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, 2005:
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.
As of December 31, 2005, we had 63,329 members being served by approximately 76,800 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 2005, our wholesale power contracts, including the fuel component, produced $75.4 million in revenues, representing 34% of our total revenues and 45% of our total sales to customers.
MEA and HEA
We have two power sales contracts with Alaska Electric Generation & Transmission Cooperative, Inc., (AEG&T): one for firm, all-requirement sales to MEA and one for firm, partial- requirement sales to HEA. AEG&T is a generation and transmission cooperative that was formed by MEA and HEA in the mid 1980’s. Under each of these contracts, we sold power to AEG&T, for resale to MEA and HEA. On June 19, 2002, the RCA approved the request by Alaska Electric and Energy Cooperative, Inc. (AEEC) and AEG&T to Transfer Certificate of Public Convenience and Necessity No. 345 to serve as the power supplier of HEA to AEEC, instead of AEG&T. HEA is the sole member of AEEC. As part of this transaction our power sales agreement was assigned to AEEC and the Nikiski dispatch agreement was assigned to HEA with certain exceptions with the remaining rights and obligations under the Dispatch Agreement being assigned to AEEC. Management has not experienced a decline in revenue as a result of this transfer. Under our contracts, each of MEA and HEA is obligated to pay us for the power sold to AEG&T and AEEC even if AEG&T and AEEC do not pay.
Under the contract with AEG&T and MEA, MEA is obligated to purchase all of its electric power and energy requirements from us. MEA has the right, on advance notice 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
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the Agreement, as well as the desires and potential circumstances of all parties following the termination date. At that meeting and shortly thereafter by letter dated November 2, 2004, MEA communicated to Chugach that MEA does not desire to renew, extend or modify the Agreement. Further, MEA stated that it does not envision any type of firm power purchase arrangement with Chugach following expiration of the Agreement on December 31, 2014. MEA assured Chugach that it intends to continue to purchase power from Chugach in accordance with the Agreement through December 31, 2014.
During the past several years, we have had numerous disputes and engaged in substantial litigation with MEA regarding many aspects of our contractual relationship with it. For a discussion of material pending litigation between MEA and us, see “Legal Proceedings.”
Our contract for the benefit of HEA obligates HEA (through AEEC) to take or pay for 73 megawatts of capacity, and not less than 350,000 MWh per year. The HEA contract, as interpreted by the Alaska Public Utilities Commission (APUC), 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.
Seward
We currently provide nearly all the power needs of the City of Seward. In February 1998, we entered into a power sales agreement with Seward that allows us to interrupt service to Seward up to 12 times per year, not to exceed seventy-two cumulative hours annually and thereby reduces the demand charge by 1/3 (approximately $350,000 annually). This agreement was scheduled to expire January 31, 2006, however, Seward and Chugach jointly requested, and the RCA granted a four-month extension to May 31, 2006, of that contract to allow the parties to complete negotiations on a new contract.
The parties have reached an agreement with a nominal effective date of June 1, 2006, and expect in April of 2006 to file the proposed contract for RCA approval. The proposed contract does not become effective until it is approved by the RCA, however we do not expect any interruption of service to Seward pending RCA approval. The contract is a firm all-requirements/no reserves contract. Seward is supplying its own generation reserves to back its load. Chugach is obligated to meet all of Seward’s electric power supply needs and Seward is obligated to take all of its electric supply from Chugach when Chugach has sufficient capacity to meet those needs. The power supplied by Chugach is interruptible if Chugach does not have sufficient capacity to serve Seward after meeting the needs of its other non-interruptible loads, HEA, MEA and Chugach retail customers. In the ratemaking process, Seward will be allocated no reserve costs. The contribution
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to fixed costs will be approximately 23% more than Seward paid under the current contract based on a new demand rate of $8.14 per kW per month compared to the existing demand rate of $6.64 per kW per month. The contract is for five years with two automatic five-year extensions if no notice is given.
Economy Customers
Since 1988, we have sold economy (non-firm) energy to GVEA under an agreement that expires in 2008. Under the agreement, we use available generating capacity in excess of our own needs to produce electric energy for sale to GVEA, which uses that energy to serve its own loads in place of more expensive energy that it would otherwise generate itself or purchase from other sources. We purchased gas from Marathon Oil Company (Marathon) to produce energy for sale to GVEA, and we charge GVEA a rate sufficient to recover the gas cost, the costs of incremental operations and maintenance expense resulting from increased use of our generators for GVEA, and an agreed-upon margin for each kWh sold.
In 2000, the RCA approved an amendment to our agreement with GVEA and a settlement of an inter-utility dispute. As a result, the market for economy energy sold to GVEA has now been divided into two parts. The larger part continues to be governed by a contractual priority right under our agreement with GVEA. Under this 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 294,054 MWh, 206,451 MWh and 191,616 MWh for the years 2005, 2004 and 2003, 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
7
rate covenants contained in the instruments that govern our outstanding long-term indebtedness do not impose any greater TIER requirement than those previously approved by the RCA.
We expect to continue to recover changes in our fuel and purchased power expenses through routine fuel surcharge filings with the RCA. See“Management’s Discussion and Analysis - Results of Operations – Overview.”
The Amended and Restated Indenture, which became effective January 22, 2003, governs all of our outstanding bonds and requires us to set rates expected to yield margins for interest equal to at least 1.10 times total interest expense. The CoBank Master Loan Agreement also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. On February 6, 2003, we received Order U-01-108(26) from the RCA, based on our 2000 test year general rate case, that revised our overall TIER from 1.35 to 1.30. For the year ended December 31, 2005, our achieved TIER was 1.42.
Our Service Areas and Local Economy
Our service areas and those of our wholesale and economy energy customers are often described collectively as the Railbelt region of Alaska because the three geographic areas (the Southcentral, the Kenai Peninsula and the Interior) are linked by the Alaska Railroad.
Anchorage is located in the south central portion of Alaska and is the trade, service and financial center for most of Alaska and serves as a major center for many state governmental functions. Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, air and rail transportation facilities and headquarters support for the petroleum, mining and other basic industries located elsewhere in the state.
The Matanuska-Susitna Borough is immediately north of the Municipality of Anchorage, centered around the communities of Palmer and Wasilla. Although agriculture, tourism, mining and forestry are factors in the economy of the Matanuska-Susitna Borough, the economic well-being of the area is closely tied to that of Anchorage and many Matanuska-Susitna residents commute to jobs in Anchorage.
The Kenai Peninsula is south of Anchorage with an economy substantially independent of the Anchorage area. The most significant basic industry on the Kenai Peninsula is the production and processing of petroleum products from the Cook Inlet region. Agrium, a producer and marketer of agricultural nutrients and industrial products, located on the Kenai Peninsula, may cease operations due to a reduction in the supply of natural gas. If Agrium is unable to obtain favorably-priced additional natural gas, Agrium may be forced to cease production at the Kenai facility. This loss could have a negative affect on the economy of the Kenai Peninsula. Other important basic industries include tourism and fish harvesting and processing. Principal communities on the Kenai Peninsula are Homer, Seward, Kenai and Soldotna.
Fairbanks is the center of economic activity for the central part of the state (known as the Interior). Fairbanks (250 air miles north of Anchorage and about 400 air miles south of Alaska’s northern border) is Alaska’s second largest city. Economic activities in the Fairbanks region include federal and state government and military operations, the University of Alaska, tourism and
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support of natural resource development in the Interior and northern parts of the state. A major gold mine operates near Fairbanks; another is being developed. The Trans-Alaska Pipeline System (which transports crude oil) passes near Fairbanks on its route from the North Slope oilfield to Valdez. Alyeska Pipeline Company, which operates the Trans-Alaska oil pipeline from Prudhoe Bay to Valdez, has its main operations base in Fairbanks.
Load Forecasts
The following table sets forth our projected load forecasts for the next five years:
| | | | | | | | | | | | | | | | |
Load (MWh) | | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | |
| | |
| | |
| | |
| | |
| | |
| |
Retail | | | 1,237,652 | | | 1,251,813 | | | 1,260,927 | | | 1,261,672 | | | 1,262,455 | |
Wholesale | | | 1,263,548 | | | 1,273,498 | | | 1,307,035 | | | 1,317,822 | | | 1,342,902 | |
Economy | | | 335,733 | | | 165,000 | | | 165,000 | | | 100,000 | | | 100,000 | |
Losses | | | 174,447 | | | 183,136 | | | 185,450 | | | 183,217 | | | 184,360 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Total | | | 3,011,380 | | | 2,873,447 | | | 2,918,412 | | | 2,862,711 | | | 2,889,717 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Retail and wholesale sales are expected to increase over the next five years primarily due to economic growth resulting from increased federal and state spending. Our firm energy requirements are expected to grow at an average annual compounded rate of 1.2% from 2006 to 2010, retail sales at a rate of 0.8% and wholesale sales at a rate of 1.5%. Economy energy sales beyond 2006 are reduced to a historical planning average. It is difficult to forecast due to the uncertainty of fuel oil prices. Sales are further reduced in 2009 due to the expiration of the GVEA agreement in 2008. 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 would affect change in the sales forecast.
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 reflect current fuel cost and to recover under-recoveries and refund over-recoveries with a three-month lag. If Chugach were to materially under-recover fuel costs, we may seek an increase in the surcharge to recover those costs at the time of the next fuel surcharge filing. During periods of significant increases in natural gas prices such as occurred in 2004 and 2005, Chugach realizes a lag in the ability to reflect increases in fuel costs in its fuel and purchased power surcharge mechanism. As a result, cash flow may be impacted due to the lag in collection of fuel costs from customers. At December 31, 2005,
9
Chugach had under-recovered $1.8 million and at December 31, 2004, Chugach had over-recovered $2.7 million. 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 particularly 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 may 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.
Item 1B – Unresolved Staff Comments
None
Item 2 - Properties
General
We have 530 megawatts of installed capacity consisting of 17 generating units at five power plants. These include 385.0 megawatts of operating capacity at the Beluga facility on the west side of Cook Inlet; 67.5 megawatts of power at the Bernice Lake facility on the Kenai Peninsula; 46.7 megawatts of power at IGT in Anchorage; and 19.2 megawatts at the Cooper Lake facility, which is also on the Kenai Peninsula. We also own rights to 11.7 megawatts of capacity from the two Eklutna Hydroelectric Project generating units that we jointly own with MEA and AML&P. In addition to our own generation, we purchase power from the 126 megawatt Bradley Lake hydroelectric project owned by the Alaska Energy Authority (AEA) through Alaska Industrial Development and Export Authority. The Bradley Lake facility is operated by HEA and dispatched by us. The Beluga, Bernice Lake and International facilities are all fueled by natural gas. We own our offices and headquarters, located adjacent to IGT in Anchorage. We also lease warehouse space for some generation, transmission and distribution inventory (including a small amount of office space).
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Generation Assets
We own the land and improvements comprising our generating facilities at Beluga and IGT. We also own all improvements comprising our generating plant at Bernice Lake, located on land leased from HEA. The Bernice Lake ground lease expires in 2011. We are in the process of reviewing the lease. We have no reason to believe that we will not be able to renew the lease if desired.
The Cooper Lake Hydroelectric Project is partially located on federal land. The Project is operated pursuant to a major project license granted to us by the Federal Energy Regulatory Commission (FERC) in May 1957. The current license expires in 2007. 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. We anticipate that a new license will be issued in the first or second quarter of 2007. Until that time, we will continue operation of the Project pursuant to the existing license terms and conditions.
In 1997, we acquired a 30% interest in the Eklutna Hydroelectric Project. The plant is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October 1997.
Our principal generation units are Beluga 3, 5, 6, 7 and 8. These units have a combined capacity of 345.8 MW and meet most of our load. All other units are used principally as reserve. While the Beluga turbine-generators have been in service for many years, they have been maintained in good working order with periodic upgrades. Beluga Unit 3 had combustion inspections performed in 2003 and 2004, and a hot gas path inspection in 2005. Beluga Unit 5 also had combustion inspections in 2003 and 2004, and had a major inspection in 2005. Beluga Unit 6 had annual inspections in 2004 and 2005. Its first major inspection since the unit was re-powered in 2000 was performed in 2003. Its next major inspection will be performed in 2006. Beluga Unit 7 was re-powered in 2001 and had its first major inspection in 2004. An annual inspection was performed on that unit in 2005. Beluga Unit 8, a steam turbine, received routine annual inspections in 2003 and 2004, and a 25,000 hour inspection in 2005.
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The following matrix depicts nomenclature, run hours for 2005 and percentages of contribution and other historical information for all Chugach generation units.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Facility | | Commercial
Operation
Date | | | Nomenclature | | Rating
(MW)(1) | | Run Hours (2005) | | Percent of
Total Run
Hours | | Percent of
Time
Available | |
| |
| | |
| |
| |
| |
| |
| |
Beluga Power Plant(3) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
1 | | | | 1968 | | | | GE Frame 5 | | | | 19.6 | | | | | 437.9 | | | | | 0.8 | | | | | 95.9 | | |
2 | | | | 1968 | | | | GE Frame 5 | | | | 19.6 | | | | | 384.5 | | | | | 0.7 | | | | | 97.4 | | |
3 | | | | 1972 | | | | GE Frame 7 | | | | 64.8 | | | | | 6,657.2 | | | | | 12.3 | | | | | 82.8 | | |
5 | | | | 1975 | | | | GE Frame 7 | | | | 68.7 | | | | | 6,155.5 | | | | | 11.3 | | | | | 75.1 | | |
6 | | | | 1975 | | | | AP 11DM-EV | | | | 79.2 | | | | | 8,506.1 | | | | | 15.7 | | | | | 97.1 | | |
7 | | | | 1978 | | | | AP 11DM-EV | | | | 80.1 | | | | | 8,309.1 | | | | | 15.3 | | | | | 94.9 | | |
8 | | | | 1981 | | | | BBC DK021150(2) | | | | 53.0 | | | | | 7,901.2 | | | | | 14.5 | | | | | 91.1 | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 385.0 | | | | | | | | | | | | | | | | | |
Bernice Lake Power Plant | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2 | | | | 1971 | | | | GE Frame 5 | | | | 19.0 | | | | | 4.6 | | | | | 0.0 | | | | | 99.9 | | |
3 | | | | 1978 | | | | GE Frame 5 | | | | 26.0 | | | | | 1,286.4 | | | | | 2.4 | | | | | 83.9 | | |
4 | | | | 1981 | | | | GE Frame 5 | | | | 22.5 | | | | | 1,725.0 | | | | | 3.2 | | | | | 97.0 | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 67.5 | | | | | | | | | | | | | | | | | |
Cooper Lake Hydroelectric Plant | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
1 | | | | 1960 | | | | BBC MV 230/10 | | | | 9.6 | | | | | 6,174.1 | | | | | 11.4 | | | | | 83.6 | | |
2 | | | | 1960 | | | | BBC MV 230/10 | | | | 9.6 | | | | | 6,317.5 | | | | | 11.6 | | | | | 85.4 | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 19.2 | | | | | | | | | | | | | | | | | |
IGT Power Plant | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
1 | | | | 1964 | | | | GE Frame 5 | | | | 14.1 | | | | | 272.6 | | | | | 0.5 | | | | | 99.9 | | |
2 | | | | 1965 | | | | GE Frame 5 | | | | 14.1 | | | | | 165.0 | | | | | 0.3 | | | | | 85.7 | | |
3 | | | | 1969 | | | | Westinghouse 191G | | | | 18.5 | | | | | 42.2 | | | | | 0.1 | | | | | 94.4 | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 46.7 | | | | | | | | | | | | | | | | | |
Eklutna Hydroelectric Plant(4) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
1 | | | | 1955 | | | | Newport News | | | | 5.8 | | | | | N/A | (5) | | | | N/A | (5) | | | | 98.37 | | |
2 | | | | 1955 | | | | Oerlikon custom | | | | 5.9 | | | | | N/A | (5) | | | | N/A | (5) | | | | 98.17 | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | 11.7 | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
System Total | | | | | | | | | | | | 530.1 | | | | | 54,338.9 | | | | | 100.00 | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | |
| (1) | Capacity rating in MW at 30 degrees Fahrenheit. |
| | |
| (2) | Steam-turbine powered generator with heat provided by exhaust from natural-gas fueled Units 6 and 7 (combined-cycle). |
| | |
| (3) | Beluga Unit 4 and Bernice Lake Unit 1 were retired during 1994. |
| | |
| (4) | The Eklutna Hydroelectric Plant is jointly owned by Chugach, MEA and AML&P. The capacity shown is our 30% share of the plant’s output. |
| | |
| (5) | Because Eklutna Hydroelectric Plant 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 |
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Transmission and Distribution Assets
As of December 31, 2005, our transmission and distribution assets included 39 substations and 530 miles of transmission lines, which included 128 miles of leased transmission lines and Chugach’s share of the Eklutna transmission line, 925 miles of overhead distribution lines and 729 miles of underground distribution line. We own the land on which 20 of our substations are located and a portion of the right-of-way connecting our Beluga plant to Anchorage. As part of our 1997 acquisition of 30% of the Eklutna facility, we also acquired a partial interest in two substations and additional transmission facilities.
Many substations and a substantial number of our transmission and distribution rights-of-way are subject to federal or state permits and licenses. Under a federal license and a permit from the United States Forest Service, we operate the Quartz Creek transmission substation, substations at Hope, Summit Lake and Daves Creek, and transmission lines over all federal lands between Cooper Lake on the Kenai Peninsula and Anchorage. Long-term permits from the Alaska Division of Lands and the Alaska Railroad Corporation govern much of the rest of our transmission system outside the Anchorage area. Within the Anchorage area, we operate our University substation and several major transmission lines pursuant to long-term rights-of-way grants from the U.S. Department of the Interior, Bureau of Land Management, and transmission and distribution lines have been constructed across privately owned lands via easements and across public rights-of-way and waterways pursuant to authority granted by the appropriate governmental entity.
Title
Under the Amended and Restated Indenture, all of Chugach’s bonds are general unsecured and unsubordinated obligations. Chugach is prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on our properties and assets (other than those arising by operation of law) to secure the repayment of borrowed money or the obligation to pay the deferred purchase price of property unless we equally and ratably secure all bonds subject to the Amended and Restated Indenture, except that we may incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements.
Many of our properties are burdened by easements, plat restrictions, mineral reservation, water rights and similar title exceptions common to the area or customarily reserved in conveyances from federal or state governmental entities, and by additional minor title encumbrances and defects. We do not believe that any of these title defects will materially impair the use of our properties in the operation of our business.
Under the Alaska Electric and Telephone Cooperative Act, we possess the power of eminent domain for the purpose and in the manner provided by Alaska condemnation laws for acquiring private property for public use.
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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 insure system stability. We have a 30.4% (27.4 megawatts as currently operated) share in the Bradley Lake project’s output, and take Seward’s and MEA’s shares which we net bill to them, for a total of 45% of the project’s capacity. We are obligated to pay 30.4% of the annual project costs regardless of project output.
The project was financed and built by AEA through grants from the State of Alaska and the issuance of $166 million principal amount of revenue bonds supported by power sales agreements with six electric utilities that share the output from the facility (AML&P, HEA and MEA (through AEG&T and AEEC), GVEA, Seward and us). The participating utilities have entered into take-or-pay power sales agreements under which AEA has sold percentage shares of the project capacity and the utilities have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt-service costs and amounts required to maintain established reserves). By contract, we also provide transmission and related services to all of the participants in the Bradley Lake project.
The length of our Bradley Lake power sales agreement is fifty years from the date of commercial operation of the facility (September, 1991) or when the revenue bond principal is repaid, whichever is the longer. The agreement may be renewed for successive forty-year periods or for the useful life of the project, whichever is shorter. We believe that our maximum annual liability for our take-or-pay obligations is approximately $4.7 million. We believe that so long as this project produces power taken by us for our use that this expense will be recoverable through the fuel surcharge mechanism. The share of Bradley Lake indebtedness for which we are responsible is approximately $40 million. Upon the default of a participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs and output pro rata, to the extent necessary to compensate for the failure of the defaulting participant to pay its share, provided that no participant’s percentage share is increased by more than 25%.
Eklutna. We purchased a 30% undivided interest in the Eklutna Hydroelectric Project from the federal government in 1997. MEA also owns 17% of the Eklutna Hydroelectric Project. The power MEA purchases from the Eklutna Hydroelectric Project is pooled with our purchases and sold back to MEA to be used in meeting MEA’s overall power requirements. AML&P owns the remaining 53% undivided interest in the Eklutna Hydroelectric Project.
Fuel Supply
For 2005, 88% of our power was generated from gas, and 86% of that gas-fired generation took place at Beluga.
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Our primary sources of natural gas are the Beluga River Field producers (ConocoPhillips Alaska, Inc., AML&P, ChevronTexaco) and Marathon. ConocoPhillips, AML&P and ChevronTexaco each own one-third of the gas produced from the Beluga River Field and in 2005 provided approximately equal shares of the Beluga gas. We have approximately 258 billion cubic feet (BCF) of remaining gas committed to us from Marathon and the Beluga River Field producers (including Period 3 gas). We currently use approximately 25 BCF of natural gas per year for firm service. We estimate that our contract gas will last 7 to 12 years. Under almost all circumstances the deliverability supplied under our contracts is sufficient to meet all the needs of the Beluga Plant.
Beluga River Field Producers
We have similar requirements contracts with each of ConocoPhillips, AML&P and ChevronTexaco that were executed in April 1989, superseding contracts that had been in place since 1973. Each of the contracts with the Beluga River Field producers provides for delivery of gas on different terms in three different periods. Period 1 related to the delivery of gas previously committed by the respective producer under the 1973 contracts and ended in June 1996.
During Period 2, which began in June 1996 and continues until the earlier of the delivery of 180 BCF of natural gas or December 31, 2013, we are entitled to take delivery of up to 180 BCF of natural gas (60 BCF per Beluga River Field producer). During this period, we are required to take 60% of our total fuel requirements at Beluga from the three Beluga River Field producers, exclusive of gas purchased at Beluga under the Marathon contract for use in making sales to GVEA or certain other wholesale purchasers. The price for gas during this period under the ConocoPhillips and AML&P contracts is approximately 88% of the price of gas under the Marathon contract (described below) ($3.6037 per thousand cubic feet (MCF) on January 1, 2006), plus taxes. The price during this period under the ChevronTexaco contract is approximately 110% of the price of gas under the Marathon contract (described below) ($4.5046 per MCF on January 1, 2006), plus taxes.
During Period 3 under the Beluga River Field producers’ contracts, which begins on the earlier of December 31, 2013, or the end of Period 2, we may become entitled to take delivery of up to 120 BCF of natural gas (40 BCF per producer). Whether any gas will be taken in Period 3, and the price and take requirements with respect thereto, are to be determined in the future based upon then-current market conditions. Chugach is currently exploring sources for future supplies of natural gas.
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We have supplemental, annually renewable contracts with the Beluga River Field producers to supply supplemental gas (for peak periods of energy usage) if they have it available in excess of the amounts guaranteed in the basic contracts. The supplemental gas contracts raise the daily deliverability of gas from the Beluga River Field producers to an aggregate of 85,200 MCF per day. The base price of the gas under these contracts is the same as the base price under the Marathon contract (described below), plus taxes. ConocoPhillips has verbally indicated that it intends to terminate their supplemental gas contract. Chugach will explore ways to cover these needs in the future.
Marathon
We entered into a requirements contract with Marathon in September 1988 for an initial commitment of 215 BCF. The contract expires on the earlier of December 31, 2015, or the date on which Marathon has delivered to us a volume of gas in total, which equals or exceeds 215 BCF, which we currently expect to occur by mid-2010. The base price for gas under the Marathon contract is $1.35 per MCF, adjusted quarterly to reflect the percentage change between the preceding twelve-month period and a base period in the average closing prices of New York Mercantile Exchange (NYMEX) Light, Sweet Crude Oil Futures, the Producer Price Index for natural gas, and the Consumer Price Index for heating fuel oil. The price on January 1, 2006, exclusive of taxes, was $4.0951 per MCF.
Under the terms of the Marathon contract, Marathon generally provides the gas required for sales to GVEA, all of our requirements at Bernice Lake, International and Nikiski and 40% of the requirements at Beluga, not related to sales to GVEA. Marathon also has a right of first refusal to provide additional gas under any sales agreements that we may enter into with electric utilities we do not currently serve. The terms of the Marathon contract also gave Marathon a right to provide additional volumes in the period following depletion of the initial commitment of 215 BCF. On June 13, 2001, we were notified that Marathon will not commit to supply any additional volumes.
ENSTAR
We entered into a transportation agreement with ENSTAR Natural Gas Company (ENSTAR) in December 1992, whereby ENSTAR would transport our gas purchased from the Beluga River Field producers or Marathon on a firm basis to our International Power Plant at a transportation rate of $0.63 per MCF. In addition, ENSTAR agreed to transport gas on an interruptible basis for off-system sales at a rate of $0.29 per MCF. The agreement contains a minimum monthly bill of $2,600 for firm service. ENSTAR has initiated a process to provide transport services to Chugach, as well as other large users pursuant to price terms and conditions set out in a tariff. We do not expect that will result in price, terms and conditions significantly different from those in the contract.
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Environmental Matters
General
Chugach’s operations are subject to certain federal, state and local environmental laws and regulations, which seek to limit air, water and other pollution and regulate hazardous or toxic waste disposal. While we monitor these laws and regulations to ensure compliance, they frequently change and often become more restrictive. When this occurs, the costs of our compliance generally increase.
We include costs associated with environmental compliance in both our operating and capital budgets. We accrue for costs associated with environmental remediation obligations when those costs are probable and reasonably estimable. We do not anticipate that environmental related expenditures will have a material effect on our results of operations or financial condition. We cannot, however, predict the nature, extent or cost of new laws or regulations relating to environmental matters.
The Clean Air Act and Environmental Protection Agency (EPA) regulations under the act (the “Clean Air Act”) establish ambient air quality standards and limit the emission of many air pollutants. Some Clean Air Act programs that regulate electric utilities, notably the Title IV “acid rain” requirements, do not apply to facilities located in Alaska. The EPA’s anticipated regulations to limit mercury emissions from fossil-fired steam-electric generating facilities, are not expected to materially impact Chugach because our thermal power plants burn exclusively natural gas.
New Clean Air Act regulations impacting electric utilities may result from future events or may result from new regulatory programs that may be established to address problems such as global warming. While we cannot predict whether any new regulation would occur or its limitation, it is possible that new laws or regulations could increase our capital and operating costs. We have obtained or applied for all Clean Air Act permits currently required for the operation of our generating facilities, and we are not aware of any future requirements that will materially impact our financial condition.
Chugach is subject to numerous other environmental statutes including the Clean Water Act, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Endangered Species Act, and the Comprehensive Environmental Response, Compensation and Liability Act and to the regulations implementing these statutes. We do not believe that compliance with these statutes and regulations to date has had a material impact on our financial condition or results of operation. However, new laws or regulations, implementation of final regulations or changes in or new interpretations of these laws or regulations could result in significant additional capital or operating expenses.
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Item 3 - Legal Proceedings
Matanuska Electric Association, Inc., v. Chugach Electric Association, Inc., Superior Court Case No. 3AN-99-8152 Civil
In this action filed in 1999, Matanuska Electric Association, Inc. (MEA) alleged that Chugach breached the Power Sales Agreement under which Chugach is obligated to sell MEA power for 25 years, from 1989 through 2014. MEA asserted that Chugach failed to provide it certain information, failed to properly manage Chugach’s long-term debt, and failed to bring Chugach’s base rate action to a Joint Committee before presenting it to the Regulatory Commission of Alaska (RCA). All of MEA’s claims were dismissed by the Superior Court.
On April 29, 2002, MEA appealed to the Alaska Supreme Court the Superior Court’s dismissal of its claims related to Chugach’s financial management and Chugach’s decision not to bring its base rate action to the Joint Committee before filing with the RCA. Chugach cross-appealed the Superior Court’s decision not to also dismiss the financial management claim on jurisprudential and res judicata grounds. The Alaska Supreme Court, on October 8, 2004, issued an order upholding Chugach’s right to not bring its base rate action to the Joint Committee before filing with the RCA. But the Court rejected Chugach’s cross-appeal and reversed the Superior Court’s decision dismissing MEA’s financial management claim. The Supreme Court remanded that claim to the Superior Court for further proceedings.
On January 24, 2005, Chugach filed for summary judgment on that claim asserting that in the 2000 Test Year rate case the RCA had fully reviewed and decided the prudency of Chugach’s financial management. In a decision dated August 22, 2005, the Superior Court granted Chugach’s summary judgment motion, finding that the RCA had adjudicated the question of Chugach’s financial management and that its decision should be given res judicata effect. The Superior Court also found that the RCA had exercised its primary jurisdiction in reviewing Chugach’s financial management, and that its decision should be given deference.
The Superior Court entered final judgment on November 10, 2005, after which Chugach sought its costs and fees. On December 14, 2005, the Superior Court entered judgment awarding Chugach fees and costs from MEA in the amount of $104,732, which has not, as yet, been recorded in the financial statements.
On December 9, 2005, MEA appealed to the Alaska Supreme Court the Superior Court’s grant of summary judgment. On December 23, 2005, Chugach cross-appealed the Superior Court’s failure to also grant summary judgment based on the doctrine of collateral estoppel. This appeal is pending. Management is uncertain of the outcome of the proceeding before the Supreme Court. No reserves have been established for this matter.
Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc. Superior Court Case No. 3AN-04-11776 Civil
On October 12, 2004, MEA filed suit in Superior Court alleging that Chugach had violated its bylaws in allocating margins (capital credits) during the years 1998 through 2003. The margins
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Chugach earns each year are allocated to the customers who contributed them and are booked as capital credits to those customers’ accounts. Capital credits are eventually repatriated to customers at the discretion of the board of directors, typically many years after the margins are earned.
On February 17, 2006, MEA filed a Motion to File an Amended Complaint and an Amended Complaint in this case. The Amended Complaint is identical to MEA’s initial Complaint except for changes made to accommodate one new claim. The new claim challenges Chugach’s failure to provide MEA with a capital credit allocation for 2004. We expect the Court will allow MEA’s proposed amendment.
In this suit, MEA asks the Court to hold that Chugach breached its bylaws in the manner in which it allocated capital credits in 1998 through 2003 and if the Amended Complaint is allowed by the Court, through 2004. MEA also asks the court to enjoin Chugach to re-calculate MEA’s capital credits applying MEA’s interpretation of Chugach’s bylaws and in accordance with what MEA refers to as “generally accepted accounting practices for nonprofit cooperatives and cooperative principles”. The suit also seeks damages in an unspecified amount to compensate MEA for the alleged breach of contract. This matter currently is scheduled for a five-day trial beginning October 9, 2006. Management is vigorously defending against the claim. The ultimate resolution of this matter is not currently determinable.
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 – Submission of Matters to a Vote of Security Holders
Not Applicable
PART II
Item 5 - Market for Registrant’s
Common Equity and Related Stockholder Matters
Not Applicable
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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:
| | | | | | | | | | | | | | | | |
| | 2005 | | 2004 | | 2003 | | 2002 | | 2001 | |
| |
| |
| |
| |
| |
| |
Balance Sheet Data | | | | | | | | | | | | | | | | |
Plant, net: | | | | | | | | | | | | | | | | |
In service | | $ | 435,474,237 | | $ | 442,552,526 | | $ | 453,706,406 | | $ | 450,480,385 | | $ | 452,964,686 | |
| | | | | | | | | | | | | | | | |
Construction work in Progress | | | 32,505,401 | | | 25,278,388 | | | 16,560,438 | | | 20,224,302 | | | 28,887,008 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| | | | | | | | | | | | | | | | |
Electric plant, net | | | 467,979,638 | | | 467,830,914 | | | 470,266,844 | | | 470,704,687 | | | 481,851,694 | |
| | | | | | | | | | | | | | | | |
Other assets | | | 97,155,862 | | | 91,523,673 | | | 88,524,659 | | | 99,510,187 | | | 93,429,493 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| | | | | | | | | | | | | | | | |
Total assets | | $ | 565,135,500 | | $ | 559,354,587 | | $ | 558,791,503 | | $ | 570,214,874 | | $ | 575,281,187 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| | | | | | | | | | | | | | | | |
Capitalization: Long-term debt | | | 364,532,099 | | | 363,357,786 | | | 384,289,179 | | | 389,834,179 | | | 364,310,000 | |
| | | | | | | | | | | | | | | | |
Equities and margins | | | 145,039,152 | | | 138,998,799 | | | 134,216,122 | | | 127,477,895 | | | 131,808,706 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| | | | | | | | | | | | | | | | |
Total capitalization | | | 509,571,251 | | $ | 502,356,585 | | $ | 518,505,301 | | $ | 517,312,074 | | $ | 496,118,706 | |
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|
| |
|
| |
|
| |
|
| |
|
| |
| | | | | | | | | | | | | | | | |
Summary Operations Data | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Operating revenues | | $ | 225,697,349 | | $ | 201,246,615 | | $ | 184,032,413 | | $ | 171,944,918 | | $ | 178,595,214 | |
| | | | | | | | | | | | | | | | |
Operating expenses | | | 194,823,965 | | | 173,340,037 | | | 156,153,029 | | | 149,369,936 | | | 147,496,721 | |
| | | | | | | | | | | | | | | | |
Interest expense | | | 22,586,054 | | | 21,491,865 | | | 22,710,828 | | | 26,230,825 | | | 28,353,487 | |
| | | | | | | | | | | | | | | | |
Amortization of gain on refinancing | | | 0 | | | 0 | | | 0 | | | 188,082 | | | 1,123,973 | |
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|
| |
|
| |
|
| |
|
| |
|
| |
| | | | | | | | | | | | | | | | |
Net operating margins | | | 8,287,330 | | | 6,414,713 | | | 5,168,556 | | | (3,467,761 | ) | | 3,868,979 | |
| | | | | | | | | | | | | | | | |
Nonoperating margins | | | 1,227,401 | | | 1,187,743 | | | 1,084,564 | | | 1,451,611 | | | 1,670,157 | |
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|
| |
|
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|
| |
|
| |
|
| |
| | | | | | | | | | | | | | | | |
Assignable margins | | $ | 9,514,731 | | $ | 7,602,456 | | $ | 6,253,120 | | $ | (2,016,150 | ) | $ | 5,539,136 | |
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|
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|
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|
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Item 7 - Management’s Discussion and Analysis
of Financial Condition and Results of Operations
Caution Regarding Forward Looking Statements
Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. We undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this prospectus or the effect of those events or circumstances on any of the forward-looking statements contained herein, except as required by law.
Results of Operations
Overview
Margins. We operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation and principal and interest on our indebtedness and to provide for the establishment of reasonable margins and reserves. These amounts are referred to as “margins.” Patronage capital, the retained margins of our members, constitutes our principal equity.
Times Interest Earned Ratio (TIER). Alaska electric cooperatives generally set their rates on the basis of TIER. TIER is determined by dividing the sum of assignable margins plus long-term interest expense (excluding capitalized interest) by long-term interest expense (excluding capitalized interest). Chugach’s authorized TIER for rate-making purposes on a system basis is 1.30, which was ordered by the RCA in Order U-01-108(26). Generally, it is not possible to achieve the authorized TIER due to factors such as adjustments to the revenue requirement that eliminate certain ongoing costs and increases in the costs of operation that occur after the test year on which rates were based. Accordingly, we manage our business with a view toward achieving a TIER of 1.20 or greater. We achieved TIERs for the past five years as follows:
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Year | | | TIER | |
| | |
| |
2005 | | | 1.42 | |
2004 | | | 1.35 | |
2003 | | | 1.27 | |
2002 | | | 0.92 | * |
2001 | | | 1.20 | |
*The 2002 TIER was adversely affected by Order U-01-108(26) we received on February 6, 2003, from the RCA. See “Management’s Discussion and Analysis – Results of Operations – Overview – Rate Regulation and Rates.”
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Rate Regulation and Rates. Our rates are made up of two components: “base rates” and “fuel surcharge rates.” “Base rates” are composed of fixed and variable charges in connection with all components of providing electricity. “Fuel surcharge” rates take into account the rise and fall of fuel and purchased power costs and ensure collection of fuel and purchased power costs above the base component included in the base energy rate. The RCA approves the amounts paid by our wholesale and retail customers under base rates and approves the quarterly fuel surcharge filing authorizing rate changes in the fuel surcharge calculations. In addition, a Regulatory Cost Charge (RCC) is assessed on each retail customer invoice to fund Chugach’s share of the RCA’s budget. The RCC tax is revised annually by the RCA.
Base Rates.We recover operating and maintenance and other non-fuel and purchased power costs through our base rates established through an order of the RCA following a general rate case, where we propose a rate increase or decrease for each class of customer based on our costs to service those classes during a recent year referred to as a test year. The RCA may authorize, after a notice period, rate changes on an interim and refundable basis.
Docket U-01-108
Chugach filed a general rate case on July 10, 2001, based on the 2000 test year and subsequently implemented interim and refundable rate increases as approved by the RCA. In an updated filing on April 15, 2002, Chugach reduced its base rate increase request from 6.5% to 5.7%. Three wholesale customers and the Public Advocacy staff of the RCA participated in the rate case.
Order No. 26
On February 6, 2003, Chugach received Order U-01-108(26) (Order 26) from the RCA, which required a refund of revenues collected in 2001 and 2002 of approximately $7.1 million, which resulted in a net operating loss of approximately $2 million in 2002. Under the Order, Chugach’s financial performance for 2002 fell below the 1.10 level contained in the Rate Covenants in its currently effective indenture, the Amended and Restated Indenture, the CoBank Master Loan Agreement and the MBIA Insurance Corporation’s (MBIA) Reimbursement and Indemnity Agreement. (note 8)
In accordance with the Rate Covenant in the Amended and Restated Indenture, on February 13, 2003, Chugach filed a Motion with the RCA asking the RCA to stay the effect of Order 26 until after the RCA considered Chugach’s Petition for Reconsideration. On February 18, 2003, the RCA granted, in part, Chugach’s motion for stay. Chugach filed the Petition for Reconsideration with the RCA on February 28, 2003.
Order No. 30
On April 14, 2003, the RCA issued Order No. 30 in Docket U-01-108, significantly revising its earlier ruling. On April 28, 2003, Chugach submitted a revised revenue requirement and cost of service study in compliance with RCA Order No. 30. This order increased Chugach’s revenue requirement by $3.1 million and adjusted the required refund from $7.1 million to $1.9 million.
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Order No. 33
On August 26, 2003, the RCA issued Order No. 33 and accepted, in part, Chugach’s April 28, 2003, compliance filing.
Order No. 36
Effective November 7, 2003, the RCA approved Chugach’s compliance filing to Order 33 and final rates in this docket. As a result, and in relation to prior-approved permanent rates, Chugach’s rates on a system basis increased 0.07 percent, or an increase of 3.5 percent to retail customers and a decrease of 7.9 percent to wholesale customers.
The results of the RCA’s decision on final rates were implemented on November 10, 2003.
Appeal of RCA Orders
Chugach filed a timely appeal of RCA Orders Nos. 26, 30 and 33 to the Alaska Superior Court. In a November 25, 2004, decision, the Alaska Superior Court upheld all decisions of the RCA.
Provision For Rate Refund
At December 31, 2002, Chugach recorded a provision for rate refund of $7.1 million. On April 15, 2003, the RCA issued Order No. 30 in Docket U-01-108, significantly revising its earlier ruling in which $5.2 million of that provision was reversed. Between March and November of 2003, additional provisions were recorded in the amount of $3.8 million reflecting RCA decisions through Order No. 30, in addition to RCA orders that continued through the period. In October and November of 2003, Chugach’s wholesale customers were refunded $5.0 million. Between March 19 and April 19, 2004, Chugach issued refunds totaling $0.6 million to its Small General Service class for customer bills rendered between January 31 and November 10, 2003.
Docket No. U-04-102 (Revision to Current Depreciation Rates)
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 a net impact on 2004 depreciation expense of approximately $259 thousand, which, in aggregate, 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, however, Chugach 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.
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Order No. 2
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 August 8, 2005, Chugach filed a motion proposing an implementation plan.
Order No. 8
On September 21, 2005, the RCA issued Order No. 8 denying our motion and granting a motion filed by a wholesale customer of Chugach to enforce Order No. 2. Order No. 8 required that Chugach 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.
Order No. 9
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, to reflect new depreciation rates. In comparison to the old depreciation rates resulting from the last rate case (U-01-108), implementation of Order No. 9 increased depreciation expense for Generation & Transmission (G&T) plant of approximately $2.2 million, decreased depreciation expense for Distribution plant of approximately $1.2 million and decreased depreciation expense for General Plant of approximately $2.0 million. The overall impact to Chugach is an estimated decrease in annual depreciation expense of $1.0 million. No issues were raised in relation to the proposed Distribution depreciation adjustments. Because Chugach did not request changes to the electric rates charged to our customers based on the proposed new depreciation rates, there is no immediate electric rate impact. Wholesale customers MEA and HEA were active in the proceeding. MEA filed a motion for reconsideration of the effective date of January 1, 2005, for the changes to depreciation rates based on the RCA’s ruling. Management is uncertain of the outcome of the reconsideration motion.
Our base rate changes, excluding fuel surcharges, for retail and wholesale classes for the years 2003 through 2005 were as follows:
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Rate Class * | | | 2005 | | 2004 | | 2003 | |
| | |
| |
| |
| |
Retail | | | 0.00 | % | | 0.00 | % | | 0.24 | % | |
Wholesale: | | | | | | | | | | | |
HEA | | | 0.00 | % | | 0.00 | % | | (10.9 | %) | |
MEA | | | 0.00 | % | | 0.00 | % | | (12.4 | %) | |
SES | | | 0.00 | % | | 0.00 | % | | (9.9 | %) | |
* Rate changes shown are based on percent changes as applied to demand and energy rate levels.
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Base rate changes in 2003 were associated with Chugach’s 2000 test period general rate case discussed above.
Fuel Surcharge. We pass fuel and purchased power costs above base amounts included in the base rate directly to our wholesale and retail customers through the fuel surcharge mechanism. Changes in fuel and purchase power costs are primarily due to fuel price adjustment mechanisms in our gas-supply contracts based on natural gas, crude oil and fuel oil indexed price changes. We pass these costs directly to our retail and wholesale customers. The fuel surcharge is approved on a quarterly basis by the RCA. There are no limitations on the number or amount of fuel surcharge rate changes. Increases in our fuel and purchased power costs result in increased revenues while decreases in these costs result in lower revenues. Therefore, revenue from the fuel surcharge normally does not impact margins.
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Year ended December 31, 2005, compared to the years ended December 31, 2004, and 2003
Margins
Our margins for the years ended December 31 were as follows:
| | | | | | | | | | |
| | 2005 | | 2004 | | 2003 | |
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| |
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| |
|
Net Operating Margins | | $ | 8,287,330 | | $ | 6,414,713 | | $ | 5,168,556 | |
Nonoperating Margins | | $ | 1,227,401 | | $ | 1,187,743 | | $ | 1,084,564 | |
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Assignable Margins | | $ | 9,514,731 | | $ | 7,602,456 | | $ | 6,253,120 | |
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The increase in assignable margins in 2005 of $1.9 million, or 25%, was due primarily to increased sales and a decrease in transmission and administrative and general expense. The increase in assignable margins in 2004 of $1.3 million, or 22%, was due primarily to a decrease in interest expense caused by lower interest rates.
Nonoperating margins include interest income, AFUDC, capital credits and patronage capital allocations. Nonoperating margins did not materially change in 2005 from 2004. Nonoperating margins increased in 2004 from 2003 by $103,179, or 10%, due primarily to an increase in interest income caused by a higher than average cash balance during the year and higher interest rates.
Revenues
Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2005, operating revenues were $24.5 million, or 12%, higher than in 2004 due to increased sales and higher fuel costs recovered in revenue through the fuel surcharge mechanism. Retail sales did not significantly change from 2004, 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 increased due to increased job growth and continued state and federal spending, which generated additional economic activity, as well as higher fuel costs recovered in revenue through the fuel surcharge mechanism. Economy energy sales were $5.2 million, or 59%, higher in 2005 than in 2004 due to higher fuel prices. GVEA purchases power from Chugach when fuel oil prices are high because it is more economical for GVEA to purchase from Chugach, rather than generate its own.
In 2004, operating revenues were $17.2 million, or 9%, higher than in 2003 due to increased sales and higher fuel costs. With regard to retail revenues, the Municipality of Anchorage, our primary service area, continued to experience job growth during 2004. Additionally, increased state and federal spending generated additional general economic activity. These factors contributed to increased retail revenues. With regard to wholesale revenues, base rate revenue decreased in 2004 due to a decrease in the base rates charged to Chugach’s wholesale customers, however, actual sales to Chugach’s wholesale customers increased due to the same economic activity described above. Economy energy sales were $1.8 million, or 25%, higher in 2004 than in 2003 due to higher fuel prices.
26
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 $24, $24 and $26 million to Chugach’s fixed costs for the years ended December 31, 2005, 2004 and 2003, 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, 2005, 2004 and 2003.
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| | Base Rate Sales Revenue | Fuel and Purchased
Power Revenue | Total Revenue |
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| | 2005 | | 2004 | | | %
Variance | 2005 | | 2004 | | | %
Variance | 2005 | | 2004 | | | %
Variance |
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Retail | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Residential | | $ | 47.1 | | $ | 47.9 | | | (1.7 | %) | $ | 21.7 | | $ | 17.7 | | | 22.8 | % | $ | 68.8 | | $ | 65.6 | | | 5.0 | % |
Small Commercial | | $ | 8.4 | | $ | 8.3 | | | 1.0 | % | $ | 4.5 | | $ | 3.6 | | | 25.0 | % | $ | 12.9 | | $ | 11.9 | | | 8.3 | % |
Large Commercial | | $ | 29.3 | | $ | 29.3 | | | 0.0 | % | $ | 20.8 | | $ | 16.5 | | | 26.0 | % | $ | 50.1 | | $ | 45.8 | | | 9.4 | % |
Lighting | | $ | 1.3 | | $ | 1.3 | | | 0.0 | % | $ | 0.1 | | $ | 0.1 | | | 0.5 | % | $ | 1.4 | | $ | 1.4 | | | (0.1 | %) |
Total Retail | | $ | 86.1 | | $ | 86.8 | | | (0.7 | %) | $ | 47.1 | | $ | 37.9 | | | 24.3 | % | $ | 133.2 | | $ | 124.7 | | | 6.8 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Wholesale | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
HEA | | $ | 10.3 | | $ | 10.2 | | | 1.2 | % | $ | 18.4 | | $ | 14.6 | | | 26.1 | % | $ | 28.7 | | $ | 24.8 | | | 15.8 | % |
MEA | | $ | 18.3 | | $ | 17.3 | | | 5.7 | % | $ | 25.1 | | $ | 19.8 | | | 26.3 | % | $ | 43.4 | | $ | 37.1 | | | 17.0 | % |
SES | | $ | 1.0 | | $ | 1.0 | | | 2.3 | % | $ | 2.3 | | $ | 1.9 | | | 23.5 | % | $ | 3.3 | | $ | 2.9 | | | 16.1 | % |
Total Wholesale | | $ | 29.6 | | $ | 28.5 | | | 3.6 | % | $ | 45.8 | | $ | 36.3 | | | 26.3 | % | $ | 75.4 | | $ | 64.8 | | | 16.3 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Economy Sales | | $ | 4.4 | | $ | 3.0 | | | 44.9 | % | $ | 9.7 | | $ | 5.9 | | | 66.2 | % | $ | 14.1 | | $ | 8.9 | | | 59.0 | % |
Miscellaneous | | $ | 3.0 | | $ | 2.8 | | | 6.4 | % | $ | 0.0 | | $ | 0.0 | | | n/a | | $ | 3.0 | | $ | 2.8 | | | 6.4 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Revenue | | $ | 123.1 | | $ | 121.1 | | | 1.6 | % | $ | 102.6 | | $ | 80.1 | | | 28.0 | % | $ | 225.7 | | $ | 201.2 | | | 12.1 | % |
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, 2004, and 2003.
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| | Base Rate Sales Revenue | | Fuel and Purchased Power Revenue | | Total Revenue | |
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| | 2004 | | 2003 | | %
Variance | | 2004 | | 2003 | | %
Variance | | 2004 | | 2003 | | %
Variance | |
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Retail | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Residential | | $ | 47.9 | | $ | 47.5 | | 0.8 | % | | $ | 17.7 | | $ | 14.2 | | 24.6 | % | | $ | 65.6 | | $ | 61.7 | | 6.4 | % | |
Small Commercial | | $ | 8.3 | | $ | 7.4 | | 12.2 | % | | $ | 3.6 | | $ | 2.6 | | 38.5 | % | | $ | 11.9 | | $ | 10.0 | | 18.7 | % | |
Large Commercial | | $ | 29.3 | | $ | 29.1 | | 0.7 | % | | $ | 16.5 | | $ | 13.6 | | 21.3 | % | | $ | 45.8 | | $ | 42.7 | | 7.2 | % | |
Lighting | | $ | 1.3 | | $ | 1.3 | | 0.0 | % | | $ | 0.1 | | $ | 0.1 | | 0.0 | % | | $ | 1.4 | | $ | 1.4 | | 0.0 | % | |
Total Retail | | $ | 86.8 | | $ | 85.3 | | 1.8 | % | | $ | 37.9 | | $ | 30.5 | | 24.3 | % | | $ | 124.7 | | $ | 115.8 | | 7.7 | % | |
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Wholesale | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
HEA | | $ | 10.2 | | $ | 10.9 | | (6.4 | %) | | $ | 14.6 | | $ | 10.7 | | 36.4 | % | | $ | 24.8 | | $ | 21.6 | | 14.8 | % | |
MEA | | $ | 17.3 | | $ | 18.9 | | (8.7 | %) | | $ | 19.8 | | $ | 15.3 | | 29.4 | % | | $ | 37.1 | | $ | 34.2 | | 8.6 | % | |
SES | | $ | 1.0 | | $ | 1.0 | | 0.0 | % | | $ | 1.9 | | $ | 1.5 | | 26.6 | % | | $ | 2.9 | | $ | 2.5 | | 14.7 | % | |
Total Wholesale | | $ | 28.5 | | $ | 30.8 | | (7.5 | %) | | $ | 36.3 | | $ | 27.5 | | 32.0 | % | | $ | 64.8 | | $ | 58.3 | | 11.1 | % | |
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Economy Sales | | $ | 3.0 | | $ | 7.1 | | (57.7 | %) | | $ | 5.9 | | $ | 0.0 | | n/a | | | $ | 8.9 | | $ | 7.1 | | 25.4 | % | |
Miscellaneous | | $ | 2.8 | | $ | 2.8 | | 0.0 | % | | $ | 0.0 | | $ | 0.0 | | n/a | | | $ | 2.8 | | $ | 2.8 | | 0.0 | % | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Revenue | | $ | 121.1 | | $ | 126.0 | | (3.8 | %) | | $ | 80.1 | | $ | 58.0 | | 38.1 | % | | $ | 201.2 | | $ | 184.0 | | 9.3 | % | |
27
The major components of our operating revenue for the year ending December 31 were as follows:
| | | | | | | | | | | | | | | | | | | |
| | 2005 | | 2005 | | 2004 | | 2004 | | 2003 | | 2003 | |
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| | Sales (kWh) | | Revenue | | Sales (kWh) | | Revenue | | Sales (kWh) | | Revenue | |
| | | | | | | | | | | | | | | | | | | |
Retail | | | 1,216,808 | | $ | 133,180,178 | | | 1,225,049 | | $ | 124,736,765 | | | 1,176,587 | | $ | 115,717,488 | |
Wholesale | | | | | | | | | | | | | | | | | | | |
HEA | | | 499,510 | | | 28,718,393 | | | 477,256 | | | 24,790,344 | | | 448,029 | | | 21,733,244 | |
MEA | | | 688,885 | | | 43,363,549 | | | 658,208 | | | 37,164,894 | | | 620,164 | | | 34,205,260 | |
Seward | | | 63,353 | | | 3,309,570 | | | 62,176 | | | 2,850,001 | | | 60,966 | | | 2,461,200 | |
Economy energy | | | 294,129 | | | 14,101,797 | | | 206,835 | | | 8,867,625 | | | 191,616 | | | 7,112,276 | |
Other | | | N/A | | | 3,023,862 | | | N/A | | | 2,836,986 | | | N/A | | | 2,802,945 | |
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Total revenue | | | 2,762,685 | | $ | 225,697,349 | | | 2,629,524 | | $ | 201,246,615 | | | 2,497,362 | | $ | 184,032,413 | |
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We make economy sales to GVEA. These sales commenced in 1988 and have contributed to our growth in operating revenues. We do not take such economy sales into consideration in our long-range resource planning process because these sales are non-firm sales that depend on GVEA’s need for additional energy and our available generating capacity at the time. In 2005, 2004, and 2003, economy sales to GVEA constituted approximately 6.0%, 5.0%, and 4.0%, respectively, of our sales revenues. The increase in economy sales in 2005 from 2004 and in 2004 from 2003 was due to GVEA’s higher fuel costs than Chugach’s, which made it more economical for GVEA to purchase power from Chugach rather than generate its own.
Expenses
The major components of our operating expenses for the years ended December 31 were as follows:
| | | | | | | | | | | |
| | | 2005 | | 2004 | | 2003 | |
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| Fuel | | $ | 84,776,131 | | $ | 64,113,474 | | $ | 48,667,262 | |
| Power production | | | 15,005,786 | | | 15,378,858 | | | 13,961,565 | |
| Purchased power | | | 23,664,412 | | | 20,579,992 | | | 18,244,921 | |
| Transmission | | | 5,847,648 | | | 6,526,684 | | | 4,511,002 | |
| Distribution | | | 11,780,502 | | | 11,723,316 | | | 10,866,251 | |
| Consumer accounts | | | 5,227,478 | | | 5,308,353 | | | 5,589,788 | |
| Administrative, general and other | | | 20,272,291 | | | 21,719,908 | | | 26,520,189 | |
| Depreciation | | | 28,249,717 | | | 27,989,452 | | | 27,792,051 | |
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| Total operating expenses | | $ | 194,823,965 | | $ | 173,340,037 | | $ | 156,153,029 | |
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Fuel
Chugach recognizes actual fuel expense. Fuel expense increased by $20.7 million, or 32%, in 2005 from 2004 due to higher fuel prices as well as higher fuel volume purchases. In 2005, Chugach used 26,728,140 MCF of fuel at an average effective price of $3.50 per MCF. Fuel expense increased by $15.4 million, or 32%, in 2004 from 2003 due to the same reasons discussed above. In 2004, Chugach used 25,024,954 MCF of fuel at an average effective price of $2.56 per MCF. In 2003, Chugach used 23,402,981 MCF of fuel at an average effective price of $2.27 per MCF.
Power Production
Power production expense did not materially change in 2005 from 2004. Power production expense increased by $1.4 million, or 10%, in 2004 from 2003 due, in part, to the assignment of maintenance costs among various departments to more accurately reflect the costs in the proper functional area. The increase was also due to higher material and professional services costs associated with scheduled maintenance and inspections on multiple units at Beluga. In addition, labor costs in 2003 were unusually low as a result of reduced overtime and hiring constraints.
Purchased Power
Purchased power costs increased by $3.1 million, or 15%, in 2005 from 2004 due to higher fuel costs. In 2005, Chugach purchased 560,376 MWH of energy at an average effective price of 4.03 cents per kWh. Purchased power costs increased by $2.3 million, or 12.8%, in 2004 from 2003 due to higher fuel costs and increased sales. In 2004, Chugach purchased 581,103 MWH of energy at an average effective price of 3.36 cents per kWh. In 2003, Chugach purchased 554,706 MWH of energy at an average effective price of 3.09 cents per kWh.
Transmission
Transmission expense decreased $679.0 thousand, or 10%, in 2005 from 2004 due to a decrease in transmission substation maintenance performed in 2005. Transmission expense increased by $2.0 million, or 45%, in 2004 from 2003 due to increased transmission substation maintenance being performed in 2004. In addition, the increase was also due to the assignment of maintenance costs discussed under Power Production.
Distribution
Distribution expense did not materially change in 2005 from 2004. Distribution expense increased $857 thousand, or 8%, in 2004 from 2003 due to the assignment of maintenance costs discussed under Power Production.
Consumer Accounts
Consumer accounts expense did not materially change in 2005 from 2004. Consumer accounts expense decreased by $281 thousand, or 5%, in 2004 from 2003 due to the recovery of
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previously recorded bad debt expense through capital credits.
Administrative, General and Other
Administrative, general and other expenses decreased $1.4 million, or 7%, in 2005 from 2004 due primarily to a $463.2 thousand decrease in labor due to several vacant positions and an $851.6 thousand decrease in workers compensation claims charged to the administrative, general and other expense category and a $241.9 thousand decrease in property insurance, due in part to a membership credit Chugach received upon renewal. These decreases, however, were offset by a $419.2 thousand increase in Operations and technical support and legal professional services. Operations and technical support’s increase was due to network security, testing and benchmarking expenses and Legal’s professional services increase was due to expenses associated with labor relations, the Joint Action Agency and the 2002 Depreciation study. Administrative, general and other expenses decreased by $4.8 million, or 18%, in 2004 from 2003 due to the $1.8 million write down of an impaired asset and the $965 thousand write-off of several studies in 2003 not recurring in 2004. The decrease is also due to $1.9 million associated with the aforementioned assignment of maintenance costs, as well as $1.6 million associated with the completion of the amortization of a large portion of the Year 2000 (Y2K) software costs. These decreases, however, were offset by $594 thousand associated with a performance incentive program in place at the time and $457 thousand associated with the write-off of obsolete inventory and cancelled projects.
Depreciation
We use remaining life rates set forth in the most recent depreciation study. In 2003 an update of the 1999 Depreciation Study was completed utilizing Electric Plant in Service balances as of December 31, 2002. The RCA approved the study with certain changes to the proposed depreciation rates. Chugach revised its depreciation rates effective January 1, 2005, to reflect the new depreciation rates. The impact on Chugach’s financial statements to depreciation expense was a decrease of $1.0 million, however, this was offset by the increase in depreciation expense due to the closeout of several projects. Therefore, depreciation expense did not vary materially in 2005 from 2004. Depreciation expense did not vary materially in 2004 from 2003.
Interest
Interest on long-term obligations increased by $1.4 million, or 6%, in 2005 from 2004 due to higher variable interest rates. Interest on long-term obligations decreased by $1.1 million, or 5%, in 2004 from 2003 due to lower interest rates.
Interest on short-term borrowing increased $46.6 thousand, or 100%, in 2005 from 2004 due to the use of the line of credit in the first quarter of 2005. Interest on short-term borrowing decreased by $11.9 thousand, or 100%, in 2004 from 2003 due to the line of credit not being utilized during 2004.
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Interest charged to construction increased by $352.4 thousand, or 72%, in 2005 from 2004 due to a higher average balance in Construction Work in Progress (CWIP) caused by the continued construction of the South Anchorage Substation project. Interest charged to construction increased by $81.2 thousand, or 20%, in 2004 from 2003 due to a higher average balance in Construction Work in Progress (CWIP) caused by the South Anchorage Substation project and the new 138kV transmission line being built between the International substation and the South Anchorage Substation. Net interest expense includes interest on long-term obligations and short-term obligations, reduced by interest charged to construction.
Patronage Capital (Equity)
The following table summarizes our patronage capital and total equity position for the years ended December 31:
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| | 2005 | | 2004 | | 2003 | |
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Patronage capital at beginning of year | | $ | 130,750,269 | | $ | 126,341,413 | | $ | 120,148,502 | |
Retirement of capital credits and estate payments, including discounted capital credits | | | (4,079,622 | ) | | (3,193,600 | ) | | (60,209 | ) |
Assignable margins | | | 9,514,731 | | | 7,602,456 | | | 6,253,120 | |
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Patronage capital at end of year | | | 136,185,378 | | | 130,750,269 | | | 126,341,413 | |
Other equity* | | | 8,853,774 | | | 8,248,530 | | | 7,874,709 | |
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Total equity at end of year | | $ | 145,039,152 | | $ | 138,998,799 | | $ | 134,216,122 | |
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* Other equity includes memberships, donated capital and gain on capital credit retirements.
We credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves. These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of distributions of these amounts to members, also known as capital credits, is at the discretion of our Board of Directors. We currently have a practice of retiring patronage capital on a first-in, first-out basis for retail customers. The Board of Directors may also return capital credits to former members and estates who have requested early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002. In 2005, the Board of Directors authorized the retirement of $3,801,228 of retail patronage for 1986 and 1987. In 2004 The Board of Directors also authorized $500,000 for capital credit payments to those former members and estates who requested early retirements at discounted rates to be distributed in 2005. The retirement of $3,801,228 included discounted estate payments in the amount of $394,520. In addition, Chugach retained $282,479, which represented discounted capital credits transferred to other equities and margins under the discounted capital credit retirement program. In 2004, the Board of Directors authorized the retirement of $3,126,560 of retail patronage for 1985 and 1986. The Board of Directors also, in 2004, authorized $125,000 for capital credits payments under the discounted capital credit retirement plan. In 2004, the retirement of $3,126,560 included discounted estate payments in the amount of $55,639. In addition, Chugach retained $65,990, which represented discounted capital credits transferred to other equities and margins under the discounted capital credit
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retirement program. In 2003, the Board of Directors was unable to authorize a capital credit retirement due to covenant restrictions contained in the Amended and Restated Indenture. Prior to 2000, wholesale capital credits had been retired on a 10-year cycle pursuant to an approved capital credit retirement program, which was contained in the Chugach business plan. However, in 2000 we implemented a plan to return the capital credits of wholesale and retail customers on a 15-year rotation.
The Amended and Restated Indenture prohibits us from making any distributions, payment or retirement of patronage capital to our customers if an event of default under the Amended and Restated Indenture exists. Otherwise, we may make distributions to our members in each year equal to the lesser of 5% of our patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, our aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of our total liabilities and equities and margins.
Under our Master Loan Agreement with CoBank, we also may not declare or pay any dividend or make any distributions to members or retirements of patronage capital if, giving effect to such distribution an event of default under the Master Loan Agreement exists, or our equities and margins as of the end of our most recent fiscal quarter would be less than thirty percent (30%) of the sum of our total long-term debt plus equities and margins at that time. However, as long as no event of default exists under the Master Loan Agreement with CoBank and the ratio of our equities and margins to the sum of total long-term debt plus equities and margins would not be less than 22%, we may make a distribution of up to the lesser of five percent (5%) of our aggregate equities and margins as of the end of the immediately preceding fiscal year or fifty percent (50%) of the prior fiscal year’s margins.
The table below sets forth a five-year summary of anticipated capital credit retirements based on 50% of prior year’s margins retirement criteria:
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Year Ending | | Total | |
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2006 | | $ | 3,900,000 | |
2007 | | | 6,000,000 | |
2008 | | | 5,500,000 | |
2009 | | | 5,000,000 | |
2010 | | | 3,500,000 | |
Changes in Financial Condition
Assets
Total assets increased $5.8 million, or 1%, from December 31, 2004, to December 31, 2005. The net increase was due to a $3.7 million, or 16% increase in accounts receivable due to higher fuel costs and increased sales to GVEA. The increase was also due to a $1.8 million, or 100%, increase in fuel cost under-recovery caused by the under collection of fuel and purchased power costs through the fuel surcharge mechanism. The increase was also due to a $1.0 million, or 124%, increase in prepayments caused by the timing of the payments for insurance renewals.
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The increases were offset by a $1.3 million, or 6%, decrease in deferred charges caused by the amortization of deferred projects in excess of additions to the Cooper Lake Relicensing project.
Liabilities and Equities
Changes in total liabilities and equities include a $6.0 million, or 4%, increase in total equities and margins due to margins, net of capital credit retirements, in 2005 and a $5.2 million, or 40%, increase in fuel payable due to higher fuel prices. Other current liabilities also increased $1.6 million, or 114%, due to a $525.1 thousand increase in patronage capital payable caused by the capital credit retirement in 2005, as well as a $1.1 million state and municipal underground compliance charge on retail revenue that was implemented June 1, 2005. Total long-term obligations also increased $1.2 million, or .3% caused by the refinancing of CoBank 2, which reclassified the majority of CoBank 2 to long-term obligations from current installments of long-term obligations. Accounts payable also increased $1.7 million, or 22%, caused primarily by capital expenditures for phase 3 of the South Anchorage Substation project. The increases were offset by a $7.6 million, or 48% decrease in current installments of long-term obligations caused by the refinancing of CoBank 2 mentioned above, as well as a $2.7 million, or 100% decrease in fuel cost over-recovery due to the under collection of the previous quarter’s fuel cost through the fuel surcharge mechanism.
Inflation
We do not believe that inflation has a significant effect on our operations.
Contractual Obligations and Commercial Commitments
The following are Chugach’s contractual and commercial commitments as of December 31, 2005:
Contractual cash obligations: (In thousands)
Payments Due By Period
| | | | | | | | | | | | | | | | |
| | Total | | 2006 | | 2007-2008 | | 2009-2010 | | Thereafter | |
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Long-term debt | | $ | 372,858 | | $ | 8,326 | | $ | 22,969 | | $ | 19,561 | | $ | 322,002 | |
Short-term debt1 | | | 0 | | | 0 | | | 0 | | | 0 | | | 0 | |
Bradley Lake2 | | | 16,000 | | | 4,000 | | | 4,000 | | | 4,000 | | | 4,000 | |
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Total | | $ | 388,858 | | $ | 12,326 | | $ | 26,969 | | $ | 23,561 | | $ | 326,002 | |
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Commercial Commitments: (In thousands)
| | | | | | | | | | | | | | | | |
| | Amount of Commitment
Expiration Per Period | |
| | Total | | 2006 | | 2007-2008 | | 2009-2010 | | Thereafter | |
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Lines of credit-available * | | | $58 | | | $58 | | | $0 | | | $0 | | | $0 | |
1At December 31, 2005, Chugach had $58 million in lines of credit available with various financial institutions, which fund capital requirements. At December 31, 2005, there was no outstanding balance on the lines of credit, therefore, the available borrowing capacity under these lines of credit was $58 million.
2Estimated annual costs
Purchase obligations:
Chugach is a participant and has a 30.4% share in the Bradley Lake hydroelectric project (See “Item 2-Properties-Other Property-Bradley Lake.”) This contract runs through 2041. We have agreed to pay a like percentage of annual costs of the project, which has averaged $4 million over the past five years. We believe these costs, adjusted for inflation, reasonably reflect anticipated future project costs.
Our primary sources of natural gas are the Beluga River Field producers and Marathon Oil Company (See “Item 2-Properties-Fuel Supply-Beluga River Field Producers/Marathon.”) We have contracts with each of these producers with varying expiration dates that generally require us to purchase from them all of our fuel requirements for our Beluga plant. The current phase of these contracts expires in December 2013. Our fuel costs vary due to the impact of the energy future indices used to index the price of fuel and are inherently difficult to predict. We pass fuel costs directly to our wholesale and retail customers through the fuel surcharge mechanism (See “Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Fuel Surcharge.”)
Liquidity And Capital Resources
We satisfy our operational and capital cash requirements primarily through internally generated funds, a $50 million line of credit from National Rural Utilities Cooperative Finance Corporation (NRUCFC), which was renewed for a five-year term on October 15, 2002, and a $7.5 million line of credit with CoBank, ACB (CoBank), which expires October 31, 2006, subject to renewal at the discretion of the parties. Chugach had maintained a $20 million line of credit with CoBank. On October 27, 2005, Chugach reduced the line of credit to $7.5 million due to a decrease in short-term borrowing projections. At December 31, 2005, there was no outstanding balance with CFC or CoBank, however the CoBank line was utilized in the first quarter of 2005.
34
Principal maturities and sinking fund payments of our outstanding indebtedness at December 31, 2005 are set forth below:
| | | | | | | | | | |
Year Ending
December 31 | | Sinking Fund Requirements | | Principal maturities | | Total | |
| |
| |
| |
| |
| | | | | | | |
2006 | | | 5,200,000 | | | 3,125,687 | | $ | 8,325,687 | |
2007 | | | 5,500,000 | | | 8,228,569 | | | 13,728,569 | |
2008 | | | 5,900,000 | | | 3,340,725 | | | 9,240,725 | |
2009 | | | 6,300,000 | | | 3,463,358 | | | 9,763,358 | |
2010 | | | 6,700,000 | | | 3,097,157 | | | 9,797,157 | |
Thereafter | | | 286,600,000 | | | 35,402,290 | | | 322,002,290 | |
| |
|
| |
|
| |
|
| |
| | $ | 316,200,000 | | $ | 56,657,786 | | $ | 372,857,786 | |
| |
|
| |
|
| |
|
| |
During 2005 we spent approximately $27.5 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 2006 through 2010 as contained in the Capital Improvement Plan (CIP), which was approved on March 22, 2006:
| |
2006 | $30.8 million |
2007 | $32.6 million |
2008 | $97.5 million |
2009 | $74.3 million |
2010 | $64.5 million |
We expect that cash flows from operations and external funding sources will be sufficient to cover operational and capital funding requirements in 2006, however, additional borrowing will be required thereafter to fund a new 130MW generating unit which is forecasted to begin construction in 2007 and continue through 2010.
Ratings
Our bond ratings with Moody’s Investors Service and Fitch Investor Service remained unchanged in 2005, however, on December 23, 2005, Standard & Poors Ratings Services affirmed its ‘A-’ issuer credit rating and revised its rating outlook to stable from negative.
35
Off-Balance Sheet Arrangements
We have not created, and are not party to, any special-purpose or off-balance-sheet entities for the purpose of raising capital, incurring debt or operating parts of our business that are not consolidated into our financial statements. We do not have any arrangements or relationships with entities that are not consolidated into our financial statements that are reasonably likely to materially affect our liquidity or the availability of our capital resources.
Critical Accounting Policies
Our accounting and reporting policies comply with accounting principles generally accepted in the United States of America. The preparation of financial statements in conformity with Generally Accepted Accounting Principles (GAAP) requires that management apply accounting policies and make estimates and assumptions that affect results of operations and reported amounts of assets and liabilities in the financial statements. Significant accounting policies are described in Note 1 to the financial statements (See“Financial Statements and Supplementary Data.”). Critical accounting policies are those policies that management believes are the most important to the portrayal of Chugach’s financial condition and results of its operations, and require management’s most difficult, subjective, or complex judgments, often as a result of the need to make estimates about matters that are inherently uncertain. Most accounting policies are not considered by management to be critical accounting policies. Several factors are considered in determining whether or not a policy is critical in the preparation of financial statements. These factors include, among other things, whether the estimates are significant to the financial statements, the nature of the estimates, the ability to readily validate the estimates with other information including third parties or available prices, and sensitivity of the estimates to changes in economic conditions and whether alternative accounting methods may be utilized under accounting principles general accepted in the United States of America. For all of these policies management cautions that future events rarely develop exactly as forecast, and the best estimates routinely require adjustment. Management has discussed the development and the selection of critical accounting policies with Chugach’s Audit Committee. The following policies are considered to be critical accounting policies for the year ended December 31, 2005.
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
36
costs such as depreciation and pension and post-retirement benefits have less of a direct impact on Chugach’s results of operations than they would on a non-regulated company. As reflected in Note 1 to the financial statements under “Deferred Charges and Credits”, significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislation and judicial or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact Chugach’s financial statements.
Critical estimates also include provision for rate refunds and allowance for doubtful accounts. Actual results could differ from those estimates.
New Accounting Standards
FASB Interpretation No. 47 (FIN 47) “Accounting for Conditional Asset Retirement Obligations”
In March, 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). FIN 47, effective for fiscal years ending after December 15, 2005, is an interpretation of FASB Statement No. 143, Accounting for Asset Retirement Obligations (Statement 143). FIN 47 Interpretation clarifies that conditional obligations meet the definition of an asset-retirement obligation in Statement 143 and therefore should be recognized if their fair value is reasonably estimable. It also provides additional guidance to evaluate whether fair value is reasonably estimable. Chugach evaluated the provisions of FIN 47 and implemented the Interpretation effective January 1, 2005. The implementation of the statement had no significant impact on the financial statements.
SFAS 154“Accounting Changes and Error Corrections”
This statement replaces Accounting Principles Board (APB) Opinion No. 20, “Accounting Changes” and FASB Statement No. 3, “ReportingChanges in Interim Financial Statements,” and establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. It applies to all voluntary changes in accounting principle, and to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Chugach will implement the Statement effective January 1, 2006.
SFAS 153“Exchanges of Nonmonetary Assets”
This Statement addresses the measurement of exchanges of nonmonetary assets. It eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in APB Opinion No. 29,“Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. This
37
Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Chugach implemented the statement effective January 1, 2006. The implementation of the statement had no significant impact on the financial statements.
SFAS 150“Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”
In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS 150). This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Many of those instruments were previously classified as equity. Some of the provisions of this Statement are consistent with the current definition of liabilities in FASB Concepts Statement No. 6,Elements of Financial Statements. The remaining provisions of this Statement are consistent with FASB’s proposal to revise that definition to encompass certain obligations that a reporting entity can or must settle by issuing its own equity shares depending on the nature of the relationship established between the holder and the issuer. While FASB still plans to revise that definition through an amendment to Concepts Statement 6, FASB decided to defer issuing that amendment until it has concluded its deliberations on the next phase of this project. That next phase will deal with certain compound financial instruments including puttable shares, convertible bonds, and dual-indexed financial instruments. Chugach implemented SFAS 150 effective January 1, 2004. The impact of this statement on its financial statements was immaterial.
Outlook
Effective March 20, 2006, Chugach reorganized its operations into more distinct business units - Office of the Chief Executive Officer (CEO), Power Supply, Power Delivery, Finance and Administration.
The Office of the Chief Executive Officer is responsible for all corporate level activities including board of director functions, human resources and safety, legal matters, labor relations and employee relations. The CEO’s Chief of Staff is responsible for corporate planning and key contract negotiations. The CEO’s direct staff is the Chief of Staff, Chief Financial Officer, Vice President, Human Resources and General Counsel. The Senior Vice Presidents of Power Supply, Power Delivery and Administration also report to the CEO.
Power Supply includes all generation functions, System Control, Supervisory Control and Data Acquisition (SCADA), Communications and administrative requirements associated with power supply. The Power Supply sector is led by Bradley Evans, Sr. Vice President.
Power Delivery functions include Transmission, Engineering, Operations, Technical Services and Fleet Services. The Power Delivery area is led by Lee Thibert, Sr. Vice President.
38
Finance is responsible for all accounting and finance functions, budget and financial analysis, regulatory affairs and risk management. This office is led by Michael R. Cunningham, Sr. Vice President and Chief Financial Officer.
Administration is comprised of Administrative Services (Environmental Engineering and Hazardous Materials, Contracting, Security, and Purchasing), Member Services, Corporate Communications and Information Services. Administration is led by William Stewart, Sr. Vice President, Administration.
On September 2, 2005, Joe Griffith resigned from his position as CEO. Effective September 3, 2005, William R. Stewart, General Manager, Corporate Services Division was appointed interim CEO. Mr. Stewart has over 37 years of electric utility experience at Chugach.
39
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, 2005:
2005
| | | | | | | | | | | | | | | | | | | | | | | | | |
Total Debt* | | 2006 | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | Total | | Fair
Value | |
| |
| |
| |
| |
| |
| |
| |
| |
| |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Fixed rate | | $ | 2,000 | | $ | 2,000 | | $ | 2,000 | | $ | 2,000 | | $ | 1,500 | | $ | 270,000 | | $ | 279,500 | | $ | 297,569 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Average interest rate | | | 5.50 | % | | 5.50 | % | | 5.50 | % | | 5.50 | % | | 5.50 | % | | 6.39 | % | | 6.36 | % | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Variable rate | | $ | 6,326 | | $ | 11,729 | | $ | 7,241 | | $ | 7,763 | | $ | 8,297 | | $ | 52,002 | | $ | 93,358 | | $ | 93,358 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Average interest rate | | | 4.96 | % | | 5.49 | % | | 4.96 | % | | 4.96 | % | | 4.96 | % | | 5.71 | % | | 5.45 | % | | | |
* Includes current portion
Chugach is exposed to market risk from changes in interest rates. A 100 basis-point change (up or down) would increase or decrease our interest expense by approximately $93,358, based on $93,358,000 of variable debt outstanding at December 31, 2005.
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.
40
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. (the Company) as of December 31, 2005 and 2004, and the related statements of revenue, expenses and patronage capital, and cash flows for each of the years in the three-year period ended December 31, 2005. 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, 2005 and 2004, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2005, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG, LLP
KPMG, LLP
Anchorage, Alaska
February 27, 2006
41
Chugach Electric Association, Inc.
Balance Sheets
December 31, 2005 and 2004
| | | | | | | | | |
Assets | | 2005 | | 2004 | |
| |
| |
| |
| | | | | | | |
Utility Plant: | | | | | | | |
Electric plant in service (notes 1d, 3, 11 and 12) | | $ | 762,859,198 | | $ | 748,484,527 | |
| | | | | | | |
Construction work in progress | | | 32,505,401 | | | 25,278,388 | |
| |
|
| |
|
| |
Total utility plant | | | 795,364,599 | | | 773,762,915 | |
| | | | | | | |
Less accumulated depreciation | | | (327,384,961 | ) | | (305,932,001 | ) |
| |
|
| |
|
| |
Net utility plant | | | 467,979,638 | | | 467,830,914 | |
| | | | | | | |
Other property and investments, at cost: | | | | | | | |
Nonutility property | | | 24,461 | | | 24,461 | |
| | | | | | | |
Investments in associated organizations (note 4) | | | 11,883,053 | | | 11,768,457 | |
| |
|
| |
|
| |
Total other property and investments | | | 11,907,514 | | | 11,792,918 | |
| | | | | | | |
Current assets: | | | | | | | |
Cash and cash equivalents, including repurchase agreements of $11,446,907 in 2005 and $12,826,644 in 2004 | | | 10,650,594 | | | 10,465,004 | |
| | | | | | | |
Special deposits | | | 216,191 | | | 217,191 | |
| | | | | | | |
Fuel cost under-recovery (note 1o) | | | 1,781,833 | | | 0 | |
| | | | | | | |
Accounts receivable, less provision for doubtful accounts of $398,321 in 2005 and $364,261 in 2004 | | | 27,436,278 | | | 23,740,383 | |
| | | | | | | |
Materials and supplies | | | 23,809,691 | | | 23,691,509 | |
| | | | | | | |
Prepayments | | | 1,801,104 | | | 805,670 | |
| | | | | | | |
Other current assets | | | 282,939 | | | 260,115 | |
| |
|
| |
|
| |
Total current assets | | | 65,978,630 | | | 59,179,872 | |
| | | | | | | |
Deferred charges, net (notes 5 and 13) | | | 19,269,718 | | | 20,550,883 | |
| |
|
| |
|
| |
| | | | | | | |
Total assets | | $ | 565,135,500 | | $ | 559,354,587 | |
| |
|
| |
|
| |
See accompanying notes to financial statements.
42
Chugach Electric Association, Inc.
Balance Sheets, Continued
December 31, 2005 and 2004
| | | | | | | | | |
Liabilities and Equities | | 2005 | | 2004 | |
| |
|
| |
|
| |
Equities and margins (notes 6 and 7): | | | | | | | |
Memberships | | $ | 1,250,398 | | $ | 1,202,538 | |
| | | | | | | |
Patronage capital | | | 136,185,378 | | | 130,750,269 | |
| | | | | | | |
Other | | | 7,603,376 | | | 7,045,992 | |
| |
|
| |
|
| |
Total equities and margins | | | 145,039,152 | | | 138,998,799 | |
| | | | | | | |
Long-term obligations, excluding current installments (notes 8 and 9): | | | | | | | |
2001 Series A Bond payable | | | 150,000,000 | | | 150,000,000 | |
| | | | | | | |
2002 Series A Bond payable | | | 120,000,000 | | | 120,000,000 | |
| | | | | | | |
2002 Series B Bond payable | | | 41,000,000 | | | 46,200,000 | |
| | | | | | | |
National Bank for Cooperatives promissory notes payable | | | 53,532,099 | | | 47,157,786 | |
| |
|
| |
|
| |
Total long-term obligations | | | 364,532,099 | | | 363,357,786 | |
| | | | | | | |
Current liabilities: | | | | | | | |
Current installments of long-term obligations (notes 8 and 9) | | | 8,325,687 | | | 15,931,393 | |
| | | | | | | |
Accounts payable | | | 9,598,958 | | | 7,890,172 | |
| | | | | | | |
Consumer deposits | | | 1,980,285 | | | 1,947,511 | |
| | | | | | | |
Fuel cost over-recovery (note 1o) | | | 0 | | | 2,714,345 | |
| | | | | | | |
Accrued interest | | | 6,360,652 | | | 6,201,769 | |
| | | | | | | |
Salaries, wages and benefits | | | 5,373,496 | | | 5,530,740 | |
| | | | | | | |
Fuel | | | 18,123,139 | | | 12,919,623 | |
| | | | | | | |
Other current liabilities | | | 3,035,915 | | | 1,416,400 | |
| |
|
| |
|
| |
Total current liabilities | | | 52,798,132 | | | 54,551,953 | |
| | | | | | | |
Deferred credits (note 5) | | | 2,766,117 | | | 2,446,049 | |
| |
|
| |
|
| |
| | | | | | | |
Total liabilities and equities | | $ | 565,135,500 | | $ | 559,354,587 | |
| |
|
| |
|
| |
See accompanying notes to financial statements.
43
Chugach Electric Association, Inc.
Statements of Revenues, Expenses and Patronage Capital
Years ended December 31, 2005, 2004 and 2003
| | | | | | | | | | |
| | 2005 | | 2004 | | 2003 | |
| |
| |
| |
| |
Operating revenues (notes 1n, 2 and 13) | | $ | 225,697,349 | | $ | 201,246,615 | | $ | 184,032,413 | |
| | | | | | | | | | |
Operating expenses: | | | | | | | | | | |
| | | | | | | | | | |
Fuel (note 13) | | | 84,776,131 | | | 64,113,474 | | | 48,667,262 | |
| | | | | | | | | | |
Power production | | | 15,005,786 | | | 15,378,858 | | | 13,961,565 | |
| | | | | | | | | | |
Purchased power | | | 23,664,412 | | | 20,579,992 | | | 18,244,921 | |
| | | | | | | | | | |
Transmission | | | 5,847,648 | | | 6,526,684 | | | 4,511,002 | |
| | | | | | | | | | |
Distribution | | | 11,780,502 | | | 11,723,316 | | | 10,866,251 | |
| | | | | | | | | | |
Consumer accounts | | | 5,227,478 | | | 5,308,353 | | | 5,589,788 | |
| | | | | | | | | | |
Administrative, general and other | | | 20,272,291 | | | 21,719,908 | | | 26,520,189 | |
| | | | | | | | | | |
Depreciation | | | 28,249,717 | | | 27,989,452 | | | 27,792,051 | |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | |
Total operating expenses | | | 194,823,965 | | | 173,340,037 | | | 156,153,029 | |
| | | | | | | | | | |
Interest expense: | | | | | | | | | | |
| | | | | | | | | | |
On long-term obligations | | | 23,384,316 | | | 21,984,371 | | | 23,110,239 | |
| | | | | | | | | | |
On short-term obligations | | | 46,649 | | | 0 | | | 11,901 | |
| | | | | | | | | | |
Charged to construction-credit | | | (844,911 | ) | | (492,506 | ) | | (411,312 | ) |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | |
Net interest expense | | | 22,586,054 | | | 21,491,865 | | | 22,710,828 | |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | |
Net operating margins | | | 8,287,330 | | | 6,414,713 | | | 5,168,556 | |
| | | | | | | | | | |
Nonoperating margins: | | | | | | | | | | |
| | | | | | | | | | |
Interest income | | | 560,418 | | | 453,606 | | | 325,324 | |
| | | | | | | | | | |
Capital credits, patronage dividends and other | | | 666,983 | | | 734,137 | | | 759,240 | |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | |
Total nonoperating margins | | | 1,227,401 | | | 1,187,743 | | | 1,084,564 | |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | |
Assignable margins | | | 9,514,731 | | | 7,602,456 | | | 6,253,120 | |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | |
Patronage capital at beginning of period | | | 130,750,269 | | | 126,341,413 | | | 120,148,502 | |
| | | | | | | | | | |
Retirement of capital credits and estate payments, including discounted capital credits transferred to other equities and margins (note 6) | | | (4,079,622 | ) | | (3,193,600 | ) | | (60,209 | ) |
| |
|
| |
|
| |
|
| |
| | | | | | | | | | |
| | | | | | | | | | |
Patronage capital at end of period | | $ | 136,185,378 | | $ | 130,750,269 | | $ | 126,341,413 | |
| |
|
| |
|
| |
|
| |
See accompanying notes to financial statements.
44
Chugach Electric Association, Inc.
Statements of Cash Flows
Years ended December 31, 2005, 2004 and 2003
| | | | | | | | | | |
| | 2005 | | 2004 | | 2003 | |
| |
| |
| |
| |
Cash flows from operating activities: | | | | | | | | | | |
Assignable margins | | $ | 9,514,731 | | $ | 7,602,456 | | $ | 6,253,120 | |
| | | | | | | | | | |
Adjustments to reconcile assignable margins to net cash provided by operating activities: | | | | | | | | | | |
Provision for rate refund | | | 0 | | | 0 | | | (1,400,000 | ) |
Depreciation and amortization | | | 30,341,574 | | | 31,586,948 | | | 33,780,103 | |
Capitalized interest | | | (993,499 | ) | | (571,013 | ) | | (487,359 | ) |
Impairment of long-lived asset | | | 0 | | | 0 | | | 1,846,816 | |
Property (gains) losses, net | | | 57,202 | | | (11,190 | ) | | (80,061 | ) |
Write-off of deferred charges | | | 0 | | | 217,665 | | | 1,088,260 | |
Investments in associated organizations | | | (114,596 | ) | | (386,661 | ) | | (418,081 | ) |
| | | | | | | | | | |
Changes in assets and liabilities: | | | | | | | | | | |
(Increase) decrease in assets: | | | | | | | | | | |
Accounts receivable | | | (3,695,895 | ) | | (4,928,184 | ) | | 7,598,064 | |
Fuel cost under-recovery | | | (1,781,833 | ) | | 2,032,730 | | | (2,032,730 | ) |
Materials and supplies | | | (118,182 | ) | | (1,802,715 | ) | | 1,858,796 | |
Prepayments | | | (995,434 | ) | | 652,979 | | | 494,702 | |
Special deposits/other | | | (21,824 | ) | | 102,122 | | | (20,468 | ) |
Deferred charges | | | (810,692 | ) | | (854,481 | ) | | (1,887,037 | ) |
| | | | | | | | | | |
Increase (decrease) in liabilities: | | | | | | | | | | |
Accounts payable | | | 1,114,809 | | | 213,266 | | | (43,068 | ) |
Provision for rate refund | | | 0 | | | (671,071 | ) | | (4,978,929 | ) |
Consumer deposits | | | 32,774 | | | 112,759 | | | 8,487 | |
Fuel cost over-recovery | | | (2,714,345 | ) | | 2,714,345 | | | (363,862 | ) |
Accrued interest | | | 158,883 | | | 35,979 | | | (215,316 | ) |
Salaries, wages and benefits | | | (157,244 | ) | | 644,140 | | | (90,994 | ) |
Fuel | | | 5,203,516 | | | 3,912,865 | | | 1,911,356 | |
Other liabilities | | | 2,213,492 | | | 630,640 | | | (1,242,178 | ) |
Deferred credits | | | (143,138 | ) | | (92,314 | ) | | (210,681 | ) |
| |
|
|
|
|
|
|
|
| |
Net cash provided by operating activities | | | 37,090,299 | | | 41,141,265 | | | 41,368,940 | |
| | | | | | | | | | |
Investing activities: | | | | | | | | | | |
Extension and replacement of plant | | | (27,462,144 | ) | | (27,810,212 | ) | | (26,526,858 | ) |
| |
|
|
|
|
|
|
|
| |
Net cash used in investing activities | | | (27,462,144 | ) | | (27,810,212 | ) | | (26,526,858 | ) |
| | | | | | | | | | |
Financing activities: | | | | | | | | | | |
Net transfer of restricted construction funds | | | 0 | | | 488,846 | | | 110,018 | |
Repayments of long-term obligations | | | (6,431,393 | ) | | (10,545,000 | ) | | (5,165,821 | ) |
Repayments of short-term borrowings | | | 0 | | | 0 | | | (6,081,250 | ) |
Memberships and donations received | | | 605,244 | | | 373,821 | | | 545,316 | |
Retirement of patronage capital and estate payments, including discounted capital credits transferred to other equities and margins | | | (4,079,622 | ) | | (3,193,600 | ) | | (60,209 | ) |
Net receipts of consumer advances for construction | | | 463,206 | | | (1,175,202 | ) | | (289,342 | ) |
| |
|
|
|
|
|
|
|
| |
Net cash used in financing activities | | | (9,442,565 | ) | | (14,051,135 | ) | | (10,941,288 | ) |
| | | | | | | | | | |
Net changes in cash and cash equivalents | | | 185,590 | | | (720,082 | ) | | 3,900,794 | |
| | | | | | | | | | |
Cash and cash equivalents at beginning of period | | $ | 10,465,004 | | $ | 11,185,086 | | $ | 7,284,292 | |
| | | | | | | | | | |
Cash and cash equivalents at end of period | | $ | 10,650,594 | | $ | 10,465,004 | | $ | 11,185,086 | |
| |
|
|
|
|
|
|
|
| |
| | | | | | | | | | |
Supplemental disclosure of cash flow information - interest expense paid, excluding amounts capitalized | | $ | 22,427,171 | | $ | 21,354,036 | | $ | 23,076,144 | |
See accompanying notes to financial statements.
45
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(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 members are the consumers of the electricity sold. |
| |
| Chugach operates on a not-for-profit basis and, accordingly, seeks only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation, and principal and interest on all indebtedness and to provide for reasonable margins and reserves. Chugach is subject to the regulatory authority of the Regulatory Commission of Alaska (RCA). |
| |
| b. Management Estimates |
| |
| In preparing the financial statements, management of Chugach is required to make estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the balance sheet and revenues and expenses for the reporting period. Critical estimates include the provision for rate refund and allowance for doubtful accounts. Actual results could differ from those estimates. |
| |
| c. Regulation |
| |
| The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Statement of Financial Accounting Standards (SFAS) No. 71,Accounting for the Effects of Certain Types of Regulation (SFAS 71). |
46
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(1) | Description of Business and Significant Accounting Policies (continued) |
| |
| d. Utility Plant and Depreciation |
| |
| Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. For property replaced or retired, the average unit cost of the property unit, plus removal cost, less salvage, is charged to accumulated provision for depreciation. The cost of replacement is added to electric plant. Renewals and betterments are capitalized, while maintenance and repairs are charged to expense as incurred. In accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144), utility plant is reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of are separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell, and are no longer depreciated. The assets and liabilities of a disposed group classified as held for sale are presented separately in the appropriate asset and liability section of the balance sheet. During the second quarter of 2003, Chugach entered into a plan to take a generation asset out of service. The asset was physically abandoned in September of 2003. In accordance with SFAS 144, paragraph 28, Chugach adjusted the remaining depreciable life of the asset. Chugach determined the depreciation that would have been recorded in the third quarter of 2003 was immaterial, therefore Chugach committed to a plan to abandon the asset. The value of that asset was reduced by $1,846,816 to its estimated salvage value. This amount is included in the 2003 Statement of Revenues, Expenses and Patronage Capital, “Administrative, general and other,” category. |
| |
| Depreciation and amortization rates have been applied on a straight-line basis and at December 31 are as follows: |
| | | | | | | | | | | | | | | | | | | | |
| | | Annual Depreciation Rate Ranges | |
|
| | | 2005 | | 2002 - 2004 | |
| | |
|
|
|
|
| | | | | | | | | | | | | | | | | | | | |
| Steam production plant | | | 2.55 | % | | — | | | 3.24 | % | | 2.55 | % | | — | | | 2.80 | % |
| | | | | | | | | | | | | | | | | | | | |
| Hydraulic production plant | | | 1.63 | % | | — | | | 2.94 | % | | 0.04 | % | | — | | | 1.56 | % |
| | | | | | | | | | | | | | | | | | | | |
| Other production plant | | | 3.32 | % | | — | | | 9.81 | % | | 2.67 | % | | — | | | 7.62 | % |
| | | | | | | | | | | | | | | | | | | | |
�� | Transmission plant | | | 1.72 | % | | — | | | 5.26 | % | | 1.50 | % | | — | | | 4.24 | % |
| | | | | | | | | | | | | | | | | | | | |
| Distribution plant | | | 2.10 | % | | — | | | 9.98 | % | | 2.13 | % | | — | | | 9.22 | % |
| | | | | | | | | | | | | | | | | | | | |
| General plant | | | 2.23 | % | | — | | | 27.25 | % | | 2.21 | % | | — | | | 20.40 | % |
| | | | | | | | | | | | | | | | | | | | |
| Other | | | 2.75 | % | | — | | | 2.75 | % | | 2.35 | % | | — | | | 2.75 | % |
47
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| | |
(1) | Description of Business and Significant Accounting Policies (continued) |
| |
| Chugach uses remaining life rates set forth in the most recent depreciation study. In 2003 an update of the 1999 Depreciation Study was completed utilizing Electric Plant in Service balances as of December 31, 2002. In an order dated January 10, 2006, the RCA approved the 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. The impact on Chugach’s financial statements to depreciation expense was a decrease of $1.0 million |
| |
| e. Capitalized Interest |
| |
| Allowance for funds used during construction (AFUDC) and interest charged to construction - credit (IDC) are the estimated costs during the period of construction of equity and borrowed funds. Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 5.0% during 2005, 4.6% during 2004 and 4.8% during 2003. |
| |
| f. Investments in Associated Organizations |
| |
| Investments in associated organizations represent capital requirements as part of financing arrangements. These investments are non-marketable and accounted for at cost. |
| |
| g. Fair Value of Financial Instruments |
| |
| SFAS No. 107,Disclosures About the Fair Value of Financial Instruments (SFAS 107), requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments: |
| | |
| | Cash and cash equivalents and restricted cash - the carrying amount approximates fair value because of the short maturity of those instruments. |
| | |
| | Investments in associated organizations - the carrying amount approximates fair value because of limited marketability and the nature of the investments. |
| | |
| | Consumer deposits - the carrying amount approximates fair value because of the short refunding term. |
| | |
| | Long-term obligations - the fair value is estimated based on the quoted market price for same or similar issues (notes 8 and 9). |
48
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(1) | Description of Business and Significant Accounting Policies (continued) |
| |
| h. Financial Instruments and Hedging |
| |
| Chugach used U.S. Treasury forward rate lock agreements to hedge expected interest rates on the February 2002 debt re-financings. Chugach accounted for the agreements under SFAS 133. For rate-making purposes, Chugach did not adjust rates for gains and losses prior to settlement, and the loss on settlement will be an adjustment to rates over the lives of the associated debt. This rate-making treatment was approved by the RCA in Order U-01-108(26). See note 2, “Regulatory Matters.” Accordingly, the unrealized loss was not recorded and was treated as a regulatory asset upon settlement (note 5). At December 31, 2005, the regulatory asset associated with the rate lock agreements was $3.4 million. |
| |
| i. Cash and Cash Equivalents |
| |
| For purposes of the statement of cash flows, Chugach considers all highly liquid debt instruments with a maturity of three months or less upon acquisition by Chugach (excluding restricted cash and investments) to be cash equivalents. |
| |
| j. Accounts Receivable |
| |
| Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectibility. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers. |
| |
| k. Materials and Supplies |
| |
| Materials and supplies are stated at average cost. |
| |
| l. Deferred Charges and Credits |
| |
| In accordance with SFAS 71, Chugach’s financial statements reflect regulatory assets and liabilities. Continued accounting under SFAS 71 requires that certain criteria be met. Management believes Chugach’s operations currently satisfy these criteria. However, if events or circumstances should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on the financial position and results of operations. Deferred charges, representing regulatory assets, are amortized to operating expense over the period allowed for rate-making purposes. |
49
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(1) | Description of Business and Significant Accounting Policies (continued) |
| |
| Deferred credits, representing regulatory liabilities, are amortized to operating expense over the period allowed for rate-making purposes. It also includes nonrefundable contributions in aid of construction, which are credited to the associated cost of construction of property units. Refundable contributions in aid of construction are held in deferred credits pending their return or other disposition. |
| |
| m. Patronage Capital |
| |
| Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on Chugach’s statement of revenues and expenses as assignable margins. These excess amounts (i.e. assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by Chugach until such future time as they are retired and returned without interest at the discretion of the Board of Directors. Retained assignable margins are designated on Chugach’s balance sheet as patronage capital. This patronage capital constitutes the principal equity of Chugach. The Board of Directors may also return capital credits to former members and estates who request early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002. |
| |
| n. Operating Revenues |
| |
| Revenues are recognized 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. Included in operating revenue are billings rendered to customers adjusted for differences in meter read dates from year to year to insure the recognition of a full year’s revenue. Chugach accrued $6,231,072 and $5,675,996 of unbilled retail revenue at December 31, 2005 and 2004, respectively. Wholesale revenue is recorded from metered locations, 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. |
| |
| o. Fuel and Purchased Power Costs |
| |
| The expenses associated with electric services include fuel used to generate electricity and power purchased from others. These costs are recognized in the month incurred, both on an expense and revenue basis. Actual fuel and purchased power used is included in revenue to directly offset the actual fuel expense in the month it was incurred. 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 under-recovered by $1.8 million in 2005, over-recovered by $2.7 million in 2004 and under-recovered by $2.0 million in 2003. Total fuel and purchased power costs in 2005, 2004 and 2003 were approximately $108 million, $85 and $67 million, respectively. |
50
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(1) | Description of Business and Significant Accounting Policies (continued) |
| |
| p. Environmental Remediation Costs |
| |
| Chugach accrues for losses and establishes a liability associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. Estimates of future costs for environmental remediation obligations are not discounted to their present value. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset. |
| |
| q. Income Taxes |
| |
| Chugach is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code, except for unrelated business income. For the years ended December 31, 2005, 2004 and 2003, Chugach received no unrelated business income. |
| |
| r. Reclassifications |
| |
| Certain reclassifications, which have no affect on assignable margins, have been made to the 2003 and 2004 financial statements to conform to the 2005 presentation. |
| |
| s. New Accounting Pronouncements |
| |
| FASB Interpretation No. 47 (FIN 47) “Accounting for Conditional Asset Retirement Obligations” |
| |
| In March, 2005, the FASB issued FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations(FIN 47). FIN 47, effective for fiscal years ending after December 15, 2005, is an interpretation of FASB Statement No. 143,Accounting for Asset Retirement Obligations (Statement 143).FIN 47Interpretation clarifies that conditional obligations meet the definition of an asset-retirement obligation in Statement 143 and therefore should be recognized if their fair value is reasonably estimable. It also provides additional guidance to evaluate whether fair value is reasonably estimable. Chugach evaluated the provisions of FIN 47 and implemented the Interpretation effective January 1, 2005. The implementation of the statement had no significant impact on the financial statements. |
| |
| SFAS 154“Accounting Changes and Error Corrections” |
| |
| This statement replaces Accounting Principles Board (APB) Opinion No. 20, “Accounting Changes” and FASB Statement No. 3, “ReportingChanges in Interim Financial Statements,” and establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition |
51
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(1) | Description of Business and Significant Accounting Policies (continued) |
| |
| requirements specific to the newly adopted accounting principle. It applies to all voluntary changes in accounting principle, and to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. This Statement is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. Chugach will implement the Statement effective January 1, 2006. |
| |
| SFAS 153“Exchanges of Nonmonetary Assets” |
| |
| This Statement addresses the measurement of exchanges of nonmonetary assets. It eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets in APB Opinion No. 29,“Accounting for Nonmonetary Transactions,” and replaces it with an exception for exchanges that do not have commercial substance. This Statement specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. The provisions of this Statement are effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. Chugach implemented the statement effective January 1, 2006. The implementation of the statement had no significant impact on the financial statements. |
| |
| SFAS 150“Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” |
| |
| In May 2003, the Financial Accounting Standards Board (FASB) issued SFAS No. 150,Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS 150). This Statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. Many of those instruments were previously classified as equity. Some of the provisions of this Statement are consistent with the current definition of liabilities in FASB Concepts Statement No. 6,Elements of Financial Statements. The remaining provisions of this Statement are consistent with FASB’s proposal to revise that definition to encompass certain obligations that a reporting entity can or must settle by issuing its own equity shares depending on the nature of the relationship established between the holder and the issuer. While FASB still plans to revise that definition through an amendment to Concepts Statement 6, FASB decided to defer issuing that amendment until it has concluded its deliberations on the next phase of this project. That next phase will deal with certain compound financial instruments including puttable shares, convertible bonds, and dual-indexed financial instruments. Chugach implemented SFAS 150 effective January 1, 2004. The impact of this statement on its financial statements was immaterial. |
52
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(2) | Regulatory Matters |
| |
| Docket U-01-108 |
| |
| Chugach filed a general rate case on July 10, 2001, based on the 2000 test year and subsequently implemented interim and refundable rate increases as approved by the RCA. In an updated filing on April 15, 2002, Chugach reduced its base rate increase request from 6.5% to 5.7%. Three wholesale customers and the Public Advocacy staff of the RCA participated in the rate case. |
| |
| Order No. 26 |
| |
| On February 6, 2003, Chugach received Order U-01-108(26) (Order 26) from the RCA, which required a refund of revenues collected in 2001 and 2002 of approximately $7.1 million, which resulted in a net operating loss of approximately $2 million in 2002. Under the Order, Chugach’s financial performance for 2002 fell below the 1.10 level contained in the Rate Covenants in its currently effective indenture, the Amended and Restated Indenture, the CoBank Master Loan Agreement and the MBIA Insurance Corporation’s (MBIA) Reimbursement and Indemnity Agreement. (note 8) |
| |
| In accordance with the Rate Covenant in the Amended and Restated Indenture, on February 13, 2003, Chugach filed a Motion with the RCA asking the RCA to stay the effect of Order 26 until after the RCA considered Chugach’s Petition for Reconsideration. On February 18, 2003, the RCA granted, in part, Chugach’s motion for stay. Chugach filed the Petition for Reconsideration with the RCA on February 28, 2003. |
| |
| Order No. 30 |
| |
| On April 14, 2003, the RCA issued Order No. 30 in Docket U-01-108, significantly revising its earlier ruling. On April 28, 2003, Chugach submitted a revised revenue requirement and cost of service study in compliance with RCA Order No. 30. This order increased Chugach’s revenue requirement by $3.1 million and adjusted the required refund from $7.1 million to $1.9 million. |
| |
| Order No. 33 |
| |
| On August 26, 2003, the RCA issued Order No. 33 and accepted, in part, Chugach’s April 28, 2003, compliance filing. |
53
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(2) | Regulatory Matters (continued) |
| |
| Order No. 36 |
| |
| Effective November 7, 2003, the RCA approved Chugach’s compliance filing to Order 33 and final rates in this docket. As a result, and in relation to prior-approved permanent rates, Chugach’s rates on a system basis increased 0.07 percent, or an increase of 3.5 percent to retail customers and a decrease of 7.9 percent to wholesale customers. |
| |
| The results of the RCA’s decision on final rates were implemented on November 10, 2003. |
| |
| Appeal of RCA Orders |
| |
| Chugach filed a timely appeal of RCA Orders Nos. 26, 30 and 33 to the Alaska Superior Court. In a November 25, 2004, decision, the Alaska Superior Court upheld all decisions of the RCA. |
| |
| Provision For Rate Refund |
| |
| At December 31, 2002, Chugach recorded a provision for rate refund of $7.1 million. On April 15, 2003, the RCA issued Order No. 30 in Docket U-01-108, significantly revising its earlier ruling in which $5.2 million of that provision was reversed. Between March and November of 2003, additional provisions were recorded in the amount of $3.8 million reflecting RCA decisions through Order No. 30, in addition to RCA orders that continued through the period. In October and November of 2003, Chugach’s wholesale customers were refunded $5.0 million. Between March 19 and April 19, 2004, Chugach issued refunds totaling $0.6 million to its Small General Service class for customer bills rendered between January 31 and November 10, 2003. |
| |
| Docket No. U-04-102 (Revision to Current Depreciation Rates) |
| |
| 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 a net impact on 2004 depreciation expense of approximately $259 thousand, which, in aggregate, 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, however, Chugach 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. |
| |
| Order No. 2 |
| |
| 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 August 8, 2005, Chugach filed a motion proposing an alternate implementation plan. |
54
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(2) | Regulatory Matters (continued) |
| |
| Order No. 8 |
| |
| On September 21, 2005, the RCA issued Order No. 8 denying our motion and granting a motion filed by a wholesale customer of Chugach to enforce Order No. 2. Order No. 8 required that Chugach 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. |
| |
| Order No. 9 |
| |
| 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, to reflect new depreciation rates. In comparison to the old depreciation rates resulting from the last rate case (U-01-108), implementation of Order No. 9 increased depreciation expense for Generation & Transmission (G&T) plant of approximately $2.2 million, decreased depreciation expense for Distribution plant of approximately $1.2 million and decreased depreciation expense for General Plant of approximately $2.0 million. The overall impact to Chugach is an estimated decrease in annual depreciation expense of $1.0 million. No issues were raised in relation to the proposed Distribution depreciation adjustments. Because Chugach did not request changes to the electric rates charged to our customers based on the proposed new depreciation rates, there is no immediate electric rate impact. Wholesale customers MEA and HEA were active in the proceeding. MEA filed a motion for reconsideration of the effective date of January 1, 2005, for the changes to depreciation rates based on the RCA’s ruling. Management is uncertain of the outcome of the reconsideration. |
55
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(3) | Utility Plant |
| |
| Major classes of electric plant as of December 31 are as follows: |
| | | | | | | | |
| | | 2005 | | 2004 | |
| | |
| |
| |
| Electric plant in service: | | | | | | | |
| Steam production plant | | $ | 60,462,671 | | $ | 60,462,671 | |
| Hydraulic production plant | | | 20,241,725 | | | 18,180,685 | |
| Other production plant | | | 132,990,991 | | | 134,495,475 | |
| Transmission plant | | | 226,544,759 | | | 222,483,924 | |
| Distribution plant | | | 219,597,822 | | | 213,119,035 | |
| General Plant | | | 52,606,167 | | | 53,678,686 | |
| Unclassified electric plant in service | | | 43,651,171 | | | 39,300,159 | |
| Other | | | 6,763,892 | | | 6,763,892 | |
| | |
|
| |
|
| |
| Total electric plant in service | | | 762,859,198 | | | 748,484,527 | |
| Construction work in progress | | | 32,505,401 | | | 25,278,388 | |
| | |
|
| |
|
| |
| Total electric plant in service and construction work in progress | | $ | 795,364,599 | | $ | 773,762,915 | |
| | |
|
| |
|
| |
| |
| Unclassified electric plant in service consists of complete unclassified of general plant, generation, transmission and distribution projects. Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment. |
| |
(4) | Investments in Associated Organizations |
| |
| Investments in associated organizations, which are non-marketable and accounted for at cost, include the following at December 31: |
| |
| | | | | | | | |
| | | 2005 | | 2004 | |
| | |
| |
| |
| National Rural Utilities Cooperative Finance Corporation (NRUCFC) | | $ | 6,095,980 | | $ | 6,095,980 | |
| National Bank for Cooperatives (CoBank) | | | 5,628,192 | | | 5,513,192 | |
| NRUCFC capital term certificates | | | 41,677 | | | 42,662 | |
| Other | | | 117,204 | | | 116,623 | |
| | |
|
| |
|
| |
| Total Investments in Associated Organizations | | $ | 11,883,053 | | $ | 11,768,457 | |
| | |
|
| |
|
| |
56
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(4) | Investments in Associated Organizations (continued) |
| |
| The Farm Credit Administration, CoBank’s federal regulators, requires minimum capital adequacy standards for all Farm Credit System institutions. CoBank’s loan agreements require, as a condition of the extension of credit, that an equity ownership position be established by all borrowers. Chugach’s investment in NRUCFC similarly was required by Chugach’s financing arrangements with NRUCFC. |
| |
(5) | Deferred Charges and Credits |
| |
| Deferred Charges |
| |
| Deferred charges, or regulatory assets, net of amortization, consisted of the following at December 31: |
| | | | | | | | |
| | | 2005 | | 2004 | |
| | |
| |
| |
| Debt issuance and reacquisition costs | | $ | 9,392,807 | | $ | 10,981,260 | |
| Refurbishment of transmission equipment | | | 206,791 | | | 216,050 | |
| Computer software and conversion | | | 330,946 | | | 740,771 | |
| Studies | | | 5,758,382 | | | 4,646,181 | |
| Business venture studies | | | 171,378 | | | 172,578 | |
| Fuel supply negotiations | | | 233,314 | | | 256,030 | |
| Major overhaul of steam generating unit | | | 1,503,192 | | | 1,895,329 | |
| Environmental matters and other | | | 149,879 | | | 74,304 | |
| Other regulatory deferred charges | | | 1,523,029 | | | 1,568,380 | |
| | |
|
| |
|
| |
| Total deferred charges | | $ | 19,269,718 | | $ | 20,550,883 | |
| | |
|
| |
|
| |
| |
| At December 31, 2005 and 2004, $6.4 million and $5.6 million, respectively, of total deferred charges represent regulatory assets in progress and are not currently being amortized, however, Chugach expects recovery, as well as a recovery period determination in the future. The majority of these charges represent costs associated with the Cooper Lake Power Plant FERC re-licensing effort. Over/under recovered fuel costs is not included in Deferred Charges or Deferred Credits. |
57
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(5) | Deferred Charges and Credits (continued) |
| |
| Deferred Credits |
| |
| Deferred credits, or regulatory liabilities, at December 31 consisted of the following: |
| | | | | | | | |
| | | 2005 | | 2004 | |
| | |
| |
| |
| Refundable consumer advances for construction | | $ | 1,816,275 | | $ | 1,353,069 | |
| Estimated initial installation costs for transformers and meters | | | 436,786 | | | 387,336 | |
| Post retirement benefit obligation | | | 480,900 | | | 480,900 | |
| Other | | | 32,156 | | | 224,744 | |
| | |
|
| |
|
| |
| Total deferred credits | | $ | 2,766,117 | | $ | 2,446,049 | |
| | |
|
| |
|
| |
| |
(6) | Patronage Capital |
| |
| Chugach has an approved capital credit retirement policy, which is contained in the Chugach Financial Management Plan. This establishes, in general, a plan to return the capital credits of wholesale and retail customers based on the members’ proportionate contribution to Chugach’s assignable margins on an approximately 15-year rotation. At December 31, 2005, Chugach had assigned $120,255,933 of patronage capital (net of capital credit retirements). Approval of actual capital credit retirements is at the discretion of Chugach’s Board of Directors. Chugach records a liability when the retirements are approved by the Board of Directors. 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. (note 8) |
| |
| In 2003, the Board of Directors was unable to authorize a capital credit retirement due to covenant restrictions contained in the Amended and Restated Indenture of Trust. (note 8) |
58
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(6) | Patronage Capital (continued) |
| |
| In November 2004, the Board of Directors authorized the retirement of $3,126,560 of retail patronage for 1985 and 1986. |
| |
| In December 2004, the Board of Directors authorized $125,000 for capital credit payments to those former members and estates who have requested early retirements at discounted rates under the discounted capital credit retirement plan authorized by the Board in September 2002. |
| |
| In December 2004, the Board of Directors authorized $500,000 for capital credit payments to be distributed during 2005 under the discounted capital credit retirement plan. |
| |
| In November 2005, the Board of Directors authorized the retirement of $3,801,228 of retail patronage for 1986 and 1987. |
| |
| In 2005, the retirement of $3,801,228 included discounted estate payments in the amount of $394,520. In addition, Chugach retained $282,479, which represented discounted capital credits transferred to other equities and margins under the discounted capital credit retirement program. |
| |
| In 2004, the retirement of $3,126,560 included discounted estate payments in the amount of $55,639. In addition, Chugach retained $65,990, which represented discounted capital credits transferred to other equities and margins under the discounted capital credit retirement program. |
| |
| Estate payments in the amount of $60,209 were made in 2003. |
| |
| The discount rate for discounted payments, including discounted estate payments in 2005 and 2004 was 9.20%. |
| |
| Following is a five-year summary of anticipated capital credit retirements: |
| | | | |
Year ending
December 31, | | Total | |
| | | |
2006 | | $ | 3,900,000 | |
2007 | | $ | 6,000,000 | |
2008 | | $ | 5,500,000 | |
2009 | | $ | 5,000,000 | |
2010 | | $ | 3,500,000 | |
59
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(7) | Other Equities |
| |
| A summary of other equities at December 31 follows: |
| | | | | | | | |
| | | 2005 | | 2004 | |
| | |
| |
| |
| Nonoperating margins, prior to 1967 | | $ | 23,625 | | $ | 23,625 | |
| Donated capital | | | 532,103 | | | 249,624 | |
| Unclaimed capital credit retirement* | | | 7,047,648 | | | 6,772,743 | |
| | |
|
| |
|
| |
| | | | | | | | |
| Total other equities | | $ | 7,603,376 | | $ | 7,045,992 | |
| | |
|
| |
|
| |
| |
| * 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 |
Long-term obligations at December 31 are as follows:
| | | | | | | |
| | 2005 | | 2004 | |
| |
| |
| |
CoBank 7.76% fixed rate note maturing in 2005, with interest payable monthly; unsecured | | $ | 0 | | $ | 10,000,000 | |
| | | | | | | |
CoBank 5.50% fixed rate note maturing in 2010, with interest payable monthly; unsecured | | $ | 9,500,000 | | $ | 0 | |
| | | | | | | |
CoBank 5.96% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003; unsecured | | | 42,157,786 | | | 43,189,179 | |
| | | | | | | |
CoBank 5.96% variable rate note, with interest payable monthly and principal due in 2007; unsecured | | | 5,000,000 | | | 5,000,000 | |
| | | | | | | |
2001 Series A Bond of 6.55%, maturing in 2011, with interest payable semi-annually March 15 and September 15; unsecured | | | 150,000,000 | | | 150,000,000 | |
| | | | | | | |
2002 Series A Bond of 6.20%, maturing in 2012, with interest payable semi-annually February 1 and August 1; unsecured | | | 120,000,000 | | | 120,000,000 | |
| | | | | | | |
2002 Series B Bond of a rate set for 28-day auction periods, maturing in 2012, with interest payable monthly and principal due annually; unsecured | | | 46,200,000 | | | 51,100,000 | |
| |
|
| |
|
| |
Total long-term obligations | | | 372,857,786 | | | 379,289,179 | |
| | | | | | | |
Less current installments | | | 8,325,687 | | | 15,931,393 | |
| |
|
| |
|
| |
| | | | | | | |
Long-term obligations, excluding current installments | | $ | 364,532,099 | | $ | 363,357,786 | |
| |
|
| |
|
| |
60
| |
(8) | Debt (continued) |
| |
| Covenants |
| |
| Chugach is required to comply with all covenants set forth in the Amended and Restated Indenture, dated April 1, 2001, which became effective January 22, 2003. The indenture initially governing the outstanding bonds of Chugach, 2001 Series A, 2002 Series A and 2002 Series B, provided that the bonds were secured by a mortgage on substantially all of Chugach’s assets so long as any amounts remained outstanding to CoBank on bonds issued under the indenture. Upon the retirement of the bonds issued to CoBank, Chugach’s outstanding bonds became subject to the Amended and Restated Indenture pursuant to which the bonds became unsecured obligations of Chugach. |
| |
| Chugach is also required to comply with the Master Loan Agreement between Chugach and CoBank dated December 27, 2002, pursuant to which CoBank and Chugach replaced the bonds issued to CoBank with unsecured promissory notes not governed by the indenture. CoBank returned the old CoBank bonds to Chugach on January 22, 2003. The CoBank Master Loan Agreement requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense. |
| |
| Security |
| |
| Substantially all assets were pledged as collateral for the long-term obligations until retirement of the 1991 Series A Bonds and subsequent institution of the Amended and Restated Indenture. On January 22, 2003, the Bonds became general unsecured and unsubordinated obligations. Under the Amended and Restated Indenture, Chugach is prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on Chugach’s properties and assets (other than those arising by operation of law) to secure the repayment of borrowed money or the obligation to pay the deferred purchase price of property unless Chugach equally and ratably secure all bonds subject to the Amended and Restated Indenture, except that Chugach may incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements. |
61
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(8) | Debt (continued) |
| |
| Rate |
| |
| The Amended and Restated Indenture requires Chugach, subject to any necessary regulatory approval, to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. The CoBank Master Loan Agreement also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense. 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. |
| |
| 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. |
62
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(8) | Debt (continued) |
| |
| Maturities of Long-term Obligations |
| |
| Long-term obligations at December 31, 2005, mature as follows: |
| | | | | | | | | | | | | | | |
| | Sinking Fund
Requirements
2001 Series A
Bonds | | Sinking Fund
Requirements
2002 Series A
Bonds | | Sinking Fund
Requirements
2002 Series B
Bonds | | Principal
Maturities
CoBank
Promissory
Notes | | Total | |
Year ending
December 31 | | | | | | |
| | | | | |
| | | | | |
| | | | | |
| |
| |
| |
| |
| |
| |
2006 | | | 0 | | | 0 | | | 5,200,000 | | | 3,125,687 | | | 8,325,687 | |
2007 | | | 0 | | | 0 | | | 5,500,000 | | | 8,228,569 | | | 13,728,569 | |
2008 | | | 0 | | | 0 | | | 5,900,000 | | | 3,340,725 | | | 9,240,725 | |
2009 | | | 0 | | | 0 | | | 6,300,000 | | | 3,463,358 | | | 9,763,358 | |
2010 | | | 0 | | | 0 | | | 6,700,000 | | | 3,097,157 | | | 9,797,157 | |
Thereafter | | | 150,000,000 | | | 120,000,000 | | | 16,600,000 | | | 35,402,290 | | | 322,002,290 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| | $ | 150,000,000 | | $ | 120,000,000 | | $ | 46,200,000 | | $ | 56,657,786 | | $ | 372,857,786 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| |
| Short-term obligations |
| |
| Chugach had maintained a $20 million line of credit with CoBank, ACB (CoBank). On October 27, 2005, Chugach reduced the line of credit to $7.5 million due to a decrease in short-term borrowing projections. The CoBank line of credit expires October 31, 2006, subject to annual renewal at the discretion of the parties. Chugach utilized this line of credit in March of 2005, however, the balance was subsequently paid back in the same month. Chugach had an annual line of credit of $20,000,000 available at December 31, 2004, with CoBank. Chugach did not utilize this line of credit in 2004. At December 31, 2005 and 2004, there was no outstanding balance on this line of credit. At December 31, 2005 and 2004, the borrowing rate would have been 5.95% and 3.80%, respectively. In addition, Chugach had an annual line of credit of $50,000,000 available at December 31, 2005 and 2004, with NRUCFC. Chugach did not utilize this line of credit in 2005. At December 31, 2005 and 2004, there was no outstanding balance on this line of credit. At December 31, 2005 and 2004, the borrowing rate would have been 6.10% and 4.05%, respectively. The NRUCFC line of credit expires October 15, 2007. |
| |
| Refinancing |
| |
| On August 31, 2005, Chugach refinanced its $10 million promissory note with CoBank. The new $10 million, 5.50% fixed rate promissory note will mature September 20, 2010 and contains consecutive monthly installment payments commencing October 20, 2005. |
63
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(8) | Debt (continued) |
| |
| 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 2006. |
| |
| The 2002 Series A Bond and the Auction Rate Bonds (collectively the “Bonds”) are unsecured obligations, ranking equally with Chugach’s other unsecured and unsubordinated obligations. In addition, Chugach’s ability is limited to secure obligations for borrowed money or the deferred purchase price of property unless Chugach equally and ratably secures Chugach’s outstanding indebtedness subject to the Amended and Restated Indenture governing the Bonds. |
| |
| The following table provides information regarding auction dates and rates in 2005. |
| | | | |
Auction
Date | | Interest
Rate | |
|
| |
| |
January 26, 2005 | | 2.50 | % | |
February 23, 2005 | | 2.62 | % | |
March 23, 2005 | | 3.00 | % | |
April 20, 2005 | | 3.05 | % | |
May 18, 2005 | | 3.09 | % | |
June 15, 2005 | | 3.22 | % | |
July 13, 2005 | | 3.38 | % | |
August 10, 2005 | | 3.56 | % | |
September 7, 2005 | | 3.65 | % | |
October 5, 2005 | | 3.74 | % | |
November 2, 2005 | | 4.04 | % | |
December 28, 2005 | | 4.40 | % | |
64
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(8) | Debt (continued) |
| |
| Treasury Rate Lock Agreements |
| |
| On March 17, 1999, Chugach entered into a U.S.Treasury rate lock transaction with Lehman Brothers Financial Products Inc., (Lehman Brothers) for the purpose of taking advantage of favorable market interest rates in anticipation of refinancing Chugach’s Series A Bond due 2022 on their optional call date (March 15, 2002). On May 11, 2001, Chugach terminated the $18.7 million 30-year U.S. Treasury portion of the Treasury Rate Lock Agreement in receipt of payment of $10,000 by Lehman. On December 7, 2001, Chugach terminated 50%, or $98.0 million, of the 10-year U.S. Treasury portion of the U.S. Treasury Rate Lock Agreement for a settlement payment of $4 million to Lehman Brothers. Chugach settled the remaining 50% of the 10-year U.S. Treasury portion of the Treasury Rate Lock Agreement for $3 million on December 19, 2001. On January 14, 2002, Chugach entered into an 18-day rate lock agreement with JP Morgan on the 2002 refinancing. Chugach terminated the rate lock on February 1, 2002, which generated a payment to Chugach of $1.2 million. The settlement payments were accounted for as regulatory assets and amortized over the life of the corresponding debt, which was authorized by the RCA in Order U-01-108(26). |
| |
(9) | Fair Value of Long-Term Obligations |
| |
| The estimated fair values (in thousands) of the long-term obligations included in the financial statements at December 31 are as follows: |
| | | | | | | | | | | | | |
| | 2005 | | 2004 | |
| |
| |
| |
| | Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value | |
| | |
| |
| |
| |
| |
Long-term obligations
(including current installments) | | $ | 372,858 | | $ | 390,927 | | $ | 379,289 | | $ | 408,791 | |
| |
| Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions. |
| |
(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 |
65
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(10) | Employee Benefit Plans (continued) |
| |
| for the union plans were approximately $2.4 million, $2.5 million and $2.4 million in 2005, 2004 and 2003, respectively. The Company 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 $1.8 million, $1.6 million and $1.5 million in 2005, 2004 and 2003, respectively, to the NRECA plan. The Company 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, 2005, 2004 and 2003 totaled $3.0 million, $2.9 million and $2.9 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, 2005, 2004 and 2003 totaled $2.0 million, $2.0 million and $1.7 million, respectively. |
| |
| 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, 2005, 2004 and 2003 were $80.7 thousand, $90.1 thousand and $82.2 thousand, respectively. |
| |
| 401(k) Plan |
| |
| Effective March 1, 1988, 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 $14,000, $13,000 and $12,000 in 2005, 2004 and 2003, respectively. |
66
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(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 $40,000,000. Under a worst-case scenario, Chugach could be faced with annual expenditures of approximately $4.7 million as a result of Chugach’s Bradley Lake take-or-pay obligations. Management believes that such expenditures, if any, would be recoverable through the fuel surcharge ratemaking process. Upon the default of a Bradley Lake participant, and subject to certain other conditions, AEA, through Alaska Industrial Development and Export Authority, is entitled to increase each participant’s share of costs pro rata, to the extent necessary to compensate for the failure of another participant to pay its share, provided that no participant’s percentage share is increased by more than 25%. |
| |
| The following represents information with respect to Bradley Lake at June 30, 2005 (the most recent date for which information is available). Chugach’s share of expenses was $4,993,670 in 2005, $4,205,657 in 2004 and $4,212,072 in 2003 and is included in purchased power in the accompanying financial statements. |
| | | | | | | | | |
(In thousands) | | Total | | Proportionate Share | |
| |
| |
| |
|
Plant in service | | $ | 310,463 | | | $ | 94,381 | | |
Accumulated depreciation | | | (94,990) | | | | (28,877) | | |
Long-term debt | | | 125,485 | | | | 129,205 | | |
| | | | | | | | | |
Interest expense | | | 8,553 | | | | 2,600 | | |
| |
| Other electric plant represents Chugach’s share of a Bradley Lake transmission line financed internally and Electric Plant Held for Future Use. |
67
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(12) | 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%). |
| |
| Plant in service in 2005 includes $2,616,854, net of accumulated depreciation of $525,457, which represents Chugach’s share of the Eklutna Hydroelectric Plant. In 2004 plant in service included $2,469,350, net of accumulated depreciation of $432,654. 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 $476,739, $784,264 and $490,338 in 2005, 2004 and 2003, 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. ML&P performs major maintenance at the plant. Chugach personnel perform daily plant inspections, meter reading, monthly report preparation, and other activities as required. |
| |
(13) | Commitments, Contingencies and Concentrations |
| |
| Contingencies |
| |
| Chugach is a participant in various legal actions, rate disputes, personnel matters and claims both for and against Chugach’s interests. Management believes the outcome of any such matters will not materially impact Chugach’s financial condition, results of operations or liquidity. |
| |
| Long-Term Fuel Supply Contracts |
| |
| Chugach has entered into long-term fuel supply contracts from various producers at market terms. The current contracts will expire at the end of the currently committed volumes or the contract expiration dates of 2015 and 2025. The committed volumes for the 2015 contract should be used by early 2011. The currently priced volumes for the 2025 contract should also be used by early 2011, however, there is an additional 120 BCF reserved if satisfactory terms and conditions can be negotiated. In 2005, 88% of our power was generated from gas, while in 2004 and 2003, 86% of our power was generated from gas. Of that gas-fired generation, in 2005 and 2004, 86% took place at Beluga, while in 2003 85% of gas-fired generation took place at Beluga. |
| |
| Concentrations |
| |
| Approximately 70% of Chugach’s employees are represented by the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit |
68
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(13) | Commitments, Contingencies and Concentrations (continued) |
| |
| Agreements (CBA) with the IBEW, which expire on June 30, 2006. The CBA’s are under review at this time. |
| |
| Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts represented $72.1 million or 32.4% of operating revenues in 2005, $62.0 million or 31.2% in 2004 and $55.8 million or 30.8% in 2003. The HEA contract expires January 1, 2014, and the MEA contract expires December 31, 2014. |
| |
| Fuel is purchased directly from Marathon Oil Company, ChevronTexaco, ML&P and ConocoPhillips. The following represents the cost of fuel purchased from these vendors as a percentage of total fuel costs for the years ended December 31: |
| | | | | | | | | | |
| | 2005 | | 2004 | | 2003 | |
| |
| |
| |
| |
| | | | | | | | | | |
Marathon Oil Company | | | 48.8 | % | | 48.8 | % | | 47.4 | % |
Chevron Texaco | | | 19.5 | % | | 19.5 | % | | 20.0 | % |
Municipal Light & Power (ML&P) | | | 15.8 | % | | 15.8 | % | | 16.2 | % |
ConocoPhillips | | | 15.8 | % | | 15.8 | % | | 16.2 | % |
| |
| Cooper Lake Hydroelectric Plant |
| |
| Chugach discovered polychlorinated biphenyls (PCBs) in paint, caulk and grease at the Cooper Lake Hydroelectric plant during initial phases of a turbine overhaul in 2000. A FERC approved plan, prepared in consultation with the Environmental Protection Agency (EPA), was implemented to remediate the PCBs in the plant. In an order in Chugach’s general rate case, Order U-01-108(26), the RCA permitted the costs associated with the overhaul and the PCB remediation to be recovered through rates. The costs of PCB sampling and analysis in Kenai Lake were accounted for as an expense. |
| |
| Legal Proceedings |
| |
| Matanuska Electric Association, Inc., v. Chugach Electric Association, Inc., Superior Court Case No. 3AN-99-8152 Civil |
| |
| In this action filed in 1999, Matanuska Electric Association, Inc. (MEA) alleged that Chugach breached the Power Sales Agreement under which Chugach is obligated to sell MEA power for 25 years, from 1989 through 2014. MEA asserted that Chugach failed to provide it certain information, failed to properly manage Chugach’s long-term debt, and failed to bring Chugach’s base rate action to a Joint Committee before presenting it to the Regulatory Commission of Alaska (RCA). All of MEA’s claims were dismissed by the Superior Court. |
| |
| On April 29, 2002, MEA appealed to the Alaska Supreme Court the Superior Court’s |
69
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(13) | Commitments, Contingencies and Concentrations (continued) |
| |
| dismissal of its claims related to Chugach’s financial management and Chugach’s decision not to bring its base rate action to the Joint Committee before filing with the RCA. Chugach cross-appealed the Superior Court’s decision not to also dismiss the financial management claim on jurisprudential and res judicata grounds. The Alaska Supreme Court, on October 8, 2004, issued an order upholding Chugach’s right to not bring its base rate action to the Joint Committee before filing with the RCA. But the Court rejected Chugach’s cross-appeal and reversed the Superior Court’s decision dismissing MEA’s financial management claim. The Supreme Court remanded that claim to the Superior Court for further proceedings. |
| |
| On January 24, 2005, Chugach filed for summary judgment on that claim asserting that in the 2000 Test Year rate case the RCA had fully reviewed and decided the prudency of Chugach’s financial management. In a decision dated August 22, 2005, the Superior Court granted Chugach’s summary judgment motion, finding that the RCA had adjudicated the question of Chugach’s financial management and that its decision should be given res judicata effect. The Superior Court also found that the RCA had exercised its primary jurisdiction in reviewing Chugach’s financial management, and that its decision should be given deference. |
| |
| The Superior Court entered final judgment on November 10, 2005, after which Chugach sought its costs and fees. On December 14, 2005, the Superior Court entered judgment awarding Chugach fees and costs from MEA in the amount of $104,732, which has not been recorded in the financial statements. |
| |
| On December 9, 2005, however, MEA appealed to the Alaska Supreme Court the Superior Court’s grant of summary judgment. On December 23, 2005, Chugach cross-appealed the Superior Court’s failure to also grant summary judgment based on the doctrine of collateral estoppel. This appeal is pending. Management is uncertain of the outcome of the proceeding before the Supreme Court. No reserves have been established for this matter. |
| |
| Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc. Superior Court Case No. 3AN-04-11776 Civil |
| |
| On October 12, 2004, MEA filed suit in Superior Court alleging that Chugach had violated its bylaws in allocating margins (capital credits) during the years 1998 through 2003. The margins Chugach earns each year are allocated to the customers who contributed them and are booked as capital credits to those customers’ accounts. Capital credits are eventually repatriated to customers at the discretion of the board of directors, typically many years after the margins are earned. |
| |
| In this suit, MEA asks the Court to hold that Chugach breached its bylaws in the manner in which it allocated capital credits in 1998 through 2003. MEA also asks the court to enjoin Chugach to re-calculate MEA’s capital credits applying MEA’s interpretation of Chugach’s |
70
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(13) | Commitments, Contingencies and Concentrations (continued) |
| |
| bylaws and in accordance with what MEA refers to as “generally accepted accounting practices for nonprofit cooperatives and cooperative principles”. The suit also seeks damages in an unspecified amount to compensate MEA for the alleged breach of contract. This matter currently is scheduled for a five-day trial beginning October 9, 2006. Management is vigorously defending against the claim. The ultimate resolution of this matter is not currently determinable. |
| |
| Chugach has certain additional litigation matters and pending claims that arise in the ordinary course of Chugach’s business. In the opinion of management, no individual matter or the matters in the aggregate is likely to have a material adverse effect on Chugach’s results of operations, financial condition or liquidity. |
| |
| Regulatory Cost Charge |
| |
| In 1992 the State of Alaska Legislature passed legislation authorizing the Department of Revenue to collect a Regulatory Cost Charge from utilities in order to fund the governing regulatory commission, which is currently the RCA. The tax is assessed on all retail consumers and is based on kilowatt-hour (kWh) consumption. The 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 $0.000433, effective July 1, 2005. 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. |
71
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2005 and 2004
| |
(13) | 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 a State of Alaska undergrounding requirement, Chugach is permitted to amend its rates by adding a 2% surcharge to its member’s 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. At December 31, 2005, Chugach had collected $1,064,058 from its retail members for this surcharge. |
| |
(14) | Quarterly Results of Operations (unaudited) |
| | | | | | | | | | | | | |
| | 2005 Quarter Ended | |
| |
| |
| | | | | | | | | | | | | |
| | Dec. 31 | | Sept. 30 | | June 30 | | March 31 | |
| |
| |
| |
| |
| |
| | | | | | | | | | | | | |
Operating Revenue | | $ | 63,847,123 | | $ | 54,323,791 | | $ | 50,314,401 | | | 57,212,034 | |
Operating Expense | | | 53,773,333 | | | 49,766,632 | | | 44,308,718 | | | 46,975,282 | |
Net Interest | | | 5,753,831 | | | 5,748,482 | | | 5,597,536 | | | 5,486,205 | |
| |
|
| |
|
| |
|
| |
|
| |
Net Operating Margins | | | 4,319,959 | | | (1,191,323 | ) | | 408,147 | | | 4,750,547 | |
Non-Operating Margins | | | 706,961 | | | 196,363 | | | 166,942 | | | 157,135 | |
| |
|
| |
|
| |
|
| |
|
| |
Assignable Margins | | $ | 5,026,920 | | $ | (994,960 | ) | $ | 575,089 | | $ | 4,907,682 | |
| |
|
| |
|
| |
|
| |
|
| |
| | | | | | | | | | | | | |
| | 2004 Quarter Ended | |
| |
| |
| | | | | | | | | | | | | |
| | Dec. 31 | | Sept. 30 | | June 30 | | March 31 | |
| |
| |
| |
| |
| |
| | | | | | | | | | | | | |
Operating Revenue | | $ | 55,221,563 | | $ | 47,991,700 | | $ | 46,388,411 | | $ | 51,644,941 | |
Operating Expense | | | 46,010,061 | | | 43,778,224 | | | 41,441,061 | | | 42,110,691 | |
Net Interest | | | 5,512,148 | | | 5,373,404 | | | 5,254,092 | | | 5,352,221 | |
| |
|
| |
|
| |
|
| |
|
| |
Net Operating Margins | | | 3,699,354 | | | (1,159,928 | ) | | (306,742 | ) | | 4,182,029 | |
Non-Operating Margins | | | 805,322 | | | 145,698 | | | 122,788 | | | 113,935 | |
| |
|
| |
|
| |
|
| |
|
| |
Assignable Margins | | $ | 4,504,676 | | $ | (1,014,230 | ) | $ | (183,954 | ) | $ | 4,295,964 | |
| |
|
| |
|
| |
|
| |
|
| |
72
Item 9 - Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure
None
Item 9A – Disclosure Controls and Procedures
Evaluation of Controls and Procedures
As of the end of the period covered by this report, we evaluated the effectiveness of the design and operation of our disclosure controls and procedures. Our chief executive officer (CEO) and chief financial officer (CFO) supervised and participated in this evaluation. Based on this evaluation, our CEO and CFO each concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic reports to the SEC. The design of any system of controls is based in part upon various assumptions about the likelihood of future events, and there can be no assurance that any of our plans, products, services or procedures will succeed in achieving their intended goals under future conditions. In addition, there have been no significant changes in our internal controls or in other factors known to management that could significantly affect our internal controls subsequent to our most recent evaluation.
Chugach is in the process of implementing the requirements of Section 404 of the Sarbanes-Oxley Act of 2002, which requires our management to assess the effectiveness of our internal controls over financial reporting and include an assertion in our annual report as to the effectiveness of our controls. In addition, our independent registered public accounting firm, KPMG LLP, will be required to attest to whether our assessment of the effectiveness of our internal controls over financial reporting is fairly stated in all material respects and separately report on whether it believes Chugach maintained, in all material respects, effective internal controls over financial reporting as of December 31, 2007. Chugach is in the process of performing the system and process documentation, evaluation and testing required for management to make this assessment and for KPMG LLP to provide its attestation report. This process will continue to require significant amounts of management time and resources. In the course of evaluation and testing, management may identify deficiencies that will need to be addressed and remediated.
Item 9B – Other Items
On January 26, 2006, Chugach gave notice as provided in Section 14(b) of the Alaska Railbelt Energy Authority of its withdrawl 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.
73
PART III
Item 10 - Directors and Executive Officers of the Registrant
Management
Chugach operates under the direction of a Board of Directors that is elected at large by our membership. Day-to-day business and affairs are administered by the Chief Executive Officer. Our seven-member Board of Directors sets policy and provides direction to the Chief Executive Officer. The following table sets forth certain information with respect to our executive officers and directors.
| | | | | | | | | | |
| Name | | | | Age | | | | Position | |
| | |
| | |
|
William R. Stewart | | 59 | | Interim-Chief Executive Officer |
Lee D. Thibert | | 50 | | Sr. Vice President Power Delivery |
Michael R. Cunningham | | 56 | | Chief Financial Officer |
Bradley W. Evans | | 51 | | Sr. Vice President Power Supply |
Alan Christopherson | | 53 | | Chairman and Director |
David Cottrell | | 58 | | Secretary and Director |
Elizabeth Vazquez | | 54 | | Treasurer and Director |
Bruce Davison | | 57 | | Director |
Uwe Kalenka | | 61 | | Director |
Jeffrey W. Lipscomb | | 55 | | Director |
Ray Kreig | | 59 | | Director |
Executive Officers
William R. Stewart was appointed Interim-Chief Executive Officer on September 3, 2005, upon the resignation of former Chief Executive Officer, Joe Griffith. Prior to that appointment, Mr. Stewart had served as General Manager, Corporate Services Division since January 31, 2005. Prior to that appointment he had served as Sr. Vice President, Administration since June 5, 2002. Prior to that, he had served as Executive Manager, Retail Services since a June 1, 1997 reorganization. Prior to that, he was Executive Manager, Administration from July 1987 to June 1, 1997. He was our Division Director of Administration from January 1984 to July 1987 and Staff Assistant to the General Manager of Chugach from November 1982 to January 1984. He has been employed at Chugach since 1969.
Lee D. Thibert was appointed Sr. Vice President, Power Delivery in a March 20, 2006, reorganization. Prior to that appointment he had served as General Manager, Distribution Division since January 31, 2005. Prior to that appointment he had served as Sr. Vice President, Power Delivery since June 3, 2002. Prior to that, he had served as Executive Manager, Transmission & Distribution Network Services since June 1, 1997 reorganization. Prior to that, he was Executive Manager, Operating Divisions from June of 1994. Before moving up to the Executive Manager position, he served as Director of Operations from May 1987.
74
Michael R. Cunningham was appointed Chief Financial Officer on June 5, 2002. Prior to that appointment he had served as Controller since 1986. Prior to that he was Budget Analyst and Manager of Accounting since beginning his Chugach employment in 1982. Prior to his Chugach employment, Mr. Cunningham spent 15 years in various capacities with Pacific Northwest Bell Telephone Company.
Bradley W. Evans was appointed Sr. Vice President, Power Supply in a March 20, 2006, reorganization. Prior to that appointment he had served as General Manager, G&T Division since January 31, 2005. Prior to that appointment he had served as Sr. Vice President, Energy Supply since June 5, 2002. Prior to that, he had served as Director of Energy Supply since February 26, 2001. Prior to his current Chugach employment, Mr. Evans served as Manager, System Dispatch for Golden Valley Electric Association.
Board of Directors
Alan Christopherson, P.E. was elected to the board in 2005. He is a Principal Civil Engineer, Senior Partner and Treasurer with the consulting civil engineering firm, PND Engineers, Inc. He currently serves as Chairman of the Board. He is also chair of the Operations Committee.
Elizabeth Vazquez was elected to the board in 2005. She is an attorney with the State of Alaska. She chairs the board’s Finance Committee.
Uwe Kalenka was elected to the board in 2005. He is a self-employed property manager.
Bruce Davison was appointed to the Board of Directors in June 1997 to fill a vacancy, elected to the board in 1998 and re-elected in 2001 and 2004. Prior to his appointment, he served two years on our Bylaws Committee. He has served as board Chairman, Vice Chairman and Secretary. He is an attorney and professional engineer.
Jeff Lipscomb was elected director in April 2000 and re-elected in 2003. Mr. Lipscomb is a professional mechanical engineer and project management consultant. He is the principal and owner of JWL Engineering. He is currently a Trustee and Chair of the Audit Committee of the Northwest Public Power Association.
Dave Cottrell was elected to the board in 2001 and re-elected in 2004. He currently chairs the board’s Audit committee. He has previously served as Vice President of the Board. Mr. Cottrell is a founding member and past managing partner of Mikunda Cottrell & Co., Certified Public Accountants. He is currently the president and managing director of Mikunda, Cottrell, Accountants and Consultants.
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
75
website atwww.chugachelectric.com.
Audit Committee Financial Expert
Chugach is a cooperative and each board member must be a member of the cooperative. The Board of Directors relies on the advice of all members of the Finance and Audit Committees, therefore the Board of Directors has not formally designated an Audit Committee financial expert.
Item 11 - Executive Compensation
Cash Compensation
The following table sets forth all remuneration paid by us for the last three years to each of our five executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2005, and for all such executive officers as a group:
| | | | | | | | | | | | | | | | |
Name | | Principal Position | | Year | | Total
Remuneration | | Bonus | | Total | |
| |
| |
| |
| |
| |
| |
|
William R. Stewart | | Interim-Chief Executive Officer | | 2005 | | | $ | 171,387 | | | $ | 3,503 | | $ | 174,890 | |
| | | | 2004 | | | $ | 182,741 | | | $ | 5,438 | | $ | 188,179 | |
| | | | 2003 | | | $ | 161,879 | | | $ | 3,712 | | $ | 165,591 | |
| | | | | | | | | | | | | | �� | | |
Lee D. Thibert | | Sr. Vice President , | | 2005 | | | $ | 165,824 | | | $ | 5,197 | | $ | 171,021 | |
| | Power Delivery | | 2004 | | | $ | 170,312 | | | $ | 8,158 | | $ | 178,470 | |
| | | | 2003 | | | $ | 149,103 | | | $ | 5,939 | | $ | 155,042 | |
| | | | | | | | | | | | | | | | |
Michael R. Cunningham | | Chief Financial Officer | | 2005 | | | $ | 164,836 | | | $ | 2,970 | | $ | 167,806 | |
| | | | 2004 | | | $ | 155,955 | | | | — | | $ | 155,955 | |
| | | | 2003 | | | $ | 132,316 | | | | — | | $ | 132,316 | |
| | | | | | | | | | | | | | | | |
Bradley W. Evans | | Sr. Vice President, | | 2005 | | | $ | 156,426 | | | $ | 3,712 | | $ | 160,138 | |
| | Power Supply | | 2004 | | | $ | 148,137 | | | $ | 7,154 | | $ | 155,291 | |
| | | | 2003 | | | $ | 135,398 | | | $ | 5,197 | | $ | 140,595 | |
Directors are compensated for their services at the rate of $200 per board meeting or other meeting at which they are representing the Association in an official capacity within the State of Alaska, and $250 per day when attending meetings outside the State, including each day of travel, plus reasonable out of pocket expenses, up to a maximum of 70 meetings per year for a director and 85 meetings per year for the Chairman.
76
Compensation Pursuant to Plans
We have elected to participate in the National Rural Electric Cooperative Association (NRECA) Retirement and Security Program (the “Plan”), a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. The Plan is intended to be a qualified pension plan under Section 401(a) of the Code. All our employees not covered by a union agreement become participants in the Plan on the first day of the month following completion of one year of eligibility service. An employee is credited with one year of eligibility service if he or she completes 1,000 hours of service either in his or her first twelve consecutive months of employment or in any calendar year for us or certain other employers in rural electrification (related employers). Pension benefits vest at the rate of 10% for each of the first four years of vesting service and become fully vested and nonforfeitable on the earlier of the date a participant has five years of vesting service or the date the participant attains age fifty-five while employed by us or a related employer. A participant is credited with one year of vesting service for each calendar year in which he or she performs at least one hour of service for us or a related employer. Pension benefits are generally paid upon the participant’s retirement or death. A participant may also elect to receive pension benefits while still employed by us if he or she has reached his normal retirement date by completing thirty years of benefit service (defined below) or, if earlier, by attaining age sixty-two. A participant may elect to receive actuarially reduced early retirement pension benefits before his or her normal retirement date provided he or she has attained age fifty-five.
Pension benefits paid in normal form are paid monthly for the remaining lifetime of the participant. Unless an actuarially equivalent optional form of benefit payment to the participant is elected, upon the death of a participant the participant’s surviving spouse will receive pension benefits for life equal to 50% of the participant’s benefit. The annual amount of a participant’s pension benefit and the resulting monthly payments the participant receives under the normal form of payment are based on the number of his or her years of participation in the Plan (benefit service) and the highest five-year average of the annual rate of his or her base salary during the last ten years of his or her participation in the Plan (final average salary). Annual compensation in excess of $200,000, as adjusted by the Internal Revenue Service for cost of living increases, is disregarded after January 1, 1989. The participant’s annual pension benefit at his or her normal retirement date is equal to the product of his or her years of benefit service times final average salary times 2%. In 1998, NRECA notified us that there were employees whose pension benefits from NRECA’s Retirement & Security Program would be reduced because of limitations on retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA made available a Pension Restoration Severance Pay Plan and a Pension Restoration Deferred Compensation Plan for cooperatives to adopt in order to make employees whole for their lost benefits. In May 1998, we adopted both of these plans to protect the benefits of current and future employees whose pension benefits would be reduced because of these limitations.
On October 16, 2002, the Board of Directors authorized an amendment to the Plan with an effective date of November 1, 2002. Under the amended Plan, the retirement benefit payable to any Participant whose retirement is postponed beyond his or her Normal Retirement Date shall
77
be computed as of the Participant’s actual retirement date. The retirement benefit payable to any Participant under the 30-Year Plan shall be computed as of the first day of the month in which the Participant’s actual retirement date occurs.
The following table sets forth the estimated annual pension benefit payable at normal retirement date for participants in the specified final average salary and years of benefit service categories:
| | | | | | | | | | | | | | | | | | | | | |
| | | Years of Benefit Service | |
| | |
| |
Final Average
Salary | | | 15 | | | 20 | | | 25 | | | 30 | | | 35 | | | 40 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
$125,000 | | $ | 37,500 | | $ | 50,000 | | $ | 62,500 | | $ | 75,000 | | $ | 87,500 | | $ | 100,000 | |
$150,000 | | $ | 45,000 | | $ | 60,000 | | $ | 75,000 | | $ | 90,000 | | $ | 105,000 | | $ | 120,000 | |
$175,000 | | $ | 52,500 | | $ | 70,000 | | $ | 87,500 | | $ | 105,000 | | $ | 122,500 | | $ | 140,000 | |
$200,000 | | $ | 60,000 | | $ | 80,000 | | $ | 100,000 | | $ | 120,000 | | $ | 140,000 | | $ | 160,000 | |
The annual pension benefits indicated above are the joint and surviving spouse life annuity amounts payable by the Plan, and they are not subject to any deduction for Social Security or other offset amounts.
Benefit service as of December 31, 2005 taken into account under the Plan for the executive officers is shown below. Base salary for 2005 taken into account under the Plan for purposes of determining final average salary is also included.
| | | | | | | | | | | | | | | |
| Name | | | | Principal Position | | | | Benefit Service | | | | | Covered
Compensation | |
| | |
| | | |
| | | | |
| |
| | | | | | | | | | | | | | | |
Lee D. Thibert | | Sr. Vice President
Power Delivery
| | 17 years, 7 months | | 156,561 |
Michael R. Cunningham | | Chief Financial Officer | | 22 years, 1 month | | 140,670 |
William R. Stewart* | | Interim-Chief Executive
Officer
| | 3 year, 2 months | | 162,406 |
Bradley W. Evans | | Sr. Vice President
Power Supply | | 4 years, 10 months | | 150,009 |
* Under the Plan in effect prior to November 1, 2002, Mr. Stewart had 30 years of service as of April 1, 2000, and was no longer eligible to receive contributions on his behalf to the Plan. Under the terms of the amendment to the Plan, approved by the Board of Directors on October 16, 2002, Mr. Stewart was re-enrolled effective November 1, 2002.
In May 2005, Chief Executive Officer Joe Griffith resigned effective September 2, 2005. The Board of Directors appointed William R. Stewart as Interim-Chief Executive Officer effective September 3, 2005, at an annual salary of $162,406. Mr. Stewart’s First Amended Memorandum of Agreement is included as an exhibit to this filing.
78
Item 12 - Security Ownership of Certain Beneficial Owners and Management
Not Applicable
Item 13 - Certain Relationships and Related Transactions
Not Applicable
Item 14 – Principal Accountant Fees and Services
The Audit Committee of the Board of Directors retained KPMG LLP as the independent certified public accountants for Chugach during the fiscal year ended December 31, 2005.
Fees and Services
KPMG LLP has provided certain audit, audit-related, tax and non-audit services, the fees for which are as follows:
| | | | | | | |
| | 2005 | | 2004 | |
| |
| |
| |
| | | | | |
Audit services and quarterly reviews | | $ | 104,753 | | $ | 93,075 | |
Audit-related services (Single audit and employee benefit plans) | | $ | 18,050 | | $ | 8,250 | |
Non-audit services: | | | | | | | |
Tax consulting and return preparation | | $ | 2,375 | | $ | 2,250 | |
The Audit Committee of the Board of Directors has a policy to pre-approve all invoices by Chugach’s independent public accountants. All invoices from KPMG LLP for fiscal years ended December 31, 2005 and 2004 were approved by the Audit Committee.
79
PART IV
Item 15 – Exhibits and Financial Statement Schedules
| | |
| | Page |
Financial Statements
| |
| |
Included in Part IV of this Report: | |
| Independent Auditors’ Report | 41 |
| Balance Sheets, December 31, 2005 and 2004 | 42-43 |
| Statements of Revenues, Expenses and Patronage Capital,
Years ended December 31, 2005, 2004 and 2003 | 44 |
| Statements of Cash Flows,
Years ended December 31, 2005, 2004 and 2003 | 45 |
| Notes to Financial Statements | 46-72 |
| | |
Financial Statement Schedules | |
| | |
| Included in Part IV of this Report: | |
| Independent Auditors’ Report | 81 |
| Schedule II - Valuation and Qualifying Accounts,
Years ended December 31, 2005, 2004 and 2003 | 82 |
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.
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Report of Independent Registered Public Accounting Firm
The Board of Directors
Chugach Electric Association, Inc.
Under date of February 27, 2006, we reported on the balance sheets of Chugach Electric Association, Inc. (the Company) as of December 31, 2005 and 2004, and the related statements of revenue, expenses and patronage capital, and cash flows for each of the years in the three-year period ended December 31, 2005. In connection with our audits of the aforementioned financial statements, we also audited the related financial statement schedules. These financial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statement schedules based on our audits.
In our opinion, such financial statement schedules, 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
KPMG, LLP
Anchorage, Alaska
February 27, 2006
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Schedule II
CHUGACH ELECTRIC ASSOCIATION, INC.
Valuation and Qualifying Accounts
| | | | | | | | | | | | | |
| | Balance at
Beginning
Of year | | Charged
To costs
And expenses | | Deductions | | Balance
at end
of year | |
| |
| |
| |
| |
| |
Allowance for doubtful accounts: | | | | | | | | | | | | | |
Activity for year ended: | | | | | | | | | | | | | |
December 31, 2005 | | | (364,261 | ) | | (270,713 | ) | | 236,653 | | | (398,321 | ) |
December 31, 2004 | | | (273,793 | ) | | (202,533 | ) | | 112,065 | | | (364,261 | ) |
December 31, 2003 | | | (313,545 | ) | | (326,842 | ) | | 366,594 | | | (273,793 | ) |
82
EXHIBITS
Listed below are the exhibits, which are filed as part of this Report:
| | |
Exhibit
Number | | | Description | |
| |
|
|
|
3.1 | | Articles of Incorporation of the Registrant. (13) |
| | |
3.2 | | Bylaws of the Registrant. (18) |
| | |
4.11 | | Tenth Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. (11) |
| | |
4.12 | | Eleventh Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association. (14) |
| | |
4.13 | | Amended and Restated Indenture between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. (11) |
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4.14 | | Form of 2001 Series A Bond due 2011. (11) |
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4.15 | | Form of 2002 Series A Bond due 2012. (14) |
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4.16 | | Form of 2002 Series B Bond due 2012. (14) |
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10.1 | | Wholesale Power Agreement between the Registrant and the City of Seward. (1) |
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10.2 | | Joint Use Agreement between the Registrant and the City of Seward dated effective as of September 11, 1998. (1) |
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10.3 | | Net Billing Agreement among the Registrant and the City of Seward dated effective as of September 11, 1998. (1) |
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10.4 | | Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective as of September 11, 1998. (8) |
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10.4.1 | | Amendment No. 1 to Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective as of July 9, 2001. (13) |
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10.5 | | Agreement for Sale of Electric Power and Energy by and among the Registrant, Homer Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated September 27, 1985. (1) |
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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) |
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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) |
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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) |
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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) |
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10.7 | | Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc. dated May 18, 1988. (1) |
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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) |
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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) |
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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) |
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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) |
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10.8 | | Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. dated April 21, 1989. (1) |
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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) |
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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) |
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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) |
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10.9 | | Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and ARCO Alaska, Inc. dated October 3, 1991. (1) |
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10.10 | | Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company dated September 26, 1988. (1) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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10.14 | | Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Chevron USA, Inc. dated September 25, 1990. (1) |
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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) |
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10.16 | | Addendum No. 1 to the Alaska Intertie Agreement-Reserve Capacity and Operating Reserve Responsibility dated December 23, 1985. (1) |
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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) |
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10.18 | | Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. (11) |
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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) |
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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) |
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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) |
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10.22 | | Amendment No. 1 to the 1993 Alaska Intertie Project Participants Agreement dated December 10, 1999. (11) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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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) |
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10.30 | | Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated December 2, 1983. (1) |
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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) |
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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) |
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10.31 | | Gas Transportation Agreement by and among the Registrant, Alaska Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992. (1) |
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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) |
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10.33 | | Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. (3) |
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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) |
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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) |
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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) |
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10.37 | | Daves Creek Substation Agreement between the Registrant and the Alaska Energy Authority dated March 13, 1992. (1) |
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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) |
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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) |
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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) |
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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) |
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10.40 | | Lease Amendment between the Registrant and Standard Oil Company of California dated June 1, 1975. (1) |
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10.41 | | Lease Amendment between the Registrant and Chevron USA, Inc. dated September 1, 1985. (1) |
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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) |
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10.44 | | Line of Credit Agreement and Promissory Note between the Registrant and the National Bank for Cooperatives dated May 5, 1993. (1) |
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10.44.1 | | Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated March 11, 1994. (1) |
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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) |
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10.44.3 | | Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated May 1, 1995. (1) |
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10.44.4 | | Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated May 15, 1995. (1) |
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10.44.5 | | Amendment to Line of Credit Agreement between the Registrant and CoBank, ACB dated September 30, 2000. (10) |
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10.44.6 | | Amendment to Line of Credit Agreement between the Registrant and CoBank, ACB dated December 27, 2002. (18) |
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10.44.7 | | Promissory Note and Consolidating Committed Resolving Credit Supplement between the Registrant and CoBank, ACB dated May 3, 2005. (22) |
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10.45.1 | | Master Loan Agreement between the Registrant and CoBank, ACB dated December 27, 2002. (17) |
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10.45.2 | | Promissory Note and Consolidating Term Loan Supplement between the Registrant and CoBank, ACB dated December 27, 2002. (17) |
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10.45.3 | | Master Loan Agreement between the Registrant and CoBank, ACB dated May 3, 2005 (22) |
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10.45.4 | | Promissory Note and Supplement between the Registrant and CoBank, ACB dated August 24, 2005. (23) |
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10.47 | | Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 15, 2002. (17) |
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10.52 | | Employment Agreement between the Registrant and Evan J. Griffith dated effective April 21, 2004. (20) |
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10.53 | | First Amended Memorandum of Agreement between the Registrant and William R. Stewart dated effective March 17, 2006. |
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14 | | Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. (21) |
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31.1 | | Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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31.2 | | Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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32.1 | | Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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32.2 | | Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |
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| | (1) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1996. |
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| | (2) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 1997. |
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| | (3) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1997. |
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| | (4) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 1998. |
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| | (5) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1998. |
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| | (6) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1998. |
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| | (7) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 1999. |
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| | (8) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999. |
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| | (9) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2000. |
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| | (10) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2000. |
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| | (11) Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (File No. 333-57400) dated March 22, 2001. |
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| | (12) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2001. |
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| | (13) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2001. |
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| | (14) Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (File No. 333-75840) dated December 21, 2001. |
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| | (15) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2002. |
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| | (17) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2002. |
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| | (18) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2003. |
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| | (19) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003. |
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| | (20) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2004. |
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| | (21) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2004. |
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| | (22) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2005. |
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| | (23) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2005. |
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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 onMarch 22, 2006.
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| CHUGACH ELECTRIC ASSOCIATION, INC. |
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| By: | /s/ William R. Stewart |
| | William R. Stewart, Interim-Chief Executive Officer |
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| Date: | March 22, 2006 |
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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 22, 2006, by the following persons on behalf of the registrant in the capacities indicated:
| | |
/s/ William R. Stewart | | Interim-Chief Executive Officer |
William R. Stewart | | (Principal Executive Officer) |
| | Sr. Vice President, Administration |
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/s/ Lee D. Thibert | | |
Lee D. Thibert | | Sr. Vice President, Power Delivery |
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/s/ Michael R. Cunningham | | |
Michael R. Cunningham | | Chief Financial Officer |
| | (Principal Financial Officer) |
| | (Principal Accounting Officer) |
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/s/ Bradley W. Evans | | |
Bradley W. Evans | | Sr. Vice President, Power Supply |
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/s/ Alan Christopherson | | |
Alan Christopherson | | Director & Chairman of the Board |
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/s/ David Cottrell | | |
David Cottrell | | Director & Secretary of the Board |
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/s/ Elizabeth Vazquez | | |
Elizabeth Vazquez | | Director & Treasurer of the Board |
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/s/ Bruce Davison | | |
Bruce Davison | | Director |
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/s/ Jeffrey Lipscomb | | |
Jeffrey Lipscomb | | Director |
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/s/ Uwe Kalenka | | |
Uwe Kalenka | | Director |
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/s/ Ray Kreig | | |
Ray Kreig | | Director |
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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 2005 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.
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