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 70,400 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 527 megawatts of installed generating capacity provided by 17 generating units at our five owned power plants: Beluga Power Plant, Bernice Lake Power Plant, International Power Plant, Cooper Lake Hydroelectric Plant and Eklutna Hydroelectric Project, in which we own a 30% interest. Approximately 94% (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 2001, approximately 90% 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 1,610 miles of distribution line and 402 miles of transmission line. For the year ended December 31, 2001, we sold 2.3 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 other than 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.
Our members are the consumers of the electricity sold by us. As of December 31, 2001, we had 59,957 retail members receiving service at approximately 70,416 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 Regulatory Commission of Alaska (RCA) (see "Rate Regulation and Rates" below).
Rates (derived from the historic cost of service basis) are established to 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 currently collect a regulatory cost charge of $.000360 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 354 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 (HERE), Local 878 in effect through June 30, 2003. We believe our relationship with our employees is good.
Gene Bjornstad, Chugach's General Manager, has given notice of his intention to retire in May 2002. Mr. Bjornstad joined Chugach in 1983 and has served as Executive Manager, Operating Divisions and Acting General Manager before his appointment as General Manager in June of 1994.
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 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. 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.
Competition
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 the RCA permit us access over a neighboring utility's distribution and transmission system. 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. Nearly all other Alaskan utilities have opposed our efforts to develop retail competition and are treating their service territories as exclusive. At this time no bill relating to customer choice has moved out of committee in the Alaskan legislature. We do not expect the legislature to pass a law granting retail competition for electric service in the foreseeable future.
We have made organizational changes in preparation for retail 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 retail competition in the electric industry should it develop.
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
The RCA regulates our rates. We can seek increases in our base rates and fuel surcharge 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 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. However, the rate covenant contained in the Amended Indenture will impose no greater TIER requirement than does the rate covenant contained in the Indenture. We do not expect the requirements of either the Indenture or the Amended Indenture to exceed the TIER most recently approved for us 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 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. On the release date, the Amended Indenture will supersede the Indenture and require us to set rates designed to yield margins for interest equal to at least 1.10 times total interest expense. Under RCA orders establishing our current base rates, we are permitted to achieve a TIER of 1.35. For the year ended December 31, 2001, our achieved TIER was 1.20.
In our general rate case filed July 10, 2001, based on the 2000 test year, we proposed that margins be calculated using a rate base/rate of return methodology rather than the TIER methodology previously used. Under this methodology, we can assign different rates of return to our various business functions, such as generation, transmission and distribution, in order to recover appropriate margins for each individual function. In addition, the change in methodology allows us to more efficiently allocate our cost of funds. The resultant system TIER would be 1.38 based on the proposed capital structure contained in that filing. We do not believe that our request to change from the TIER-based methodology to the return-on-rate-base methodology will have any material adverse effect on future ratemaking or on our ability to service our outstanding indebtedness.
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, 2001:
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
As of December 31, 2001, we had 59,957 members being served by approximately 70,400 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 2001, our wholesale power contracts, not including the fuel component, produced $60.8 million in revenues, representing 34% of our revenues and 47% of our total kWh sales to customers.
MEA and HEA
We have two power sales contracts with Alaska Electric Generation & Transmission Cooperative, Inc. (AEG&T): one for sales to MEA and one for sales to HEA. AEG&T is a generation and transmission cooperative that was formed by MEA and HEA. Under each of these contracts, we sell power to AEG&T, which resells the power to MEA and HEA. MEA and HEA have recently indicated that they may be disbanding or substantially changing their relationship with AEG&T but no changes to our contracts have been made at this time. Under our contracts, each of MEA and HEA is obligated to pay us for the power sold to AEG&T even if AGE&T does not pay.
Under the contract, MEA is obligated 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. 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 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 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. We do not expect that the Alaska legislature will pass a law granting retail competition in the foreseeable future and 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 a discussion of material pending litigation between MEA and us, see "Legal Proceedings."
Our contract for the benefit of HEA obligates HEA (through AEG&T) to take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per year. The HEA contract includes limitations on the costs that may be included in our rates charged to it. The HEA contract expires on January 1, 2014. HEA'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 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 AEG&T 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.
On August 24, 2001, Alaska Electric and Energy Cooperative, Inc. (AEEC) and AEG&T filed an Application to Transfer Certificate of Public Convenience and Necessity No. 345 to serve as the wholesale power supplier of HEA, instead of AEG&T. HEA is the sole member of AEEC. The RCA was requested to act on the transfer prior to the end of 2001; however, the application includes the expectation that our power sales agreement will be assigned to AEEC and the Nikiski dispatch agreement will be assigned to HEA. HEA has been requested to meet with us in that regard.
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 thereby reduces the demand charge by 1/3 (approximately $350,000 annually). This agreement was originally set to expire September 1, 2001, but we negotiated an amendment to the agreement that extended 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. The RCA conditionally approved the extension on April 19, 2001, with an effective date of September 11, 2001. The RCA required an amendment to the contract to include an option to re-negotiate the terms of the contract if rates are adjusted by the general rate case we filed in July 2001. Seward has three choices within sixty days of the final order of the RCA in that general rate case. The choices are to continue the contract using the rate methodology adopted in the case, negotiate a new contract or give notice of termination effective twelve months from the effective date of the final order of the RCA.
Economy Customers
Since 1988, we have sold economy (nonfirm) 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 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 our agreement with GVEA, in which we are assured of selling 300 million kWh of GVEA's load and an additional 80% of the excess over 450 million kWh of energy that GVEA purchases each year if we are capable of producing that energy. The remaining energy purchases by GVEA are made through the "Economy Energy Spot Market." Neither we nor any other seller enjoys a contractual priority in making such sales. GVEA makes purchases from the seller offering the lowest competitive price. One of those sellers, AML&P, is expected to dominate sales in the Economy Energy Spot Market for the immediate future, partly because AML&P prices its gas at a rate less than the rate on which we rely in making such sales (based on Marathon gas).
Load Forecasts
The following table sets forth our projected load forecasts for the next five years:
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 a rate of 2.1% and wholesale sales at a rate of 3.2%.
Item 2
Item 2 - Properties
General
We have 527 megawatts of installed capacity consisting of 17 generating units at five power plants. These include 381.2 megawatts of operating capacity at the Beluga facility on the west side of Cook Inlet; 67.5 megawatts of power at the Bernice Lake facility on the Kenai Peninsula; 46.7 megawatts of power at International Power Plant in Anchorage; and 20.0 megawatts at the Cooper Lake facility, which is also on the Kenai Peninsula. We also have 11.7 megawatts of capacity from the two Eklutna Hydroelectric 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 our International Power Plant 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 International facilities. 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. The Cooper Lake facility is located on federal land pursuant to a major project license granted to us by the Federal Power Commission in 1957 and which expires in 2007. We are in the process of reviewing the lease. We have no reason to believe that we will not be able to renew the federal license or the Bernice Lake facility ground lease if desirable.
In 1997, we acquired a 30% interest in the Eklutna Hydroelectric Project. The plant is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October 1997.
Our principal generation units are Beluga 3, 5, 6, 7 and 8. These units have a combined capacity of 342.0 MWh 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 a major overhaul in 1996 and was recently placed back into service after another major overhaul. Beluga unit 5 received a major overhaul in 1997 and is scheduled for another overhaul in the fall of 2002. Beluga unit 6 was "repowered" in 2000 adding in excess of 25 years to its life. Beluga unit 7 was "repowered" in 2001. Beluga unit 8, a steam turbine, was overhauled in 1994 and is slated for another major overhaul in 2002.
The following matrix depicts nomenclature, run hours for 2001 and percentages of contribution and other historical information for all Chugach generation units.
Transmission and Distribution Assets
As of December 31, 2001, our transmission and distribution assets included 39 substations and 402 miles of transmission lines, 930 miles of overhead distribution lines and 680 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 the subject of federal or state permits and licenses. Under a federal license and a permit from the United States Forest Service, we operate the Quartz Creek transmission substation, substations at Hope, Summit Lake and Daves Creek, and transmission lines over all federal lands between Cooper Lake on the Kenai Peninsula and Anchorage. Long-term permits from the Alaska Division of Lands and the Alaska Railroad Corporation govern much of the rest of our transmission system outside the Anchorage area. Within the Anchorage area, we operate our University substation and several major transmission lines pursuant to long-term rights-of-way grants from the U.S. Department of the Interior, Bureau of Land Management, and transmission and distribution lines have been constructed across privately owned lands pursuant to easements across public rights-of-way and waterways pursuant to authority granted by the appropriate governmental entity.
Title
Substantially all of our tangible and some of our intangible properties and assets, including generation, transmission and distribution properties, but excluding all excepted property identified in the Indenture, are pledged as collateral for the long-term obligations until retirement of the 1991 Series A Bond and subsequent institution of the Amended and Restated Indenture. On the release date, the Bonds will become general unsecured and unsubordinated obligations. Under the Amended Indenture, 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 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.
In addition to the lien of the Indenture, many of our properties are burdened by easements, plat restrictions, mineral reservation, water rights and similar title exceptions common to the area or customarily reserved in conveyances from federal or state governmental entities, and to additional minor tide encumbrances and defects. We do not believe that any of these title defects will materially impair the use of our properties in the operation of our business.
Under the Alaska Electric and Telephone Cooperative Act, we possess the power of eminent domain for the purpose and in the manner provided by Alaska condemnation laws for acquiring private property for public use.
Other Assets
Bradley Lake. We are a participant in the Bradley Lake hydroelectric project, which is a 126 megawatt rated capacity hydroelectric facility near Homer on the southern end of the Kenai Peninsula that was placed into service in September 1991. The project is nominally scheduled at 90 megawatts to minimize losses and insure system stability. We have a 27.4 megawatt or 30.4% share in the Bradley Lake project's output, and take Seward's and MEA's shares which we net bill to them, for a total of 45% of the project's capacity.
The project was financed and built by AEA through grants from the State of Alaska and the issuance of $166 million principal amount of revenue bonds supported by power sales agreements with six electric utilities that share the output from the facility (AML&P, HEA and MEA (through AEG&T), GVEA and 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). We also provide transmission and related services as a wheeling agent (one who dispatches and transmits power of third parties over its own system) for all of the participants in the Bradley Lake project.
The length of our Bradley Lake power sales agreement is fifty years from the date of commercial operation of the facility (September, 1991) or when the revenue bond principal is repaid, whichever is the longer. We believe that our maximum annual liability for our take-or-pay obligations is approximately $4.1 million. We believe that so long as this project produces power taken by us for our use that this expense will be recoverable through a fuel surcharge. The share of Bradley Lake indebtedness for which we are responsible is approximately $43.9 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 the defaulting participant to pay its share, provided that no participant's percentage share is increased by more than 25%.
We negotiated with AEG&T a scheduling agreement whereby we schedule HEA's share of the Bradley Lake project through AEG&T for the benefit of the Railbelt electric system. AEG&T continues to pay its Bradley Lake project costs and receives credit for the Bradley Lake energy generated for HEA. We pay a fixed annual fee of $112,000 to AEG&T for these scheduling rights. This agreement allows us to improve the efficiency of our generating resources through better hydrothermal coordination.
Eklutna. We purchased a 30% undivided interest in the Eklutna Hydroelectric Project from the federal government in 1997. MEA 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 2001, 94% of our power was generated from gas, and 77% of that gas-fired generation took place at Beluga.
Our primary sources of natural gas are the Beluga River Field producers (Phillips Alaska, Inc. (Phillips), AML&P and Chevron USA Inc. (Chevron), and Marathon. Phillips, AML&P and Chevron each own one-third of the gas produced from the Beluga River Field and in 2001 provided approximately equal shares of the Beluga gas. We have approximately 353 billion cubic feet (BCF) of remaining gas committed to us from the Beluga River Field producers and Marathon. We currently use approximately 23 BCF of natural gas per year for firm service. We believe that this usage will increase approximately 0.5 BCF per year and estimate that our contract gas will last 10 to 15 years. The deliverability requirements under the Beluga Field producers and Marathon contracts are in excess of the peak winter demand requirements of the Beluga plant.
Beluga River Field Producers
We have similar requirements contracts with each of Phillips, AML&P and Chevron that were executed in April 1989, superseding contracts that had been in place since 1973. Each of the contracts with the Beluga River Field producers provides for delivery of gas on different terms in three different periods. Period 1 related to the delivery of gas previously committed by the respective producer under the 1973 contracts and ended in June 1996.
During Period 2, which began in June 1996 and continues until the earlier of the delivery of 180 BCF of natural gas or December 31, 2013, we are entitled to take delivery of up to 180 BCF of natural gas (60 BCF per Beluga River Field producer). During this period, we are required to take 60% of our total fuel requirements at Beluga from the three Beluga River Field producers, exclusive of gas purchased at Beluga under the Marathon contract for use in making sales to GVEA or certain other wholesale purchasers. The price for gas during this period under the Phillips and AML&P contracts is approximately 88% of the price of gas under the Marathon contract (described below) ($2.3422 per thousand cubic feet (MCF) on January 1, 2002), plus taxes. The price during this period under the Chevron contract is approximately 110% of the price of gas under the Marathon contract (described below) ($2.9278 per MCF on January 1, 2002), plus taxes.
During Period 3 under the Beluga River Field producers' contracts, which begins on the earlier of December 31, 2013, or the end of Period 2, we may become entitled to take delivery of up to 120 BCF of natural gas (40 BCF per producer). Whether any gas will be taken in Period 3, and the price and take requirements with respect thereto, are to be determined in the future based upon then-current market conditions.
We have supplemental, annually renewable contracts with the Beluga River Field producers to supply supplemental gas (for peak periods of energy usage) if they have it available in excess of the amounts guaranteed in the basic contracts. The supplemental gas contracts raise the daily deliverability of gas from the Beluga River Field producers to an aggregate of 85,200 MCF per day. The base price of the gas under these contracts is the same as the base price under the Marathon contract (described below), plus taxes.
Marathon
We entered into a requirements contract with Marathon in September 1988 for an initial commitment of 215 BCF. The contract expires on the earlier of December 31, 2015, or the date on which Marathon has delivered to us a volume of gas in total, which equals or exceeds 215 BCF, which we currently expect to occur by mid-2009. The base price for gas under the Marathon contract is $1.35 per MCF, adjusted quarterly to reflect the percentage change between the preceding twelve-month period and a base period in the average prices of West Texas Intermediate Crude Oil (a benchmark of the Light Sweet Crude Oil Futures Index), the Producer Price Index for natural gas, and the Consumer Price Index for heating fuel oil. The price on January 1, 2002, exclusive of taxes, was $2.6616 per MCF.
Under the terms of the Marathon contract, Marathon generally provides the primary supply of gas required for sales to GVEA, all of our requirements at Bernice Lake, International and Nikiski and 40% of the requirements at Beluga. Marathon also has a right of first refusal to provide additional gas under any sales agreements that we may enter into with electric utilities we do not currently serve. 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 $0.30 per MCF. The agreement contains a minimum monthly bill of $2,600 for firm service. We hold a reservation to receive our gas requirements at International Power Plant from ENSTAR under a tariff approved by the RCA in the event that the transportation agreement is subsequently canceled. ENSTAR is obligated to supply all of the gas we require at a price approved by the RCA. There is a monthly minimum bill of $10,465 but no requirement to actually use any gas at the International Power Plant.
Environmental Matters
General
Our operations are subject to certain federal, state and local environmental laws and regulations, which seek to limit to 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.
We are 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
The Association discovered polychlorinated biphenyls (PCBs) in paint, caulk and grease at the Cooper Lake Hydroelectric plant during initial phases of a turbine overhaul. A Federal Energy Regulatory Commission (FERC) approved plan, prepared in consultation with the Environmental Protection Agency (EPA), was implemented to remediate the PCBs in the plant. As a condition of its approval of the license amendment for the overhaul project, FERC required Chugach to also investigate the presence of PCBs in Kenai Lake. A sampling plan was developed by Chugach in consultation with various agencies and approved by FERC. In 2000, Chugach sampled sediments and fish collected from Kenai Lake and other waters. While extremely low levels of PCBs were found in some sediment samples taken near the plant, no pathway from sediment to fish was established. Additional sediment sampling and analysis in this area is being performed. While the presence of PCBs in fish did not reveal amounts above background levels, Chugach has conducted additional sampling and analysis of fish in Kenai Lake and other waters and is preparing a report to FERC, analyzing the results of the sampling. Management believes the costs of this work will be recoverable through rates and therefore will have no material impact on our financial condition or results of operations. The RCA has issued an order to Chugach generally allowing prudently incurred remediation costs at Cooper Lake to be recovered through rates, however, the RCA has not approved the final recovery amount in this matter and will review these costs as part of the 2000 test year rate case.
Item 3
Item 3 - Legal Proceedings
Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc. Superior Court Case No. 3AN-99-8152 Civil - --------------------------------------------------------------------------------
This action was 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 the Company's sale of power to MEA during that time. MEA asserted the Company breached that contract by failing to provide a variety of kinds of information, by failing to properly manage the Company's long-term debt, and by failing to bring its base rate action to the Joint Rates Committee before presentation to the RCA. All of MEA's claims have been dismissed. MEA has indicated that it intends to appeal to the Alaska Supreme Court, at a minimum, the Superior Court's dismissal of its financial mismanagement claim.
We have certain additional litigation matters and pending claims that arise in the ordinary course of our business. In the opinion of management, no individual matter or the matters in the aggregate is likely to have a material adverse effect on our results of operations or financial condition.
Item 4
Item 4 - Submission of Matters to a Vote of Security Holders
Not Applicable
PART II
Item 5
Item 5 - Market for Registrant's Common Equity and Related Stockholder Matters
Not Applicable
Item 6
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:
Item 7
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). We manage our business with a view toward achieving a TIER of 1.25 or greater. We achieved TIERs for the past five years as follows:
Year TIER ---- ---- 2001 1.20 2000 1.39 1999 1.40 1998 1.35 1997 1.30
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 the generation and transmission of electricity. Although a base fuel and purchased power component is included in base rates, they consist primarily of costs other than fuel and purchased power costs. "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.
Base Rates. We recover operating and maintenance and other non-fuel and purchased power costs through our base rate 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. While this process typically takes nine months to one year, the RCA may authorize, after a notice period, rate changes on an interim and refundable basis. In addition, the RCA has been willing to open limited reviews of rate cases to resolve specific issues from which expeditious decisions can often be generated.
We filed a general rate case in July 2001, requesting a permanent base rate increase of 6.5%, and an interim base rate increase of 4%. On September 5, 2001, the RCA granted a 1.6% interim increase effective September 14, 2001. We filed a petition for reconsideration and on October 25, 2001, the RCA approved an interim base rate increase of 3.97%. The additional rate increase was implemented on November 1, 2001. The 3.97% interim base rate increase was anticipated to result in approximately $0.7 million in additional revenue in 2001 compared to previous permanent base rates, or $4.1 million on an annualized basis. The interim base rate increase is based on a normalized, or adjusted for recurring expenses, test year and a system ratemaking TIER of 1.35.
The requested permanent base rate increase of 6.5%, if approved by the RCA, is anticipated to result in $7.5 million in additional revenue each year, or approximately $3.4 million more than the interim base rate increase approved by the RCA, which became effective on November 1, 2001, and margins of $10.8 million for 2002 at the base rate submitted. The requested permanent base rate increase is scheduled for a hearing before the RCA in August 2002.
Prior to 2001, our base rates to our retail customers had not increased since 1994. As part of a settlement of disputes over rate adjustments with our wholesale customers (the "Settlement Agreement"), we agreed that our base rate for wholesale customers would not exceed 1995 levels at least through 1999 and could be reduced if those rates provide returns significantly higher than those specified in the settlement. As discussed below, we have granted refunds for rates based on our 1996 costs. The RCA issued an order on February 27, 2001, that no rate reduction or refunds were required based on our 1997 test year costs. According to an order issued by the RCA on March 15, 2002, no rate reduction or refunds were required based on our 1998 test year costs. Parties have until April 1, 2002 to file a request for reconsideration.
Our base rate changes, excluding fuel surcharges, for retail and wholesale classes, for the years 1999 through 2001 were as follows:
2001 2000 1999 ---- ---- ---- Retail* 1.6% 0.0% 0.0% Wholesale: HEA 1.6% (0.7%) (0.3%) MEA 1.6% (0.8%) (3.8%) Seward 0.0% 0.0% 0.0%
* The 2001 base rate increase was not applied to small general service or lighting customer classes.
The rate reductions shown in the table for Matanuska Electric Association (MEA) and Homer Electric Association (HEA) in 1999 and 2000 relate to our filing under the Settlement Agreement of our cost of service for 1996. Our calculations 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 $2.7 million at December 31, 1999. Early in 2000, we issued additional refunds of $86,132 to HEA and $1.8 million to MEA that represented uncontested amounts owed to them under the Settlement Agreement. 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 HEA 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 RCA issued an order for the 1997 test year that did not reduce wholesale rates or require refunds under the Settlement Agreement. According to an order issued by the RCA on March 15, 2002, no rate reduction or refunds were required based on our 1998 test year costs. Parties have until April 1, 2002 to file a request for reconsideration.
The rate reduction to the City of Seward (Seward) in 1998 was the result of a contract re-negotiation through which Seward moved from being a firm customer to an interruptible customer. The rate reduction reflects a negotiated reduction of rates for Seward since the Seward load can be interrupted.
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. 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.
The RCA ordered refunds of approximately $1.2 million because of alleged over-collection of fuel surcharges in 1995, 1996 and 1997. We appealed that finding to the Superior Court, which overturned it. MEA appealed that decision to the Alaska Supreme Court and the RCA filed an amicus brief generally supporting the MEA position. A hearing before the court was held October 17, 2001 and a decision is pending.
Year ended December 31, 2001 compared to the years ended December 31, 2000 and 1999 Margins
Our margins for the years ended December 31, 2001, 2000 and 1999, were as follows:
The decrease in net operating margins and assignable margins is primarily attributable to an increase in depreciation due to a substantial increase in plant in the fourth quarter of 2000 related to the Beluga unit 6 re-powering, increased interest expense due to the issuance of $150 million of long-term debt in the second quarter of 2001, and a decrease in capitalized interest charged to construction. Another factor in the margin decrease was that our requested interim rate increase did not become effective until September 14, 2001.
Nonoperating margins include interest income, allowance for funds used during construction, capital credits and patronage capital allocations. Nonoperating margins decreased in 2001 over 2000 by $617,000 or 27%. This was due to decreased allocations of patronage capital from CoBank and the loss associated with the sale of the Internet segment. 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.
Revenues
Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2001, operating revenues were $20 million, or 13% higher than in 2000 due to increased kWh sales and increased fuel prices, resulting in increased revenue collected through the fuel surcharge mechanism. This was offset by decreased economy energy sales to Golden Valley Electric Association (GVEA) and decreased revenue generated by the Internet segment. In 2000, operating revenues were $159 million, which was 11% higher than in 1999 primarily due to increased sales of economy energy to 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. The major components of our operating revenue for the year ended December 31, 2001 and 2000, were as follows:
2001 2000 1999 ---- ---- ----
Retail $112,026,122 $98,536,690 $94,057,713 Wholesale HEA 24,260,072 19,060,244 17,357,727 MEA 33,706,678 27,252,051 25,063,734 Seward 2,816,970 2,369,550 2,168,982 Economy energy 3,354,719 7,820,998 1,864,873 Other 2,430,653 3,501,581 2,131,298 --------- --------- --------- Total revenue $178,595,214 $158,541,114 $142,644,327 ============ ============ ============
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 2001, 2000, and 1999, economy sales to GVEA constituted approximately 1.90%, 5.00%, and 0.79%, respectively, of our sales revenues. The decrease in economy sales in 2001 from 2000 was due to increased fuel prices, which made it more economical for GVEA to produce their own power, rather than purchase it from Chugach. 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 clean-coal 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, 2001, 2000 and 1999 were as follows:
Power production expense increased in 2001 from 2000 by $15.8 million, or 30%, due primarily to an increase in fuel expense from $42.5 million in 2000 to $56.1 million in 2001, as well as the use of less efficient units in order to meet demand while Beluga unit 6 and unit 7 were unavailable. 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.
Purchased power costs increased by $5.6 million, or 61%, from 2000 to 2001 due to Soldotna #1 power plant being placed back into service under a new contract at a Nikiski fertilizer plant that requires the Nikiski unit to be run at full capacity. 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 2000, the limited availability of Beluga 3 and Beluga 6 units during the summer months and an increase in economy energy purchases for GVEA.
Transmission expense did not vary materially in 2001 from 2000 or from 1999 to 2000.
Distribution expense increased in 2001 from 2000 by $643,000, or 7%, due to an increase in trouble calls in the Operations area relating to outages and damage claims, as well as increased locate activity in Tyonek. 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.
Consumer accounts expense did not vary materially from 2000 to 2001. 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.
Sales expense decreased from 2000 to 2001 by $617,000, or 55%, due to the sale of the Internet business, as well as a shift in the activities of the Marketing department from sales activities to customer information activities. Sales expense did not vary materially from 1999 to 2000. The slight variances were due to more or less allocated marketing cost resulting from changes in the number of employees in the marketing department in those years.
Administrative, general and other expense decreased by $1.8 million, or 8%, from 2000 to 2001, due to the sale of the Internet business, which resulted in a decrease in cost of goods sold and consulting expenses. Administrative, general and other expense decreased by $1.6 million, or 7%, 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 the takeover attempt by MEA, the resultant special meeting in 1999 and an update in allocations of cost related to information services in 2000.
We use the composite method of depreciation. Depreciation expense increased by $1.9 million, or 8%, from 2000 to 2001, due to the completion of many projects thereby increasing the level of plant currently being depreciated. 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.
Interest on long-term obligations increased from 2000 to 2001 by $2.1 million, or 9%, due to the public bond offering in April 2001. Interest on long-term obligations 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). Interest on short-term obligations decreased by $745,000, or 39%, from 2000 to 2001 due to lower outstanding balances on the lines of credit. Interest on short-term debt increased from 1999 to 2000 by $912,000, or 91%, due 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. There was a decrease in interest charged to construction due to a decrease in construction projects from 2000 to 2001, which was the same reason there was an increase from 1999 to 2000 in this category. Net interest expense includes interest on long-term obligations and short-term obligations, reduced by interest charged to construction. The amortization of the gain on refinancing debt offset by the amortization of losses on refinancing debt and transaction costs resulted in a reduction to net interest expense of $1.1 million, $1.4 million and $1.1 million in 2001, 2000 and 1999, respectively.
Patronage Capital (Equity)
Our patronage capital and total equity have shown steady growth. The following table summarizes our patronage capital and total equity position for the years ended December 31, 2001, 2000 and 1999:
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 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. At December 31, 2001, 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 is contained in the Chugach business plan. 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 million plus 35% of the aggregate assignable margins earned after December 31, 1990. At December 31, 2001, we were permitted to distribute $4.5 million to our members under the 1991 Indenture under this formula. In December 2001, we distributed $3 million of patronage capital to our members. The Amended Indenture prohibits us from making any distributions, payment or retirement of patronage capital to our customers if an event of default under the Amended 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.
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
2002 $0 $3,500,000 $3,500,000 2003 0 3,500,000 3,500,000 2004 1,359,000 2,141,000 3,500,000 2005 1,109,000 2,391,000 3,500,000 2006 1,671,000 1,829,000 3,500,000
Sale of a Segment
As of March 6, 2001, with an effective date of March 20, 2001, Chugach sold the bulk of its internet service provider assets related to dial-up services (excluding DSL services) to General Communication Incorporated. The aggregate purchase price was $759,049 at closing, plus an additional amount of $70,075, which was based on number of subscriber accounts retained during the ninety-day transition period following closing. These transactions resulted in a loss of $258,073.
Changes In Financial Condition
Total assets increased by $35.5 million, or 7%, from December 31, 2000, to December 31, 2001. The increase was primarily due to an increase in electric plant in service related to the Beluga unit 7 "repower", the Cooper Lake overhaul, the Supervisory Control and Data Acquisition (SCADA) upgrade, the International Generating Terminal (IGT) auxiliaries improvement and miscellaneous distribution projects. Deferred charges increased due to debt issuance and acquisition costs associated with the April 2001 public bond offering. There was also an increase in accounts receivable due to wholesale power bills that were accrued but not paid at December 31, 2001. There was an increase in fuel cost recovery caused by the under-collection of the fuel surcharge in the fourth quarter of 2001 and an increase in materials and supplies caused by the purchase of generation parts needed for unit maintenance in 2002.
Changes to total liabilities include the increase in long-term obligations and accrued interest due to the public bond offering in April 2001. Current installments of long-term obligations increased due to the first installment of CoBank 5 due in June of 2002. 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. These, however, were offset by a decrease in notes payable, as well as a decrease in deferred credits caused by the decrease of the gain on refinancing.
Contractual Obligations and Commercial Commitments
The following are Chugach's contractual and commercial commitments as of December 31, 2001:
Contractual cash obligations:
Commercial Commitments:
*At December 31, 2001, Chugach had $85 million in lines of credit with various financial institutions, which fund capital requirements, effectively reducing the available borrowing capacity under these lines of credit to $74 million.
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, 2001, there was no outstanding balance with CFC. As of December 31, 2001, $11 million was outstanding under the CoBank line of credit. This line of credit bears interest at a variable rate, which was 3.75% as of December 31, 2001, and is currently 3.75% as of March 2002.
On April 17, 2001, Chugach issued $150,000,000 of 2001 Series A Bond, for the purpose of retiring indebtedness outstanding under existing lines of credit and outstanding bonds, for capital expenditures and for general working capital. The lines of credit had an aggregate outstanding principal balance of $55,000,000, as of April 17, 2001, were renewable annually and bore interest at variable annual rates ranging from 7.55% to 7.80% at April 17, 2001. The variable-rate bonds retired had an aggregate outstanding principal balance of $72,500,000, as of April 17, 2001, would have matured in 2002 and bore interest at a variable rate that was 7.55% on April 17, 2001.
The 2001 Series A Bond will mature on March 15, 2011, and bear interest at 6.55% per annum. Interest will be paid semi-annually on March 15 and September 15 of each year commencing on September 15, 2001. The 2001 Series A Bond is secured by a first lien on substantially all of Chugach's assets. The first lien will be automatically released when all bonds issued by Chugach prior to April 1, 2001, cease to be outstanding or their holders consent to conversion to unsecured status. Thereafter, the 2001 Series A Bond will be an unsecured obligation, ranking equally with Chugach's other unsecured and unsubordinated obligations.
On February 1, 2002, Chugach issued a $120,000,000 2002 Series A Bond and $60,000,000 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. On March 15, 2002, all of the remaining 1991 Series A Bonds due 2022 were redeemed and the final payment on the 1991 Series A Bonds due 2022 was made. The 2002 Series A Bond will mature on February 1, 2012, and bear interest at 6.20% per annum. Interest will be paid 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 will bear interest from February 1, 2002 through February 27, 2002, at 1.97% and afterwards, will initially bear interest at the rate set for 28-day auction periods. The initial auction date was February 27, 2002. The applicable interest rate for any 28-day auction period will be the term rate established by the auction agent based on the terms of the auction. The Auction Rate Bond may be converted, in our discretion and in some cases subject to the consent of the bond insurer, 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 will act as the auction agent and J.P. Morgan Securities Inc., will act as the initial broker-dealer for the Auction Rate Bond.
Payment of the 2002 Series A Bond and the Auction Rate Bond (collectively the "Bonds") initially will be secured by a first lien on substantially all of Chugach's tangible and some intangible properties. The first lien will be automatically released when all bonds issued by Chugach prior to April 1, 2001, cease to be outstanding or their holders consent to the release of the lien. After that time, the Bonds will be unsecured obligations; ranking equally with our other unsecured and unsubordinated obligations. In addition, we will be limited in our ability to secure obligations for borrowed money or the deferred purchase price of property after that time unless Chugach equally and ratably secures our outstanding indebtedness subject to the Indenture governing the Bonds.
Principal maturities and sinking fund payments of our outstanding indebtedness at December 31, 2001 are set forth below:
During 2001 we spent approximately $36.4 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 2002 through 2006:
2002 $33.2 million 2003 $32.8 million 2004 $42.3 million 2005 $24.7 million 2006 $38.4 million
The anticipated large increase in capital expenditures in 2004 represents the construction of a transmission line from the International Power Plant to University Station via new South Anchorage Bulk Substation, the Wind Turbine capital project and an overhaul of Beluga unit 6.
We expect that cash flows from operations and external funding sources will be sufficient to cover operational and capital funding requirements in 2002 and thereafter.
Critical Accounting Policies
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. The following areas represent those that management believes are particularly important to the financial statements and that require the use of estimates and assumptions to describe matters that are inherently uncertain.
FERC Accounting
Chugach prepares its financial statements in accordance with GAAP and in conformity with the FERC's uniform system of accounts.
Cost Basis Regulation
Chugach is subject to regulation by the RCA. The rates that are charged by CEA to its customers are based upon cost basis regulation reviewed and approved by this regulatory commission. Under the authority of this commission, CEA has recorded certain regulatory assets in the amount of $21.5 million and regulatory liabilities in the amount of $15.6 million as of December 31, 2001. If CEA's rates were no longer based upon cost basis or the probability of future collection in rates, regulation, the assets and liabilities would be written off to margins.
Financial Instruments and Hedging
CEA uses U.S. Treasury forward rate lock agreements to hedge expected interest rates on probable debt. The Association accounted for the agreements under SFAS 80 and 71 through December 31, 2000, and SFAS 133, 138 and 71 subsequent to that date. Gains or losses are treated as regulatory assets or liabilities 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.
Recent Accounting Pronouncements
Chugach was required to adopt SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an Amendment of FASB Statement No. 133, effective January 1, 2001. This new standard requires all derivative financial instruments to be reflected on the balance sheet. The adoption resulted in Chugach establishing a liability for the settlement of U.S. Treasury Rate Lock Agreements.
In July 2001 the Financial Accounting Standards Board issued Statement 141, Business Combinations, and Statement 142, Goodwill and Other Intangible Assets. Statement 141 requires that the purchase method of accounting be used for all business combinations initiated or completed after June 30, 2001. Statement 142 will require that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. The provisions of Statement 142 are required to be applied starting with fiscal years beginning after December 15, 2001. Management believes the adoption of Statement 141 and 142 will have no impact on our financial statements.
In August 2001 the Financial Accounting Standards Board issued Statement 143, Accounting for Asset Retirement Obligations. Statement 143 requires an enterprise to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and an increase to the carrying amount of the related long-lived asset, which is depreciated over the life of the asset. Enterprises are required to adopt Statement 143 for fiscal years beginning after June 15, 2002. Management believes the adoption of Statement 143 will have no impact on our financial statements.
In October 2001 the Financial Accounting Standards Board issued Statement 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Statement 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. While Statement 144 supersedes FASB Statement 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, it retains many of the fundamental provisions of that Statement, and broadens the presentation of discontinued operations to include more disposal transactions. Statement 144 also supersedes the accounting and reporting provisions of Accounting Principles Board (APB) Opinion 30, Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of a business. However, it retains the requirement in Opinion 30 to report separately discontinued operations and extends that reporting to a component of an entity that either has been disposed of or is classified as held for sale. Statement 144 is effective for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. Management believes the adoption of Statement 144 will have no impact on our financial statements.
Item 7A
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, 2001, all of our 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, 2001, and 2000:
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 $110,000, based on $11 million of variable debt outstanding at December 31, 2001. The CoBank and CFC lines of credit, under which we currently have $11 million in short-term debt outstanding, bear interest at variable rates.
As of December 31, 2001, the aggregate principal amount of outstanding 1991 Series A Bond due 2022 was $149,310,000. In May 2001, we reacquired $10 million of our Series A 2022 Bond for $11.2 million, which included accrued interest and premium. On December 10, 2001, we reacquired $5 million of our Series A 2022 Bonds for $5.7 million, which included accrued interest and premium. The 1991 Series A Bonds due 2022 were not subject to redemption until March 15, 2002, and all outstanding 1991 Series A Bonds due 2022 were redeemed on that date.
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 agreement with Lehman Brothers Financial Products Inc. (Lehman Brothers) in March 1999. The treasury rate-lock agreement has 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. The settlement payments will be accounted for as a regulatory asset. We believe the regulatory asset will be recovered through rates. On January 14, 2002, Chugach entered into an 18-day rate lock agreement with JP Morgan on the $120 million 10-year term bond of the proposed 2002 financing based on the 10-year treasury issued August 15, 2001, that was trading at 4.877%. That rate, along with a 4.1 basis point fee, set a benchmark rate for the transaction at 4.918%. Chugach terminated the rate lock on February 1, 2002, which generated a payment to Chugach for $1.2 million.
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.
Item 8
Item 8 -Financial Statements and Supplementary Data
December 31, 2001 and 2000
Independent Auditors' Report
The Board of Directors Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association, Inc. (Association) as of December 31, 2001 and 2000, 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, 2001. These financial statements are the responsibility of the Association's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and the 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, 2001 and 2000, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.
/s/ KPMG LLP
March 1, 2002 Anchorage, Alaska
Chugach Electric Association, Inc. Notes to Financial Statements December 31, 2001 and 2000
(1) Description of Business and Summary of Significant Accounting Policies
Description of Business
Chugach Electric Association, Inc., (Association or Chugach) is the largest electric utility in Alaska. The Association is engaged in the generation, transmission and distribution of electricity to directly served retail customers in the Anchorage and upper Kenai Peninsula areas. Through an interconnected regional electrical system, Chugach's power flows throughout Alaska's Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska's largest cities, Anchorage and Fairbanks.
Chugach also supplies much of the power requirements of three wholesale customers, Matanuska Electric Association (MEA), Homer Electric Association (HEA) and the City of Seward (Seward). Our members are the consumers of the electricity sold.
The Association operates on a not-for-profit basis and, accordingly, seeks only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation, and principal and interest on all indebtedness and to provide for reasonable margins and reserves. The Association is subject to the regulatory authority of the Regulatory Commission of Alaska (RCA).
Management Estimates
In preparing the financial statements, management of the Association is required to make estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the balance sheet and revenues and expenses for the reporting period. Actual results could differ from those estimates.
Regulation
The accounting records of the Association conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission. The Association meets the criteria, and accordingly, follows the accounting and reporting requirements of Statement of Financial Accounting Standards 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on the Association's statement of revenues and expenses as assignable margins. Retained assignable margins are designated on the Association's balance sheet as patronage capital, which is assigned to members on the basis of patronage. This patronage capital constitutes the principal equity of the Association.
Reclassifications
Certain reclassifications have been made to the 1999 and 2000 financial statements to conform to the 2001 presentation.
Plant Additions and Retirements
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.
Operating Revenues
Operating revenues are based on billing rates authorized by the RCA, which are applied to customers' usage of electricity. Included in operating revenue are billings rendered to customers adjusted for differences in meter read dates from year to year. The Association's tariffs include provisions for the flow through of gas costs according to existing gas supply contracts.
Chugach entered into a settlement agreement with MEA and HEA in 1996. The settlement agreement was designed to resolve a number of ratemaking disputes and assure MEA and HEA that their base rates would be no higher than those based on 1995 costs and would be reduced (and refunds given) if our 1996, 1997 or 1998 test year costs to serve their needs were significantly reduced. The Agreement required Chugach to make filings of Chugach's cost of service to facilitate determination of any refunds owed under the settlement agreement.
Calculations based on 1996 costs indicated that a rate reduction was required and that a refund was owed for the previous periods. Chugach recorded provisions for wholesale rate refunds that totaled $2,651,361 as of December 31, 1999. Early in 2000, refunds of $86,132 were issued to HEA and $1,809,801 to MEA that represented uncontested amounts owed consistent with the 1996 test year filing.
In June 2000, the RCA issued its final order approving the 1996 test year cost of service. As a result of this order, additional refunds were issued to MEA and HEA 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 RCA issued an order for the 1997 test year that did not reduce wholesale rates or require refunds under the Settlement Agreement. The 1998 test year hearing has been completed but an order from the RCA has not yet been issued. Management believes that no rate reduction or refund will be required based on the 1998 test year. No additional test years remain to be reviewed under the Settlement Agreement.
Chugach filed a general rate case on July 10, 2001, based on the 2000 test year, requesting a permanent base rate increase of 6.5%, and an interim base rate increase of 4.0%. On September 5, 2001, the RCA granted a 1.6% interim increase effective September 14, 2001. We filed a petition for reconsideration and on October 25, 2001, the RCA approved an interim base rate increase of 3.97%. The additional rate increase was implemented on November 1, 2001. The 3.97% interim base rate increase is anticipated to result in approximately $4.1 million additional revenue on an annualized basis. The interim and permanent rate increases are subject to final approval by the RCA after a hearing process. If the RCA does not agree with the interim increase, Chugach may be required to refund a portion of the increase. Management believes it is unlikely any of the interim increase will have to be refunded.
In this filing, Chugach proposed that margins be calculated using a rate base/rate of return methodology rather than the TIER methodology previously used. Under this methodology, we can assign different rates of return to our various business functions, such as generation, transmission and distribution, in order to recover appropriate risk premiums for each individual function. In addition, the change in methodology allows us to more efficiently allocate our cost of funds. The resultant system TIER would be 1.38 based on the proposed capital structure contained in that filing. We do not believe that our request to change from the TIER-based methodology to the return-on-rate-base methodology will have any material adverse effect on future ratemaking or on our ability to service our outstanding indebtedness.
In 1998 a power sales agreement was negotiated between Chugach and Seward. The contract was approved by the RCA on June 14, 1999 for a three-year term, which expired on September 1, 2001. The parties negotiated and executed an Amendment, extending the term of the contract to January 31, 2006, which was approved by the RCA July 9, 2001.
In October 1998 Marathon Oil Company, one of Chugach's natural gas suppliers, notified Chugach that it had reached a settlement with the State of Alaska regarding additional excise and royalty taxes for the period 1989 through 1998. In accordance with the purchase contract, Chugach would be responsible for these additional taxes. The RCA approved Chugach's plan to recover this over 12 months through the Fuel Surcharge mechanism except for the retail portion in the amount of $436,778 that, in accordance with Chugach's request, was written off at December 31, 1998. Recovery of this expense in rates continued
from April 1, 1999, through April 1, 2000. Despite RCA approval and subsequent re-confirmation by the RCA, MEA has refused to pay the portion of its monthly bill it considers to be recovery of the Marathon tax. Effective December 20, 2000, by the Superior Court for the State of Alaska, MEA was ordered to pay $298,004, representing the unpaid tax liability and associated litigation costs. MEA has appealed this order to the Alaska Supreme Court.
Investments in Associated Organizations
Investments in associated organizations represent capital requirements as part of financing arrangements. These investments are non-marketable and accounted for at cost.
Deferred Charges and Credits
Deferred charges, representing regulatory assets, are amortized to operating expense over the period allowed for rate-making purposes. In accordance with SFAS 71, the Association's financial statements reflect regulatory assets and liabilities. Continued accounting under SFAS 71 required certain criteria be met. Management believes the Association'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.
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.
Depreciation and Amortization
Depreciation and amortization rates have been applied on a straight-line basis and at December 31, 2001 are as follows: Annual Depreciation Rate Ranges
Steam production plant 2.70 - 2.96 Hydraulic production plant 1.33 - 2.88 Other production plant 3.34 - 6.50 Transmission plant 1.85 - 5.37 Distribution plant 2.10 - 4.55 General plant 2.22 - 20.00 Other 1.88 - 2.75
Chugach uses average service life rates set forth in the most recently approved depreciation study. In 1997 an update of the Depreciation Study was completed utilizing Electric Plant in Service balances as of December 31, 1995. Depreciation rates developed in that study were implemented in January, 1998. In 2000, another update of the study was completed. Depreciation rates determined in that study will be implemented upon approval by the RCA.
Capitalized Interest
Allowance for funds used during construction and interest charged to construction - credit are the estimated costs during the period of construction of equity and borrowed funds used for construction purposes. The Association capitalized such funds at the weighted average rate (adjusted monthly) of 7.5% during 2001, 7.9% during 2000 and 7.4% during 1999.
Cash and Cash Equivalents
For purposes of the statement of cash flows, the Association considers all highly liquid debt instruments with a maturity of three months or less upon acquisition by the Association (excluding restricted cash and investments) to be cash equivalents.
Materials and Supplies
Materials and supplies are stated at the lower of average cost or market.
Fair Value of Financial Instruments
SFAS 107, Disclosures About the Fair Value of Financial Instruments, requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments:
Cash and cash equivalents and restricted cash - the carrying amount approximates fair value because of the short maturity of those instruments.
Investments in associated organizations - the carrying amount approximates fair value because of limited marketability and the nature of the investments.
Consumer deposits - the carrying amount approximates fair value because of the short refunding term.
Long-term obligations - the fair value is estimated based on the quoted market price for same or similar issues (note 7).
Treasury rate lock agreements - the fair value is estimated based on discounted cash flow using current rates.
Financial Instruments and Hedging
The Association uses U.S. Treasury forward rate lock agreements to hedge expected interest rates on probable debt re-financings. The Association accounted for the agreements under SFAS 80 and 71 through December 31, 2000, and SFAS 133, 138 and 71 subsequent to that date. The Association adopted SFAS 133 on January 1, 2001. Accordingly, the unrealized gain or loss has not been recorded and will be treated as a regulatory asset or liability upon settlement (note 6).
Income Taxes
The Association is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code, except for unrelated business income. For the years ended December 31, 2001, 2000 and 1999 the Association received no unrelated business income.
Environmental Remediation Costs
The Association 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.
2) Utility Plant Summary
Major classes of electric plant as of December 31 are as follows:
Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment.
3) Investments in Associated Organizations
Investments in associated organizations include the following at December 31:
The Farm Credit Administration, CoBank's federal regulators, requires minimum capital adequacy standards for all Farm Credit System institutions. CoBank's loan agreements require, as a condition of the extension of credit, that an equity ownership position be established by all borrowers. The Association's investment in NRUCFC similarly was required by its financing arrangements with NRUCFC.
(4) Patronage Capital
The Association has an approved capital credit retirement program, which is contained in the Chugach business plan. This establishes, in general, a plan to return the capital credits of wholesale and retail customers based on the members' proportionate contribution to Association assignable margins on an approximately 15-year rotation. At December 31, 2001, out of the total of $125,184,374 patronage capital, the Association had assigned $122,055,164 of such patronage capital (net of capital credit retirements). Approval of actual capital credit retirements is at the discretion of the Association's Board of Directors.
In November 1999, the Board of Directors authorized the retirement of $1,766,000 of retail patronage for 1984.
In November 2000, the Board of Directors authorized the retirement of $3,750,000 of retail patronage for 1984 and 1985.
In November 2001, the Board of Directors authorized the retirement of $3,000,000 of retail patronage for 1985.
Following is a five-year summary of anticipated capital credit retirements:
Year ending Wholesale Retail Total 2002 $0 $3,500,0 $3,500,000 2003 0 3,500,0 3,500,000 2004 1,359,000 2,141,0 3,500,000 2005 1,109,000 2,391,0 3,500,000 2006 1,671,000 1,829,0 3,500,000
(5) Other Equities
A summary of other equities at December 31 follows:
Covenants
Chugach is in compliance with all covenants set forth in the Indenture of Trust, dated September 15, 1991.
Security
Substantially all assets are pledged as collateral for the long-term obligations until retirement of the 1991 Series A Bond and subsequent institution of the Amended and Restated Indenture. On the release date, the Bonds will become general unsecured and unsubordinated obligations. Under the Amended Indenture, 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 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.
Rate
The 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 1.20 times total interest expense. Margins for interest generally consist of our assignable margins plus total interest expense and income tax accruals. The Amended Indenture will require 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.
Distribution to Members
The Indenture prohibits Chugach from making any distribution of patronage capital to our customers if an event of default under the Indenture then exists. Otherwise we are permitted to make distributions to our members after December 31, 1990 in the aggregate amount of $7 million plus 35% of the aggregate assignable margins earned after December 31, 1990. This restriction does not apply if, after the distribution, our aggregate equities and margins as of the end of the immediately preceding fiscal quarter would be equal to at least 45% of our total liabilities and equities and margins. The Amended Indenture will prohibit Chugach from making any distribution of patronage capital to our customers if an event of default under the Amended Indenture then 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 will not apply if, after the distribution, our aggregate equities and margins as of the end of the immediately preceding fiscal quarter would be equal to at least 30% of our total liabilities and equities and margins. The Association does not anticipate that this provision will limit the anticipated capital credit retirements described in note 4.
Maturities of Long-term Obligations
Long-term obligations at December 31, 2001, mature as follows:
The Association had an annual line of credit of $35,000,000 in 2001 and 2000 available with CoBank. The CoBank line of credit expires August 1, 2002, but carries an annual automatic renewal clause. At December 31, 2001, there was $11 million outstanding on this line of credit, which carried an interest rate of 3.75%. At December 31, 2000, there was $35 million outstanding on this line of credit, which carried an interest rate of 8.20%. In addition, the Association had an annual line of credit of $50,000,000 available at December 31, 2001 and 2000 with NRUCFC. At December 31, 2001, there was no outstanding balance on this line of credit. At December 31, 2000, there was $5 million outstanding on this line of credit, which carried an interest rate of 8.55%. The NRUCFC line of credit expires October 14, 2002.
Refinancing
On April 17, 2001, Chugach issued $150,000,000 of 2001 Series A Bond, for the purpose of retiring indebtedness outstanding under existing lines of credit and outstanding bonds, for capital expenditures and for general working capital. The lines of credit had an aggregate outstanding principal balance of $55,000,000, as of April 17, 2001, were renewable annually and bore interest at variable annual rates ranging from 7.55% to 7.80% at April 17, 2001. The variable-rate bonds retired had an aggregate outstanding principal balance of $72,500,000, as of April 17, 2001, would have matured in 2002 and bore interest at a variable rate that was 7.55% on April 17, 2001.
The 2001 Series A Bond will mature on March 15, 2011, and bear interest at 6.55% per annum. Interest will be paid semi-annually on March 15 and September 15 of each year commencing on September 15, 2001. The 2001 Series A Bond is secured by a first lien on substantially all of Chugach's assets. The first lien will be automatically released when all bonds issued by Chugach prior to April 1, 2001, cease to be outstanding or their holders consent to conversion to unsecured status. Thereafter, the 2001 Series A Bond will be unsecured obligations, ranking equally with Chugach's other unsecured and unsubordinated obligations.
On September 19, 1991, Chugach issued $314,000,000 of First Mortgage Bond, 1991 Series A (Bond), for purposes of repaying existing debt to the Federal Financing Bank and the Rural Electrification Administration (now Rural Utilities Services). Pursuant to Section 311 of the Rural Electrification Act, Chugach was permitted to prepay the REA debt at a discounted rate of approximately 9%, resulting in a discount of approximately $45,000,000 (note 12).
The bond maturing in 2002 (1991 Series A 2002 Bond) is subject to annual sinking fund redemption at 100% of the principal amount thereof, which commenced March 15, 1993. The bond maturing in 2022 (1991 Series A 2022 Bond) is subject to annual sinking fund redemption at 100% of the principal amount thereof commencing March 15, 2003. The Series A 2002 Bond is not subject to optional redemption. The Series A 2022 Bond is redeemable at the option of Chugach on any interest payment date at an initial redemption price commencing in 2002 of 109.140 of the principal amount thereof declining ratably to par on March 15, 2012. The Bond is secured by a first lien on substantially all of Chugach's assets. The Indenture prohibits outstanding short-term indebtedness (other than trade payables) in excess of 15% of Chugach's net utility plant and limits certain cash investments to specific securities.
In February 1999, Chugach reacquired $11,000,000 of the 1991 Series A 2022 Bond at a premium of 117.05. Total transaction costs, including accrued interest and premium, were $13,322,344.
In February 1999, Chugach reacquired $14,000,000 of the 1991 Series A 2022 Bond at a premium of 116.25. Total transaction costs, including accrued interest and premium, were $16,868,592.
In February 1999, Chugach reacquired $9,895,000 of the 1991 Series A 2022 Bond at a premium of 116.75. Total transaction costs, including accrued interest and premium, were $11,974,467.
In March 2000, Chugach reacquired $8,500,000 of the 1991 Series A 2022 Bond at a premium of 104.00. Total transaction cost, including accrued interest and premium, were $9,215,502.
In April 2000, Chugach reacquired $10,000,000 of the 1991 Series A 2022 Bond at a premium of 108.875. Total transaction costs, including accrued interest and premium, were $10,953,511.
In May 2001, Chugach reacquired $10,000,000 of its 1991 Series A 2022 Bond at a premium of 111.00. Total transaction costs, including accrued interest and premium, were $11,242,178.
In December 2001, Chugach reacquired $5,000,000 of its 1991 Series A 2022 Bond at a premium of 111.00. Total transaction costs, including accrued interest and premium, were $5,661,711.
The premiums paid are reflected as a regulatory asset and amortized over the life of the 2001 Series A Bond.
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. The settlement payments were accounted for as regulatory assets. Chugach believes the regulatory assets will be recovered through rates, however, if the RCA does not approve this treatment, such amounts that are not deferrable under SFAS 133 would be charged off. As of December 31, 2001, the aggregate principal amount of the Series A Bond due 2022 was $149,310,000.
(7) Fair Value of Long-Term Obligations
The estimated fair values (in thousands) of the long-term obligations included in the financial statements at December 31 are as follows:
Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions.
(8) Employee Benefits
Employee benefits for substantially all employees are provided through the Alaska Electrical Trust and Alaska Hotel, Restaurant and Camp Employees Health and Welfare Trust Funds (union employees) and the National Rural Electric Cooperative Association (NRECA) Retirement and Security Program (nonunion employees). The Association makes annual contributions to the plans equal to the amounts accrued for pension expense. For the union plans, the Association pays a contractual hourly amount per union employee, which is based on total plan costs for all employees of all employers participating in the plan. In these master, multiple-employer plans, the accumulated benefits and plan assets are not determined or allocated separately to the individual employer. Costs for union plans were approximately $1,990,000 in 2001, $2,017,000 in 2000 and $1,832,000 in 1999. In 2001, 2000 and 1999, the Association contributed $1,397,000, $1,057,000 and $868,000, respectively, to the NRECA plan.
(9) Deferred Charges
Deferred charges consisted of the following at December 31:
2001 2000 ---- ---- Debt issuance and reacquisition costs $15,649,174 $5,399,282 Refurbishment of transmission equipment 243,828 253,087 Computer software and conversion 8,161,890 10,672,135 Studies 1,776,576 1,724,936 Business venture studies 531,416 562,435 Fuel supply negotiations 348,986 346,894 Major overhaul of steam generating unit 17,092 222,198 Environmental matters and other 272,899 261,892 Other regulatory deferred charges 1,704,432 0 --------- - $28,706,293 $19,442,859 =========== =========== (10) Employee Representation
Approximately 72% of the Association's employees are represented by the International Brotherhood of Electrical Workers (IBEW). The various IBEW contracts expire on June 30, 2003.
(11) Deferred Credits
Deferred credits at December 31 consisted of the following:
In conjunction with the refinancing described in note 6, the Association had recognized a gain of approximately $45,000,000. The APUC required the Association to pass through the gain to consumers in the form of reduced rates over a period equal to the life of the bonds using the effective interest method; consequently, the gain has been deferred for financial reporting purposes as required by SFAS 71. Approximately $1,231,000 of the deferred gain was amortized in 2001. Approximately $1,553,000 of the deferred gain was amortized in 2000. Approximately $1,215,000 of the deferred gain was amortized in 1999.
(12) Bradley Lake Hydroelectric Project
The Association is a participant in the Bradley Lake Hydroelectric Project (Bradley Lake). Bradley Lake was built and financed by the Alaska Energy Authority (AEA) through State of Alaska grants and $166,000,000 of revenue bonds. The Association and other participating utilities have entered into take-or-pay power sales agreements under which shares of the project capacity have been purchased and the participants have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt service costs and amounts required to maintain established reserves). Under these take-or-pay power sales agreements, the participants have agreed to pay all project costs from the date of commercial operation even if no energy is produced. The Association has a 30.4% share of the project's capacity. The share of debt service exclusive of interest, for which the Association has guaranteed, is approximately $44,000,000. Under a worst-case scenario, the Association could be faced with annual expenditures of approximately $4.1 million as a result of its Bradley Lake take-or-pay obligations. Management believes that such expenditures, if any, would be recoverable through the fuel surcharge ratemaking process. Upon the default of a Bradley Lake participant, and subject to certain other conditions, AEA, through Alaska Industrial Development and Export Authority, is entitled to increase each participant's share of costs pro rata, to the extent necessary to compensate for the failure of another participant to pay its share, provided that no participant's percentage share is increased by more than 25%.
On April 6, 1999, AEA issued $59,485,000 of Power Revenue Refunding Bonds, Third Series, for the purpose of refunding $59,110,000 of the First Series Bonds. The refunded First Series Bonds were called on July 1, 1999. The refunding resulted in aggregate debt service payments over the next nineteen years in a total amount approximately $9,500,000 less than the debt service payments, which would be due on the refunded bonds. There was an economic gain of approximately $5,900,000. Economic gain is calculated as the net difference between the present value of the old debt service requirements and the present value of the new debt service requirements, discounted at the effective interest rate and adjusted for additional cash paid.
On April 13, 1999, AEA issued $30,640,000 of Power Revenue Refunding Bonds, Fifth Series, for the purpose of refunding $28,910,000 of the First Series Bonds. The refunded First Series Bonds were called on July 1, 1999. The refunding resulted in aggregate debt service payments over the next twenty-three years in a total amount approximately $4,400,000 less than the debt service payments, which would be due on the refunded bonds. There was an economic gain of approximately $2,900,000.
On April 4, 2000, AEA issued $47,710,000 of Power Revenue Refunding Bonds, Fourth Series, for the purpose of refunding $46,235,000 of the Second Series Bonds. The refunded Second Series Bonds were called on July 1, 2000. The refunding resulted in aggregate debt service payments over the next twenty-two years in a total amount approximately $6,400,000 less than the debt service payment, which would be due on the refunded bonds. There was an economic gain of approximately $3,500,000.
The following represents information with respect to Bradley Lake at June 30, 2001 (the most recent date for which information is available). The Association's share of expenses was $3,929,614 in 2001, $3,696,829 in 2000 and $3,902,737 in 1999 and is included in purchased power in the accompanying financial statements.
(In thousands) Total Proportionate Share ----- ------------------- Plant in service $ 306,872 $ 93,289 Accumulated depreciation (67,534) (20,530) Interest expense 9,467 2,878
Other electric plant in service represents the Association's share of a Bradley Lake transmission line financed internally and the Association's share of the Eklutna Hydroelectric Project, purchased in 1997 (note 14).
(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 consists of the Association along with Matanuska Electric Association (MEA) and Municipal Light and Power (AML&P).
Other electric plant in service includes $1,957,742 representing the Association's share of the Eklutna Hydroelectric Plant. This balance will be amortized over the estimated life of the facility. During the transition phase and after the transfer of ownership, Chugach, MEA and AML&P have jointly operated the facility. Each participant contributes their proportionate share for 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.
(14) Commitments and Contingencies
Contingencies
The Association is a participant in various legal actions, rate disputes, personnel matters and claims both for and against its interests. Management believes that the outcome of any such matters will not materially impact the Association's financial condition, results of operations or liquidity.
Long-Term Fuel Supply Contracts
The Association has entered into long-term fuel supply contracts from various producers at market terms. The current contracts will expire at the end of the currently committed volumes or the contract expiration dates of 2015 and 2025.
Significant Customers
The Association is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts represented $57.7 million or 32.3% of operating revenues in 2001, $45.2 million or 28.5% in 2000 and $43.4 million or 30.4% in 1999. These contracts will expire in 2014.
Cooper Lake Hydroelectric Plant
The Association discovered polychlorinated biphenyls (PCBs) in paint, caulk and grease at the Cooper Lake Hydroelectric plant during initial phases of a turbine overhaul. A Federal Energy Regulatory Commission (FERC) approved plan, prepared in consultation with the Environmental Protection Agency (EPA), was implemented to remediate the PCBs in the plant. As a condition of its approval of the license amendment for the overhaul project, FERC required Chugach to also investigate the presence of PCBs in Kenai Lake. A sampling plan was developed by Chugach in consultation with various agencies and approved by FERC. In 2000, Chugach sampled sediments and fish collected from Kenai Lake and other waters. While extremely low levels of PCBs were found in some sediment samples taken near the plant, no pathway from sediment to fish was established. Additional sediment sampling and analysis in this area is being performed. While the presence of PCBs in fish did not reveal amounts above background levels, Chugach has conducted additional sampling and analysis of fish in Kenai Lake and other waters and is preparing a report to FERC, analyzing the results of the sampling. Management believes the costs of this work will be recoverable through rates and therefore will have no material impact on our financial condition or results of operations. The RCA has issued an order to Chugach generally allowing prudently incurred remediation costs at Cooper Lake to be recovered through rates, however, the RCA has not approved the final recovery amount in this matter and will review these costs as part of the 2000 test year rate case.
Legal Proceedings
Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc. Superior Court Case No. 3AN-99-8152 Civil -------------------------------------------------------------------------
This action was 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 the Company's sale of power to MEA during that time. MEA asserted the Company breached that contract by failing to provide a variety of kinds of information, by failing to properly manage the Company's long-term debt, and by failing to bring its base rate action to the Joint Rates Committee before presentation to the RCA. All of MEA's claims have been dismissed. MEA has indicated that it intends to appeal to the Alaska Supreme Court, at a minimum, the Superior Court's dismissal of its financial mismanagement claim.
Regulatory Cost Charge
In 1992 the State of Alaska Legislature passed legislation authorizing the Department of Revenue to collect a regulatory cost charge from utilities in order to fund the APUC. The tax is assessed on all retail consumers and is based on kilowatt-hour (kWh) consumption. The Regulatory Cost Charge has decreased since its inception (November 1992) from an initial rate of $.000626 per kWh to the current rate of $.000360, effective October 1, 2001.
(15) Recent Accounting Pronouncements
Chugach was required to adopt SFAS 133, Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS 138, Accounting for Certain Derivative Instruments and Certain Hedging Activities, an Amendment of FASB Statement No. 133, effective January 1, 2001. This new standard requires all derivative financial instruments to be reflected on the balance sheet. The adoption resulted in Chugach establishing a liability for the settlement of U.S. Treasury Rate Lock Agreements.
In July 2001, the Financial Accounting Standards Board issued Statement 141, Business Combinations, and Statement 142, Goodwill and Other Intangible Assets. Statement 141 requires that the purchase method of accounting be used for all business combinations initiated or completed after June 30, 2001. Statement 142 will require that goodwill and intangible assets with indefinite useful lives no longer be amortized, but instead tested for impairment at least annually. The provisions of Statement 142 are required to be applied starting with fiscal years beginning after December 15, 2001. Management believes the adoption of Statement 141 and 142 will have no impact on our financial statements.
In August 2001, the Financial Accounting Standards Board issued Statement 143, Accounting for Asset Retirement Obligations. Statement 143 requires an enterprise to record the fair value of an asset retirement obligation as a liability in the period in which it incurs a legal obligation associated with the retirement of tangible long-lived assets and an increase to the carrying amount of the related long-lived asset, which is depreciated over the life of the asset. Enterprises are required to adopt Statement 143 for fiscal years beginning after June 15, 2002. Management believes the adoption of Statement 143 will have no impact on our financial statements.
In October 2001, the Financial Accounting Standards Board issued Statement 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Statement 144 addresses financial accounting and reporting for the impairment or disposal of long-lived assets. While Statement 144 supersedes FASB Statement 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, it retains many of the fundamental provisions of that Statement, and broadens the presentation of discontinued operations to include more disposal transactions. Statement 144 also supersedes the accounting and reporting provisions of Accounting Principles Board (APB) Opinion 30, Reporting the Results of Operations-Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions, for the disposal of a segment of a business. However, it retains the requirement in Opinion 30 to report separately discontinued operations and extends that reporting to a component of an entity that either has been disposed of or is classified as held for sale. Statement 144 is effective for fiscal years beginning after December 15, 2001, and interim periods within those fiscal years. Management believes the adoption of Statement 144 will have no impact on our financial statements.
(16) Segment Reporting
The Association had divided its operations into two reportable segments: Energy and Internet service. The energy segment derives its revenues from sales of electricity to residential, commercial and wholesale customers, while the Internet segment derives its revenues from provision of residential and commercial internet services and products. The reporting segments follow the same accounting policies used for the Association's financial statements and described in the summary of significant accounting policies. Management evaluates a segment's performance based upon profit or loss from operations. Jointly used assets are allocated by percentage of reportable segment usage and centrally incurred costs are allocated using factors developed by the Association, which are patterned upon usage. The following is a tabulation of business segment information for the years ended December 31:
As of March 6, 2001, with an effective date of March 20, 2001, Chugach sold the bulk of it's internet service provider assets related to dial-up services (excluding DSL services) to GCI Communication Corporation. The aggregate purchase price was $759,049 at closing, plus an additional amount of $70,075, which was based on number of subscriber accounts retained during the ninety-day transition period following closing. These transactions resulted in a loss of $258,073.
(17) Quarterly Results of Operations (unaudited)
(18) Subsequent Events
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 bear interest at 6.20% per annum. Interest will be paid 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 will bear 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 afterwards, will initially bear interest at the rate set for 28-day auction periods. The initial auction date will be February 27, 2002. The applicable interest rate for any 28-day auction period will be the term rate established by the auction agent based on the terms of the auction. The Auction Rate Bond may be converted, in our 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 will act as the auction agent and J.P. Morgan Securities Inc., will act as the initial broker-dealer for the Auction Rate Bond.
Payment of the 2002 Series A Bond and the Auction Rate Bond (collectively the "Bonds") initially will be secured by a first lien on substantially all of Chugach's tangible and some intangible properties. The first lien will be automatically released when all bonds issued by Chugach prior to April 1, 2001, cease to be outstanding or their holders consent to the release of the lien. After that time, the Bonds will be unsecured obligations, ranking equally with our other unsecured and unsubordinated obligations. In addition, we will be limited in our ability to secure obligations for borrowed money or the deferred purchase price of property after that time unless Chugach equally and ratably secures our outstanding indebtedness subject to the Indenture governing the Bonds.
Treasury Rate Lock Agreements
On January 14, 2002, Chugach entered into an 18-day rate lock agreement with JP Morgan on the $120 million 10-year term bond of the proposed 2002 financing based on the 10-year treasury issued August 15, 2001, that was trading at 4.877%. That rate, along with a 0.041% U.S. note fee, set a benchmark rate for the transaction at 4.918%. Chugach terminated the rate lock on February 1, 2002, which generated a payment to Chugach of $1.2 million. The settlement payment will be reflected as an offset to regulatory assets.
Item 9
Item 9 - Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
PART III
Item 10
Item 10 - Directors and Executive Officers of the Registrant
Management
We operate under the direction of a Board of Directors that is elected at large by our membership. Day-to-day business and affairs are administered by the General Manager. Our seven-member Board of Directors sets policy and provides direction to our General Manager. The following table sets forth certain information with respect to our executive officers and directors.
Executive Officers
Eugene N. Bjornstad was appointed our General Manager on June 22, 1994. Prior to that he served as Acting General Manager from March 28, 1994, until his permanent appointment. He joined Chugach in 1983 and served as Executive Manager, Operating Divisions from 1988 to 1994. Mr. Bjornstad has given notice of his intention to retire in May 2002. The Board of Directors has undertaken the process of finding a replacement.
Lee D. Thibert was appointed our Executive Manager, Transmission & Distribution Network Services in a reorganization on June 1, 1997. Prior to that he was Executive Manager, Operating Divisions from June of 1994. Before moving up to the Executive Manager position, he served as Director of Operations from May 1987.
Evan J. Griffith has been our Executive Manager, Finance and Energy Supply since our internal reorganization on June 1, 1997. Prior to that, he was Executive Manager, Finance & Planning from August 1989 to June 1997. Prior to coming to us, he was Budget/Program Analyst for the Anchorage Municipal Assembly from August 1984 to August 1989.
William R. Stewart has been our Executive Manager, Retail Services since the June 1, 1997 reorganization. Prior to that, he was our Executive Manager, Administration from July 1987 to June 1, 1997. He was our Division Director of Administration from January 1984 to July 1987 and Staff Assistant to the General Manager of Chugach from November 1982 to January 1984. He has been employed by us since 1969.
Board of Directors
Bruce Davison serves as President of the Board. He had served as the Secretary of the Board since April 1998. Mr. Davison was first appointed to the Board of Directors in June 1997. Prior to his appointment, he served two years on our Bylaws Committee. He is a partner in the law firm of Davison & Davison, Inc.
Red Boucher became Vice President of the Board in April 2001. He was elected to the Board in April 1999. In addition to being a director, Mr. Boucher owns a consulting firm, serves as president of a telecommunication firm and hosts a weekly statewide TV show. He has held many elected offices including Lieutenant Governor of Alaska.
Chris Birch has been serving as Secretary of the Board since April 2001. He was appointed to fill a Board vacancy in October 1996. Mr. Birch was elected to that seat in April 1997 and since that time has served as a director. He has previously served as Secretary and President. He is a professional engineer for the Alaska Department of Transportation and Public Facilities.
Jeff Lipscomb was elected director in April 2000 and currently serves as Treasurer. Mr. Lipscomb is the principal of JWL Engineering, which he founded in 1995. He is a professional mechanical engineer with over 20 years of experience in Alaskan oil and gas production facility design.
Pat Kennedy has served on the board since 1993 and has served as both Secretary and President. She is an attorney who has been licensed to practice law since 1976.
Pat Jasper most recently served as the President of the Board from April 2000 to April 2001. Ms. Jasper was originally elected to the Board in April 1995. Since 1995, she has held several offices including Secretary, Vice President and President. She is a small business owner and has been a computer programmer and systems analyst.
Dave Cottrell was elected to the Board in April 2001. Mr. Cottrell has been the president and managing partner at Mikunda Cottrell & Co., an accounting firm he owns in Anchorage, since 1977. Mr. Cottrell is a certified public accountant.
Item 11
Item 11 - Executive Compensation
Cash Compensation
.........The following table sets forth all remuneration paid by us for the last three years to each of our four executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2001, and for all such executive officers as a group:
Our directors are compensated for their services in the amount of $100 per board meeting attended (including committee meetings) up to a maximum of seventy meetings per year for a director and eighty-five meetings per year for the President. Upon termination, Mr. Bjornstad's employment agreement provides that he may receive an amount equal to his salary for the greater of six months or remaining term of his employment agreement (which number shall not be less than six months) plus any accrued annual leave or other compensation then due as of the effective date of the notice of termination.
Compensation Pursuant to Plans
We have elected to participate in the National Rural Electric Cooperative Association (NRECA) Retirement and Security Program (the "Plan"), a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. The Plan is intended to be a qualified pension plan under Section 401(a) of the Code. All our employees not covered by a union agreement become participants in the Plan on the first day of the month following completion of one year of eligibility service. An employee is credited with one year of eligibility service if he completes 1,000 hours of service either in his first twelve consecutive months of employment or in any calendar year for 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 performs at least one hour of service for us or a related employer. Pension benefits are generally paid upon the participant's retirement or death. A participant may also elect to receive pension benefits while still employed by us if he has reached his normal retirement date by completing thirty years of benefit service (defined below) or, if earlier, by attaining age sixty-two. A participant may elect to receive actuarially reduced early retirement pension benefits before his normal retirement date provided he has attained age fifty-five.
Pension benefits paid in normal form are paid monthly for the remaining lifetime of the participant. Unless an actuarially equivalent optional form of benefit payment to the participant is elected, upon the death of a participant the participant's surviving spouse will receive pension benefits for life equal to 50% of the participant's benefit. The annual amount of a participant's pension benefit and the resulting monthly payments the participant receives under the normal form of payment are based on the number of his years of participation in the Plan (benefit service) and the highest five-year average of the annual rate of his base salary during the last ten years of his participation in the Plan (final average salary). Annual compensation in excess of $200,000, as adjusted by the Internal Revenue Service for cost of living increases, is disregarded after January 1, 1989. The participant's annual pension benefit at his normal retirement date is equal to the product of his years of benefit service (up to thirty) times final average salary times 2%. In 1998, NRECA notified us that there were employees whose pension benefits from NRECA's Retirement & Security Program would be reduced because of limitations on retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA made available a Pension Restoration Severance Pay Plan and a Pension Restoration Deferred Compensation Plan for cooperatives to adopt in order to make employees whole for their lost benefits. In May 1998, we adopted both of these plans to protect the benefits of current and future employees whose pension benefits would be reduced because of these limitations.
The following table sets forth the estimated annual pension benefit payable at normal retirement date for participants in the specified final average salary and years of benefit service categories:
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, 2001 taken into account under the Plan for the executive officers is shown below. Base salary for 2001 taken into account under the Plan for purposes of determining final average salary is also included.
Employment Arrangements
In August 2001, we entered into an employment agreement with Eugene Bjornstad, our General Manager. He is paid an annual base salary of $175,000. Mr. Bjornstad also is eligible to receive additional compensation, bonus and benefits for meeting performance goals established annually by the Board of Directors. In the event that Mr. Bjornstad is terminated without cause, he will be entitled to severance in an amount equal to six months of his annual salary, plus any accrued annual leave and any bonuses or other compensation then due.
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management
Not Applicable
Item 13
Item 13 - Certain Relationships and Related Transactions
Not Applicable
PART IV
Item 14
Item 14 - Exhibits, Financial Statement Schedules and Reports on Form 8-K
Page
Financial Statements
Included in Part IV of this Report: Independent Auditors' Report 36 Balance Sheets, December 31, 2001 and 2000 37-38 Statements of Revenues, Expenses and Patronage Capital, Years ended December 31, 2001, 2000 and 1999 39 Statements of Cash Flows, Years ended December 31, 2001, 2000 and 1999 40 Notes to Financial Statements 41-65
Financial Statement Schedules
Included in Part IV of this Report: Schedule II - Valuation and Qualifying Accounts, Years ended December 31, 2001, 2000 and 1999 73
Other schedules are omitted as they are not required or are not applicable, or the required information is shown in the applicable financial statements or notes thereto.
Schedule II
CHUGACH ELECTRIC ASSOCIATION, INC.
Valuation and Qualifying Accounts
EXHIBITS
Listed below are the exhibits, which are filed as part of this Report:
REPORTS ON FORM 8-K
The Company was not required to file any report on Form 8K for the year ended December 31, 2001.
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 29, 2002.
CHUGACH ELECTRIC ASSOCIATION, INC.
By: /s/ Eugene N. Bjornstad Eugene N. Bjornstad, General Manager
Date: March 29, 2002
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated March 29, 2002:
/s/ Eugene N. Bjornstad Eugene N. Bjornstad General Manager
/s/ Lee D. Thibert Lee D. Thibert Executive Manager, T&D Network Services
/s/ Evan J. Griffith Evan J. Griffith Executive Manager, Finance & Energy Supply (Principal Financial officer) /s/ William R. Stewart William R. Stewart Executive Manager, Retail Services
/s/ Michael R. Cunningham Michael R. Cunningham Controller (Principal Accounting officer) /s/ Bruce Davison Bruce Davison President (Principal Executive Officer & Director) /s/ H.A. Boucher H.A. Boucher Director & Vice President
/s/ Christopher Birch Christopher Birch Director & Secretary
/s/ Jeffrey Lipscomb Jeffrey Lipscomb Director & Treasurer
/s/ Elizabeth Page Kennedy Elizabeth Page Kennedy Director
/s/ Patricia B. Jasper Patricia B. Jasper Director
/s/ Dave Cottrell Dave Cottrell 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 2001 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.