 28, 1984. (1) 10.31 Gas Transportation Agreement by and among the Registrant, Alaska Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992. (1) 10.32 Eklutna Purchase Agreement by and among the Registrant, Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power and Alaska Power Administration. (3) 10.33 Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. (1) 10.34 Settlement Agreement by and among the Registrant, Homer Electric Association, Inc., Matanuska Electric Association, Inc., the City of Seward and Alaska Electric Generation and Transmission Cooperative, Inc., resolving G&T TIER Level, Equity Level, Capital Credits, Equity Management Plan and Loan Covenant Disputes, dated effective as of February 3, 1993. (1) 10.35 First Amendment to "Settlement Agreement Resolving G&T TIER Level, Equity Level, Capital Credits, Equity Management Plan and Loan Covenant Disputes" in APUC Docket U-92-10 between the Registrant, Matanuska Electric Association, Inc., Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated March 1993. (1) 10.36 Agreement by and among the Registrant, Municipality of Anchorage d/b/a Anchorage Municipal Light and Power, Matanuska Electric Association, Inc., U.S. Fish and Wildlife Service, National Marine Fisheries Service, Alaska Energy Authority and the State of Alaska re: the Eklutna and Snettisham Hydroelectric Projects. (1) 10.37 Daves Creek Substation Agreement between the Registrant and the Alaska Energy Authority dated March 13, 1992. (1) 10.38 Settlement Agreement between the Registrant and Intervenor Wholesale Customers in APUC Docket U-93-15 dated September 1993 regarding depreciation of submarine cables. (8) 10.39 Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated February 12, 1999. (1) 10.40 Lease Amendment between the Registrant and Standard Oil Company of California dated June 1, 1975. (1) 10.41 Lease Amendment between the Registrant and Chevron USA, Inc. dated September 1, 1985. (1) 10.42 Loan Agreement between the Registrant and the National Bank for Cooperatives (formerly Spokane Bank for Cooperatives), as amended. (1) 10.43 Amendment to Loan Agreement between the Registrant and the National Bank for Cooperatives dated September 13, 1991. (1) 10.44 Twenty Five Million Dollar Line of Credit Agreement and Promissory Note between the Registrant and the National Bank for Cooperatives. (1) 10.44.1 Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated March 11, 1994. (1) 10.44.2 Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives and amended and restated Promissory Note (thirty-five million dollars) dated April 18, 1994. (1) 10.44.3 Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives (thirty-five million dollars) dated May 1, 1995. (1) 10.44.4 Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives (thirty-five million dollars) dated May 15, 1995. (10)10.44.5 Amendment to Line of Credit Agreement between the Registrant and CoBank, ACB dated September 30, 2000. (2) 10.45 National Bank for Cooperatives (CoBank) Credit Agreement dated June 22, 1994. (2) 10.46 Amendment No. 1 to National Bank for Cooperatives (CoBank) Credit Agreement, dated June 1, 1997. (3) 10.47 Fifty Million Dollar Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 22, 1997. (6) 10.48 International Swap Dealers Association, Inc. Master Agreement between the Registrant and Lehman Brothers Financial Products Inc. dated March 17, 1999. (7) 10.49 Confirmation for U.S. dollar Treasury rate-lock transaction to be subject to 1992 Master Agreement between the Registrant and Lehman Brothers Financial Products Inc. dated March 17, 1999. (1) 10.50 Employment Agreement between the Registrant and Eugene N. Bjornstad dated July 6, 1994. (4) 10.51 Amendment to Employment Agreement by and among the Registrant and Eugene N. Bjornstad dated February 25, 1998. (5) 10.52 Settlement Agreement by and among the Registrant, Nationwide Mutual Insurance Company, Alaska National Insurance Company, Providence Washington Insurance Company and Admiral Insurance Company dated May 15, 1998. (11) 12.1 Statement regarding computation of ratios. (1) Previously referred to in the Registrant's Annual Report on Form 10-K dated December 31, 1996. (2) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated September 30, 1997. (3) Previously filed as an exhibit to the Registrant's Annual Report on Form 10-K dated December 31, 1997. (4) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated March 31, 1998. (5) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated June 30, 1998. (6) Previously filed as an exhibit to the Registrant's Annual Report on Form 10-K dated December 31, 1998. (7) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated March 31, 1999. (8) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated June 30, 1999. (9) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated March 31, 2000. (10)Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated September 30, 2000. (11)Previously filed as an exhibit to the Registrant's Registration Statement on Form S-1 dated March 22, 2001. REPORTS ON FORM 8-K The Company was not required to file any report on Form 8K for the year ended December 31, 2000. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 30, 2001. CHUGACH ELECTRIC ASSOCIATION, INC. By: /s/ Eugene N. Bjornstad Eugene N. Bjornstad, General Manager Date: March 30, 2001 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated March 30, 2001: /s/ Eugene N. Bjornstad Eugene N. Bjornstad General Manager /s/ Lee D. Thibert Lee D. Thibert Executive Manager, T&D Network Services /s/ Evan J. Griffith Evan J. Griffith Executive Manager, Finance & Energy Supply (Principal Financial officer) /s/ William R. Stewart William R. Stewart Executive Manager, Retail Services /s/ Michael R. Cunningham Michael R. Cunningham Controller (Principal Accounting officer) /s/ Patricia B. Jasper Patricia B. Jasper President (Principal Executive Officer & Director) /s/ Elizabeth Page Kennedy Elizabeth Page Kennedy Director & Vice President /s/ Bruce Davison Bruce Davison Director & Secretary /s/ Mary Minder Mary Minder Director & Treasurer /s/ H.A. Boucher H.A. Boucher Director /s/ Christopher Birch Christopher Birch Director /s/ Jeffrey Lipscomb Jeffrey Lipscomb Director Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the Act by registrants which have not registered securities pursuant to Section 12, of the Act: Chugach has not made an Annual Report to securities holders for 2000 and will not make such a report after the filing of this Form 10-K. As a consequence, no copies of any such report will be furnished to the Securities and Exchange Commission. -----END PRIVACY-ENHANCED MESSAGE-----