Item 1 - Business
General
Chugach was organized as an Alaska electric cooperative in 1948. Cooperatives are business organizations that are owned by their members. As not-for-profit organizations (Internal Revenue Code 501 (c)(12)), cooperatives are intended to provide services to their members at cost, in part by eliminating the need to produce profits or a return on equity other than for reasonable reserves and margins. Today, cooperatives in general operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and credit. All cooperatives are based upon similar principles and legal foundations. Because members’ equity is not considered an investment, a cooperative’s objectives and policies are oriented to serving member interests, rather than maximizing return on investment.
Chugach makes its current and periodic reports available, free of charge, on its website at www.chugachelectric.com as soon as practicable after filing with the Securities and Exchange Commission (SEC). Our website provides a link to the SEC website.
Chugach is the largest electric utility in Alaska. We are engaged in the generation, transmission and distribution of electricity to approximately 80,300 active metered locations in the Anchorage and upper Kenai Peninsula areas. Through an interconnected regional electrical system, our energy is distributed throughout Alaska’s Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska’s largest cities, Anchorage and Fairbanks. Neither Chugach nor any other electric utility in Alaska has any connection to the electric grid of the mainland United States or Canada.
Chugach is a rural electric cooperative that is exempt from federal income taxation as an organization described in Section 501(c)(12) of the Internal Revenue Code (Code). Alaska electric cooperatives must pay to the State of Alaska, a gross receipts tax 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. This tax is accrued monthly and remitted annually. In addition, we currently collect a regulatory cost charge (RCC) of $0.000274 per kWh of retail electricity sold. This charge is assessed to fund the operations of the Regulatory Commission of
Alaska (RCA). This tax is collected monthly and remitted to the State of Alaska quarterly. We also collect sales tax on retail electricity sold to Kenai and Whittier consumers. This tax is also collected monthly and remitted to the Kenai Peninsula Borough quarterly. These taxes are a direct pass-through to consumers bills and thus do not impact our margins.
Our workforce consists of approximately 348 full-time employees. Approximately 70% of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW, which expire on June 30, 2010. We also have an agreement with the Hotel Employees & Restaurant Employees (HERE) which also expires on June 30, 2010. We believe our relationship with our employees is good.
Through direct service to retail customers and indirectly through wholesale and economy energy sales, we provide some or all of the electricity used by approximately two-thirds of Alaska’s electric customers. We supply much of the power requirements of three wholesale customers, Matanuska Electric Association (MEA), Homer Electric Association (HEA) and the City of Seward (Seward). We sell available generation in excess of our own needs to produce electric energy for sale to Golden Valley Electric Association, Inc. (GVEA). In addition, on a periodic basis, we provide electricity to Anchorage Municipal Light & Power (AML&P or ML&P).
Our members are the consumers of the electricity sold by us. As of December 31, 2007, we had 65,360 retail members receiving service at approximately 80,300 active metered locations and three major wholesale customers. No individual retail customer receives more than 5% of our power.
Our customers are billed per a tariff rate on a monthly basis for electrical power consumed during the preceding period. Billing rates are approved by the RCA (see “Rate Regulation and Rates” below).
Rates (derived on the basis of historic cost of service and margins) are established to generate revenues in excess of current period costs in any year and such excess is designated on our Statements of Revenues, Expenses and Patronage Capital as “assignable margins.” Retained assignable margins are designated on our balance sheet as “patronage capital” that is assigned to each member on the basis of patronage.
We have 530 megawatts of installed generating capacity provided by 17 generating units at our five owned power plants: Beluga Power Plant, Bernice Lake Power Plant, International Generation and Transmission Power Plant (IGT), Cooper Lake Hydroelectric Project and Eklutna Hydroelectric Project, in which we own a 30% interest. Approximately 85% (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 2007, 93% of our power was generated from gas, and 86% of that gas-fired generation took place at Beluga. The Bradley Lake Hydroelectric Project provides up to 27.4 megawatts for our retail customers and up to 38.6 megawatts for our wholesale customers. For more information concerning Bradley Lake, see “Item 2 - Properties - Other Property - Bradley Lake.” We also purchase approximately 40 megawatts from the Nikiski power plant on the Kenai Peninsula. We operate 1,673 miles of distribution line and 533 miles of transmission line, which includes 128 miles of leased transmission lines and
Chugach’s share of the Eklutna transmission line. For the year ended December 31, 2007, we sold 2.6 billion kilowatt hours (kWh) of electrical power.
Customer Revenue From Sales
The following table shows the energy sales to and electric revenues from our retail, wholesale, and economy energy customers for the year ended December 31, 2007:
Retail Customers
Service Territory
Our retail service area covers the populated areas of Anchorage (other than downtown Anchorage) as well as remote mountain areas and villages. The service area ranges from the northern Kenai Peninsula on the south, to Tyonek on the west, to Whittier on the east and to the Glenn Highway on the north.
Customers
As of December 31, 2007, we had 65,360 members being served by approximately 80,300 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 2007, our wholesale power contracts, including the fuel component, produced $97.8 million in revenues, representing 39% of our total revenues and 50% of our total sales to customers.
MEA and HEA
We have two power sales contracts with Alaska Electric Generation & Transmission Cooperative, Inc., (AEG&T): one for firm, all-requirement sales to MEA and one for firm, partial- requirement sales to HEA. AEG&T is a generation and transmission cooperative that was formed by MEA and HEA in the mid 1980’s. Under each of these contracts, we sold power to AEG&T, for resale to MEA and HEA. On June 19, 2002, the RCA approved the request by Alaska Electric and Energy Cooperative, Inc. (AEEC) and AEG&T to transfer Certificate of Public Convenience and Necessity No. 345 to serve as the power supplier of HEA to AEEC, instead of AEG&T. HEA is the sole member of AEEC. As part of this transaction our power sales agreement was assigned to AEEC and the Nikiski dispatch agreement was assigned to HEA with certain exceptions with the remaining rights and obligations under the Dispatch Agreement being assigned to AEEC (see ensuing discussion on page 7). Chugach has not experienced a decline in revenue as a result of this transfer. Under our contracts, each of MEA and HEA is obligated to pay us for the power sold to AEG&T and AEEC even if AEG&T and AEEC do not pay.
Under the contract with AEG&T and MEA, MEA is obligated to purchase all of its electric power and energy requirements from us. MEA has the right, on advance notice given after 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 after RCA approval, depending on which non-Chugach resources MEA proposes to use to satisfy its power needs. MEA has not invoked this right at this time.
If MEA converts to a net-requirements purchaser under the contract, MEA cannot reduce its payment for power that it purchases from us below a certain minimum amount. MEA will be required to pay demand charges based upon the highest post-1985 historical coincident peak on the MEA system. Therefore, if MEA converts to net-requirements service, we will continue to recover all or substantially all of the fixed costs now assigned to it. Also, our revenues from energy sales to MEA would partially decline in proportion to the reduction in the energy sold, but this decline would be offset to an extent by savings in the variable costs associated with energy production.
MEA also has the right, on seven years advance notice after RCA approval, to convert to a take-or-pay purchase of a fixed amount of power, also subject to minimum payment requirements associated with prior purchases. The MEA contract is in effect through December 31, 2014. Chugach and MEA met on October 27, 2004, pursuant to Section 12(c) of the MEA/Chugach Power Sales Agreement. This provision requires the parties to meet no later than ten years prior to the termination date of the Agreement, to discuss a possible renewal, extension, or modification of the Agreement, as well as the desires and potential circumstances of all parties following the termination date. At that meeting and shortly thereafter by letter dated November 2, 2004, MEA
communicated to Chugach that MEA does not desire to renew, extend or modify the Agreement. Further, MEA stated that it does not envision any type of firm power purchase arrangement with Chugach following expiration of the Agreement on December 31, 2014. MEA assured Chugach that it intends to continue to purchase power from Chugach in accordance with the Agreement through December 31, 2014.
During the past several years, we have had numerous disputes and engaged in substantial litigation with MEA regarding many aspects of our contractual relationship with it. For a discussion of material pending litigation between MEA and us, see “Item 3 - Legal Proceedings.”
Our contract for the benefit of HEA obligates HEA (through AEEC) to take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per year. The HEA contract, as interpreted by the Alaska Public Utilities Commission (APUC), the predecessor to the RCA, limits the costs that may be included in our rates charged to HEA. The HEA contract expires on January 1, 2014. HEA’s remaining resource requirements are provided by AEEC’s Nikiski cogeneration facility and AEEC’s contract rights to receive power from the Bradley Lake hydroelectric project for the benefit of HEA. In February 1999, we entered into a dispatch agreement with AEG&T to operate the Nikiski unit as a Chugach system resource. The agreement provides that, in addition to the energy that we already sell to AEEC and HEA, we will sell energy to AEG&T equal to HEA’s residual energy requirements less its allocated share of the Bradley Lake project, up to a maximum of 320,000 MWh per year. A portion of the Nikiski unit output may be dispatched for HEA needs in excess of the sum of our contract demand plus HEA’s share of energy from the Bradley Lake project. The dispatch agreement will terminate on January 1, 2014, when our power supply contract for the benefit of HEA terminates. In a letter dated January 9, 2007, HEA notified Chugach that HEA would not seek to renew, extend or modify the current Agreement for Sale of Electric Power and Energy (the Agreement) when the Agreement expires on December 31, 2013. On January 15, 2008, Chugach and HEA signed an agreement entitled Settlement of Dispute over Nikiski Cogeneration Plant System Use and Dispatch Agreement and Premium Demand Charges under HEA’s Power Sales Agreement. This resolved a dispute over the interpretation of the Nikiski Cogeneration Plant System Use and Dispatch agreement. As part of the Settlement Agreement, Chugach agreed to dispatch HEA’s share of Bradley Lake output for $30,000 per year to minimize, to the extent possible, any premium demand charges to be paid to Chugach by HEA. On February 18, 2008, Chugach offered AEEC the opportunity to participate in the development of a gas-fired generation plant in order to partially satisfy its power requirements. For further discussion see “Part II - Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Outlook.”
Seward
We currently provide nearly all the power needs of the City of Seward. Sales to Seward represent approximately 2.0% of Chugach’s total sales of energy (including both retail and wholesale). In February 1998, we entered into a power sales agreement (Old Contract) with Seward that allowed us to interrupt service to Seward up to 12 times per year, not to exceed seventy-two cumulative hours annually and also reduce the demand charge by 1/3 (approximately $350,000 annually). This agreement was scheduled to expire January 31, 2006. The RCA granted a four-month extension to May 31, 2006, of the old contract to allow the parties to complete negotiations on a new contract.
Negotiations with Seward were successful and on April 14, 2006, Chugach filed a request for approval by the RCA of a proposed new power sales agreement with the City of Seward (2006 Agreement) with a nominal effective date of June 1, 2006. The proposed contract was for five years with two automatic five-year extensions unless notice of termination is given by either party and resulted in a 5 percent increase in revenues in relation to the Old Contract.
The 2006 Agreement is an interruptible, all-requirements/no reserves contract. It has many of the attributes of firm service, especially in the requirement that so long as Chugach has sufficient power available, it must meet Seward’s needs for power. However, service is interruptible because Chugach is under no obligation to supply or plan for generation capacity reserves to supply Seward and there is no limit on the number of times or hours per year that the supply can be interrupted.
Counterbalancing this is the requirement that Chugach must provide power to Seward if Chugach has the power available after first meeting its obligations to its other customers for whom Chugach has an obligation to provide reserves (MEA, HEA and Chugach retail customers).
The price under the 2006 Agreement reflects the reduced level of service because no costs of generation in excess of that needed to meet the system peak will be assigned to Seward.
Approval of the new Agreement was contested by Chugach’s wholesale customer, MEA and Chugach’s wholesale customer HEA also intervened in the proceeding. A hearing was set to begin November 30, 2006. Chugach filed a Motion for Summary Disposition. The Motion was granted in part and citing this decision, MEA withdrew from the case.
The remaining parties entered into a stipulation, accepted by the RCA, to allow additional RCA review of the agreement before an automatic extension of the agreement, which is permitted after the first five years of the term of the agreement. On the basis of the stipulation, the RCA cancelled the hearing and the 2006 Agreement with Seward was approved as amended.
Economy Customers
Since 1989, we have sold economy (non-firm) energy to GVEA under an agreement that expires in 2009. Under the agreement, we use available generation 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 purchase gas from Marathon Oil Company (Marathon) to produce energy for sale to GVEA, and we
charge GVEA a rate sufficient to recover the gas cost, the costs of incremental operations and maintenance expense resulting from increased use of our generators for GVEA, and an agreed-upon margin for each kWh sold.
In 2000, the RCA approved an amendment to our agreement with GVEA and a settlement of an inter-utility dispute. As a result, the market for economy energy sold to GVEA has now been divided into two parts. The larger part continues to be governed by a contractual priority right under our agreement with GVEA. Under this contractual priority right provision, if GVEA requires non-firm energy in sufficient quantities, we have an opportunity to sell and GVEA has a corresponding obligation to purchase two-thirds of the first 450,000 MWh and an additional 80% of the excess over 450,000 MWh of the non-firm energy that GVEA purchases each year if we are capable of producing that energy. Under the above contractual priority right provision, non-firm sales to GVEA have been 93,753 MWh, 261,177 MWh, and 294,054 MWh for 2007, 2006, and 2005, respectively. For sales not covered by the contractual priority right, no seller enjoys a contractual priority in making such sales and GVEA makes purchases from the seller offering the lowest competitive price.
Rate Regulation and Rates
The RCA regulates our rates. We can seek changes in our base rates by filing general rate cases with the RCA. On August 10, 2002, A.S. 42.05.175 imposed timelines for RCA decisions. Among other provisions, it provided that for all dockets commenced on or after July 1, 2002, the RCA shall issue a final order not later than 15 months after a complete tariff filing is made for a tariff filing that changes the utility’s revenue requirement or rate design. It is within the RCA’s authority to authorize, after a notice period, rate changes on an interim, refundable basis. In addition, the RCA has been willing to open limited reviews of matters to resolve specific issues from which expeditious decisions can often be rendered.
The RCA has exclusive regulatory control of our retail and wholesale rates, subject to appeal to the Alaska courts. Under Alaska law, financial covenants of an Alaskan electric cooperative contained in a debt instrument will be valid and enforceable, and rates set by the RCA must be adequate to meet those covenants. Under Alaska law, a cooperative utility that is negotiating to enter into a mortgage or other debt instrument that provides for a Times Interest Earned Ratio (TIER) greater than the ratio the RCA most recently approved for that cooperative must submit the mortgage or debt instrument to the RCA before the instrument takes effect. The rate covenants contained in the instruments that govern our outstanding long-term indebtedness do not impose any greater TIER requirement than those previously approved by the RCA.
We expect to continue to recover changes in our fuel and purchased power expenses through routine fuel surcharge filings with the RCA. See “Item 7 - Management’s Discussion and Analysis - Results of Operations- Overview.”
The Amended and Restated Indenture, which became effective January 22, 2003, governs all of our outstanding bonds and requires us to set rates expected to yield margins for interest equal to at least 1.10 times total interest expense. The CoBank Master Loan Agreement also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. On February 6, 2003, we received Order U-01-108(26) from the RCA, based on our 2000 test year general rate case, which revised our overall rate-making TIER from 1.35 to 1.30. For the year ended December 31, 2007, our achieved TIER and Margins for Interest/Interest (MFI/I) was 1.12.
Our Service Areas and Local Economy
Our service areas and those of our wholesale and economy energy customers are often described collectively as the Railbelt region of Alaska because the three geographic areas (the Southcentral, the Kenai Peninsula and the Interior) are linked by the Alaska Railroad.
Anchorage is located in the south central portion of Alaska and is the trade, service and financial center for most of Alaska and serves as a major center for many state governmental functions. Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, air and rail transportation facilities and headquarters support for the petroleum, mining and other basic industries located elsewhere in the state.
The Matanuska-Susitna Borough is immediately north of the Municipality of Anchorage, centered around the communities of Palmer and Wasilla. Although agriculture, tourism, mining and forestry are factors in the economy of the Matanuska-Susitna Borough, the economic well-being of the area is closely tied to that of Anchorage and many Matanuska-Susitna residents commute to jobs in Anchorage.
The Kenai Peninsula is south of Anchorage with an economy substantially independent of the Anchorage area. The most significant basic industry on the Kenai Peninsula is the production and processing of oil and gas from the Cook Inlet region. Agrium is a producer and marketer of agricultural fertilizers and industrial products. Located on the Kenai Peninsula, Agrium is the largest exporter of value-added product from Alaska. In October 2007, Agrium began shutting down operations due to the lack of an economically-priced gas supply. Agrium had considered this a warm shut-down as they reviewed their options, including the possibility of building a coal-gasification facility, however, Agrium announced on March 13, 2008, that they determined the coal gasification project uneconomical at this time. Consequently, Agrium is proceeding with the complete closure of the facility. The impact of a long-term shutdown of this facility impacts the local economy through loss of tax revenue and the impact of the loss of more than a hundred oilfield jobs. Other important basic industries include tourism and seafood 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. Several gold
mines operate near Fairbanks. The Trans-Alaska Pipeline System (which transports crude oil) passes near Fairbanks on its route from the North Slope oilfield to Valdez. Alyeska Pipeline Company, which operates the Trans-Alaska oil pipeline from Prudhoe Bay to Valdez, has its main operations base in Fairbanks.
Load Forecasts
The following table sets forth our projected load forecasts for the next five years:
Retail and wholesale sales are expected to increase over the next five years primarily due to economic growth resulting from continued federal and state spending, and the expansion of the Matanuska-Susitna (MatSu) Borough economy as it grows to meet an increasing suburban population which commutes to work in Anchorage. Our firm energy requirements are expected to grow at an average annual compounded rate of 0.4% from 2008 to 2012, retail sales at a rate of 0.5% and wholesale sales at a rate of 0.3%. The appearance of slower growth in wholesale sales is due to the expected decline in industrial sales by wholesale customer HEA. Without the impact of HEA’s declining industrial sales, wholesale energy sales are forecasted to increase at an average rate of 1.7%, primarily the result of growth in the MatSu Borough. Economy energy sales beyond 2008 are forecasted using a historical planning average. Long-term economy sales are difficult to project due to the uncertainty in the price of petroleum-distillate naphtha, GVEA’s primary fuel type. Furthermore, Chugach’s economy sales agreement with GVEA expires in 2009. These projections are based on assumptions that management believes to be reasonable as of the date the projections were made. The occurrence of a significant change in any of the assumptions could effect a change in the projected sales forecast.
Item 1A
Item 1A - Risk Factors
Chugach’s consolidated financial results will be impacted by weather, the economy of our service territory, fuel availability and prices, the future direction customers may take and the decisions of regulatory agencies. Our creditworthiness will be affected by national and international monetary trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that may affect our consolidated financial condition and results of operations. The statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.
Fuel and Purchased Power Surcharge Mechanism
The fuel and purchased power surcharge mechanism allows Chugach to recover its current fuel and purchased power costs and to recover under-recoveries and refund over-recoveries from prior periods with minimal regulatory lag. Chugach’s fuel surcharge rates are adjusted through quarterly filings with the RCA, which sets the rates on projected costs, sales and system operations for the quarter. Any under or over recovery of costs is incorporated into the following quarterly surcharge. At December 31, 2007, Chugach had over-recovered $1.6 million and at December 31, 2006, Chugach had over-recovered $300.6 thousand. To the extent the regulated fuel recovery process does not provide for the timely recovery of fuel costs, Chugach could experience a material negative impact on its cash flows.
Equipment Failures and Other External Factors
The generation and transmission of electricity require the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. We are vulnerable to this due to the advanced age of several of our gas-fired generating units. In the event of unplanned outages, we must acquire power from others at unpredictable costs in order to supply our customers and comply with our contractual agreements. The fuel and purchased power surcharge mechanism allows Chugach to reflect current purchased power cost and to recover under-recoveries and refund over-recoveries with a three-month lag. If Chugach were to materially under-recover purchased power costs due to an unplanned outage, we would normally seek an increase in the surcharge to recover those costs at the time of the next fuel surcharge filing. As a result, cash flow may be impacted due to the lag in payments of purchased power costs and collection of purchased power costs from customers. To the extent the regulated purchased power recovery process does not provide for the timely recovery of purchased power costs, Chugach could experience a material negative impact on its cash flows. This factor, as well as weather, interest rates, economic conditions, fuel supply and prices, are largely beyond our control, but may have a material adverse effect on our consolidated earnings, cash flows and financial position.
Fuel Supply
For 2007, 93% of our power was generated from gas. Our primary sources of natural gas are the Beluga River Field Producers and Marathon. We have approximately 83 billion cubic feet (BCF) of gas remaining from Marathon and the Beluga River Field producers. We currently use approximately 27 BCF of natural gas per year for firm service. We estimate that our contract gas with the Beluga River Producers will last approximately 3 years. We estimate that our contract gas with Marathon will expire by mid-2010. Chugach is involved in active negotiations to secure additional natural gas supplies after the existing contracts run out. The Cook Inlet continues to be a supply basin with adequate reserves for both domestic and foreign utilities. Chugach anticipates presenting contracts before the RCA by the first quarter of 2009. It is unlikely that Chugach will be unable to negotiate new fuel supply contracts after the existing contracts expire because there are adequate reserves in the Cook Inlet. A study by the Department of Energy (DOE) released in 2004 predicts that for a minimal investment an additional 1.4 trillion cubic feet (TCF) of gas can be extracted from existing fields. In a 2005 study released by the United States Geological Survey (USGS) it was estimated that total recoverable reserves remaining are 8.5 TCF, an amount equal to
what has been extracted from the Cook Inlet over the last thirty years. Additionally, according to an economic analysis completed by the USGS, at prices above $6, significant volumes of gas can be commercially developed from the North Slope. Even though adequate reserves are available for the future, Chugach may experience a change to the existing pricing mechanism from the current contracts. The fuel and purchased power surcharge mechanism allows Chugach to recover its current fuel and purchased power costs with minimal regulatory lag. To the extent the regulated fuel recovery process does not provide for the timely recovery of fuel costs, Chugach could experience a material negative impact on its cash flows.
Capital market
Recent pressures on bond insurers and a lack of liquidity have created volatility in the auction rate securities markets. Chugach currently has $29.6 million of Series B, 2002 bonds outstanding. Chugach mitigated this risk on March 20, 2008 by redeeming the entire outstanding principal amount of the 2002 Series B Bonds using funds available under our existing lines of credit. Chugach management is evaluating future financing plans and intends to refinance this on a long-term basis, however, given the current state of the capital markets, the terms of the future financing may be at higher interest rates. For further discussion see “Item 7A - Quantitative and Qualitative Disclosures About Market Risk -2002 Series B Bonds.”
Chugach has $150 million of 2001 Series A Bonds that is due March 15, 2011. Chugach also has $120 million of 2002 Series A Bonds due February 1, 2012. While Chugach may be subject to interest rate risk at the time of refinancing, management continues to examine several financing alternatives to mitigate this risk.
Wholesale contracts
Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts, including the fuel component, represented $93.4 million or 36.7% of sales revenue in 2007 and $90.1 million or 34.1% in 2006. The HEA contract expires January 1, 2014, and the MEA contract expires December 31, 2014. All rates are established by the RCA.
Chugach and MEA met on October 27, 2004, pursuant to Section 12(c) of the MEA/Chugach Power Sales Agreement. This provision requires the parties to meet no later than ten years prior to the termination date of the Agreement, to discuss a possible renewal, extension, or modification of the Agreement, as well as the desires and potential circumstances of all parties following the termination date. At that meeting and shortly thereafter by letter dated November 2, 2004, MEA communicated to Chugach that MEA does not desire to renew, extend or modify the Agreement. Further, MEA stated that it does not envision any type of firm power purchase arrangement with Chugach following expiration of the Agreement on December 31, 2014. MEA assured Chugach that it intends to continue to purchase power from Chugach in accordance with the Agreement through December 31, 2014.
In a letter dated January 9, 2007, HEA notified Chugach that HEA would not seek to renew, extend or modify the current Agreement for Sale of Electric Power and Energy (the Agreement) when the Agreement expires on December 31, 2013.
Chugach’s planning process reflects the termination of the MEA and HEA wholesale contracts. Nonetheless, the loss of those wholesale customers may require Chugach to file a general rate case to recover total costs and or restructure rates. To the extent that the general rate case could take up to fifteen months to be completed, Chugach may request an interim and refundable rate increase in which the RCA is required to take action within 45 days. 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. In the opinion of management, the loss of those wholesale customers is not likely to have a material adverse effect on Chugach’s results of operations, financial condition or liquidity.
Chugach is in the process of developing a gas-fired generation plant in the South Anchorage area and has offered AEEC and ML&P the opportunity to participate in the project in order to partially satisfy their power requirements. On February 18, 2008, the Board approved authorizing the Interim CEO to execute a Memorandum of Understanding with AEEC and AML&P regarding joint development of the South Anchorage Power Project.
Item 1B
Item 1B - Unresolved Staff Comments
None
Item 2
Item 2 - Properties
General
We have 530 megawatts of installed capacity consisting of 17 generating units at five power plants. These include 385.0 megawatts of operating capacity at the Beluga facility on the west side of Cook Inlet; 67.5 megawatts of power at the Bernice Lake facility on the Kenai Peninsula; 46.7 megawatts of power at IGT in Anchorage; and 19.2 megawatts at the Cooper Lake facility, which is also on the Kenai Peninsula. We also own rights to 11.7 megawatts of capacity from the two Eklutna Hydroelectric Project generating units that we jointly own with MEA and AML&P. In addition to our own generation, we purchase power from the 126 megawatt Bradley Lake hydroelectric project owned by the Alaska Energy Authority (AEA) through the Alaska Industrial Development and Export Authority. The Bradley Lake facility is operated by HEA and dispatched by us. The Beluga, Bernice Lake and International facilities are all fueled by natural gas. We own our offices and headquarters, located adjacent to IGT in Anchorage. We also lease warehouse space for some generation, transmission and distribution inventory (including a small amount of office space).
Generation Assets
We own the land and improvements comprising our generating facilities at Beluga and IGT. We also own all improvements comprising our generating plant at Bernice Lake, located on land leased from HEA. The Bernice Lake ground lease expires in 2011. We are in the process of reviewing the lease.
The Cooper Lake Hydroelectric Project is partially located on federal land. The Project is operated pursuant to a major project license granted to us by the Federal Energy Regulatory Commission (FERC) in May 1957. On April 22, 2005, Chugach filed its Final License Application (FLA), with FERC, seeking a 50-year license for the Project. On August 31, 2005, Chugach filed an Offer of Settlement reflecting a settlement agreement with the affected agencies, non-governmental organizations and others that resolves all major issues surrounding a new 50-year license. On February 28, 2006, FERC issued its formal acceptance of the FLA and settlement agreement for filing and notice that the FLA is ready for environmental analysis. On August 24, 2007, FERC issued Chugach a new 50-year license for the Cooper Lake Hydroelectric Project. The license allows Chugach to continue operations and maintenance of the Cooper Lake power plant.
In 1997, we acquired a 30% interest in the Eklutna Hydroelectric Project. The plant is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October 1997.
Our principal generation units are Beluga 3, 5, 6, 7 and 8. These units have a combined capacity of 345.8 MW and meet most of our load. All other units are used principally as reserve. While the Beluga turbine-generators have been in service for many years, they have been maintained in good working order with annual inspections and periodic upgrades. Beluga Unit 3 had a combustion inspection performed in 2004 and a hot gas path inspection in 2005. Due to the age of Unit 3 several of the high risk parts of the turbine rotor were replaced during a major inspection in 2007. Beluga Unit 5 had a combustion inspection in 2004 and a major inspection in 2005. In 2006 Beluga Unit 5 maintenance requirements increased from one to two combustion inspections per year due to high rates of wear observed on aging combustion parts. This maintenance plan continued with two inspections performed in 2007. Beluga Unit 6 was re-powered in 2000 and had an annual inspection in 2007 during which the last row of turbine blades was exchanged. Beluga Unit 7 was re-powered in 2001 and had its first major inspection in 2004. Beluga Unit 8, a steam turbine, received a 25,000-hour inspection in 2005.
The following matrix depicts nomenclature, run hours for 2007 and percentages of contribution and other historical information for all Chugach generation units.
(1)
Capacity rating in MW at 30 degrees Fahrenheit.
(2)
Steam-turbine powered generator with heat provided by exhaust from natural-gas fueled Units 6 and 7 (combined-cycle).
(3)
Beluga Unit 4 and Bernice Lake Unit 1 were retired during 1994.
(4)
The Eklutna Hydroelectric Project is jointly owned by Chugach, MEA and AML&P. The capacity shown is our 30% share of the plant’s output.
(5)
Because Eklutna Hydroelectric Project is managed by a committee of the three owners, we do not record run hours or in-commission rates.
Note: GE = General Electric, BBC = Brown Boveri Corporation, AP = Alstom Power
Transmission and Distribution Assets
As of December 31, 2007, our transmission and distribution assets included 42 substations and 533 miles of transmission lines, which included 128 miles of leased transmission lines and Chugach’s share of the Eklutna transmission line, 918 miles of overhead distribution lines and 755 miles of underground distribution line. We own the land on which 20 of our substations are located and a portion of the right-of-way connecting our Beluga plant to Anchorage. As part of our 1997 acquisition of 30% of the Eklutna facility, we also acquired a partial interest in two substations and additional transmission facilities.
Many substations and a substantial number of our transmission and distribution rights-of-way are subject to federal or state permits, leases and licenses. Under a federal license and a permit from the United States Forest Service, we operate the Quartz Creek transmission substation and the Hope substation. We also operate transmission lines over federal, state and Kenai Peninsula Borough lands between Cooper Lake on the Kenai Peninsula and Anchorage. Under a State of Alaska permit from the Department of Natural Resources, we operate the Summit Lake and Daves Creek substations. Long-term permits from the Alaska Division of Lands and the Alaska Railroad Corporation govern much of the rest of our transmission system outside the Anchorage area. Within the Anchorage area, we operate our University substation and several major transmission lines pursuant to long-term rights-of-way grants from the U.S. Department of the Interior, Bureau of Land Management, and transmission and distribution lines have been constructed across privately owned lands via easements and across public rights-of-way and waterways pursuant to authority granted by the appropriate governmental entity.
Title
Under the Amended and Restated Indenture, all of Chugach’s bonds are general unsecured and unsubordinated obligations. Chugach is prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on our properties and assets (other than those arising by operation of law) to secure the repayment of borrowed money or the obligation to pay the deferred purchase price of property unless we equally and ratably secure all bonds subject to the Amended and Restated Indenture, except that we may incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements.
Many of our properties are burdened by easements, plat restrictions, mineral reservation, water rights and similar title exceptions common to the area or customarily reserved in conveyances from federal or state governmental entities, and by additional minor title encumbrances and defects. We do not believe that any of these title defects will materially impair the use of our properties in the operation of our business.
Under the Alaska Electric and Telephone Cooperative Act, we possess the power of eminent domain for the purpose and in the manner provided by Alaska condemnation laws for acquiring private property for public use.
Other Property
Bradley Lake. We are a participant in the Bradley Lake hydroelectric project, which is a 126 megawatt rated capacity hydroelectric facility near Homer on the southern end of the Kenai Peninsula that was placed into service in September 1991. The project is nominally scheduled below 90 megawatts to minimize losses and ensure system stability. We have a 30.4% (27.4 megawatts as currently operated) share in the Bradley Lake project’s output, and take Seward’s and MEA’s shares which we net bill to them, for a total of 45% of the project’s capacity. We are obligated to pay 30.4% of the annual project costs regardless of project output.
The project was financed and built by AEA through grants from the State of Alaska and the issuance of $166 million principal amount of revenue bonds supported by power sales agreements with six electric utilities that share the output from the facility (AML&P, HEA and MEA (through AEG&T and AEEC), GVEA, Seward and us). The participating utilities have entered into take-or-pay power sales agreements under which AEA has sold percentage shares of the project capacity and the utilities have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt-service costs and amounts required to maintain established reserves). By contract, we also provide transmission and related services to all of the participants in the Bradley Lake project.
The length of our Bradley Lake power sales agreement is fifty years from the date of commercial operation of the facility (September 1991) or when the revenue bond principal is repaid, whichever is the longer. The agreement may be renewed for successive forty-year periods or for the useful life of the project, whichever is shorter. We believe that our maximum annual liability for our take-or-pay obligations is approximately $5.0 million. We believe that so long as this project produces power taken by us for our use that this expense will be recoverable through the fuel and purchased power surcharge mechanism. The share of Bradley Lake indebtedness for which we are responsible is approximately $37 million. Upon the default of a participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs and output pro rata, to the extent necessary to compensate for the failure of the defaulting participant to pay its share, provided that no participant’s percentage share is increased by more than 25%.
Eklutna. We purchased a 30% undivided interest in the Eklutna Hydroelectric Project from the federal government in 1997. MEA 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 2007, 93% of our power was generated from gas, and 86% of that gas-fired generation took place at Beluga.
Our primary sources of natural gas are the Beluga River Field producers (ConocoPhillips Alaska, Inc., AML&P, Chevron) and Marathon. ConocoPhillips, AML&P and Chevron each own one-third of the gas produced from the Beluga River Field and in 2007 each provided approximately 16% of the gas burned at the Beluga power plant. We have approximately 83 billion cubic feet (BCF) of gas remaining from Marathon and the Beluga River Field producers. We currently use approximately 27 BCF of natural gas per year for firm service. We estimate that our contract with the Beluga River Producers will last approximately 3 years. We estimate that our contract gas with Marathon will expire by mid-2010. Under almost all circumstances the deliverability supplied under our contracts is sufficient to meet all of our generating requirements.
Beluga River Field Producers
We have similar requirements contracts with each of ConocoPhillips, 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. The price for gas during this period under the ConocoPhillips and AML&P contracts is approximately 88% of the price of gas under the Marathon contract (described below) ($4.5897 per thousand cubic feet (MCF) on January 1, 2008), 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) ($5.0487 per MCF on January 1, 2008), 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-2010. The base price for gas under the Marathon contract is $1.35 per MCF, adjusted quarterly to reflect the percentage change between the preceding twelve-month period and a base period in the average closing prices of New York Mercantile Exchange (NYMEX) Light, Sweet Crude Oil Futures, the Producer Price Index for natural gas, and the Consumer Price Index for heating fuel oil. The price on January 1, 2008, exclusive of taxes, was $4.5897 per MCF.
Under the terms of the Marathon contract, Marathon generally provides all of the gas required for sales to GVEA, all of our requirements at Bernice Lake, International and Nikiski and 40% of the requirements at Beluga, not related to sales to GVEA. Marathon also has a right of first refusal to provide additional gas under any sales agreements that we may enter into with electric utilities we do not currently serve. The terms of the Marathon contract also gave Marathon a right
to provide additional volumes in the period following depletion of the initial commitment of 215 BCF. On June 13, 2001, we were notified that Marathon would not commit to supply any additional volumes under the existing contract.
Chugach is involved in active negotiations to secure additional natural gas supplies after the existing contracts run out beginning in mid 2010. The Cook Inlet continues to be a supply basin with adequate reserves for both domestic and foreign utilities. Chugach anticipates presenting contracts before the RCA by the first quarter of 2009.
ENSTAR
ENSTAR Natural Gas Company (ENSTAR) has a tariff to transport our gas purchased from the Beluga River Field producers or Marathon on a firm basis to our IGT Power Plant at a transportation rate of $0.63 per MCF. The agreement contains a fixed monthly charge of $2,840 for firm service.
Environmental Matters
General
Chugach’s operations are subject to certain federal, state and local environmental laws and regulations, which seek to limit air, water and other pollution and regulate hazardous or toxic waste disposal. While we monitor these laws and regulations to ensure compliance, they frequently change and often become more restrictive. When this occurs, the costs of our compliance generally increase.
We include costs associated with environmental compliance in both our operating and capital budgets. We accrue for costs associated with environmental remediation obligations when those costs are probable and reasonably estimable. We do not anticipate that environmental related expenditures will have a material effect on our results of operations or financial condition. We cannot, however, predict the nature, extent or cost of new laws or regulations relating to environmental matters.
The Clean Air Act and Environmental Protection Agency (EPA) regulations under the act (the “Clean Air Act”) establish ambient air quality standards and limit the emission of many air pollutants. Some Clean Air Act programs that regulate electric utilities, notably the Title IV “acid rain” requirements, do not apply to facilities located in Alaska. The EPA’s anticipated regulations to limit mercury emissions from fossil-fired steam-electric generating facilities are not expected to materially impact Chugach because our thermal power plants burn exclusively natural gas.
New Clean Air Act regulations impacting electric utilities may result from future events or may result from new regulatory programs that may be established to address problems such as global warming. While we cannot predict whether any new regulation would occur or its limitation, it is possible that new laws or regulations could increase our capital and operating costs. We have obtained or applied for all Clean Air Act permits currently required for the operation of our generating facilities.
In March 2007 Chugach conducted emissions testing at the Bernice Lake Power Plant which indicated that two of the gas turbines at the facility were exceeding the New Source Performance Standards (NSPS) emission limit for nitrogen oxides (NOx). Chugach voluntarily limited the power output of these turbines to ensure interim compliance with the NSPS regulations and is currently in the final stages of commissioning a water injection system to control NOx emissions from the turbines. With the water injection system, Chugach will again be able to fully utilize the power output from these turbines while complying with the NSPS regulations.
Chugach is also currently working with the Alaska Department of Environmental Conservation (ADEC) to resolve the issue of past non-compliance with the Bernice Lake turbines. On March 26, 2008, the ADEC issued a formal Notice of Violation (NOV) to Chugach regarding the NSPS issues. Specifically, the NOV alleges that Chugach violated its operating permit and air quality regulations by operating two generating units at the Bernice Lake Power Plant in excess of the NOx emission limit; failing to perform a source test to demonstrate compliance with regulations; and failing to conduct reasonable inquiry regarding source test compliance for the 2006 annual compliance certification. ADEC requested a meeting with Chugach to discuss settlement of the identified alleged violations. It is not possible at this time to reasonably anticipate the amount of any potential penalty that may result from this NOV.
Chugach is subject to numerous other environmental statutes including the Clean Water Act, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Endangered Species Act, and the Comprehensive Environmental Response, Compensation and Liability Act and to the regulations implementing these statutes. We do not believe that compliance with these statutes and regulations to date has had a material impact on our financial condition or results of operation. However, new laws or regulations, implementation of final regulations or changes in or new interpretations of these laws or regulations could result in significant additional capital or operating expenses.
Item 3
Item 3 - Legal Proceedings
Matanuska Electric Association, Inc. (MEA) v. State of Alaska, Regulatory Commission of Alaska, Superior Court Case No. 3AN-06-8243 Civil
On May 17, 2006, MEA appealed and on May 30, 2006, Homer Electric Association, Inc., (HEA) cross appealed the RCA’s decision in Commission Docket No. U-04-102. (See “Part II - Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Rate Regulation and Rates - Revision to Current Depreciation Rates (Docket No. U-04-102).”) On appeal, MEA claims the Commission’s decision dated January 10, 2006 to authorize Chugach to implement new depreciation rates as of January 1, 2005 constituted illegal retroactive ratemaking. MEA further contends that the Commission’s reliance on avoidance of regulatory lag as a basis for its decision was improper. MEA also challenged certain of the Commission’s discovery rulings. Chugach has joined the State of Alaska in defending the Commission’s rulings. HEA stipulated with the other parties to dismiss its cross appeal which the Court granted by order dated September 11, 2007. Briefing is complete and oral argument before the Superior Court is scheduled for April 29, 2008. Thereafter, an appeal to the Alaska Supreme Court is possible.
The ultimate resolution of this matter is not currently determinable. In the opinion of management, an adverse outcome is not likely to have a material adverse effect on Chugach’s results of operations, financial condition or liquidity. No reserves have been established for this matter.
Chugach has certain additional litigation matters and pending claims that arise in the ordinary course of Chugach’s business. In the opinion of management, no individual matter or the matters in the aggregate is likely to have a material adverse effect on Chugach’s results of operations, financial condition or liquidity.
Item 4
Item 4 - Submission of Matters to a Vote of Security Holders
Chugach’s annual membership meeting was held on April 26, 2007, and two new board members were elected. Out of 28,797 votes, P.J. Hill received 9,535 votes and Alex Gimarc received 8,800 votes and were elected to three-year terms.
The members approved the following amendments to the Bylaws:
o
The deadlines for appointing members to member committees were standardized.
o
Clarified that the Board of Directors (Board) is able to engage the service of consultants to advise it on various Association matters.
PART II
Item 5
Item 5 - Market for Registrant’s
Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
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 reserves. These amounts are referred to as “margins.” Patronage capital, the retained margins of our members, constitutes our principal equity.
Times Interest Earned Ratio (TIER). Alaska electric cooperatives generally set their rates on the basis of TIER. TIER is determined by dividing the sum of assignable margins plus long-term interest expense (excluding capitalized interest) by long-term interest expense (excluding capitalized interest). Chugach’s authorized TIER for rate-making purposes on a system basis is 1.30, which was ordered by the RCA on January 31, 2003, in Order U-01-108(26). In addition Chugach’s achieved TIER reflects non-operating margins that are not generated by electric rates. We manage our business with a view toward achieving a TIER of 1.25 or greater. For further discussion on factors that contribute to TIER results, see “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Years ended December 31, 2007, compared to the years ended December 31, 2006, and December 31, 2005 - Expenses.” We achieved TIERs for the past five years as follows:
Rate Regulation and Rates. Our rates are made up of two components: “base rates” and “fuel surcharge rates.” “Base rates” are composed of fixed and variable charges in connection with all components of providing electricity. “Fuel surcharge” rates take into account the rise and fall of fuel and purchased power costs and ensure collection of fuel and purchased power costs above the base component included in the base energy rate. The RCA approves the amounts paid by our
wholesale and retail customers under base rates and approves the quarterly fuel surcharge filing authorizing rate changes in the fuel surcharge calculations. In addition, a RCC is assessed on each retail customer invoice to fund Chugach’s share of the RCA’s budget. The RCC tax is revised annually by the RCA.
Base Rates. We recover operating and maintenance and other non-fuel and purchased power costs through our base rates established through an order of the RCA following a general rate case, where we propose a rate increase or decrease for each class of customer based on our costs to service those classes during a recent year referred to as a test year. The RCA may authorize, after a notice period, rate changes on an interim and refundable basis.
There were no base rate changes for our retail customers or for our wholesale customers, MEA and HEA, in 2007, 2006 and 2005. Base rates for Seward were modified in accordance with a new power sales agreement on an interim and refundable basis effective June 1, 2006. The RCA approved the rates and issued a final order December 20, 2006. (See “Part I - Item 1 - Business - Wholesale Customers - Seward.”)
Revision to Current Depreciation Rates (Docket No. U-04-102)
In 2004, Chugach implemented new depreciation rates based on an update of the 1999 Depreciation Study utilizing Electric Plant in Service balances as of December 31, 2002. The 2002 Depreciation Study resulted in an increase to 2004 depreciation expense, which was not material to the financial statements. The 2002 Depreciation Study was submitted to the RCA for approval on November 19, 2004, resulting in the RCA opening a docket to review the proposed new rates. Chugach, however, implemented the new rates effective January 1, 2004. Chugach did not request a change in electric rates charged to customers based on the proposed revisions to depreciation rates.
On March 9, 2005, the RCA ruled in Order No. 2 that depreciation rates may not be implemented without prior approval of the RCA.
On September 21, 2005, the RCA issued Order No. 8 requiring Chugach to adjust its underlying 2004 financial records to reflect the results as if Chugach had not implemented unapproved rates. In November of 2005, Chugach reversed the 2004 depreciation expense and depreciation reserves that were previously recorded using the 2002 Depreciation Study rates and calculated 2004 depreciation expense for all categories of plant using the 1999 Depreciation Study rates as approved by the RCA in Docket U-01-108. The adjustment was not material to Chugach’s financial statements.
In Order No. 9 dated January 10, 2006, the RCA ruled substantially in Chugach’s favor approving the 2002 Depreciation Study with certain changes to the proposed depreciation rates. The main effect of this decision is to allow Chugach to revise its depreciation rates effective as of January 1, 2005.
Because Chugach did not request changes to the electric rates charged to our customers based on the proposed new depreciation rates, there was no immediate electric rate impact.
Wholesale customers MEA and HEA were active in the proceeding. Subsequently, MEA and HEA filed an appeal of the RCA’s decision in Superior Court. (See “Part I - Item 3 - Legal Proceedings - Matanuska Electric Association, Inc. v. State of Alaska, Regulatory Commission of Alaska, Superior Court Case No. 3AN-06-8243 Civil.”)
HEA later dismissed its appeal leaving MEA’s claim focusing mainly on the question of whether implementation of the new depreciation rates as of January 1, 2005 constituted illegal retroactive ratemaking. Briefing is complete and oral argument before the Superior Court is anticipated in the spring of 2008. Thereafter an appeal to the Alaska Supreme Court is possible.
Test Year General Rate Case (Docket No. U-06-134)
On September 27, 2006, the Chugach Board of Directors authorized and instructed management to file a general rate case with the RCA. On September 29, 2006, Chugach filed a general rate case based on a 2005 test year and requested a revenue increase of $10.6 million for the Generation and Transmission (G&T) function and a revenue decrease of $7.8 million for the Distribution function. Overall revenues were proposed to increase $2.8 million in the initial filing.
The RCA permitted intervention from Chugach’s wholesale customers and the Regulatory Affairs and Public Advocacy (RAPA) section within the Attorney General’s office of the State of Alaska. It also permitted intervention of a single Chugach retail member. A scheduling order was issued on January 23, 2007, establishing a hearing schedule to adjudicate the case. Discovery from the intervenors in the case on Chugach’s filing and pre-filed initial testimony has been completed. Intervenor testimony has been submitted. Chugach’s reply testimony was submitted May 29, 2007.
A settlement agreement between several of the intervenors and Chugach, reached in July 2007, has been accepted by the RCA. The settlement agreement results in an estimated 3% overall decrease for Chugach retail members and an estimated 3.5% overall increase for HEA and Seward.
The hearing scheduled to occur in August 2007 with the remaining intervenors was canceled. The remaining active intervener, MEA, and Chugach entered into a stipulation to resolve outstanding procedural issues on October 16, 2007. This stipulation agrees to a procedure whereby the RCA will decide the matter based on the written record with provisions for RCA written questions and optional oral questioning by the RCA of selected witnesses. Chugach and MEA filed closing briefs on December 5, 2007. The RCA did not engage in oral questioning of witnesses.
Chugach submitted to the RCA permanent rates to implement the settlement agreement as well as interim and refundable rates for MEA, the party that did not settle, for implementation in the fourth quarter of 2007. The RCA declined to implement any tariff changes at that time and as a result, the implementation date of the rate changes for all parties has been delayed, pending a ruling on the rate changes associated with MEA.
Rates resulting from the settlement agreement approved by the RCA for Chugach retail members, HEA and SES will result in an annual revenue reduction of $2.7 million.
On April 1, 2008, the RCA issued Order No. 21 in Docket U-06-134. In this order, the RCA approved the rates from the Settlement Agreement among Chugach, HEA and SES that it had previously accepted. MEA did not join the Settlement Agreement and this Order addressed the issues that it had raised. Order No. 21 reached findings similar to the Settlement Agreement and the rates for MEA are slightly higher than rates agreed to in the Settlement Agreement. The cumulative effect of Order 15, Settlement Agreement revenues, and Order 21 is overall revenues decreasing by 0.8%, with retail revenue decreasing by 4.8% and wholesale revenue increasing by 11.0%. Order No. 21 is effective June 1, 2008. Chugach expects to be filing a request for reconsideration and a proposed correction to an RCA calculation. It is unknown whether MEA will be making additional filings.
Fuel Surcharge. We pass fuel and purchased power costs above base amounts included in the base rate directly to our wholesale and retail customers through the fuel surcharge mechanism. Changes in fuel and purchase power costs are primarily due to fuel price adjustment mechanisms in our gas-supply contracts based on natural gas, crude oil and fuel oil indexed price changes. We pass these costs directly to our retail and wholesale customers. The fuel surcharge is approved on a quarterly basis by the RCA. There are no limitations on the number or amount of fuel surcharge rate changes. Increases in our fuel and purchased power costs result in increased revenues while decreases in these costs result in lower revenues. Therefore, revenue from the fuel surcharge normally does not impact margins.
Years ended December 31, 2007, compared to the years ended December 31, 2006, and December 31, 2005
Margins
Our margins for the years ended December 31 were as follows:
The decrease in assignable margins in 2007 from 2006 of $7.2 million, or 71.3%, was due to a decrease in retail kWh sales and an increase in power production, transmission, distribution and administrative, general and other expense. The increase in assignable margins in 2006 from 2005 of $524.3 thousand, or 5.5%, was due primarily to increased retail and wholesale kWh sales offset in part by administrative, general and other and interest expense.
Non-operating margins include interest income, allowance for funds used in construction, capital credits and patronage capital allocations. Non-operating margins did not materially change in 2007 from 2006. Non-operating margins increased $249.1 thousand, or 20.3% in 2006 from 2005 due primarily to an increase in interest income caused by a higher than average cash balance during the year and higher interest rates.
Revenues
Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2007, operating revenues were $10.1 million, or 3.8%, lower than in 2006 primarily due to a decrease in economy energy sales and a decrease in retail kWh sales. The decrease was also due to lower fuel costs recovered in revenue through the fuel surcharge mechanism due primarily to a reduction and subsequent refund of Cook Inlet power production taxes. These decreases were partially offset by an increase in wholesale kWh sales and demand.
Retail revenue decreased in 2007 from 2006 primarily due to lower fuel costs recovered in revenue through the fuel surcharge mechanism due to a reduction and subsequent refund of Cook Inlet power production taxes, as well as lower sales to Chugach’s large commercial customer classes. Several large commercial classes experienced growth, however, one large commercial customer replaced their electric compressors with gas-fired compressors, significantly reducing sales.
Wholesale revenue was higher in 2007 from 2006 due to increased sales and demand. The increase in sales to MEA and HEA was due to increased economic activity while the increase in sales in 2007 to Seward was caused by a decrease in sales due to an avalanche in 2006 that interrupted service on their single transmission line connecting Seward to the grid. These increases were offset by lower fuel costs recovered in revenue through the fuel surcharge mechanism due primarily to a reduction and subsequent refund of Cook Inlet power production taxes. Economy energy revenue also decreased in 2007 from 2006 due to a decrease in economy energy sales due to our limited ability to generate additional output and contracted fuel limitations.
In 2006, operating revenues were $41.8 million, or 18.5% higher than in 2005 due to increased retail and wholesale kWh sales as well as higher fuel costs recovered in revenue through the fuel surcharge mechanism. Retail sales did not significantly change from 2005, however, total retail revenues increased due to higher fuel costs recovered in revenue through the fuel surcharge mechanism. With regard to wholesale revenues, actual sales to MEA increased due to increased economic activity while sales to Seward decreased due to an avalanche, which cut the 69 kV line, that required Seward to rely on its own generation in the first quarter of 2006. HEA revenue
increased due to increased fuel costs recovered in revenue through the fuel surcharge mechanism. Economy energy kWh sales decreased in 2006 from 2005 primarily due to GVEA purchasing less from Chugach due to periodic unavailability of our units, although economy revenue increased due to increased fuel costs recovered in revenue through the fuel surcharge mechanism.
Based on the results of fixed and variable cost recovery established in Chugach’s last rate case, wholesale sales to MEA, HEA and SES contributed approximately $26 million, $25 million and $24 million to Chugach’s fixed costs for the years ended December 31, 2007, 2006 and 2005, respectively. The following table shows the base rate sales revenue and fuel and purchased power revenue by customer class that is included in revenue for the years ended December 31, 2007, and 2006.
The following table shows the base rate sales revenue and fuel and purchased power revenue by customer class that is included in revenue for the years ended December 31, 2006, and 2005.
The major components of our operating revenue for the year ending December 31 were as follows:
We make economy sales to GVEA. These sales commenced in 1989 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 generation at the time. In 2007, 2006, and 2005, economy sales to GVEA constituted approximately 2.0%, 6.0%, and 6.0%, respectively, of our sales revenues. 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. Subsequently, sales to GVEA do not significantly affect margins. Economy energy sales decreased in 2007 from 2006 due to transmission line work and maintenance on several Beluga units which limited our ability to generate additional output available for economy energy sales. Chugach was also constrained by contracted fuel limitations from our economy sales fuel supplier. The decrease in economy kWh sales in 2006 from 2005 was due to GVEA purchasing less from Chugach due to periodic unavailability of our units, although economy revenue increased due to increased fuel costs recovered in revenue through the fuel surcharge mechanism.
Expenses
The major components of our operating expenses for the years ended December 31 were as follows:
Fuel
Chugach recognizes actual fuel expense. Fuel expense decreased by $14.3 million, or 11.9%, in 2007 from 2006 due primarily to a reduction and subsequent refund of $3.4 million of Cook Inlet power production taxes, which resulted in a lower average fuel price than in 2006. In 2007, Chugach used 27,633,963 MCF of fuel at an average effective price of $4.49 per MCF.
Fuel expense increased by $35.5 million, or 41.9%, in 2006 from 2005 due to higher fuel prices as well as higher volume purchases. In 2006, Chugach used 27,006,822 MCF of fuel at an average effective price of $4.74 per MCF. In 2005, Chugach used 26,728,140 MCF of fuel at an average effective price of $3.50 per MCF.
Power Production
Power production expense increased $1.1 million, or 7.5%, in 2007 from 2006 due primarily to information services allocated compliance costs and the amortization associated with the Beluga River Gas Compression project. Power production expense did not materially change in 2006 from 2005.
Purchased Power
Purchased power costs increased $8.0 million, or 30.7%, in 2007 from 2006 due primarily to higher MWh purchased and at a higher average effective price. In 2007, Chugach purchased 523,910 MWh of energy at an average effective price of 6.15 cents per kWh. Higher MWh purchased in 2007 was caused by Dynamite Slough transmission line work and maintenance on several Beluga units which limited our output from Beluga. We also purchased less from Bradley Lake in 2007 due to low water levels and inflows but paid more in Bradley Lake expenses which contributed to the higher average effective price.
Purchased power costs increased by $2.3 million, or 9.8%, in 2006 from 2005 due to higher fuel costs. In 2006, Chugach purchased 475,909 MWh of energy at an average effective price of 5.19 cents per kWh. In 2005, Chugach purchased 560,376 MWh of energy at an average effective price of 4.03 cents per kWh.
Transmission
Transmission expense increased $497.3 thousand, or 7.9%, in 2007 from 2006 due primarily to higher information services allocated compliance costs as well as labor contract increases in 2007 over 2006. Transmission expense increased $436.2 thousand, or 7.5%, in 2006 from 2005 due to an increase in transmission substation maintenance performed in 2006.
Distribution
Distribution expense increased $1.6 million, or 13.0%, in 2007 from 2006 due primarily to information services allocated compliance costs, labor contract increases and costs associated with an outage in the first quarter of 2007. Distribution expense increased $353.6 thousand, or 3.0%, in 2006 from 2005 primarily due to an increase in labor associated with substation, overhead line and street light maintenance and a new labor contract.
Consumer Accounts
Consumer accounts expense, which represents costs associated with maintaining customer accounts and membership, did not materially change in 2007 from 2006. Consumer accounts expense decreased by $245.2 thousand, or 4.7%, in 2006 from 2005 primarily due to a decrease in professional services associated with television safety advertising.
Administrative, General and Other Charges
Administrative, general and other charges did not materially change in 2007 from 2006, however, labor increased $422.1 thousand in 2007 over 2006 primarily due to administrative cost-of-living labor increases as well as an accrual for estimated severance costs. Professional services increased $1.7 million in 2007 over 2006 primarily due to costs associated with Sarbanes-Oxley compliance and other Board related studies. These increases were offset by a decrease in other deductions due to the $1.6 million write off of obsolete inventory and cancelled projects in 2006.
Administrative, general and other charges increased $1.5 million, or 7.2%, in 2006 from 2005 due primarily to a $1.6 million write-off of obsolete inventory and cancelled projects as well as a $950.9 thousand increase in injuries and damages primarily due to an accrual for an insurance claim. The increases were offset by a $1.0 million decrease in labor as a result of retirements and unfilled positions in 2006 compared to 2005.
Depreciation
Depreciation expense did not materially change in 2007 from 2006, nor did it materially change in 2006 from 2005. We use remaining life rates set forth in the most recent depreciation study, currently the 2002 depreciation study, which has been in effective since January 1, 2005. An update to depreciation rates was included in a general rate case filed by Chugach with the RCA on September 29, 2006, see Note (2) - “Regulatory Matters - 2005 Test Year General Rate Case (Docket No. U-06-134).”
Interest
Interest on long-term obligations did not materially change in 2007 from 2006. Interest on long-term obligations increased by $1.1 million, or 4.6%, in 2006 from 2005 due to higher variable interest rates.
Interest on short-term borrowing increased $90.6 thousand, or 100%, in 2007 from 2006 due to interest paid on an electric account. Interest on short-term borrowing decreased $46.6 thousand, or 100%, in 2006 from 2005 due to the line of credit not being utilized during 2006.
Interest charged to construction increased $168.2 thousand, or 37.5%, in 2007 from 2006 due to a higher average balance in Construction Work In Progress (CWIP), primarily due to more capital spending in 2007 over 2006. Interest charged to construction decreased $395.9 thousand, or 46.9%, in 2006 from 2005 due to a lower balance in CWIP, as well as the early completion of the Beluga Unit 6 C inspection.
Patronage Capital (Equity)
The following table summarizes our patronage capital and total equity position for the years ended December 31:
1 Other equity includes memberships, donated capital and gain on capital credit retirements.
We credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves. These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of distributions of these amounts to members, also known as capital credits, is at the discretion of our Board. We currently have a practice of retiring patronage capital on a first-in, first-out basis for retail customers. The Board may also return capital credits to former members and estates who have requested early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002. Chugach retired $5,289,538, $5,106,817, and $4,079,622 in capital credits for the years ended December 31, 2007, 2006, and 2005, respectively. Prior to 2000, wholesale capital credits had been retired on a 10-year cycle pursuant to an approved capital credit retirement program, which was contained in the Chugach business plan. However, in 2000 we implemented a plan to return the capital credits of wholesale and retail customers on a 15-year rotation. For the years 1997, 1998 and 1999, wholesale capital credits are to be retired on a 10-year cycle pursuant to a prior settlement agreement. In 2007, $79,079 of 1997 wholesale capital credits were retired to MEA, HEA and SES.
The Amended and Restated Indenture prohibits us from making any distributions, payment or retirement of patronage capital to our customers if an event of default under the Amended and Restated Indenture exists. Otherwise, we may make distributions to our members in each year equal to the lesser of 5% of our patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, our aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of our total liabilities and equities and margins.
Under our Master Loan Agreement with CoBank, Chugach is prohibited from making any distribution of patronage capital to Chugach’s customers if an event of default under the Master Loan Agreement exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins.
The table below sets forth a five-year summary of anticipated capital credit retirements:
Changes in Financial Condition
Assets
Total assets decreased $6.0 million, or 1.1%, from December 31, 2006, to December 31, 2007. The decrease was due in part to a $4.0 million, or 0.9%, decrease in net utility plant due to depreciation expense in excess of extension and replacement of plant, as well as a $3.6 million, or 36.9%, decrease in cash and cash equivalents. The decrease was also due to a $1.5 million, or 4.7% decrease in accounts receivable caused by lower fuel costs and a decrease in sales. These decreases were offset by a $3.0 million, or 11.8%, increase in materials and supplies due to the purchase of inventory items primarily associated with generation and distribution in preparation for scheduled maintenance and capital projects in 2008.
Liabilities
Total liabilities decreased by $4.6 million, or 1.1%, in 2007 as compared to 2006. Major contributors to this change include a $9.0 million, or 2.5% decrease in long-term obligations and current installments of long-term obligations due to the principal payments made on CoBank 2, 3, 4 and 5 and the 2002 Series B bonds. Accounts payable also decreased $2.4 million, or 23.0% due to the timing of cash payments on invoices for good and services. Other notable changes to total liabilities in 2007 as compared to 2006 include a $0.4 million, or 10.5% decrease in other current liabilities primarily due to an increase in state and municipal undergrounding activities, which reduced our ordinance liability, offset by an increase in patronage capital payable. These decreases were offset by a $6.2 million, or 38.2% increase in fuel payable due to the timing of fuel payment at December 31, 2007. The decreases were also offset by a $1.3 million, or 431.0% increase in fuel cost over-recovery due to the over collection of fuel and purchased power costs through the fuel and purchased power surcharge mechanism.
Equities and Margins
Total margins and equities decreased $1.4 million, or 0.9%, in 2007 as compared to 2006 due to a $2.4 million, 1.7%, net decrease in patronage capital ($2.9 million increase in margins coupled with a $5.3 million retirement of capital credits). This decrease was offset by a $1.0 million, or 11.5%, increase in other margins and equities primarily attributed to the increase of unclaimed capital credits from the 2007 retirement of patronage capital.
Inflation
We do not believe that inflation had a significant effect on our operations in 2007.
Contractual Obligations and Commercial Commitments
The following are Chugach’s contractual and commercial commitments as of December 31, 2007:
Contractual cash obligations:
(In thousands)
Payments Due By Period
1 Long-term interest expense includes fixed and estimated variable rates. The variable rates are forecasted using actual December 31, 2007 rates for CoBank 3, 4 and 5 and the 2002 Series B bonds. (See “Part II - Item 8 - Financial Statements and Supplemental Data - Note (8) Debt.”)
2 At December 31, 2007, Chugach had $58 million in lines of credit available with various financial institutions, which fund capital requirements. At December 31, 2007, there was no outstanding balance on the lines of credit, therefore, the available borrowing capacity under these lines of credit was $58 million and could be used for future operational and capital funding requirements.
3 Estimated annual cost
4 Anticipated capital credit retirements for the next five years. All capital credit retirements require Board approval.
5 Estimated fuel and fuel transportation expense. We estimate that our fuel contracts will last approximately three years, however, we are currently negotiating new fuel contracts.
Purchase obligations
Chugach is a participant and has a 30.4% share in the Bradley Lake hydroelectric project (See “Item 2 - Properties-Other Property-Bradley Lake.”) This contract runs through 2041. We have agreed to pay a like percentage of annual costs of the project, which has averaged $4 million over the past five years. We believe these costs, adjusted for inflation, reasonably reflect anticipated future project costs.
Our primary sources of natural gas are the Beluga River Field producers and Marathon Oil Company (See “Item 2 - Properties-Fuel Supply-Beluga River Field Producers/Marathon.”) We have contracts with each of these producers with varying expiration dates that generally require us to purchase from them all of our fuel requirements for our Beluga plant. The current phase of these contracts expires in mid-2010 based on current gas volume takes. Our fuel costs vary due to the impact of the energy future indices used to index the price of fuel and are inherently difficult to predict. We pass fuel costs directly to our wholesale and retail customers through the fuel surcharge mechanism (See “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Fuel Surcharge.”)
Liquidity And Capital Resources
Chugach had maintained a $20,000,000 line of credit with CoBank, ACB (CoBank) prior to 2005. On October 25, 2005, Chugach reduced the line of credit to $7.5 million due to a decrease in short-term borrowing projections. On October 17, 2007, the Board approved a resolution to renew this line of credit. The CoBank line of credit expires October 31, 2008, subject to annual renewal at the discretion of the parties. Management intends to extend the CoBank line of credit in 2008. In March of 2007, Chugach borrowed $3.5 million and repaid the balance in April. In September of 2007, Chugach borrowed $1.0 million and repaid the balance in the same month. Chugach did not utilize this line of credit in 2006. At December 31, 2007 and 2006, there was no outstanding balance on this line of credit. The borrowing rate is calculated using the CoBank BaseRate on the first business day of the week plus 3%. The average borrowing rate for 2007 and 2006 was 6.47% and 6.51%, respectively. In 2008, Chugach utilized this line of credit and currently has $4.5 million outstanding.
In addition, Chugach had an annual line of credit of $50,000,000 available at December 31, 2007 and 2006, with NRUCFC. Chugach did not utilize this line of credit in 2007 or 2006. At December 31, 2007 and 2006, there was no outstanding balance on this line of credit. The borrowing rate is calculated using the total rate per annum as may be fixed by CFC and will not exceed the Prevailing Prime Rate, plus one percent per annum. At December 31, 2007 and 2006, the borrowing rate would have been 6.40% and 7.15%, respectively. The NRUCFC line of credit expires October 17, 2012. On March 20, 2008, Chugach borrowed $29.7 million on this line of credit to redeem the outstanding principal amount and pay accrued interest on the 2002 Series B Bonds.
Principal maturities and sinking fund payments of our outstanding indebtedness at December 31, 2007 are set forth below:
During 2007 we spent approximately $27.3 million on capital-construction projects, net of reimbursements, which includes interest capitalized during construction. We develop five-year capital improvement plans that are updated every year. Our capital improvement requirements are based on long-range plans and other supporting studies and are executed through the five-year capital improvement program. Set forth below is an estimate of capital expenditures for the years 2008 through 2012 as contained in the Capital Improvement Plan (CIP), which was approved on December 19, 2007:
We expect that cash flows from operations and external funding sources will be sufficient to cover future operational and capital funding requirements.
Outlook
Chugach faces several challenges in 2008 as we move towards procuring new, more efficient power generation facilities. The choices facing Chugach is whether to build and own the new generation, partner with another entity to build and operate the new facility or purchase power from another entity. Chugach continues to explore joint development options with other entities and the development of a unified power provider organization to provide future needs. In any event, this new generation is needed to fulfill current as well as future needs. Our current generating fleet is aging and less fuel- efficient than newer technology. Savings will be realized in decreased maintenance of plant and increased fuel efficiency.
Procuring a new long-term natural gas supply continues to be at the forefront of Chugach’s efforts in 2008. Negotiations continue with potential suppliers into 2008. A close eye will be kept on the potential for a North Slope natural gas line being constructed to potentially meet the needs of all south central Alaska consumers.
An order on the 2005 Test Year general rate case was issued April 1, 2008. The decision will mean more equitable electric rates being charged to generation and transmission (G&T) customers and distribution (D) customers. It will also mean a more balanced return being realized by both areas of Chugach.
In May of 2007 the Board appointed a Blue Ribbon Panel to review basic high-level performance measures and finances, review member and community communications and make recommendations that it deems appropriate. The Blue Ribbon Panel issued their report in November of 2007. Continued evaluation and implementation of the Blue Ribbon Panel recommendations will be a major focus in 2008 as Chugach continues to provide cost efficient electric service to all of its consumers.
In recognizing the value to Chugach, and to the electric consumers of the Railbelt as a whole, Chugach is willing to explore with other Railbelt utilities the creation of a public corporation, organized for the purpose of providing for the unified generation and transmission needs in the Alaska Railbelt. On February 18, 2008, the Board approved authorizing the Interim CEO to execute a Memorandum of Understanding with other Railbelt utilities regarding organization of a Unified Power Provider.
Chugach’s existing generation is aging and new generation is more efficient using substantially less fuel. Jointly building a new generation unit offers economies of scale that cannot be gained through individual utility efforts. Chugach is in the process of developing a gas-fired generation plant in the South Anchorage area and has offered AEEC and ML&P the opportunity to participate in the project in order to partially satisfy their power requirements. On February 18, 2008, the Board approved authorizing the Interim CEO to execute a Memorandum of Understanding with AEEC and AML&P regarding joint development of the South Anchorage Power Project.
Ratings
Our bond ratings with Moody’s Investors Service, Fitch Investor Service and Standard & Poors Ratings Services remained unchanged in 2007 at A2 Stable, A- Stable and A- Stable, respectively.
Off-Balance Sheet Arrangements
We have not created, and are not party to, any special-purpose or off-balance-sheet entities for the purpose of raising capital, incurring debt or operating parts of our business that are not consolidated into our financial statements. We do not have any arrangements or relationships with entities that are not consolidated into our financial statements that are reasonably likely to materially affect our liquidity or the availability of our capital resources.
Critical Accounting Policies
Our accounting and reporting policies comply with U.S. generally accepted accounting principles (GAAP). The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and reported amounts of assets and liabilities in the financial statements. Significant accounting policies are described in Note 1 to the financial statements (See “Item 8 -Financial Statements and Supplementary Data.”). Critical accounting policies are those policies that management believes are the most important to the portrayal of Chugach’s financial condition and results of its operations, and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about matters that are inherently uncertain. Most accounting policies are not considered by management to be critical accounting policies. Several factors are considered in determining whether or not a policy is critical in the preparation of financial statements. These factors include, among other things, whether the estimates are significant to the financial statements, the nature of the estimates, the ability to readily validate the estimates with other information including third parties or available prices, and sensitivity of the estimates to changes in economic conditions and whether alternative accounting methods may be utilized under GAAP. For all of these policies management cautions that future events rarely develop exactly as forecast, and the best estimates routinely require adjustment. Management has discussed the development and the selection of critical accounting policies with Chugach’s Audit Committee. The following policies are considered to be critical accounting policies for the year ended December 31, 2007.
Electric Utility Regulation
Chugach is subject to regulation by the RCA. The RCA sets the rates Chugach is permitted to charge customers based on allowable costs. As a result, Chugach applies Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71). Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on Chugach’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement benefits have less of a direct impact on Chugach’s results of operations than they would on a non-regulated company. As reflected in the financial statements (See “Item 8 -Financial Statements and Supplementary Data - Note 1k - Deferred Charges and Credits”), significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislation and judicial or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact Chugach’s financial statements.
Unbilled revenue
Chugach calculates unbilled retail revenue at the end of each month to ensure the recognition of a full year’s revenue. Chugach estimates calendar-month unbilled sales based on billing cycle sales adjusted to a calendar month using weather, hours of darkness and the number of calendar and unbilled days. The unbilled estimate is calibrated to deliveries measured at Chugach distribution substations net of losses. The resulting unbilled estimate is multiplied by the respective billing class determinates to arrive at the monthly unbilled accrual. Chugach accrued $8,300,461 and $9,346,702 of unbilled retail revenue at December 31, 2007 and 2006, respectively.
Allowance for Doubtful Accounts
We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We base our estimates on the aging of our accounts receivable balances, historical bad debt reserves, historical percent of retail revenue that has been deemed uncollectible, changes in our collections process and regulatory requirements. If the financial condition of our customers were to deteriorate resulting in an impairment of their ability to make payments, additional allowances may be required. If their financial condition improves, allowances may be reduced. Such allowance changes could have a material effect on our consolidated financial condition and results of operations.
New Accounting Standards
SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115”
In February 2007, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115.” SFAS No. 159 allows for certain financial assets and liabilities to be measured at fair value on an instrument-by-instrument basis subject to certain restrictions. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Chugach will begin application of SFAS No. 159 on January 1, 2008, and it will not have a material affect on our results of operations, financial position, and cash flows.
SFAS 157 “Fair Value Measurements”
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 provides guidance for using fair value to measure assets and liabilities. In addition, this statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This statement applies when other accounting pronouncements require fair value measurement; it does not require new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. This statement delays the effective date for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. Chugach will begin application of SFAS No. 157 on January 1, 2008, and it will not have a material affect on our results of operations, financial position, and cash flows.
SFAS 141R “Business Combinations”
In December 2007, the FASB issued SFAS No. 141R, “Business Combinations.” SFAS No. 141R replaces FASB Statement No. 141, “Business Combinations.” This statement retains the requirements in Statement 141 that the acquisition method of accounting be used and for an acquirer to be identified for each business combination. This statement defines the acquirer and establishes the acquisition date. This statement applies only to business combinations in which control was obtained by transferring consideration. By applying the same method, this statement improves the comparability of the information about business combinations provided in financial reports. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. Chugach will begin application of SFAS No. 141R on January 1, 2009, and it does not expect to have a material affect on our results of operations, financial position, and cash flows.
Item 7A
Item 7A - Quantitative and Qualitative Disclosures About Market Risk
Chugach is exposed to a variety of risks, including changes in interest rates and changes in commodity prices due to repricing mechanisms inherent in gas supply contracts. In the normal course of our business, we manage our exposure to these risks as described below. We do not engage in trading market risk-sensitive instruments for speculative purposes.
Interest Rate Risk
The following table provides information regarding cash flows for principal payments on total debt by maturity date (dollars in thousands) as of December 31, 2007:
1 Includes current portion
Chugach is exposed to market risk from changes in interest rates on its variable rate long term debt (Series B, 2002 and CoBank notes). A 100 basis-point change (up or down) would increase or decrease our interest expense by approximately $800,303, based on $80,030,304 of variable debt outstanding at December 31, 2007.
Series B Bonds
Chugach had $35.5 million of 2002 Series B Bonds outstanding at December 31, 2007, and in February of 2008 made a $5.9 million principal payment. The interest rate on the 2002 Series B Bonds is subject to a reset mechanism every 28 days through an auction process. Recent events affecting bond insurers, including Chugach’s bond insurer, MBIA, have injected some level of uncertainty regarding the success of the auction process. By the terms of the auction securities agreement, should an attempt to reset the interest rate on Chugach’s auction rate bonds fail because there are insufficient bids to establish a market-based price, the interest rate on Chugach’s 2002 Series B Bonds would be set utilizing an “Auction Mode Multiple” as defined in Exhibit A to Appendix 2 to Eleventh Supplemental Indenture (Auction Procedures Description).
The “Auction Mode Multiple” as of any Auction Date is a percentage of the Index in effect on such auction date (in Chugach’s case, a percentage of the one month London Interbank Offered Rate (LIBOR). That percentage is based on the Prevailing Rating of the 2002 Series B Bonds in effect at the close of business on the Business Day immediately preceding the Auction Date.
In Chugach’s case, the Auction Mode Multiple is based on MBIA’s AAA rating and would be 150% of one-month LIBOR. This rate would stay in effect for 28 days, followed by another auction. On February 20, 2008, the auction was held and failed to obtain sufficient clearing bids. Therefore, the current bondholders continued to hold the bonds and the rate on the 2002 Series B Bonds was set at 4.677% and stayed in effect until March 20, 2008. The failure of the auction does not constitute an event of default under any financing arrangement.
On March 5, 2008, bondholders were notified of the intent of Chugach to redeem the entire outstanding principal amount of the 2002 Series B Bonds. The Board of Directors authorized the redemption using funds obtained from one or more new borrowings under Chugach’s existing lines of credit with CoBank or NRUCFC.
On March 20, 2008 Chugach redeemed the $29.6 million outstanding principal amount of the 2002 Series B Bonds using our NRUCFC line of credit at an initial rate of 3.46%. Repayment of the NRUCFC line of credit is required by March 15, 2009. Accordingly, outstanding borrowings continue to be classified as long-term. Management is currently evaluating long-term financing options.
Commodity Price Risk
Chugach’s gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because purchased power costs are passed directly to our wholesale and retail customers through a fuel surcharge mechanism, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not normally impact margins.
Item 8
Item 8 - Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors
Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association, Inc. as of December 31, 2007 and 2006, and the related statements of operations, changes in equities and margins, and cash flows for each of the years in the three-year period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Chugach Electric Association, Inc. as of December 31, 2007 and 2006, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2007, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG, LLP
April 14, 2008
Anchorage, Alaska
Chugach Electric Association, Inc.
Balance Sheets
December 31, 2007 and 2006
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Balance Sheets (continued)
December 31, 2007 and 2006
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Operations
Years Ended December 31, 2007, 2006 and 2005
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Changes in Equities and Margins
Years Ended December 31, 2007, 2006 and 2005
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Cash Flows
Years Ended December 31, 2007, 2006 and 2005
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(1)
Description of Business and Significant Accounting Policies
a. Description of Business
Chugach Electric Association, Inc. (Chugach) is the largest electric utility in Alaska. Chugach is engaged in the generation, transmission and distribution of electricity to directly serve 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, Inc. (MEA), Homer Electric Association, Inc. (HEA) and the City of Seward (Seward). Chugach’s retail and wholesale members are the consumers of the electricity sold.
Chugach operates on a not-for-profit basis and, accordingly, seeks only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation, and principal and interest on all indebtedness and to provide for reserves. Chugach is subject to the regulatory authority of the Regulatory Commission of Alaska (RCA).
b. Management Estimates
In preparing the financial statements, management of Chugach is required to make estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the balance sheet and revenues and expenses for the reporting period. Estimates include allowance for doubtful accounts, unbilled revenue and the estimated useful life of utility plant. Actual results could differ from those estimates.
c. Regulation
The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS 71).
SFAS No. 71 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates. The regulatory assets or liabilities are then reduced as the cost or credit is reflected in rates.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(1)
Description of Business and Significant Accounting Policies (continued)
d. Utility Plant and Depreciation
Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. For property replaced or retired, the book value of the property, plus removal cost, less salvage, is charged to accumulated provision for depreciation. Renewals and betterments are capitalized, while maintenance and repairs are charged to expense as incurred.
In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144), certain utility plant is reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable in rates. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.
Depreciation and amortization rates have been applied on a straight-line basis and at December 31 are as follows:
Chugach currently uses remaining life rates set forth in the 2002 depreciation study. In an order dated January 10, 2006, the RCA approved the 2002 depreciation study with certain changes to the proposed depreciation rates and allowed Chugach to revise its depreciation rates effective January 1, 2005 to reflect the new depreciation rates. An update to depreciation rates was included in a general rate case filed by Chugach with the RCA on September 29, 2006, see Note (2) - “Regulatory Matters - 2005 Test Year General Rate Case (Docket No. U-06-134).”
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(1)
Description of Business and Significant Accounting Policies (continued)
e. Capitalized Interest
Allowance for funds used during construction (AFUDC) and interest charged to construction - credit (IDC) are the estimated costs during the period of construction of equity and borrowed funds. AFUDC and IDC are non-cash credits, which represent the estimated cost of funds used to finance the construction of utility plant. AFUDC and IDC are applied to applicable projects during construction. AFUDC and IDC include the net cost of borrowed funds and a rate of return on other funds when used and is recovered through rates as utility plant is depreciated. Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 6.3% during 2007, 6.1% during 2006 and 5.0% during 2005.
f. Investments in Associated Organizations
The loan agreements with CoBank and National Rural Utilities Cooperative Finance Corporation (NRUCFC) require as a condition of the extension of credit, that an equity ownership position be established by all borrowers. Chugach’s equity ownership in these organizations is approximately 1%. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment.
g. Fair Value of Financial Instruments
SFAS No. 107, Disclosures About the Fair Value of Financial Instruments (SFAS 107), requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments:
Cash and cash equivalents - the carrying amount approximates fair value because of the short maturity of those instruments.
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 (notes 8 and 9).
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(1)
Description of Business and Significant Accounting Policies (continued)
h. Cash and Cash Equivalents
For purposes of the statement of cash flows, Chugach considers all highly liquid debt instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. Chugach has an Overnight Repurchase Agreement with First National Bank Alaska (FNBA). Each day the balance is invested by FNBA and Chugach receives varying interest rates for our investment pursuant to our Overnight Purchase Agreement. The Overnight Repurchase Agreement account had an average balance in 2007 and 2006 of $8,179,484 and $12,687,391, at an average interest rate of 3.13% and 5.14%, respectively.
i. Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off-balance-sheet credit exposure related to its customers.
j. Materials and Supplies
Materials and supplies are stated at average cost.
k. Deferred Charges and Credits
In accordance with SFAS 71, Chugach’s financial statements reflect regulatory assets and liabilities. Continued accounting under SFAS 71 requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for rate making purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria. However, if events or circumstances should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on the financial position and results of operations. Deferred charges, representing regulatory assets, are amortized to operating expense over the period allowed for rate making purposes.
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.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(1)
Description of Business and Significant Accounting Policies (continued)
l. Patronage Capital
Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on Chugach’s statement of revenues and expenses as assignable margins. These excess amounts (i.e. assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by Chugach until such future time as they are retired and returned without interest at the discretion of the Board of Directors. Retained assignable margins are designated on Chugach’s balance sheet as patronage capital. This patronage capital constitutes the principal equity of Chugach. The Board of Directors may also approve the return of capital to former members and estates who request early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002.
m. Operating Revenues
Revenues are recognized upon delivery of electricity. Operating revenues are based on billing rates authorized by the RCA, which are applied to customers’ usage of electricity. Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results. Chugach calculates unbilled revenue at the end of each month to insure the recognition of a full year’s revenue. Chugach accrued $8,300,461 and $9,346,702 of unbilled retail revenue at December 31, 2007 and 2006, respectively. Wholesale revenue is recorded from metered locations on a calendar month basis, so no accrual is made. Chugach’s tariffs include provisions for the flow through of gas costs according to existing gas supply contracts, as well as purchased power costs.
n. Fuel and Purchased Power Costs
Expenses associated with electric services include fuel used to generate electricity and power purchased from others. Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel surcharge mechanism, which is adjusted quarterly to reflect increases and decreases of such costs. Revenues are adjusted for differences between recoverable fuel costs and amounts actually recovered through rates. Fuel costs were over-recovered by $1,596,010 in 2007 and over-recovered by $300,567 in 2006. Total fuel and purchased power costs in 2007, 2006, and 2005 were $139,971,562, $146,260,428, and $108,440,543, respectively.
o. Environmental Remediation Costs
Chugach accrues for losses and establishes a liability associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. Estimates of future costs for environmental remediation obligations are not discounted to their present value. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(1)
Description of Business and Significant Accounting Policies (continued)
p. Income Taxes
Chugach is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code, except for unrelated business income. For the years ended December 31, 2007, 2006 and 2005, Chugach received no unrelated business income. In addition, as described in “Note (13) - Commitments, Contingencies and Concentrations,” Chugach collects sales tax and is assessed gross receipts and excise taxes which are presented on a net basis in accordance with Emerging Issues Task Force (EITF) No. 06-3 “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement.”
q. Recently Issued Accounting Pronouncements
SFAS 159 “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115”
In February 2007, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities - Including an amendment of FASB Statement No. 115.” SFAS No. 159 allows for certain financial assets and liabilities to be measured at fair value on an instrument-by-instrument basis subject to certain restrictions. SFAS No. 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Chugach will begin application of SFAS No. 159 on January 1, 2008, and it will not have a material affect on our results of operations, financial position, and cash flows.
SFAS 157 “Fair Value Measurements”
In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 provides guidance for using fair value to measure assets and liabilities. In addition, this statement defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. This statement applies when other accounting pronouncements require fair value measurement; it does not require new fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. This statement delays the effective date for non-financial assets and non-financial liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis. Chugach will begin application of SFAS No. 157 on January 1, 2008, and it will not have a material affect on our results of operations, financial position, and cash flows.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(1)
Description of Business and Significant Accounting Policies (continued)
q. Recently Issued Accounting Pronouncements (continued)
SFAS 141R “Business Combinations”
In December 2007, the FASB issued SFAS No. 141R, “Business Combinations.” SFAS No. 141R replaces FASB Statement No. 141, “Business Combinations.” This statement retains the requirements in Statement 141 that the acquisition method of accounting be used and for an acquirer to be identified for each business combination. This statement defines the acquirer and establishes the acquisition date. This statement applies only to business combinations in which control was obtained by transferring consideration. By applying the same method, this statement improves the comparability of the information about business combinations provided in financial reports. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. Chugach will begin application of SFAS No. 141R on January 1, 2009, and it does not expect to have a material affect on our results of operations, financial position, and cash flows.
r. Presentation of Financial Information
Certain reclassifications have been made to the 2005 and 2006 financial statements to conform to the 2007 presentation.
(2)
Regulatory Matters
Revision to Current Depreciation Rates (Docket No. U-04-102)
In 2004, Chugach implemented new depreciation rates based on an update of the 1999 Depreciation Study utilizing Electric Plant in Service balances as of December 31, 2002. The 2002 Depreciation Study resulted in an increase to 2004 depreciation expense, which was not material to the financial statements. The 2002 Depreciation Study was submitted to the RCA for approval on November 19, 2004, resulting in the RCA opening a docket to review the proposed new rates. Chugach, however, implemented the new rates effective January 1, 2004. Chugach did not request a change in electric rates charged to customers based on the proposed revisions to depreciation rates.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(2)
Regulatory Matters (continued)
Revision to Current Depreciation Rates (Docket No. U-04-102) (continued)
On March 9, 2005, the RCA ruled in Order No. 2 that depreciation rates may not be implemented without prior approval of the RCA.
On September 21, 2005, the RCA issued Order No. 8 requiring Chugach to adjust its underlying 2004 financial records to reflect the results as if Chugach had not implemented unapproved rates. In November of 2005, Chugach reversed the 2004 depreciation expense and depreciation reserves that were previously recorded using the 2002 Depreciation Study rates and calculated 2004 depreciation expense for all categories of plant using the 1999 Depreciation Study rates as approved by the RCA in Docket U-01-108. The adjustment was not material to Chugach’s financial statements.
In Order No. 9 dated January 10, 2006, the RCA ruled substantially in Chugach’s favor approving the 2002 Depreciation Study with certain changes to the proposed depreciation rates. The main effect of this decision is to allow Chugach to revise its depreciation rates effective as of January 1, 2005.
Because Chugach did not request changes to the electric rates charged to our customers based on the proposed new depreciation rates, there was no immediate electric rate impact.
Wholesale customers MEA and HEA were active in the proceeding. Subsequently, MEA and HEA filed an appeal of the RCA’s decision in Superior Court, see Note (13) -“Commitments, Contingencies and Concentrations - Legal Proceedings - Matanuska Electric Association, Inc. v. State of Alaska, Regulatory Commission of Alaska, Superior Court Case No. 3AN-06-8243 Civil.”
HEA later dismissed its appeal leaving MEA’s claim focusing mainly on the question of whether implementation of the new depreciation rates as of January 1, 2005 constituted illegal retroactive rate making. Briefing is complete and oral argument before the Superior Court is scheduled for April 29, 2008. Thereafter, an appeal to the Alaska Supreme Court is possible.
2005 Test Year General Rate Case (Docket No. U-06-134)
On September 27, 2006, the Chugach Board of Directors authorized and instructed management to file a general rate case with the RCA. On September 29, 2006, Chugach filed a general rate case based on a 2005 test year and requested a revenue increase of $10.6 million for the Generation and Transmission (G&T) function and a revenue decrease of $7.8 million for the Distribution function. Overall revenues were proposed to increase $2.8 million in the initial filing.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(2)
Regulatory Matters (continued)
2005 Test Year General Rate Case (Docket No. U-06-134) (continued)
The RCA permitted intervention from Chugach’s wholesale customers and the Regulatory Affairs and Public Advocacy (RAPA) section within the Attorney General’s office of the State of Alaska. It also permitted intervention of a single Chugach retail member. A scheduling order was issued on January 23, 2007, establishing a hearing schedule to adjudicate the case. Discovery from the intervenors in the case on Chugach’s filing and pre-filed initial testimony has been completed. Intervenor testimony has been submitted. Chugach’s reply testimony was submitted May 29, 2007.
A settlement agreement between several of the intervenors and Chugach, reached in July 2007, has been accepted by the RCA. The settlement agreement results in an estimated 3% overall decrease for Chugach retail members and an estimated 3.5% overall increase for HEA and Seward.
The hearing scheduled to occur in August 2007 with the remaining intervenors was canceled. The remaining active intervener, MEA, and Chugach entered into a stipulation to resolve outstanding procedural issues on October 16, 2007. This stipulation agrees to a procedure whereby the RCA will decide the matter based on the written record with provisions for RCA written questions and optional oral questioning by the RCA of selected witnesses. Chugach and MEA filed closing briefs on December 5, 2007. The RCA did not engage in oral questioning of witnesses.
Chugach submitted to the RCA permanent rates to implement the settlement agreement as well as interim and refundable rates for MEA, the party that did not settle, for implementation in the fourth quarter of 2007. The RCA declined to implement any tariff changes at that time and as a result, the implementation date of the rate changes for all parties has been delayed, pending a ruling on the rate changes associated with MEA.
Rates resulting from the settlement agreement approved by the RCA for Chugach retail members, HEA and SES will result in an annual revenue reduction of $2.7 million.
On April 1, 2008, the RCA issued Order No. 21 in Docket U-06-134. In this order, the RCA approved the rates from the Settlement Agreement among Chugach, HEA and SES that it had previously accepted. MEA did not join the Settlement Agreement and this Order addressed the issues that it had raised. Order No. 21 reached findings similar to the Settlement Agreement and the rates for MEA are slightly higher than rates agreed to in the Settlement Agreement. The cumulative effect of Order 15, Settlement Agreement revenues, and Order 21 is overall revenues decreasing by 0.8%, with retail revenue decreasing by 4.8% and wholesale revenue increasing by 11.0%. Order No. 21 is effective June 1, 2008. Chugach expects to be filing a request for reconsideration and a proposed correction to an RCA calculation. It is unknown whether MEA will be making additional filings.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(3)
Utility Plant
Major classes of utility plant as of December 31 are as follows:
Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant. Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment.
(4)
Investments in Associated Organizations
Investments in associated organizations 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. Chugach’s investment in NRUCFC similarly was required by Chugach’s financing arrangements with NRUCFC.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(5)
Deferred Charges and Credits
Deferred Charges
Deferred charges, or regulatory assets, net of amortization, consisted of the following at December 31:
At December 31, 2007 and 2006, $852,560 and $10,229,583, respectively, of total deferred charges represent regulatory assets in progress and are not currently being amortized. Chugach, however, through future RCA rulings, considers recovery and a determination of a recovery period in the future probable. In 2007, the majority of these charges represent costs associated with Chugach’s exploration of new generation options.
Deferred Credits
Deferred credits, or regulatory liabilities, at December 31 consisted of the following:
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(6)
Patronage Capital
Chugach has a Board approved capital credit retirement policy, which is contained in Chugach’s Financial Management Plan. This establishes, in general, a plan to return the capital credits of wholesale and retail customers based on the members’ proportionate contribution to Chugach’s assignable margins. At December 31, 2007, Chugach had $138,713,338 of patronage capital (net of capital credits retired in 2007), which included $116,029,438 of patronage capital that had been assigned and $22,683,900 of patronage capital to be assigned to its members. Approval of actual capital credit retirements is at the discretion of Chugach’s Board of Directors. Chugach records a liability when the retirements are approved by the Board of Directors. The Amended and Restated Indenture prohibits Chugach from making any distribution of patronage capital to Chugach’s members in the event of default under the Amended and Restated Indenture exists (note 8).
Capital credits retired were $5,289,538, $5,106,817, and $4,079,622 for the years ended December 31, 2007, 2006, and 2005, respectively. The outstanding liability for capital credits authorized but not paid was $2,416,552 and $1,322,577 at December 31, 2007 and 2006, respectively.
Following is a five-year summary of anticipated capital credit retirements:
(7)
Other Equities
A summary of other equities at December 31 follows:
1 Represents unclaimed capital credits that have met all requirements of section 34.45.200 of Alaska’s unclaimed property law and has therefore reverted to Chugach.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(8)
Debt
Covenants
Chugach is required to comply with all covenants set forth in the Amended and Restated Indenture, dated April 1, 2001, which became effective January 22, 2003. The indenture initially governing the outstanding CoBank, 2001 Series A, 2002 Series A and 2002 Series B bonds, provided that the bonds were secured by a mortgage on substantially all of Chugach’s assets so long as any amounts were outstanding to CoBank on bonds issued under the indenture. Upon the retirement of the then outstanding bonds on January 22, 2003, the 2001 Series A, 2002 Series A and 2002 Series B bonds (the Bonds) became subject to the Amended and Restated Indenture pursuant to which the Bonds became unsecured obligations of Chugach.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(8)
Debt (continued)
Covenants (continued)
Chugach is also required to comply with the Master Loan Agreement, which covers the CoBank 2, 3, 4 and 5 promissory notes, between Chugach and CoBank dated December 27, 2002, pursuant to which CoBank and Chugach replaced the CoBank 2, 3, 4 and 5 bonds issued to CoBank with the above stated unsecured promissory notes not governed by the indenture. CoBank returned the old CoBank bonds to Chugach on January 22, 2003.
The CoBank Master Loan Agreement requires Chugach to establish and collect electric rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense.
Security
On January 22, 2003, the Bonds became general unsecured and unsubordinated obligations. Under the Amended and Restated Indenture, Chugach is prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on Chugach’s properties and assets (other than those arising by operation of law) to secure the repayment of borrowed money or the obligation to pay the deferred purchase price of property unless Chugach equally and ratably secures the Bonds subject to the Amended and Restated Indenture, except that Chugach may incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements.
Rates
The Amended and Restated Indenture requires Chugach, subject to any necessary regulatory approval, to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. The CoBank Master Loan Agreement also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense. Margins for interest generally consist of Chugach’s assignable margins plus total interest expense. If there occurs any material change in the circumstances contemplated at the time rates were most recently reviewed, the Amended and Restated Indenture requires Chugach to seek appropriate adjustments to those rates so that they would generate revenues reasonably expected to yield margins for interest equal to at least 1.10 times interest charges.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(8)
Debt (continued)
Distributions to Members
The Amended and Restated Indenture prohibits Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Amended and Restated Indenture exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins.
Maturities of Long-term Obligations
Long-term obligations at December 31, 2007, mature as follows:
Short-term obligations
Chugach had maintained a $20,000,000 line of credit with CoBank, ACB (CoBank). On October 25, 2005, Chugach reduced the line of credit to $7.5 million due to a decrease in short-term borrowing projections. On October 17, 2007, the Board of Directors approved a resolution to renew this line of credit. The CoBank line of credit expires October 31, 2008, subject to annual renewal at the discretion of the parties. In March of 2007, Chugach borrowed $3.5 million and repaid the balance in April. In September of 2007, Chugach borrowed $1.0 million and repaid the balance in the same month. Chugach did not utilize this line of credit in 2006. At December 31, 2007 and 2006, there was no outstanding balance on this line of credit. The CoBank Master Loan Agreement requires Chugach to establish and collect electric rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense, to achieve a funded debt to operating cash flow ratio not greater than 8 to 1 and achieve an equity to total capitalization ratio greater than 22%. The borrowing rate is calculated using the CoBank BaseRate on the first day of the week plus 3%. The average borrowing rate for 2007
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(8)
Debt (continued)
Short-term obligations (continued)
and 2006 was 6.47% and 6.51%, respectively. In addition, Chugach had an annual line of credit of $50,000,000 available at December 31, 2007 and 2006, with NRUCFC. Chugach did not utilize this line of credit in 2007 or 2006. At December 31, 2007 and 2006, there was no outstanding balance on this line of credit. The borrowing rate is calculated using the total rate per annum as may be fixed by CFC and will not exceed the Prevailing Prime Rate, plus one percent per annum. At December 31, 2007 and 2006, the borrowing rate would have been 6.40% and 7.15%, respectively. The NRUCFC Revolving Line Of Credit Agreement requires that Chugach, for each 12-month period, for a period of at least five consecutive days, pay down the entire outstanding principal balance. The NRUCFC line of credit expires October 17, 2012. These lines are immediately available for unconditional borrowing.
Refinancing
On August 20, 2007, Chugach refinanced its $5 million promissory note (CoBank 5) with CoBank. The new $5,000,000, variable rate promissory note will mature August 20, 2012 and contains consecutive monthly installment payments commencing September 20, 2007.
2002 Series B Bonds
The 2002 Series B Bonds (the “Auction Rate Bonds”) will mature on February 1, 2012. The applicable interest rate for any 28-day auction period is the term rate established by the auction agent based on the terms of the auction. The Auction Rate Bonds may be converted, in Chugach’s discretion, to a daily, seven-day, 35-day, three-month or a semi-annual period or a flexible auction period. The Auction Rate Bonds are not subject to redemption at the option of the bondholders under any circumstances. Chugach may elect to redeem the bonds and Chugach is required to redeem the bonds in pre-established incremental amounts over time through a sinking fund. The Auction Rate Bonds are subject to a remarketing agreement on a best efforts basis, however in the event of unsuccessful remarketing, the bonds are returned to the bondholders and continue as auction rate bonds subject to a maximum auction rate (15%). Under no circumstances would Chugach be obligated to pay off the Bonds in the event of an unsuccessful remarketing effort. Chugach has not provided any protection to the bondholders in the event of an unsuccessful remarketing, therefore, Chugach has classified the Bonds as long-term, with the exception of the mandatory sinking fund payment due in 2007. The average interest rate for the 2002 Series B Bonds in 2007, 2006, and 2005 was 5.34%, 5.07%, and 3.42%, respectively.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(8)
Debt (continued)
2002 Series B Bonds (continued)
Recent events affecting bond insurers, including Chugach’s bond insurer, MBIA, have injected some level of uncertainty regarding the success of the auction process. By the terms of the auction securities agreement, should an attempt to reset the interest rate on Chugach’s auction rate bonds fail because there are insufficient bids to establish a market-based price, the interest rate on Chugach’s 2002 Series B Bonds would be set utilizing an “Auction Mode Multiple” as defined in Exhibit A to Appendix 2 to Eleventh Supplemental Indenture (Auction Procedures Description).
The “Auction Mode Multiple” as of any Auction Date is a percentage of the Index in effect on such auction date (in Chugach’s case, a percentage of the one month London Interbank Offered Rate (LIBOR). That percentage is based on the Prevailing Rating of the 2002 Series B Bonds in effect at the close of business on the Business Day immediately preceding the Auction Date.
In Chugach’s case, the Auction Mode Multiple is based on MBIA’s AAA rating and would be 150% of one-month LIBOR. This rate would stay in effect for 28 days, followed by another auction. On February 20, 2008, the auction was held and failed to obtain sufficient clearing bids. Therefore, the current bondholders continued to hold the bonds and the rate on the 2002 Series B Bonds was set at 4.677% and stayed in effect until March 20, 2008. The failure of the auction does not constitute an event of default under any financing arrangement.
On March 5, 2008, bondholders were notified of the intent of Chugach to redeem the entire outstanding principal amount of the 2002 Series B Bonds. The Board of Directors authorized the redemption using funds obtained from one or more new borrowings under Chugach’s existing lines of credit with CoBank or NRUCFC.
On March 20, 2008 Chugach redeemed the $29.6 million outstanding principal amount of the 2002 Series B Bonds using our NRUCFC line of credit at an initial rate of 3.46%. Repayment of the NRUCFC line of credit is required by March 15, 2009. Accordingly, outstanding borrowings continue to be classified as long-term. Management is currently evaluating long-term financing options.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(8)
Debt (continued)
2002 Series B Bonds (continued)
The following table provides information regarding auction dates and rates:
(9)
Fair Value of Long-Term Obligations
The estimated fair values (in thousands) of the long-term obligations included in the financial statements at December 31 are as follows:
Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions. The fair value of long-term debt has been determined using discounted future cash flows at borrowing rates currently available to Chugach.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(10)
Employee Benefit Plans
Pension Plans
Pension benefits for substantially all union employees are provided through the Alaska Electrical Pension Trust Fund and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund, multi-employer plans. Chugach pays an hourly amount per eligible union employee pursuant to the collective bargaining unit agreements. In these master, multi-employer plans, the accumulated benefits and plan assets are not determined or allocated separately to the individual employer.
The costs for the union plans were approximately $2.9 million, $2.5 million, and $2.4 million in 2007, 2006, and 2005, respectively. Chugach has no responsibility for any unfunded benefit obligation of the Plan at this time.
Pension benefits for non-union employees are provided by the National Rural Electric Cooperative Association (NRECA) Retirement and Security Program, a multi-employer plan. Chugach makes annual contributions to the pension plan equal to the amounts accrued for pension expense. Chugach contributed $1.9 million, $1.6 million, and $1.8 million in 2007, 2006, and 2005, respectively, to the NRECA plan. Chugach has no responsibility for any unfunded benefit obligation of the Plan at this time.
Health and Welfare Plans
Health and welfare benefits for union employees are provided through the Alaska Electrical Health and Welfare Trust and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund. Chugach participates in multi-employer plans that provide substantially all union workers with health care and other welfare benefits during their employment with Chugach. Chugach pays a defined amount per union employee pursuant to collective bargaining unit agreements. Amounts charged to benefit costs and contributed to the health and welfare plans for these benefits for the years ending December 31, 2007, 2006, and 2005 were $3.3 million, $2.9 million, and $3.0 million respectively.
Chugach participates in a multi-employer plan through the Group Benefits Program of NRECA for non-union employees. Amounts charged to benefit cost and contributed to this Plan for those benefits for the years ended December 31, 2007, 2006, and 2005 totaled $1.9 million, $2.0 million, and $2.0 million respectively.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(10)
Employee Benefit Plans (continued)
Money Purchase Pension Plan
Chugach participates in a multi-employer defined contribution money purchase pension plan covering some employees who are covered by a collective bargaining agreement. Contributions to the Plan are made based on a percentage of each employee’s compensation. Contributions to the money purchase pension plan for the years ending December 31, 2007, 2006, and 2005 were $142.1 thousand, $85.4 thousand, and $80.7 thousand, respectively.
401(k) Plan
Chugach has a defined contribution 401(k) retirement plan which covers substantially all employees who have completed ninety days of continuous service during a twelve month period.
Employees who elect to participate may contribute up to the Internal Revenue Service’s maximum of $15,500, $15,000, and $14,000 in 2007, 2006, and 2005 respectively. Chugach does not make contributions to the plan.
Deferred Compensation
Chugach adopted NRECA’s unfunded Deferred Compensation Program (the Program) to allow highly compensated employees who elect to participate in the Program to defer a portion of their current compensation and avoid paying tax on the deferrals until received. The program is a non-qualified plan under Internal Revenue Code 457(b).
Deferred compensation accounts are established for the individual employees, however, they are considered to be owned by Chugach until a distribution is made. The amounts credited to the deferred compensation account, including gains or losses, are retained by Chugach until the entire amount credited to the account has been distributed to the participant or to the participant’s beneficiary. The balance of the Program for the years ending December 31, 2007, 2006 and 2005 was $768,041, $645,582 and $283,924, respectively.
Potential Termination Payments
Pursuant to a Chugach Operating Policy, non-represented employees, including the executive officers except the Chief Executive Officer, who are terminated by Chugach for reasons unrelated to employee performance are entitled to severance pay for each year or partial year of service as follows: two weeks for each year of service to a maximum of twenty (26) weeks for thirteen (13) years or more of service. If the Interim CEO is terminated with or without cause, he shall revert to his position of Senior Vice President of Power Supply.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
(11)
Bradley Lake Hydroelectric Project
Chugach is a participant in the Bradley Lake Hydroelectric Project (Bradley Lake). Bradley Lake was built and financed by the Alaska Energy Authority (AEA) through State of Alaska grants and $166,000,000 of revenue bonds. Chugach and other participating utilities have entered into take-or-pay power sales agreements under which shares of the project capacity have been purchased and the participants have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt service costs and amounts required to maintain established reserves). Under these take-or-pay power sales agreements, the participants have agreed to pay all project costs from the date of commercial operation even if no energy is produced. Chugach has a 30.4% share of the project’s capacity. The share of debt service exclusive of interest, for which Chugach has guaranteed, is approximately $37,000,000. 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%. Upon default, Chugach could be faced with annual expenditures of approximately $5.0 million as a result of Chugach’s Bradley Lake take-or-pay obligations. Management believes that such expenditures, if any, would be recoverable through the fuel surcharge rate making process.
The following represents information with respect to Bradley Lake at June 30, 2007 (the most recent date for which information is available). Chugach’s share of expenses was $4,816,790 in 2007, $4,219,321 in 2006, and $4,993,670 in 2005 and is included in purchased power in the accompanying financial statements.
Other electric plant represents Chugach’s share of a Bradley Lake transmission line financed internally and Electric Plant Held for Future Use.
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Eklutna Hydroelectric Project
During October 1997, the ownership of the Eklutna Hydroelectric Project formally transferred from the Alaska Power Administration to the participating utilities. This group, including their corresponding interest in the project, consists of Chugach (30%), MEA (16.7%) and Anchorage Municipal Light & Power (AML&P) (53.3%).
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
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Eklutna Hydroelectric Project (continued)
Plant in service in 2007 includes $2,540,275, net of accumulated depreciation of $719,186, which represents Chugach’s share of the Eklutna Hydroelectric Plant. In 2006 plant in service included $2,644,397, net of accumulated depreciation of $608,495. Chugach and AML&P jointly operate 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. Chugach’s share of expenses was $712,552, $591,903, and $476,739 in 2007, 2006, and 2005, respectively and is included in power production and depreciation in the accompanying financial statements. Chugach provides personnel for the daily operation and maintenance of the power plant. AML&P performs major maintenance at the plant. Chugach personnel perform daily plant inspections, meter reading, monthly report preparation, and other activities as required.
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Commitments, Contingencies and Concentrations
Contingencies
Chugach is a participant in various legal actions, rate disputes, personnel matters and claims both for and against Chugach’s interests. Management believes the outcome of any such matters will not materially impact Chugach’s financial condition, results of operations or liquidity.
Long-Term Fuel Supply Contracts
Chugach has entered into long-term fuel supply contracts from various producers at market terms. The current contracts will expire at the end of the currently committed volumes or the contract expiration dates of 2015 and 2025. The committed 215 BCF for the 2015 contract should be used by mid 2010. The currently committed 180 BCF for the 2025 contract should also be used by 2010. Chugach is currently working with Cook Inlet producers on future supply contracts. In 2007, 93% of our power was generated from gas, while in 2006 and 2005, 90% and 88%, respectively, of our power was generated from gas. Of that gas-fired generation, 86% took place at Beluga in 2007, while in 2006 and 2005, 87% and 86%, respectively, of gas-fired generation took place at Beluga.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
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Commitments, Contingencies and Concentrations (continued)
Long-Term Fuel Supply Contracts (continued)
Fuel is purchased directly from Marathon Oil Company, ChevronTexaco, AML&P and ConocoPhillips. The following represents the cost of fuel purchased from these vendors as a percentage of total fuel costs for the years ended December 31:
Concentrations
Approximately 70% of Chugach’s employees are represented by the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW, which expire on June 30, 2010.
Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts, including the fuel component, represented $93.4 million or 36.7% of sales revenue in 2007, $90.1 million or 34.1% in 2006, and $72.1 million or 32.4% in 2005. The HEA contract expires January 1, 2014, and the MEA contract expires December 31, 2014. All rates are established by the RCA.
Legal Proceedings
Matanuska Electric Association, Inc. (MEA) v. State of Alaska, Regulatory Commission of Alaska, Superior Court Case No. 3AN-06-8243 Civil
On May 17, 2006, MEA appealed and on May 30, 2006, Homer Electric Association, Inc., (HEA) cross appealed the RCA’s decision in Commission Docket No. U-04-102, see “Footnote 2, Regulatory Matters - Revision to Current Depreciation Rates (Docket No. U-04-102).” On appeal, MEA claims the RCA’s decision dated January 10, 2006, to authorize Chugach to implement new depreciation rates as of January 1, 2005, constituted illegal retroactive rate making. MEA further contends that the RCA’s reliance on avoidance of regulatory lag as a basis for its decision was improper. MEA also challenged certain of the RCA’s discovery rulings. Chugach has joined the State of Alaska in defending the RCA’s rulings. HEA stipulated with the other parties to dismiss its cross appeal which the Court granted by order dated September 11, 2007. All of the parties have filed their respective briefs and the Court scheduled oral argument for April 29, 2008.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
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Commitments, Contingencies and Concentrations (continued)
Legal Proceedings (continued)
The ultimate resolution of this matter is not currently determinable. In the opinion of management, an adverse outcome is not likely to have a material adverse effect on Chugach’s results of operations, financial condition or liquidity. No reserves have been established for this matter.
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 to fund the governing regulatory commission, which is currently the RCA. The tax is assessed on all retail consumers and is based on kilowatt-hour (kWh) consumption. The tax is collected monthly and remitted to the State of Alaska quarterly. The Regulatory Cost Charge has changed since its inception (November 1992) from an initial rate of $0.000626 per kWh to the current rate of $0.000274, effective July 1, 2007. The tax is reported on a net basis and the tax is not included in revenue or expense.
Sales Tax
Chugach collects sales tax on retail electricity sold to Kenai and Whittier consumers. The tax is collected monthly and remitted to the Kenai Peninsula Borough quarterly. Sales tax is reported on a net basis and the tax is not included in revenue or expense.
Gross Receipts Tax
Chugach pays to the State of Alaska a gross receipts tax in lieu of state and local ad valorem, income and excise taxes on electricity sold in the retail market. The tax is accrued monthly and remitted annually. The tax is reported on a net basis and the tax is not included in revenue.
Excise taxes
Excise taxes on Chugach fuel purchases are paid directly to our gas producers and are recorded under “Fuel” in Chugach’s financial statements and are not directly passed through to our consumers.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
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Commitments, Contingencies and Concentrations (continued)
Underground Compliance Charge
In 2005 the Anchorage Municipal Assembly adopted an ordinance to require utilities to convert overhead distribution lines to underground. To comply with the ordinance, Chugach must invest two percent of gross retail revenue in the Municipality of Anchorage annually in moving existing distribution overhead lines underground. Consistent with State of Alaska undergrounding requirement, Chugach is permitted to amend its rates by adding a 2% surcharge to its retail members’ bills to recover the actual costs of the program. The rate amendments are not subject to RCA review or approval. Chugach implemented the surcharge in June 2005. Chugach’s liability was $571,530 and $2,044,001 for this surcharge at December 31, 2007 and December 31, 2006, respectively and will use the funds to offset the costs of the projects.
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.
In March 2007 Chugach conducted emissions testing at the Bernice Lake Power Plant which indicated that two of the gas turbines at the facility were exceeding the New Source Performance Standards (NSPS) emission limit for nitrogen oxides (NOx). Chugach voluntarily limited the power output of these turbines to ensure interim compliance with the NSPS regulations and is currently in the final stages of commissioning a water injection system to control NOx emissions from the turbines. With the water injection system, Chugach will again be able to fully utilize the power output from these turbines while complying with the NSPS regulations.
Chugach is also currently working with the Alaska Department of Environmental Conservation (ADEC) to resolve the issue of past non-compliance with the Bernice Lake turbines. On March 26, 2008, the ADEC issued a formal Notice of Violation (NOV) to Chugach regarding the NSPS issues. Specifically, the NOV alleges that Chugach violated its operating permit and air quality regulations by operating two generating units at the Bernice Lake Power Plant in excess of the NOx emission limit; failing to perform a source test to demonstrate compliance with regulations; and failing to conduct reasonable inquiry regarding source test compliance for the 2006 annual compliance certification. ADEC requested a meeting with Chugach to discuss
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2007 and 2006
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Commitments, Contingencies and Concentrations (continued)
Environmental Matters (continued)
settlement of the identified alleged violations. It is not possible at this time to reasonably anticipate the amount of any potential penalty that may result from this NOV.
Chugach is subject to numerous other environmental statutes including the Clean Water Act, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Endangered Species Act, and the Comprehensive Environmental Response, Compensation and Liability Act and to the regulations implementing these statutes. We do not believe that compliance with these statutes and regulations to date has had a material impact on our financial condition or results of operation. However, new laws or regulations, implementation of final regulations or changes in or new interpretations of these laws or regulations could result in significant additional capital or operating expenses.
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Quarterly Results of Operations (unaudited)
Item 9
Item 9 - Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure
None
Item 9A
Item 9A - Controls and Procedures
Evaluation of Controls and Procedures
As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 (“Exchange Act”) Rule 13a - 15(e)) under the supervision and with the participation of our management, including our CEO and our Chief Financial Officer (CFO). Based on this evaluation, our CEO and CFO each concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic reports to the SEC. The design of any system of controls is based in part upon various assumptions about the likelihood of future events, and there can be no assurance that any of our plans, products, services or procedures will succeed in achieving their intended goals under future conditions. In addition, there have been no significant changes in our internal controls or in other factors known to management that could significantly affect our internal controls subsequent to our most recent evaluation.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal controls over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Under the supervision and with the participation of our management, including our CEO and CFO, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2007, using the criteria set forth in “Internal Control Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management believes that, as of December 31, 2007, Chugach maintained effective internal control over financial reporting. This annual report does not include an attestation report of Chugach’s independent registered public accounting firm, KPMG, LLP, regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
Item 9B
Item 9B - Other Information
On January 26, 2006, Chugach gave notice as provided in Section 14(b) of the Alaska Railbelt Energy Authority of its withdrawal from the Joint Action Agency Agreement Relating to the Alaska Railbelt Energy Authority (AREA) dated as of August 1, 2005 (Agreement) and the AREA effective January 27, 2006. The Chugach Board of Directors passed a resolution at their March 14, 2007 meeting rejoining the AREA Joint Action Agency (JAA).
On June 15, 2007, AML&P and Chugach issued a mutual press release announcing plans to explore a possible merger or joint operations between Chugach and AML&P.
On September 7, 2007, Director Alan Christopherson tendered his resignation from the Board of Directors effective immediately. On October 17, 2007, the Board of Directors voted to fill the vacancy with Rebecca Logan.
On December 5, 2007, the Chugach Board of Directors voted to terminate the contract of Chugach’s CEO Bill Stewart. He had been named interim CEO by the board in September 2005, and appointed CEO by the Board in August 2006. The Board appointed Brad Evans as Interim CEO, effective immediately. Mr. Evans was Chugach’s Senior Vice President of Power Supply and has more than 23 years of utility experience. The Board also appointed a subcommittee to consider selection of a longer term chief executive officer. The subcommittee consists of Chair Elizabeth Vazquez, Vice Chair Uwe Kalenka and Director Rebecca Logan.
On January 11, 2008, Senior Vice President, Power Delivery and Chief of Staff Lee Thibert, tendered his resignation effective February 1, 2008. Mr. Thibert is resigning from Chugach in order to return to the construction and consulting industry.
On February 8, 2008, AML&P and Chugach issued a mutual press release announcing that a panel, appointed to consider the possible merger of Southcentral Alaska’s two largest utilities, is recommending the utilities explore joint generation and operations between the two, which a consultant’s report says could save ratepayers nearly $200 million. The panel adopted a motion recommending the management of Chugach and AML&P seek ways to implement the savings identified by the Navigant study and report back on their progress within 60 days. The panel is chaired by Mayor Mark Begich and Chugach Board Chair Elizabeth Vazquez.
On March 20, 2008, Chugach redeemed the $29.6 million outstanding principal amount of the 2002 Series B Bonds using our NRUCFC line of credit at an initial rate of 3.46%.
PART III
Item 10
Item 10 - Directors, Executive Officers and Corporate Governance
Chugach operates under the direction of a Board of Directors that is elected at large by our membership. Day-to-day business and affairs are administered by the CEO. Our seven-member
Board sets policy and provides direction to the CEO. No member of the Board is an employee of the company nor does any member of the Board have a material relationship with the company. Therefore, the Chugach Board has determined that all members are independent.
Identification of Directors
Elizabeth Vazquez, 56, is an attorney with the State of Alaska and has a Master of Business Administration (MBA). She was elected to the Board in 2005 and elected Board Chair in 2007. She also chairs the Board’s Operations Committee and serves on the Finance and Audit committees. She is a National Rural Electric Cooperative Association (NRECA) Credentialed Cooperative Director. She previously served as Treasurer and as Chair of the Finance Committee. Mrs. Vazquez’s current term expires in April 2008.
Uwe Kalenka, 63, is a self-employed property manager. He was elected to the Board in 2005 and elected Board Vice Chairman in 2007. He serves on the Board’s Audit, Finance and Operations committees. Kalenka also serves as Chugach’s Alaska Power Association (APA) representative and is the Board liaison for MEA, HEA and the City of Seward. He is a NRECA Credentialed Cooperative Director and has received his Board Leadership Certificate. Mr. Kalenka’s current term expires in April 2008.
P.J. Hill, 63, is an Associate Professor of Economics at the University of Alaska Anchorage and commercial fisherman. He was elected to the Board in 2007 and currently serves as Treasurer. Hill chairs the Board’s Finance and Audit Committees and serves on the Operations Committee. Mr. Hill’s current term ends in April 2010.
Alex Gimarc, 56, is a systems analyst with the Muncipality of Anchorage. He was elected to the Board in 2007 and currently serves as Secretary. Gimarc currently serves on the Board’s Operations Committee and is also Chugach’s JAA representative. Mr. Gimarc’s current term ends in April 2010.
Jeff Lipscomb, 57, is a project management consultant with JWL Engineering. He was elected to the Board in 2000 and re-elected in 2003 and 2006. Lipscomb currently serves on the Board’s Finance and Audit Committees. He also serves on Northwest Public Power Association’s (NWPPA) Board of trustees and chairs their Audit Committee and is a NRECA Credentialed Cooperative Director. He previously served as Board Treasurer and has also served as Chairman of the Operations, Finance and Audit Committees. Mr. Lipscomb’s current term ends in April 2009.
Jim Nordlund, 55, is a self-employed homebuilder and general contractor with Nordlund Carpentry, LLC. Nordlund is a former legislator and state Director of Public Assistance. He was elected to the Board in 2006 and currently serves on the Board’s Operations Committee and is a NRECA Credentialed Cooperative Director. He previously served on the Board’s Operations, Finance and Audit Committees. Mr. Nordlund’s current term expires in April 2009.
Rebecca Logan, 44, is President and Chief Executive Officer for the Associated Builders and Contractors, Alaska Chapter. She was appointed to fill a Board vacancy in 2007. Logan serves as Chugach’s APA Resolutions/Government Affairs representative. Mrs. Logan’s current term expires in April 2008.
Identification of Executive Officers
Brad W. Evans, 53, was appointed Interim CEO on December 5, 2007. Prior to that appointment, Mr. Evans had served as Sr. Vice President, Power Supply since March 20, 2006, General Manager, G&T Division since January 31, 2005, Sr. Vice President, Energy Supply since June 5, 2002 and Director, Energy Supply since February 26, 2001. Prior to his current Chugach employment, Mr. Evans served as Manager, System Dispatch for Golden Valley Electric Association.
Edward Jenkin, 47, was appointed Acting Sr. Vice President Power Delivery on January 14, 2008. Mr. Jenkin has over 20 years utility experience in engineering, system operations, and planning. He is a Registered Engineer in the State of Alaska. Mr. Jenkin was promoted from the position of the Director, Engineering Services Division that he held since July of 2004. Prior to that Mr. Jenkin served as System Operations Supervisor beginning in February of 2000 and was the Senior Planning Engineer starting August of 1995. Mr. Jenkin began his utility career as an Engineering Technician for Matanuska Electric Association in April of 1982.
Michael R. Cunningham, 58, was appointed Chief Financial Officer on June 5, 2002. Prior to that appointment he served as Controller since 1986. Prior to that, he was Budget Analyst and Manager of Accounting since beginning his Chugach employment in 1982. Prior to his Chugach employment, Mr. Cunningham spent 15 years in various capacities with Pacific Northwest Bell Telephone Company.
Paul Risse, 53, was appointed Acting Sr. Vice President, Power Supply on December 6, 2007. Prior to that appointment, Mr. Risse had served as Director of Generation Technical Services since March 27, 2006; Manager, Plant Technical Services since January 1, 2003; Project Manager since August 15, 2000; Project Engineer since April 5, 2000; and Manager Substation Operations since January 25, 1995. Prior to his current Chugach employment, Mr. Risse served in various Transmission and Generation positions at Southern California Edison.
Ron Vecera, 50, was appointed Acting Sr. Vice President, Strategic Planning & Corporate Affairs, on February 19, 2008. Prior to that appointment, Mr. Vecera served as Director of Member Services since 1997. Mr. Vecera has worked at Chugach over 25 years, including 20 years in Member Services and 5 years in Planning and Rates. Mr. Vecera has also worked for the Alaska Public Utilities Commission and has an MBA degree from Columbia University.
Audit Committee Financial Expert
Chugach is a cooperative and each Board member must be a member of the cooperative. The Board relies on the advice of all members of the Finance and Audit Committees, therefore the Board has not formally designated an Audit Committee financial expert.
Identification of the Audit Committee
Chugach Board Policy No. 127, “Audit Committee Charter,” defines the Audit Committee as follows:
The Audit Committee shall be comprised of three or more directors as determined by the Board. Unless otherwise determined by the Board, the members of the Board Finance Committee shall be the members of the Audit Committee. Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Association or an outside consultant or other programs. The Committee may also retain the services of a qualified accounting professional with auditing expertise to assist it in the performance of its responsibilities.
The Board shall appoint members of the Committee. Unless a Chair is designated by the Board, the members of the Committee may appoint their own Chair by majority vote. Members of the 2007 Audit Committee include Chair P.J. Hill and Directors Jeffrey Lipscomb, Elizabeth Vazquez and Uwe Kalenka.
The disclosure required by §240.10A-3(d) regarding exemption from the listing standards for the audit committees is not applicable to the Chugach Audit Committee.
Item 11
Item 11 - Executive Compensation
Compensation Discussion and Analysis
In 1986, National Rural Electric Cooperative Association (NRECA) developed the COMPensate wage and salary plan to provide its members with a systematic and standardized method to evaluate jobs in their specific cooperative, grade them, compare wages and salaries with those in similar electric utility systems and in the external marketplace and then create and apply statistically determined, equitable pay scales. In 1988, the Chugach Board approved implementation of NRECA’s COMPensate wage and salary plan for non-bargaining unit employees with the objective of establishing wages and salaries for non-bargaining unit employees that would attract and retain qualified personnel and encourage their superior performance, growth and development.
Each year the regression analysis/compensation model is updated with current salary survey values to insure that the ranges reflect fair market value. The overall change to the salary ranges reflects market changes to the midpoint of the salary ranges and creates an opportunity for but not a guarantee of salary increases. Salary increases are not automatic and are based on performance. Salary increases are awarded to non-represented employees based on individual performance and their compa-ratio. The compa-ratio indicates where an individual’s annual salary is in relationship to the mid-point of their salary grade. The mid-point represents the market value of the individual position. Any changes to the COMPensate wage and salary plan for Chugach are approved by the Chugach Board.
On February 21, 2007, the Board of Directors approved the following goals for the CEO however, on May 16, 2007, the Board returned the CEO goals to the Operations Committee for reconsideration. No compensation was linked to the success of each goal.
1.
Achieve service reliability targets of no more than 1.6 outages of 75 minutes or more per average customer and no more than 150 outage minutes per year per average customer
2.
Achieve customer survey results indicating high satisfaction with Chugach’s reliability, service and price
3.
Achieve utility financial management targets of an overall Margins For Interest/Interest (MFI/I) ratio of 1.37, equity to total capitalization ratio of 30.9%, a Distribution MFI/I ratio of 2.76 and a G&T MFI/I ratio of 0.82
4.
Be proactive in respect to the (2005 Test Year) Rate Case and management thereof
5.
Complete negotiations on the labor contracts
6.
Report periodically on benchmarking and process improvement efforts
7.
Finalize plan for new generation capacity by April 1, 2007
8.
Complete mid range fuel contract negotiations by November 1, 2007
9.
Make a recommendation to the Board for a G&T and Distribution organization by March 31, 2007
10.
Develop a Financial Management Plan by March 31, 2007
11.
Perceive to be a leader by employees and the Board. Achieve highly deemed personal ethics and accountability
12.
Effectively promote the Association and the Association’s goals with members of the public, governmental bodies and through the media
13.
Establish an effective organization that is designed and staffed to meet a changing environment
14.
Effectively participate in local, regional, state and national organizations to promote the Association and achieve Association’s goals
15.
Keep the Board informed of important industry issues and Chugach’s performance. Bring well thought-out recommendations for the Board’s consideration. Actively build trust and support of the Board. Encourage the Board to work together effectively and encourage innovative thinking on the part of the Board
16.
Create a positive work environment for employees and encourage team work. Delegate effectively to key staff and provide effective feedback. Keep employees informed about industry issues and trends and influence them to adapt to change. Assure that competent individuals are hired, trained and promoted. Empower employees to make decisions that improve Chugach’s performance
17.
Develop a Strategic Business Plan by October 15, 2007
18.
Achieve a lost time injury incident rate of less than 3.00
19.
Achieve a recordable incident rate of less than 6.0
20.
Achieve vehicle incidents of less than 7
21.
Promote an environment of safety in the workforce
22.
Receive no environmental violations during 2007
On December 5, 2007, the Board voted to terminate the contract of Chugach’s CEO Bill Stewart and appointed Brad Evans as Interim CEO. Interim CEO Brad Evan’s Memorandum of Agreement provided for a one time bonus to be paid on or before January 11, 2008 (Ref. Exhibit 10.57).
The salary and bonuses for all other named executive officers are set annually by the CEO within annual budget guidelines approved by the Board of Directors.
Cash Compensation
The following table sets forth all remuneration paid by us for the last two fiscal years to each of our executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2007 and for all such executive officers as a group:
Summary Compensation Table
1Includes costs for life insurance premiums, tax gross up and payment for unused vacation days. The amount in 2007 for Mr. Cunningham includes $14,680 of payment for unused vacation days. The amount in 2007 for Mr. Stewart includes $44,249 of payment for unused vacation days.
On March 19, 2008, the Board of Directors voted to terminate former CEO William R. Stewart for cause, therefore Mr. Stewart may not receive any further compensation over the remaining term of his employment contract. Mr. Stewart has contested the Board’s decision to terminate him for cause, and, in accordance with the dispute resolution mechanism in his employment agreement, has demanded arbitration. In the event an arbitrator rules in favor of Mr. Stewart, he will be entitled to up to 18 months severance pay and benefits.
Pension Benefits
We have elected to participate in the National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (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. Under FAS 87, the plan is a multi employer plan, in which the accumulated benefits and plan assets are not determined or allocated separately to individual employers. The Plan is intended to be a qualified pension plan under Section 401(a) of the Code. All our employees not covered by a union agreement become participants in the Plan on the first day of the month following completion of one year of eligibility service. An employee is credited with one year of eligibility service if he or she completes 1,000 hours of service either in his or her first twelve consecutive months of employment or in any calendar year for us or certain other employers in rural electrification (related employers). Pension benefits vest at the rate of 10% for each of the first four years of vesting service and become fully vested and nonforfeitable on the earlier of the date a participant has five years of vesting service or the date the participant attains age fifty-five while employed by us or a related employer. A participant is credited with one year of vesting service for each calendar year in which he or she performs at least one hour of service for us or a related employer. Pension benefits are generally paid upon the participant’s retirement or death. A participant may also elect to receive pension benefits while still employed by us if he or she has reached his normal retirement date by completing thirty years of benefit service (defined below) or, if earlier, by attaining age sixty-two. A participant may elect to receive actuarially reduced early retirement pension benefits before his or her normal retirement date provided he or she has attained age fifty-five.
Pension benefits paid in normal form are paid monthly for the remaining lifetime of the participant. Unless an actuarially equivalent optional form of benefit payment to the participant is elected, upon the death of a participant the participant’s surviving spouse will receive pension benefits for life equal to 50% of the participant’s benefit. The annual amount of a participant’s pension benefit and the resulting monthly payments the participant receives under the normal form of payment are based on the number of his or her years of participation in the Plan (benefit service) and the highest five-year average of the annual rate of his or her base salary during the last ten years of his or her participation in the Plan (final average salary). Annual compensation in excess of $200,000, as adjusted by the Internal Revenue Service for cost of living increases, is disregarded after January 1, 1989. The participant’s annual pension benefit at his or her normal retirement date is equal to the product of his or her years of benefit service times final average salary times 2%. In 1998, NRECA notified us that there were employees whose pension benefits from NRECA’s Retirement & Security Program would be reduced because of limitations on retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA made available a Pension Restoration Severance Pay Plan and a Pension Restoration Deferred Compensation Plan for cooperatives to adopt in order to make employees whole for their lost benefits. In May 1998, we adopted both of these plans to protect the benefits of current and future employees whose pension benefits would be reduced because of these limitations.
On October 16, 2002, the Board authorized an amendment to the Plan with an effective date of November 1, 2002. Under the amended Plan, the retirement benefit payable to any Participant whose retirement is postponed beyond his or her Normal Retirement Date shall be computed as of the Participant’s actual retirement date. The retirement benefit payable to any Participant under the 30-Year Plan shall be computed as of the first day of the month in which the Participant’s actual retirement date occurs.
Benefit service as of December 31, 2007 that is taken into account under the Plan for the executive officers is shown below with the assumptions for calculation of the present value of accumulated benefits.
Pension Benefits Table
It is assumed that participants retire at the earlier of age 62 or 30 years of benefit service and elect a lump sum benefit.
Lump sum amounts are calculated using the 30-year Treasury rate, which was 4.69% for 2007, and the required IRS mortality table for lump sum payments. The lump sum is then discounted at 5.75% interest only with no mortality assumed from age 62 back to December 31, 2007.
Deferred Compensation
Chugach adopted NRECA’s unfunded Deferred Compensation Program (the Program) to allow highly compensated employees who elect to participate in the Program to defer a portion of their current compensation and avoid paying tax on the deferrals until received. As a non-qualified plan under Internal Revenue Code 457(b), NRECA’s Deferred Compensation Plan is not subject to non-discrimination testing. The Program is designed to help decrease current taxable income, take advantage of tax deferred compounding and set aside additional money for retirement. The money is accessible only upon separation of service, disability or death (in which case it is paid to the designated beneficiary). The distribution is taxable as income in the year received.
Deferred compensation accounts are established for the individual employees, however, they are considered to be owned by Chugach until a distribution is made. Deferred compensation plan assets would be subject to creditors’ demands in the case of bankruptcy. Deferred compensation assets are invested with Homestead Funds, a family of no-load mutual funds. Homestead Funds’ investment managers, RE Advisers, is a wholly-owned subsidiary of NRECA. Each participant in the Program determines the investment fund or funds into which their accounts are invested. The amounts credited to the deferred compensation account, including gains and losses, are retained by Chugach until the entire amount credited to the account has been distributed to the Participant or to the Participant’s beneficiary.
Deferred Compensation Table
Potential Termination Payments
Pursuant to a Chugach Operating Policy, non-represented employees, including the executive officers except the Chief Executive Officer, who are terminated by Chugach for reasons unrelated to employee performance are entitled to severance pay for each year or partial year of service as follows: two weeks for each year of service to a maximum of twenty (26) weeks for thirteen (13) years or more of service. If the Interim CEO is terminated with or without cause, he shall revert to his position of Senior Vice President of Power Supply. (Ref. Exhibit 10.57)
The following is a list of the estimated severance payments, including the payment of accrued vacation that would be made to each of the executive officers in the case of termination not related to employee performance:
Potential Termination Payments Table
On December 5, 2007, the Board voted to terminate the contract of Chugach’s CEO Bill Stewart. On March 19, 2008, the Board of Directors voted to terminate former CEO William R. Stewart for cause, therefore Mr. Stewart may not receive any further compensation over the remaining term of his employment contract. Mr. Stewart has contested the Board’s decision to terminate him for cause, and, in accordance with the dispute resolution mechanism in his employment agreement, has demanded arbitration. In the event an arbitrator rules in favor of Mr. Stewart, he will be entitled to up to 18 months severance pay and benefits.
Director Compensation
Directors are compensated for their services at the rate of $200 per Board meeting or other meeting at which they are representing the Association in an official capacity within the State of Alaska, and $250 per day when attending meetings or training outside of the State, including each day of travel, plus reimbursement of reasonable out of pocket expenses, up to a maximum of 70 meetings per year for a director and 85 meetings per year for the Chairman.
The following table sets forth the dollar amounts of all fees paid in cash by us for the fiscal year ending December 31, 2007 to each of our current and former Board members:
Director Compensation Table
Two new Board members were elected at Chugach’s annual membership meeting held on April 26, 2007. P.J. Hill and Alex Gimarc were elected to three-year terms, replacing directors Bruce Davison and David Cottrell. On September 7, 2007, Director Alan Christopherson tendered his resignation from the Board. On October 17, 2007, the Board voted to fill the vacancy with Rebecca Logan.
Code of Ethics
Chugach developed a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer and any person performing similar functions. The code of ethics was finalized June 16, 2004. It is also posted on Chugach’s website at www.chugachelectric.com.
Item 12
Item 12 - Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
Not Applicable
Item 13
Item 13 - Certain Relationships and Related Transactions, and Director Independence
Not Applicable
Item 14
Item 14 - Principal Accounting Fees and Services
The Audit Committee of the Board retained KPMG LLP as the independent registered public accounting firm for Chugach during the fiscal year ended December 31, 2007.
Fees and Services
KPMG LLP has provided certain audit, audit-related, tax and non-audit services, the fees for which are as follows:
The Audit Committee of the Board has a policy to pre-approve all services to be provided by Chugach’s independent public accountants. All services from KPMG LLP for fiscal years ended December 31, 2007 and 2006 were approved by the Audit Committee.
PART IV
Item 15
Item 15 - Exhibits and Financial Statement Schedules
Page
Financial Statements
Included in Part II of this Report:
Report of Independent Registered Public Accounting Firm
Balance Sheets, December 31, 2007 and 2006
45-46
Statements of Operations,
Years ended December 31, 2007, 2006 and 2005
Statements of Changes in Equities and Margins,
Years ended December 31, 2007, 2006 and 2005
Statements of Cash Flows,
Years ended December 31, 2007, 2006 and 2005
Notes to Financial Statements
50-75
Financial Statement Schedules
Included in Part IV of this Report:
Report of Independent Registered Public Accounting Firm
Schedule II - Valuation and Qualifying Accounts,
Years ended December 31, 2007, 2006 and 2005
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.
Report of Independent Registered Public Accounting Firm
The Board of Directors
Chugach Electric Association, Inc.
Under date of April 14, 2008, we reported on the balance sheets of Chugach Electric Association, Inc. as of December 31, 2007 and 2006, and the related statements of operations, changes in equities and margins and cash flows for each of the years in the three-year period ended December 31, 2007, which are included in the 2007 Annual Report on Form 10-K. In connection with our audits of the aforementioned financial statements, we also audited the related financial statement schedule in the 2007 Annual Report on Form 10-K. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement schedule based on our audits.
In our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ KPMG, LLP
Anchorage, Alaska
April 14, 2008
Schedule II
CHUGACH ELECTRIC ASSOCIATION, INC.
Valuation and Qualifying Accounts
EXHIBITS
Listed below are the exhibits, which are filed as part of this Report:
10.5.1
Assignment of Agreement for Sale of Electric Power and Energy by and among the Registrant, Homer Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19)
10.6
Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of January 30, 1989. (1)
10.6.1
First Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of February 10, 1995. (1)
10.6.2
Net Billing Agreement by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 16, 1987. (1)
10.7
Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc. dated May 18, 1988. (1)
10.7.1
Amendatory Agreement No. 1 to Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc., dated December 14, 1989. (11)
10.7.2
Letter Agreement dated January 18, 1996 between the Registrant and Golden Valley Electric Association, Inc., amending the Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc. (11)
10.7.3
Amendatory Agreement No. 2 to Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc., dated February 8, 1999. (11)
10.7.4
Settlement Agreement by and among the Registrant, Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Anchorage Municipal Light and Power dated May 6, 1999. (11)
10.8
Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. dated April 21, 1989. (1)
10.8.1
Amendment No. 1 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc., dated August 1, 1990. (1)
10.8.2
Letter Agreement dated April 23, 1999, regarding the Registrant’s consent to the assignment to ARCO Beluga, Inc. of the Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. (11)
10.8.3
Amendment No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Beluga, Inc., dated May 6, 1999. (8)
10.9
Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and ARCO Alaska, Inc. dated October 3, 1991. (1)
10.10
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company dated September 26, 1988. (1)
10.10.1
Letter Agreement dated September 26, 1988 between the Registrant and Marathon Oil Company, amending the Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company. (1)
10.10.2
Amendatory Agreement No. 1 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated effective as of February 21, 1990. (1)
10.10.3
Amendatory Agreement No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated effective as of February 21, 1990. (1)
10.10.4
Amendatory Agreement No. 3 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated January 28, 1991. (1)
10.10.5
Amendatory Agreement No. 4 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated October 6, 1993. (11)
10.10.6
Letter Agreement dated January 18, 1996 between the Registrant and Marathon Oil Company, amending the Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company. (11)
10.10.7
Amendatory Agreement No. 5 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated May 24, 1999. (8)
10.11
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Shell Western E&P Inc. dated April 25, 1989. (1)
10.11.1
Amendatory Agreement No. 1 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc., dated October 1, 1989. (1)
10.11.2
Amendment No. 2 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc., dated June 20, 1990. (1)
10.11.3
Amendatory Agreement No. 3 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc. dated October 14, 1996. (1)
10.12
Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Shell Western E&P Inc. dated November 2, 1990. (1)
10.13
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron USA Inc. dated April 27, 1989 (including Attachment No. 1 thereto dated December 20, 1989). (1)
10.13.2
Amendment No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron USA Inc., dated June 7, 1990. (1)
10.13.3
Amendment No. 3 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron U.S.A. Inc., dated May 26, 1999. (8)
10.14
Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Chevron USA, Inc. dated September 25, 1990. (1)
10.15
Alaska Intertie Agreement between Alaska Power Authority, Municipality of Anchorage, the Registrant, City of Fairbanks, Alaska Municipal Utilities System, Golden Valley Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 23, 1985. (1)
10.16
Addendum No. 1 to the Alaska Intertie Agreement-Reserve Capacity and Operating Reserve Responsibility dated December 23, 1985. (1)
10.17
Memorandum of Understanding Regarding Intertie Upgrades among Alaska Energy Authority, the Registrant, Golden Valley Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power, and the City of Seward d/b/a Seward Electric System dated March 21, 1990. (1)
10.18
Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. (11)
10.19
Intertie Grant Agreement between the Registrant, Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Matanuska Electric Association, Inc. and Homer Electric Association, Inc.), City of Seward, the State of Alaska, Department of Administration and Alaska Industrial Development and Export Authority dated August 17, 1993. (1)
10.20
Grant Transfer and Delegation Agreement between the Registrant and Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc., Matanuska Electric Association, Inc., Homer Electric Association, Inc., Seward, the State of Alaska, Department of Administration, and AMEA dated November 5, 1993. (1)
10.21
1993 Alaska Intertie Project Participants Agreement by and among Alaska Power Authority, Municipality of Anchorage, the Registrant, City of Fairbanks, Alaska Municipal Utilities System, Golden Valley Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., City of Seward d/b/a Seward Electric System, Homer Electric Association, Inc. and Matanuska Electric Association, Inc. dated January 24, 1994. (11)
10.22
Amendment No. 1 to the 1993 Alaska Intertie Project Participants Agreement dated December 10, 1999. (11)
10.23
Grant Administration Agreement by and among the Registrant, Alaska Industrial Development and Export Authority, Golden Valley Electric Association, Inc., Fairbanks Municipal Utilities System, Anchorage Municipal Light & Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Homer Electric Association, Inc. and Matanuska Electric Association, Inc.) and City of Seward dated August 30, 1994. (11)
10.24
Bradley Lake Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated December 8, 1987. (1)
10.24.1
Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated June 30, 2003. (19)
10.25
Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 8, 1987. (1)
10.25.1
Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19)
10.26
Transmission Sharing Agreement by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power. (1)
10.27
Amendment to Agreement for Sale of Transmission Capability by and among the Registrant, Homer Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power dated March 7, 1989. (1)
10.28
Bradley Lake Hydroelectric Agreement for the Dispatch of Electric Power and for Related Services between the Registrant and the Alaska Energy Authority dated February 19, 1992. (1)
10.29
Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated September 29, 1992. (1)
10.29.1
Assignment of Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19)
10.30
Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated December 2, 1983. (1)
10.30.1
Addendum No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated August 8, 1984. (1)
10.30.2
Amendment No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated November 28, 1984. (1)
10.31
Gas Transportation Agreement by and among the Registrant, Alaska Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992. (1)
10.32
Eklutna Purchase Agreement by and among the Registrant, Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power and Alaska Power Administration. (1)
10.33
Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. (3)
10.34
Settlement Agreement by and among the Registrant, Homer Electric Association, Inc., Matanuska Electric Association, Inc., the City of Seward and Alaska Electric Generation and Transmission Cooperative, Inc., resolving G&T TIER Level, Equity Level, Capital Credits, Equity Management Plan and Loan Covenant Disputes, dated effective as of February 3, 1993. (1)
10.35
First Amendment to “Settlement Agreement Resolving G&T TIER Level, Equity Level, Capital Credits, Equity Management Plan and Loan Covenant Disputes” in APUC Docket U-92-10 between the Registrant, Matanuska Electric Association, Inc., Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated March 1993. (1)
10.36
Agreement by and among the Registrant, Municipality of Anchorage d/b/a Anchorage Municipal Light and Power, Matanuska Electric Association, Inc., U.S. Fish and Wildlife Service, National Marine Fisheries Service, Alaska Energy Authority and the State of Alaska re: the Eklutna and Snettisham Hydroelectric Projects. (1)
10.37
Daves Creek Substation Agreement between the Registrant and the Alaska Energy Authority dated March 13, 1992. (1)
10.38
Settlement Agreement between the Registrant and Intervenor Wholesale Customers in APUC Docket U-93-15 dated September 1993 regarding depreciation of submarine cables. (1)
10.39
Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated February 12, 1999. (8)
10.39.1
Second Amendment to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 1, 2001. (13)
10.39.2
Assignment of Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19)
10.39.3
Settlement of Dispute Over Nikiski Cogeneration Plant System Use and Dispatch Agreement and Premium Demand Charges Under HEA PSA between the Registrant and Alaska Electric and Energy Cooperative, Inc. and Homer Electric Association, Inc. dated January 15, 2008.
10.40
Lease Amendment between the Registrant and Standard Oil Company of California dated June 1, 1975. (1)
10.41
Lease Amendment between the Registrant and Chevron USA, Inc. dated September 1, 1985. (1)
10.42
First Amended and Restated Joint Action Agency Agreement Relating To The Alaska Railbelt Energy Authority among the Registrant, Anchorage Municipal Light & Power (AML&P) and Golden Valley Electric Association, Inc. (GVEA) dated August 1, 2005. (22)
10.44
Line of Credit Agreement and Promissory Note between the Registrant and the National Bank for Cooperatives dated May 5, 1993. (1)
10.44.1
Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated March 11, 1994. (1)
10.44.2
Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives and amended and restated Promissory Note dated April 18, 1994. (1)
10.44.3
Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated May 1, 1995. (1)
10.44.4
Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated May 15, 1995. (1)
10.44.5
Amendment to Line of Credit Agreement between the Registrant and CoBank, ACB dated September 30, 2000. (10)
10.44.6
Amendment to Line of Credit Agreement between the Registrant and CoBank, ACB dated December 27, 2002. (18)
10.44.7
Promissory Note and Consolidating Committed Resolving Credit Supplement between the Registrant and CoBank, ACB dated May 3, 2005. (22)
10.45.1
Master Loan Agreement between the Registrant and CoBank, ACB dated December 27, 2002. (17)
10.45.2
Promissory Note and Consolidating Term Loan Supplement between the Registrant and CoBank, ACB dated December 27, 2002. (17)
10.45.3
Master Loan Agreement between the Registrant and CoBank, ACB dated May 3, 2005 (22)
10.45.4
Promissory Note and Supplement between the Registrant and CoBank, ACB dated August 24, 2005. (23)
10.45.5
Amended and Restated Promissory Note and Committed Revolving Credit Supplement between the Registrant and CoBank, ACB dated September 12, 2006. (26)
10.45.6
Amended and Restated Promissory Note and Multiple Advance Term Loan Supplement between the Registrant and CoBank, ACB dated June 5, 2007. (30)
10.45.7
Amended and Restated Promissory Note and Committed Revolving Credit Supplement between the Registrant and CoBank, ACB dated October 10, 2007. (30)
10.47
Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 15, 2002. (17)
10.47.1
Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 17, 2007. (30)
10.52
Employment Agreement between the Registrant and Evan J. Griffith dated effective April 21, 2004. (20)
10.53
First Amended Memorandum of Agreement between the Registrant and William R. Stewart dated effective March 17, 2006. (24)
10.54
Employment Agreement between the Registrant and William R. Stewart dated effective July 1, 2006. (25)
10.55
Order accepting settlement agreements, amending procedural schedule, and permitting supplemental testimony and statement of commissioner Dave Harbour dissenting in part and concurring in part. (29)
10.56
Order On Offer Of Settlement And Issuing New License between the Registrant and the Federal Energy Regulatory Commission dated effective August 24, 2007.
10.57
Memorandum of Agreement between the Registrant and Bradley Evans dated effective December 6, 2007.
10.58
Agreement Covering Terms and Conditions of Employment for Beluga Power Plant Culinary Employees between the Registrant and the Hotel Employees & Restaurant Employees Union Local 878 dated effective December 13, 2007.
10.59
Agreement Covering Terms and Conditions of Employment for Office and Engineering Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective September 13, 2007.
10.60
Agreement Covering Terms and Conditions of Employment for Generation Plant Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective November 9, 2007.
10.61
Agreement Covering Terms and Conditions of Employment for Outside Plant Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective December 12, 2007.
10.62
Memorandum of Understanding Regarding Joint Development of South Anchorage Power Project between the Registrant and Anchorage Municipal Light and Power dated effective February 28, 2008.
Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. (21)
31.1
Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2
Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1
Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2
Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
Press release announcing plans to explore a possible merger or joint operations between the Registrant and Municipal Light & Power dated effective June 15, 2007. (28)
99.1
Press release announcing a panel recommendation that the Municipality of Anchorage and the registrant explore joint generation and operations dated effective February 8, 2008. (31)
(1) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1996.
(2) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 1997.
(3) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1997.
(4) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 1998.
(5) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1998.
(6) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1998.
(7) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 1999.
(8) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999.
(9) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2000.
(10) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2000.
(11) Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (File No. 333-57400) dated March 22, 2001.
(12) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2001.
(13) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2001.
(14) Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (File No. 333-75840) dated December 21, 2001.
(15) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2002.
(17) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2002.
(18) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2003.
(19) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003.
(20) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2004.
(21) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2004.
(22) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2005.
(23) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2005.
(24) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2005.
(25) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2006.
(26) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2006.
(27) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2007.
(28) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated June 21, 2007
(29) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2007.
(30) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2007.
(31) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated February 8, 2008.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on April 11, 2008.
CHUGACH ELECTRIC ASSOCIATION, INC.
By:
/s/ Bradley W. Evans
Bradley W. Evans, Interim Chief Executive Officer
Date:
April 11,
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on April 11, 2008, by the following persons on behalf of the registrant in the capacities indicated:
/s/ Bradley W. Evans
Bradley W. Evans
Interim Chief Executive Officer
(Principal Executive Officer)
/s/ Edward M. Jenkin
Edward M. Jenkin
Acting Sr. Vice President, Power Delivery
/s/ Michael R. Cunningham
Michael R. Cunningham
Chief Financial Officer
(Principal Financial Officer)
(Principal Accounting Officer)
/s/ Paul Risse
Paul Risse
Acting Sr. Vice President, Power Supply
/s/ Ronald K. Vecera
Ronald K. Vecera
Acting Sr. Vice President, Strategic Planning &
Corporate Affairs
/s/ Elizabeth Vazquez
Elizabeth Vazquez
Director & Chairman of the Board
/s/ Uwe Kalenka
Uwe Kalenka
Director & Vice-Chairman of the Board
/s/ P.J. Hill
P. J. Hill
Director & Treasurer of the Board
/s/ Alex Gimarc
Alex Gimarc
Director & Secretary of the Board
/s/ Jeffrey Lipscomb
Jeffrey Lipscomb
Director
/s/ James Nordlund
James Nordlund
Director
/s/ Rebecca Logan
Rebecca Logan
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 2007 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.