-----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, Qow37Jn8yxUp1TktkxX7i4yuxBnIGxu2Eju+E805Qrhn1MWVT1sNo3eNqR3KCU9Y LpfBjnirolTGkXL+mXvS1w== 0000878004-05-000005.txt : 20050331 0000878004-05-000005.hdr.sgml : 20050331 20050331170251 ACCESSION NUMBER: 0000878004-05-000005 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20041231 FILED AS OF DATE: 20050331 DATE AS OF CHANGE: 20050331 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: 1934 Act SEC FILE NUMBER: 033-42125 FILM NUMBER: 05721438 BUSINESS ADDRESS: STREET 1: 5601 MINNESOTA DR STREET 2: PO BOX 196300 CITY: ANCHORAGE STATE: AK ZIP: 99518 BUSINESS PHONE: 9075637494 10-K 1 sec200410k.txt FORM 10K 2004 UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10K (Mark One) X ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2004 ----------------- or 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 (I.R.S. Employer incorporation or organization) Identification No.) 5601 Electron Dr., 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 registrant (1) has filed reports required to be filed by Section 13 or 15(d) of the Securities 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 Registration S-K (Section 229.405 of this chapter) 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 Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act) __ Yes X No State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. N/A CHUGACH ELECTRIC ASSOCIATION, INC. 2004 Form 10-K Annual Report Table of Contents PART I Page Item 1 - Business 1 Item 2 - Properties 8 Item 3 - Legal Proceedings 16 Item 4 - Submission of Matters to a Vote of Security Holders 17 PART II Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters 17 Item 6 - Selected Financial Data 18 Item 7 - Management's Discussion and Analysis of Financial Condition 19 and Results of Operations Item 7A - Quantitative and Qualitative Disclosures About Market Risk 35 Item 8 - Financial Statements and Supplementary Data 37 Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 65 Item 9A - Disclosure Controls and Procedures 65 Item 9B - Other Items 65 PART III Item 10 - Directors and Executive Officers of the Registrant 66 Item 11 - Executive Compensation 69 Item 12 - Security Ownership of Certain Beneficial Owners and Management 72 Item 13 - Certain Relationships and Related Transactions 72 Item 14 - Principal Accountant Fees and Services 72 PART IV Item 15 - Exhibits and Financial Statement Schedules 73 SIGNATURES 86 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) 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 was organized as an Alaska electric cooperative in 1948. Cooperatives are business organizations that are owned by their members. As not-for-profit organizations (Internal Revenue Code 501 (c)(12), 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 other than for reasonable reserves and margins. 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. Chugach makes its current and periodic reports available, free of charge, on its website at www.chugachelectric.com as soon as practicable after filing with the Securities and Exchange Commission (SEC). Our website provides a link to the SEC website. Chugach is the largest electric utility in Alaska. We are engaged in the generation, transmission and distribution of electricity to approximately 75,500 active 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 Chugach nor any other electric utility in Alaska has any connection to the electric grid of the mainland United States or Canada. Chugach is 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 currently collect a regulatory cost charge of $.000397 per kWh of retail electricity sold. This charge is assessed to fund the operations of the Regulatory Commission of Alaska (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, 2006. We also have an agreement with Hotel Employees, Restaurant Employees (HERE), Local 878 in effect through June 30, 2006. We believe our relationship with our employees is good. 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 approximately 30,000 meters. Our members are the consumers of the electricity sold by us. As of December 31, 2004, we had 62,684 retail members receiving service at approximately 75,500 active metered locations and three major wholesale customers. No individual retail customer receives more than 5% of our power. Our customers are billed per a tariff rate on a monthly basis for electrical power consumed during the preceding period. Billing rates are approved by the RCA (see "Rate Regulation and Rates" below). Rates (derived on the basis of historic cost of service) are established to generate revenues in excess of current period costs 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 have 530 megawatts of installed generating capacity provided by 17 generating units at our five owned power plants: Beluga Power Plant, Bernice Lake Power Plant, International Generation and Transmission Power Plant (IGT), Cooper Lake Hydroelectric Plant and Eklutna Hydroelectric Project, in which we own a 30% interest. Approximately 84% (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 2004, approximately 86% of our energy was generated at the Beluga facility. The Bradley Lake Hydroelectric Project provides up to 27.4 megawatts for our retail customers and up to 38.6 megawatts for our wholesale customers. We also purchase approximately 40 megawatts from the Nikiski power plant on the Kenai Peninsula. We operate 1,645 miles of distribution line and 402 miles of transmission line. For the year ended December 31, 2004, we sold 2.6 billion kilowatt hours (kWh) of electrical power. Customer Revenue From Sales 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, 2004:
Percent of Revenue MWh 2004 Revenues from Sales Direct retail sales: Residential.................... 571,320 $65,651,405 33% Commercial..................... 653,729 59,085,360 30% ------- ---------- --- Total.......................... 1,225,049 124,736,765 63% Wholesale sales: MEA............................ 658,208 37,164,894 19% HEA............................ 477,256 24,790,344 12% Seward......................... 62,176 2,850,001 1% ------ --------- -- Total.......................... 1,197,640 64,805,239 32% Economy energy sales(1) ............ 206,835 8,867,625 5% ------- --------- Total revenue from sales............ 2,629,524 198,409,629 100% ========= ==== Miscellaneous energy revenue 2,836,986 --------- Total energy revenues $201,246,615 ============ (1) Economy sales were made to Golden Valley Electric Association (GVEA) and AML&P.
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 the Glenn Highway on the north. Customers As of December 31, 2004, we had 62,684 members being served by approximately 74,750 meters (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 HEA under separate wholesale power contracts. For 2004, our wholesale power contracts, including the fuel component, produced $64.8 million in revenues, representing 32% of our total revenues and 46% of our total sales to customers. MEA and HEA We have two power sales contracts with Alaska Electric Generation & Transmission Cooperative, Inc., (AEG&T): one for firm, all-requirement sales to MEA and one for firm, partial- requirement sales to HEA. AEG&T is a generation and transmission cooperative that was formed by MEA and HEA in the mid 1980's. Under each of these contracts, we sold power to AEG&T, for resale to MEA and HEA. On June 19, 2002, the RCA approved the request by Alaska Electric and Energy Cooperative, Inc. (AEEC) and AEG&T to Transfer Certificate of Public Convenience and Necessity No. 345 to serve as the power supplier of HEA to AEEC, instead of AEG&T. HEA is the sole member of AEEC. As part of this transaction our power sales agreement was assigned to AEEC and the Nikiski dispatch agreement was assigned to HEA with certain exceptions with the remaining rights and obligations under the Dispatch Agreement being assigned to AEEC. Management has not experienced a decline in revenue as a result of this transfer. Under our contracts, each of MEA and HEA is obligated to pay us for the power sold to AEG&T and AEEC even if AEG&T and AEEC do not pay. Under the contract with AEG&T and MEA, MEA is obligated to purchase all of its electric power and energy requirements from us. 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. MEA has not invoked this right at this time. If MEA converts to a net-requirements purchaser under the contract, MEA cannot reduce its payment for power that it purchases from us below a certain minimum amount. MEA will be required to pay demand charges based upon the highest post-1985 historical coincident peak on the MEA system. Therefore, if MEA converts to net-requirements service, we will continue to recover all or substantially all of the fixed costs now assigned to it. 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 after 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. Chugach and MEA met on October 27, 2004, pursuant to Section 12(c) of the MEA/Chugach Power Sales Agreement. This provision requires the parties to meet no later than ten years prior to the termination date of the Agreement, to discuss a possible renewal, extension, or modification of the Agreement, as well as the desires and potential circumstances of all parties following the termination date. At that meeting and shortly thereafter by letter dated November 2, 2004, MEA communicated to Chugach that MEA does not desire to renew, extend or modify the Agreement. Further, MEA stated that it does not envision any type of firm power purchase arrangement with Chugach following expiration of the Agreement on December 31, 2014. MEA assured Chugach that it intends to continue to purchase power from Chugach in accordance with the Agreement through December 31, 2014. 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 a discussion of material pending litigation between MEA and us, see "Legal Proceedings." Our contract for the benefit of HEA obligates HEA (through AEEC) to take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per year. The HEA contract, as interpreted by the Alaska Public Utilities Commission (APUC), limits the costs that may be included in our rates charged to HEA. The HEA contract expires on January 1, 2014. HEA's remaining resource requirements are provided by AEEC's Nikiski cogeneration facility and AEEC's contract rights to receive power from the Bradley Lake hydroelectric project for the benefit of HEA. 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 AEEC and HEA, we will sell energy to AEG&T equal to HEA'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 HEA needs in excess of the sum of our contract demand plus HEA's share of energy from the Bradley Lake project. The dispatch agreement will terminate in 2014 when our power supply contract for the benefit of HEA terminates. 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, not to exceed seventy-two cumulative hours annually and thereby reduces the demand charge by 1/3 (approximately $350,000 annually). This agreement expires January 31, 2006. Economy Customers Since 1988, we have sold economy (nonfirm) energy to 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 it would otherwise generate itself or purchase from other sources. We purchased gas 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 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. 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 a contractual priority right under our agreement with GVEA. Under this provision, if GVEA requires non-firm energy in sufficient quantities, we have an opportunity to sell two-thirds of the first 450,000 MWh and an additional 80% of the excess over 450,000 MWh of the non-firm energy that GVEA purchases each year if we are capable of producing that energy. Under the above provisions, non-firm sales to GVEA have been 206,451 MWh, 191,616 MWh and 125,462 MWh for the years 2004, 2003 and 2002, respectively. No seller enjoys a contractual priority in making such sales. GVEA makes purchases from the seller offering the lowest competitive price. Rate Regulation and Rates The RCA regulates our rates. We can seek changes in our base rates by filing general rate cases with the RCA. On August 10, 2002, A.S. 42.05.175 imposed timelines for RCA decisions. Among other provisions, it provided that for all dockets commenced on or after July 1, 2002, the RCA shall issue a final order not later than 15 months after a complete tariff filing is made for a tariff filing that changes the utility's revenue requirement or rate design. 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 retail and wholesale rates, subject to appeal to the Alaska courts. 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. Under Alaska law, a cooperative utility that is negotiating to enter into a mortgage or other debt instrument that provides for a Times Interest Earned Ratio (TIER) greater than the ratio the RCA most recently approved for that cooperative must submit the mortgage or debt instrument to the RCA before the instrument takes effect. The rate covenants contained in the instruments that govern our outstanding long-term indebtedness do not impose any greater TIER requirement than those previously approved by the RCA. We expect to 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 - Overview." The Amended and Restated Indenture, which became effective January 22, 2003, governs all of our outstanding bonds and requires us to set rates expected to yield margins for interest equal to at least 1.10 times total interest expense. The CoBank Master Loan Agreement also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. On February 6, 2003, we received Order U-01-108(26) from the RCA, based on our 2000 test year general rate case, that revised our overall TIER from 1.35 to 1.30. For the year ended December 31, 2004, our achieved TIER was calculated to be 1.35. Our Service Areas and Local Economy 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 located in the south central portion of Alaska and 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. Agrium, a producer and marketer of agricultural nutrients and industrial products, located on the Kenai Peninsula, may cease operations due to a reduction in the supply of natural gas. If Agrium is unable to obtain favorably-priced additional natural gas, Agrium may be forced to cease production at the Kenai facility. This loss could have a negative affect on the economy of the Kenai Peninsula. 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. 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. A major gold mine operates near Fairbanks; another is being developed. The Trans-Alaska Pipeline System (which transports crude oil) passes near Fairbanks on its route from the North Slope oilfield to Valdez. Alyeska Pipeline Company, which operates the Trans-Alaska oil pipeline from Prudhoe Bay to Valdez, has its main operations base in Fairbanks. Load Forecasts The following table sets forth our projected load forecasts for the next five years:
Load (MWh) 2005 2006 2007 2008 2009 ---------- ---- ---- ---- ---- ---- Retail............ 1,237,661 1,273,895 1,289,163 1,308,717 1,308,060 Wholesale......... 1,219,048 1,254,746 1,282,758 1,275,670 1,295,137 Economy........... 188,756 165,000 165,000 165,000 100,000 Losses............ 139,355 143,271 144,921 147,034 146,963 Total.......... 2,784,820 2,836,912 2,881,842 2,896,421 2,850,160 ========= ========= ========= ========= =========
Sales are expected to increase over the next five years principally due to economic growth resulting from increased federal and state spending. Our total energy requirements are expected to grow at an average annual compounded rate of 1.5% from 2005 to 2009, retail sales at a rate of 1.4% and wholesale sales at a rate of 1.5%. These projections are based on assumptions that management believes to be reasonable. If one or more of these assumptions proves inaccurate in light of actual events, our actual load requirements for one or more of the years could vary materially from the forecast. Item 2 - Properties General We have 530 megawatts of installed capacity consisting of 17 generating units at five power plants. These include 385.0 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 IGT in Anchorage; and 19.2 megawatts at the Cooper Lake facility, which is also on the Kenai Peninsula. We also own rights to 11.7 megawatts of capacity from the two Eklutna Hydroelectric Project generating units that we jointly own 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 HEA 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 IGT in Anchorage. We also lease warehouse space for some generation, transmission and distribution inventory (including a small amount of office space). Generation Assets We own the land and improvements comprising our generating facilities at Beluga and IGT. We also own all improvements comprising our generating plant at Bernice Lake, located on land leased from HEA. The Bernice Lake ground lease expires in 2011. We are in the process of reviewing the lease. We have no reason to believe that we will not be able to renew the lease if desired. The Cooper Lake Hydroelectric Project is partially located on federal land. Consequently, we must operate the Project pursuant to a major project license granted to us by the Federal Energy Regulatory Commission (FERC) in May 1957. The current license expires in 2007, so we are preparing an application for a new license for continued operation of the project in consultation with state and federal agencies, non-governmental organizations and interested public. We anticipate that the FERC will conduct its relicensing process in a manner that allows us to continue operation of the Project after 2007. 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 have a combined capacity of 345.8 MW and meet most of our load. All other units are used principally as reserve. While the Beluga turbine-generators have been in service for many years, they have been maintained in good working order with periodic upgrades. Beluga Unit 3 had combustion inspections performed in 2004 and 2003. Beluga Unit 5 also had combustion inspections in 2004 and 2003. Beluga Unit 6 had a combustion inspection performed in 2004. Its first major inspection since the unit was repowered in 2000 was performed in 2003. Its first major inspection after the unit was repowered in 2001 was performed on Beluga Unit 7 in 2004. A combustion inspection was performed on Unit 7 during 2003. Beluga Unit 8, a steam turbine, received routine annual inspections in 2004 and 2003. The following matrix depicts nomenclature, run hours for 2004 and percentages of contribution and other historical information for all Chugach generation units.
Percent of Commercial Operation Rating Run Hours Percent of Time Facility Date Nomenclature (MW)(1) (2004) Total Run Hours Available -------- ---- ------------ ------- ------ --------------- --------- Beluga Power Plant (3) 1 1968 GE Frame 5 19.6 556.7 1.04 90.4 2 1968 GE Frame 5 19.6 542.2 1.01 92.7 3 1972 GE Frame 7 64.8 6,692.5 12.49 94.8 5 1975 GE Frame 7 68.7 5,341.6 9.97 83.4 6 1975 AP 11DM-EV 79.2 8,176.4 15.26 93.1 7 1978 AP 11DM-EV 80.1 6,694.9 12.50 76.3 8 1981 BBC DK021150(2) 53.0 7,826.3 14.61 89.1 --------------- --------------- Bernice Lake 385.0 Power Plant 2 1971 GE Frame 5 19.0 4.4 0.01 99.82 3 1978 GE Frame 5 26.0 620.0 1.16 95.90 4 1981 GE Frame 5 22.5 1,194.4 2.23 96.21 --------------- --------------- Cooper Lake 67.5 Hydroelectric Plant 1 1960 BBC MV 230/10 9.6 7,379.4 13.78 87.16 2 1960 BBC MV 230/10 9.6 8,086.4 15.09 94.24 --------------- --------------- IGT Power Plant 19.2 1 1964 GE Frame 5 14.1 187.8 0.35 97.18 2 1965 GE Frame 5 14.1 267.3 0.50 95.12 3 1969 Westinghouse 191G 18.5 79.6 0.15 99.30 -------------- 46.7 Eklutna Hydroelectric Plant (4) 1 1955 Newport News 5.8 N/A(5) N/A(5) N/A5 2 1955 Oerlikon custom 5.9 N/A(5) N/A(5) N/A5 --------------- --------------- 11.7(6) System Total -------------- 53,570.3 100.00 530.10 =============== (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. (6) Represents Chugach's 30% share, 11.7 MW maximum Note: GE = General Electric, BBC = Brown Boveri Corporation, AP = Alstom Power
Transmission and Distribution Assets As of December 31, 2004, our transmission and distribution assets included 39 substations and 402 miles of transmission lines, 926 miles of overhead distribution lines and 719 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. As part of our 1997 acquisition of 30% of the Eklutna facility, 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 subject to 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 via easements and across public rights-of-way and waterways pursuant to authority granted by the appropriate governmental entity. Title Under the Amended and Restated Indenture, all of Chugach's bonds are general unsecured and unsubordinated obligations. Chugach is prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on our properties and assets (other than those arising by operation of law) to secure the repayment of borrowed money or the obligation to pay the deferred purchase price of property unless we equally and ratably secure all bonds subject to the Amended and Restated Indenture, except that we may incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements. 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 by additional minor title 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 Property 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 30.4% (27.4 megawatts as currently operated) 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. We are obligated to pay 30.4% of the annual project costs regardless of project output. 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 (AML&P, HEA and MEA (through AEG&T and AEEC), GVEA, Seward and us). 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). By contract, we also provide transmission and related services to 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 commercial operation of the facility (September, 1991) or when the revenue bond principal is repaid, whichever is the longer. The agreement may be renewed for successive forty-year periods or for the useful life of the project, whichever is shorter. We believe that our maximum annual liability for our take-or-pay obligations is approximately $4.7 million. We believe that so long as this project produces power taken by us for our use that this expense will be recoverable through the fuel surcharge mechanism. The share of Bradley Lake indebtedness for which we are responsible is approximately $41 million. 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 the defaulting participant to pay its share, provided that no participant's percentage share is increased by more than 25%. Eklutna. We purchased a 30% undivided interest in the Eklutna Hydroelectric Project from the federal government in 1997. MEA also owns 17% of 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 2004, 86% of our power was generated from gas, and 86% of that gas-fired generation took place at Beluga. Our primary sources of natural gas are the Beluga River Field producers (ConocoPhillips Alaska, Inc., AML&P, ChevronTexaco) and Marathon. ConocoPhillips, AML&P and ChevronTexaco each own one-third of the gas produced from the Beluga River Field and in 2004 provided approximately equal shares of the Beluga gas. We have approximately 285 billion cubic feet (BCF) of remaining gas committed to us from Marathon and the Beluga River Field producers (including Period 3 gas). We currently use approximately 25 BCF of natural gas per year for firm service. We estimate that our contract gas will last 7 to 12 years. Under almost all circumstances the deliverability supplied under our contracts is sufficient to meet all the needs of the Beluga Plant. Beluga River Field Producers We have similar requirements contracts with each of ConocoPhillips, AML&P and ChevronTexaco 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 ConocoPhillips and AML&P contracts is approximately 88% of the price of gas under the Marathon contract (described below) ($2.6414 per thousand cubic feet (MCF) on January 1, 2005), plus taxes. The price during this period under the ChevronTexaco contract is approximately 110% of the price of gas under the Marathon contract (described below) ($3.3017 per MCF on January 1, 2005), 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. ConocoPhillips has verbally indicated that it intends to terminate their supplemental gas contract. Chugach will explore ways to cover these needs in the future. 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-2010. 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 closing prices of New York Mercantile Exchange (NYMEX) Light, Sweet Crude Oil Futures, the Producer Price Index for natural gas, and the Consumer Price Index for heating fuel oil. The price on January 1, 2005, exclusive of taxes, was $3.0016 per MCF. Under the terms of the Marathon contract, Marathon generally provides the gas required for sales to GVEA, all of our requirements at Bernice Lake, International and Nikiski and 40% of the requirements at Beluga, not related to sales to GVEA. 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. The terms of the Marathon contract also gave Marathon a right to provide additional volumes in the period following depletion of the initial commitment of 215 BCF. On June 13, 2001, we were notified that Marathon will not commit to supply any additional volumes. 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 $0.29 per MCF. The agreement contains a minimum monthly bill of $2,600 for firm service. ENSTAR has initiated a process to provide transport services to Chugach, as well as other large users pursuant to price terms and conditions set out in a tariff. We do not expect that will result in price, terms and conditions unilaterally different from those in the contract. Environmental Matters General Chugach's operations are subject to certain federal, state and local environmental laws and regulations, which seek to limit air, water and other pollution and regulate hazardous or toxic waste disposal. While we monitor these laws and regulations to ensure compliance, they frequently change and often become more restrictive. When this occurs, the costs of our compliance generally increase. We include costs associated with environmental compliance in both our operating and capital budgets. We accrue for costs associated with environmental remediation obligations when those costs are probable and reasonably estimable. We do not anticipate that environmental related expenditures will have a material effect on our results of operations or financial condition. We cannot, however, predict the nature, extent or cost of new laws or regulations relating to environmental matters. The Clean Air Act and Environmental Protection Agency (EPA) regulations under the act (the "Clean Air Act") establish ambient air quality standards and limit the emission of many air pollutants. Some Clean Air Act programs that regulate electric utilities, notably the Title IV "acid rain" requirements, do not apply to facilities located in Alaska. The EPA's anticipated regulations to limit mercury emissions from fossil-fired steam-electric generating facilities, are not expected to materially impact Chugach because our thermal power plants burn exclusively natural gas. New Clean Air Act regulations impacting electric utilities may result from future events or may result from new regulatory programs that may be established to address problems such as global warming. While we cannot predict whether any new regulation would occur or its limitation, it is possible that new laws or regulations could increase our capital and operating costs. We have obtained or applied for all Clean Air Act permits currently required for the operation of our generating facilities, and we are not aware of any future requirements that will materially impact our financial condition. Chugach is subject to numerous other environmental statutes including the Clean Water Act, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Endangered Species Act, and the Comprehensive Environmental Response, Compensation and Liability Act and to the regulations implementing these statutes. We do not believe that compliance with these statutes and regulations to date has had a material impact on our financial condition or results of operation. However, new laws or regulations, implementation of final regulations or changes in or new interpretations of these laws or regulations could result in significant additional capital or operating expenses. Cooper Lake Chugach discovered polychlorinated biphenyls (PCBs) in paint, caulk and grease at the Cooper Lake Hydroelectric plant during initial phases of a turbine overhaul in 2000. A FERC approved plan, prepared in consultation with the Environmental Protection Agency (EPA), was implemented to remediate the PCBs in the plant. Chugach filed its final report with FERC in April of 2002 concluding that no further analysis was necessary and in a letter dated June of 2002, FERC agreed. In an order in Chugach's general rate case, Order U-01-108(26), the RCA permitted the costs associated with the overhaul and the PCB remediation to be recovered through rates. The costs of PCB sampling and analysis in Kenai Lake were accounted for as an expense. Item 3 - Legal Proceedings Matanuska Electric Association, Inc., v. Chugach Electric Association, Inc., Superior Court Case No. 3AN-99-8152 Civil This action is a claim for a breach of the Tripartite Agreement, which is the contract governing the parties' relationship for a 25-year period from 1989 through 2014 and governing Chugach's sale of power to MEA during that time. MEA asserted Chugach breached that contract by failing to provide information, by failing to properly manage Chugach's long-term debt, and by failing to bring Chugach's base rate action to a Joint Committee before presenting it to the RCA. All of MEA's claims were dismissed by the Superior Court. On April 29, 2002, MEA appealed the Superior Court's decisions relating to Chugach's financial management and Chugach's failure to bring Chugach's base rate action to the joint committee before filing with the RCA to the Alaska Supreme Court. We cross-appealed the Superior Court's decision not to dismiss the financial management claim on jurisdictional and res judicata grounds. The Alaska Supreme Court, on October 8, 2004, ruled in Chugach's favor supporting its right under the power sales agreement to file for interim rate relief without first going to the Joint Committee. The Supreme Court ruled against Chugach in its cross appeal. The Supreme Court also overturned the Superior Court's decision that dismissed MEA's claim asking for review of Chugach's management of use of rate locks instead of defeasing debt based on the Prudent Utility Practice standard under our power sales agreement. The Supreme Court remanded this issue to the Superior Court. On January 24, 2005, Chugach filed a summary judgment motion based on Chugach's claim that in the 2000 Test Year rate case the RCA has already decided the underlying issues relating to the prudency of Chugach's use of rate locks instead of defeasing debt. This motion is pending. Management is uncertain of the outcome of the proceeding before the Superior Court. Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc. Superior Court Case No. 3AN-04-11776 Civil On October 12, 2004, MEA filed suit in Superior Court alleging a breach of the power sales agreement between the parties and violation of Chugach's bylaws in connection with allocation of margins (capital credits) to MEA for the years 1998 through 2003. Allocation of capital credits assigns a share of the margins earned in a particular year to each customer. Capital credits are repatriated to customers at the discretion of the board of directors typically many years after the margins are earned. The suit seeks a declaration by the Court that Chugach is in breach of its bylaws and the power sales agreement based on its allocation of capital credits to MEA as well as injunctive relief requiring Chugach to calculate MEA's capital credit allocations based on MEA's patronage and in accordance with generally accepted accounting practices for nonprofit cooperatives and cooperative principles. The suit also seeks damages in an unspecified amount to compensate MEA for the alleged breach of contract. Management intends to vigorously defend against the claim. Management is uncertain of the outcome of the suit. Chugach has 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 are likely to have a material adverse effect on our results of operations, financial condition or liquidity. 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 for the years ended December 31:
Balance Sheet Data 2004 2003 2002 2001 2000 ---- ---- ---- ---- ---- Plant, net: In service $442,552,526 $453,706,406 $450,480,385 $452,964,686 $427,127,258 Construction work in Progress 25,278,388 16,560,438 20,224,302 28,887,008 42,027,617 ---------- ---------- ---------- ---------- ---------- Electric plant, net 467,830,914 470,266,844 470,704,687 481,851,694 469,154,875 Other assets 91,523,673 88,524,659 99,510,187 93,429,493 70,591,105 ---------- ---------- ---------- ---------- ---------- Total assets $559,354,587 $558,791,503 $570,214,874 $575,281,187 $539,745,980 ============ ============ ============ ============ ============ Capitalization: Long-term debt 363,357,786 384,289,179 389,834,179 364,310,000 312,219,945 Equities and margins 138,998,799 134,216,122 127,477,895 131,808,706 128,815,340 ----------- ----------- ----------- ----------- ----------- Total capitalization $502,356,585 $518,505,301 $517,312,074 $496,118,706 $441,035,285 ============ ============ ============ ============ ============ Summary Operations Data Operating revenues $201,246,615 $184,032,413 $171,944,918 $178,595,214 $158,541,114 Operating expenses 173,340,037 156,153,029 149,369,936 147,496,721 126,430,273 Interest expense 21,491,865 22,710,828 26,230,825 28,353,487 26,158,769 Amortization of gain on refinancing 0 0 188,082 1,123,973 1,440,479 - - ------- --------- --------- Net operating margins 6,414,713 5,168,556 (3,467,761) 3,868,979 7,392,551 Nonoperating margins 1,187,743 1,084,564 1,451,611 1,670,157 2,287,227 --------- --------- --------- --------- --------- Assignable margins $7,602,456 $6,253,120 $(2,016,150) $5,539,136 $9,679,778 ========== ========== ============ ========== ==========
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. These amounts are referred to as "margins." Patronage capital, the retained margins of our members, constitutes our principal equity. Times Interest Earned Ratio (TIER). Alaska electric cooperatives generally set their 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 (excluding capitalized interest). Chugach's authorized TIER for rate-making purposes on a system basis is 1.30, which was ordered by the RCA in Order U-01-108(26). Generally, it is not possible to achieve the authorized TIER due to factors such as adjustments to the revenue requirement that eliminate certain ongoing costs and increases in the costs of operation that occur after the test year on which rates were based. Accordingly, we manage our business with a view toward achieving a TIER of 1.20 or greater. We achieved TIERs for the past five years as follows: Year TIER ---- ---- 2004 1.35 2003 1.27 2002 0.92* 2001 1.20 2000 1.39 *The 2002 TIER was adversely affected by Order U-01-108(26) we received on February 6, 2003, from the RCA. See "Management's Discussion and Analysis - Results of Operations - Overview - Rate Regulation and Rates." Rate Regulation and Rates. Our rates are made up of two components: "base rates" and "fuel surcharge rates." "Base rates" are composed of fixed and variable charges in connection with all components of providing electricity. "Fuel surcharge" rates take into account the rise and fall of fuel and purchased power costs and ensure collection of fuel and purchased power costs above the base component included in the base energy rate. The RCA approves the amounts 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. In addition, a Regulatory Cost Charge (RCC) is assessed on each retail customer invoice to fund Chugach's share of the RCA's budget. The RCC tax is revised annually by the RCA. Base Rates. We recover operating and maintenance and other non-fuel and purchased power costs through our base rates established through an order of the RCA following a general rate case, where we propose a rate increase or decrease for each class of customer based on our costs to service those classes during a recent year referred to as a test year. The RCA may authorize, after a notice period, rate changes on an interim and refundable basis. Docket U-01-108 Chugach filed a general rate case on July 10, 2001, based on the 2000 test year and subsequently implemented interim and refundable rate increases as approved by the RCA. On April 15, 2002, Chugach submitted a filing with the RCA to update certain known and measurable costs and savings that had occurred outside the 2000 Test Year. In the updated filing, Chugach reduced its base rate increase request from 6.5% to 5.7%. Three wholesale customers and the Public Advocacy staff of the RCA participated in the rate case. Order No. 26 On February 6, 2003, Chugach received Order U-01-108(26) (Order 26) from the RCA. Order 26 required a refund of revenues collected in 2001 of approximately $1.1 million and revenues collected in 2002 of approximately $6.0 million, which resulted in a net operating loss of approximately $2 million in 2002. Under the Order, Chugach's financial performance for 2002 fell below the 1.10 level contained in the Rate Covenants in its currently effective indenture, the Amended and Restated Indenture, the CoBank Master Loan Agreement and the MBIA Insurance Corporation's (MBIA) Reimbursement and Indemnity Agreement. (See "Item 1-Business-Rate Regulation and Rates.") In accordance with the Rate Covenant in the Amended and Restated Indenture, on February 13, 2003, Chugach filed a Motion with the RCA asking the RCA to stay the effect of Order 26 until after the RCA considered Chugach's Petition for Reconsideration. On February 18, 2003, the RCA granted, in part, Chugach's motion for stay. Chugach filed the Petition for Reconsideration with the RCA on February 28, 2003. Order No. 30 On April 14, 2003, the RCA issued Order No. 30 in Docket U-01-108, significantly revising its earlier ruling. On April 28, 2003 Chugach submitted a revised revenue requirement and cost of service study in compliance with RCA Order No. 30. This order increased Chugach's revenue requirement by $3.1 million and adjusted the required refund from $7.1 million to $1.9 million. Order No. 33 On August 26, 2003, the RCA issued Order No. 33 and accepted Chugach's April 28, 2003, compliance filing subject to reducing long-term interest expense by $1.2 million associated with Allowance For Funds Used During Construction / Interest During Construction (AFUDC/IDC). In Order No. 33, the RCA re-reversed its earlier decision regarding the treatment of AFUDC/IDC. Order No. 36 Effective November 7, 2003, the RCA approved Chugach's compliance filing and final rates in this docket. As a result, and in relation to prior-approved permanent rates, Chugach's rates on a system basis increased 0.07 percent, or an increase of 3.5 percent to retail customers and a decrease of 7.9 percent to wholesale customers. The results of the RCA's decision on final rates were implemented on November 10, 2003. Appeal of RCA Orders Chugach filed a timely appeal of RCA Orders Nos. 26, 30 and 33 to the Alaska Superior Court. In its Appellant's brief dated February 18, 2004, Chugach asserted that the RCA's orders contained three errors: o The split TIER decision unduly discriminates against retail customers; o Interest expense was allocated on the basis of plant associated with Generation and Transmission (G&T) and Distribution rather than on the basis of debt associated with each function; and o Chugach is entitled to include all of its interest expense in rates and the RCA's offset for IDC was not justified because nearly all of the plant that produced the IDC was in service by the time the new rate went into effect. The resolution of the first two issues would not have changed the total amount Chugach could have recovered through rates. If Chugach had prevailed on the last issue, it would have been authorized to recover approximately $1,000,000 more each year in rates. One of Chugach's wholesale customers, MEA, also appealed the RCA's orders. In its Appellant's brief, MEA argued that the RCA's decision to normalize Chugach's variable rate debt at 3.8 percent and to authorize the corresponding interest expense constitutes error based on the historic rates prevailing for Chugach's variable rate debt. If MEA had prevailed on its argument, Chugach's authorized rates would have been reduced by approximately $1,000,000 each year. After oral argument on October 8, 2004, the Alaska Superior Court upheld all decisions of the RCA. We decided not to appeal this decision. Provision For Rate Refund At December 31, 2002, Chugach recorded a provision for rate refund of $7.1 million. On April 15, 2003, the RCA issued Order No. 30 in Docket U-01-108, significantly revising its earlier ruling in which $5.2 million of that provision was reversed. Between March and November of 2003, additional provisions were recorded in the amount of $3.8 million reflecting RCA decisions through Order No. 30, in addition to RCA orders that continued through the period. In October and November of 2003, Chugach's wholesale customers were refunded $5.0 million. Between March 19 and April 19, 2004, Chugach issued refunds totaling $0.6 million to its Small General Service class for customer bills rendered between January 31 and November 10, 2003. Our base rate changes, excluding fuel surcharges, for retail and wholesale classes for the years 2002 through 2004 were as follows: Rate Class * 2004 2003 2002 ---------- ---- ---- ---- Retail 0.00% 0.24% 0.00% Wholesale: HEA 0.00% (10.9%) 0.00% MEA 0.00% (12.4%) 0.00% SES 0.00% (9.9%) 0.00% * Rate changes shown are based on percent changes as applied to demand and energy rate levels. Base rate changes in 2003 were associated with Chugach's 2000 test period general rate case discussed above. Fuel Surcharge. We pass fuel and purchased power costs above base amounts included in the base rate directly to our wholesale and retail customers through the fuel surcharge mechanism. Changes in fuel and purchase power costs are primarily due to fuel price adjustment mechanisms in our gas-supply contracts based on natural gas, crude oil and fuel oil indexed price changes. We pass these costs directly to our retail and wholesale customers. The fuel surcharge is approved on a quarterly basis by the RCA. There are no limitations on the number or amount of 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. Year ended December 31, 2004, compared to the years ended December 31, 2003, and 2002 Margins Our margins for the years ended December 31 were as follows:
2004 2003 2002 ---- ---- ---- Net Operating Margins $ 6,414,713 $ 5,168,556 $(3,467,761) Nonoperating Margins $ 1,187,743 $ 1,084,564 $1,451,611 ----------- ----------- ---------- Assignable Margins $ 7,602,456 $ 6,253,120 $(2,016,150) =========== =========== ============
The increase in assignable margins in 2004 of $1.3 million, or 22%, was due primarily to a decrease in interest expense caused by lower interest rates. The increase in assignable margins in 2003 of $8.3 million, or 410%, was due in part to the reversal of $5.2 million of the provision for rate refunds that was recorded in 2002 and a decrease in interest expense caused by lower interest rates. Nonoperating margins include interest income, AFUDC, capital credits and patronage capital allocations. Nonoperating margins increased in 2004 from 2003 by $103,179, or 10%, due primarily to an increase in interest income caused by a higher than average cash balance during the year and higher interest rates. Nonoperating margins decreased in 2003 from 2002 by $367,000, or 25%, due to lower interest rates, as well as a decrease in allocations of patronage capital from CoBank. Revenues Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2004, operating revenues were $17.2 million, or 9%, higher than in 2003 due to increased sales and higher fuel costs recovered in revenue through the fuel surcharge mechanism. In 2003, operating revenues were $12.1 million, or 7%, higher than in 2002 due in part to increased sales and to a $5.2 million partial reversal recorded in 2003 of a $7.1 million provision for rate refund recorded in 2002 and an increase of $2.5 million in economy energy sales to GVEA. In addition, fuel costs were higher in 2003 and recovered in revenue through the fuel surcharge mechanism. The major components of our operating revenue for the year ending December 31 were as follows:
2004 2003 2002 ---- ---- ---- Retail $124,736,765 $115,717,488 $110,082,014 Wholesale HEA 24,790,344 21,733,244 22,035,973 MEA 37,164,894 34,205,260 30,018,227 Seward 2,850,001 2,461,200 2,709,752 Economy energy 8,867,625 7,112,276 4,567,179 Other 2,836,986 2,802,945 2,531,773 --------- --------- --------- Total revenue $201,246,615 $184,032,413 $171,944,918 ============ ============ ============
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 2004, 2003, and 2002, economy sales to GVEA constituted approximately 5.0%, 4.0%, and 2.7%, respectively, of our sales revenues. The increase in economy sales in 2004 from 2003 was due to GVEA's higher fuel costs than Chugach's, which made it more economical for GVEA to purchase power from Chugach rather than generate its own. The increase in economy sales in 2003 from 2002 was due to GVEA's maintenance schedule as well as higher fuel prices. Expenses The major components of our operating expenses for the years ended December 31 were as follows:
2004 2003 2002 ---- ---- ---- Fuel $64,113,474 $48,667,262 $46,822,943 Power production 15,070,486 13,961,565 13,500,103 Purchased power 20,579,992 18,244,921 18,750,936 Transmission 6,350,344 4,511,002 3,930,902 Distribution 11,451,931 10,866,251 10,869,335 Consumer accounts 5,308,353 5,589,788 5,594,572 Administrative, general and other 22,476,005 26,520,189 22,251,895 Depreciation 27,989,452 27,792,051 27,649,250 ---------- ---------- ---------- Total operating expenses $173,340,037 $156,153,029 $149,369,936 ============ ============ ============
Fuel Fuel expense increased by $15.4 million, or 32%, in 2004 from 2003 due to higher fuel prices as well as higher fuel volume purchases. Fuel expense did not vary materially in 2003 from 2002. Power Production Power production expense increased by $1.1 million, or 8%, in 2004 from 2003 due, in part, to the method in which maintenance costs are recorded was updated in 2004 to more accurately reflect the costs in the proper functional area. The increase was also due to higher material and professional services costs associated with scheduled maintenance and inspections on multiple units at Beluga. In addition, labor costs in 2003 were unusually low as a result of reduced overtime and hiring constraints. Power production expense did not vary materially in 2003 from 2002. Purchased Power Purchased power costs increased by $2.3 million, or 12.8%, in 2004 from 2003 due to higher fuel costs and increased sales. Purchased power costs did not vary materially in 2003 from 2002. Transmission Transmission expense increased by $1.8 million, or 41%, in 2004 from 2003 due to increased transmission substation maintenance being performed in 2004. In addition, the increase was also due to the aforementioned update to the method used to record maintenance costs. Transmission expense increased in 2003 from 2002 by $580 thousand, or 15%, due to transmission substation maintenance being performed in 2003 that had been deferred in 2002 as a result of not being able to schedule the necessary outages to perform the maintenance. In addition, transmission right-of-way clearing had been deferred in 2002 as a result of permitting issues was also performed in 2003. Distribution Distribution expense increased $586 thousand, or 5%, in 2004 from 2003 due to the aforementioned update to the method used to record maintenance costs. Distribution expense did not vary materially in 2003 from 2002. Consumer Accounts Consumer accounts expense decreased by $281 thousand, or 5%, in 2004 from 2003 due to the recovery of previously recorded bad debt expense through capital credits. Consumer accounts expense did not vary materially in 2003 from 2002. Administrative, General and Other Administrative, general and other expenses decreased by $4.0 million, or 15%, in 2004 from 2003 due to the $1.8 million write down of an impaired asset and the $965 thousand write-off of several studies in 2003 not recurring in 2004. The decrease is also due to $1.9 million associated with the aforementioned update to the method used to record maintenance costs, as well as $1.6 million associated with the completion of the amortization of a large portion of the Year 2000 (Y2K) software costs. These decreases, however, were offset by $757 thousand associated with an improvement in the process of recording workers compensation claims, $594 thousand associated with our performance incentive program and $457 thousand associated with the write-off of obsolete inventory and cancelled projects. Administrative, general and other expenses increased by $4.1 million, or 18.5%, in 2003 from 2002 due to a $1.8 million write down of an impaired asset, a $500 thousand write-off of the Kenai Lake PCBs study and a $465 thousand write-off of the Southern Intertie study, a $387 thousand increase in allocated information services costs, a $445 thousand increase in insurance costs and a $207 thousand donation of an obsolete inventory item. Depreciation We use remaining life rates set forth in the most recent depreciation study. In 2003 an update of the Depreciation Study was completed utilizing Electric Plant in Service balances as of December 31, 2002. The new rates were implemented and in effect for all of 2004. The new rates are currently under review by the RCA. Depreciation expense did not vary materially in 2004 from 2003 or in 2003 from 2002. Interest Interest on long-term obligations decreased by $1.1 million, or 5%, in 2004 from 2003 due to lower interest rates. Interest on long-term obligations decreased $3.1 million, or 12% in 2003 from 2002, also due to lower interest rates. Interest on short-term borrowing decreased by $11.9 thousand, or 100%, in 2004 from 2003 due to the line of credit not being utilized during 2004. Interest on short-term borrowing decreased $287.0 thousand, or 96% in 2003 from 2002, due to a decrease in short-term borrowing, as well as decreased interest rates. Interest charged to construction increased by $81.2 thousand, or 20%, in 2004 from 2003 due to a higher average balance in Construction Work in Progress (CWIP) caused by the South Anchorage Substation project and the new 138kV transmission line being built between the International substation and the South Anchorage Substation. Net interest expense includes interest on long-term obligations and short-term obligations, reduced by interest charged to construction. Patronage Capital (Equity) The following table summarizes our patronage capital and total equity position for the years ended December 31:
2004 2003 2002 ---- ---- ---- Patronage capital at beginning of year $126,341,413 $120,148,502 $125,184,374 Retirement of capital credits and estate payments (3,193,600) (60,209) (3,019,722) Assignable margins 7,602,456 6,253,120 (2,016,150) --------- --------- ----------- Patronage capital at end of year 130,750,269 126,341,413 120,148,502 Other equity* 8,248,530 7,874,709 7,329,393 --------- --------- --------- Total equity at end of year $138,998,799 $134,216,122 $127,477,895 ============ ============ ============ * Other equity includes memberships, donated capital and gain on capital credit retirements.
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 distributions of these amounts to members, also known as capital credits, 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. The Board of Directors may also return capital credits to former members and estates who have requested early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002. In 2004, the Board of Directors authorized the retirement of $3,126,560 of retail patronage for 1985 and 1986. The Board of Directors also, in 2004, authorized $125,000 for capital credits payments to those former members and estates who requested early retirements at discounted rates. In 2003, the Board of Directors was unable to authorize a capital credit retirement due to covenant restrictions contained in the Amended and Restated Indenture. In 2002, we retired all retail capital credits attributable to margins earned in periods prior to and including 1985 retail capital credits. Prior to 2000, wholesale capital credits had been retired on a 10-year cycle pursuant to an approved capital credit retirement program, which was contained in the Chugach business plan. However, in 2000 we implemented a plan to return the capital credits of wholesale and retail customers on a 15-year rotation. The Amended and Restated Indenture prohibits us from making any distributions, payment or retirement of patronage capital to our customers if an event of default under the Amended and Restated Indenture exists. Otherwise, we may make distributions to our members in each year equal to the lesser of 5% of our patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, our aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of our total liabilities and equities and margins. Under our Master Loan Agreement with CoBank, we also may not declare or pay any dividend or make any distributions to members or retirements of patronage capital if, giving effect to such distribution an event of default under the Master Loan Agreement exists, or our equities and margins as of the end of our most recent fiscal quarter would be less than thirty percent (30%) of the sum of our total long-term debt plus equities and margins at that time. However, as long as no event of default exists under the Master Loan Agreement with CoBank and the ratio of our equities and margins to the sum of total long-term debt plus equities and margins would not be less than 22%, we may make a distribution of up to the lesser of five percent (5%) of our aggregate equities and margins as of the end of the immediately preceding fiscal year or fifty percent (50%) of the prior fiscal year's margins. The table below sets forth a five-year summary of anticipated capital credit retirements based on 50% of prior year's margins retirement criteria: Year Ending Total 2005 $3,000,000 2006 3,500,000 2007 5,500,000 2008 5,000,000 2009 5,500,000 Changes in Financial Condition Assets Total assets increased $563.1 thousand, or 0.1%, from December 31, 2003, to December 31, 2004. The net increase was due to a $4.9 million, or 26% increase in accounts receivable due to higher fuel costs and increased sales to GVEA. The increase was also due to a $1.8 million, or 8%, increase in materials and supplies caused by the purchase of inventory items in preparation for scheduled maintenance projects. The increase was offset by a $2.4 million, or 0.5%, decrease in net utility plant caused by an increase in accumulated depreciation. The increase was also offset by a $2.0 million, or 100%, decrease in fuel cost under-recovery caused by the collection of fuel costs through the fuel surcharge mechanism and a $489 thousand, or 100%, decrease in restricted construction funds. Prepayments in 2004 also decreased $653 thousand, or 45% due to a deposit on generation maintenance equipment that was prepaid in 2003 and cash and cash equivalents also decreased $720 thousand, or 6%. Liabilities and Equities Changes in total liabilities include a $4.8 million, or 3.6%, increase in total equities and margins due to margins, net of capital credit retirements, in 2004 and a $10.4 million, or 187%, increase in current installments of long-term obligations due to the reclassification of CoBank 2 to current portion of long-term obligations. Fuel cost over-recovery also increased $2.7 million, or 100%, due to the over collection of the previous quarter's fuel cost through the fuel surcharge mechanism. Fuel also increased $3.9 million, or 43%, due to higher fuel prices. Other current liabilities also increased $631 thousand, or 80%, due to the increase in patronage capital payable caused by the capital credit retirement in 2004 that did not occur in 2003 and salaries, wages and benefits increased $644 thousand, or 13% due to merit increases. The increases were offset by a $20.9 million decrease in long-term obligations due to the CoBank 2 reclassification discussed above and the installment payments on CoBank 3 and 4. Deferred credits also decreased by $1.3 million, or 34%, due to a decrease in customer advances on line extension and the return of the Southern Intertie construction funds. Provision for rate refund also decreased by $671 thousand, or 100%, due to the payment of rate refunds since December 31, 2003. Inflation We do not believe that inflation has a significant effect on our operations. Contractual Obligations and Commercial Commitments The following are Chugach's contractual and commercial commitments as of December 31, 2004: Contractual cash obligations: (In thousands) Payments Due By Period
Total 2005 2006-2007 2008-2009 Thereafter Long-term debt $379,289 $15,931 $18,054 $15,005 $330,299 Short-term debt1 0 0 0 0 0 Bradley Lake2 16,000 4,000 4,000 4,000 4,000 ------ ----- ----- ----- ----- Total $395,289 $19,931 $22,054 $19,005 $334,299 Commercial Commitments: (In thousands) Amount of Commitment Expiration Per Period Total 2004 2005-2006 2007-2008 Thereafter Lines of credit-available * $70 $70 $0 $0 $0 1At December 31, 2004, Chugach had $70 million in lines of credit available with various financial institutions, which fund capital requirements. At December 31, 2004, there was no outstanding balance on the lines of credit, therefore, the available borrowing capacity under these lines of credit was $70 million. The lines of credit were not utilized in 2004. 2Estimated annual costs
Purchase obligations: Chugach is a participant and has a 30.4% share in the Bradley Lake hydroelectric project (See "Item 2-Properties-Other Property-Bradley Lake.") This contract runs through 2041. We have agreed to pay a like percentage of annual costs of the project, which has averaged $4 million over the past five years. We believe these costs, adjusted for inflation, reasonably reflect anticipated future project costs. Our primary sources of natural gas are the Beluga River Field producers and Marathon Oil Company (See "Item 2-Properties-Fuel Supply-Beluga River Field Producers/Marathon.") We have contracts with each of these producers with varying expiration dates that generally require us to purchase from them all of our fuel requirements for our Beluga plant. The current phase of these contracts expires in December 2013. Our fuel costs vary due to the impact of the energy future indices used to index the price of fuel and are inherently difficult to predict. We pass fuel costs directly to our wholesale and retail customers through the fuel surcharge mechanism (See "Item 7-Management's Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Fuel Surcharge.") Liquidity And Capital Resources We satisfy our operational and capital cash requirements primarily through internally generated funds, a $50 million line of credit from National Rural Utilities Cooperative Finance Corporation (NRUCFC), which was renewed for a five-year term on October 15, 2002, and a $20 million line of credit with CoBank, which expires April 30, 2005, subject to renewal at the discretion of the parties. At December 31, 2004, there was no outstanding balance with CFC or CoBank and neither line was utilized in 2004. On February 1, 2002, Chugach issued $120,000,000 of 2002 Series A Bond and $60,000,000 of 2002 Series B Bond for the purpose of redeeming $149.3 million in principal amount of the 1991 Series A Bond due 2022 to pay the redemption premium on the 1991 Series A Bond due 2022 in the amount of $13.6 million and for general working capital. The 2002 Series A Bond will mature on February 1, 2012, and bears interest at 6.20% per annum. Interest is payable semi-annually on February 1 and August 1 of each year commencing on August 1, 2002. Chugach may not redeem the 2002 Series A Bond prior to maturity. The 2002 Series B Bond (the "Auction Rate Bond") will mature on February 1, 2012. The Auction Rate Bond bore interest from the date of original delivery to and through February 27, 2002, at a rate established by the underwriter prior to their date of delivery and thereafter bore interest at the rate set for 28-day auction periods. The initial auction took place on February 27, 2002. The applicable interest rate for any 28-day auction period is the term rate established by the auction agent based on the terms of the auction. The Auction Rate Bond may be converted, in Chugach's discretion, to a daily, seven-day, 35-day, three-month or a semi-annual period or a flexible auction period. The Auction Rate Bond is subject to optional and mandatory redemption and to mandatory tender for purchase prior to maturity in the manner and at the times described herein. Bankers Trust Company is the auction agent and J.P. Morgan Securities Inc., acted as the initial broker-dealer for the Auction Rate Bond. The 2002 Series A Bond and the Auction Rate Bond (collectively the "Bonds") are unsecured obligations, ranking equally with Chugach's other unsecured and unsubordinated obligations. In addition, Chugach's ability is limited to secure obligations for borrowed money or the deferred purchase price of property unless Chugach equally and ratably secures Chugach's outstanding indebtedness subject to the Amended and Restated Indenture governing the Bonds. Principal maturities and sinking fund payments of our outstanding indebtedness at December 31, 2004 are set forth below:
Year Ending Sinking Fund Principal maturities December 31 Requirement Total 2005 4,900,000 11,031,393 $15,931,393 2006 5,200,000 1,125,687 6,325,687 2007 5,500,000 6,228,569 11,728,569 2008 5,900,000 1,340,725 7,240,725 2009 6,300,000 1,463,358 7,763,358 Thereafter 293,300,000 36,999,447 330,299,447 ----------- ---------- ----------- $321,100,000 $58,189,179 $379,289,179 ============ =========== ============
During 2004 we spent approximately $27.8 million on capital-construction projects, net of reimbursements, which includes interest capitalized during construction. We develop five-year capital improvement plans that are updated every year. Our capital improvement requirements are based on long-range plans and other supporting studies and are executed through the five-year capital improvement program. Set forth below is an estimate of capital expenditures for the years 2005 through 2009 as contained in the amended Capital Improvement Plan (CIP), which was approved on March 16, 2005: 2005 $29.7 million 2006 $27.5 million 2007 $16.4 million 2008 $24.9 million 2009 $16.6 million We expect that cash flows from operations and external funding sources will be sufficient to cover operational and capital funding requirements in 2005 and thereafter. Ratings Our bond ratings remained unchanged in 2004 reflecting the rating agencies' confidence in Chugach's ability to meet future operational and financial challenges. Off-Balance Sheet Arrangements We have not created, and are not party to, any special-purpose or off-balance-sheet entities for the purpose of raising capital, incurring debt or operating parts of our business that are not consolidated into our financial statements. We do not have any arrangements or relationships with entities that are not consolidated into our financial statements that are reasonably likely to materially affect our liquidity or the availability of our capital resources. Critical Accounting Policies Our accounting and reporting policies comply with accounting principles generally accepted in the United States of America. The preparation of financial statements in conformity with Generally Accepted Accounting Principles (GAAP) requires that management apply accounting policies and make estimates and assumptions that affect results of operations and reported amounts of assets and liabilities in the financial statements. Significant accounting policies are described in Note 1 to the financial statements (See "Financial Statements and Supplementary Data."). Critical accounting policies are those policies that management believes are the most important to the portrayal of Chugach's financial condition and results of its operations, and require management's most difficult, subjective, or complex judgments, often as a result of the need to make estimates about matters that are inherently uncertain. Most accounting policies are not considered by management to be critical accounting policies. Several factors are considered in determining whether or not a policy is critical in the preparation of financial statements. These factors include, among other things, whether the estimates are significant to the financial statements, the nature of the estimates, the ability to readily validate the estimates with other information including third parties or available prices, and sensitivity of the estimates to changes in economic conditions and whether alternative accounting methods may be utilized under accounting principles general accepted in the United States of America. For all of these policies management cautions that future events rarely develop exactly as forecast, and the best estimates routinely require adjustment. Management has discussed the development and the selection of critical accounting policies with Chugach's Audit Committee. The following policies are considered to be critical accounting policies for the year ended December 31, 2004. Electric Utility Regulation Chugach is subject to regulation by the RCA. The RCA sets the rates Chugach is permitted to charge customers based on allowable costs. As a result, Chugach applies Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on Chugach's financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement benefits have less of a direct impact on Chugach's results of operations than they would on a non-regulated company. As reflected in Note 1 to the financial statements under "Deferred Charges and Credits", significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislation and judicial or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact Chugach's financial statements. Financial Instruments and Hedging Chugach used U.S. Treasury forward rate-lock agreements to hedge expected interest rates on the February 2002 debt re-financings. We accounted for the agreements under SFAS 133. For rate-making purposes, Chugach did not adjust rates for gains and losses prior to settlement, and the loss on settlement will be an adjustment to rates over the lives of the associated debt. This rate-making treatment was approved by the RCA in Order U-01-108(26). (See "Item 7-Management's Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Rate Regulation and Rates.") Accordingly, the unrealized gain or loss was not recorded and was treated as a regulatory asset upon settlement. Accounting for derivatives continue to evolve through guidance issued by the Derivatives Implementation Group (DIG) of the Financial Accounting Standards Board. To the extent that changes by the DIG modify current guidance, the accounting treatment for derivatives may change. Critical estimates also include provision for rate refunds and allowance for doubtful accounts. Actual results could differ from those estimates. New Accounting Standards In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity. This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Many of those instruments were previously classified as equity. Some of the provisions of this Statement are consistent with the current definition of liabilities in FASB Concepts Statement No. 6, Elements of Financial Statements. The remaining provisions of this Statement are consistent with FASB's proposal to revise that definition to encompass certain obligations that a reporting entity can or must settle by issuing its own equity shares depending on the nature of the relationship established between the holder and the issuer. While FASB still plans to revise that definition through an amendment to Concepts Statement 6, FASB decided to defer issuing that amendment until it has concluded its deliberations on the next phase of this project. That next phase will deal with certain compound financial instruments including puttable shares, convertible bonds, and dual-indexed financial instruments. Chugach implemented SFAS 150 January 1, 2004. The impact of this Statement on the financial statements was not material. Outlook Chugach is currently planning for future resource needs. An Integrated Resource Plan (IRP) is in development. This effort studies several possible future scenarios for power sales. On March 17, 2004, the Chugach Board of Directors authorized the Chief Executive Officer (CEO) or his designee to enter into an agreement to form a Joint Action Agency (JAA) that, if implemented, could provide a structure with which Chugach and other eligible Alaska utilities might jointly acquire, own and operate certain generation and transmission facilities. On September 15, 2004, the Chugach Board of Directors authorized the CEO to undertake all necessary steps to craft a plan to create a single-member Generation and Transmission (G&T) cooperative that would hold all Chugach G&T assets, contractual arrangements, and associated debt. Chugach is considering this option as a way to more effectively track the finances of the G&T functions and to help address issues in future rate cases involving the relative margin earning burdens among customer classes. These two organizational structures are not mutually exclusive. Effective January 31, 2005, Chugach reorganized its operations into more distinct business units - Office of the Chief Executive Officer, Generation and Transmission (G&T) Division, Distribution Division and Corporate Services. This reorganization was accomplished to more fully recognize the diversity of Chugach operations and clearly determine the financial and operational performance of each unit. The Office of the Chief Executive Officer is responsible for all corporate level activities including board of director functions, human resources, risk management, legal matters, labor relations and employee relations, legislative affairs and all financing activities Chugach may undertake. The CEO's direct staff is the Chief Financial Officer, Vice President, Human Resources, General Counsel and Government and External Affairs Manager. The general managers of the G&T Division and Distribution Division also report to the CEO. G&T operations include all power supply functions, transmission functions, power dispatch and administrative requirements associated with generation and transmission. The G&T sector is led by Bradley Evans, General Manager. Distribution functions include consumer services, public relations and line operation and maintenance and consumer information and services areas. The Distribution area is led by Lee Thibert, General Manager. Corporate Services is comprised of Administration Services, Information Services, Regulatory Affairs and Accounting. It is responsible for providing services to all other sectors of Chugach. Corporate Services is led by William Stewart, Senior Vice President. Item 7A - Quantitative and Qualitative Disclosures About Market Risk Chugach is 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 The following table provides information regarding cash flows for principal payments on total debt by maturity date (dollars in thousands) as of December 31, 2004, and 2003: 2004
Fair Total Debt* 2005 2006 2007 2008 2009 Thereafter Total Value - ----------- ---- ---- ---- ---- ---- ---------- ----- ----- Fixed rate $10,000 $0 $0 $0 $0 $270,000 $280,000 $309,502 Average interest rate 7.76% - - - - 6.39% 6.44% Variable rate $5,931 $6,326 $11,729 $7,241 $7,763 $60,299 $99,289 $99,289 Average interest rate 3.22% 3.22% 3.66% 3.22% 3.22% 3.77% 3.60% * Includes current portion 2003 Fair Total Debt* 2004 2005 2006 2007 2008 Thereafter Total Value - ----------- ---- ---- ---- ---- ---- ---------- ----- ----- Fixed rate $0 $10,000 $0 $0 $0 $270,000 $280,000 $308,590 Average interest rate - 7.76% - - - 6.39% 6.44% Variable rate $5,545 $5,931 $6,326 $11,729 $7,241 $73,063 $109,834 $109,834 Average interest rate 1.38% 1.38% 1.38% 1.98% 1.38% 2.08% 1.91% * Includes current portion
Chugach is 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 $59,310, based on $5,931,000 of variable debt outstanding at December 31, 2004. To manage interest rate exposure for refinancing the 1991 Series A Bonds due 2022, on their first available call date, March 15, 2002, we entered into a treasury rate-lock agreement with Lehman Brothers Financial Products Inc., (Lehman Brothers) in March 1999. The treasury rate-lock agreement had a settlement date of February 15, 2002. On May 11, 2001, we terminated the $18.7 million U.S. Treasury portion of the treasury rate-lock agreement in receipt of payment of $10,000 by Lehman Brothers. On December 7, 2001, we terminated 50%, $98.0 million, of the 10-year U.S. Treasury portion of the treasury rate-lock agreement for a settlement payment of $4 million to Lehman Brothers. We settled the remaining 50% of the treasury rate-lock agreement for $3 million on December 19, 2001. On January 14, 2002, we entered into an 18-day rate lock agreement with JP Morgan on the $120 million 10-year term bond of the proposed 2002 refinancing. We terminated the rate lock on February 1, 2002, which generated a payment to us of $1.2 million. All of the settlement payments were accounted for as regulatory assets and amortized over the life of the corresponding debt, which was authorized by the RCA in Order U-01-108(26). Commodity Price Risk Chugach's 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 mechanism, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not normally impact margins. Item 8 - Financial Statements and Supplementary Data Independent Auditors' Report The Board of Directors Chugach Electric Association, Inc. We have audited the accompanying balance sheets of Chugach Electric Association, Inc. (the Company) as of December 31, 2004 and 2003, and the related statements of revenue, expenses and patronage capital, and cash flows for each of the years in the three-year period ended December 31, 2004. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. 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, 2004 and 2003, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. /s/ KPMG, LLP February 11, 2005 Anchorage, AK Chugach Electric Association, Inc. Balance Sheets December 31, 2004 and 2003
Assets 2004 2003 ------ ---- ---- Utility plant (notes 1d, 3, 12 and 13): Electric plant in service $748,484,527 $747,078,372 Construction work in progress 25,278,388 16,560,438 ---------- ---------- Total utility plant 773,762,915 763,638,810 Less accumulated depreciation 305,932,001 293,371,966 ----------- ----------- Net utility plant 467,830,914 470,266,844 Other property and investments, at cost: Nonutility property 24,461 3,550 Investments in associated organizations (note 4) 11,768,457 11,381,796 ---------- ---------- Total other property and investments 11,792,918 11,385,346 Current assets: Cash and cash equivalents, including repurchase agreements of $12,826,644 in 2004 and $12,663,761 in 2003 10,465,004 11,185,086 Cash-restricted construction funds 0 488,846 Special deposits 217,191 222,163 Accounts receivable, less provision for doubtful accounts of $364,261 in 2004 and $273,793 in 2003 23,740,383 18,812,199 Fuel cost under-recovery (note 1o) 0 2,032,730 Materials and supplies 23,691,509 21,888,794 Prepayments 805,670 1,458,649 Other current assets 260,115 357,265 ------- ------- Total current assets 59,179,872 56,445,732 Deferred charges, net (notes 5 and 14) 20,550,883 20,693,581 ---------- ---------- Total assets $559,354,587 $558,791,503 ============ ============ See accompanying notes to financial statements.
Chugach Electric Association, Inc. Balance Sheets, Continued December 31, 2004 and 2003
Liabilities & Equities 2004 2003 ---------------------- ---- ---- Equities and margins (note 6 and 7): Memberships $1,202,538 $1,155,818 Patronage capital 130,750,269 126,341,413 Other 7,045,992 6,718,891 --------- --------- Total equities and margins 138,998,799 134,216,122 Long-term obligations, excluding current installments (notes 8, and 9): 2001 Series A Bonds payable 150,000,000 150,000,000 2002 Series A Bonds payable 120,000,000 120,000,000 2002 Series B Bonds payable 46,200,000 51,100,000 National Bank for Cooperatives promissory notes payable 47,157,786 63,189,179 ---------- ---------- Total long-term obligations 363,357,786 384,289,179 Current liabilities: Current installments of long-term obligations (notes 8 and 9) 15,931,393 5,545,000 Accounts payable 7,890,172 7,676,906 Provision for rate refund (note 2) 0 671,071 Consumer deposits 1,947,511 1,834,752 Fuel cost over-recovery (note 1o) 2,714,345 0 Accrued interest 6,201,769 6,165,790 Salaries, wages and benefits 5,530,740 4,886,600 Fuel 12,919,623 9,006,758 Other current liabilities 1,416,400 785,760 --------- ------- Total current liabilities 54,551,953 36,572,637 Deferred credits (note 10) 2,446,049 3,713,565 --------- --------- Total liabilities and equities $559,354,587 $558,791,503 ============ ============ See accompanying notes to financial statements.
Chugach Electric Association, Inc. Statements of Revenues, Expenses and Patronage Capital Years ended December 31, 2004, 2003 and 2002
2004 2003 2002 ---- ---- ---- Operating revenues (notes 2 and 14) $201,246,615 $184,032,413 $171,944,918 Operating expenses: Fuel (note 14) 64,113,474 48,667,262 46,822,943 Power production 15,070,486 13,961,565 13,500,103 Purchased power 20,579,992 18,244,921 18,750,936 Transmission 6,350,344 4,511,002 3,930,902 Distribution 11,451,931 10,866,251 10,869,335 Consumer accounts 5,308,353 5,589,788 5,594,572 Administrative, general and other 22,476,005 26,520,189 22,251,895 Depreciation 27,989,452 27,792,051 27,649,250 ---------- ---------- ---------- Total operating expenses 173,340,037 156,153,029 149,369,936 Interest expense: On long-term obligations 21,984,371 23,110,239 26,161,891 Charged to construction - credit (492,506) (411,312) (418,078) On short-term obligations 0 11,901 298,930 - ------ ------- Net interest expense 21,491,865 22,710,828 26,042,743 ---------- ---------- ---------- Net operating margins 6,414,713 5,168,556 (3,467,761) Nonoperating margins: Interest income 453,606 325,324 774,814 Capital credits, patronage dividends and other 722,947 679,179 897,761 Property gain (loss) 11,190 80,061 (220,964) ------ ------ --------- Assignable margins 7,602,456 6,253,120 (2,016,150) Patronage capital at beginning of year 126,341,413 120,148,502 125,184,374 Retirement of capital credits and estate payments (note 6) (3,193,600) (60,209) (3,019,722) ----------- -------- ----------- Patronage capital at end of year $130,750,269 $126,341,413 $120,148,502 ============ ============ ============ See accompanying notes to financial statements.
Chugach Electric Association, Inc. Statements of Cash Flows Years ended December 31, 2004, 2003 and 2002
2004 2003 2002 ---- ---- ---- Operating activities: Assignable margins $7,602,456 $6,253,120 $(2,016,150) Adjustments to reconcile assignable margins to net cash provided by operating activities: Provision for rate refund 0 (1,400,000) 7,050,000 Depreciation and amortization 31,586,948 33,780,103 33,472,159 Capitalization of interest (571,013) (487,359) (491,349) Impairment of long-lived asset 0 1,846,816 0 Property (gains) losses, net (11,190) (80,061) 220,964 Write-off of deferred charges 217,665 1,088,260 0 Other 1,007 1,145 1,568 Changes in assets and liabilities: (Increase) decrease in assets: Accounts receivable (4,928,184) 7,598,064 (4,107,864) Fuel cost recovery 2,032,730 (2,032,730) 3,591,963 Materials and supplies (1,802,715) 1,858,796 (925,587) Prepayments 652,979 494,702 (1,325,806) Other assets 102,122 (20,468) (1,044) Deferred charges (854,481) (1,887,037) (4,479,028) Increase (decrease) in liabilities: Accounts payable 213,266 (43,068) (3,292,931) Provision for rate refund (671,071) (4,978,929) 0 Consumer deposits 112,759 8,487 222,574 Fuel cost payable 2,714,345 (363,862) 363,862 Accrued interest 35,979 (215,316) (996,952) Salaries, wages and benefits 644,140 (90,994) 132,775 Fuel 3,912,865 1,911,356 (4,469,715) Other liabilities 630,640 (1,242,178) 127,782 Deferred credits (92,314) (210,681) (15,887,873) -------- --------- ------------ Net cash provided by operating activities 41,528,933 41,788,166 7,189,348 Investing activities: Extension and replacement of plant (27,810,212) (26,526,858) (16,859,047) Purchase of investments in associated organizations (387,668) (419,226) (480,097) --------- --------- --------- Net cash used in investing activities (28,197,880) (26,946,084) (17,339,144) Financing activities: Net transfer of restricted construction funds 488,846 110,018 (80,993) Proceeds from long-term obligations 0 0 180,000,000 Repayments of long-term obligations (10,545,000) (5,165,821) (164,638,695) Repayments of short-term borrowings 0 (6,081,250) 0 Memberships and donations received 373,821 545,316 705,061 Retirement of patronage capital (3,193,600) (60,209) (3,019,722) Net receipts (refunds) of consumer advances for construction (1,175,202) (289,342) 653,670 ----------- --------- ------- Net cash provided by (used in) financing activities (14,051,135) (10,941,288) 13,619,321 ------------ ------------ ---------- Net change in cash and cash equivalents (720,082) 3,900,794 3,469,525 Cash and cash equivalents at beginning of year $11,185,086 $7,284,292 $3,814,767 ----------- ---------- ---------- Cash and cash equivalents at end of year $10,465,004 $11,185,086 $7,284,292 =========== =========== ========== Supplemental disclosure of cash flow information Interest expense paid, including amounts capitalized $21,354,036 $23,076,144 $27,039,695 =========== =========== =========== See accompanying notes to financial statements.
Chugach Electric Association, Inc. Notes to Financial Statements December 31, 2004 and 2003 (1) Description of Business and Significant Accounting Policies a. Description of Business Chugach Electric Association, Inc., (Chugach) is the largest electric utility in Alaska. Chugach 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 (HEA) and the City of Seward (Seward). Chugach's members are the consumers of the electricity sold. Chugach 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. Chugach is subject to the regulatory authority of the Regulatory Commission of Alaska (RCA). b. Management Estimates In preparing the financial statements, management of Chugach 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. Critical estimates include the provision for rate refund and allowance for doubtful accounts. Actual results could differ from those estimates. c. Regulation The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). (1) Description of Business and Significant Accounting Policies (continued) d. Utility Plant and Depreciation Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. 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. Renewals and betterments are capitalized, while maintenance and repairs are charged to expense as incurred. In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144), utility plant is reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of are separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale are presented separately in the appropriate asset and liability section of the balance sheet. Chugach performed an analysis of certain generation assets in the second quarter of 2003 and determined an impairment of an asset existed. As a result of this analysis, the value of an asset was reduced by $1,846,816 to its estimated salvage value. This amount is included in the 2003 Statement of Revenues, Expenses and Patronage Capital, "Administrative, general and other," category. Depreciation and amortization rates have been applied on a straight-line basis and at December 31 are as follows:
Annual Depreciation Rate Ranges 2004 2002-2003 Steam production plant 2.55% - 3.24% 2.55% - 2.80% Hydraulic production plant 1.63% - 2.94% 0.04% - 1.56% Other production plant 4.10% - 9.81% 2.67% - 7.62% Transmission plant 1.72% - 5.26% 1.50% - 4.24% Distribution plant 2.10% - 9.98% 2.13% - 9.22% General plant 2.23% - 27.25% 2.21% - 20.40% Other 2.75% - 2.75% 2.35% - 2.75%
(1) Description of Business and Significant Accounting Policies (continued) Chugach uses remaining life rates set forth in the most recent depreciation study. In 2003 an update of the Depreciation Study was completed utilizing Electric Plant in Service balances as of December 31, 2002. The new rates were implemented and in effect for all of 2004. The new rates are currently under review by the RCA. Management believes that any change as a result of the RCA's review will not have a material impact to the financial statements. e. Capitalized Interest Allowance for funds used during construction (AFUDC) and interest charged to construction - credit (IDC) are the estimated costs during the period of construction of equity and borrowed funds. Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 4.6% during 2004, 4.8% during 2003 and 4.7% during 2002. f. 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. g. Fair Value of Financial Instruments SFAS No. 107, Disclosures About the Fair Value of Financial Instruments (SFAS 107), 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 8). (1) Description of Business and Significant Accounting Policies (continued) h. Financial Instruments and Hedging Chugach used U.S. Treasury forward rate lock agreements to hedge expected interest rates on the February 2002 debt re-financings. Chugach accounted for the agreements under SFAS 133. For rate-making purposes, Chugach did not adjust rates for gains and losses prior to settlement, and the loss on settlement will be an adjustment to rates over the lives of the associated debt. This rate-making treatment was approved by the RCA in Order U-01-108(26). See note 2, "Regulatory Matters." Accordingly, the unrealized gain or loss was not recorded and was treated as a regulatory asset upon settlement (note 6). i. Cash and Cash Equivalents For purposes of the statement of cash flows, Chugach considers all highly liquid debt instruments with a maturity of three months or less upon acquisition by Chugach (excluding restricted cash and investments) to be cash equivalents. j. Accounts Receivable Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management's best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectibility. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off-balance-sheet credit exposure related to its customers. k. Materials and Supplies Materials and supplies are stated at average cost. l. Deferred Charges and Credits Deferred charges, representing regulatory assets, are amortized to operating expense over the period allowed for rate-making purposes. In accordance with SFAS 71, Chugach's financial statements reflect regulatory assets and liabilities. Continued accounting under SFAS 71 requires that certain criteria be met. Management believes Chugach's operations currently satisfy these criteria. However, if events or circumstances should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on the financial position and results of operations. (1) Description of Business and Significant Accounting Policies (continued) Deferred credits, representing regulatory liabilities, are amortized to operating expense over the period allowed for rate-making purposes. It also includes nonrefundable contributions in aid of construction, which 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. m. Patronage Capital Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on Chugach's statement of revenues and expenses as assignable margins. These excess amounts (i.e. assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by Chugach until such future time as they are retired and returned without interest at the discretion of the Board of Directors. Retained assignable margins are designated on Chugach's balance sheet as patronage capital. This patronage capital constitutes the principal equity of Chugach. The Board of Directors may also return capital credits to former members and estates who request early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002. n. Operating Revenues Revenues are recognized when customers are billed. 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. Chugach's tariffs include provisions for the flow through of gas costs according to existing gas supply contracts, as well as purchased power costs. o. Fuel and Purchased Power Costs The expenses associated with electric services include fuel used to generate electricity and power purchased from others. These costs are expensed as used or purchased. Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel surcharge mechanism, which is adjusted quarterly to reflect increases and decreases of such costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered through rates. Fuel costs were over-recovered by $2.7 million in 2004 and under-recovered by $2.0 million in 2003. Total fuel and purchased power costs in 2004 and 2003 were approximately $85 million and $67 million, respectively. (1) Description of Business and Significant Accounting Policies (continued) p. Environmental Remediation Costs Chugach accrues for losses and establishes a liability 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. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset. q. Income Taxes Chugach 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, 2004, 2003 and 2002, Chugach received no unrelated business income. r. Reclassifications Certain reclassifications, which have no affect on assignable margins, have been made to the 2002 and 2003 financial statements to conform to the 2004 presentation. s. New Accounting Pronouncements In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS 150). This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Many of those instruments were previously classified as equity. Some of the provisions of this Statement are consistent with the current definition of liabilities in FASB Concepts Statement No. 6, Elements of Financial Statements. The remaining provisions of this Statement are consistent with FASB's proposal to revise that definition to encompass certain obligations that a reporting entity can or must settle by issuing its own equity shares depending on the nature of the relationship established between the holder and the issuer. While FASB still plans to revise that definition through an amendment to Concepts Statement 6, FASB decided to defer issuing that amendment until it has concluded its deliberations on the next phase of this project. That next phase will deal with certain compound financial instruments including puttable shares, convertible bonds, and dual-indexed financial instruments. Chugach implemented SFAS 150 effective January 1, 2004. The impact of this statement on its financial statements was immaterial. (2) Regulatory Matters Docket U-01-108 Chugach filed a general rate case on July 10, 2001, based on the 2000 test year and subsequently implemented interim and refundable rate increases as approved by the RCA. On April 15, 2002, Chugach submitted a filing with the RCA to update certain known and measurable costs and savings that had occurred outside the 2000 Test Year. In the updated filing, Chugach reduced its base rate increase request from 6.5% to 5.7%. Three wholesale customers and the Public Advocacy staff of the RCA participated in the rate case. Order No. 26 On February 6, 2003, Chugach received Order U-01-108(26) (Order 26) from the RCA. Order 26 required a refund of revenues collected in 2001 of approximately $1.1 million and revenues collected in 2002 of approximately $6.0 million, which resulted in a net operating loss of approximately $2 million in 2002. Under the Order, Chugach's financial performance for 2002 fell below the 1.10 level contained in the Rate Covenants in its currently effective indenture, the Amended and Restated Indenture, the CoBank Master Loan Agreement and the MBIA Insurance Corporation's (MBIA) Reimbursement and Indemnity Agreement. (Note 8) In accordance with the Rate Covenant in the Amended and Restated Indenture, on February 13, 2003, Chugach filed a Motion with the RCA asking the RCA to stay the effect of Order 26 until after the RCA considered Chugach's Petition for Reconsideration. On February 18, 2003, the RCA granted, in part, Chugach's motion for stay. Chugach filed the Petition for Reconsideration with the RCA on February 28, 2003. Order No. 30 On April 14, 2003, the RCA issued Order No. 30 in Docket U-01-108, significantly revising its earlier ruling. On April 28, 2003 Chugach submitted a revised revenue requirement and cost of service study in compliance with RCA Order No. 30. This order increased Chugach's revenue requirement by $3.1 million and adjusted the required refund from $7.1 million to $1.9 million. Order No. 33 On August 26, 2003, the RCA issued Order No. 33 and accepted Chugach's April 28, 2003, compliance filing subject to reducing long-term interest expense by $1.2 million associated with AFUDC/IDC. In Order No. 33, the RCA re-reversed its earlier decision regarding the treatment of AFUDC/IDC. (2) Regulatory Matters (continued) Order No. 36 Effective November 7, 2003, the RCA approved Chugach's compliance filing and final rates in this docket. As a result, and in relation to prior-approved permanent rates, Chugach's rates on a system basis increased 0.07 percent, or an increase of 3.5 percent to retail customers and a decrease of 7.9 percent to wholesale customers. The results of the RCA's decision on final rates were implemented on November 10, 2003. Appeal of RCA Orders Chugach filed a timely appeal of RCA Orders Nos. 26, 30 and 33 to the Alaska Superior Court. In its Appellant's brief dated February 18, 2004, Chugach asserted that the RCA's orders contained three errors: o The split TIER decision unduly discriminates against retail customers; o Interest expense was allocated on the basis of plant associated with G&T and Distribution rather than on the basis of debt associated with each function; and o Chugach is entitled to include all of its interest expense in rates and the RCA's offset for Interest During Construction (IDC) was not justified because nearly all of the plant that produced the IDC was in service by the time the new rate went into effect. The resolution of the first two issues would not have changed the total amount Chugach could have recovered through rates. If Chugach had prevailed on the last issue, it would have been authorized to recover approximately $1,000,000 more each year in rates. One of Chugach's wholesale customers, MEA, also appealed the RCA's orders. In its Appellant's brief, MEA argued that the RCA's decision to normalize Chugach's variable rate debt at 3.8 percent and to authorize the corresponding interest expense constitutes error based on the historical rates prevailing for Chugach's variable rate debt. If MEA had prevailed on its argument, Chugach's authorized rates would have been reduced by approximately $1,000,000 each year. After oral argument on October 8, 2004, the Alaska Superior Court upheld all decisions of the RCA. (2) Regulatory Matters (continued) Provision For Rate Refund At December 31, 2002, Chugach recorded a provision for rate refund of $7.1 million. On April 15, 2003, the RCA issued Order No. 30 in Docket U-01-108, significantly revising its earlier ruling in which $5.2 million of that provision was reversed. Between March and November of 2003, additional provisions were recorded in the amount of $3.8 million reflecting RCA decisions through Order No. 30, in addition to RCA orders that continued through the period. In October and November of 2003, Chugach's wholesale customers were refunded $5.0 million. Between March 19 and April 19, 2004, Chugach issued refunds totaling $0.6 million to its Small General Service class for customer bills rendered between January 31 and November 10, 2003. (3) Utility Plant Major classes of electric plant as of December 31 are as follows:
2004 2003 ---- ---- Electric plant in service: Steam production plant $60,462,671 $60,392,869 Hydraulic production plant 18,180,685 17,990,505 Other production plant 132,449,993 109,737,781 Transmission plant 222,338,304 215,716,581 Distribution plant 213,119,035 202,573,670 General plant 53,636,315 54,871,238 Unclassified electric plant in service* 39,575,890 77,256,535 Other 8,721,634 8,539,193 --------- --------- Total electric plant in service 748,484,527 747,078,372 Construction work in progress 25,278,388 16,560,438 ---------- ---------- Total electric plant in service and construction work in progress $773,762,915 $763,638,810 ============ ============ *Unclassified electric plant in service consists of complete unclassified of general plant, generation, transmission and distribution projects
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. (4) Investments in Associated Organizations Investments in associated organizations, which are non-marketable and accounted for at cost, include the following at December 31:
2004 2003 ---- ---- National Rural Utilities Cooperative Finance Corporation (NRUCFC) 6,095,980 6,095,980 National Bank for Cooperatives (CoBank) 5,513,192 5,125,524 NRUCFC capital term certificates 42,662 43,647 Other 116,623 116,645 ------- ------- $11,768,457 $11,381,796 =========== ===========
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. Chugach's investment in NRUCFC similarly was required by Chugach's financing arrangements with NRUCFC. (5) Deferred Charges Deferred charges, net of amortization, consisted of the following at December 31:
2004 2003 ---- ---- Debt issuance and reacquisition costs $10,981,260 $12,569,713 Refurbishment of transmission equipment 216,050 225,309 Computer software and conversion 740,771 516,249 Studies (note 14) 4,646,181 2,942,082 Business venture studies 172,578 172,216 Fuel supply negotiations 256,030 278,745 Major overhaul of steam generating unit 1,895,329 2,287,466 Environmental matters and other 74,304 88,071 Other regulatory deferred charges 1,568,380 1,613,731 --------- --------- $20,550,883 $20,693,581 =========== ===========
At December 31, 2004 and 2003, $5.6 million and $3.6 million, respectively, of total deferred charges represent regulatory assets in progress and are not currently being amortized. The majority of these charges represent costs associated with the Cooper Lake Power Plant FERC re-licensing effort. (6) Patronage Capital Chugach has an approved capital credit retirement policy, which is contained in the Chugach Financial Management Plan. This establishes, in general, a plan to return the capital credits of wholesale and retail customers based on the members' proportionate contribution to Chugach's assignable margins on an approximately 15-year rotation. At December 31, 2004, Chugach had assigned $117,979,257 of patronage capital (net of capital credit retirements). Approval of actual capital credit retirements is at the discretion of Chugach's Board of Directors. Chugach records a liability when the retirements are approved by the Board of Directors. In November 2002, the Board of Directors authorized the retirement of $2,769,568 of retail patronage for 1985. In 2003, the Board of Directors was unable to authorize a capital credit retirement due to covenant restrictions contained in the Amended and Restated Indenture of Trust. (Note 8) In November 2004, the Board of Directors authorized the retirement of $3,126,560 of retail patronage for 1985 and 1986. In December 2004, the Board of Directors authorized $125,000 for capital credits payments to those former members and estates who have requested early retirements at discounted rates under the discounted capital credits retirement plan authorized by the Board in September 2002. Estate payments in the amount of $121,629, $60,209 and $250,154 were made in 2004, 2003 and 2002, respectively. Following is a five-year summary of anticipated capital credit retirements: Year ending Total December 31, 2005 $ 3,000,000 2006 $ 3,500,000 2007 $ 5,500,000 2008 $ 5,000,000 2009 $ 5,500,000 (7) Other Equities A summary of other equities at December 31 follows:
2004 2003 ---- ---- Nonoperating margins, prior to 1967 $23,625 $23,625 Donated capital 249,624 183,633 Unclaimed capital credit retirement 6,772,743 6,511,633 --------- --------- $7,045,992 $6,718,891
(8) Debt
Long-term obligations at December 31 are as follows: 2004 2003 ---- ---- CoBank 7.76% fixed rate note maturing in 2005, with interest payable monthly $10,000,000 $10,000,000 CoBank 3.81% variable rate note maturing in 2022, with interest payable monthly and principal due annually beginning in 2003 43,189,179 44,134,179 CoBank 3.81% variable rate note, with principal due in 2007, and with interest payable monthly 5,000,000 10,000,000 2001 Series A Bond of 6.55%, maturing in 2011, with interest payable semi-annually March 15 and September 15: 150,000,000 150,000,000 2002 Series A Bond of 6.20%, maturing in 2012, with interest payable semi-annually February 1 and August 1: 120,000,000 120,000,000 2002 Series B Bond of a rate set for 28-day auction periods, maturing in 2012, with interest payable monthly and principal due annually 51,100,000 55,700,000 ---------- ---------- Total long-term obligations 379,289,179 389,834,179 Less current installments 15,931,393 5,545,000 ---------- --------- Long-term obligations, excluding current installments $363,357,786 $384,289,179 ============ ============
(8) Debt (continued) Covenants Chugach is required to comply with all covenants set forth in the Amended and Restated Indenture, dated April 1, 2001, which became effective January 22, 2003. The indenture initially governing the outstanding bonds of Chugach, 2001 Series A, 2002 Series A and 2002 Series B, provided that the bonds were secured by a mortgage on substantially all of Chugach's assets so long as any amounts remained outstanding to CoBank on bonds issued under the indenture. Upon the retirement of the bonds issued to CoBank, Chugach's outstanding bonds became subject to the Amended and Restated Indenture pursuant to which the bonds became unsecured obligations of Chugach. Chugach is also required to comply with the Master Loan Agreement between Chugach and CoBank dated December 27, 2002, pursuant to which CoBank and Chugach replaced the bonds issued to CoBank with unsecured promissory notes not governed by the indenture. CoBank returned the old CoBank bonds to Chugach on January 22, 2003. The CoBank Master Loan Agreement requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense. CoBank waived the rate covenant as of December 31, 2002, and reduced the rate covenant for 2003 from 1.10 to 1.08. Security Substantially all assets were pledged as collateral for the long-term obligations until retirement of the 1991 Series A Bonds and subsequent institution of the Amended and Restated Indenture. On January 22, 2003, the Bonds became general unsecured and unsubordinated obligations. Under the Amended and Restated Indenture, Chugach is prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on Chugach's properties and assets (other than those arising by operation of law) to secure the repayment of borrowed money or the obligation to pay the deferred purchase price of property unless Chugach equally and ratably secure all bonds subject to the Amended and Restated Indenture, except that Chugach may incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements. (8) Debt (continued) Rate The Amended and Restated Indenture requires Chugach, subject to any necessary regulatory approval, to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. The CoBank Master Loan Agreement also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense. As described under "Covenants" above, Chugach received a waiver of the rate covenant from CoBank. Margins for interest generally consist of Chugach's assignable margins plus total interest expense. If there occurs any material change in the circumstances contemplated at the time rates were most recently reviewed, the Amended and Restated Indenture requires Chugach to seek appropriate adjustments to those rates so that they would generate revenues reasonably expected to yield margins for interest equal to at least 1.10 times interest charges. In order to maintain Chugach's compliance with this covenant, Chugach took the actions described in note 2, "Regulatory Matters." Distribution to Members The Amended and Restated Indenture prohibits Chugach from making any distribution of patronage capital to Chugach's customers if an event of default under the Amended and Restated Indenture exists. Otherwise, Chugach may make distributions to Chugach's members in each year equal to the lesser of 5% of Chugach's patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach's aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach's total liabilities and equities and margins. (8) Debt (continued) Maturities of Long-term Obligations Long-term obligations at December 31, 2004, mature as follows:
Year ending Sinking Fund Sinking Fund Sinking Fund Principal Maturities Total December 31 Requirements Requirements Requirements 2001 Series A 2002 Series A 2002 Series B CoBank Promissory -------------- -------------- -------------- ----------------- Bonds Bonds Bonds Notes ----- ----- ----- ----- 2005 0 0 4,900,000 11,031,393 15,931,393 2006 0 0 5,200,000 1,125,687 6,325,687 2007 0 0 5,500,000 6,228,569 11,728,569 2008 0 0 5,900,000 1,340,725 7,240,725 2009 0 0 6,300,000 1,463,358 7,763,358 Thereafter 150,000,000 120,000,000 23,300,000 36,999,447 330,299,447 ----------- ----------- ---------- ---------- ----------- $150,000,000 $120,000,000 $51,100,000 $58,189,179 $379,289,179 ============= ============= ============ =========== ============
Short-term obligations Chugach had an annual line of credit of $20,000,000 available at December 31, 2004 and 2003, with CoBank. The CoBank line of credit expires April 30, 2005. Chugach anticipates renewing the CoBank line of credit for 2005. Chugach did not utilize this line of credit in 2004. At December 31, 2004 and 2003, there was no outstanding balance on this line of credit. In addition, Chugach had an annual line of credit of $50,000,000 available at December 31, 2004 and 2003, with NRUCFC. Chugach did not utilize this line of credit in 2004. At December 31, 2004 and 2003, there was no outstanding balance on this line of credit. The NRUCFC line of credit expires October 15, 2007. Refinancing On February 1, 2002, Chugach issued $120,000,000 of 2002 Series A Bond and $60,000,000 of 2002 Series B Bond for the purpose of redeeming $149.3 million in principal amount of the 1991 Series A Bond due 2022 to pay the redemption premium on the 1991 Series A Bond due 2022 in the amount of $13.6 million and for general working capital. The 2002 Series A Bond will mature on February 1, 2012, and bears interest at 6.20% per annum. Interest is payable semi-annually on February 1 and August 1 of each year commencing on August 1, 2002. Chugach may not redeem the 2002 Series A Bond prior to maturity. (8) Debt (continued) The 2002 Series B Bond (the "Auction Rate Bond") will mature on February 1, 2012. The Auction Rate Bond bore interest from the date of original delivery to and through February 27, 2002, at a rate established by the underwriter prior to their date of delivery and thereafter bore interest at the rate set for 28-day auction periods. The initial auction took place on February 27, 2002. The applicable interest rate for any 28-day auction period is the term rate established by the auction agent based on the terms of the auction. The Auction Rate Bond may be converted, in Chugach's discretion, to a daily, seven-day, 35-day, three-month or a semi-annual period or a flexible auction period. The Auction Rate Bond is subject to optional and mandatory redemption and to mandatory tender for purchase prior to maturity in the manner and at the times described herein. Bankers Trust Company is the auction agent and J.P. Morgan Securities Inc., acted as the initial broker-dealer for the Auction Rate Bond. The 2002 Series A Bond and the Auction Rate Bond (collectively the "Bonds") are unsecured obligations, ranking equally with Chugach's other unsecured and unsubordinated obligations. In addition, Chugach's ability is limited to secure obligations for borrowed money or the deferred purchase price of property unless Chugach equally and ratably secures Chugach's outstanding indebtedness subject to the Amended and Restated Indenture governing the Bonds. Treasury Rate Lock Agreements On March 17, 1999, Chugach entered into a U.S.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 Bond due 2022 on their optional call date (March 15, 2002). On May 11, 2001, Chugach terminated the $18.7 million 30-year U.S. Treasury portion of the Treasury Rate Lock Agreement in receipt of payment of $10,000 by Lehman. On December 7, 2001, Chugach terminated 50%, or $98.0 million, of the 10-year U.S. Treasury portion of the U.S. Treasury Rate Lock Agreement for a settlement payment of $4 million to Lehman Brothers. Chugach settled the remaining 50% of the 10-year U.S. Treasury portion of the Treasury Rate Lock Agreement for $3 million on December 19, 2001. On January 14, 2002, Chugach entered into an 18-day rate lock agreement with JP Morgan on the 2002 refinancing. Chugach terminated the rate lock on February 1, 2002, which generated a payment to Chugach of $1.2 million. The settlement payments were accounted for as regulatory assets and amortized over the life of the corresponding debt, which was authorized by the RCA in Order U-01-108(26). (9) 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:
2004 2003 ---- ---- Carrying Fair Carrying Fair Value Value Value Value Long-term obligations (including current installments) $379,289 $408,791 $389,834 $418,424
Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions. (10) Deferred Credits Deferred credits at December 31 consisted of the following:
2004 2003 ---- ---- Refundable consumer advances for construction $1,353,069 $2,528,271 Estimated initial installation costs for transformers and meters 387,336 369,153 Post retirement benefit obligation 480,900 405,700 Other 224,744 410,441 ------- ------- $2,446,049 $3,713,565 ========== ==========
(11) 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). Chugach makes annual contributions to the plans equal to the amounts accrued for pension expense. For the union plans, Chugach 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 $2,565,000 in 2004, $2,529,000 in 2003 and $2,253,000 in 2002. In 2004, 2003 and 2002, Chugach contributed $1,638,000, $1,492,000 and $1,401,000, respectively, to the NRECA plan. (12) Bradley Lake Hydroelectric Project Chugach 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. Chugach 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. Chugach has a 30.4% share of the project's capacity. The share of debt service exclusive of interest, for which Chugach has guaranteed, is approximately $41,000,000. Under a worst-case scenario, Chugach could be faced with annual expenditures of approximately $4.7 million as a result of Chugach's 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%. The following represents information with respect to Bradley Lake at June 30, 2004 (the most recent date for which information is available). Chugach's share of expenses was $4,205,657 in 2004, $4,212,072 in 2003 and $4,343,562 in 2002 and is included in purchased power in the accompanying financial statements. (In thousands) Total Proportionate Share ----- ------------------- Plant in service $ 308,966 $ 93,926 Accumulated depreciation (88,385) (26,869) Interest expense 8,782 2,670 Other electric plant in service represents Chugach's share of a Bradley Lake transmission line financed internally and Chugach's share of the Eklutna Hydroelectric Project, purchased in 1997 (note 13). (13) 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, including their corresponding interest in the project, consists of Chugach (30%), MEA (16.7%) and Anchorage Municipal Light & Power (AML&P) (53.3%). Other electric plant in service includes $1,957,742 representing Chugach'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 operation, maintenance and capital improvement costs to the plant, as well as to the transmission line between Anchorage and the plant. Under net billing arrangements, Chugach then reimburses MEA for their share of the costs. On January 22, 2004, the Eklutna Operating Committee voted to remove MEA as the operator of the plant. Chugach will provide personnel for the daily operation and maintenance of the power plant. ML&P will continue to perform major maintenance at the plant. Chugach personnel will perform daily plant inspections, meter reading, monthly report preparation, and other activities as required. (14) Commitments, Contingencies and Concentrations Contingencies Chugach is a participant in various legal actions, rate disputes, personnel matters and claims both for and against Chugach's interests. Management believes the outcome of any such matters will not materially impact Chugach's financial condition, results of operations or liquidity. Long-Term Fuel Supply Contracts Chugach has entered into long-term fuel supply contracts from various producers at market terms. The current contracts will expire at the end of the currently committed volumes or the contract expiration dates of 2015 and 2025. The committed volumes for the 2015 contract should be used by early 2011. The currently priced volumes for the 2025 contract should also be used by early 2011, however, there is an additional 120 BCF reserved if satisfactory term and conditions can be negotiated. For 2004, 86% of our power was generated from gas, and 86% of that gas-fired generation took place at Beluga. Concentrations Approximately 72% of Chugach's employees are represented by the International Brotherhood of Electrical Workers (IBEW). The various IBEW contracts expire on June 30, 2006. (14) Commitments, Contingencies and Concentrations (continued) Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts represented $62.0 million or 31.2% of operating revenues in 2004, $55.8 million or 30.8% in 2003 and $57.0 million or 33.7% in 2002. These contracts will expire in 2014. Fuel is purchased directly from Marathon Oil Company, ChevronTexaco, ML&P and ConocoPhillips. The following represents the cost of fuel purchased from these vendors as a percentage of total fuel costs for the years ended December 31: 2004 2003 2002 ---- ---- ---- Marathon Oil Company 48.8% 47.4% 45.6% Chevron Texaco 19.5% 20.0% 20.6% ML&P 15.8% 16.2% 16.6% ConocoPhillips 15.8% 16.2% 16.6% Cooper Lake Hydroelectric Plant Chugach discovered polychlorinated biphenyls (PCBs) in paint, caulk and grease at the Cooper Lake Hydroelectric plant during initial phases of a turbine overhaul. A FERC approved plan, prepared in consultation with the Environmental Protection Agency (EPA), was implemented to remediate the PCBs in the plant. In an order in Chugach's general rate case, Order U-01-108(26), the RCA permitted the costs associated with the overhaul and the PCB remediation to be recovered through rates. The costs of PCB sampling and analysis in Kenai Lake were accounted for as an expense. Legal Proceedings Matanuska Electric Association, Inc., v. Chugach Electric Association, Inc., Superior Court Case No. 3AN-99-8152 Civil This action is a claim for a breach of the Tripartite Agreement, which is the contract governing the parties' relationship for a 25-year period from 1989 through 2014 and governing Chugach's sale of power to MEA during that time. MEA asserted Chugach breached that contract by failing to provide information, by failing to properly manage Chugach's long-term debt, and by failing to bring Chugach's base rate action to a Joint Committee before presenting it to the RCA. All of MEA's claims were dismissed by the Superior Court. On April 29, 2002, MEA appealed the Superior Court's decisions relating to Chugach's financial management and Chugach's failure to bring Chugach's base rate action to the joint committee before filing with the RCA to the Alaska Supreme Court. We cross-appealed the Superior Court's decision not to dismiss the financial management claim on jurisdictional and res judicata grounds. (14) Commitments, Contingencies and Concentrations (continued) The Alaska Supreme Court, on October 8, 2004, ruled in Chugach's favor supporting its right under the power sales agreement to file for interim rate relief without first going to the Joint Committee. The Supreme Court ruled against Chugach by overturning the Superior Court's decision that dismissed MEA's claim asking for review of Chugach's management of use of rate locks instead of defeasing debt based on the Prudent Utility Practice standard under our power sales agreement. The Supreme Court remanded this issue to the Superior Court. On January 24, 2005, Chugach filed a summary judgment motion based on Chugach's claim that in the 2000 Test Year rate case the RCA has already decided the underlying issues relating to the prudency of Chugach's use of rate locks instead of defeasing debt. This motion is pending. Management is uncertain of the outcome of the proceeding before the Superior Court. Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc. Superior Court Case No. 3AN-04-11776 Civil On October 12, 2004, MEA filed suit in Superior Court alleging a breach of the power sales agreement between the parties and violation of Chugach's bylaws in connection with allocation of margins (capital credits) to MEA for the years 1998 through 2003. Allocation of capital credits assigns a share of the margins earned in a particular year to each customer. Capital credits are repatriated to customers at the discretion of the board of directors typically many years after the margins are earned. The suit seeks a declaration by the Court that Chugach is in breach of its bylaws and the power sales agreement based on its allocation of capital credits to MEA as well as injunctive relief requiring Chugach to calculate MEA's capital credit allocations based on MEA's patronage and in accordance with generally accepted accounting practices for nonprofit cooperatives and cooperative principles. The suit also seeks damages in an unspecified amount to compensate MEA for the alleged breach of contract. Management intends to vigorously defend against the claim. Management is uncertain of the outcome of the suit. Other Chugach received a demand letter from a third party offering a license to a patent and implying that the patent may be infringed by certain services provided by Chugach. The patent purportedly relates to intellectual property rights over a system for automated electronic bill presentment and payment. As of this date, no legal proceedings have been instituted against us, but if the third party's patents are valid, enforceable and apply to our business, we could be required to seek a license, discontinue certain activities or be subject to a claim for past infringement. We are currently considering this matter, but lack (14) Commitments, Contingencies and Concentrations (continued) sufficient information to assess the potential outcome at this time. Chugach has certain additional litigation matters and pending claims that arise in the ordinary course of Chugach's business. In the opinion of management, no individual matter or the matters in the aggregate is likely to have a material adverse effect on Chugach's results of operations, financial condition or liquidity. 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 governing regulatory commission, which is currently the RCA. The tax is assessed on all retail consumers and is based on kilowatt-hour (kWh) consumption. The Regulatory Cost Charge has changed since its inception (November 1992) from an initial rate of $0.000626 per kWh to the current rate of $0.000397, effective October 1, 2004. (15) Quarterly Results of Operations (unaudited)
2004 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 ------- -------- ------- -------- Operating Revenue $55,221,563 $47,991,700 $46,388,411 $51,644,941 Operating Expense 46,010,061 43,778,224 41,441,061 42,110,691 Net Interest 5,512,148 5,373,404 5,254,092 5,352,221 --------- --------- --------- --------- Net Operating Margins 3,699,354 (1,159,928) (306,742) 4,182,029 Non-Operating Margins 805,322 145,698 122,788 113,935 ------- ------- ------- ------- Assignable Margins $4,504,676 $(1,014,230) $(183,954) $4,295,964 ========== ============ ========== ========== 2003 Quarter Ended Dec. 31 Sept. 30 June 30 March 31* ------- -------- ------- --------- Operating Revenue $50,940,575 $41,163,160 $41,689,671 $50,239,007 Operating Expense 44,326,751 38,351,606 38,320,588 35,154,084 Net Interest 5,321,421 5,734,622 5,870,169 5,784,616 --------- --------- --------- --------- Net Operating Margins 1,292,403 (2,923,068) (2,501,086) 9,300,307 Non-Operating Margins 614,311 153,236 91,100 225,917 ------- ------- ------ ------- Assignable Margins $1,906,714 $(2,769,832) $(2,409,986) $9,526,224 ========== ============ ============ ========== *The increase to operating revenue described in note 2 "Regulatory Matters" was recorded in the 2003 quarter ended March 31.
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None Item 9A - Disclosure Controls and Procedures Evaluation of Controls and Procedures As of the end of the period covered by this report, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Our chief executive officer (CEO) and chief financial officer (CFO) supervised and participated in this evaluation. Based on this evaluation, our CEO and CFO each concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic reports to the SEC. The design of any system of controls is based in part upon various assumptions about the likelihood of future events, and there can be no assurance that any of our plans, products, services or procedures will succeed in achieving their intended goals under future conditions. In addition, there have been no significant changes in our internal controls or in other factors known to management that could significantly affect our internal controls subsequent to our most recent evaluation. Item 9B - Other Items None PART III Item 10 - Directors and Executive Officers of the Registrant Management Chugach operates 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 Chief Executive Officer. Our seven-member Board of Directors sets policy and provides direction to the Chief Executive Officer. The following table sets forth certain information with respect to our executive officers and directors.
Name Age Position Evan J. Griffith............................ 63 Chief Executive Officer Lee D. Thibert.............................. 49 General Manager, Distribution Division Michael R. Cunningham....................... 55 Chief Financial Officer William R. Stewart.......................... 58 Sr. Vice President, Services Division Bradley W. Evans............................ 50 General Manager, G&T Division H. A. (Red) Boucher......................... 84 Chairman and Director Bruce Davison............................... 56 Vice Chairman and Director Patricia B. (Pat) Jasper.................... 75 Secretary and Director Jeffrey W. Lipscomb......................... 54 Treasurer and Director Samuel W. Cason............................. 45 Director Christopher Birch........................... 54 Director David Cottrell.............................. 57 Director
Executive Officers Evan J. Griffith was appointed Chief Executive Officer on May 1, 2002. Prior to that appointment he had served as Executive Manager, Finance and Energy Supply since an internal reorganization on June 1, 1997. Prior to that, he was Executive Manager, Finance & Planning from August 1989 to June 1997. Prior to his Chugach employment, he was Budget/Program Analyst for the Anchorage Municipal Assembly from August 1984 to August 1989. Lee D. Thibert was appointed General Manager, Distribution Division in a January 31, 2005, reorganization. Prior to that appointment he had served as Sr. Vice President, Power Delivery since June 3, 2002. Prior to that, he had served as Executive Manager, Transmission & Distribution Network Services since June 1, 1997 reorganization. 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. William R. Stewart was appointed Sr. Vice President, Services Division in a January 31, 2005, reorganization. Prior to that appointment he had served as Sr. Vice President, Administration since June 5, 2002. Prior to that, he had served as Executive Manager, Retail Services since a June 1, 1997 reorganization. Prior to that, he was 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 at Chugach since 1969. Michael R. Cunningham was appointed Chief Financial Officer on June 5, 2002. Prior to that appointment he had served as Controller since 1986. Prior to that he was Budget Analyst and Manager of Accounting since beginning his Chugach employment in 1982. Prior to his Chugach employment, Mr. Cunningham spent 15 years in various capacities with Pacific Northwest Bell Telephone Company. Bradley W. Evans was appointed General Manager, G&T Division in a January 31, 2005, reorganization. Prior to that appointment he had served as Sr. Vice President, Energy Supply since June 5, 2002. Prior to that, he had served as Director of Energy Supply since February 26, 2001. Prior to his current Chugach employment, Mr. Evans served as Manager, System Dispatch for Golden Valley Electric Association. Board of Directors Bruce Davison serves as Vice Chairman of the Board and also chairs the board's Operations Committee. He has served as board Chairman and Secretary. Mr. Davison was first appointed to the Board of Directors in June 1997. Prior to his appointment, he served two years on our Bylaws Committee. He is an attorney and professional engineer and a partner in the law firm of Davison & Davison, Inc. Red Boucher serves as Chairman of the Board. He has served on the board since 1999 and has previously served as Vice Chairman and Vice President. In addition to being a director, Mr. Boucher is a communications consultant who owns a consulting firm. He has held many elected offices including Lieutenant Governor of Alaska. Pat Jasper serves as Secretary of the Board. She 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 former computer programmer and systems analyst. Jeff Lipscomb was elected director in April 2000 and currently serves as Treasurer and chairs the board's Finance committee. Mr. Lipscomb is a project management consultant with JWL Engineering. He is a professional mechanical engineer with over 20 years of experience in Alaskan oil and gas production facility design. Dave Cottrell has served on the board since 2001 and currently chairs the board's Audit committee. He has previously served as Vice President of the Board. Mr. Cottrell is a founding member and past managing partner of Mikunda Cottrell & Co., Certified Public Accountants. He is currently the president and managing director of Mikunda, Cottrell, Accountants and Consultants. Chris Birch was appointed to fill a board vacancy in 1996 and re-elected to that seat in 1997, 2000 and 2003. He has served as board Secretary and President and currently chairs the board's Technology committee. Mr. Birch is a professional civil engineer, licensed in Alaska since 1978 and recently retired as Director of Engineering, Environment and Planning at the Ted Stevens Anchorage International Airport. He is currently a senior engineer with Tryck Nyman Hayes, Inc. Sam Cason is a self-employed attorney. He was elected to a 3-year term on the board in 2002 and currently chairs the board's Government and External Affairs committee. Code of Ethics Chugach developed a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer and any person performing similar functions. The code of ethics was finalized June 16, 2004. It is also posted on Chugach's website at www.chugachelectric.com. Audit Committee Financial Expert Chugach is a cooperative and each board member must be a member of the cooperative. The Board of Directors relies on the advice of all members of the Finance and Audit Committees, therefore the Board of Directors has not formally designated an Audit Committee financial expert. 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 five executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2004, and for all such executive officers as a group:
Name Principal Position Year Total Remuneration Bonus Total Evan J. Griffith Chief Executive Officer 2004 $216,073 $14,848 $230,921 2003 $201,685 - $201,685 2002 $172,239 - $172,239 Lee D. Thibert General Manager, 2004 $170,312 $8,158 $178,470 Distribution Division 2003 $149,103 $5,939 $155,042 2002 $154,881 - $154,881 Michael R. Cunningham Chief Financial Officer 2004 $155,955 - $155,955 2003 $132,316 - $132,316 2002 $130,220 - $130,220 William R. Stewart Sr. Vice President, 2004 $182,741 $5,438 $188,179 Services Division 2003 $161,879 $3,712 $165,591 2002 $159,839 - $159,839 Bradley W. Evans General Manager, 2004 $148,137 $7,154 $155,291 G&T Division 2003 $135,398 $5,197 $140,595 2002 $128,227 - $128,227
Directors are compensated for their services at the rate of $200 per board meeting or other meeting at which they are representing the Association in an official capacity within the State of Alaska, and $250 per day when attending meetings outside the State, including each day of travel, plus reasonable out of pocket expenses, up to a maximum of 70 meetings per year for a director and 85 meetings per year for the Chairman. 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 or she completes 1,000 hours of service either in his or her first twelve consecutive months of employment or in any calendar year for us 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 or she 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 or she has reached his normal retirement date by completing thirty years of benefit service (defined below) or, if earlier, by attaining age sixty-two. A participant may elect to receive actuarially reduced early retirement pension benefits before his or her normal retirement date provided he or she 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 or her years of participation in the Plan (benefit service) and the highest five-year average of the annual rate of his or her base salary during the last ten years of his or her 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 or her normal retirement date is equal to the product of his or her years of benefit service 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. On October 16, 2002, the Board of Directors authorized an amendment to the Plan with an effective date of November 1, 2002. Under the amended Plan, the retirement benefit payable to any Participant whose retirement is postponed beyond his or her Normal Retirement Date shall be computed as of the Participant's actual retirement date. The retirement benefit payable to any Participant under the 30-Year Plan shall be computed as of the first day of the month in which the Participant's actual retirement date occurs. 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 35 40 -- -- -- -- -- -- $125,000 $37,500 $50,000 $62,500 $75,000 $87,500 $100,000 $150,000 $45,000 $60,000 $75,000 $90,000 $105,000 $120,000 $175,000 $52,500 $70,000 $87,500 $105,000 $122,500 $140,000 $200,000 $60,000 $80,000 $100,000 $120,000 $140,000 $160,000
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, 2004 taken into account under the Plan for the executive officers is shown below. Base salary for 2004 taken into account under the Plan for purposes of determining final average salary is also included.
Name Principal Position Benefit Service Covered Compensation Evan J. Griffith Chief Executive Officer 14 years, 4 months $193,066 Lee D. Thibert General Manager, Distribution Division 16 years, 7 months 152,006 Michael R. Cunningham Chief Financial Officer 21 years, 1 month 136,572 William R. Stewart* Sr. Vice President, Services Division 2 year, 2 months 146,016 Bradley W. Evans General Manager, General Manager, G&T Division 3 years, 10 months 142,002 * Under the Plan in effect prior to November 1, 2002, Mr. Stewart had 30 years of service as of April 1, 2000, and was no longer eligible to receive contributions on his behalf to the Plan. Under the terms of the amendment to the Plan, approved by the Board of Directors on October 16, 2002, Mr. Stewart was re-enrolled effective November 1, 2002.
Employment Arrangements In March 2004, the Board of Directors authorized the renewal of the employment agreement with Evan J. Griffith, our Chief Executive Officer, for two years with an additional one-year option. He is paid an annual base salary of $193,066. Mr. Griffith is also eligible to receive additional compensation, bonus and benefits for meeting performance goals established annually by the Board of Directors. Item 12 - Security Ownership of Certain Beneficial Owners and Management Not Applicable Item 13 - Certain Relationships and Related Transactions Not Applicable Item 14 - Principal Accountant Fees and Services The Audit Committee of the Board of Directors retained KPMG LLP as the independent certified public accountants for Chugach during the fiscal year ended December 31, 2004. Fees and Services KPMG LLP has provided certain audit, audit-related, tax and non-audit services, the fees for which are as follows: 2004 2003 ---- ---- Audit services and quarterly reviews $93,075 $65,400 Audit-related services (registration statement) $0 $0 Non-audit services: Single audit and employee benefit plans $8,250 $15,850 Tax consulting and return preparation $2,250 $2,500 The Audit Committee of the Board of Directors has a policy to pre-approve all invoices by Chugach's independent public accountants. All invoices from KPMG LLP for fiscal years ended December 31, 2004 and 2003 were approved by the Audit Committee. PART IV Item 15 - Exhibits and Financial Statement Schedules Page Financial Statements Included in Part IV of this Report: Independent Auditors' Report 37 Balance Sheets, December 31, 2004 and 2003 38-39 Statements of Revenues, Expenses and Patronage Capital, Years ended December 31, 2004, 2003 and 2002 40 Statements of Cash Flows, Years ended December 31, 2004, 2003 and 2002 41 Notes to Financial Statements 42-64 Financial Statement Schedules Included in Part IV of this Report: Independent Auditors' Report 74 Schedule II - Valuation and Qualifying Accounts, Years ended December 31, 2004, 2003 and 2002 75 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. Independent Auditors' Report The Board of Directors Chugach Electric Association, Inc. We have audited the accompanying balance sheets of Chugach Electric Association, Inc. (the Company) as of December 31, 2004 and 2003, 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, 2004. In connection with our audits of the financial statements, we have also audited the financial statement schedule listed in Item 15 herein. These financial statements and financial statement schedule are the responsibility of the Company'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 generally accepted auditing standards as established by the Auditing Standards Board (United States) and in accordance with the auditing standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. 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, 2004 and 2003, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2004, in conformity with U.S. generally accepted accounting principles. 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 11, 2005 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, 2004 (273,793) (202,533) 112,065 (364,261) December 31, 2003 (313,545) (326,842) 366,594 (273,793) December 31, 2002 (318,757) (344,472) 349,684 (313,545)
EXHIBITS Listed below are the exhibits, which are filed as part of this Report:
Exhibit Number Description 3.1 Articles of Incorporation of the Registrant. (13) 3.2 Bylaws of the Registrant. (18) 4.11 Tenth Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. (11) 4.12 Eleventh Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association. (14) 4.13 Amended and Restated Indenture between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. (11) 4.14 Form of 2001 Series A Bond due 2011. (11) 4.15 Form of 2002 Series A Bond due 2012. (14) 4.16 Form of 2002 Series B Bond due 2012. (14) 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. (1) 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. (8) 10.4.1 Amendment No. 1 to Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective as of July 9, 2001. (13) 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) 10.5.1 Assignment of 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 June 30, 2003. (19) 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. (1) 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. (11) 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. (1) 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. (11) 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. (8) 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. (1) 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. (11) 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. (8) 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. (1) 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. (8) 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. (1) 10.18 Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. (11) 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. (1) 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. (11) 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) 10.24.1 Partial Assignment of Bradley Lake Hydroelectric Project 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 June 30, 2003. (19) 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) 10.25.1 Partial Assignment of Bradley Lake Hydroelectric Project 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 June 30, 2003. (19) 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) 10.29.1 Assignment of 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 June 30, 2003. (19) 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. (1) 10.33 Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. (3) 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. (1) 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. (8) 10.39.1 Second Amendment to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 1, 2001. (13) 10.39.2 Assignment of Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19) 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) 10.44 Line of Credit Agreement and Promissory Note between the Registrant and the National Bank for Cooperatives dated May 5, 1993. (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 dated April 18, 1994. (1) 10.44.3 Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated May 1, 1995. (1) 10.44.4 Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated May 15, 1995. (1) 10.44.5 Amendment to Line of Credit Agreement between the Registrant and CoBank, ACB dated September 30, 2000. (10) 10.44.6 Amendment to Line of Credit Agreement between the Registrant and CoBank, ACB dated December 27, 2002. (18) 10.45.1 Master Loan Agreement between the Registrant and CoBank, ACB dated December 27, 2002. (17) 10.45.2 Promissory Note and Consolidating Term Loan Supplement between the Registrant and CoBank, ACB dated December 27, 2002. (17) 10.47 Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 15, 2002. (17) 10.52 Employment Agreement between the Registrant and Evan J. Griffith dated effective April 21, 2004. (20) 14 Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. (21) 31.1 Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (1) Previously filed as an exhibit to 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 (File No. 333-57400) dated March 22, 2001. (12) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated March 31, 2001. (13) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated June 30, 2001. (14) Previously filed as an exhibit to the Registrant's Registration Statement on Form S-1 (File No. 333-75840) dated December 21, 2001. (15) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated June 30, 2002. (17) Previously filed as an exhibit to the Registrant's Annual Report on Form 10-K dated December 31, 2002. (18) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated March 31, 2003. (19) Previously filed as an exhibit to the Registrant's Annual Report on Form 10-K dated December 31, 2003. (20) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated March 31, 2004. (21) Previously filed as an exhibit to the Registrant's Quarterly Report on Form 10-Q dated June 30, 2004.
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 31, 2005. CHUGACH ELECTRIC ASSOCIATION, INC. By: /s/ Evan J. Griffith Evan J. Griffith, Chief Executive Officer Date: March 31, 2005 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 31, 2005, by the following persons on behalf of the registrant in the capacities indicated: /s/ Evan J. Griffith Evan J. Griffith Chief Executive Officer (Principal Executive Officer) /s/ Lee D. Thibert Lee D. Thibert General Manager, Distribution Division /s/ Michael R. Cunningham Michael R. Cunningham Chief Financial Officer (Principal Financial Officer) /s/ William R. Stewart William R. Stewart Senior Vice President, Services Division /s/ Bradley W. Evans Bradley W. Evans General Manager, G&T Division /s/ H. A. Boucher H. A. Boucher Director & Chairman of the Board /s/ Bruce Davison Bruce Davison Director & Vice Chairman of the Board /s/ Patricia B. Jasper Patricia B. Jasper Director & Secretary of the Board /s/ Jeffrey Lipscomb Jeffrey Lipscomb Director & Treasurer of the Board /s/ Samuel W. Cason Samuel W. Cason Director /s/ David Cottrell David Cottrell Director /s/ Christopher Birch Christopher Birch 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 2004 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. EX-31 2 sec200410kexh311.txt CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) I, Evan J. Griffith, certify that: 1. I have reviewed this annual report on Form 10-K of Chugach Electric Association, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for Chugach, and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Chugach is made known to us, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of our disclosure controls and procedures and presented in this report our conclusions about the effectiveness of our disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) disclosed in this report any change in our internal control over financial reporting that occurred during the fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting; and 5. The other certifying officers and I have disclosed, based on our most recent evaluation, to our auditors and the audit committee of our Board of Directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the our ability to record, process, summarize and report financial data and have identified for our auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in our internal controls. Date: March 31, 2005 /s/ Evan J. Griffith ----------------- Evan J. Griffith Chief Executive Officer Principal Executive Officer EX-31 3 sec200410kexh312.txt CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002) I, Michael R. Cunningham, certify that: 1. I have reviewed this annual report on Form 10-K of Chugach Electric Association, Inc.; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for Chugach, and we have: a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to Chugach is made known to us, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of our disclosure controls and procedures and presented in this report our conclusions about the effectiveness of our disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and c) disclosed in this report any change in our internal control over financial reporting that occurred during the fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting; and 5. The other certifying officers and I have disclosed, based on our most recent evaluation, to our auditors and the audit committee of our Board of Directors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the our ability to record, process, summarize and report financial data and have identified for our auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in our internal controls. Date: March 31, 2005 /s/ Michael R. Cunningham ---------------------- Michael R. Cunningham Chief Financial Officer Principal Financial Officer EX-32 4 sec200410kexh321.txt CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) In connection with the annual report on Form 10-K of Chugach Electric Association, Inc. (the "Company") for the year ended December 31, 2004, as filed with the Securities and Exchange Commission (the "Report"), I, Evan J. Griffith, Chief Executive Officer and Principal Executive Officer of the Company, hereby certify as the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge: (1) the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated. Date: March 31, 2005 /s/ Evan J. Griffith ----------------- Evan J. Griffith Chief Executive Officer Principal Executive Officer EX-32 5 sec200410kexh322.txt CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002) In connection with the annual report on Form 10-K of Chugach Electric Association, Inc. (the "Company") for the year ended December 31, 2004, as filed with the Securities and Exchange Commission (the "Report"), I, Michael R. Cunningham, Chief Financial Officer and Principal Financial Officer of the Company, hereby certify as the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge: (1) the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and (2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated. Date: March 31, 2005 /s/ Michael R. Cunningham ---------------------- Michael R. Cunningham Chief Financial Officer Principal Financial Officer -----END PRIVACY-ENHANCED MESSAGE-----