-----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, Pz283Xtyt/0zAcwH2hSh9fYU1E3OxKmlj8t1GPHMW1iONAx5ezGVhSgXaPPusdj3 NNOxdwTFhb07Bz7ZTzek5A== 0000878004-01-000005.txt : 20010410 0000878004-01-000005.hdr.sgml : 20010410 ACCESSION NUMBER: 0000878004-01-000005 CONFORMED SUBMISSION TYPE: 10-K/A PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010409 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/A SEC ACT: SEC FILE NUMBER: 033-42125 FILM NUMBER: 1598155 BUSINESS ADDRESS: STREET 1: 5601 MINNESOTA DR STREET 2: PO BOX 196300 CITY: ANCHORAGE STATE: AK ZIP: 99518 BUSINESS PHONE: 9075637494 10-K/A 1 0001.txt FORM 10-K/A AMENDMENT #1 FOR CHUGACH ELECTRIC UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K/A (AMENDMENT NO. 1) (x) Annual Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 2000 ( ) Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from_____________________to___________________________ Commission file Number 33-42125 Chugach Electric Association, Inc. (Exact name of registrant as specified in its charter) Alaska 92-0014224 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 5601 Minnesota Drive, Anchorage, Alaska 99518 (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (907) 563-7494 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered ---------------------------- --------------------------------------------- ---------------------------- --------------------------------------------- Securities registered pursuant to Section 12(g) of the Act: - -------------------------------------------------------------------------------- (Title of class) - -------------------------------------------------------------------------------- (Title of class) Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securites Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. /x/ Yes / / No Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. N/A State the aggregate market value of the voting stock held by non-affiliates of the registrant. The aggregate market value shall be computed by reference to the price at which the stock was sold, or the average bid and asked prices of such stock, as of a specified date within 60 days prior to the date of filing. (See definition of affiliate in Rule 405, 17 CFR 230.405). N/A CHUGACH ELECTRIC ASSOCIATION, INC. 2000 Form 10-K/A (Amendment No. 1) Annual Report Table of Contents PART I Page Item 1 - Business 1 PART II Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations 9 Item 7A - Quantitative and Qualitative Disclosures About Market Risk 18 SIGNATURES 20 INTRODUCTORY STATEMENT Chugach Electric Association, Inc. hereby amends Items 1, 7 and 7A of its Form 10-K for the fiscal year ended December 31, 2000, as filed with the Securities and Exchange Commission on March 30, 2001, to correct MWh energy sales to customers stated in Item 1 and Item 7. Chugach has also included an update to current interest rates stated in Item 7, the value of the Treasury-rate lock agreement stated in Item 7 and the current amount of short-term debt outstanding as stated in Item 7A. PART I Item 1 - Business General Chugach Electric Association, Inc., is the largest electric utility in Alaska. We are engaged in the generation, transmission and distribution of electricity to approximately 71,800 metered locations in the Anchorage and upper Kenai Peninsula areas. Through an interconnected regional electrical system, our energy is distributed throughout Alaska's Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska's largest cities, Anchorage and Fairbanks. Neither we nor any other electric utility in Alaska has any connection to the electric grid of the mainland United States or Canada. Through direct service to retail customers and indirectly through wholesale and economy energy sales, we provide some or all of the electricity used by approximately two-thirds of Alaska's electric customers. We also supply much of the power requirements of three wholesale customers, Matanuska Electric Association ("MEA"), Homer Electric Association ("HEA") and the City of Seward ("Seward"). In addition, on a periodic basis, we provide electricity to Anchorage Municipal Light & Power ("AML&P"). AML&P has about 30,000 meters. We have approximately 511 megawatts of installed generating capacity provided by 17 generating units at our five owned power plants: Beluga Power Plant, Bernice Lake Power Plant, International Generating Station, Cooper Lake Hydroelectric Plant and Eklutna Hydroelectric Project, in which we own a 30% interest. Approximately 96% (by rated capacity) of our generating capacity is fueled by natural gas, which we purchase under long-term gas contracts. The remainder of our generating resources are hydroelectric facilities. In 2000, approximately 85% of our energy was generated at our Beluga facility. We purchase up to 27.4 megawatts from the Bradley Lake Hydroelectric Project and up to 40 megawatts from the Nikiski power plant on the Kenai Peninsula. We operate 1,602 miles of distribution line and 402 miles of transmission line. For the year ended December 31, 2000, we sold 2.4 billion kilowatt hours ("kWh") of power. We were organized as an Alaska electric cooperative in 1948. Cooperatives are business organizations that are owned by their members. As not-for-profit organizations, cooperatives are intended to provide services to their members at cost, in part by eliminating the need to produce profits or a return on equity. Today, cooperatives operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and credit. All cooperatives are based upon similar principles and legal foundations. Because members' equity is not considered an investment, a cooperative's objectives and policies are oriented to serving member interests, rather than maximizing return on investment. Our members are the consumers of the electricity sold by us. As of December 31, 2000, we had approximately 57,900 retail members receiving service at approximately 71,800 metered locations and three major wholesale customers. No individual retail customer receives more than 5% of our power. Our business and affairs are managed by the General Manager and are overseen by a seven-member Board of Directors. Directors are elected at large by the membership and serve three-year staggered terms. Each member is entitled to one vote. In addition to voting for directors, members have voting rights with respect to mergers and the sale, lease, or other disposition (except by mortgage or deed of trust) of all or a substantial portion of our property. Our customers are billed per a tariff rate on a monthly basis for electrical power consumed during the preceding month. Billing rates are approved by the Regulatory Commission of Alaska ("RCA") (see "Rate Regulation and Rates" below). Rates (derived from the historic cost of service basis) may generate revenues in excess of current period costs (net operating margins and nonoperating margins) in any year and such excess is designated on our Statements of Revenues, Expenses and Patronage Capital as "assignable margins." Retained assignable margins are designated on our balance sheet as "patronage capital" that is assigned to each member on the basis of patronage. We are a rural electric cooperative that is exempt from federal income taxation as an organization described in Section 501(c)(12) of the Internal Revenue Code ("Code"). Alaska electric cooperatives must pay to the State of Alaska, in lieu of state and local ad valorem, income and excise taxes, a tax at the rate of $0.0005 per kWh of electricity sold in the retail market during the preceding year. In addition, we collect a regulatory cost charge of $.000318 per kWh of retail electricity sold. This charge is assessed to fund the operations of the RCA. It is a pass-through and thus does not impact our margins. Our workforce consists of approximately 355 full -time employees. Approximately two-thirds of our employees are members of the International Brotherhood of Electrical Workers ("IBEW"). We have three collective bargaining agreements with the IBEW that are in effect through June 30, 2003. We also have an agreement with Hotel Employees, Restaurant Employees, Local 878 in effect through June 30, 2003. We believe our relationship with our employees is good. Our Service Areas Our service areas and those of our wholesale and economy energy customers are often described collectively as the Railbelt region of Alaska because the three geographic areas (the Southcentral, the Kenai Peninsula and the Interior) are linked by the Alaska Railroad. Anchorage is the trade, service and financial center for most of Alaska and serves as a major center for many state governmental functions. Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, air and rail transportation facilities and headquarters support for the petroleum, mining and other basic industries located elsewhere in the state. The Matanuska-Susitna Borough is immediately north of the Municipality of Anchorage, centered around the communities of Palmer and Wasilla. Although agriculture, tourism, mining and forestry are factors in the economy of the Matanuska-Susitna Borough, the economic well-being of the area is closely tied to that of Anchorage and many Matanuska-Susitna residents commute to jobs in Anchorage. The Kenai Peninsula is south of Anchorage with an economy substantially independent of the Anchorage area. The most significant basic industry on the Kenai Peninsula is the production and processing of petroleum products from the Cook Inlet region. Other important basic industries include tourism and fish harvesting and processing. Principal communities on the Kenai Peninsula are Homer, Seward, Kenai and Soldotna. Fairbanks is the center of economic activity for the central part of the state (known as the Interior). Fairbanks (250 air miles north of Anchorage and about 400 air miles south of Alaska's northern border) is Alaska's second largest city. Basic economic activities in the Fairbanks region include federal and state government and military operations, the University of Alaska, tourism and support of natural resource development in the Interior and northern parts of the state. Recently a major gold mine commenced operation near Fairbanks. The Trans-Alaska Pipeline System (which transports crude oil) passes near Fairbanks on its route from the North Slope oilfield to Valdez. Competition Nationwide, the electric utility industry is entering a period of unprecedented upheaval and restructuring. We have taken several steps to be more effectively positioned to meet the challenge of a competitive market for electricity. We have been active at the Alaska Legislature in support of the customer's right to choose their electric power supplier. For example, we have requested access over a neighboring utility's distribution and transmission system and asked the RCA to enforce the request. The RCA ruled that retail competition is permitted in Alaska only after prior review and approval by the RCA. We are appealing this ruling in the courts. Virtually all other Alaskan utilities have opposed our efforts to develop competition and are treating their service territories as exclusive. At this time no bill relating to customer choice has moved out of legislative committee. It is not possible to predict the outcome of this legislative process. We have made organizational changes in preparation for competition. Recognizing that the new marketplace will probably be "unbundled" along the functional lines of generation, transmission and distribution and retail services, our organizational structure reflects these functions. Operating with three divisions: Finance and Energy Supply, Transmission and Distribution Network Services and Retail Services, we have positioned ourselves to meet competition in the electric industry. We continue to operate a key account program for larger customers and are developing new services to enhance existing customers' satisfaction. It is our objective to continually improve the efficiency and cost effectiveness of our operations. We participate in customer satisfaction surveys, benchmark the performance of system operations against an international peer group and perform studies on how to implement business process best practices. These ongoing programs focus on distribution and transmission lines, substations, power plants, fleet operations and administrative services. Rate Regulation and Rates We are subject to rate regulation by the RCA. We can seek increases in our demand and energy charges by filing general rate cases with the RCA. While the formal ratemaking process typically takes nine months to one year, it is within the RCA's authority to authorize, after a notice period, rate changes on an interim, refundable basis. In addition, the RCA has been willing to open limited reviews of matters to resolve specific issues from which expeditious decisions can often be rendered. The RCA has exclusive regulatory control of our rates, subject to appeal to the Alaska Superior Court and the Alaska Supreme Court under the Alaska Administrative Procedures Act. Under Alaska law, financial covenants of an Alaskan electric cooperative contained in a debt instrument will be valid and enforceable, and rates set by the RCA must be adequate to meet those covenants. We will continue to recover changes in our fuel and purchased power expenses through routine fuel surcharge filings with the RCA. See "Management's Discussion and Analysis - Results of Operations - Rate Regulation and Rates." The 1991 Indenture governing all of our outstanding bonds requires us to set rates designed to yield margins for interest equal to at least 1.20 times total interest expense. The authorized rate-setting Times Interest Earned Ratio ("TIER") level of 1.35 has allowed us to achieve margins for interest greater than 1.20. For the year ended December 31, 2000, our achieved TIER was 1.39. Sales to Customers The following table shows the energy sales to and electric revenues from our retail, wholesale, and economy energy customers for the year ended December 31, 2000: Percent of Total MWh 2000 Revenues 2000 Revenues Direct retail sales: Residential........ 509,799 $ 51,288,657 33% Commercial......... 586,352 47,248,033 31% Total.............. 1,096,151 $ 98,536,690 64% Wholesale sales: MEA................ 549,517 $ 27,252,051 17% Homer.............. 436,112 19,060,244 12% Seward............. 59,453 2,369,550 2% Total.............. 1,045,082 $ 48,681,845 31% Economy energy sales(1).. 267,855 $ 7,820,998 5% Total sales to customers. 2,409,088 $155,039,533 100% Miscellaneous energy revenue ------ $ 2,331,133 Total energy revenues $157,370,666 (1) All economy sales were made to GVEA. Retail Customers Service Territory Our retail service area covers the populated areas of Anchorage (other than downtown Anchorage) as well as remote mountain areas and villages. The service area ranges from the northern Kenai Peninsula on the south, to Tyonek on the west, to Whittier on the east and to Fort Richardson on the north. Customers. We directly serve approximately 71,800 meters. We have approximately 57,900 members (some members are served by more than one meter). Our customers are primarily urban and suburban. The urban nature of our customer base means that we have a relatively high customer density per line mile. Higher customer density means that fixed costs can be spread over a greater number of customers. As a result of lower average costs attributable to each customer, we benefit from a greater stability in revenue, as compared to a less dense distribution system in which each individual customer would have a more significant impact on operating results. For the past five years no retail customer accounted for more than 5% of our revenues. Wholesale Customers We are the principal supplier of power to MEA, Seward and Homer under separate wholesale power contracts. For 2000, our wholesale power contracts produced $47.4 million in revenues, representing 31% of our revenues and 43% of our total kWh sales to customers. MEA and Homer We have two power sales contracts with AEG&T and each of MEA and Homer. AEG&T is a generation and transmission cooperative formed by MEA and Homer. Under each of these contracts, we sell power to AEG&T, which resells the power to MEA and Homer. Each of MEA and Homer is obligated to pay us for the power sold to AEG&T for its use if AEG&T does not pay. Our contract for the benefit of MEA obligates MEA (through AEG&T) to purchase all of its electric power and energy requirements from us. Contractually, MEA has the right, on advance notice and subject to RCA approval, to convert to a net requirements purchaser of power, and as such MEA would be obligated to buy its needed power from us net of its power needs satisfied from any of its own or AEG&T's resources. The notice period required for such conversion may be up to five years, depending on which non-Chugach resources MEA proposes to use to satisfy its power needs. After conversion to a net requirements purchaser under the contract, MEA cannot reduce the payment for power it purchases from us below a certain minimum amount. If MEA converts to net requirements service, MEA will be required to pay demand charges based upon the highest post-1985 historical coincident peak on the MEA system. Therefore, we will continue to recover fixed costs if MEA converts to net-requirements service. Also, our revenues from energy sales to MEA would partially decline in proportion to the reduction in the energy sold, but this decline would be offset to an extent by savings in the variable costs associated with energy production. MEA also has the right, on seven years advance notice and subject to RCA approval, to convert to a take-or-pay purchase of a fixed amount of power, also subject to minimum payment requirements associated with prior purchases. The MEA contract is in effect through December 31, 2014. This contract does not protect us against loss of load resulting from retail competition in MEA's distribution service territory if retail competition is ever permitted in Alaska. It is not possible at this time to estimate the potential impact on our revenues that could result from such competition. See "Competition" above. During the past several years, we have had numerous disputes and engaged in substantial litigation with MEA regarding many aspects of our contractual relationship with it. For example, in October 1998, the Board of Directors of MEA announced that it had offered to acquire Chugach. Our Board of Directors rejected the MEA acquisition proposal. MEA circulated a petition and gathered a sufficient number of signatures from our members so that a special meeting of our members was called for the purpose of considering MEA's proposal. This meeting was held November 18, 1999, at which time our members overwhelmingly rejected the MEA proposal. No further action regarding this offer has been initiated by MEA. For a discussion of material pending litigation between MEA and us, refer to Part I, Item 3 - "Legal Proceedings," of the Form 10-K filed by Chugach with respect to the annual report for the period ending December 31, 2000. Our contract for the benefit of Homer obligates Homer (through AEG&T) to take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per year. The Homer contract includes certain limitations on the costs that may be included in our rates charged to Homer. The Homer contract expires on January 1, 2014. Homer's remaining resource requirements are provided by AEG&T's Nikiski cogeneration facility and AEG&T's entitlement for power from the Bradley Lake hydroelectric project for the benefit of Homer. In February 1999, we entered into a dispatch agreement with AEG&T to operate the Nikiski unit as a Chugach system resource. The agreement provides that, in addition to the energy that we already sell to AEG&T and Homer, we will sell energy to AEG&T equal to Homer's residual energy requirements less its allocated share of the Bradley Lake project, up to a maximum of 320,000 MWh per year. A portion of the Nikiski unit output may be dispatched for Homer needs in excess of the sum of our contract demand plus Homer's share of energy from the Bradley Lake project. The dispatch agreement will terminate in 2014 coincident with our power supply contract for the benefit of Homer. Seward We currently provide nearly all the power needs of the City of Seward. In February 1998, we entered into a new power sales agreement with Seward that allows us to interrupt service to Seward up to 12 times per year and provides for a 1/3 reduction in the demand charge (approximately $350,000 annually). This agreement expires September 1, 2001, but we have negotiated an amendment to the agreement that will extend its term to January 31, 2006. The amendment was fully executed on December 12, 2000, and subsequently filed for approval with the RCA on February 5, 2001, and will be effective upon approval by the RCA. Economy Customers Since 1988, we have sold nonfirm (economy) energy to Golden Valley Electric Association ("GVEA") under an agreement that expires in 2008. Under the agreement, we use available generating capacity in excess of our own needs to produce electric energy for sale to GVEA, which uses that energy to serve its own loads in place of more expensive energy that GVEA would otherwise generate itself or purchase from other sources. We use gas purchased from Marathon Oil Company ("Marathon") to produce energy for sale to GVEA, and we charge GVEA a rate sufficient to recover the gas cost, the costs of incremental operations and maintenance expense resulting from increased use of our generators for GVEA, and an agreed-upon markup or margin for each kWh sold. In 2000, the RCA approved an amendment to our agreement with GVEA and a settlement of an inter-utility dispute involving it. As a result, the market for economy energy sold to GVEA has now been divided into two parts. The larger part continues to be governed by our agreement with GVEA, which assures us of priority in sales of such energy to GVEA. In general, we are assured of selling to GVEA two-thirds of the first 450,000,000 kWh of economy energy and 80% of the excess over 450,000,000 kWh of economy energy that GVEA purchases each year if we are capable of producing that energy. Remaining economy energy sales to GVEA have now become the "Economy Energy Spot Market." Sales in the Economy Energy Spot Market are completely competitive among potential sellers of economy energy to GVEA. Neither we nor any other seller enjoys a contractual priority in making such sales. One of those sellers, AML&P, is expected to dominate sales to GVEA in the Economy Energy Spot Market for the immediate future, partly because AML&P prices its gas at less than the Marathon gas on which we rely in making such sales. Load Forecasts The following table sets forth our projected load forecasts for the next five years: Load (MWh) 2001 2002 2003 2004 2005 Retail....... 1,118,259 1,138,639 1,162,634 1,187,001 1,213,582 Wholesale.... 1,114,376 1,179,616 1,206,385 1,234,757 1,263,427 Economy...... 260,000 260,000 260,000 260,000 260,000 Losses....... 138,428 142,505 145,613 148,847 152,218 Total.....2,631,063 2,720,760 2,774,632 2,830,605 2,889,227 Sales are expected to increase over the next five years principally due to economic growth in the service sector. Based on a study by University of Alaska, our total energy requirements are expected to grow at an average compounded annual rate of 2.6% from 2001 to 2005--retail sales at 2.1% and wholesale sales at 3.2%. Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations Results Of Operations Overview Margins. We operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation and principal and interest on our indebtedness and to provide for the establishment of reasonable margins and reserves. Patronage capital, the retained margins of our members, constitutes our principal equity. Rate Regulation and Rates. Our rates are made up of two components: "base rates" composed of demand and energy charges; and a "fuel surcharge" that takes into account the rise and fall of fuel and purchased power costs. The RCA regulates the rates paid by our wholesale and retail customers under base rates and approves the quarterly fuel surcharge filing authorizing rate changes in the fuel surcharge calculations. Base Rates. We recover operating and maintenance and other non-fuel and purchased power costs through our base rate established through a general rate case process or through other normal RCA procedures. While the formal ratemaking process typically takes nine months to one year, it is within the RCA's authority to authorize, after a notice period, rate changes on an interim and refundable basis. In addition, the RCA has been willing to open limited reviews to resolve specific issues from which expeditious decisions can often be generated. Our base rates to our retail customers have not increased since 1994. Our base rates to our wholesale customers have been subject to periodic adjustment based on an order from the RCA. We will file a new general rate case at the end of the second quarter of 2001 that, when adjudicated, may result in a modest rate increase. Our annual base rate changes, excluding fuel surcharges, for retail and wholesale classes, for the years 1998 through 2000 were as follows: 2000 1999 1998 Retail 0.00% 0.00% 0.00% Wholesale: Homer (0.70%) (0.30%) 0.00% MEA (0.80%) (3.80%) (0.20%) Seward 0.00% 0.00% (15.00%) The rate reductions to Matanuska Electric Association ("MEA") and Homer result from the operation of a Settlement Agreement dated effective as of November 21, 1996 as amended, among us, MEA, Homer and AEG&T (the "Settlement Agreement"). The Settlement Agreement was designed to resolve a number of ratemaking disputes and assure MEA and Homer that their base rates through 1999 would be no higher than those based on 1995 costs and would be reduced and refunds given if our 1996, 1997 or 1998 test year costs to serve their needs were significantly reduced. The Settlement Agreement has not operated as we intended, because the RCA has required us to make filings of our cost of service to facilitate determination of over- or under-collection based on the 1996, 1997 and 1998 test years. The rate reductions shown in the table for MEA and Homer in 1999 and 2000 relate to the first filing under the Settlement Agreement based on 1996 costs. Our calculations based on 1996 costs indicated that a rate reduction was required and that a refund was owed for the previous periods. We recorded provisions for wholesale rate refunds that totaled $2,651,361 at December 31, 1999. Early in 2000, we issued refunds of $86,132 to Homer and $1,809,801 to MEA that represented uncontested amounts owed consistent with the 1996 test year filing. In June 2000, the RCA issued a final order approving our 1996 test year cost of service. As a result of this order, we issued additional refunds to MEA and Homer in the amounts of $332,157 and $503,272, respectively, on July 25, 2000. Consistent with the Settlement Agreement, these refunds were based on demand and energy purchases retroactive to January 1, 1997. The rate reduction to Seward in 1998 was the result of a contract renegotiation through which Seward moved from being a firm customer to an interruptible customer. The rate reduction reflects the reduced cost of service to serve Seward since the Seward load can be interrupted. Fuel Surcharge. Fuel and purchased power costs are passed directly to our wholesale and retail customers through the fuel surcharge. Changes in these costs are due to fuel price adjustment mechanisms in our gas supply contracts based on factors like inflation or other market conditions. We pass these costs directly to our retail and wholesale customers, resulting in either a direct increase or decrease to our system revenues. The fuel surcharge is approved on a quarterly basis by the RCA. There are no limitations on fuel surcharge rate changes. Increases in our fuel and purchased power costs result in increased revenues while decreases in these costs result in lower revenues. Therefore, revenue from the fuel surcharge normally does not impact margins. The RCA ordered retroactive refunds in the approximate amount of $1.2 million because of alleged overcollection of fuel surcharges in 1995, 1996 and 1997. We appealed that finding to the Superior Court, which overturned the RCA's ruling. While the RCA did not appeal the decision, our wholesale customer, MEA did appeal that decision to the Alaska Supreme Court. MEA filed a brief in support of its claim in January 2001. We filed our brief on March 14, 2001. No hearing date has been set by the court. Year ended December 31, 2000 compared to the years ended December 31, 1999 and 1998 Revenues Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2000, operating revenues were $159 million, or 11%, higher than in 1999 primarily due to increased sales of economy energy to Golden Valley Electric Association ("GVEA") following the shutdown of the Healy Clean Coal Project (the "Healy Plant") in February 2000, higher recoverable fuel and purchased power costs and increased revenue generated by our non-traditional business ventures. In 1999, operating revenues were $143 million, or 0.57%, higher than in 1998. Retail base rates for demand and energy did not change in 1999 while base rates for demand and energy charged to MEA and Homer decreased slightly. Revenues and power sold were as follows for the years ended December 31: Year MWH Sold Operating Revenues 2000 2,409,088 $158,541,114 1999 2,190,253 $142,644,327 1998 2,055,963 $141,825,373 We make economy sales to GVEA. These sales commenced in 1988 and have contributed to our growth in operating revenues. We do not take such economy sales into consideration in our long-range resource planning process because these sales are non-firm sales that depend on GVEA's need for additional energy and our available generating capacity at the time. In 2000, 1999, and 1998, economy sales to GVEA constituted approximately 5.03%, 0.79%, and 0.92%, respectively, of our sales revenues. The increase in economy sales in 2000 from 1999 is due primarily to the shutdown of the Healy Plant, increasing the need for GVEA to make economy purchases. The Healy Plant is a 50 megawatt demonstration project in Healy, Alaska on the Alaska Intertie between Fairbanks and Anchorage. Following the test period in 1998, GVEA asserted that the demonstration was not successful. Litigation ensued and the Healy Plant has been shutdown since that time pending further analysis of alternatives for its operation. As a result, GVEA began buying economy energy from us at the time of the Healy Plant shutdown. Expenses The major components of our operating expenses for the years ended December 31, 2000, 1999 and 1998 were as follows: 2000 1999 1998 Power production $ 52,726,374 $ 40,301,607 $ 45,261,450 Purchased power 9,152,248 8,581,979 8,462,835 Transmission 3,828,630 3,813,438 2,771,652 Distribution 9,774,860 9,400,618 8,876,890 Consumer accounts 5,275,455 4,387,421 4,177,980 Sales expense 1,112,804 1,227,908 1,125,410 Administrative, general and other 21,343,393 22,892,479 17,592,829 Depreciation 23,216,509 19,851,436 22,468,395 Total operating expenses $126,430,273 $110,456,886 $110,737,441 Power production expense increased in 2000 from 1999 by $12.4 million, or 31%, due primarily to an increase in fuel expense from $29.6 million in 1999 to $42.5 million in 2000, which resulted from an average 40% increase in fuel prices from 1999 to 2000. Power production expense decreased by $4.9 million, or 11%, in 1999 from 1998 due primarily to a decrease in fuel expense. Purchased power costs increased from 1999 to 2000 by $570,000, or 7%. We purchased more power from the Soldotna 1 unit and Anchorage Municipal Light and Power ("AML&P") than anticipated due to avalanche damage to our transmission lines early in the year, the limited availability of Beluga 3 and Beluga 6 units during the summer months and an increase in economy energy purchases for GVEA. Purchased power costs did not vary materially from 1998 to 1999. Transmission expense did not vary materially from 1999 to 2000. Transmission expense increased in 1999 from 1998 by $1 million, or 38%, due to unanticipated transmission line repairs, Y2K preparation and testing and overhead line maintenance activity as a result of outages early in 1999. Distribution expense increased in 2000 from 1999 by $374,000, or 4%, due primarily to an update in allocations of cost related to the information services and garage clearing. This update shifted those costs from the general and administrative category to the appropriate functional areas of the company. Distribution expense increased in 1999 from 1998 by $525,000, or 6%, due primarily to the increased outage activity that occurred early in 1999, which resulted in increased labor costs. Consumer accounts expense increased in 2000 from 1999 by $888,000 or 20%. This was due to less charges to costs for doubtful accounts in 1999 as compared to 2000. In addition, the update to allocations of cost related to information services caused an increase to this category in 2000. The increase in consumer accounts in 1999 from 1998 was not material but resulted from additional allocated marketing costs offset by less charges to costs for doubtful accounts in 1999. Sales expense did not vary materially in 2000, 1999 or 1998. The slight variances are due to more or less allocated marketing cost resulting from changes in the number of employees in the marketing department in these years. Administrative, general and other expense decreased by $1.55 million, or 6.8%, from 1999 to 2000. This decrease was a result of costs incurred in 1999 for outside counsel, consulting, advertising and internal labor costs associated with an unsolicited MEA takeover attempt and resultant special meeting in 1999 and an update in allocations of cost related to information services in 2000. General and administrative expense increased by $5.3 million, or 30%, from 1998 to 1999, primarily due to the costs associated with the MEA takeover attempt, an increase in software amortization expense, increased maintenance costs of the Y2K compliant software implementation completed in 1998, additional expenses associated with our ancillary businesses and multiple insurance settlements paid in 1999. In addition, general plant maintenance expenses were higher due to multiple projects completed in 1999. We use the composite method of depreciation. The increase in depreciation expense from 1999 to 2000 was $3.4 million, or 17%, and was the result of more transmission assets being placed in service in 2000. Depreciation expense decreased in 1999 from 1998 by $2.6 million, or 12%, due to a change in lives of general plant. Interest on long term debt increased for the year ended December 31, 2000 over 1999, by $849,000, or 4%, due to higher amounts of outstanding debt. Our outstanding indebtedness increased due to the issuance of $30 million in bonds to CoBank, ACB ("CoBank") and to increased borrowing under the lines of credit with CoBank and the National Rural Utilities Cooperative Finance Corporation ("CFC") to fund the Beluga 6 re-powering project and the Cooper Lake facility overhaul. Interest on short-term debt increased from 1999 to 2000 by $912,000, or 91%, because of higher balances maintained and higher interest rates. Our weighted average cost of total borrowings for 2000 was 8.06% compared to 8.14% for 1999. Interest on long-term debt was slightly lower in 1999 than 1998 by $1 million, or 4%, due primarily to the refinancing of $34.9 million of Series A Bonds due 2022 in the first quarter of 1999. Our weighted average cost of total borrowings for 1998 was 8.43%. Net interest expense includes interest on long-term debt and short-term debt, reduced by interest charged to construction. Net interest expense is reduced by $1.54 million, $1.09 million and $1.44 million in 1998, 1999 and 2000, respectively, which represents the net effect of the amortization of the gain on refinancing offset by the amortization of losses on refinancing and transaction costs. Margins Our margins for the years ended December 31, 2000, 1999 and 1998, were as follows: Net Operating Margins Nonoperating Margins Assignable Margins 2000 $ 7,392,551 $ 2,287,227 $ 9,679,778 1999 $ 8,052,060 $ 1,615,374 $ 9,667,434 1998 $ 6,619,263 $ 2,111,141 $ 8,730,404 Nonoperating margins include interest income, allowance for funds used during construction, capital credits and patronage capital allocations. Nonoperating margins increased in 2000 over 1999 by $672,000 or 42%. This was due to an allowance for funds used during construction based on higher construction work in progress balances during the year, increased allocations of patronage capital from CoBank, and higher interest earnings in 2000 as a result of increased short-term investment balances. Nonoperating margins decreased in 1999 over 1998, by $496,000, or 23%. The primary contributor to the decrease from 1998 is the gain on the sale of a surplus compressor rotor to GVEA in 1998. The variance is also due in part to higher-than-anticipated patronage capital from CoBank but is offset by a decrease in interest earnings in 1999 as a result of decreased short-term investment balances. Patronage Capital (Equity) Our patronage capital and total equity have shown steady growth. The following table summarizes our patronage capital and total equity position since 1998: 2000 1999 1998 Patronage capital at beginning of year $117,335,481 $109,622,996 $104,800,092 Retirement of capital credits and estate payments (4,090,006) (1,954,949) (3,907,500) Assignable margins 9,679,778 9,667,434 8,730,404 Patronage capital at end of year 122,925,253 117,335,481 109,622,996 Other equity 5,890,087 5,189,164 4,400,300 Total equity at end of year $128,815,340 $122,524,645 $114,023,296 In furtherance of our operations as a cooperative, we credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves. These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of actual capital credit retirements is at the discretion of our Board of Directors. We currently have a practice of retiring patronage capital on a first-in, first-out basis for retail customers. At December 31, 2000, we retired all retail capital credits attributable to margins earned in periods prior to 1984 and approximately 19% of 1985 retail capital credits. Prior to 2000, wholesale capital credits had been retired on a 10-year cycle pursuant to an Equity Management Plan Settlement Agreement despite its expiration in 1995. However, in 2000, there was no wholesale retirement as we implemented a plan to return the capital credits of wholesale and retail customers on a 15-year rotation. The 1991 Indenture includes a covenant restricting the distribution of patronage capital to members. We cannot distribute patronage capital to members if 1) an event of default exists or 2) the aggregate amount of patronage capital distributions after September 15, 1991, exceeds the sum of $7,000,000 plus 35% of the aggregate assignable margins earned after December 31, 1990. At December 31, 2000, we were permitted to distribute $4.14 million to our members under the 1991 Indenture under this formula. We also retire our patronage credits through annual payments to our members. The table below sets forth a five-year summary of anticipated capital credit retirements: Year Ending Wholesale Retail Total 2001 $ 0 $3,500,000 $3,500,000 2002 0 3,500,000 3,500,000 2003 0 3,500,000 3,500,000 2004 1,359,000 3,500,000 4,859,000 2005 1,109,000 3,500,000 4,609,000 Times Interest Earned Ratio (TIER) Alaska electric cooperatives generally set rates on the basis of TIER. TIER is determined by dividing the sum of assignable margins plus long-term interest expense (excluding capitalized interest) by long-term interest expense. Beginning in 1989, our Board of Directors approved an Equity Management Plan that established a schedule for building our equity. Since then we have managed our business with a view toward achieving a TIER of 1.25 or greater. We achieved TIERs for the past five years as follows: Period TIER 2000 1.39 1999 1.40 1998 1.35 1997 1.30 1996 1.39 Sale of a Segment As of March 20, 2001, we sold to GCI Communication Corporation the bulk of our internet service provider assets related to dial-up services (excluding DSL services). The aggregate purchase price was $759,049 at closing, with a potential for additional amounts, not to exceed $85,850, based on the number of subscriber accounts retained during the ninety-day transition period following closing. We are also to receive service fees for technical and other transition services during such period billed on a time-and-materials basis. The transaction will result in a minimal gain. Changes In Financial Condition Total assets increased by $21.4 million, or 4%, from December 31, 1999, to December 31, 2000. The increase was due to an increase in electric plant in service related to the Beluga 6 unit re-powering, the U.S. Postal Service fuel cell project and various distribution projects. This, however, was offset by a decrease in cash and cash equivalents caused by the funding requirements imposed by the above-mentioned projects and a decrease in materials and supplies caused by the writing off of spare generation parts from inventory. There was an increase in accounts receivable caused by the under-collection of the fuel surcharge in the fourth quarter of 2000. Changes to total liabilities include the increase in notes payable due to borrowing activity during the year. There was also an increase in accrued salaries, wages and benefits due to overall increases in company-wide benefits, as well as increases associated with new contracts with the IBEW. Additionally, the fuel liability increased due to rising fuel prices. Liquidity And Capital Resources We satisfy our operational and capital cash requirements primarily through internally-generated funds, a $50 million line of credit from CFC and a $35 million line of credit with CoBank. At December 31, 2000, there was $5 million outstanding with CFC. An additional $5 million was borrowed in January 2001, and an additional $10 million was borrowed in March 2001. The current outstanding balance as of March 2001 is $20 million. This line of credit bears interest at a variable rate, which was 8.550% as of December 31, 2000, and is currently 7.80% as of April 6, 2001. As of December 31, 2000, $35 million was outstanding under the CoBank line of credit. This line of credit bears interest at a variable rate, which was 8.20% as of December 31, 2000, and is currently 7.55% as of April 6, 2001. Additionally, we have negotiated a supplemental indenture with CFC authorizing a series of bonds in an amount of up to $80 million. At December 31, 2000, we had issued no bonds to CFC. On March 22, 2001, Chugach filed a Registration Statement, Form S-1, with the Securities and Exchange Commission in anticipation of Chugach's $150 million public bond offering. Principal maturities and sinking fund payments of our outstanding indebtedness at December 31, 2000 are set forth below: Year Ending December 31 Sinking Fund Requirements Principal maturities Total 2001 $ 6,097,000 $ 333,350 $ 6,430,350 2002 5,232,000 77,677,944 82,909,944 2003 5,041,000 865,821 5,906,821 2004 5,502,000 945,000 6,447,000 2005 6,005,000 11,031,000 17,036,000 Thereafter 147,762,000 52,158,180 199,920,180 During 2000, we spent approximately $46.7 million on capital construction projects, which includes interest capitalized during construction. We develop five-year work plans that are updated every year. Our capital improvement requirements are based on long-range plans and other supporting studies and are executed through a five-year construction work plan. Set forth below is an estimate of capital expenditures for the years 2001 through 2005: 2001 $36.0 million 2002 $42.5 million 2003 $40.2 million 2004 $40.0 million 2005 $40.1 million We are a party to a Treasury rate-lock with respect to the refinancing of a portion of the 1991 Series A Bonds. The settlement date of this contract is March 15, 2002. At December 31, 2000, the Treasury-rate lock agreement had an estimated value of ($8.6) million. At April 6, 2001, the agreement had an estimated value of ($12.0) million. See "Quantitative and Qualitative Disclosures About Market Risk--Interest Rate Risk." We expect that cash flows from operations and external funding sources will be sufficient to cover operational and capital funding requirements in 2001 and thereafter. Changes in Accounting Principles We were required to adopt SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS No. 138, effective January 1, 2001. This new standard requires all derivative financial instruments to be reflected on the balance sheet. As of January 1, 2001, we have established a regulatory asset for $8.6 million and a liability for the same amount. The regulatory asset and liability will be adjusted for changes in the fair value of a Treasury rate-lock agreement entered into by us. See "Quantitative and Qualitative Disclosures about Market Risk - Interest Rate Risk." Management believes it is probable the regulatory asset will be recovered through rates. Item 7A - Quantitative and Qualitative Disclosures About Market Risk We are exposed to a variety of risks, including changes in interest rates and changes in commodity prices due to repricing mechanisms inherent in gas supply contracts. In the normal course of our business, we manage our exposure to these risks as described below. We do not engage in trading market risk-sensitive instruments for speculative purposes. Interest Rate Risk As of December 31, 2000, except for two bonds issued to CoBank carrying variable interest rates that are periodically re-priced, all of our other outstanding long-term borrowings were at fixed interest rates with varying maturity dates. The following table provides information regarding cash flows for principal payments on total debt by maturity date (dollars in thousands) as of December 31, 2000 and 1999: 2000 Fair Total Debt* 2001 2002 2003 2004 2005 Thereafter Total Value Fixed rate $6,430 $10,410 $5,907 $6,447 $17,036 $199,920 $246,150 $262,655 Average interest rate 8.13% 6.90% 8.62% 8.62% 8.12% 8.22% 8.17% Variable rate $40,000 $72,500 $0 $0 $0 $0 $112,500 $112,500 Average interest rate 8.24% 8.20% -- -- -- -- 8.22% * Includes current portion
1999 Fair Total Debt* 2000 2001 2002 2003 2004 Thereafter Total Value Fixed rate $6,372 $6,430 $10,410 $5,907 $6,447 $235,456 $271,023 $282,034 Average interest rate 8.12% 8.13% 6.90% 8.62% 8.62% 7.95% 7.95% Variable rate $0 $0 $72,500 $0 $0 $0 $72,500 $72,500 Average interest rate -- -- 6.87% -- -- -- 6.87% * Includes current portion
We are exposed to market risk from changes in interest rates. A 100 basis-point change (up or down) would increase or decrease our interest expense by approximately $1,125,000, based on $112.5 million of variable debt outstanding at December 31, 2000. The CoBank and CFC lines of credit, under which we currently have $55 million in short-term debt outstanding, bear interest at variable rates. As of December 31, 2000, the aggregate principal amount of outstanding 1991 Series A Bonds due 2022 was $164,310,000. The 1991 Series A Bonds due 2022 are not callable until March 15, 2002. To manage interest rate exposure for refinancing of these bonds on their first available call date, March 15, 2002, we entered into a Treasury rate-lock transaction with Lehman Brothers Financial Products Inc. ("Lehman Brothers"). Under the Treasury rate-lock contract, we will receive a lump-sum payment from Lehman Brothers on March 15, 2002, if the yield on 10- or 30-year Treasury bonds as of mid-February 2002, exceeds a specified target level (5.653% and 5.838%, respectively). Conversely, we will on the same date be required to make a payment to Lehman Brothers if the yield on the 10- or 30-year Treasury bonds falls below their stated target yields. In each case, the amount of the payment will increase as the difference between the actual yield and the target yield widens. For each basis point (0.01% per annum) by which the yield on 10-year or 30-year Treasury bonds deviates from the stated target level we will receive (if the prevailing Treasury yield exceeds the target yield) or make (if the prevailing Treasury yield falls short of the target yield) a payment equal to the product obtained by multiplying (i) the difference between the prevailing and target yields (expressed in basis points) by (ii) the changes in the prices of $196 million (in the case of 10-year Treasury bonds) and $18.7 million (in the case of the 30-year Treasury bonds) of Treasury bonds, given a one-basis-point change in their respective yields (determined with reference to the Bloomberg Financial Markets Government Yield Analysis Page). In this way, we intend that higher interest costs resulting from any increases in market interest rates between the date of the rate-lock contract and the refinancing of our long-term debt would be mitigated by a lump-sum, up-front payment to us at the time of the refinancing. Conversely, any savings from decreases in interest rates during the same period would be reduced by a payment by us to the rate-lock counterparty. At December 31, 2000 and 1999, the Treasury rate lock agreement had an estimated value of approximately $(8,600,000) and $13,000,000, respectively. The decrease in estimated value is due to the decline on the yield on the 10-year and 30-year Treasury bonds. A 10 basis-point change (up or down) in the prevailing yield on both 10-year and 30-year Treasury bonds would change the value of the rate-lock agreement (up or down) by approximately $1,800,000. Commodity Price Risk Our gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because purchased power costs are passed directly to our wholesale and retail customers through a fuel surcharge, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not normally impact margins. The fuel surcharge mechanism mitigates the commodity price risk related to market fluctuations in the price of purchased power. 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 April 9, 2001. CHUGACH ELECTRIC ASSOCIATION, INC. By: /s/ Eugene N. Bjornstad Eugene N. Bjornstad General Manager Date: April 9, 2001 By: /s/ Evan J. Griffith Evan J. Griffith Executive Manager, Finance & Energy Supply (Principal Financial Officer) Date: April 9, 2001 -----END PRIVACY-ENHANCED MESSAGE-----