Attached files
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2009
or
o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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For the transition period from
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to
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Commission file number 33-42125
Chugach Electric Association, Inc.
(Exact name of registrant as specified in its charter)
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Alaska
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92-0014224
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(State or other jurisdiction of
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(I.R.S. Employer
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incorporation or organization)
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Identification No.)
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5601 Electron Dr., Anchorage, Alaska
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99518
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(Address of principal executive offices)
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(Zip Code)
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Registrant’s telephone number, including area code
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(907) 563-7494
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Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which registered
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N/A
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N/A
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Securities registered pursuant to Section 12(g) of the Act:
N/A
(Title of class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
o Yes x No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
x Yes o No
Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
x Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
o Yes o No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large accelerated filer o
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Accelerated filer o
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Non-accelerated filer x
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Smaller reporting company o
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes xNo
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.
N/A
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the last practicable date.
NONE
CHUGACH ELECTRIC ASSOCIATION, INC.
2009 Form 10-K Annual Report
Table of Contents
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PART I
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Page
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Item 1
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3
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Item 1A
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12
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Item 1B
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17
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Item 2
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17
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Item 3
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26
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Item 4
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26
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PART II
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Item 5
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26
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Item 6
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27
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Item 7
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28
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Item 7A
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51
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Item 8
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52
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Item 9
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88
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Item 9A
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88
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Item 9B
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89
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PART III
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Item 10
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89
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Item 11
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93
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Item 12
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99
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Item 13
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99
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Item 14
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99
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PART IV
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Item 15
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100
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115
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CAUTION REGARDING FORWARD-LOOKING STATEMENTS
Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements, that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. Chugach Electric Association, Inc. (Chugach) undertakes no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this report or the effect of those events or circumstances on any of the forward-looking statements contained in this report, except as required by law.
PART I
Item 1 - Business
General
Chugach was organized as an Alaska electric cooperative in 1948. Cooperatives are business organizations that are owned by their members. As not-for-profit organizations (Internal Revenue Code 501 (c)(12)), cooperatives are structured to provide services to their members at cost, in part by eliminating the need to produce profits or a return on equity other than for reasonable reserves and margins. Today, cooperatives in general operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and credit. All cooperatives are based upon similar principles and legal foundations. Because members’ equity is not considered an investment, a cooperative’s objectives and policies are oriented to serving member interests, rather than maximizing return on investment.
Chugach makes its current and periodic reports available, free of charge, on its website at www.chugachelectric.com as soon as practicable after filing with the Securities and Exchange Commission (SEC). Our website provides a link to the SEC website.
Chugach is the largest electric utility in Alaska. We are engaged in the generation, transmission and distribution of electricity to approximately 81,047 service locations in the Anchorage and upper Kenai Peninsula areas. We also provide service to three wholesale customers. Through an interconnected regional electrical system, our energy is distributed throughout Alaska’s Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska’s largest cities, Anchorage and Fairbanks. Neither Chugach nor any other electric utility in Alaska has any connection to the electric grid of the continental United States or Canada. Our principal executive offices are located at 5601 Electron Drive, Anchorage, Alaska 99518. Our telephone number is (907) 563-7494.
Chugach is a rural electric cooperative that is exempt from federal income taxation as an organization described in Section 501(c)(12) of the Internal Revenue Code (Code). Alaska electric cooperatives must pay to the State of Alaska, a gross receipts tax in lieu of state and local ad valorem, income and excise taxes, a tax at the rate of $0.0005 per kilowatt-hour (kWh) of electricity sold in the retail market during the preceding year. This tax is accrued monthly and remitted annually. In addition, we currently collect a regulatory cost charge (RCC) of $0.000432 per kWh of retail electricity sold. This charge is assessed to fund the operations of the Regulatory Commission of Alaska (RCA). This tax is collected monthly and remitted to the State of Alaska quarterly. We also collect sales tax on retail electricity sold to Kenai Peninsula and Whittier consumers. This tax is also collected monthly and remitted to the Kenai Peninsula Borough quarterly. These taxes are a direct pass-through to consumer bills and therefore do not impact our margins.
We had 316 full-time employees as of March 1, 2010. Approximately 70 percent of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW, which expire on June 30, 2010. We also have an agreement with the Hotel Employees & Restaurant Employees (HERE) which also expires on June 30, 2010. On February 24, 2010, the Board of Directors approved an extension of the IBEW Collective Bargaining Unit Agreements. The three extensions provide no wage increase in the first year and are attached to the Consumer Price Index (CPI) in the second and third years, with a floor on the minimum increase and a cap on the maximum increase. The wage increases also have an indirect connection to Chugach’s financial performance. The contract extensions expire on June 30, 2013. We believe our relationship with our employees is good.
Through direct service to retail customers and indirectly through wholesale and economy energy sales, we provide some or all of the electricity used by approximately two-thirds of Alaska’s electric customers. We supply much of the power requirements of three wholesale customers, Matanuska Electric Association (MEA), Homer Electric Association (HEA) and the City of Seward (Seward). We sell available generation in excess of our own needs to produce electric energy for sale to Golden Valley Electric Association, Inc. (GVEA). In addition, on a periodic basis, we provide electricity to Anchorage Municipal Light & Power (AML&P or ML&P).
Our members are the consumers of the electricity sold by us. As of December 31, 2009, we had three major wholesale customers and 66,021 retail members receiving service at approximately 81,047 service locations. No individual retail customer receives more than 5 percent of our power. Our customers’ requirements for capacity and energy generally are seasonal and increase in fall and winter as home heating and lighting needs increase and then decline in the spring and summer as the weather becomes milder and hours of daylight increase.
Our customers are billed on a monthly basis per a tariff rate for electrical power consumed during the preceding period. Billing rates are approved by the RCA (see “Rate Regulation and Rates” below).
Base rates (derived on the basis of historic cost of service including margins) are established to generate revenues in excess of current period costs in any year and such excess is designated on our Statements of Revenues, Expenses and Patronage Capital as “assignable margins.” Retained assignable margins are designated on our balance sheet as “patronage capital” that is assigned to each member on the basis of patronage. Patronage capital is held for the account of the members without interest and returned when the board of directors of Chugach deems it appropriate to do so.
We have 530.1 megawatts (MW) of installed generating capacity provided by 17 generating units at our five owned power plants: Beluga Power Plant, Bernice Lake Power Plant, International Station Power Plant (historically known as “IGT”), Cooper Lake Hydroelectric Project and Eklutna Hydroelectric Project, in which we own a 30 percent interest. Approximately 85 percent (by rated capacity) of our generating capacity is fueled by natural gas, which we purchase under long-term gas contracts. The rest of our generating resources are hydroelectric facilities. In 2009, 90 percent of our power was generated from gas, which included power generated at Nikiski, and 83 percent of that gas-fired generation took place at Beluga. The Bradley Lake Hydroelectric Project provides up to 27.4 MW for our retail customers and up to 24.1 MW for our wholesale customers. For more information concerning Bradley Lake, see “Item 2 – Properties – Other Property – Bradley Lake.” We also purchase approximately 40 MW from the Nikiski power plant on the Kenai Peninsula. We operate 1,685 miles of distribution line and 533 miles of transmission line, which includes 128 miles of leased transmission lines and Chugach’s share of the Eklutna transmission line. For the year ended December 31, 2009, we sold 2.5 billion kWh of electrical power.
Customer Revenue From Sales
The following table shows the megawatt-hour (MWh) energy sales to and electric revenues from our retail, wholesale, and economy energy customers for the year ended December 31, 2009:
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MWh
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2009 Revenues
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Percent of Sales Revenue
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Direct retail sales:
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Residential
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551,740 | $ | 82,365,366 | 28 | % | |||||||
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Commercial
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631,965 | 79,735,641 | 28 | % | ||||||||
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Total
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1,183,705 | 162,101,007 | 56 | % | ||||||||
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Wholesale sales:
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MEA
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740,358 | 69,685,271 | 24 | % | ||||||||
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HEA
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472,136 | 42,865,550 | 15 | % | ||||||||
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Seward
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62,509 | 5,711,358 | 2 | % | ||||||||
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Total
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1,275,003 | 118,262,179 | 41 | % | ||||||||
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Economy energy/other sales1
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76,968 | 7,280,870 | 3 | % | ||||||||
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Total from sales
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2,535,676 | 287,644,056 | 100 | % | ||||||||
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Miscellaneous energy revenue
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2,603,252 | |||||||||||
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Total energy revenues
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$ | 290,247,308 | ||||||||||
1Economy energy/other sales were made to GVEA and AML&P.
Retail Customers
Service Territory
Our retail service area covers the populated areas of Anchorage (other than downtown Anchorage) as well as remote mountain areas and villages. The service area ranges from the northern Kenai Peninsula on the south, to Tyonek on the west, to Whittier on the east and to the Glenn Highway on the north.
Customers
As of December 31, 2009, we had 66,021 members receiving power from approximately 81,047 services (some members are served by more than one service). 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 percent of our revenues.
Wholesale Customers
We are the principal supplier of power to MEA, HEA and Seward under separate wholesale power contracts. For 2009, our wholesale power contracts, including the fuel and purchased power components, produced $118.3 million in revenues, representing 41 percent of our total revenues and 50 percent of our total MWh sales to customers.
MEA
We currently have a power sales contract with Alaska Electric Generation & Transmission Cooperative, Inc., (AEG&T) for firm, all-requirement sales to MEA. In 2009, sales to MEA represented approximately 29 percent of Chugach’s total sales of energy (including both retail and wholesale). AEG&T is a generation and transmission cooperative that was formed by MEA and HEA in the mid 1980’s. Under this contract, we sell power to AEG&T for resale to MEA. Under this contract, MEA is obligated to purchase all of its electric power and energy requirements from us. MEA had the right, on advance notice given after RCA approval, to convert to a net-requirements purchaser of power, and as such MEA would have been 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 could have been up to five years after RCA approval, depending on which non-Chugach resources MEA proposed to use to satisfy its power needs. MEA did not invoke this right. If MEA had converted to a net-requirements purchaser under the contract, MEA could not have reduced its payment for power that it purchases from us below a certain minimum amount. MEA would have been required to pay demand charges based upon the highest post-1985 historical coincident peak on the MEA system. Therefore, if MEA had converted to net-requirements service, we would have continued to recover all or substantially all of the fixed costs now assigned to it. Also, our revenues from energy sales to MEA would have partially declined in proportion to the reduction in the energy sold, but this decline would have been offset to an extent by savings in the variable costs associated with energy production.
MEA also had 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. MEA did not invoke this right. The MEA contract is in effect through December 31, 2014. Under our contract, MEA is obligated to pay us for power sold to AEG&T even if AEG&T does not pay.
Section 12(c) of the MEA/Chugach Power Sales Agreement requires the parties to meet no later than ten years prior to the termination date of the Agreement to discuss possible renewal, extension or modification of the Agreement, as well as the desires and potential circumstances of all parties following the termination date. Pursuant to this provision of the contract, Chugach and MEA met on October 27, 2004. 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.
On August 5, 2008, Chugach and AML&P invited MEA to participate in the development of a gas-fired generation plant near Chugach’s Anchorage headquarters. On November 21, 2008, MEA elected to not participate in the project. At an August 26, 2009, Chugach Board of Directors’ meeting and in a letter dated September 3, 2009, MEA’s then Interim General Manager advised Chugach that MEA desires to open discussions regarding power sales possibilities beyond 2014.
HEA
We had a power sales contract with AEG&T for firm, partial- requirement sales to HEA until June 19, 2002, when 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 (discussed below). Chugach has not experienced a decline in revenue as a result of this transfer. Under our contract, HEA is obligated to pay us for the power sold to AEEC even if AEEC does not pay. Under this contract, HEA is obligated (through AEEC) to take or pay for 73 MW 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 2009, sales to HEA represented approximately 19 percent of Chugach’s total sales of energy (including both retail and wholesale).
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, provided HEA supplies the fuel, 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 with HEA terminates. In a letter dated January 9, 2007, HEA notified Chugach that HEA would not seek to renew, extend or modify the current Agreement for Sale of Electric Power and Energy (the Agreement) when the Agreement expires on January 1, 2014. On January 15, 2008, Chugach and HEA signed an agreement entitled Settlement of Dispute over Nikiski Cogeneration Plant System Use and Dispatch Agreement and Premium Demand Charges under HEA’s Power Sales Agreement. This resolved a dispute over the interpretation of the Nikiski Cogeneration Plant System Use and Dispatch agreement. As part of the Settlement Agreement, Chugach agreed to dispatch HEA’s share of Bradley Lake output for $30,000 per year to minimize, to the extent possible, any premium demand charges to be paid to Chugach by HEA.
On February 18, 2008, Chugach offered AEEC the opportunity to participate in the development of a gas-fired generation plant in order to partially satisfy its power requirements. In June 2008, AEEC elected to withdraw from further participation discussions and pursue its own generation project.
On November 9, 2009, the RCA approved Amendment No. 3 to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between Chugach and HEA effective November 6, 2009. The contract modification recognizes HEA’s Sustainable Natural Alternative Power (SNAP) program and allows HEA to purchase energy from members that generate power from alternative power sources, including wind, solar and hydro resources.
Seward
We currently provide nearly all the power needs of the City of Seward. In 2009, sales to Seward represented approximately 2 percent of Chugach’s total sales of energy (including both retail and wholesale). In February 1998, we entered into a power sales agreement (Old Contract) with Seward that allowed us to interrupt service to Seward up to 12 times per year, not to exceed seventy-two cumulative hours annually. Seward’s demand charge was adjusted to reflect the level of service provided by Chugach (approximately $350,000 annually). This agreement expired on May 31, 2006.
We entered into a new power sales agreement (2006 Agreement) with the City of Seward, nominally effective June 1, 2006. The new contract is for five years with two automatic five-year extensions, after RCA review, unless notice of termination is given by either party. The 2006 Agreement is an interruptible, all-requirements/no reserves contract. It has many of the attributes of firm service, especially in the requirement that so long as Chugach has sufficient power available, it must meet Seward’s needs for power. However, service is interruptible because Chugach is under no obligation to supply or plan for generation capacity reserves to supply Seward and there is no limit on the number of times or hours per year that the supply can be interrupted. Counterbalancing this is the requirement that Chugach must provide power to Seward if Chugach has the power available after first meeting its obligations to its other customers for whom Chugach has an obligation to provide reserves (MEA, HEA and Chugach retail customers). The price under the 2006 Agreement reflects the reduced level of service because no costs of generation in excess of that needed to meet the system peak will be assigned to Seward.
Economy Customers
Since 1989, we have sold economy (non-firm) energy to Golden Valley Electric Association, Inc. (GVEA) under an agreement that expired on March 31, 2009. Under that agreement, we used available generation in excess of our own needs to produce electric energy for sale to GVEA, which used that energy to serve its own loads in place of more expensive energy that it would have otherwise generated itself or purchased from other sources. We purchased gas from Marathon Oil Company (Marathon) to produce energy for sale to GVEA.
Chugach negotiated a three-month gas sales agreement, spanning September through November of 2009, with Marathon, to provide between 5,000 and 7,000 million cubic feet (MCF) per day to facilitate a 20 megawatt (MW) economy energy sale to GVEA. The short-term agreement was extended through December 31, 2009. We are currently using gas from existing contracts to make economy sales to GVEA as we negotiate other agreements. Sales were and continue to be made under the terms and conditions of Chugach’s economy energy sales tariff. Non-firm sales to GVEA have been 76,968 MWh, 254,372 MWh and 93,753 MWh for 2009, 2008, and 2007, respectively. For sales not covered by a 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 December 15, 2009, Chugach submitted a request to the RCA for approval to adjust base rates through the Simplified Rate Filing (SRF) process. If approved Chugach would be allowed to adjust rates semi-annually as proposed. Chugach would still be permitted to adjust base rates by filing general rate cases on an as-needed basis. On August 10, 2002, A.S. 42.05.175 imposed timelines for RCA decisions. Among other provisions, it provided that for all dockets commenced on or after July 1, 2002, the RCA shall issue a final order not later than 15 months after a complete tariff filing is made for a tariff filing that changes the utility’s revenue requirement or rate design. It is within the RCA’s authority to authorize, after a notice period, rate changes on an interim, refundable basis. In addition, the RCA has been willing to open limited reviews of matters to resolve specific issues from which expeditious decisions can often be rendered.
The RCA has exclusive regulatory control of our retail and wholesale rates, subject to appeal to the Alaska courts. Under Alaska law, financial covenants of an Alaskan electric cooperative contained in a debt instrument will be valid and enforceable, and rates set by the RCA must be adequate to meet those covenants. Under Alaska law, a cooperative utility that is negotiating to enter into a mortgage or other debt instrument that provides for a Times Interest Earned Ratio (TIER) greater than the ratio the RCA most recently approved for that cooperative must submit the mortgage or debt instrument to the RCA before the instrument takes effect. The rate covenants contained in the instruments that govern our outstanding long-term indebtedness do not impose any greater TIER requirement than those previously approved by the RCA.
We expect to continue to recover changes in our fuel and purchased power expenses through routine fuel surcharge filings with the RCA. See “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations – Overview – Rate Regulation and Rates - Fuel Surcharge.”
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. The Credit Agreement with NRUCFC, which became effective October 10, 2008, and governs loans and extended credit associated with Chugach’s commercial paper program, also requires Chugach to maintain a minimum margins for interest of at least 1.10 times interest charges for each fiscal year, calculated using the average margins for interest of the two best years out of the three fiscal years most recently ended.
On February 6, 2003, we received Order U-01-108(26) from the RCA, based on our 2000 test year general rate case, which revised our overall rate-making TIER from 1.35 to 1.30. For the years ended December 31, 2009, 2008 and 2007, our Margins for Interest/Interest (MFI/I) was 1.27, 1.28 and 1.12, respectively.
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 Southcentral region of Alaska and is the trade, service, medical and financial center for most of Alaska and serves as a major center for many state governmental functions. Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, air and rail transportation facilities and headquarters support for the petroleum, mining and other basic industries located elsewhere in the state.
The Matanuska-Susitna Borough is immediately north of the Municipality of Anchorage, centered around the communities of Palmer and Wasilla. Although agriculture, tourism, mining and forestry are factors in the economy of the Matanuska-Susitna Borough, the economic well-being of the area is closely tied to that of Anchorage and many Matanuska-Susitna residents commute to jobs in Anchorage.
The Kenai Peninsula is south of Anchorage with an economy substantially independent of the Anchorage area. The most significant basic industry on the Kenai Peninsula is the production and processing of oil and gas from the Cook Inlet region. Consequently, the Kenai Peninsula economy is sensitive to fluctuations in the price of the commodity. Recent examples include the closure of Agrium’s Kenai facilities in 2008; the largest exporter of value-added product from Alaska until 2007, because it could not acquire an economic supply of gas. Offsetting this loss, Tesoro (one of the largest Alaska refiners producing gasoline, gasoline blendstocks, jet fuel, diesel fuel, heating oil, heavy fuel oils, marine diesel fuels, propane, and asphalt) refinery expanded its operations and capacity, including the production of ultra low sulfur gasoline and diesel. Other important basic industries include tourism and commercial fishing 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, which is approximately 350 miles north of Anchorage, is Alaska’s second largest city. Economic activities in the Fairbanks region include federal and state government and military operations, the University of Alaska, tourism and support of natural resource development in the Interior and northern parts of the state. Several gold mines operate near Fairbanks. The Trans-Alaska Pipeline System, which transports crude oil, passes near Fairbanks on its route from the North Slope oilfields to Valdez.
Load Forecasts
The following table sets forth our projected load forecasts for the next five years:
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Load (MWh)
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2010
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2011
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2012
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2013
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2014
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Retail
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1,179,633 | 1,179,224 | 1,178,818 | 1,178,494 | 1,178,631 | |||||||||||||||
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Wholesale
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1,265,305 | 1,257,273 | 1,269,444 | 1,276,715 | 844,396 | |||||||||||||||
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Losses
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139,585 | 139,285 | 139,653 | 139,867 | 125,587 | |||||||||||||||
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Total
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2,584,523 | 2,575,782 | 2,587,915 | 2,595,076 | 2,148,614 | |||||||||||||||
Overall, retail and wholesale energy requirements are expected to remain relatively flat over the next four years. The only known growth served by our system is the Goose Creek Correctional Center currently under construction in the MEA service area. Also, while MEA’s growth has slowed over the last three years, the Matanuska-Susitna (MatSu) Borough economy continues to expand to serve an increasing suburban population. Our total firm energy requirements are expected to grow at an average annual compounded rate of 0.1 percent from 2010 to 2013, with retail sales staying flat and wholesale sales growing at a rate of 0.3 percent. In 2014, HEA’s contract to purchase their requirements from Chugach expires, causing wholesale sales to fall by approximately one-third from the previous year.
Growth in wholesale energy sales are expected to be partially offset by expected consumer efficiency/conservancy and declining industrial sales by wholesale customer HEA. These projections are based on assumptions that management believes to be reasonable as of the date the projections were made. The occurrence of a significant change in any of the assumptions could effect a change in the projected sales forecast.
Item 1A – 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.
Financing
Over the next four years Chugach anticipates financing increased capital expenditures due to the construction of a natural gas fired generation plant and on-going capital needs and plans to refinance $150 million of 2001 Series A Bonds due March 15, 2011, and $120 million of 2002 Series A Bonds due February 1, 2012. Chugach will be subject to interest rate risk at the time of refinancing. In October of 2008, Chugach entered into a $300 million Unsecured Credit Agreement between National Rural Utilities Cooperative Finance Corporation (NRUCFC), KeyBank, CoBank, ACB (CoBank) and US Bank. Commercial paper will be issued under this facility and will act as a bridge until Chugach converts Commercial Paper balances to long-term debt and will provide flexibility in paying down the 2011 and 2012 bullet maturities to allow us to approach either the public or private debt markets at an optimal time considering interest rates and market volatility. The credit agreement expires on October 10, 2011. At this time, management intends to renew this agreement although the terms may be different. No assurance can be given that Chugach will be able to refinance the commercial paper facility with longer term debt or that it will be able to continue to access the commercial paper market. Chugach began issuing short term Commercial Paper in the first quarter of 2009,see “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Commercial Paper.” The potential termination of the wholesale power contracts with MEA and HEA could negatively impact our ability to finance or could impact the cost associated with our financing efforts.
Wholesale Contracts
Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts, including the fuel component, represented $112.6 million, or 39 percent and $104.6 million, or 37 percent in 2009 and 2008, respectively, of total sales revenue. The HEA and MEA contracts expire January 1, 2014, and December 31, 2014, respectively. All rates are approved by the RCA.
Pursuant to provisions of their contracts, notification was made by MEA in 2004 and by HEA in 2007 that neither organization intends to be on the Chugach system under the current contractual arrangements post 2014. This would result in a loss of approximately 50 percent of Chugach’s power sales load and approximately 40 percent of the utility’s annual sales revenue. At the August 26, 2009, Chugach Board of Directors’ meeting and in a letter dated September 3, 2009, MEA’s then Interim General Manager advised Chugach that MEA desires to open discussions regarding power sales possibilities beyond 2014.
Chugach’s planning process, however, reflects the termination of the MEA and HEA wholesale contracts post 2014. Consequently, to mitigate this risk, Chugach will be pursuing replacement sources of revenue through potential new power sales agreements and revised transmission wheeling and ancillary services tariff revisions. The loss of these wholesale customers may require Chugach to file a general rate case to recover total costs and/or restructure rates. To the extent that the general rate case could take up to fifteen months to be completed, Chugach may request an interim and refundable rate increase in which the RCA is required to take action within 45 days. To the extent a general rate case or an interim and refundable rate increase does not provide for the timely recovery of expenses, Chugach could experience a material negative impact on its cash flows. 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.
Capital Markets
Global financial markets and economic conditions have been volatile due to a variety of factors, including current weak economic conditions. As a result, the cost of raising money in the debt capital markets could increase while the availability of funds from those markets could diminish. We are currently pursuing and expect to have access to long-term funding through several financing sources, including cooperative lenders, banks and private and public market placements. We will also continue to pursue bond buy back opportunities when available. We will be subject to interest rate risk and will need to negotiate acceptable terms at the time of refinancing.
Credit Ratings
Changes in our credit ratings could affect our ability to access capital. Standard & Poor's Rating Services (S&P), Moody's Investors Service (Moody's) and Fitch Inc. (Fitch) currently rate our outstanding bonds issued under the Amended & Restated Indenture at "A-", "A3" and "A-", respectively. S&P and Moody's currently rate our commercial paper at "A-1" and "P-2". If these agencies were to downgrade our ratings, particularly below investment grade, we may be required to pay higher interest rates on financings which we need to undertake in the future, and our potential pool of investors and funding sources could decrease.
Pension Plans
We participate in the Alaska Electrical Pension Fund (AEPF). The AEPF is a multiemployer pension plan to which we make fixed, per employee contributions through our collective bargaining agreement with the IBEW, which covers our IBEW-represented workforce. We do not have control over the AEPF and receive information concerning its funding status annually. The AEPF was 100 percent funded as of December 31, 2007, however, its assets declined in value during 2008. If a funding shortfall in the AEPF exists, we incur a contingent withdrawal liability. Our contingent withdrawal liability is an amount based on our pro rata share among AEPF participants of the value of the funding shortfall. This contingent liability becomes due and payable by us if we terminate our participation in the AEPF. If another participant in the AEPF goes bankrupt, we would become liable for a pro rata share of the bankrupt participant’s unpaid withdrawal liability only if we terminate participation. This could result in an unexpected contribution requirement which could be substantial, and may have a material adverse effect on our cash position and other financial results. The likelihood of this liability is difficult to predict because we do not know the financial condition of all employers in the plan.
We also participate in the National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (the “Plan”), a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. All our employees not covered by a union agreement become participants in the Plan. We do not have control over the Plan and we may not be timely informed about the funding status of the Plan. We believe the Plan’s assets have likely declined substantially in value during 2008 and 2009. The Plan updates contribution rates on an annual basis to maintain the health of the plan consistent with Pension Protection Act of 2006 minimum funding standards. Currently, the plan does not require accelerated catch-up contributions to maintain minimum funding standards. Contribution rate updates are difficult to predict. An unexpected annual contribution rate increase could be substantial, and may have a material effect on our cash position and other financial results.
Equipment Failures and Other External Factors
The generation and transmission of electricity requires the use of expensive and complex equipment. While we have a maintenance program in place, generating plants are subject to unplanned outages because of equipment failure. We are vulnerable to this due to the advanced age of several of our gas-fired generating units. In the event of unplanned outages, we must acquire power from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements. The fuel surcharge process allows Chugach to reflect current purchased power cost and to recover under-recoveries and refund over-recoveries with a three-month lag. If Chugach were to materially under-recover purchased power costs due to an unplanned outage, we would normally seek an increase in the surcharge to recover those costs at the time of the next quarterly fuel surcharge filing. As a result, cash flow may be impacted due to the lag in payments for purchased power costs and the corresponding collection of those costs from customers. To the extent the regulated process does not provide for the timely recovery of purchased power costs, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and Commercial Paper borrowing capacity to mitigate this risk.
Southcentral Power Project (SPP)
We are currently in the process of developing a natural gas-fired generation plant near our Anchorage headquarters. The generation plant is being developed jointly with AML&P. All projects of this size and nature are subject to numerous schedule and cost risks including weather conditions, delays in obtaining key materials, labor difficulties, permitting, construction delays, difficulties with partners or other factors beyond our control. Any of these events could cause the total costs of construction to be higher than anticipated and the performance of our business following the construction to not meet expectations, hence hindering our ability to timely and effectively integrate the SPP into our operations, resulting in unforeseen operating difficulties or unanticipated costs. Any of these or other factors could adversely affect our ability to realize the anticipated benefits from the project. At this time we are not aware of any substantial risk to this project and expect the project to be completed on time and on budget.
Fuel Supply
In 2009, 90 percent of our power was generated from gas, which included power generated at Nikiski. Our primary suppliers of natural gas are the Beluga River Field Producers and Marathon. Chugach currently has a contract in place to fill 100 percent of Chugach’s unmet needs until April 2011, approximately 50 percent of Chugach’s unmet needs from May 2011 through December 2014, approximately 60 percent in 2015 and approximately 29 percent in 2016. Chugach has a tentative agreement on a contract that would fill Chugach’s remaining unmet needs through the near future and expects to file that contract with the RCA for approval by the end of the first quarter of 2010. The RCA approved inclusion of all fuel (gas) and transportation costs related to our current contracts in the calculation of Chugach’s fuel surcharge process which will ensure, in advance, that costs incurred under the contracts can be recovered from Chugach’s customers . The fuel surcharge process allows Chugach to recover its current fuel and purchased power costs with minimal regulatory lag. To the extent the regulated fuel recovery process does not provide for the timely recovery of fuel expenses, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and Commercial Paper borrowing capacity to mitigate this risk.
The State of Alaska Department of Natural Resources (DNR) completed a preliminary engineering and geological evaluation of the remaining Cook Inlet gas reserves in December of 2009. The study identified 863 billion cubic feet (BCF) of proved, developed, producing reserves, additional probable reserves of 279 BCF and an additional increment of 353 BCF in high-confidence pay intervals. Combined, these 1.5 trillion cubic feet of gas reserves are similar to the 1.4 trillion cubic feet of gas reserves identified in a 2004 study undertaken by the Department of Energy in 2004. Given current demand and deliverability, DNR estimates at minimum a 10-year supply of gas exist in currently producing leases. DNR does note that economic considerations will play a major role in whether producers continue drilling and development activities to meet demand. Chugach has been working closely with the state and producers to develop a comprehensive Cook Inlet management plan that will meet this goal.
Chugach continues to explore its options for future fuel supply needs by working with developers on commercial terms for natural gas storage and the state of Alaska on energy policies to promote gas development in Cook Inlet and other in-state gas options such as the North Slope Pipeline, Spur Line or Bullet line to South Central Alaska. Chugach is also evaluating liquefied natural gas (LNG) storage and import options as transition gas until in-state gas options are developed.
Cooper Lake Hydropower Project
The Cooper Lake Hydropower Project received a 50 year license from the Federal Energy Regulatory Commission (FERC) in August of 2007. A condition of that license is a requirement to construct a Stetson Creek diversion structure into Cooper Lake and a bypass structure to release warm water from Cooper Lake into Cooper Creek potentially enhancing fish habitat. The cost and feasibility of this project are currently being assessed. If the project is not feasible or if the cost estimate materially exceeds the terms of the license it may require a license amendment.
Other Environmental Regulations
We currently are required to comply with numerous federal, state and local laws and regulations relating to the protection of the environment. While we believe that we have obtained all material environmental-related approvals currently required to own and operate our facilities, we may incur significant additional costs because of compliance with these requirements in addition to costs related to any costs of compliance with laws or regulations relating to CO2 emissions. Failure to comply with environmental laws and regulations could have a material effect on us, including potential civil or criminal liability and the imposition of fines or expenditures of funds to bring our facilities into compliance. Delay in obtaining, or failure to obtain and maintain in effect any environmental approvals, or the delay or failure to satisfy any applicable environmental regulatory requirements related to the operation of our existing facilities could result in significant additional costs to us.
Recovery of Fuel and Purchased Power Costs
The fuel surcharge process allows Chugach to recover its current fuel and purchased power costs and to recover under-recoveries and refund over-recoveries from prior periods with minimal regulatory lag. Chugach's fuel surcharge rates are adjusted through quarterly filings with the RCA, which sets the rates on projected costs, sales and system operations for the quarter. Any under or over recovery of costs is incorporated into the following quarterly surcharge. At December 31, 2009, Chugach had over-recovered $3.2 million and at December 31, 2008, Chugach had under-recovered $11.8 million. The cost under-recovery in 2008 was due primarily to unplanned maintenance and lower than expected output from our hydro facilities. To the extent the regulated fuel and purchased power recovery process does not provide for the timely recovery of costs, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and Commercial Paper borrowing capacity to mitigate this risk.
Accounting Standards or Practices
We cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or our operations specifically. New accounting standards could be issued that could change the way we record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect our reported earnings or could increase reported liabilities.
Climate Change
There is substantial uncertainty about the potential impacts of climate change on Chugach's operations and whether climate change is responsible for increased frequency of warmer weather, including potentially decreased hydroelectric generation resulting from reduced runoff from snow pack. If climate change reduces Chugach's hydroelectric energy production, there may be a need for additional production even if there is no change in average load. The impact of events caused by climate change could range widely, but under certain conditions, could result in increased expenses. Chugach would also be required to comply with any future climate change regulation which could have a material effect on our results of operations, financial position, and cash flows.
These factors, 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 530.1 MW of installed capacity consisting of 17 generating units at five power plants. These include 385.0 MW of operating capacity at the Beluga facility on the west side of Cook Inlet; 67.5 MW of power at the Bernice Lake facility on the Kenai Peninsula; 46.7 MW of power at IGT in Anchorage; and 19.2 MW at the Cooper Lake facility, which is also on the Kenai Peninsula. We also own rights to 11.7 MW 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 MW Bradley Lake hydroelectric project owned by the Alaska Energy Authority (AEA) through the Alaska Industrial Development and Export Authority. The Bradley Lake facility is operated by HEA and dispatched by us. The Beluga, Bernice Lake and IGT facilities are all fueled by natural gas. We own our offices and headquarters, located adjacent to IGT in Anchorage. We also lease warehouse space for some generation, transmission and distribution inventory (including a small amount of office space).
Generation Assets
We own the land and improvements comprising our generating facilities at Beluga and IGT. In December of 2008 we purchased land adjacent to our Anchorage headquarters for use during the construction of a new gas fired generation plant we are jointly developing with AML&P. We also own all improvements comprising our generating plant at Bernice Lake, located on land leased from HEA for an immaterial amount. The Bernice Lake ground lease expires in 2011. We are currently involved in discussions with the lease holder concerning a lease extension.
The Cooper Lake Hydroelectric Project is partially located on federal land. We operate and maintain the Cooper Lake power plant pursuant to a 50-year license granted to us by the Federal Energy Regulatory Commission (FERC) in August 2007. Cooper Lake Unit 2 was out of service since August of 2008 when it was forced out of service by damage to its turbine runner and wicket gates. It was repaired, major maintenance performed, and the unit put back into service in May of 2009. Inspection of Unit 1 during the Unit 2 outage identified damage on the Unit 1 runner as well, though it was not as extensive as Unit 2. Unit 1 was taken out of service in May of 2009, shortly after the return to service of Unit 2, to perform repairs and major maintenance, and returned back into service in February of 2010.
In 1997, we acquired a 30 percent interest in the Eklutna Hydroelectric Project. The plant is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October 1997.
Our principal generation units are Beluga 3, 5, 6, 7 and 8. These units have a combined capacity of 345.8 MW and meet most of our load. All other units are used principally as reserve. While the Beluga turbine-generators have been in service for many years, they have been maintained in good working order with annual inspections and periodic upgrades. Due to the age of Unit 3, several of the high risk parts of the turbine rotor were replaced during a major inspection in 2007. A combustion inspection was performed on Unit 3 in 2006 and again in 2008 and 2009 in accordance with the existing maintenance plan. Beluga Unit 5 continued to have two combustion inspections per year in 2007, 2008 and 2009 due to high rates of wear observed on aging combustion parts. One of these inspections in 2007 was a hot gas path inspection involving generator repairs. Beluga Unit 6 was re-powered in 2000 and had major inspections in 2003 and 2006 with annual inspections in 2007, 2008 and 2009. During the annual inspection in 2007 the last row of turbine blades was exchanged. Beluga Unit 7 was re-powered in 2001 and had major inspections in 2004 and 2008 with annual inspections in 2007 and 2009. Beluga Unit 8, a steam turbine, received a 25,000-hour inspection in 2005 and a major inspection in 2008 with an annual inspection in 2009.
Chugach is in the process of developing a natural gas fired generation plant on land currently owned by Chugach near its Anchorage headquarters. The SPP will be developed and owned jointly with AML&P. Chugach will own and take 70 percent of the new plant’s output and AML&P will own and take the remaining 30 percent. Chugach will account for its ownership in the SPP proportionately. Chugach and AML&P signed Participation, Operation and Maintenance (O&M) and Lease Agreements (Agreements) for this project on August 28, 2008. On November 17, 2008, Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines with an option for a fourth turbine with General Electric Packaged Power (GEPP). The option to purchase a fourth turbine expired on January 31, 2009. During 2009 Chugach executed several change orders associated with its purchase agreement with GEPP totaling $7.2 million, which included the purchase of a spare engine for maintenance purposes. Chugach made progress and milestone payments of $5.1 and $24.3 million in 2008 and 2009, respectively, and is expected to make payments of $29.2 million in 2010, pursuant to its purchase agreement and subsequent change orders with GEPP. In December of 2008, Chugach purchased land adjacent to its Anchorage headquarters for SPP use. Chugach executed an Owner’s Engineer Services Contract on May 12, 2009. This contract expired on December 31, 2009, but was later renewed effective January 1, 2010. Chugach made payments of $0.7 million in 2009, pursuant to its Owner’s Engineer Services Contract. On January 5, 2010, Chugach executed a Services Contract for the shipment of the combustion turbine generators and related accessories. Chugach is expected to make payments of $1.1 million in 2010 pursuant to this contract. On February 25, 2010, Chugach purchased additional land adjacent to its Anchorage headquarters for the laydown of equipment displaced by the new power plant. Chugach is currently proceeding with a Request for Proposal (RFP) for engineering, procurement and construction services as well as a steam turbine generator purchase agreement to be awarded in 2010.
The following matrix depicts nomenclature, run hours for 2009 and percentages of contribution and other historical information for all Chugach generation units.
|
Facility
|
Commercial Operation Date
|
Nomenclature
|
Rating
(MW)(1)
|
Run Hours (2009)
|
Percent of Total Run Hours
|
Percent of
Time
Available
|
|||||||||||||||
|
Beluga Power Plant (3)
|
|||||||||||||||||||||
| 1 | 1968 |
GE Frame 5
|
19.6 | 681.8 | 1.6 | 97.0 | |||||||||||||||
| 2 | 1968 |
GE Frame 5
|
19.6 | 504.4 | 1.2 | 95.0 | |||||||||||||||
| 3 | 1972 |
GE Frame 7
|
64.8 | 4,958.9 | 11.6 | 91.4 | |||||||||||||||
| 5 | 1975 |
GE Frame 7
|
68.7 | 5,643.6 | 13.2 | 94.1 | |||||||||||||||
| 6 | 1975 |
AP 11DM-EV
|
79.2 | 8,633.9 | 20.2 | 98.6 | |||||||||||||||
| 7 | 1978 |
AP 11DM-EV
|
80.1 | 8,575.4 | 20.0 | 97.9 | |||||||||||||||
| 8 | 1981 |
BBC DK021150(2)
|
53.0 | 7,530.3 | 17.6 | 86.0 | |||||||||||||||
|
Bernice Lake Power Plant
|
385.0 | ||||||||||||||||||||
| 2 | 1971 |
GE Frame 5
|
19.0 | 942.3 | 2.2 | 85.3 | |||||||||||||||
| 3 | 1978 |
GE Frame 5
|
26.0 | 620.1 | 1.5 | 92.3 | |||||||||||||||
| 4 | 1981 |
GE Frame 5
|
22.5 | 268.0 | 0.6 | 90.3 | |||||||||||||||
|
Cooper Lake Hydroelectric Plant
|
67.5 | ||||||||||||||||||||
| 1 | 1960 |
BBC MV 230/10
|
9.6 | 1,330.9 | 3.1 | 18.7 | |||||||||||||||
| 2 | 1960 |
BBC MV 230/10
|
9.6 | 2,935.0 | 6.9 | 58.7 | |||||||||||||||
|
IGT Power Plant
|
19.2 | ||||||||||||||||||||
| 1 | 1964 |
GE Frame 5
|
14.1 | 35.8 | 0.1 | 91.5 | |||||||||||||||
| 2 | 1965 |
GE Frame 5
|
14.1 | 26.3 | 0.1 | 91.5 | |||||||||||||||
| 3 | 1969 |
Westinghouse 191G
|
18.5 | 48.0 | 0.1 | 91.5 | |||||||||||||||
| 46.7 | |||||||||||||||||||||
|
Eklutna Hydroelectric Plant
|
|||||||||||||||||||||
| 1 | 1955 |
Newport News
|
5.8 | (4) | N/A | (5) | N/A | (5) | 95.4 | ||||||||||||
| 2 | 1955 |
Oerlikon custom
|
5.9 | (4) | N/A | (5) | N/A | (5) | 94.1 | ||||||||||||
|
|
11.7 | 42,734.7 | 100.00 | ||||||||||||||||||
|
System Total
|
530.1 | ||||||||||||||||||||
|
(1)
|
Capacity rating in MW at 30 degrees Fahrenheit.
|
|
(2)
|
Steam-turbine powered generator with heat provided by exhaust from natural-gas fueled Units 6 and 7 (combined-cycle).
|
|
(3)
|
Beluga Unit 4 and Bernice Lake Unit 1 were retired during 1994.
|
|
(4)
|
The Eklutna Hydroelectric Project is jointly owned by Chugach, MEA and AML&P. The capacity shown is our 30 percent share of the plant’s output. The actual nameplate rating on each unit is 23.5MW.
|
|
(5)
|
Because Eklutna Hydroelectric Project is managed by a committee of the three owners, we do not record run hours or in-commission rates.
|
Note: GE = General Electric, BBC = Brown Boveri Corporation, AP = Alstom Power
Transmission and Distribution Assets
As of December 31, 2009, our transmission and distribution assets included 42 substations and 533 miles of transmission lines, which included 128 miles of leased transmission lines and Chugach’s share of the Eklutna transmission line, 916 miles of overhead distribution lines and 769 miles of underground distribution line. We own the land on which 22 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 percent of the Eklutna facility, we also acquired a partial interest in two substations and additional transmission facilities.
Many substations and a substantial number of our transmission and distribution rights-of-way are subject to federal or state permits, leases and licenses. Under a federal license and a permit from the United States Forest Service, we operate the Quartz Creek transmission substation and the Hope substation. We also operate transmission lines over federal, state and borough lands. Under a State of Alaska permit from the Department of Natural Resources, we operate the Summit Lake and Daves Creek substations. Long-term permits from the Alaska Division of Lands and the Alaska Railroad Corporation govern much of the rest of our transmission system outside the Anchorage area. Within the Anchorage area, we operate our University substation and several major transmission lines pursuant to long-term rights-of-way grants from the U.S. Department of the Interior, Bureau of Land Management, and transmission and distribution lines have been constructed across privately owned lands via easements and across public rights-of-way and waterways pursuant to authority granted by the appropriate governmental entity.
Title
Under the Amended and Restated Indenture, all of Chugach’s bonds are general unsecured and unsubordinated obligations. Chugach is prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on our properties and assets (other than those arising by operation of law) to secure the repayment of borrowed money or the obligation to pay the deferred purchase price of property unless we equally and ratably secure all bonds subject to the Amended and Restated Indenture, except that we may incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements.
Many of our properties are burdened by easements, plat restrictions, mineral reservation, water rights and similar title exceptions common to the area or customarily reserved in conveyances from federal or state governmental entities, and by additional minor title encumbrances and defects. We do not believe that any of these title defects will materially impair the use of our properties in the operation of our business.
Under the Alaska Electric and Telephone Cooperative Act, we possess the power of eminent domain for the purpose and in the manner provided by Alaska condemnation laws for acquiring private property for public use.
Other Property
Bradley Lake. We are a participant in the Bradley Lake hydroelectric project, which is a 126 MW 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 MW to minimize losses and ensure system stability. We have a 30.4 percent (27.4 MW 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 45.2 percent of the project’s capacity. We are obligated to pay 30.4 percent 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 term of our Bradley Lake power sales agreement is fifty years from the date of commercial operation of the facility (September 1991) or when the revenue bond principal is repaid, whichever is the longer. The agreement may be renewed for successive forty-year periods or for the useful life of the project, whichever is shorter. We believe that our maximum annual liability for our take-or-pay obligations is approximately $5.4 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 process. The share of Bradley Lake indebtedness for which we are responsible is approximately $34 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 percent.
Eklutna. We purchased a 30 percent undivided interest in the Eklutna Hydroelectric Project from the federal government in 1997. MEA owns 17 percent 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 percent undivided interest in the Eklutna Hydroelectric Project.
Fuel Supply
In 2009, 90 percent of our power was generated from natural gas, which included power generated at Nikiski, and 83 percent of that gas-fired generation took place at Beluga.
Total gas usage in 2009 was approximately 26 BCF. Our primary sources of natural gas are divided among four long-term contracts with major oil and gas companies. All of the production came from Cook Inlet, Alaska. Marathon Oil Company provided 52 percent, while ConocoPhillips Alaska Inc., AML&P, and Chevron U.S.A. each provided 16 percent of Chugach’s gas requirements. Approximately 27 BCF of gas remains on the current contracts. We estimate that our contract gas with Marathon will run-out in 2010 and expect the remaining three contracts to run-out in early 2011. A new contract with ConocoPhillips will provide gas, now estimated to be 62 BCF, beginning in 2010. Chugach has a tentative agreement on a contract that would fill Chugach’s remaining unmet needs through the near future and expects to file that contract with the RCA for approval by the end of the first quarter of 2010. Under almost all circumstances the deliverability supplied under our contracts is sufficient to meet all of our generating requirements.
ConocoPhillips
We entered into a contract with COP in 2009. The new contract will provide gas beginning in 2010 and will terminate December 31, 2016. The total amount of gas under the contract is now estimated to be 62 BCF. The new contract is now designed to fill 100 percent of Chugach’s unmet needs until April 2011, approximately 50 percent of Chugach’s unmet needs from May 2011 through December 2014, approximately 60 percent in 2015 and approximately 29 percent in 2016.
The gas supplied by COP under the contract is separated into two volume tranches for pricing purposes. “Firm Fixed Quantity” gas will meet a portion of Chugach’s base load requirements, while “Firm Variable Quantity” gas will meet peaking needs. Chugach expects that ninety percent of the gas purchased under the contract will be firm fixed and ten percent will be firm variable. The dividing line between firm fixed and firm variable volumes will be calculated based on a methodology that involves using a multiplier and the simple average of Chugach’s average daily volumes for the thirty lowest volume days during the last calendar year.
Pricing for firm fixed gas will be based on the average of five Lower 48 natural gas production areas. The contract price will be calculated on a quarterly basis as the trailing average of the simple daily average of the Platts Gas Daily midpoint prices for each “flow day” in these market areas during the last quarter. ($5.75 per MCF on January 1, 2010), exclusive of taxes. There will be a price collar, floor of $5.75 per MCF and cap of $6.25 per MCF, on the firm fixed gas between January 1, 2010 and June 30, 2010.
Pricing for firm variable gas purchased between January 1, 2010, and March 31, 2011, will be the one quarter trailing average of ninety-five percent of the average monthly price of Kenai liquefied natural gas delivered to Japan, as officially reported to the U.S. Department of Energy. Pricing for firm variable gas purchased from April 1, 2011, to December 31, 2013, will be 120 percent of the one calendar quarter trailing average of “Platts National Average Price” as published in Platts Gas Daily for each “flow day.” ($10.39 per MCF on January 1, 2010), plus taxes in excess of $0.25 per MCF. The price for firm variable gas is capped at two-hundred percent of the firm fixed price. Firm variable gas is not provided by the contract after December 31, 2013.
Chugach also has the option to receive a fixed price quote from COP and lock that price of any quantity as long as the quantity does not exceed the “Firm Fixed Quantity” and for any term up to December 31, 2016, for which price is to be locked.
Beluga River Field Producers
We have similar requirements contracts with each of the one third working interest owners of the Beluga River Field, ConocoPhillips, AML&P and Chevron, which were executed in April 1989, superseding contracts that had been in place since 1973.
The current contracts continue until the earlier of the delivery of 180 BCF of natural gas or December 31, 2013. Chugach is entitled to 180 BCF of natural gas (60 BCF per Beluga River Field producer). During the term of the contracts, we are required to take 60 percent of our total fuel requirements at Beluga Power Plant from the three Beluga River Field producers, exclusive of gas purchased at Beluga Power Plant under the Marathon contract for use in making sales to GVEA. The price for gas during this period under the ConocoPhillips and AML&P contracts is approximately 88 percent of the price of gas under the Marathon contract (described below) ($3.44 per thousand cubic feet (MCF) on January 1, 2010), plus taxes. The price during this period under the Chevron contract is approximately 110 percent of the price of gas under the Marathon contract (described below) ($4.44 per MCF on January 1, 2010), plus taxes.
Marathon
We entered into a requirements contract with Marathon in September 1988 for an initial commitment of 215 BCF. The contract expires on the earlier of December 31, 2015, or the date on which Marathon has delivered to us a volume of gas in total, which equals 215 BCF. Chugach estimates that the contract will run-out in 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, 2010, exclusive of taxes, was $4.04 per MCF.
Under the terms of the Marathon contract, Marathon provides all of Chugach’s requirements at Bernice Lake, IGT and Nikiski. Additionally, Marathon had responsibility to supply 40 percent of gas volumes to the Beluga plant. For the last year of the Marathon contract, year 2010, Marathon volumes are not sufficient to meet the 40% gas requirements for the full year. To make the transition from the expiring Marathon contract to the new COP gas contract, Marathon and ConocoPhillips are sharing the gas deliverability of the 40% gas volume for the entire year.
ENSTAR
ENSTAR Natural Gas Company (ENSTAR) has a tariff to transport our gas purchased from gas suppliers on a firm basis to our IGT Power Plant at a transportation rate of $0.63 per MCF. The agreement contains a fixed monthly charge of $2,840 for firm service.
Environmental Matters
General
Chugach’s operations are subject to certain federal, state and local environmental laws and regulations, which seek to limit air, water and other pollution and regulate hazardous or toxic waste disposal. While we monitor these laws and regulations to ensure compliance, they frequently change and often become more restrictive. When this occurs, the costs of our compliance generally increase.
We include costs associated with environmental compliance in both our operating and capital budgets. We accrue for costs associated with environmental remediation obligations when those costs are probable and reasonably estimable. We do not anticipate that environmental related expenditures will have a material effect on our results of operations or financial condition. We cannot, however, predict the nature, extent or cost of new laws or regulations relating to environmental matters.
The Clean Air Act and Environmental Protection Agency (EPA) regulations under the act (the “Clean Air Act”) establish ambient air quality standards and limit the emission of many air pollutants. Some Clean Air Act programs that regulate electric utilities, notably the Title IV “acid rain” requirements, do not apply to facilities located in Alaska. In 2008 the EPA vacated regulations to limit mercury emissions from fossil-fired steam-electric generating facilities.
New Clean Air Act regulations impacting electric utilities may result from future events or may result from new regulatory programs. On October 30, 2009, EPA published new federal regulations requiring the mandatory reporting of greenhouse gases from all sectors of the economy. Chugach is subject to this new regulation which is not expected to have a material effect on our results of operations, financial position, and cash flows. While we cannot predict whether any additional new regulation would occur or its limitation, it is possible that new laws or regulations could increase our capital and operating costs. We have obtained or applied for all Clean Air Act permits currently required for the operation of our generating facilities.
In March 2007, Chugach conducted emissions testing at the Bernice Lake Power Plant which indicated that two of the gas turbines at the facility were exceeding the New Source Performance Standards (NSPS) emission limit for nitrogen oxides (NOx). Chugach voluntarily limited the power output of these turbines to ensure interim compliance with the NSPS regulations until a water injection system to control NOx emissions from the turbines was installed and operational. With the water injection system, Chugach is able to fully utilize the power output from these turbines while complying with the NSPS regulations.
The Alaska Department of Environmental Conservation (ADEC) issued a Notice of Violation (NOV) on March 26, 2008, regarding the NSPS NOx emission limit exceedances. Chugach entered into a settlement with ADEC regarding the NOV for the past NSPS non-compliance. Chugach and the ADEC signed the settlement agreement on February 18, 2009. As part of the settlement, Chugach paid a civil penalty of $112,161 to ADEC on April 3, 2009, bringing the issue to a close.
Chugach is subject to numerous other environmental statutes including the Clean Water Act, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Endangered Species Act, and the Comprehensive Environmental Response, Compensation and Liability Act and to the regulations implementing these statutes. We do not believe that compliance with these statutes and regulations to date has had a material impact on our financial condition or results of operation. However, new laws or regulations, implementation of final regulations or changes in or new interpretations of these laws or regulations could result in significant additional capital or operating expenses.
Item 3 - Legal Proceedings
Chugach has certain 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 – Reserved
None
PART II
Item 5 - Market for Registrant's
Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities
Not Applicable
Item 6 - Selected Financial Data
The following table presents selected historical information relating to financial condition and results of operations for the years ended December 31:
|
Balance Sheet Data
|
2009
|
2008
|
2007
|
2006
|
2005
|
|||||||||||||||
|
Electric plant, net:
|
||||||||||||||||||||
|
In service
|
$ | 414,002,926 | $ | 432,460,336 | $ | 438,239,286 | $ | 439,268,514 | $ | 435,474,237 | ||||||||||
|
Construction work in
|
||||||||||||||||||||
|
Progress
|
48,383,610 | 25,151,072 | 17,712,884 | 20,683,335 | 32,505,401 | |||||||||||||||
|
Electric plant, net
|
462,386,536 | 457,611,408 | 455,952,170 | 459,951,849 | 467,979,638 | |||||||||||||||
|
Other assets
|
102,912,190 | 119,080,561 | 101,773,948 | 103,733,881 | 97,155,862 | |||||||||||||||
|
Total assets
|
$ | 565,298,726 | $ | 576,691,969 | $ | 557,726,118 | $ | 563,685,730 | $ | 565,135,500 | ||||||||||
|
Capitalization:
|
||||||||||||||||||||
|
Long-term debt
|
307,301,819 | 354,383,506 | 345,423,500 | 350,803,530 | 364,532,099 | |||||||||||||||
|
Equities and margins
|
156,320,597 | 153,766,999 | 149,310,436 | 150,716,100 | 145,039,152 | |||||||||||||||
|
Total capitalization
|
$ | 463,622,416 | $ | 508,150,505 | $ | 494,733,936 | $ | 501,519,630 | $ | 509,571,251 | ||||||||||
|
Equity Ratio1
|
33.7 | % | 30.3 | % | 30.2 | % | 30.1 | % | 28.5 | % | ||||||||||
|
Summary Operations Data
|
||||||||||||||||||||
|
Operating revenues
|
$ | 290,247,308 | $ | 288,292,112 | $ | 257,443,919 | $ | 267,542,713 | $ | 225,697,349 | ||||||||||
|
Operating expenses
|
264,872,577 | 260,580,365 | 232,367,023 | 234,969,329 | 194,823,965 | |||||||||||||||
|
Interest expense, net
|
20,606,349 | 22,532,797 | 23,712,797 | 24,010,874 | 22,586,054 | |||||||||||||||
|
Net operating margins
|
4,768,382 | 5,178,950 | 1,364,099 | 8,562,510 | 8,287,330 | |||||||||||||||
|
Nonoperating margins
|
891,966 | 1,232,800 | 1,521,157 | 1,476,549 | 1,227,401 | |||||||||||||||
|
Assignable margins
|
$ | 5,660,348 | $ | 6,411,750 | $ | 2,885,256 | $ | 10,039,059 | $ | 9,514,731 | ||||||||||
|
Margins for Interest Ratio2
|
1.27 | 1.28 | 1.12 | 1.41 | 1.41 | |||||||||||||||
1 Equity ratio equals equities and margins divided by the sum of our long-term debt and equities and margins.
2 Margins for interest ratio equals the sum of long and short-term interest expense and assignable margins divided by the sum of long and short-term interest expense.
Equity ratios and margins for interest ratios are considered non-GAAP measures. We consider these ratios to be useful to users of Chugach’s financial statements and are components of financial covenants contained in Chugach’s Amended and Restated Indenture and debt agreements.
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 fuel and purchased power, capital expenditures, depreciation and principal and interest on our indebtedness and to provide for reserves. These amounts are referred to as “margins.” Patronage capital, the retained margins of our members, constitutes our principal equity.
Times Interest Earned Ratio (TIER). Alaska electric cooperatives generally set their rates on the basis of TIER. TIER is determined by dividing the sum of assignable margins plus long-term interest expense (excluding capitalized interest) by long-term interest expense (excluding capitalized interest). Chugach’s authorized TIER for rate-making purposes on a system basis is 1.30, which was established by the RCA in order U-01-08(26) on January 31, 2003.
Chugach’s achieved TIER reflects non-operating margins that are not generated by electric rates. We manage our business with a view towards achieving our authorized TIER (currently 1.30) averaged over a 5-year period. For further discussion on factors that contribute to TIER results, see “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations - Years ended December 31, 2009, compared to the years ended December 31, 2008, and December 31, 2007 – Expenses.” We achieved TIERs for the past five years as follows:
|
Year
|
TIER
|
|
2009
|
1.28
|
|
2008
|
1.30
|
|
2007
|
1.12
|
|
2006
|
1.41
|
|
2005
|
1.41
|
Rate Regulation and Rates. Our electric rates are made up of two primary components: “base rates” and “fuel surcharge rates.” Base rates provide the recovery of fixed and variable costs (excluding fuel and purchased power) related to providing electric service. Fuel surcharge rates provide the recovery of fuel and purchased power costs.
The RCA approves both base rates and fuel surcharge rates paid by our retail and wholesale customers. In addition, a RCC is assessed on each retail customer invoice to fund Chugach’s share of the RCA’s budget. In general, 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. The RCA may authorize, after a notice period, rate changes on an interim and refundable basis.
On October 9, 2009, base rates charged to retail customers increased 3.3 percent and base rates charged to wholesale customers HEA, MEA and Seward increased 7.8 percent, 2.0 percent and 9.7 percent, respectively. The base rate changes were effective on an interim and refundable basis and were the result of proposed rates included in Chugach’s 2008 Test Year Rate Case filed with the RCA on June 23, 2009, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Overview – Rate Regulation and Rates - 2008 Test Year General Rate Case (Docket U-09-080).”
In June of 2008, the base rates charged to retail customers decreased 4.8 percent and base rates charged to wholesale customers HEA, MEA and Seward increased 13.0 percent, 10.5 percent and 9.6 percent, respectively. The base rate changes were the result of Chugach’s 2005 Test Year Rate Case adjudicated under Docket U-06-134, see “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations - Overview – Rate Regulation and Rates - 2005 Test Year General Rate Case (Docket No. U-06-134).” There were no base rate changes for our retail customers or for our wholesale customers in 2007.
Request for Participation in the Simplified Rate Filing Process
On December 15, 2009, Chugach submitted a request to the RCA for approval to implement the Simplified Rate Filing (SRF) process for the adjustment of base energy and demand rates in accordance with Alaska Statute 42.05.381(e).
Utilization of SRF will allow Chugach to more efficiently adjust base rates in response to lower sales resulting from both energy conservation and technological improvements. Chugach is also interested in SRF as a means to expedite the rate adjustment process with the goal of timely cost recovery and lower adjudicatory costs.
Chugach requested that base rate adjustments under SRF be completed on a semi-annual basis, utilizing the twelve months ended June and December as the test periods in each year. Chugach requested that its initial SRF be submitted on the June 2010 test year for rate adjustments, if necessary, during fourth quarter, 2010.
Under SRF, base rate increases are limited to 8 percent over a 12-month period and 20 percent over a 36-month period. Chugach is still permitted to submit general rate case filings while participating in the SRF process. However, during these periods, rate adjustments under SRF would temporarily cease. The Commission has not yet issued an order on Chugach’s request.
2008 Test Year General Rate Case (Docket U-09-080)
On June 23, 2009, Chugach filed a general rate case with the RCA to increase base rate revenue by $4.2 million, with increases of $2.7 million to Chugach retail customers and $1.5 million to wholesale customers. Base rates charged to retail customers increased 3.3 percent and base rates charged to wholesale customers HEA, MEA and Seward increased 7.8 percent, 2.0 percent and 9.7 percent, respectively. The estimated increase to Chugach’s retail end-users was approximately 1.7 percent, while the increase to retail end-users of Chugach’s wholesale customers was approximately 0.9 percent. Chugach requested that the proposed rates become effective on an interim and refundable basis beginning August 7, 2009.
On August 7, 2009, the RCA suspended Chugach’s filing into Docket U-09-080 and issued Order No. 1. The RCA indicated that it would issue a final order in this case no later than September 16, 2010. The RCA did not issue a decision on Chugach’s interim rate request. The RCA named the Attorney General and Chugach’s wholesale customers HEA, MEA and Seward parties to the docket.
On October 9, 2009, the RCA issued Order No. 2 granting Chugach’s original request that the proposed rates go into effect on an interim and refundable basis.
2005 Test Year General Rate Case (Docket U-06-134)
On September 29, 2006, Chugach filed a general rate case based on a 2005 test year with the RCA. Overall revenues were proposed to increase $2.8 million in the initial filing.
A settlement agreement reached in July 2007 between several of the intervenors and Chugach was accepted by the RCA in Order No. 15. On April 1, 2008, the RCA issued Order No. 21 in Docket U-06-134, approving the rates from the Settlement Agreement among Chugach, HEA and Seward. MEA did not join the Settlement Agreement. The effect of Order 21 was that overall revenues decreased by 0.8 percent, or $0.9 million, with retail base rate revenue decreasing by 4.8 percent, or $4.2 million and wholesale base rate revenue increasing by 11.0 percent, or $3.3 million. Order No. 21 was effective June 1, 2008.
After reconsiderations concerning a long-term debt allocator, the computation of depreciation expense and re-affirming filing requirements, the RCA issued Order No. 25 on November 7, 2008, accepting Chugach’s filings and closed docket U-06-134. In this rate case, we modified the rate design so that all fuel and purchased power costs would be recovered through the fuel and purchased power process, which was approved by the RCA.
Fuel Surcharge. We recover fuel and purchased power costs directly from our wholesale and retail customers through the fuel surcharge process. Changes in fuel and purchased 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. Other factors, including generation unit availability also impact fuel surcharge rate levels. 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 does not impact margins. We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates. The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under or over collection of fuel and purchase power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods.
Years ended December 31, 2009, compared to the years ended December 31, 2008, and December 31, 2007
Margins
Our margins for the years ended December 31 were as follows:
|
2009
|
2008
|
2007
|
||||||||||
|
Net Operating Margins
|
$ | 4,768,382 | $ | 5,178,950 | $ | 1,364,099 | ||||||
|
Non-Operating Margins
|
$ | 891,966 | $ | 1,232,800 | $ | 1,521,157 | ||||||
|
Assignable Margins
|
$ | 5,660,348 | $ | 6,411,750 | $ | 2,885,256 | ||||||
The decrease in assignable margins in 2009 from 2008 of $751.4 thousand, or 11.7 percent, was due primarily to a decrease in sales revenue, an increase in depreciation and administrative and general expense and a decrease in interest income, which was partially offset by a decrease in net interest expense. The increase in assignable margins in 2008 from 2007 of $3.5 million, or 122.2 percent, was due primarily to a decrease in transmission, distribution and net interest expense, see “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Years ended December 31, 2009, compared to the years ended December 31, 2008, and December 31, 2007 – Expenses.”
Non-operating margins include interest income, allowance for funds used in construction, capital credits and patronage capital allocations. Non-operating margins decreased in 2009 from 2008 by $340.8 thousand, or 27.6 percent due primarily to lower interest income as a result of a lower cash balance and lower interest rates and a lower patronage capital allocation. Our patronage capital allocation from CoBank decreased in 2009 as our total debt outstanding with CoBank decreased. Non-operating margins decreased in 2008 from 2007 by $288.4 thousand, or 19.0 percent due primarily to lower interest income as a result of a lower cash balance and lower interest rates and lower Allowance for Funds Used During Construction (AFUDC) as a result of lower 2007 margins which is used in the average equity balance calculation of AFUDC.
Revenues
Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2009, operating revenues were $2.0 million, or 0.7 percent higher than in 2008. The increase was due primarily to higher purchased power costs recovered in revenue through the fuel surcharge process which was partially offset by lower overall base revenue. The increase was also offset by a decrease in kWh and economy energy sales and a decrease in fuel recovered in revenue through the fuel surcharge process due primarily to lower kWh and economy energy sales.
In 2008, operating revenues were $30.8 million, or 12.0 percent higher than in 2007 due primarily to higher fuel costs recovered in revenue through the fuel surcharge process and an increase in wholesale and economy revenue. These increases were partially offset by a decrease in retail revenue due to a decrease in kWh sales.
Overall, retail revenue increased in 2009 from 2008. The increase was due primarily to higher purchased power costs recovered in revenue through the fuel surcharge process which was partially offset by a decrease in base revenue due to lower kWh sales caused by observed patterns of conservation and implementation of protective measures in response to the threat of volcanic ash fall that continued as additional conservation measures.
Overall, retail revenue increased in 2008 from 2007. Base revenue decreased due to lower kWh sales caused by a change in consumer consumption patterns, as well as base rates charged to retail customers decreased effective June 1, 2008, as a result of Chugach’s 2005 Test Year Rate Case. This base revenue decrease was more than offset by higher fuel costs recovered in revenue through the fuel surcharge process due in part to higher fuel prices and the impact of credits received in 2007 for reduced fuel production taxes.
Wholesale revenue was higher in 2009 from 2008 caused by higher base rates charged to wholesale customers as a result of Chugach’s 2008 Test Year Rate Case and higher purchased power costs recovered in revenue through the fuel surcharge process. These increases were offset by lower kWh sales caused by conservation and protection measures in response to the threat of volcanic ash fall that continued as additional conservation measures.
Wholesale revenue was higher in 2008 from 2007. Base revenue increased due to the June 1, 2008, base rate increase charged to wholesale customers as a result of Chugach’s 2005 Test Year Rate Case and higher kWh sales. The wholesale revenue increase was also due to higher fuel costs recovered in revenue through the fuel surcharge process due to higher fuel prices and the impact of credits received in 2007 for reduced fuel production taxes.
Based on the results of fixed and variable cost recovery established in Chugach’s last rate case, wholesale sales to MEA, HEA and Seward contributed approximately $28.6 million, $27.7 million and $26 million to Chugach’s fixed costs for the years ended December 31, 2009, 2008 and 2007, 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, 2009, and 2008.
|
Base Rate Sales Revenue
|
Fuel and Purchased Power Revenue
|
Total Revenue
|
||||||||||||||||||||||||||||||||||
|
2009
|
2008
|
% Variance
|
2009
|
2008
|
% Variance
|
2009
|
2008
|
% Variance
|
||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||||||
|
Retail
|
|
|||||||||||||||||||||||||||||||||||
|
Residential
|
$ | 45.0 | $ | 46.4 | (3.0 | %) | $ | 37.3 | $ | 33.9 | 10.0 | % | $ | 82.3 | $ | 80.3 | 2.5 | % | ||||||||||||||||||
|
Small Commercial
|
$ | 8.0 | $ | 8.4 | (4.8 | %) | $ | 7.9 | $ | 7.2 | 9.7 | % | $ | 15.9 | $ | 15.6 | 1.9 | % | ||||||||||||||||||
|
Large Commercial
|
$ | 27.8 | $ | 28.3 | (1.8 | %) | $ | 34.5 | $ | 31.8 | 8.5 | % | $ | 62.3 | $ | 60.1 | 3.7 | % | ||||||||||||||||||
|
Lighting
|
$ | 1.3 | $ | 1.3 | 0.0 | % | $ | 0.3 | $ | 0.2 | 50.0 | % | $ | 1.6 | $ | 1.5 | 6.7 | % | ||||||||||||||||||
|
Total Retail
|
$ | 82.1 | $ | 84.4 | (2.7 | %) | $ | 80.0 | $ | 73.1 | 9.4 | % | $ | 162.1 | $ | 157.5 | 2.9 | % | ||||||||||||||||||
|
Wholesale
|
||||||||||||||||||||||||||||||||||||
|
HEA
|
$ | 11.8 | $ | 11.4 | 3.5 | % | $ | 31.1 | $ | 29.8 | 4.4 | % | $ | 42.9 | $ | 41.2 | 4.1 | % | ||||||||||||||||||
|
MEA
|
$ | 21.9 | $ | 20.9 | 4.8 | % | $ | 47.8 | $ | 42.6 | 12.2 | % | $ | 69.7 | $ | 63.5 | 9.8 | % | ||||||||||||||||||
|
SES
|
$ | 1.3 | $ | 1.1 | 18.2 | % | $ | 4.4 | $ | 3.7 | 18.9 | % | $ | 5.7 | $ | 4.8 | 18.8 | % | ||||||||||||||||||
|
Total Wholesale
|
$ | 35.0 | $ | 33.4 | 4.8 | % | $ | 83.3 | $ | 76.1 | 9.5 | % | $ | 118.3 | $ | 109.5 | 8.0 | % | ||||||||||||||||||
|
Economy Sales
|
$ | 1.2 | $ | 4.6 | (73.9 | %) | $ | 6.1 | $ | 13.9 | (56.1 | %) | $ | 7.3 | $ | 18.5 | (60.5 | %) | ||||||||||||||||||
|
Miscellaneous
|
$ | 2.6 | $ | 2.8 | (7.1 | %) | $ | 0.0 | $ | 0.0 | 0.0 | % | $ | 2.6 | $ | 2.8 | (7.1 | %) | ||||||||||||||||||
|
Total Revenue
|
$ | 120.9 | $ | 125.2 | (3.4 | %) | $ | 169.4 | $ | 163.1 | 3.9 | % | $ | 290.3 | $ | 288.3 | 0.7 | % | ||||||||||||||||||
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, 2008, and 2007.
|
Base Rate Sales Revenue
|
Fuel and Purchased Power Revenue
|
Total Revenue
|
||||||||||||||||||||||||||||||||||
|
2008
|
2007
|
% Variance
|
2008
|
2007
|
% Variance
|
2008
|
2007
|
% Variance
|
||||||||||||||||||||||||||||
|
|
||||||||||||||||||||||||||||||||||||
|
Retail
|
|
|||||||||||||||||||||||||||||||||||
|
Residential
|
$ | 46.4 | $ | 46.8 | (0.9 | %) | $ | 33.9 | $ | 30.1 | 12.6 | % | $ | 80.3 | $ | 76.9 | 4.4 | % | ||||||||||||||||||
|
Small Commercial
|
$ | 8.4 | $ | 8.5 | (1.2 | %) | $ | 7.2 | $ | 6.4 | 12.5 | % | $ | 15.6 | $ | 14.9 | 4.7 | % | ||||||||||||||||||
|
Large Commercial
|
$ | 28.3 | $ | 29.5 | (4.1 | %) | $ | 31.8 | $ | 28.2 | 12.8 | % | $ | 60.1 | $ | 57.7 | 4.2 | % | ||||||||||||||||||
|
Lighting
|
$ | 1.3 | $ | 1.3 | 0.0 | % | $ | 0.2 | $ | 0.1 | 100.0 | % | $ | 1.5 | $ | 1.4 | 7.1 | % | ||||||||||||||||||
|
Total Retail
|
$ | 84.4 | $ | 86.1 | (2.0 | %) | $ | 73.1 | $ | 64.8 | 12.8 | % | $ | 157.5 | $ | 150.9 | 4.4 | % | ||||||||||||||||||
|
Wholesale
|
||||||||||||||||||||||||||||||||||||
|
HEA
|
$ | 11.4 | $ | 10.5 | 8.6 | % | $ | 29.8 | $ | 26.3 | 13.3 | % | $ | 41.2 | $ | 36.8 | 12.0 | % | ||||||||||||||||||
|
MEA
|
$ | 20.9 | $ | 19.0 | 10.0 | % | $ | 42.6 | $ | 37.6 | 13.3 | % | $ | 63.5 | $ | 56.6 | 12.2 | % | ||||||||||||||||||
|
SES
|
$ | 1.1 | $ | 1.2 | (8.3 | %) | $ | 3.7 | $ | 3.2 | 15.6 | % | $ | 4.8 | $ | 4.4 | 9.1 | % | ||||||||||||||||||
|
Total Wholesale
|
$ | 33.4 | $ | 30.7 | 8.8 | % | $ | 76.1 | $ | 67.1 | 13.4 | % | $ | 109.5 | $ | 97.8 | 12.0 | % | ||||||||||||||||||
|
Economy Sales
|
$ | 4.6 | $ | 1.5 | 206.7 | % | $ | 13.9 | $ | 4.2 | 231.0 | % | $ | 18.5 | $ | 5.7 | 224.6 | % | ||||||||||||||||||
|
Miscellaneous
|
$ | 2.8 | $ | 3.0 | (6.7 | %) | $ | 0.0 | $ | 0.0 | 0.0 | % | $ | 2.8 | $ | 3.0 | (6.7 | %) | ||||||||||||||||||
|
Total Revenue
|
$ | 125.2 | $ | 121.3 | 3.2 | % | $ | 163.1 | $ | 136.1 | 19.8 | % | $ | 288.3 | $ | 257.4 | 12.0 | % | ||||||||||||||||||
The major components of our operating revenue for the year ending December 31 were as follows:
|
2009
|
2009
|
2008
|
2008
|
2007
|
2007
|
|||||||||||||||||||
|
Sales (MWh)
|
Revenue
|
Sales (MWh)
|
Revenue
|
Sales (MWh)
|
Revenue
|
|||||||||||||||||||
|
Retail
|
1,183,705 | $ | 162,101,007 | 1,205,832 | $ | 157,549,359 | 1,206,037 | $ | 150,891,863 | |||||||||||||||
|
Wholesale:
|
||||||||||||||||||||||||
|
HEA
|
472,136 | 42,865,550 | 517,368 | 41,133,287 | 522,901 | 36,812,475 | ||||||||||||||||||
|
MEA
|
740,358 | 69,685,271 | 742,666 | 63,500,034 | 724,465 | 56,566,527 | ||||||||||||||||||
|
Seward
|
62,509 | 5,711,358 | 63,734 | 4,798,286 | 63,941 | 4,454,186 | ||||||||||||||||||
|
Total Wholesale
|
1,275,003 | 118,262,179 | 1,323,768 | 109,431,607 | 1,311,307 | 97,833,188 | ||||||||||||||||||
|
Economy energy
|
76,968 | 7,280,870 | 256,105 | 18,526,481 | 93,753 | 5,745,732 | ||||||||||||||||||
|
Other
|
N/A | 2,603,252 | N/A | 2,784,665 | N/A | 2,973,136 | ||||||||||||||||||
|
Total revenue
|
2,535,676 | $ | 290,247,308 | 2,785,705 | $ | 288,292,112 | 2,611,097 | $ | 257,443,919 | |||||||||||||||
Since 1989, we have sold economy (non-firm) energy to GVEA under an agreement that expired on March 31, 2009. Under that agreement, we used available generation in excess of our own needs to produce electric energy for sale to GVEA, which used that energy to serve its own loads in place of more expensive energy that it would have otherwise generated itself or purchased from other sources. We charged 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. Consequently, sales to GVEA did not significantly affect margins. We purchased gas from Marathon to produce energy for sale to GVEA. Chugach negotiated a three-month gas sales agreement, spanning September through November of 2009, with Marathon, to provide between 5,000 and 7,000 million cubic feet (MCF) per day to facilitate a 20 MW economy energy sale to GVEA. The short-term agreement was extended through December 31, 2009. We are currently using gas from existing contracts to make economy sales to GVEA as we negotiate other agreements. Sales were and continue to be made under the terms and conditions of Chugach’s economy energy sales tariff. In 2009, 2008, and 2007, economy sales to GVEA constituted approximately 3 percent, 6 percent, and 2 percent, respectively, of our sales revenues. Economy energy revenue decreased in 2009 from 2008 due primarily to the expiration of our agreement with GVEA. Economy energy revenue increased in 2008 from 2007 due to transmission line work, maintenance on several Beluga units and contracted fuel limitations in 2007.
Expenses
The major components of our operating expenses for the years ended December 31 were as follows:
|
2009
|
2008
|
2007
|
||||||||||
|
Fuel
|
$ | 136,416,761 | $ | 137,894,553 | $ | 106,023,734 | ||||||
|
Power production
|
16,406,911 | 16,718,777 | 16,171,717 | |||||||||
|
Purchased power
|
35,690,476 | 31,486,621 | 33,947,828 | |||||||||
|
Transmission
|
5,709,578 | 5,841,405 | 6,781,166 | |||||||||
|
Distribution
|
12,740,381 | 12,398,832 | 13,716,105 | |||||||||
|
Consumer accounts
|
5,259,348 | 5,396,662 | 4,899,878 | |||||||||
|
Administrative, general and other
|
20,518,688 | 20,014,239 | 21,776,968 | |||||||||
|
Depreciation
|
32,130,434 | 30,829,276 | 29,049,627 | |||||||||
|
Total operating expenses
|
$ | 264,872,577 | $ | 260,580,365 | $ | 232,367,023 | ||||||
Fuel
Chugach recognizes actual fuel expense as incurred. Fuel expense decreased $1.5 million, or 1.1 percent, in 2009 from 2008 due primarily to a decrease in MCF used as a result of lower kWh and economy sales, which was somewhat offset by a higher average effective fuel price. In 2009, Chugach used 26,139,407 MCF of fuel at an average effective price of $6.08 per MCF, which did not include 3,711,074 MCF of fuel that is recorded as purchased power expense. Fuel expense increased by $31.9 million, or 30.1 percent, in 2008 from 2007 due primarily to an increase in MCF used as a result of higher economy sales, the unavailability of our steam generating unit, Beluga Unit 8, due to maintenance and a higher average effective fuel price. The increase was also due in part to the impact of credits received in 2007 for reduced fuel production taxes. In 2008, Chugach used 30,792,658 MCF of fuel at an average effective price of $5.13 per MCF, which did not include 3,895,468 MCF of fuel that is recorded as purchased power expense.
Power Production
Power production expense did not materially change in 2009 from 2008.
Power production expense increased $547.1 thousand, or 3.4 percent, in 2008 from 2007 due primarily to the amortization associated with the Beluga River Gas Compression project, as well as the accelerated amortization of the prior Beluga Unit 8 overhaul caused by a change to the maintenance schedule.
Purchased Power
Purchased power costs increased $4.2 million, or 13.4 percent, in 2009 from 2008 due primarily to an increase in MWh purchased and a higher average effective price caused by higher fuel prices. In 2009, Chugach purchased 502,063 MWh of energy at an average effective price of 6.81 cents per kWh. Purchased power costs decreased $2.5 million, or 7.2 percent, in 2008 from 2007 due primarily to less MWh purchased, which was somewhat offset by a higher price caused by higher fuel prices. Transmission line work and other maintenance activities in 2007 limited our generation, resulting in higher purchased power costs in 2007. In 2008, Chugach purchased 483,742 MWh of energy at an average effective price of 6.24 cents per kWh.
Transmission
Transmission expense did not materially change in 2009 from 2008.
Transmission expense decreased $939.8 thousand, or 13.9 percent, in 2008 from 2007 due primarily to lower labor expense related to substation maintenance as well as lower information services allocated compliance costs.
Distribution
Distribution expense did not materially change in 2009 from 2008.
Distribution expense decreased $1.3 million, or 9.6 percent, in 2008 from 2007 due primarily to lower labor and professional services associated with line maintenance, as well as lower information services allocated compliance costs.
Consumer Accounts
Consumer accounts expense did not materially change in 2009 from 2008.
Consumer accounts expense, which represents costs associated with maintaining customer accounts and membership, increased $496.8 thousand, or 10.1 percent, in 2008 from 2007 due primarily to an increase in uncollectible accounts and higher advertising and imaging costs associated with capital credit retirements.
Administrative, General and Other Charges
Overall, administrative, general and other charges did not materially change in 2009 from 2008, however, an increase in other deductions caused by the write off of obsolete inventory and cancelled projects and an increase in labor was partially offset by a decrease in legal expenses and credit card fees.
Administrative, general and other charges decreased $1.8 million, or 8.1 percent, in 2008 from 2007 due primarily to lower professional services and information services allocated compliance costs in 2007. The decrease was also due to a decrease in credit card fees in 2008 compared to 2007.
Depreciation
Depreciation expense increased $1.3 million, or 4.2 percent, in 2009 from 2008 due to a full year of new depreciation rates as a result of Chugach’s 2005 Test Year Rate Case and the closeout of construction projects.
Depreciation expense increased $1.8 million, or 6.1 percent, in 2008 from 2007 due in part to a change in depreciation rates as a result of Chugach’s 2005 Test Year Rate Case, as well as the continued closeout of construction projects.
Interest
Interest on long-term obligations decreased $1.2 million, or 5.4 percent, in 2009 from 2008 due primarily to the use of our NRUCFC line of credit to redeem the outstanding principal amount of the 2002 Series B Bonds in March of 2008, resulting in a shift from long-term to short-term interest expense, lower interest rates in 2009 and continued principal payments on our CoBank debt.
Interest on long-term obligations decreased $2.9 million, or 12.1 percent, in 2008 from 2007 due primarily to the use of our NRUCFC line of credit to redeem the outstanding principal amount and pay accrued interest on the 2002 Series B Bonds in March of 2008. The decrease was also due to continued principal payments as well as lower interest rates in 2008 compared to 2007.
Interest on short-term borrowings decreased $0.6 million, or 37.2 percent, in 2009 from 2008 due primarily to the difference between the balance of the NRUCFC line of credit used in 2008 to redeem the 2002 Series B Bonds and the balance of commercial paper outstanding which was used to pay the balance of the NRUCFC line of credit in 2009. The decrease is also due to the difference in interest rates between the NRUCFC line of credit in 2008 and the commercial paper interest rates in 2009. The decreases were slightly offset by a shift from long-term to short-term interest expense described above.
Interest on short-term borrowing increased $1.6 million in 2008 from 2007 due primarily to the use of the NRUCFC line of credit described above and the increased use of our CoBank line of credit in 2008 compared to 2007. This increase is net of the affects of a decrease in interest rates in 2008 compared to 2007.
Interest charged to construction increased $154.8 thousand, or 34.7 percent, in 2009 from 2008 due primarily to a higher average balance in Construction Work In Progress (CWIP), primarily due to capital spending associated with SPP, which was slightly offset by a lower weighted average rate during 2009 of 4.9 percent compared to 5.1 percent during 2008.
Interest charged to construction decreased $170.7 thousand, or 27.7 percent, in 2008 from 2007 due primarily to a lower weighted average rate during 2008 of 5.1 percent compared to 6.3 percent during 2007.
Patronage Capital (Equity)
The following table summarizes our patronage capital and total equity position for the years ended December 31:
|
2009
|
2008
|
2007
|
||||||||||
|
Patronage capital at beginning of year
|
$ | 142,009,998 | $ | 138,713,338 | $ | 141,117,620 | ||||||
|
Retirement of capital credits
|
(3,442,125 | ) | (3,115,090 | ) | (5,289,538 | ) | ||||||
|
Assignable margins
|
5,660,348 | 6,411,750 | 2,885,256 | |||||||||
|
Patronage capital at end of year
|
144,228,221 | 142,009,998 | 138,713,338 | |||||||||
|
Other equity1
|
12,092,376 | 11,757,001 | 10,597,098 | |||||||||
|
Total equity at end of year
|
$ | 156,320,597 | $ | 153,766,999 | $ | 149,310,436 | ||||||
1Other equity includes memberships, donated capital and gain on capital credit retirements.
We credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves. These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of distributions of these amounts to members, also known as capital credits, is at the discretion of our Board. We currently have a practice of retiring patronage capital on a first-in, first-out basis for retail customers. The Board may also return capital credits to former members and estates who have requested early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002. Chugach retired $3,442,125, $3,115,090, and $5,289,538 in capital credits for the years ended December 31, 2009, 2008, and 2007, respectively. Prior to 2000, wholesale capital credits had been retired on a 10-year cycle pursuant to an approved capital credit retirement program, which was contained in the Chugach business plan. However, in 2000 we implemented a plan to return the capital credits of wholesale and retail customers on a 15-year rotation. For the years 1997, 1998 and 1999, wholesale capital credits were retired on a 10-year cycle pursuant to a prior settlement agreement. In 2009, 2008 and 2007, $1,674,809, $1,478,779 and $79,079, respectively, of 1999, 1998 and 1997 wholesale capital credits were retired to MEA, HEA and SES.
The Amended and Restated Indenture prohibits us from making any distributions, payment or retirement of patronage capital to our customers if an event of default under the Amended and Restated Indenture exists. Otherwise, we may make distributions to our members in each year equal to the lesser of 5 percent of our patronage capital or 50 percent 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 percent of our total liabilities and equities and margins.
Under our Master Loan Agreement with CoBank, Chugach is prohibited from making any distribution of patronage capital to Chugach’s customers if an event of default under the Master Loan Agreement exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent 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 percent of Chugach’s total liabilities and equities and margins.
During 2008 the Board of Directors approved the deferral of capital credit retirements after 2009 due to the construction of new generation and the anticipated loss of wholesale load in 2014.
Changes in Financial Condition
Assets
Total assets decreased $11.4 million, or 2.0 percent, from December 31, 2008, to December 31, 2009. The decrease was due in part to a $4.0 million, or 53.2 percent decrease in cash and cash equivalents. The decrease was also due to an $11.5 million, or 97.6 percent decrease in fuel cost under-recovery due to the collection of fuel and purchased power costs through the fuel surcharge process. The decrease was also due to a $0.3 million, or 18.3 percent decrease in prepayments and a $1.5 million, or 6.5 percent decrease in deferred charges due to the amortization of deferred charges which exceeded the costs associated with the overhauls of units at the Cooper Lake Power Plant, fuel supply negotiations and the charges associated with Cooper Lake license requirements. The decreases were offset by a $4.8 million, or 1.0 percent increase in net utility plant due to extension and replacement of plant in excess of depreciation expense, as well as a $1.2 million, or 4.1 percent, increase in materials and supplies due primarily to the purchase of materials for planned generation and distribution projects.
Liabilities
Total liabilities decreased by $13.9 million, or 3.3 percent, in 2009 as compared to 2008. Contributors to this change include a $2.9 million, or 100 percent, decrease in promissory notes payable caused by the payment of the note associated with the property Chugach acquired for construction of an additional electrical generation facility. The decrease also includes a $7.5 million, or 100 percent decrease in short-term obligations due to the payment of the outstanding balance on the CoBank line of credit. Fuel payable also decreased $13.8 million, or 48.6 percent, due primarily to less fuel purchased as a result of lower kWh and economy sales. Other liabilities decreased $432.2 thousand, or 25.9 percent, due primarily to a decrease in the municipal underground ordinance payable. The decrease was also due to a $676.5 thousand, or 29.4 percent decrease in deferred credits caused primarily by the transfer of customer advances to construction projects. These decreases were offset by a $3.5 million, or 100 percent increase in fuel cost over-recovery due to the over-collection of fuel and purchased power costs through the fuel surcharge process. The net of total long-term obligations and current installments of long-term debt and commercial paper increased $4.1 million, or 1.2 percent, caused by the difference in commercial paper borrowing in 2009 compared to the NRUCFC line of credit in 2008, which was somewhat offset by the principal payments made on CoBank 2, 3, 4 and 5 in 2009. Salaries, wages and benefits payable increased $474.7 thousand, or 8.7 percent and accounts payable increased $3.2 million, or 45.9 percent due to the timing of cash payments on invoices for good and services.
Equities and Margins
Total margins and equities increased $2.6 million, or 1.7 percent, in 2009 compared to 2008 due to a $2.2 million, or 1.6 percent, net increase in patronage capital ($5.6 million increase in margins coupled with a $3.4 million retirement of capital credits).
Inflation
Chugach is subject to the inflationary trends existing in the general economy. We do not believe that inflation had a significant effect on our operations in 2009. Chugach’s gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel surcharge process, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not significantly affect our operations.
Contractual Obligations and Commercial Commitments
The following are Chugach’s contractual and commercial commitments as of December 31, 2009:
Contractual cash obligations: (In thousands)
Payments Due By Period
|
Total
|
2010
|
2011-2012 | 2013-2014 |
Thereafter
|
||||||||||||||||
|
Long-term debt, including current portion
|
$ | 311,420 | $ | 4,118 | $ | 275,545 | $ | 4,343 | $ | 27,414 | ||||||||||
|
Long-term interest expense1
|
33,824 | 18,166 | 11,660 | 1,328 | 2,670 | |||||||||||||||
|
Commercial Paper2
|
51,500 | 51,500 | 0 | 0 | 0 | |||||||||||||||
|
Bradley Lake3
|
48,744 | 3,696 | 7,366 | 7,332 | 30,350 | |||||||||||||||
|
Fuel and fuel transportation expense4
|
795,620 | 94,374 | 355,474 | 283,029 | 62,743 | |||||||||||||||
|
Gas turbine purchase agreement5
|
29,192 | 29,192 | 0 | 0 | 0 | |||||||||||||||
|
Transportation services contract6
|
1,116 | 1,116 | 0 | 0 | 0 | |||||||||||||||
|
Total
|
$ | 1,271,416 | $ | 202,162 | $ | 650,045 | $ | 296,032 | $ | 123,177 | ||||||||||
1 Long-term interest expense includes fixed and variable rates. Variable rates are based on rates at December 31, 2009, for years 2010-2014 and thereafter. (See “Part II – Item 8 – Financial Statements and Supplementary Data – Note (8) Debt.”)
2 At December 31, 2009, Chugach’s Commercial Paper Program was backed by a $300 million Unsecured Credit Agreement between NRUCFC, KeyBank, CoBank and US Bank, which funds capital requirements. At December 31, 2009, there was $51.5 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $248.5 million and could be used for future operational and capital funding requirements.
3 Estimated annual cost
4 Estimated committed and uncommitted fuel and fuel transportation expense
5 In accordance with the General Electric Packaged Power gas turbine purchase agreement executed on November 17, 2008 and subsequent change orders
6 In accordance with the Services Contract for the shipment of the combustion turbine generators and related accessories
Purchase obligations
Chugach is a participant and has a 30.4 percent 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 $4.8 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.”) 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 process (See “Item 7-Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Overview-Rate Regulation and Rates-Fuel Surcharge.”)
Chugach is in the process of developing a natural gas fired generation plant on land currently owned by Chugach near its Anchorage headquarters. The SPP will be developed and owned jointly with AML&P. Chugach will own and take 70 percent of the new plant’s output and AML&P will own and take the remaining 30 percent. Chugach will account for its ownership in the SPP proportionately. Chugach and AML&P signed Participation, O&M and Lease Agreements (Agreements) for this project on August 28, 2008. On November 17, 2008, Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines with an option for a fourth turbine with GEPP. The option to purchase a fourth turbine expired on January 31, 2009. During 2009 Chugach executed several change orders associated with its purchase agreement with GEPP totaling $7.2 million, which included the purchase of a spare engine for maintenance purposes. Chugach made progress and milestone payments of $5.1 and $24.3 million in 2008 and 2009, respectively, and is expected to make payments of $29.2 million in 2010, pursuant to its purchase agreement and subsequent change orders with GEPP. In December of 2008, Chugach purchased land adjacent to its Anchorage headquarters for SPP use. Chugach executed an Owner’s Engineer Services Contract on May 12, 2009. This contract expired on December 31, 2009, but was later renewed effective January 1, 2010. Chugach made payments of $0.7 million in 2009, pursuant to its Owner’s Engineer Services Contract. On January 5, 2010, Chugach executed a Services Contract for the shipment of the combustion turbine generators and related accessories. Chugach is expected to make payments of $1.1 million in 2010 pursuant to this contract. On February 25, 2010, Chugach purchased additional land adjacent to its Anchorage headquarters for the laydown of equipment displaced by the new power plant. Chugach is currently proceeding with a RFP for engineering, procurement and construction services as well as a steam turbine generator purchase agreement to be awarded in 2010.
Liquidity And Capital Resources
Lines of Credit
Chugach maintained a $7.5 million line of credit with CoBank. The line of credit expired on October 31, 2009, and was subject to annual renewal at the discretion of the parties. Chugach did not renew this line of credit upon its expiration date due to unused carrying costs, its lack of use and the existence of the NRUCFC line of credit and Commercial Paper borrowing capacity. Chugach had activity on this line of credit in the first half of 2009, however, this line of credit wasn’t utilized in the third or fourth quarters of 2009 and had no outstanding balance upon its expiration on October 31, 2009. At December 31, 2008, the outstanding balance on this line of credit was $7.5 million. The borrowing rate is calculated using the CoBank Base Rate on the first business day of the week plus 3 percent. The average borrowing rate for 2009 and 2008 was 2.25 percent and 3.82 percent, respectively.
In addition, Chugach had an annual line of credit of $50 million available with NRUCFC until October 9, 2008, when Chugach reduced this line of credit to $45 million. The reduction to the borrowing limit was temporary in order that a full $300 million commitment on an unsecured credit agreement backstopping Chugach’s Commercial Paper program, could be met. On December 22, 2008, this line of credit was increased to $75 million, however, pursuant to the terms of the Amendment To Revolving Line of Credit Agreement with NRUCFC, this line of credit was permanently reduced to $50 million on January 30, 2009. Chugach utilized this line of credit in the first quarter of 2009 and had a balance of $38 million on January 30, 2009, when we repaid $30.0 million by issuing commercial paper under our Commercial Paper program described below. In February of 2009, Chugach repaid the balance on this line of credit by issuing additional commercial paper.
In March of 2008 Chugach borrowed $29.7 million on this line of credit to redeem the outstanding principal amount and pay accrued interest on the 2002 Series B Bonds. Chugach also utilized this line of credit for general working capital in 2008 and had a balance of $43.0 million at December 31, 2008. The borrowing rate on the transaction to redeem the 2002 Series B Bonds was 2.75 percent at December 31, 2008. The borrowing rate on all other transactions at December 31, 2009 and 2008 was 4.95 percent and 5.00 percent, respectively and is calculated using the total rate per annum as may be fixed by CFC and will not exceed the Prevailing Prime Rate, plus one percent per annum. The NRUCFC line of credit expires October 14, 2012.
Commercial Paper
Over the next five years Chugach anticipates incurring increased amounts of capital expenditures due to the construction of a gas fired generation unit, on-going capital needs and the refinancing of $150 million of 2001 Series A Bonds that is due March 15, 2011, and $120 million of 2002 Series A Bonds due February 1, 2012. Commercial paper is being issued and will act as a bridge until Chugach converts Commercial Paper balances to long term debt and to refinance the 2011 and 2012 Series A bonds. Chugach’s Commercial Paper program is backed by a $300 million Unsecured Credit Agreement, executed on October 10, 2008, between NRUCFC, KeyBank, CoBank and US Bank. The agreement expires on October 10, 2011, however, at this time, management intends to renew this agreement although the terms may be different. On January 30, 2009, Chugach issued $36.0 million of commercial paper to repay its NRUCFC line of credit. On February 5, 2009, Chugach issued $10.0 million of commercial paper to repay the balance of its NRUCFC line of credit. Chugach continued to issue additional commercial paper in 2009 and had a balance of $51.5 million outstanding at December 31, 2009. Our commercial paper can be repriced between one and two hundred and seventy days. The following table provides information regarding average commercial paper balances outstanding (dollars in millions), as well as corresponding weighted average interest rates:
|
Month
|
Average
Balance
|
Weighted Average
Interest Rate
|
|
January 2009
|
36.0
|
1.17
|
|
February 2009
|
44.6
|
1.48
|
|
March 2009
|
46.6
|
1.19
|
|
April 2009
|
47.0
|
0.60
|
|
May 2009
|
43.0
|
0.53
|
|
June 2009
|
41.7
|
0.49
|
|
July 2009
|
41.5
|
0.44
|
|
August 2009
|
48.6
|
0.36
|
|
September 2009
|
53.1
|
0.32
|
|
October 2009
|
54.2
|
0.28
|
|
November 2009
|
52.9
|
0.26
|
|
December 2009
|
53.5
|
0.26
|
Principal maturities and sinking fund payments of our outstanding indebtedness, including commercial paper, at December 31, 2009 are set forth below:
|
Year Ending
December 31
|
Sinking Fund Requirements
|
Principal Maturities
|
Total
|
|||||||||
|
2010
|
0 | 55,618,028 | 55,618,028 | |||||||||
|
2011
|
150,000,000 | 2,851,501 | 152,851,501 | |||||||||
|
2012
|
120,000,000 | 2,693,543 | 122,693,543 | |||||||||
|
2013
|
0 | 2,076,355 | 2,076,355 | |||||||||
|
2014
|
0 | 2,266,145 | 2,266,145 | |||||||||
|
Thereafter
|
0 | 27,414,275 | 27,414,275 | |||||||||
| $ | 270,000,000 | $ | 92,919,847 | $ | 362,919,847 | |||||||
During 2009 we spent approximately $37.5 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 2010 through 2014 as contained in the Capital Improvement Plan (CIP), which was approved on October 28, 2009:
|
Year
|
Estimated Expenditures
|
|
|
2010
|
$111.9 million
|
|
|
2011
|
$131.9 million
|
|
|
2012
|
$65.5 million
|
|
|
2013
|
$44.2 million
|
|
|
2014
|
$20.9 million
|
We expect that cash flows from operations and external funding sources, including our available lines of credit and commercial paper program, will be sufficient to cover future operational and capital funding requirements.
Outlook
Procuring a new, highly efficient power generation facility, natural gas contracts, low cost financing and replacement revenue sources for wholesale customer loads that will be leaving in 2014, all while controlling operating expenses to minimize adverse customer rate impacts, are some of the challenges Chugach has faced and will continue to face in the near and intermediate term.
These issues, along with emerging energy issues and plans at the state level, will shape how Chugach proceeds into the future.
Chugach has partnered with AML&P to construct and jointly own a new 183 MW natural gas fired power plant. Chugach will own and take 70 percent of the new plant’s output and AML&P will own and take the remaining 30 percent. The plant is scheduled to be placed into service in 2013. Currently, major components have been ordered and engineering is moving forward with the anticipation of awarding an Engineer, Procure and Construct (EPC) contract in May of 2010. Chugach’s interim financing for the plant will come from a commercial paper borrowing program that was established via a $300 million unsecured credit agreement in 2008. Given the past volatility in the bond and commercial paper market, close attention will be given to the timing and type of permanent financing Chugach obtains for the new plant and other capital additions.
Chugach will explore all potential sources of long term financing to include federal, state, private placement and the public markets to obtain the lowest cost financing available for the 2011 and 2012 maturing long-term debt refinancing and requirements for new, long-term financing for our capital additions that are expected to begin in 2010.
On May 12, 2009, Chugach submitted a new long-term natural gas supply contract with COP to the RCA. The new contract will provide gas beginning in 2010 and terminating December 31, 2016. The total amount of gas under the contract is now estimated to be 62 BCF. The new contract is now designed to fill 100 percent of Chugach’s unmet needs until April 2011, approximately 50 percent of Chugach’s unmet needs from May 2011 through December 2014, approximately 60 percent in 2015 and approximately 29 percent in 2016. The RCA approved the gas supply contract between Chugach and COP effective August 21, 2009. The RCA also approved inclusion of all fuel (gas) and transportation costs related to the contract in the calculation of Chugach’s fuel surcharge process. Chugach has a tentative agreement on a contract that would fill Chugach’s remaining unmet needs through the near future and expects to file that contract with the RCA for approval by the end of the first quarter of 2010. The State of Alaska Department of Natural Resources (DNR) completed a preliminary engineering and geological evaluation of the remaining Cook Inlet gas reserves in December of 2009. The study identified 863 billion cubic feet (BCF) of proved, developed, producing reserves, additional probable reserves of 279 BCF and an additional increment of 353 BCF in high-confidence pay intervals. Combined, these 1.5 trillion cubic feet of gas reserves are similar to the 1.4 trillion cubic feet of gas reserves identified in a 2004 study undertaken by the Department of Energy in 2004. Given current demand and deliverability, DNR estimates at minimum a 10-year supply of gas exist in currently producing leases. DNR does note that economic considerations will play a major role in whether producers continue drilling and development activities to meet demand. Chugach has been working closely with the state and producers to develop a comprehensive Cook Inlet management plan that will meet this goal. Chugach continues to explore its options for future fuel supply needs by working with developers on commercial terms for natural gas storage and the state of Alaska on energy policies to promote gas development in Cook Inlet and other in-state gas options such as the North Slope Pipeline, Spur Line or Bullet line to South Central Alaska. Chugach is also evaluating liquefied natural gas (LNG) storage and import options as transition gas until in-state gas options are developed.
Notification was made by MEA in 2004 and by HEA in 2007 that neither organization intends to be on the Chugach system under the current contractual arrangements post 2014. This would result in a loss of approximately 50 percent of Chugach’s power sales load and approximately 40 percent of the utility’s annual sales revenue. While financial management plan scenarios indicate Chugach can sustain operations and meet financial covenants in the event these two customers leave the system, the remaining customers will have to shoulder the burden imposed by the remaining costs and will likely face higher rates. Neither MEA nor HEA have significant resources in place at this time that would indicate a complete reduction in service from Chugach is possible. Due to the lack of this necessary physical evidence, Chugach is preparing for a continuation of some business with HEA and MEA. At the August 26, 2009, Chugach Board of Directors’ meeting and in a letter dated September 3, 2009, MEA’s then Interim General Manager advised Chugach that MEA desires to open discussions regarding power sales possibilities beyond 2014. Chugach, however, is continuing to pursue replacement sources of revenue through potential new firm power sales agreements and revised transmission wheeling and ancillary services tariff revisions. We believe that successful implementation of new power sales agreements and revised tariffs will mitigate anticipated rate increases in the 2014 and 2015 timeframe. However, we cannot assure that we will be able to replace sources of revenue or that any replacement of revenue sources or revised tariffs will fully mitigate any anticipated rate increases in this timeframe.
A State of Alaska Energy Plan called for a migration to alternative fuel sources for one half of the state by 2025. This is in concert with Chugach’s conceptual goal to move from a “90 – 10” (90 percent natural gas fuel source – 10 percent alternative fuel source) generation mix to a “10 – 90” generation mix. Chugach’s challenge in the coming years will be to find low cost, highly efficient generation projects that fulfill this goal.
On March 5, 2009, the governor of Alaska transmitted a bill to the Alaska State Legislature that creates the Greater Railbelt Energy and Transmission Corporation (GRETC). In the Governor’s transmittal letter, she identified the purpose of the corporation was to “plan for the financing, acquisition, construction, ownership, and operation of necessary electric power generation and transmission assets and services that would be necessary to provide the Railbelt with adequate, reliable, safe, and stable electric power and transmission services at the lowest feasible long-term cost.” The legislation (HB 182 and SB 143) was introduced in both the House and Senate special committees on energy and is being held in committee until the 2010 legislative session. In the interim, the six Railbelt utility governing bodies agreed to form a special task force to further discuss the legislation and make recommendations to the state administration and the legislative committees. On November 13, 2009, Chugach, MEA and Seward issued a joint resolution in support of the GRETC concept. The three organizations outlined their vision in a resolution that noted many of the benefits the new organization would bring. On January 27, 2010, the Chugach Board of Directors passed a resolution supporting HB 182, enacting the establishment of GRETC. The task force of the boards of all Railbelt electric utilities will continue their work on GRETC and related issues.
Chugach has three CBA with the IBEW, which expire on June 30, 2010. We also have an agreement with the HERE which also expires on June 30, 2010. On February 24, 2010, the Board of Directors approved an extension of the IBEW Collective Bargaining Unit Agreements. The three extensions provide no wage increase in the first year and are attached to the CPI in the second and third years, with a floor on the minimum increase and a cap on the maximum increase. The wage increases also have an indirect connection to Chugach’s financial performance. The contract extensions expire on June 30, 2013.
Ratings
Our bond ratings with Fitch Investor Service, Moody’s Investors Service and Standard & Poors Ratings Services remained unchanged in 2009 at A- Stable, A3 Stable and A- Stable, respectively. In 2008, Standard & Poors Ratings Services and Moody’s Investors Services rated our Commercial Paper A-1 and P-2, respectively. Management does not believe this rating will materially affect interest rates associated with future financing.
Off-Balance Sheet Arrangements
We have not created, and are not party to, any special-purpose or off-balance-sheet entities for the purpose of raising capital, incurring debt or operating parts of our business that are not consolidated into our financial statements. We do not have any arrangements or relationships with entities that are not consolidated into our financial statements that are reasonably likely to materially affect our liquidity or the availability of our capital resources.
Critical Accounting Policies
Our accounting and reporting policies comply with U.S. generally accepted accounting principles (GAAP). The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and reported amounts of assets and liabilities in the financial statements. Significant accounting policies are described in Note 1 to the financial statements (See “Item 8 -Financial Statements and Supplementary Data.”). Critical accounting policies are those policies that management believes are the most important to the portrayal of Chugach's financial condition and results of its operations, and require management's most difficult, subjective, or complex judgments, often as a result of the need to make estimates about matters that are inherently uncertain. Most accounting policies are not considered by management to be critical accounting policies. Several factors are considered in determining whether or not a policy is critical in the preparation of financial statements. These factors include, among other things, whether the estimates are significant to the financial statements, the nature of the estimates, the ability to readily validate the estimates with other information including third parties or available prices, and sensitivity of the estimates to changes in economic conditions and whether alternative accounting methods may be utilized under GAAP. For all of these policies management cautions that future events rarely develop exactly as forecast, and the best estimates routinely require adjustment. Management has discussed the development and the selection of critical accounting policies with Chugach's Audit Committee. The following policies are considered to be critical accounting policies for the year ended December 31, 2009.
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 FASB ASC 980, “Topic 980 – Regulated Operations.” 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 FASB ASC 980 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 Chugach; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement benefits have less of a direct impact on Chugach's results of operations than they would on a non-regulated company. As reflected in the financial statements (See “Item 8 -Financial Statements and Supplementary Data – Note 1k – Deferred Charges and Credits”), significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislation and judicial or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact Chugach’s financial statements.
Unbilled revenue
Chugach calculates unbilled retail revenue at the end of each month to ensure the recognition of a full month’s revenue. Chugach estimates calendar-month unbilled sales based on billing cycle sales, billing cycle read dates, weather and hours of darkness to produce an estimate of calendar sales. This estimate of calendar sales is then calibrated to deliveries measured at Chugach distribution substations, net of losses. Until September of 2008, calendar unbilled revenue was determined by multiplying kWh sales by an average rate. Beginning in September of 2008, Chugach fully implemented an unbilled estimate based on respective billing class determinants to produce an estimate of calendar month revenue. Chugach accrued $9,417,906 and $10,024,312 of unbilled retail revenue at December 31, 2009 and 2008, respectively.
Allowance for Doubtful Accounts
We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We base our estimates on the aging of our accounts receivable balances, historical bad debt reserves, historical percent of retail revenue that has been deemed uncollectible, our collections process and regulatory requirements. If the financial condition of our customers were to deteriorate resulting in an impairment of their ability to make payments, additional allowances may be required. If their financial condition improves, allowances may be reduced. Such allowance changes could have a material effect on our consolidated financial condition and results of operations.
New Accounting Standards
ASC Update 2009-01 “Topic 105 – Generally Accepted Accounting Principles – amendments based on – Statement No. 168 – The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles”
In June 2009, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) Update 2009-01, “Topic 105 – Generally Accepted Accounting Principles – amendments based on Statement No. 168 – The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles.” This update applies to all financial statements of nongovernmental entities that are presented in conformity with U.S. GAAP. ASC Update 2009-01 does not change GAAP, it establishes the FASB Accounting Standards CodificationTM (Codification) as the source of authoritative GAAP to be applied by nongovernmental entities, while also acknowledging the rules and interpretive releases of the SEC under authority of federal securities laws as sources of authoritative GAAP for SEC registrants. Additionally, the Codification creates a new format for tracking, identifying, and citing GAAP, by numbered topics, subtopics, sections and paragraphs. As of the effective date of this update, all then-existing non-SEC standards will be superseded by the Codification and any non-SEC accounting literature not grandfathered will become non-authoritative. ASC Update 2009-01 is effective for financial statements issued for periods ending after September 15, 2009. Chugach began application of ASC Update 2009-01 to the financial statements for the period ended September 30, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
ASC Update 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements”
In January 2010, the FASB issued ASC Update 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” ASC Update 2010-06 applies to all entities that are required to make disclosures about recurring or nonrecurring fair value measurements and expands the disclosures required based on the measurement Level. This update is effective for the first reporting period (including interim periods) beginning after December 15, 2009, except for certain Level 3 transactions. Those transaction disclosure requirements are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Chugach will begin application of ASC Update 2010-06 to the financial statements for the period ended March 31, 2010, which we do not expect to have a material effect on our results of operations, financial position, and cash flows.
ASC Update 2009-05 “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value”
In August 2009, the FASB issued ASC Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value.” ASC Update 2009-05 applies to all entities that measure liabilities at fair value within the scope of Topic 820 and clarifies the measurement techniques to be used. This update is effective for the first reporting period (including interim periods) beginning after issuance. Chugach began application of ASC Update 2009-05 to the financial statements for the period ended December 31, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
SFAS 167 “Amendments to FASB Interpretation No. 46(R)”
In June 2009, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 167, “Amendments to FASB Interpretation No. 46(R).” SFAS No. 167 applies to all entities except for those identified in FASB Interpretation No. (FIN) 46(R), “Consolidation of Variable Interest Entities,” as well as entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated by SFAS No. 166, “Accounting for Transfers of Financial Assets.” SFAS No. 167 amends FIN 46(R) to require additional disclosures regarding an entity’s involvement in variable interest entities. SFAS No. 167 is effective for interim and annual reporting periods beginning after November 15, 2009. Chugach will begin application of SFAS No. 167 on January 1, 2010, which is not expected to have a material effect on our results of operations, financial position, and cash flows.
In December 2009, the FASB issued ASC Update 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” an adaptation of SFAS No. 167 into the Codification. To view the adapted content, see FASB ASC 810-10-30, for the Initial Measurement Section of Subtopic 10, and FASB ASC 810-10-65, for the Transition and Open Effective Date Information Section of Subtopic 810-10.
SFAS 166 “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”
In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140.” SFAS No. 166 applies to all entities and amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 140 was amended to enhance the disclosure requirements as well as to define some of the terms and measurements to be used, by removing the concept of a qualifying special-purpose entity and the exception from applying FIN 46, “Consolidation of Variable Interest Entities,” to qualifying special-purpose entities. SFAS No. 166 is effective for interim and annual reporting periods beginning after November 15, 2009. Chugach will begin application of SFAS No. 166 on January 1, 2010, which is not expected to have a material effect on our results of operations, financial position, and cash flows.
In December 2009, the FASB issued ASC Update 2009-16,”Accounting for Transfers of Financial Assets,” an adaptation of SFAS No. 166 into the Codification. To view the adapted content, see FASB ASC 860-10-40, for the Derecognition Section of Subtopic 10, and FASB ASC 860-10-65, for the Transition and Open Effective Date Information of Subtopic 860-10.
FAS 165 “Subsequent Events”
In May 2009, the FASB issued SFAS No. 165, “Subsequent Events.” SFAS No. 165 applies to the accounting for and disclosure of subsequent events, in both interim and annual financial statements. However, it does not apply to those subsequent events or transactions within the scope of other GAAP that provides different guidance of subsequent events and transactions. SFAS No. 165 is effective for interim and annual reporting periods ending after June 15, 2009. Chugach began application of SFAS No. 165 with the financial statements ending June 30, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
Effective July 2009, the FASB adapted SFAS No. 165 into the Codification. To view the adapted content, see FASB ASC 855-10 for the Overall Subtopic of Topic 855.
FAS 164 “Not-for-Profit Entities: Mergers and Acquisitions – Including an amendment of FASB Statement No. 142”
In April 2009, the FASB issued SFAS No. 164, “Not-for-Profit Entities: Mergers and Acquisitions – Including an amendment of FASB Statement No. 142.” SFAS No. 164 applies to the combination of not-for-profit entities meeting the definition of a merger or acquisition, with specific exceptions. SFAS No. 164 provides guidance on the accounting and disclosure of these combinations. SFAS No. 164 is effective for annual reporting periods beginning after December 15, 2009. Chugach will begin application of SFAS No. 164 on January 1, 2010, which is not expected to have a material effect on our results of operations, financial position, and cash flows.
In January 2010, the FASB issued ASC Update 2010-07, “Not-for-Profit Entities (Topic 958): Not-for-Profit Entities: Mergers and Acquisitions,” an adaptation of SFAS No. 164 into the Codification. To view the adapted content, see FASB ASC 954-805 for the Business Combinations Subtopic of Topic 954, FASB ASC 958-805 for the Business Combinations Subtopic of 958, FASB ASC 805-10-15 for the Scope and Scope Exceptions Section of Subtopic 805-10, FASB ASC 805-50-15 for the Scope and Scope Exceptions Section of Subtopic 805-50, and FASB ASC 350-10-65 for the Transition and Open Effective Date Information Section of Subtopic 350-10.
FSP FAS 107-1 and APB 25-1 “Interim Disclosures about Fair Value of Financial Instruments”
In April 2009, the FASB issued FASB Staff Position (FSP) FAS 107-1 and APB 25-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP applies to all financial instruments within the scope of SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” held by publicly traded companies, as defined by APB Opinion No. 28, “Interim Financial Reporting.” This FSP expands the reporting of fair value disclosures required by SFAS No. 107 to include interim reporting. This FSP also amends APB Opinion No. 28 to require those disclosures in summarized financial information of interim reports. FSP FAS 107-1 and APB 25-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. Chugach began application of FSP FAS 107-1 and APB 25-1 to fair value disclosures on January 1, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
Effective July 2009, the FASB adapted FSP FAS 107-1 and APB 25-1 into the Codification. To view the adapted content, see FASB ASC 825-10-65-1 for paragraph 1 of Section 825-10-65.
FSP FAS 115-2 and FAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments”
In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments.” FSP FAS 115-2 and FAS 124-2 applies to debt securities classified as available-for-sale and held-to-maturity that are subject to other-than-temporary impairment guidance within specific parameters. This FSP amends current GAAP guidance on other-than-temporary impairment of debt securities to make the guidance more operational and to improve the presentation and disclosure of those impairments in the financial statements. FSP FAS 115-2 and FAS 124-2 are effective for interim and annual reporting periods ending after June 15, 2009. Chugach began application of FSP FAS 115-2 and FAS 124-2 on April 1, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
Effective July 2009, the FASB adapted FSP FAS 115-2 and FAS 124-2 into the Codification. To view the adapted content, see FASB ASC 320-10-65-1 for paragraph 1 of Section 320-10-65.
FSP FAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
In April 2009, the FASB issued FSP FAS 157-4, ”Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions.” FSP FAS 157-4 applies to all assets and liabilities within the scope of accounting pronouncements that require or permit fair value measurement. FSP FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009. Chugach began application of FSP FAS 157-4 on April 1, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
Effective July 2009, the FASB adapted FSP FAS 157-4 into the Codification. To view the adapted content, see FASB ASC 820-10-65-4 for paragraph 4 of Section 820-10-65.
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, 2009:
|
Total Debt1
|
2010
|
2011
|
2012
|
2013
|
2014
|
Thereafter
|
Total
|
Fair
Value
|
||||||||||||||||||||||||
|
Fixed rate
|
$ | 1,500 | $ | 150,000 | $ | 120,000 | $ | 0 | $ | 0 | $ | 0 | $ | 271,500 | $ | 290,438 | ||||||||||||||||
|
Average interest rate
|
5.50 | % | 6.55 | % | 6.20 | % | 0.00 | % | 0.00 | % | 0.00 | % | 6.39 | % | ||||||||||||||||||
|
Annual interest expense
|
$ | 17,297 | $ | 9,487 | $ | 620 | $ | 0 | $ | 0 | $ | 0 | ||||||||||||||||||||
|
Variable rate
|
$ | 54,118 | 3 | $ | 2,852 | $ | 2,694 | $ | 2,076 | $ | 2,266 | $ | 27,414 | $ | 91,420 | $ | 91,420 | |||||||||||||||
|
Average interest rate2
|
0.36 | % | 2.40 | % | 2.40 | % | 2.40 | % | 2.40 | % | 2.40 | % | 1.19 | % | ||||||||||||||||||
1Includes current portion
2Chugach applies current variable rates for the years 2010-2014 and thereafter
3Commercial paper outstanding as of December 31, 2009, is considered short term with a maturity date of 2010
Chugach is exposed to market risk from changes in interest rates on its variable rate debt (Commercial paper and CoBank notes). A 100 basis-point change (up or down) would increase or decrease our interest expense by approximately $914,198, based on $91,419,847 of variable debt outstanding at December 31, 2009.
Commercial Paper
In 2009, Chugach issued commercial paper to repay the balance of its NRUCFC line of credit. Chugach continued to issue additional commercial paper in 2009 and had a balance of $51.5 million outstanding at December 31, 2009. For information regarding current commercial paper transactions, see “Item 7 - Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Commercial Paper.”
Commodity Price Risk
Chugach’s gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel surcharge process, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not normally impact margins.
Item 8 – Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors
Chugach Electric Association, Inc.
We have audited the accompanying balance sheets of Chugach Electric Association, Inc. as of December 31, 2009 and 2008, and the related statements of operations, changes in equities and margins, and cash flows for each of the years in the three-year period ended December 31, 2009. 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, 2009 and 2008, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2009, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG, LLP
March 4, 2010
Anchorage, Alaska
Chugach Electric Association, Inc.
Balance Sheets
December 31, 2009 and 2008
|
Assets
|
2009
|
2008
|
||||||
|
Utility Plant (notes 1d, 3, 11 and 12):
|
||||||||
|
Electric plant in service
|
$ | 834,467,734 | $ | 821,462,475 | ||||
|
Construction work in progress
|
48,383,610 | 25,151,072 | ||||||
|
Total utility plant
|
882,851,344 | 846,613,547 | ||||||
|
Less accumulated depreciation
|
(420,464,808 | ) | (389,002,139 | ) | ||||
|
Net utility plant
|
462,386,536 | 457,611,408 | ||||||
|
Other property and investments, at cost:
|
||||||||
|
Nonutility property
|
24,461 | 24,461 | ||||||
|
Special Funds
|
345,792 | 264,427 | ||||||
|
Investments in associated organizations (note 4)
|
12,333,936 | 12,177,769 | ||||||
|
Total other property and investments
|
12,704,189 | 12,466,657 | ||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents, including repurchase agreements of $4,593,703 in 2009 and $9,639,446 in 2008
|
3,503,765 | 7,491,302 | ||||||
|
Special deposits
|
125,037 | 114,930 | ||||||
|
Fuel cost under-recovery (note 1n)
|
278,164 | 11,788,078 | ||||||
|
Accounts receivable, less provision for doubtful accounts of $397,815 in 2009 and $408,632 in 2008
|
32,764,733 | 33,019,372 | ||||||
|
Materials and supplies
|
29,990,618 | 28,806,641 | ||||||
|
Prepayments
|
1,261,897 | 1,544,025 | ||||||
|
Other current assets
|
246,380 | 272,357 | ||||||
|
Total current assets
|
68,170,594 | 83,036,705 | ||||||
|
Deferred charges, net (notes 5 and 13)
|
22,037,407 | 23,577,199 | ||||||
|
Total assets
|
$ | 565,298,726 | $ | 576,691,969 | ||||
Chugach Electric Association, Inc.
Balance Sheets (continued)
December 31, 2009 and 2008
|
Liabilities, Equities and Margins
|
2009
|
2008
|
||||||
|
Equities and margins (notes 6 and 7):
|
||||||||
|
Memberships
|
$ | 1,432,054 | $ | 1,390,413 | ||||
|
Patronage capital
|
144,228,221 | 142,009,998 | ||||||
|
Other
|
10,660,322 | 10,366,588 | ||||||
|
Total equities and margins
|
156,320,597 | 153,766,999 | ||||||
|
Long-term obligations, excluding current installments (notes 8 and 9):
|
||||||||
|
Bonds payable
|
270,000,000 | 270,000,000 | ||||||
|
National Bank for Cooperatives promissory notes payable
|
37,301,819 | 41,419,847 | ||||||
|
National Rural Utilities Cooperative Finance Corporation promissory notes payable
|
0 | 42,963,659 | ||||||
|
Total long-term obligations
|
307,301,819 | 354,383,506 | ||||||
|
Current liabilities:
|
||||||||
|
Current installments of long-term obligations (notes 8 and 9)
|
4,118,028 | 4,403,653 | ||||||
|
Commercial Paper
|
51,500,000 | 0 | ||||||
|
Promissory notes payable
|
0 | 2,860,000 | ||||||
|
Short-term obligations
|
0 | 7,500,000 | ||||||
|
Accounts payable
|
10,212,105 | 6,999,140 | ||||||
|
Consumer deposits
|
2,447,140 | 2,410,980 | ||||||
|
Fuel cost over-recovery (note 1n)
|
3,511,422 | 0 | ||||||
|
Accrued interest
|
6,067,630 | 6,158,927 | ||||||
|
Salaries, wages and benefits
|
5,956,320 | 5,481,621 | ||||||
|
Fuel
|
14,658,058 | 28,494,211 | ||||||
|
Other current liabilities
|
1,234,371 | 1,666,521 | ||||||
|
Total current liabilities
|
99,705,074 | 65,975,053 | ||||||
|
Deferred compensation
|
345,792 | 264,427 | ||||||
|
Deferred credits (note 5)
|
1,625,444 | 2,301,984 | ||||||
|
Total liabilities, equities and margins
|
$ | 565,298,726 | $ | 576,691,969 | ||||
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Operations
Years Ended December 31, 2009, 2008 and 2007
|
2009
|
2008
|
2007
|
||||||||||
|
Operating revenues (notes 1m, 2 and 13)
|
$ | 290,247,308 | $ | 288,292,112 | $ | 257,443,919 | ||||||
|
Operating expenses:
|
||||||||||||
|
Fuel (note 13)
|
136,416,761 | 137,894,553 | 106,023,734 | |||||||||
|
Power production
|
16,406,911 | 16,718,777 | 16,171,717 | |||||||||
|
Purchased power
|
35,690,476 | 31,486,621 | 33,947,828 | |||||||||
|
Transmission
|
5,709,578 | 5,841,405 | 6,781,166 | |||||||||
|
Distribution
|
12,740,381 | 12,398,832 | 13,716,105 | |||||||||
|
Consumer accounts
|
5,259,348 | 5,396,662 | 4,899,878 | |||||||||
|
Administrative, general and other charges
|
20,518,688 | 20,014,239 | 21,776,968 | |||||||||
|
Depreciation
|
32,130,434 | 30,829,276 | 29,049,627 | |||||||||
|
Total operating expenses
|
264,872,577 | 260,580,365 | 232,367,023 | |||||||||
|
Interest expense:
|
||||||||||||
|
On long-term obligations
|
20,159,196 | 21,309,900 | 24,239,343 | |||||||||
|
On short-term obligations
|
1,048,404 | 1,669,376 | 90,648 | |||||||||
|
Charged to construction-credit
|
(601,251 | ) | (446,479 | ) | (617,194 | ) | ||||||
|
Net interest expense
|
20,606,349 | 22,532,797 | 23,712,797 | |||||||||
|
Net operating margins
|
4,768,382 | 5,178,950 | 1,364,099 | |||||||||
|
Nonoperating margins:
|
||||||||||||
|
Interest income
|
250,958 | 553,362 | 710,480 | |||||||||
|
Capital credits, patronage dividends and other
|
641,008 | 679,438 | 810,677 | |||||||||
|
Total nonoperating margins
|
891,966 | 1,232,800 | 1,521,157 | |||||||||
|
Assignable margins
|
$ | 5,660,348 | $ | 6,411,750 | $ | 2,885,256 | ||||||
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Changes in Equities and Margins
Years Ended December 31, 2009, 2008 and 2007
|
Other Equities
|
Patronage
|
|||||||||||||||
|
Memberships
|
and Margins
|
Capital
|
Total
|
|||||||||||||
|
Balance, January 1, 2007
|
$ | 1,297,633 | $ | 8,300,847 | $ | 141,117,620 | $ | 150,716,100 | ||||||||
|
Assignable margins
|
0 | 0 | 2,885,256 | 2,885,256 | ||||||||||||
|
Retirement of capital credits
|
0 | 0 | (5,289,538 | ) | (5,289,538 | ) | ||||||||||
|
Unclaimed capital credit retirements
|
0 | 681,254 | 0 | 681,254 | ||||||||||||
|
Memberships and donations received
|
47,380 | 269,984 | 0 | 317,364 | ||||||||||||
|
Balance, December 31, 2007
|
1,345,013 | 9,252,085 | 138,713,338 | 149,310,436 | ||||||||||||
|
Assignable margins
|
0 | 0 | 6,411,750 | 6,411,750 | ||||||||||||
|
Retirement of capital credits
|
0 | 0 | (3,115,090 | ) | (3,115,090 | ) | ||||||||||
|
Unclaimed capital credit retirements
|
0 | 963,133 | 0 | 963,133 | ||||||||||||
|
Memberships and donations received
|
45,400 | 151,370 | 0 | 196,770 | ||||||||||||
|
Balance, December 31, 2008
|
1,390,413 | 10,366,588 | 142,009,998 | 153,766,999 | ||||||||||||
|
Assignable margins
|
0 | 0 | 5,660,348 | 5,660,348 | ||||||||||||
|
Retirement of capital credits
|
0 | 0 | (3,442,125 | ) | (3,442,125 | ) | ||||||||||
|
Unclaimed capital credit retirements
|
0 | 213,527 | 0 | 213,527 | ||||||||||||
|
Memberships and donations received
|
41,641 | 80,207 | 0 | 121,848 | ||||||||||||
|
Balance, December 31, 2009
|
$ | 1,432,054 | $ | 10,660,322 | $ | 144,228,221 | $ | 156,320,597 | ||||||||
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Statements of Cash Flows
Years Ended December 31, 2009, 2008 and 2007
|
2009
|
2008
|
2007
|
||||||||||
|
Cash flows from operating activities:
|
||||||||||||
|
Assignable margins
|
$ | 5,660,348 | $ | 6,411,750 | $ | 2,885,256 | ||||||
|
Adjustments to reconcile assignable margins to net cash provided by operating activities:
|
||||||||||||
|
Depreciation
|
32,130,434 | 30,829,276 | 29,049,627 | |||||||||
|
Amortization and depreciation cleared to operating expenses
|
4,755,265 | 5,029,029 | 3,376,708 | |||||||||
|
Capitalized interest
|
(746,532 | ) | (559,090 | ) | (891,443 | ) | ||||||
|
Property losses, net
|
35,289 | 2,231 | 16,748 | |||||||||
|
Write-off of inventory and projects
|
1,461,349 | 18,000 | 4,439 | |||||||||
|
Investments in associated organizations
|
(156,706 | ) | (184,390 | ) | (105,872 | ) | ||||||
|
Changes in assets and liabilities:
|
||||||||||||
|
(Increase) decrease in assets:
|
||||||||||||
|
Accounts receivable
|
584,825 | (1,663,891 | ) | 1,544,090 | ||||||||
|
Fuel cost under-recovery
|
11,509,914 | (11,788,078 | ) | 0 | ||||||||
|
Materials and supplies
|
(1,407,931 | ) | (384,553 | ) | (2,997,595 | ) | ||||||
|
Prepayments/Other assets
|
298,537 | (183,715 | ) | 228,145 | ||||||||
|
Deferred charges
|
(2,522,027 | ) | (6,640,741 | ) | (2,773,198 | ) | ||||||
|
Increase (decrease) in liabilities:
|
||||||||||||
|
Accounts payable
|
169,466 | (1,673,495 | ) | (124,362 | ) | |||||||
|
Consumer deposits/Other liabilities
|
(33,945 | ) | (4,555 | ) | (1,340,345 | ) | ||||||
|
Fuel cost over-recovery
|
3,511,422 | (1,596,010 | ) | 1,295,443 | ||||||||
|
Accrued interest
|
(91,297 | ) | (145,682 | ) | (59,491 | ) | ||||||
|
Salaries, wages and benefits
|
474,699 | (472,252 | ) | (67,600 | ) | |||||||
|
Fuel
|
(13,836,153 | ) | 6,156,558 | 6,178,870 | ||||||||
|
Deferred credits
|
11,219 | 55,070 | 16,646 | |||||||||
|
Net cash provided by operating activities
|
41,808,176 | 23,205,462 | 36,236,066 | |||||||||
|
Investing activities:
|
||||||||||||
|
Extension and replacement of plant
|
(37,499,061 | ) | (29,830,126 | ) | (28,483,067 | ) | ||||||
|
Net cash used in investing activities
|
(37,499,061 | ) | (29,830,126 | ) | (28,483,067 | ) | ||||||
|
Financing activities:
|
||||||||||||
|
Payments of notes payable
|
(2,860,000 | ) | 0 | 0 | ||||||||
|
Proceeds from short-term obligations
|
66,998,000 | 7,500,000 | 0 | |||||||||
|
Proceeds from long-term obligations
|
0 | 38,560,006 | 0 | |||||||||
|
Repayments of short-term obligations
|
(22,998,000 | ) | 0 | 0 | ||||||||
|
Repayments of long-term obligations
|
(47,367,312 | ) | (35,303,151 | ) | (9,001,795 | ) | ||||||
|
Memberships and donations received
|
21,624 | 70,761 | 76,969 | |||||||||
|
Retirement of patronage capital and estate payments
|
(3,022,246 | ) | (4,027,156 | ) | (3,273,914 | ) | ||||||
|
Net receipts of consumer advances for construction
|
931,282 | 1,105,570 | 810,763 | |||||||||
|
Net cash (used in) provided by financing activities
|
(8,296,652 | ) | 7,906,030 | (11,387,977 | ) | |||||||
|
Net changes in cash and cash equivalents
|
(3,987,537 | ) | 1,281,366 | (3,634,978 | ) | |||||||
|
Cash and cash equivalents at beginning of period
|
$ | 7,491,302 | $ | 6,209,936 | $ | 9,844,914 | ||||||
|
Cash and cash equivalents at end of period
|
$ | 3,503,765 | $ | 7,491,302 | $ | 6,209,936 | ||||||
|
Supplemental disclosure of non-cash investing and financing activities
|
||||||||||||
|
Retirement of plant (net of salvage)
|
$ | 991,011 | $ | 9,027,644 | $ | 9,473,461 | ||||||
|
Notes payable on land
|
$ | 0 | $ | 2,860,000 | $ | 0 | ||||||
|
Extension and replacement of plant included in accounts payable
|
$ | 5,712,404 | $ | 2,656,989 | $ | 2,084,120 | ||||||
|
Non-cash capital credit retirements
|
$ | 331,987 | $ | 1,089,142 | $ | 921,649 | ||||||
|
Patronage capital retired and estate payments included in other current liabilities
|
$ | 503,237 | $ | 415,345 | $ | 2,416,552 | ||||||
|
Supplemental disclosure of cash flow information – interest expense paid, excluding
|
||||||||||||
|
amounts capitalized
|
$ | 19,710,442 | $ | 21,536,503 | $ | 23,772,288 | ||||||
See accompanying notes to financial statements.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(1) Description of Business and Significant Accounting Policies
|
a. Description of Business
Chugach Electric Association, Inc. (Chugach) is the largest electric utility in Alaska. Chugach is engaged in the generation, transmission and distribution of electricity to directly serve retail customers in the Anchorage and upper Kenai Peninsula areas. Through an interconnected regional electrical system, Chugach's power flows throughout Alaska's Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska's largest cities, Anchorage and Fairbanks.
Chugach also supplies much of the power requirements of three wholesale customers, Matanuska Electric Association, Inc. (MEA), Homer Electric Association, Inc. (HEA) and the City of Seward (Seward). Chugach’s retail and wholesale members are the consumers of the electricity sold.
Chugach operates on a not-for-profit basis and, accordingly, seeks only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation, and principal and interest on all indebtedness and to provide for reserves. Chugach is subject to the regulatory authority of the Regulatory Commission of Alaska (RCA).
b. Management Estimates
In preparing the financial statements, management of Chugach is required to make estimates and assumptions relating to the reporting of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the balance sheet and revenues and expenses for the reporting period. Estimates include allowance for doubtful accounts, deferred charges and credits, unbilled revenue and the estimated useful life of utility plant. Actual results could differ from those estimates.
c. Regulation
The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 980, “Topic 980 - Regulated Operations.”
FASB ASC 980 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates. The regulatory assets or liabilities are then reduced as the cost or credit is reflected in rates.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(1)
|
Description of Business and Significant Accounting Policies (continued)
|
d. Utility Plant and Depreciation
Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. For property replaced or retired, the book value of the property, plus removal cost, less salvage, is charged to accumulated provision for depreciation. Renewals and betterments are capitalized, while maintenance and repairs are charged to expense as incurred.
In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain utility plant is reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable in rates. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.
Depreciation and amortization rates have been applied on a straight-line basis and at December 31 are as follows:
Annual Depreciation Rate Ranges
|
01/01/2005-05/31/2008
|
06/01/2008-12/31/2009
|
|||||||||||||||||||||||
|
Steam production plant
|
2.55 | % | - | 3.24 | % | 4.45 | % | - | 5.85 | % | ||||||||||||||
|
Hydraulic production plant
|
1.63 | % | - | 3.00 | % | 1.22 | % | - | 3.00 | % | ||||||||||||||
|
Other production plant
|
3.32 | % | - | 9.81 | % | 3.77 | % | - | 10.56 | % | ||||||||||||||
|
Transmission plant
|
1.72 | % | - | 5.26 | % | 1.61 | % | - | 6.67 | % | ||||||||||||||
|
Distribution plant
|
2.10 | % | - | 9.98 | % | 1.95 | % | - | 9.77 | % | ||||||||||||||
|
General plant
|
2.23 | % | - | 27.25 | % | 1.25 | % | - | 26.11 | % | ||||||||||||||
|
Other
|
2.75 | % | - | 2.75 | % | 2.75 | % | - | 2.75 | % | ||||||||||||||
On April 1, 2008, the RCA issued Order 21, which allowed Chugach to revise its depreciation rates effective June 1, 2008. See Note (2) – “Regulatory Matters – 2005 Test Year General Rate Case (Docket U-06-134).”
The most significant change resulting from the 2005 Depreciation Study update approved by the RCA in Order 21 was a reduction of the useful life of the steam plant from forty years to thirty years, which caused an increase in the rates for steam production plant. The useful life of the hydraulic production plant at Cooper Lake was extended to 2057 to coincide with the expiration of the fifty year FERC license for the Cooper Lake facility. This resulted in a decrease in the depreciation rates for most hydraulic production plant. Other factors that drove modifications to the depreciation rates included changes in surviving original cost, survivor curves and net salvage percentages.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(1) Description of Business and Significant Accounting Policies (continued)
|
e. Capitalized Interest
Allowance for funds used during construction (AFUDC) and interest charged to construction - credit (IDC) are the estimated costs during the period of construction of equity and borrowed funds. AFUDC and IDC are non-cash credits, which represent the estimated cost of funds used to finance the construction of utility plant. AFUDC and IDC are applied to applicable projects during construction. AFUDC and IDC include the net cost of borrowed funds and a rate of return on other funds when used and is recovered through rates as utility plant is depreciated. Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 4.9 percent during 2009, 5.1 percent during 2008 and 6.3 percent during 2007. Chugach capitalized actual interest expense and related fees associated with the construction of the Southcentral Power Project (SPP).
f. Investments in Associated Organizations
The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) require as a condition of the extension of credit, that an equity ownership position be established by all borrowers. Chugach’s equity ownership in these organizations is less than 1 percent. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment. No impairment was recorded during 2009, 2008 and 2007.
g. Fair Value of Financial Instruments
FASB ASC 825, “Topic 825 – Financial Instruments,” requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments:
|
|
Cash and cash equivalents - the carrying amount approximates fair value because of the short maturity of those instruments.
|
|
|
Consumer deposits - the carrying amount approximates fair value because of the short refunding term.
|
|
|
Long-term obligations - the fair value is estimated based on the quoted market price for same or similar issues (notes 8 and 9).
|
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(1) Description of Business and Significant Accounting Policies (continued)
h. Cash and Cash Equivalents
For purposes of the statement of cash flows, Chugach considers all highly liquid debt instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. Chugach has an Overnight Repurchase Agreement with First National Bank Alaska (FNBA). Each day the balance is invested by FNBA and Chugach receives varying interest rates for our investment pursuant to our Overnight Purchase Agreement. The Overnight Repurchase Agreement account had an average balance in 2009 and 2008 of $4,103,891 and $3,725,224, at an average interest rate of 0.17 percent and 1.43 percent, respectively.
i. Accounts Receivable
Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers.
j. Materials and Supplies
Materials and supplies are stated at average cost.
k. Deferred Charges and Credits
In accordance with FASB ASC 980, Chugach’s financial statements reflect regulatory assets and liabilities. Continued accounting under FASB ASC 980, requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for rate making purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria. However, if events or circumstances should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on the financial position and results of operations. Deferred charges, primarily representing regulatory assets, are amortized to operating expense over the period allowed for rate making purposes. Deferred credits, primarily representing regulatory liabilities, are amortized to operating expense over the period allowed for rate making purposes. It also includes nonrefundable contributions in aid of construction, which are credited to the associated cost of construction of property units. Refundable contributions in aid of construction are held in deferred credits pending their return or other disposition.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(1) Description of Business and Significant Accounting Policies (continued)
l. Patronage Capital
|
|
Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on Chugach's statement of revenues and expenses as assignable margins. These excess amounts (i.e. assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by Chugach until such future time as they are retired and returned without interest at the discretion of the Board of Directors. Retained assignable margins are designated on Chugach's balance sheet as patronage capital. This patronage capital constitutes the principal equity of Chugach. The Board of Directors may also approve the return of capital to former members and estates who request early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002.
|
m. Operating Revenues
Revenues are recognized upon delivery of electricity. Operating revenues are based on billing rates authorized by the RCA, which are applied to customers' usage of electricity. Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results. Chugach calculates unbilled revenue at the end of each month to ensure the recognition of a calendar year’s revenue. Chugach accrued $9,417,906 and $10,024,312 of unbilled retail revenue at December 31, 2009 and 2008, respectively. Wholesale revenue is recorded from metered locations on a calendar month basis, so no accrual is made. Chugach's tariffs include provisions for the flow through of gas costs according to existing gas supply contracts, as well as purchased power costs.
n. Fuel and Purchased Power Costs Recovery
Expenses associated with electric services include fuel used to generate electricity and power purchased from others. Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel surcharge process, which is adjusted quarterly to reflect increases and decreases of such costs. We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates. The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under or over collection of fuel and purchase power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods. Fuel costs were over-recovered by $3,233,258 in 2009 and under-recovered by $11,788,078 in 2008. Total fuel and purchased power costs in 2009, 2008, and 2007 were $172,107,237, $169,381,174, and $139,971,562, respectively.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(1) Description of Business and Significant Accounting Policies (continued)
o. Environmental Remediation Costs
Chugach accrues for losses and establishes a liability associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. Estimates of future costs for environmental remediation obligations are not discounted to their present value. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset.
p. Income Taxes
Chugach is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code and for the years ended December 31, 2009, 2008 and 2007 was in compliance with that provision. In addition, as described in “Note (13) - Commitments, Contingencies and Concentrations,” Chugach collects sales tax and is assessed gross receipts and excise taxes which are presented on a net basis in accordance with FASB ASC 605-45-50, “Topic 605 - Revenue Recognition – Subtopic 45 - Principal Agent Considerations – Section 50 - Disclosure.”
Chugach applies a more-likely-than-not recognition threshold for all tax uncertainties. FASB ASC 740 only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. Chugach’s management reviewed Chugach’s tax positions and determined there were no outstanding, or retroactive tax positions, with less than a fifty percent likelihood of being sustained upon examination by the taxing authorities.
Management has concluded that there are no significant uncertain tax positions requiring recognition in its financial statements for all periods presented. Chugach’s evaluation was performed for the tax periods ended December 31, 2006 through December 31, 2009 for U.S. Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2009.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(1) Description of Business and Significant Accounting Policies (continued)
q. Recently Issued Accounting Pronouncements
ASC Update 2009-01 “Topic 105 – Generally Accepted Accounting Principles – amendments based on – Statement No. 168 – The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles”
In June 2009, the FASB issued ASC Update 2009-01, “Topic 105 – Generally Accepted Accounting Principles – amendments based on Statement No. 168 – The FASB Accounting Standards CodificationTM and the Hierarchy of Generally Accepted Accounting Principles.” This update applies to all financial statements of nongovernmental entities that are presented in conformity with U.S. Generally Accepted Accounting Principles (GAAP). ASC Update 2009-01 does not change GAAP, it establishes the FASB Accounting Standards CodificationTM (Codification) as the source of authoritative GAAP to be applied by nongovernmental entities, while also acknowledging the rules and interpretive releases of the SEC under authority of federal securities laws as sources of authoritative GAAP for SEC registrants. Additionally, the Codification creates a new format for tracking, identifying, and citing GAAP, by numbered topics, subtopics, sections and paragraphs. As of the effective date of this update, all then-existing non-SEC standards will be superseded by the Codification and any non-SEC accounting literature not grandfathered will become non-authoritative. ASC Update 2009-01 is effective for financial statements issued for periods ending after September 15, 2009. Chugach began application of ASC Update 2009-01 to the financial statements for the period ended September 30, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
ASC Update 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements”
In January 2010, the FASB issued ASC Update 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” ASC Update 2010-06 applies to all entities that are required to make disclosures about recurring or nonrecurring fair value measurements and expands the disclosures required based on the measurement Level. This update is effective for the first reporting period (including interim periods) beginning after December 15, 2009, except for certain Level 3 transactions. Those transaction disclosure requirements are effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Chugach will begin application of ASC Update 2010-06 to the financial statements for the period ended March 31, 2010, which we do not expect to have a material effect on our results of operations, financial position, and cash flows.
ASC Update 2009-05 “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value”
In August 2009, the FASB issued ASC Update 2009-05, “Fair Value Measurements and Disclosures (Topic 820) – Measuring Liabilities at Fair Value.” ASC Update 2009-05 applies to all entities that measure liabilities at fair value within the scope of Topic 820 and clarifies the measurement techniques to be used. This update is effective for the first reporting period (including interim periods) beginning after issuance. Chugach began application of ASC Update 2009-05
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(1) Description of Business and Significant Accounting Policies (continued)
q. Recently Issued Accounting Pronouncements (continued)
to the financial statements for the period ended December 31, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
SFAS 167 “Amendments to FASB Interpretation No. 46(R)”
In June 2009, the FASB issued Statement of Financial Accounting Standards (SFAS) No. 167, “Amendments to FASB Interpretation No. 46(R).” SFAS No. 167 applies to all entities except for those identified in FIN 46(R), “Consolidation of Variable Interest Entities,” as well as entities previously considered qualifying special-purpose entities, as the concept of these entities was eliminated by SFAS No. 166, “Accounting for Transfers of Financial Assets.” SFAS No. 167 amends FIN 46(R) to require additional disclosures regarding an entity’s involvement in variable interest entities. SFAS No. 167 is effective for interim and annual reporting periods beginning after November 15, 2009. Chugach will begin application of SFAS No. 167 on January 1, 2010, which is not expected to have a material effect on our results of operations, financial position, and cash flows.
In December 2009, the FASB issued ASC Update 2009-17, “Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities,” an adaptation of SFAS No. 167 into the Codification. To view the adapted content, see FASB ASC 810-10-30, for the Initial Measurement Section of Subtopic 10, and FASB ASC 810-10-65, for the Transition and Open Effective Date Information Section of Subtopic 810-10.
SFAS 166 “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140”
In June 2009, the FASB issued SFAS No. 166, “Accounting for Transfers of Financial Assets – an amendment of FASB Statement No. 140.” SFAS No. 166 applies to all entities and amends SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities.” SFAS No. 140 was amended to enhance the disclosure requirements as well as to define some of the terms and measurements to be used, by removing the concept of a qualifying special-purpose entity and the exception from applying FIN 46, “Consolidation of Variable Interest Entities,” to qualifying special-purpose entities. SFAS No. 166 is effective for interim and annual reporting periods beginning after November 15, 2009. Chugach will begin application of SFAS No. 166 on January 1, 2010, which is not expected to have a material effect on our results of operations, financial position, and cash flows.
In December 2009, the FASB issued ASC Update 2009-16,”Accounting for Transfers of Financial Assets,” an adaptation of SFAS No. 166 into the Codification. To view the adapted content, see FASB ASC 860-10-40, for the Derecognition Section of Subtopic 10, and FASB ASC 860-10-65, for the Transition and Open Effective Date Information of Subtopic 860-10.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(1) Description of Business and Significant Accounting Policies (continued)
q. Recently Issued Accounting Pronouncements (continued)
FAS 165 “Subsequent Events”
In May 2009, the FASB issued SFAS No. 165, “Subsequent Events.” SFAS No. 165 applies to the accounting for and disclosure of subsequent events, in both interim and annual financial statements. However, it does not apply to those subsequent events or transactions within the scope of other GAAP that provides different guidance of subsequent events and transactions. SFAS No. 165 is effective for interim and annual reporting periods ending after June 15, 2009. Chugach began application of SFAS No. 165 with the financial statements ending June 30, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
Effective July 2009, the FASB adapted SFAS No. 165 into the Codification. To view the adapted content, see FASB ASC 855-10 for the Overall Subtopic of Topic 855.
FAS 164 “Not-for-Profit Entities: Mergers and Acquisitions – Including an amendment of FASB Statement No. 142”
In April 2009, the FASB issued SFAS No. 164, “Not-for-Profit Entities: Mergers and Acquisitions – Including an amendment of FASB Statement No. 142.” SFAS No. 164 applies to the combination of not-for-profit entities meeting the definition of a merger or acquisition, with specific exceptions. SFAS No. 164 provides guidance on the accounting and disclosure of these combinations. SFAS No. 164 is effective for annual reporting periods beginning after December 15, 2009. Chugach will begin application of SFAS No. 164 on January 1, 2010, which is not expected to have a material effect on our results of operations, financial position, and cash flows.
In January 2010, the FASB issued ASC Update 2010-07, “Not-for-Profit Entities (Topic 958): Not-for-Profit Entities: Mergers and Acquisitions,” an adaptation of SFAS No. 164 into the Codification. To view the adapted content, see FASB ASC 954-805 for the Business Combinations Subtopic of Topic 954, FASB ASC 958-805 for the Business Combinations Subtopic of 958, FASB ASC 805-10-15 for the Scope and Scope Exceptions Section of Subtopic 805-10, FASB ASC 805-50-15 for the Scope and Scope Exceptions Section of Subtopic 805-50, and FASB ASC 350-10-65 for the Transition and Open Effective Date Information Section of Subtopic 350-10.
FSP FAS 107-1 and APB 25-1 “Interim Disclosures about Fair Value of Financial Instruments”
In April 2009, the FASB issued FASB Staff Position (FSP) FAS 107-1 and APB 25-1, “Interim Disclosures about Fair Value of Financial Instruments.” This FSP applies to all financial instruments within the scope of SFAS No. 107, “Disclosures about Fair Value of Financial Instruments,” held by publicly traded companies, as defined by APB Opinion No. 28, “Interim Financial Reporting.” This FSP expands the reporting of fair value disclosures required by SFAS No. 107 to include interim reporting. This FSP also amends APB Opinion No. 28 to require those disclosures in summarized financial information of interim reports. FSP FAS 107-1 and APB 25-1 is effective for interim periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. Chugach began application of FSP FAS 107-1 and APB 25-1 to fair
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(1) Description of Business and Significant Accounting Policies (continued)
q. Recently Issued Accounting Pronouncements (continued)
value disclosures on January 1, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
Effective July 2009, the FASB adapted FSP FAS 107-1 and APB 25-1 into the Codification. To view the adapted content, see FASB ASC 825-10-65-1 for paragraph 1 of Section 825-10-65.
FSP FAS 115-2 and FAS 124-2 “Recognition and Presentation of Other-Than-Temporary Impairments”
In April 2009, the FASB issued FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary Impairments.” FSP FAS 115-2 and FAS 124-2 applies to debt securities classified as available-for-sale and held-to-maturity that are subject to other-than-temporary impairment guidance within specific parameters. This FSP amends current GAAP guidance on other-than-temporary impairment of debt securities to make the guidance more operational and to improve the presentation and disclosure of those impairments in the financial statements. FSP FAS 115-2 and FAS 124-2 are effective for interim and annual reporting periods ending after June 15, 2009. Chugach began application of FSP FAS 115-2 and FAS 124-2 on April 1, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
Effective July 2009, the FASB adapted FSP FAS 115-2 and FAS 124-2 into the Codification. To view the adapted content, see FASB ASC 320-10-65-1 for paragraph 1 of Section 320-10-65.
FSP FAS 157-4 “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
In April 2009, the FASB issued FSP FAS 157-4, ”Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions.” FSP FAS 157-4 applies to all assets and liabilities within the scope of accounting pronouncements that require or permit fair value measurement. FSP FAS 157-4 is effective for interim and annual reporting periods ending after June 15, 2009. Chugach began application of FSP FAS 157-4 on April 1, 2009, which did not have a material effect on our results of operations, financial position, and cash flows.
Effective July 2009, the FASB adapted FSP FAS 157-4 into the Codification. To view the adapted content, see FASB ASC 820-10-65-4 for paragraph 4 of Section 820-10-65.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(1) Description of Business and Significant Accounting Policies (continued)
r. Fair Values of Assets and Liabilities
Fair Value Hierarchy
In accordance with FASB ASC 820, Chugach groups its financial assets and liabilities measured at fair value in three levels, based on the markets in which the assets and liabilities are traded and the reliability of the assumptions used to determine fair value. These levels are:
Level 1 – Valuation is based upon quoted prices for identical instruments traded in active exchange markets, such as the New York Stock Exchange. Level 1 also includes U.S. Treasury and federal agency securities, which are traded by dealers or brokers in active markets. Valuations are obtained from readily available pricing sources for market transactions involving identical assets or liabilities.
Level 2 – Valuation is based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant assumptions are observable in the market.
Level 3 – Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect Chugach’s estimates of assumptions that market participants would use in pricing the asset or liability. Valuation techniques include use of option pricing models, discounted cash flow models and similar techniques.
The table below presents the balance of Chugach’s non-qualified deferred compensation plan measured at fair value on a recurring basis.
|
Total
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
|
2009
|
$ | 345,792 | $ | 345,792 | $ | 0 | $ | 0 | ||||||||
|
2008
|
$ | 264,427 | $ | 264,427 | $ | 0 | $ | 0 | ||||||||
Chugach had no Level 2 or Level 3 assets or liabilities measured at fair value on a recurring basis.
s. Presentation of Financial Information
For the year ended December 31, 2009, the company recorded an immaterial adjustment to correctly present cash used in investing activities and cash used in financing activities for the years ended December 31, 2008 and 2007. The adjustment represents the amount of non-refundable consumer advances previously included as a reduction of cash used in investing activities and now included as a reduction of cash used in financing activities. The impact of the adjustment was to increase cash used in investing activities by $765,019 in 2008 and $1,229,771 and reduce cash used in financing activities by the same amount.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(2) Regulatory Matters
2008 Test Year General Rate Case (Docket U-09-080)
On June 23, 2009, Chugach filed a general rate case with the RCA to increase base rate revenue by $4.2 million, with increases of $2.7 million to Chugach retail customers and $1.5 million to wholesale customers. Base rates charged to retail customers increased 3.3 percent and base rates charged to wholesale customers HEA, MEA and Seward increased 7.8 percent, 2.0 percent and 9.7 percent, respectively. The estimated increase to Chugach’s retail end-users is approximately 1.7 percent, while the increase to retail end-users of Chugach’s wholesale customers is approximately 0.9 percent. Chugach requested that the proposed rates become effective on an interim and refundable basis beginning August 7, 2009.
On August 7, 2009, the RCA suspended Chugach’s filing into Docket U-09-080 and issued Order No. 1. The RCA indicated that it would issue a final order in this case no later than September 16, 2010. The RCA did not issue a decision on Chugach’s interim rate request. The RCA named the Attorney General and Chugach’s wholesale customers HEA, MEA and Seward parties to the docket.
On October 9, 2009, the RCA issued Order No. 2 granting Chugach’s original request that the proposed rates go into effect on an interim and refundable basis.
On October 15, 2009, the RCA consolidated Docket U-09-080 (General Rate Case) and Docket U-09-97 (Depreciation Study Update, explained below) and will hold combined hearings in June 2010. The Commission has indicated that it will issue a final order in the consolidated case by September 16, 2010.
Revision to Current Depreciation Rates (Docket U-09-097)
In accordance with a stipulation with its wholesale customers, HEA and MEA, Chugach filed on August 31, 2009, an updated depreciation study based on plant balances as of December 31, 2008. The RCA opened Docket U-09-097 to consider Chugach’s updated depreciation study and issued Order No. 1 on September 14, 2009. The RCA named Chugach’s wholesale customers HEA, MEA and Seward parties to the docket. As indicated in the discussion under the General Rate Case above, the RCA has consolidated the depreciation study update with the general rate case.
Amortization of Cooper Lake Unit No. 2 Overhaul Costs (Docket U-09-093)
On August 10, 2009, Chugach filed a request with the RCA to amortize approximately $1.07 million of expenditures associated with its 2008-2009 overhaul of Cooper Lake generating Unit 2 over a ten year period. The unit’s planned overhaul was accelerated due to extensive wear that caused a forced outage in August of 2008. With this request Chugach seeks to amortize the overhaul costs and record the unamortized balance as a “regulatory asset”.
On September 2, 2009, the RCA opened Docket U-09-093 to consider Chugach’s request and issued Order No. 1.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(2) Regulatory Matters (continued)
Amortization of Cooper Lake Unit No. 2 Overhaul Costs (Docket U-09-093) (continued)
On October 1, 2009, the RCA issued Order No. 2, naming Chugach’s wholesale customers, HEA and MEA, parties to the docket and scheduled a pre-hearing scheduling conference. Subsequent to this order, HEA has withdrawn from the docket and is therefore no longer participating in this adjudicatory process. The Commission accepted a stipulation between Chugach and MEA that no evidentiary hearing would be needed. Chugach and MEA submitted testimony and legal briefs.
Chugach received payments totaling $593,854 from its insurance carrier, FM Global, for proceeds related to the overhaul of Cooper Lake Unit 2. The payment amount will offset the costs that will be amortized and subsequently recovered in electric rates.
On February 5, 2010, the RCA issued Order No. 7, approving Chugach’s request to record the balance of expenditures associated with its overhaul of Cooper Lake Unit 2 as a regulatory asset and to amortize and recover those costs over a ten year period beginning May of 2009.
Request for Participation in the Simplified Rate Filing Process
On December 15, 2009, Chugach submitted a request to the RCA for approval to implement the Simplified Rate Filing (SRF) process for the adjustment of base energy and demand rates in accordance with Alaska Statute 42.05.381(e).
Utilization of SRF will allow Chugach to more efficiently adjust base rates in response to lower sales resulting from both energy conservation and technological improvements. Chugach is also interested in SRF as a means to expedite the rate adjustment process with the goal of timely cost recovery and lower adjudicatory costs.
Chugach requested that base rate adjustments under SRF be completed on a semi-annual basis, utilizing the twelve months ended June and December as the test periods in each year. Chugach requested that its initial SRF be submitted on the June 2010 test year for rate adjustments, if necessary, during fourth quarter, 2010.
Under SRF, base rate increases are limited to 8 percent over a 12-month period and 20 percent over a 36-month period. Chugach is still permitted to submit general rate case filings while participating in the SRF process. However, during these periods, rate adjustments under SRF would temporarily cease.
The Commission has not yet issued an order on Chugach’s request.
|
|
2005 Test Year General Rate Case (Docket U-06-134)
|
On September 29, 2006, Chugach filed a general rate case based on a 2005 test year with the RCA. Overall revenues were proposed to increase $2.8 million in the initial filing.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(2) Regulatory Matters (continued)
2005 Test Year General Rate Case (Docket U-06-134) (continued)
A settlement agreement reached in July 2007 between several of the intervenors and Chugach was accepted by the RCA in Order No. 15. On April 1, 2008, the RCA issued Order No. 21 in Docket U-06-134, approving the rates from the Settlement Agreement among Chugach, HEA and Seward. MEA did not join the Settlement Agreement. The effect of Order 21 was that overall revenues decreased by 0.8 percent, or $0.9 million, with retail base rate revenue decreasing by 4.8 percent, or $4.2 million and wholesale base rate revenue increasing by 11.0 percent, or $3.3 million. Order No. 21 was effective June 1, 2008.
After reconsiderations concerning a long-term debt allocator, the computation of depreciation expense and re-affirming filing requirements, the RCA issued Order No. 25 on November 7, 2008, accepting Chugach’s filings and closed docket U-06-134. In this rate case, we modified the rate design so that all fuel and purchased power costs would be recovered through the fuel and purchased power process, which was approved by the RCA.
|
(3)
|
Utility Plant
|
Major classes of utility plant as of December 31 are as follows:
|
Electric plant in service:
|
2009
|
2008
|
||||||
|
Steam production plant
|
$ | 60,462,671 | $ | 60,462,671 | ||||
|
Hydraulic production plant
|
20,315,628 | 19,597,661 | ||||||
|
Other production plant
|
132,645,379 | 137,480,817 | ||||||
|
Transmission plant
|
247,810,006 | 247,685,063 | ||||||
|
Distribution plant
|
242,798,640 | 242,489,152 | ||||||
|
General plant
|
47,756,148 | 46,634,280 | ||||||
|
Unclassified electric plant in service1
|
71,053,056 | 60,348,939 | ||||||
|
Other
|
11,626,206 | 6,763,892 | ||||||
|
Total electric plant in service
|
834,467,734 | 821,462,475 | ||||||
|
Construction work in progress2
|
48,383,610 | 25,151,072 | ||||||
|
Total electric plant in service and construction work in progress
|
$ | 882,851,344 | $ | 846,613,547 | ||||
|
|
1Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant. Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment.
|
|
|
2The amount associated with the construction of the SPP included in construction work in progress was $26.5 and $5.8 million at December 31, 2009 and 2008, respectively.
|
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(4) Investments in Associated Organizations
Investments in associated organizations include the following at December 31:
|
2009
|
2008
|
|||||||
|
National Rural Utilities Cooperative Finance Corporation
|
$ | 6,095,980 | $ | 6,095,980 | ||||
|
CoBank, ACB
|
6,174,680 | 6,022,743 | ||||||
|
NRUCFC capital term certificates
|
46,655 | 42,196 | ||||||
|
Other
|
16,621 | 16,850 | ||||||
|
Total Investments in Associated Organizations
|
$ | 12,333,936 | $ | 12,177,769 | ||||
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:
|
2009
|
2008
|
|||||||
|
Debt issuance and reacquisition costs
|
$ | 3,439,420 | $ | 5,254,072 | ||||
|
Refurbishment of transmission equipment
|
169,754 | 179,013 | ||||||
|
Studies
|
111,121 | 15,194 | ||||||
|
Beluga Gas Compression
|
3,772,461 | 4,918,909 | ||||||
|
Cooper Lake Relicensing / projects
|
6,119,493 | 5,857,388 | ||||||
|
Fuel supply negotiations
|
1,587,238 | 1,257,993 | ||||||
|
Major overhaul of steam generating unit
|
3,775,114 | 4,530,550 | ||||||
|
Other regulatory deferred charges
|
1,721,180 | 177,103 | ||||||
|
Environmental matters and other
|
1,341,626 | 1,386,977 | ||||||
|
Total deferred charges
|
$ | 22,037,407 | $ | 23,577,199 | ||||
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(5) Deferred Charges and Credits (continued)
Deferred Charges (continued)
Deferred charges, or regulatory assets, not currently being recovered, consisted of the following at December 31, 2009 and 2008:
|
2009
|
2008
|
|||||||
|
Fuel supply negotiations
|
$ | 1,444,789 | $ | 1,092,828 | ||||
|
Studies/Other
|
111,122 | 72,077 | ||||||
|
Cooper Lake Unit 1 Major Overhaul
|
1,053,269 | 0 | ||||||
|
Cooper Lake Relicensing
|
438,380 | 5,800,506 | ||||||
|
Labor Contract Negotiations
|
14,315 | 177,103 | ||||||
|
Debt issuance costs
|
0 | 626,628 | ||||||
|
Total deferred charges
|
$ | 3,061,875 | $ | 7,769,142 | ||||
We believe all the regulatory assets that are not currently being recovered are probable of recovery in the future based upon prior recovery of similar costs allowed by our regulator. Deferred charges are amortized over the life of the underlying asset.
|
|
Deferred Credits
|
Deferred credits, or regulatory liabilities, at December 31 consisted of the following:
|
2009
|
2008
|
|||||||
|
Refundable consumer advances for construction
|
$ | 857,322 | $ | 1,545,081 | ||||
|
Estimated initial installation costs for meters
|
120,185 | 141,712 | ||||||
|
Post retirement benefit obligation
|
593,600 | 593,600 | ||||||
|
Other
|
54,337 | 21,591 | ||||||
|
Total deferred credits
|
$ | 1,625,444 | $ | 2,301,984 | ||||
(6) Patronage Capital
Chugach has a Board approved capital credit retirement policy, which is contained in Chugach’s Financial Management Plan. This establishes, in general, a plan to return the capital credits of wholesale and retail customers based on the members’ proportionate contribution to Chugach’s assignable margins. At December 31, 2009, Chugach had $144,228,221 of patronage capital (net of capital credits retired in 2009), which included $138,567,873 of patronage capital that had been assigned and $5,660,348 of patronage capital to be assigned to its members. Approval of actual capital credit retirements is at the discretion of Chugach's Board of Directors. Chugach records a liability when the retirements are approved by the Board of Directors. The Amended and Restated Indenture and the CoBank Master Loan Agreement prohibits Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Amended and Restated Indenture or CoBank Master Loan Agreement exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent 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 percent of Chugach’s total liabilities and equities and margins.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(6)
|
Patronage Capital (continued)
|
Capital credits retired were $3,442,125, $3,115,090, and $5,289,538 for the years ended December 31, 2009, 2008, and 2007, respectively. The outstanding liability for capital credits authorized but not paid was $503,237 and $415,345 at December 31, 2009 and 2008, respectively.
|
|
During 2008, the Board of Directors approved the deferral of capital credit retirements after 2009 due to the construction of new generation and the anticipated loss of wholesale load in 2014.
|
|
(7)
|
Other Equities
|
A summary of other equities at December 31 follows:
|
2009
|
2008
|
|||||||
|
Nonoperating margins, prior to 1967
|
$ | 23,625 | $ | 23,625 | ||||
|
Donated capital
|
1,380,484 | 1,300,277 | ||||||
|
Unclaimed capital credit retirement1
|
9,256,213 | 9,042,686 | ||||||
|
Total other equities
|
$ | 10,660,322 | $ | 10,366,588 | ||||
|
|
1Represents unclaimed capital credits that have met all requirements of section 34.45.200 of Alaska’s unclaimed property law and has therefore reverted to Chugach.
|
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(8)
|
Debt
|
|
Long-term obligations at December 31 are as follows:
|
2009
|
2008
|
||||||
|
CoBank 2, 5.50% fixed rate note maturing in 2010, with interest and principal payable monthly; unsecured
|
$ | 1,500,000 | $ | 3,500,000 | ||||
|
CoBank 3 and 4, 2.24% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003; unsecured
|
36,999,447 | 38,462,805 | ||||||
|
CoBank 5, 2.24% variable rate note maturing in 2012, with interest and principal payable monthly; unsecured
|
2,920,400 | 3,860,695 | ||||||
|
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 | ||||||
|
NRUCFC line of credit, $29.7 million at 2.75% and $13.3 million at 5.00%, with interest payable monthly and principal due 2010; unsecured
|
0 | 42,963,659 | ||||||
|
Total long-term obligations
|
$ | 311,419,847 | $ | 358,787,159 | ||||
|
Less current installments
|
4,118,028 | 4,403,653 | ||||||
|
Long-term obligations, excluding current installments
|
$ | 307,301,819 | $ | 354,383,506 | ||||
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(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 CoBank, 2001 Series A, 2002 Series A and 2002 Series B bonds, provided that the bonds were secured by a mortgage on substantially all of Chugach’s assets so long as any amounts were outstanding to CoBank on bonds issued under the indenture. Upon the retirement of the then outstanding bonds on January 22, 2003, the 2001 Series A, 2002 Series A and 2002 Series B bonds (collectively, the 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, which covers the CoBank 2, 3, 4 and 5 promissory notes, between Chugach and CoBank dated December 27, 2002, pursuant to which CoBank and Chugach replaced the CoBank 2, 3, 4 and 5 bonds issued to CoBank with the above stated unsecured promissory notes not governed by the indenture. CoBank returned the old CoBank bonds to Chugach on January 22, 2003.
Chugach is also required to comply with the Credit Agreement, between Chugach and NRUCFC dated October 10, 2008, which covers loans and extended credit associated with Chugach’s commercial paper program, in an aggregate principal or face amount not exceeding $300 million at any one time outstanding.
Chugach is also required to comply with other covenants set forth in the Reimbursement and Indemnity Agreement with MBIA Insurance Corporation, which insures the outstanding 2001 Series A and 2002 Series A bonds and the Revolving Line of Credit Agreement with NRUCFC.
Security
On January 22, 2003, the Bonds became general unsecured and unsubordinated obligations. Under the Amended and Restated Indenture, Chugach is prohibited from creating or permitting to exist any mortgage, lien, pledge, security interest or encumbrance on Chugach’s properties and assets (other than those arising by operation of law) to secure the repayment of borrowed money or the obligation to pay the deferred purchase price of property unless Chugach equally and ratably secures the Bonds subject to the Amended and Restated Indenture, except that Chugach may incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements.
|
|
Rates
|
The Amended and Restated Indenture requires Chugach, subject to any necessary regulatory approval, to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. 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 adjustment to those rates so that they
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(8) Debt (continued)
Rates (continued)
would generate revenues reasonably expected to yield margins for interest equal to at least 1.10 times interest charges. 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. The NRUCFC Revolving Line of Credit Agreement requires Chugach to maintain an average Times Interest Earned Ratio (TIER) of not less than 1.10. The NRUCFC Credit Agreement requires Chugach to maintain a minimum margins for interest of at least 1.10 times interest charges for each fiscal year, calculated using the average margins for interest of the two best years out of the three fiscal years most recently ended. Margins for interest generally consist of Chugach’s assignable margins plus total interest expense.
Distributions to Members
The Amended and Restated Indenture and the CoBank Master Loan Agreement prohibits Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Amended and Restated Indenture or CoBank Master Loan Agreement exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent 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 percent of Chugach’s total liabilities and equities and margins.
Maturities of Long-term Obligations
Long-term obligations at December 31, 2009, mature as follows:
|
Year ending December 31
|
Sinking Fund
Requirements
2001 Series A Bonds
|
Sinking Fund
Requirements
2002 Series A Bonds
|
Principal Maturities
CoBank Promissory Notes
NRUCFC Line of Credit
|
Total
|
||||||||||||
|
2010
|
0 | 0 | 4,118,028 | 4,118,028 | ||||||||||||
|
2011
|
150,000,000 | 0 | 2,851,501 | 152,851,501 | ||||||||||||
|
2012
|
0 | 120,000,000 | 2,693,543 | 122,693,543 | ||||||||||||
|
2013
|
0 | 0 | 2,076,355 | 2,076,355 | ||||||||||||
|
2014
|
0 | 0 | 2,266,145 | 2,266,145 | ||||||||||||
|
Thereafter
|
0 | 0 | 27,414,275 | 27,414,275 | ||||||||||||
| $ | 150,000,000 | $ | 120,000,000 | $ | 41,419,847 | $ | 311,419,847 | |||||||||
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(8)
|
Debt (continued)
|
|
|
Lines of credit
|
Chugach maintained a $7.5 million line of credit with CoBank, ACB (CoBank). The line of credit expired on October 31, 2009, and was subject to annual renewal at the discretion of the parties. Chugach did not renew this line of credit upon its expiration date due to unused carrying costs, its lack of use and the existence of the NRUCFC line of credit and Commercial Paper borrowing capacity. Chugach had activity on this line of credit in the first half of 2009, however, this line of credit wasn’t utilized in the third or fourth quarters of 2009 and had no outstanding balance upon its expiration on October 31, 2009. At December 31, 2008, the outstanding balance on this line of credit was $7.5 million.
The CoBank Master Loan Agreement requires Chugach to establish and collect electric rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense, to achieve a funded debt to operating cash flow ratio not greater than 8 to 1 and achieve an equity to total capitalization ratio greater than 22 percent. The borrowing rate is calculated using the CoBank Base Rate on the first business day of the week plus 3 percent. The average borrowing rate for 2009 and 2008 was 2.25 percent and 3.82 percent, respectively.
In addition, Chugach had an annual line of credit of $50 million available with NRUCFC until October 9, 2008, when Chugach reduced this line of credit to $45 million. The reduction to the borrowing limit was temporary in order that a full $300 million commitment on an unsecured credit agreement backstopping Chugach’s Commercial Paper program, could be met. On December 22, 2008, this line of credit was increased to $75 million, however, pursuant to the terms of the Amendment To Revolving Line of Credit Agreement with NRUCFC, this line of credit was permanently reduced to $50 million on January 30, 2009. Chugach utilized this line of credit in the first quarter of 2009 and had a balance of $38 million on January 30, 2009, when we repaid $30.0 million by issuing commercial paper under our Commercial Paper program. In February of 2009, Chugach repaid the balance on this line of credit by issuing additional commercial paper.
In March of 2008 Chugach borrowed $29.7 million on this line of credit to redeem the outstanding principal amount and pay accrued interest on the 2002 Series B Bonds. Chugach also utilized this line of credit for general working capital in 2008 and had a balance of $43.0 million at December 31, 2008. The borrowing rate on the transaction to redeem the 2002 Series B Bonds was 2.75 percent at December 31, 2008. The borrowing rate on all other transactions at December 31, 2009 and 2008 was 4.95 percent and 5.00 percent, respectively and is calculated using the total rate per annum as may be fixed by NRUCFC and will not exceed the Prevailing Prime Rate, plus one percent per annum. The NRUCFC Revolving Line Of Credit Agreement requires that Chugach, for each 12-month period, for a period of at least five consecutive days, pay down the entire outstanding principal balance. The NRUCFC line of credit expires October 14, 2012.
The CoBank and NRUCFC lines of credit are immediately available for unconditional borrowing.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(8)
|
Debt (continued)
|
Notes payable
In December of 2008, Chugach acquired property near its Anchorage headquarters for, among other purposes, construction of an additional electrical generation facility. The total purchase price of the property was $4,860,000 which included a $75,000 non refundable earnest money payment, a $1,925,000 down payment and a $2,860,000 promissory note bearing interest at six percent per annum payable in two installments. A payment of $1,000,000 was made in March of 2009 and the final payment of $1,860,000 plus accrued interest was made on June 12, 2009. Chugach had the right to prepay any amount of the note in full at any time without penalty. The promissory note was secured by a deed of trust on the property.
Financing / Commercial Paper
Over the next five years, Chugach anticipates financing increased capital expenditures due to the construction of a natural gas fired generation unit, on-going capital needs and plans to refinance $150 million of 2001 Series A Bonds due March 15, 2011, and $120 million of 2002 Series A Bonds due February 1, 2012. Commercial paper is being issued and will act as a bridge until Chugach converts Commercial Paper balances to long term debt and to refinance the 2011 and 2012 Series A bonds. On October 10, 2008, Chugach entered into a $300 million Unsecured Credit Agreement between NRUCFC, KeyBank, CoBank and US Bank intended to back the commercial paper program. The Credit Agreement was priced with an all-in drawn spread of London Interbank Offered Rate (LIBOR) plus 60 basis points, along with a 17.5 basis points facility fee. The credit agreement expires on October 10, 2011. At this time, management intends to renew this agreement although the terms may be different. On January 30 and February 5, 2009, Chugach issued $36.0 and $10.0 million, respectively, of commercial paper to repay the balance of its NRUCFC line of credit. Chugach had additional commercial paper activity in 2009 and at December 31, 2009, had $51.5 million of commercial paper outstanding. Our commercial paper can be repriced between one day and two hundred and seventy days. The following table provides information regarding average commercial paper balances outstanding (dollars in millions), as well as corresponding weighted average interest rates:
|
Month
|
Average
Balance
|
Weighted Average
Interest Rate
|
|
January 2009
|
36.0
|
1.17
|
|
February 2009
|
44.6
|
1.48
|
|
March 2009
|
46.6
|
1.19
|
|
April 2009
|
47.0
|
0.60
|
|
May 2009
|
43.0
|
0.53
|
|
June 2009
|
41.7
|
0.49
|
|
July 2009
|
41.5
|
0.44
|
|
August 2009
|
48.6
|
0.36
|
|
September 2009
|
53.1
|
0.32
|
|
October 2009
|
54.2
|
0.28
|
|
November 2009
|
52.9
|
0.26
|
|
December 2009
|
53.5
|
0.26
|
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(9) Fair Value of Financial Instruments
The estimated fair values (in thousands) of the long-term obligations included in the financial statements at December 31 are as follows:
|
2009
|
2008
|
|||||||||||||||
|
Carrying Value
|
Fair Value
|
Carrying Value
|
Fair Value
|
|||||||||||||
|
Long-term obligations
|
||||||||||||||||
|
(including current installments)
|
$ | 311,420 | $ | 330,358 | $ | 358,787 | $ | 371,213 | ||||||||
Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions. The fair value of long-term debt has been determined using discounted future cash flows at borrowing rates currently available to Chugach. The fair value of cash and cash equivalents, accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature.
|
(10)
|
Employee Benefit Plans
|
Pension Plans
Pension benefits for substantially all union employees are provided through the Alaska Electrical Pension Trust Fund and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund, multi-employer plans. Chugach pays an hourly amount per eligible union employee pursuant to the collective bargaining unit agreements. In these master, multi-employer plans, the accumulated benefits and plan assets are not determined or allocated separately to the individual employer.
The costs for the union plans were approximately $3.0 million, $2.9 million, and $2.9 million in 2009, 2008, and 2007, respectively. Chugach has no responsibility for any unfunded benefit obligation of the Plan at this time.
Pension benefits for non-union employees are provided by the National Rural Electric Cooperative Association (NRECA) Retirement and Security Program, a multi-employer plan. Chugach makes annual contributions to the pension plan equal to the amounts accrued for pension expense. Chugach contributed $2.1 million, $1.8 million, and $1.9 million in 2009, 2008, and 2007, respectively, to the NRECA plan. Chugach has no responsibility for any unfunded benefit obligation of the Plan at this time.
Health and Welfare Plans
|
|
Health and welfare benefits for union employees are provided through the Alaska Electrical Health and Welfare Trust and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund. Chugach participates in multi-employer plans that provide substantially all union workers with health care and other welfare benefits during their employment with Chugach. Chugach pays a defined amount per union employee pursuant to
|
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(10) Employee Benefit Plans (continued)
Health and Welfare Plans (continued)
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, 2009, 2008, and 2007 were $3.4 million, $3.5 million, and $3.3 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, 2009, 2008, and 2007 totaled $2.1 million, $1.9 million, and $1.9 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, 2009, 2008, and 2007 were $99.7 thousand, $91.8 thousand, and $142.1 thousand, respectively.
|
401(k) Plan
Chugach has a defined contribution 401(k) retirement plan which covers substantially all employees who, effective January 1, 2008, can participate immediately.
Employees who elect to participate may contribute up to the Internal Revenue Service’s maximum of $16,500, $15,500, and $15,500 in 2009, 2008, and 2007 respectively. Chugach does not make contributions to the plan.
Deferred Compensation
Chugach adopted NRECA’s unfunded Deferred Compensation Program (the Program) to allow highly compensated employees who elect to participate in the Program to defer a portion of their current compensation and avoid paying tax on the deferrals until received. The program is a non-qualified plan under Internal Revenue Code 457(b).
Deferred compensation accounts are established for the individual employees, however, they are considered to be owned by Chugach until a distribution is made. The amounts credited to the deferred compensation account, including gains or losses, are retained by Chugach until the entire amount credited to the account has been distributed to the participant or to the participant’s beneficiary. The balance of the Program for the years ending December 31, 2009, 2008 and 2007 was $345,792, $264,427 and $768,041, respectively.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(10) Employee Benefit Plans (continued)
Potential Termination Payments
|
|
Pursuant to a Chugach Operating Policy, non-represented employees, including the executive officers except the Chief Executive Officer, who are terminated by Chugach for reasons unrelated to employee performance are entitled to severance pay for each year or partial year of service as follows: two weeks for each year of service to a maximum of twenty-six (26) weeks for thirteen (13) years or more of service.
|
|
(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 percent share of the project’s capacity. The share of debt service exclusive of interest, for which Chugach has guaranteed, is approximately $34 million. 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 percent. Upon default, Chugach could be faced with annual expenditures of approximately $5.4 million as a result of Chugach’s Bradley Lake take-or-pay obligations. Management believes that such expenditures, if any, would be recoverable through the fuel surcharge rate making process.
The following represents information with respect to Bradley Lake at June 30, 2009 (the most recent date for which information is available). Chugach's share of expenses was $5,152,716 in 2009, $4,746,965 in 2008, and $4,816,790 in 2007 and is included in purchased power in the accompanying financial statements.
|
(In thousands)
|
Total
|
Proportionate Share
|
||||||
|
Plant in service
|
$ | 196,824 | $ | 59,834 | ||||
|
Long-term debt
|
107,301 | 32,620 | ||||||
|
Interest expense
|
7,116 | 2,163 | ||||||
Other electric plant represents Chugach's share of a Bradley Lake transmission line financed internally and Electric Plant Held for Future Use.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(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 percent), MEA (16.7 percent) and Anchorage Municipal Light & Power (AML&P) (53.3 percent).
|
|
|
Plant in service in 2009 includes $2,397,677, net of accumulated depreciation of $898,649, which represents Chugach’s share of the Eklutna Hydroelectric Plant. In 2008 plant in service included $2,476,755, net of accumulated depreciation of $816,606. 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 $615,060, $886,261, and $712,552 in 2009, 2008, and 2007, respectively and is included in power production and depreciation expense in the accompanying financial statements. AML&P performs major maintenance at the plant. Chugach provides personnel for the daily operation and maintenance of the power plant, who 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.
|
|
|
Fuel Supply Contracts
|
Chugach has long-term fuel supply contracts from various producers at market terms. These contracts will expire at the end of the currently committed volumes or the contract expiration dates of 2015 and 2025. The committed 215 billion cubic feet (BCF) for the 2015 contract is expected to run out in 2010. The 180 BCF commitment for the 2025 contracts is expected to run out in early 2011. The RCA approved a gas supply contract between Chugach and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively “COP”), effective August 21, 2009. The new contract will provide gas beginning in 2010 and will terminate December 31, 2016. The total amount of gas under the contract is now estimated to be 62 BCF. The new contract is now designed to fill 100 percent of Chugach’s unmet needs until April 2011, approximately 50 percent of Chugach’s unmet needs from May 2011 through December 2014, approximately 60 percent in 2015 and approximately 29 percent in 2016. Chugach has a tentative agreement on a contract that would fill Chugach’s remaining unmet needs through the near future and expects to file that contract with the RCA for approval by the end of the first quarter of 2010. In 2009, 90 percent of our power was generated from gas, compared to 91 percent and 93 percent in 2008 and 2007 respectively. 83 percent of the gas-fired power was generated at Chugach’s Beluga Power Plant in 2009 compared with 76 percent in 2008 and 85 percent in 2007.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
|
(13)
|
Commitments, Contingencies and Concentrations (continued)
|
Fuel Supply Contracts (continued)
In 2009, fuel was purchased directly from Marathon Oil Company, Chevron/Unocal, AML&P and COP. The following represents the cost of fuel purchased from these vendors as a percentage of total fuel costs for the years ended December 31:
|
2009
|
2008
|
2007
|
||||||||||
|
Marathon Oil Company
|
44.6 | % | 49.7 | % | 46.4 | % | ||||||
|
Chevron/Unocal
|
20.9 | % | 19.1 | % | 20.4 | % | ||||||
|
AML&P
|
16.7 | % | 15.4 | % | 16.1 | % | ||||||
|
COP
|
17.8 | % | 15.8 | % | 16.9 | % | ||||||
|
|
Concentrations
|
Approximately 70 percent of Chugach’s employees are represented by the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW which expire on June 30, 2010. On February 24, 2010, the Board of Directors approved an extension of the IBEW Collective Bargaining Unit Agreements. The three extensions provide no wage increase in the first year and are attached to the Consumer Price Index (CPI) in the second and third years, with a floor on the minimum increase and a cap on the maximum increase. The wage increases also have an indirect connection to Chugach’s financial performance. The contract extensions expire on June 30, 2013.
Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts represented $112.6 million or 39 percent of sales revenue in 2009, $104.6 million or 37 percent in 2008, and $93.4 million or 37 percent in 2007. The HEA contract expires January 1, 2014, and the MEA contract expires December 31, 2014. Non-renewal of these contracts could have a negative impact on the rates charged to other Chugach customers. Notification was made by MEA and HEA that neither organization intends to renew these contracts, however, MEA has recently advised Chugach that it desires to open discussions regarding power sales possibilities beyond 2014. All rates are established by the RCA.
Regulatory Cost Charge
In 1992, the State of Alaska Legislature passed legislation authorizing the Department of Revenue to collect a Regulatory Cost Charge from utilities to fund the governing regulatory commission, which is currently the RCA. The tax is assessed on all retail consumers and is based on kilowatt-hour (kWh) consumption. The tax is collected monthly and remitted to the State of Alaska quarterly. The Regulatory Cost Charge has changed since its inception (November 1992) from an initial rate of $0.000626 per kWh to the current rate of $0.000432, effective July 1, 2009. The tax is reported on a net basis and the tax is not included in revenue or expense.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(13) Commitments, Contingencies and Concentrations (continued)
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 consumers.
Underground Compliance Charge
In 2005 the Anchorage Municipal Assembly adopted an ordinance to require utilities to convert overhead distribution lines to underground. To comply with the ordinance, Chugach must invest two percent of gross retail revenue in the Municipality of Anchorage annually in moving existing distribution overhead lines underground. Consistent with State of Alaska undergrounding requirement, Chugach is permitted to amend its rates by adding a 2 percent surcharge to its retail members’ bills to recover the actual costs of the program. The rate amendments are not subject to RCA review or approval. Chugach implemented the surcharge in June 2005. Chugach’s liability was $0 and $468,173 for this surcharge at December 31, 2009 and December 31, 2008, respectively and will use the funds to offset the costs of the projects.
Environmental Matters
The Clean Air Act and Environmental Protection Agency (EPA) regulations under the act (the “Clean Air Act”) establish ambient air quality standards and limit the emission of many air pollutants. Some Clean Air Act programs that regulate electric utilities, notably the Title IV “acid rain” requirements, do not apply to facilities located in Alaska. In 2008 the EPA vacated regulations to limit mercury emissions from fossil-fired steam-electric generating facilities.
New Clean Air Act regulations impacting electric utilities may result from future events or may result from new regulatory programs. On October 30, 2009, EPA published new federal regulations requiring the mandatory reporting of greenhouse gases from all sectors of the economy. Chugach is subject to this new regulation which is not expected to have a material effect on our results of operations, financial position, and cash flows. While we cannot predict whether any additional 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.
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(13) Commitments, Contingencies and Concentrations (continued)
Environmental Matters (continued)
In March 2007, Chugach conducted emissions testing at the Bernice Lake Power Plant which indicated that two of the gas turbines at the facility were exceeding the New Source Performance Standards (NSPS) emission limit for nitrogen oxides (NOx). Chugach voluntarily limited the power output of these turbines to ensure interim compliance with the NSPS regulations until a water injection system to control NOx emissions from the turbines was installed and operational. With the water injection system, Chugach is able to fully utilize the power output from these turbines while complying with the NSPS regulations.
The Alaska Department of Environmental Conservation (ADEC) issued a Notice of Violation (NOV) on March 26, 2008, regarding the NSPS NOx emission limit exceedances. Chugach entered into a settlement with ADEC regarding the NOV for the past NSPS non-compliance. Chugach and the ADEC signed the settlement agreement on February 18, 2009. As part of the settlement, Chugach paid a civil penalty of $112,161 to ADEC on April 3, 2009, bringing the issue to a close.
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.
Generation Commitments
Chugach is in the process of developing a natural gas fired generation plant on land currently owned by Chugach near its Anchorage headquarters. The SPP will be developed and owned jointly with AML&P. Chugach will own and take 70 percent of the new plant’s output and AML&P will own and take the remaining 30 percent. Chugach will account for its ownership in the SPP proportionately. Chugach and AML&P signed Participation, Operation and Maintenance (O&M) and Lease Agreements (Agreements) for this project on August 28, 2008. On November 17, 2008, Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines with an option for a fourth turbine with General Electric Packaged Power (GEPP). The option to purchase a fourth turbine expired on January 31, 2009. During 2009 Chugach executed several change orders associated with its purchase agreement with GEPP totaling $7.2 million, which included the purchase of a spare engine for maintenance purposes. Chugach made progress and milestone payments of $5.1 and $24.3 million in 2008 and 2009, respectively, and is expected to make payments of $29.2 million in 2010, pursuant to its purchase agreement and subsequent change orders with GEPP. In December of 2008, Chugach purchased land adjacent to its Anchorage headquarters for SPP use. Chugach executed an Owner’s Engineer Services Contract on May 12, 2009. This contract expired on December 31, 2009, but was later renewed effective January 1, 2010. Chugach made payments of $0.7 million in 2009, pursuant to its Owner’s Engineer Services Contract. On January 5, 2010, Chugach executed a Services Contract for the
Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2009 and 2008
(13) Commitments, Contingencies and Concentrations (continued)
Generation Commitments (continued)
shipment of the combustion turbine generators and related accessories. Chugach is expected to make payments of $1.1 million in 2010 pursuant to this contract. On February 25, 2010, Chugach purchased additional land adjacent to its Anchorage headquarters for the laydown of equipment displaced by the new power plant. Chugach is currently proceeding with a Request for Proposal (RFP) for engineering, procurement and construction services as well as a steam turbine generator purchase agreement to be awarded in 2010.
|
(14)
|
Quarterly Results of Operations (unaudited)
|
|
2009 Quarter Ended
|
||||||||||||||||
|
Dec. 31
|
Sept. 30
|
June 30
|
March 31
|
|||||||||||||
|
Operating Revenue
|
$ | 74,025,693 | $ | 63,565,392 | $ | 69,239,153 | $ | 83,417,070 | ||||||||
|
Operating Expense
|
64,737,009 | 60,092,648 | 65,798,407 | 74,244,513 | ||||||||||||
|
Net Interest
|
5,013,421 | 5,122,410 | 5,164,488 | 5,306,030 | ||||||||||||
|
Net Operating Margins
|
4,275,263 | (1,649,666 | ) | (1,723,742 | ) | 3,866,527 | ||||||||||
|
Non-Operating Margins
|
577,889 | 140,868 | 61,508 | 111,701 | ||||||||||||
|
Assignable Margins
|
$ | 4,853,152 | $ | (1,508,798 | ) | $ | (1,662,234 | ) | $ | 3,978,228 | ||||||
| 2008 Quarter Ended | ||||||||||||||||
|
Dec. 31
|
Sept. 30
|
June 30
|
March 31
|
|||||||||||||
|
Operating Revenue
|
$ | 83,640,633 | $ | 70,297,168 | $ | 62,483,023 | $ | 71,871,288 | ||||||||
|
Operating Expense
|
74,389,389 | 66,066,452 | 58,789,189 | 61,335,335 | ||||||||||||
|
Net Interest
|
5,911,966 | 5,605,569 | 5,384,524 | 5,630,738 | ||||||||||||
|
Net Operating Margins
|
3,339,278 | (1,374,853 | ) | (1,690,690 | ) | 4,905,215 | ||||||||||
|
Non-Operating Margins
|
807,390 | 152,127 | 121,691 | 151,592 | ||||||||||||
|
Assignable Margins
|
$ | 4,146,668 | $ | (1,222,726 | ) | $ | (1,568,999 | ) | $ | 5,056,807 | ||||||
Item 9 - Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure
None
Item 9A – Controls and Procedures
Evaluation of Controls and Procedures
As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 (“Exchange Act”) Rule 13a - 15(e)) under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO). Based on this evaluation, our CEO and CFO each concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic reports to the SEC. The design of any system of controls is based in part upon various assumptions about the likelihood of future events, and there can be no assurance that any of our plans, products, services or procedures will succeed in achieving their intended goals under future conditions. In addition, there have been no significant changes in our internal controls or in other factors known to management that could significantly affect our internal controls subsequent to our most recent evaluation.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal controls over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Under the supervision and with the participation of our management, including our CEO and CFO, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2009, using the criteria set forth in “Internal Control Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management believes that, as of December 31, 2009, Chugach maintained effective internal control over financial reporting. In addition, there have been no changes in Chugach’s internal control over financial reporting (as defined in Rules 13a-15(f) or 15d-15(f) of the Exchange Act) during the fourth quarter that has materially affected, or is reasonably likely to affect, its internal control over financial reporting. This annual report does not include an attestation report of Chugach’s independent registered public accounting firm, KPMG, LLP, regarding internal control over financial reporting. Management’s report was not subject to attestation by the company’s independent registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit the company to provide only management’s report in this annual report.
Item 9B – Other Information
None
PART III
Item 10 – Directors, Executive Officers and Corporate Governance
Chugach operates under the direction of a Board of Directors that is elected at large by our membership. Day-to-day business and affairs are administered by the CEO. Our seven-member Board sets policy and provides direction to the CEO. Each statutory officer must be a member of the Board, but these officers do not participate in the day-to-day management of Chugach. No member of the Board is an employee of the company nor does any member of the Board have a material relationship with the company. Therefore, the Chugach Board has determined that all members are independent. Our Board of Directors oversees Chugach’s risk management, satisfying itself that our risk management practices are consistent with our corporate strategy.
Identification of Directors
Rebecca Logan, 46, Chairman, is president and chief executive officer for the Associated Builders and Contractors, Alaska Chapter. She was appointed to fill a board vacancy in 2007 and elected to the board in 2008. Logan serves on the board’s Operations, Finance and Audit Committees and the Railbelt Utility Task Force. She also serves as Chugach’s Alaska Power Association (APA) Resolutions/Government Affairs representative. She is also a Northwest Public Power Association (NWPPA) Board of Trustee. Her term expires in April of 2011.
James Nordlund, 57, Vice Chairman, is currently the director of rural development for the U.S. Department of Agriculture (USDA). He is also a self-employed homebuilder and general contractor with Nordlund Carpentry, LLC. He was elected to the board in 2006. Nordlund is a former legislator and state Director of Public Assistance. He currently serves on the Operations Committee. He is a National Rural Electric Cooperative Credentialed Cooperative Director. His term expires in April of 2012.
Alex Gimarc, 58, Secretary, is a systems programmer with the Municipality of Anchorage. He was elected to the board in 2007. Gimarc currently serves on the board’s Operations, Finance and Audit Committees and the Railbelt Utility Task Force. He also serves as Chugach’s Joint Action Agency (JAA) and APA representative. His term expires in April of 2010.
P.J. Hill, 65, Treasurer, is a retired Associate Professor of Economics at the University of Alaska Anchorage and a commercial fisherman. He was elected to the board in 2007. Hill chairs the board’s Finance and Audit committees. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in April of 2010.
Elizabeth “Pat” Kennedy, 71, Director, is a self-employed state-licensed private guardian and conservator who has been a Chugach member since 1980. She was elected to the board in 2009 and serves on the board’s Finance and Audit committees and is board liaison to the Election Committee. She is also a former board member, who served from 1993 to 2001 and is an NRECA Credentialed Cooperative Director. Her term expires in April of 2012.
Janet Reiser, 54, Director, is an engineer and Managing Partner of Salus Management Services and Chief Operating Officer of Sea Lion International. She was elected to the board in 2008. She chairs the Operations Committee and is board liaison to the Renewable Energy Committee and the SPP management team. Her term expires in April of 2011.
Elizabeth Vazquez, 58, Director, is an attorney with the State of Alaska and has a Master of Business Administration. She was elected to the board in 2005 and re-elected in 2008. She also serves on the board’s Operations and Finance committees and is board liaison to the Bylaws Committee. She is an NRECA Credentialed Cooperative Director and has earned her Board Leadership Certificate. Her term expires in April of 2011.
Identification of Executive Officers
Bradley W. Evans, 55, was appointed Chief Executive Officer on July 1, 2008. Prior to that appointment, Mr. Evans had served as Interim CEO since December 5, 2007. Prior to that appointment, he had served as Sr. Vice President, Power Supply since March 20, 2006, General Manager, G&T Division since January 31, 2005, Sr. Vice President, Energy Supply since June 5, 2002 and Director, Energy Supply since February 26, 2001. Prior to his current Chugach employment, Mr. Evans served as Manager, System Dispatch for Golden Valley Electric Association.
Michael R. Cunningham, 60, was appointed Chief Financial Officer on June 5, 2002. Prior to that appointment he served as Controller since 1986. Prior to that, he was Budget Analyst and Manager of Accounting since beginning his Chugach employment in 1982. Prior to his Chugach employment, Mr. Cunningham spent 15 years in various capacities with Pacific Northwest Bell Telephone Company.
Edward M. Jenkin, 49, was appointed Vice President, Power Delivery on August 22, 2008. Prior to that appointment he had served as Acting Sr. Vice President, Power Delivery since January 14, 2008. Mr. Jenkin has over 20 years utility experience in engineering, system operations, and planning. He is a Registered Engineer in the State of Alaska. Mr. Jenkin was promoted from the position of the Director, Engineering Services Division that he held since July of 2004. Prior to that Mr. Jenkin served as System Operations Supervisor beginning in February of 2000 and was the Senior Planning Engineer starting August of 1995. Mr. Jenkin began his utility career as an Engineering Technician for Matanuska Electric Association in April of 1982.
Paul R. Risse, 55, was appointed Sr. Vice President, Power Supply on October 27, 2008. Prior to that appointment, Mr. Risse had served as Acting Sr. Vice President, Power Supply since December 6, 2007. Prior to that appointment, Mr. Risse had served as Director of Generation Technical Services since March 27, 2006; Manager, Plant Technical Services since January 1, 2003; Project Manager since August 15, 2000; Project Engineer since April 5, 2000; and Manager Substation Operations since January 25, 1995. Prior to his current Chugach employment, Mr. Risse served in various Transmission and Generation positions at Southern California Edison.
David R. Smith, 63, was appointed Sr. Vice President, Administration on October 1, 2008. Prior to that appointment, Mr. Smith had served as Acting Sr. Vice President, Administration since December 6, 2007. Mr. Smith has over 25 years of utility experience in Information Technology, Customer Service and Procurement. Mr. Smith was promoted from the position of Director, Information Services that he held since September 2001. Prior to that he had served as the Manager of Applications and Programming beginning in 1996. Mr. Smith began his utility career as a Project Manager in 1980, consulting with several utilities.
Lee D. Thibert, 54, was appointed Sr. Vice President, Strategic Planning and Corporate Affairs on June 11, 2008. Prior to that appointment he had served as Sr. Vice President, Power Delivery from March 20, 2006 to February 1, 2008. 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 served as Executive Manager, Transmission & Distribution Network Services since June 1, 1997. Prior to that, he was Executive Manager, Operating Divisions from June of 1994. Before moving up to the Executive Manager position, he served as Director of Operations from May 1987.
Tyler E. Andrews, 44, was appointed Vice President, Human Resources on March 17, 2008. Mr. Andrews has over 15 years of experience in Human Resources and Labor Relations. Since June of 2008, Mr. Andrews has also served as an appointed board member of the State of Alaska’s labor relations agency. Prior to his employment with Chugach, Mr. Andrews served as the Sr. Manager of Labor Relations for Alaska Communications Systems. Prior to that, he served 10 years with the State of Alaska in a wide range of Human Resources and Labor Relations functions including Human Resources Manager and Chief Spokesperson on numerous collective bargaining teams. Mr. Andrews holds a bachelor’s degree in economics from the University of North Carolina Chapel Hill.
Code of Ethics
Chugach finalized a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer and any person performing similar functions on June 16, 2004. In February of 2009, Chugach contracted with an outside firm to provide a financial reporting hotline to support the code of ethics. It is also posted on Chugach’s website at www.chugachelectric.com.
Nominating Committee
Chugach has not made any material changes to the procedures by which our membership may recommend nominees to our Board of Directors.
The Board appoints a nominating committee each year. The committee consists of members selected from different sections of the service area of Chugach. No member of the Board may serve on such committee. The committee reviews the qualifications of the Board candidates and nominates candidates for election at the annual meeting. The committee considers diversity, skills, and such other factors as it deems appropriate given the current needs of the Board and Chugach. Any fifty or more members, acting together, may make other nominations by petition.
Four of our current board members were nominated by the Nominating Committee based on a combination of his or her background, experience and answers to questions concerning Chugach’s goals and challenges. The other three board members were nominated by petition.
Audit Committee Financial Expert
Chugach is a cooperative and each Board member must be a member of the cooperative. The Board relies on the advice of all members of the Finance and Audit Committees, therefore the Board has not formally designated an Audit Committee financial expert.
Identification of the Audit Committee
Chugach Board Policy No. 127, “Audit Committee Charter,” defines the Audit Committee as follows:
The Audit Committee shall be comprised of three or more directors as determined by the Board. Unless otherwise determined by the Board, the members of the Board Finance Committee shall be the members of the Audit Committee. Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Association or an outside consultant or other programs. The Committee may also retain the services of a qualified accounting professional with auditing expertise to assist it in the performance of its responsibilities.
The Board Chairman shall appoint the Audit Committee chairperson, with the consent of the Board, who need not be the Board Treasurer. The Audit Committee shall elect from its members a vice chairman, and appoint a recording secretary as needed. Members of the 2010 Audit Committee include Chair P.J. Hill and Directors Alex Gimarc, Pat Kennedy and Rebecca Logan.
The disclosure required by §240.10A-3(d) regarding exemption from the listing standards for the audit committees is not applicable to the Chugach Audit Committee.
Item 11 - Executive Compensation
Compensation Discussion and Analysis
In 1986, the NRECA developed the COMPensate wage and salary plan to provide its members with a systematic and standardized method to evaluate jobs in their specific cooperative, grade them, compare wages and salaries with those in similar electric utility systems and in the external marketplace and then create and apply statistically determined, equitable pay scales. In 1988, the Chugach Board approved implementation of NRECA’s COMPensate wage and salary plan for non-bargaining unit employees with the objective of establishing wages and salaries for non-bargaining unit employees that would attract and retain qualified personnel and encourage their superior performance, growth and development.
Each year the regression analysis/compensation model is updated with current salary survey values to insure that the ranges reflect fair market value. The overall change to the salary ranges reflects market changes to the midpoint of the salary ranges and creates an opportunity for but not a guarantee of salary increases. Due to economic conditions and in an effort to control labor costs salary range updates have been suspended. Salary increases are not automatic and are based on performance. Any changes to the COMPensate wage and salary plan for Chugach are approved by the Chugach Board.
CEO Brad Evans is eligible for performance based bonuses at the discretion of the Board of Directors based on performance standards they develop. In 2009 the Board of Directors evaluated the performance of the CEO based on standards that included organization vision and planning, leadership and management, board relations and communications, election system operations, organization effectiveness, member/community relations, financial management and performance, employee relations and achievement of goals. Each category had a performance percentage between one and five percent. Based on this evaluation, the CEO received a discretionary bonus of $40,000, or 16% of his current salary before taxes.
The salary and bonuses for all other named executive officers are set annually by the CEO within annual budget guidelines approved by the Board of Directors.
Cash Compensation
The following table sets forth all remuneration paid by us for the last three fiscal years to each of our executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2009 and for all such executive officers as a group:
Summary Compensation Table
|
Name
|
Year
|
Salary
|
Bonus
|
Change in
Pension Value and Nonqualified Deferred Compensation Earnings
|
All
Other
Compensation1
|
Total
|
||||||||||||||||
|
Bradley W. Evans,
|
2009
|
$ | 250,029 | $ | 40,000 | $ | 98,704 | $ | 3,612 | $ | 392,345 | |||||||||||
|
Chief Executive Officer
|
2008
|
$ | 224,218 | $ | 16,230 | $ | 55,256 | $ | 7,873 | $ | 303,577 | |||||||||||
|
2007
|
$ | 155,028 | $ | 10,000 | $ | 43,043 | $ | 6,070 | $ | 214,141 | ||||||||||||
|
Michael R. Cunningham,
|
2009
|
$ | 172,263 | $ | 15,000 | $ | 184,648 | $ | 9,027 | $ | 380,938 | |||||||||||
|
Chief Financial Officer
|
2008
|
$ | 166,468 | $ | 3,000 | $ | 147,412 | $ | 13,438 | $ | 330,318 | |||||||||||
|
2007
|
$ | 157,819 | $ | 0 | $ | 121,763 | $ | 16,798 | $ | 296,380 | ||||||||||||
|
Tyler E. Andrews,
|
2009
|
$ | 136,821 | $ | 5,000 | $ | 11,525 | $ | 2,855 | $ | 156,201 | |||||||||||
|
Vice President,
|
2008
|
$ | 103,276 | $ | 2,000 | N/A | $ | 1,295 | $ | 106,571 | ||||||||||||
|
Human Resources
|
2007
|
$ | 0 | $ | 0 | N/A | $ | 0 | $ | 0 | ||||||||||||
|
Edward M. Jenkin,
|
2009
|
$ | 160,570 | $ | 5,000 | $ | 152,802 | $ | 18,641 | $ | 337,013 | |||||||||||
|
Vice President,
|
2008
|
$ | 153,249 | $ | 0 | $ | 64,145 | $ | 721 | $ | 218,115 | |||||||||||
|
Power Delivery
|
2007
|
$ | 129,358 | $ | 0 | $ | 44,781 | $ | 587 | $ | 174,726 | |||||||||||
|
Paul R. Risse,
|
2009
|
$ | 163,660 | $ | 10,000 | $ | 84,645 | $ | 7,083 | $ | 265,388 | |||||||||||
|
Sr. Vice President,
|
2008
|
$ | 155,791 | $ | 3,000 | $ | 54,445 | $ | 2,554 | $ | 215,790 | |||||||||||
|
Power Supply
|
2007
|
$ | 121,279 | $ | 2,000 | $ | 41,415 | $ | 838 | $ | 165,532 | |||||||||||
|
David R. Smith,
|
2009
|
$ | 160,949 | $ | 10,000 | $ | 38,558 | $ | 17,154 | $ | 226,661 | |||||||||||
|
Sr. Vice President,
|
2008
|
$ | 152,717 | $ | 2,000 | $ | 82,657 | $ | 4,129 | $ | 241,503 | |||||||||||
|
Administration
|
2007
|
$ | 134,589 | $ | 0 | $ | 71,941 | $ | 8,458 | $ | 214,988 | |||||||||||
|
Lee D. Thibert,
|
2009
|
$ | 185,786 | $ | 15,000 | $ | 127,212 | $ | 7,288 | $ | 335,286 | |||||||||||
|
Sr. Vice President, Strategic
|
2008
|
$ | 119,951 | $ | 0 | $ | 99,323 | $ | 3,830 | $ | 223,104 | |||||||||||
|
Planning & Corporate Affairs
|
2007
|
$ | 174,235 | $ | 0 | $ | 75,324 | $ | 9,610 | $ | 259,169 | |||||||||||
|
1Includes costs for life insurance premiums, tax withholdings on bonuses and payment for unused vacation days.
|
On December 5, 2007, the Board of Directors voted to terminate the contract of Chugach’s former Chief Executive Officer, Mr. William Stewart. On August 27, 2008, the Board of Directors ratified a Settlement Agreement with Mr. Stewart relating to the amount owed him. Mr. Stewart received the amount of $263,725 paid in twelve equal monthly installments. Chugach also reimbursed Mr. Stewart for withholding taxes that were repaid by him to Chugach in the amount of $173,855.35. Chugach also released to Mr. Stewart Pension Restoration Plan funds in the amount of $317,106.34 that had been paid to Chugach for the benefit of him. Chugach and Mr. Stewart executed mutual releases of all claims each of them may have against the other.
Pension Benefits
We have elected to participate in the NRECA Retirement Security Plan (the “Plan”), a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. Under ASC 960, the plan is a multi employer plan, in which the accumulated benefits and plan assets are not determined or allocated separately to individual employers. The Plan is intended to be a qualified pension plan under Section 401(a) of the Code. All our employees not covered by a union agreement become participants in the Plan on the first day of the month following completion of one year of eligibility service. An employee is credited with one year of eligibility service if he or she completes 1,000 hours of service either in his or her first twelve consecutive months of employment or in any calendar year for us or certain other employers in rural electrification (related employers). Pension benefits vest at the rate of 10 percent 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 percent 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 percent. In 1998, NRECA notified us that there were employees whose pension benefits from NRECA's Retirement & Security Program would be reduced because of limitations on retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA made available a Pension Restoration Severance Pay Plan and a Pension Restoration Deferred Compensation Plan for cooperatives to adopt in order to make employees whole for their lost benefits. In May 1998, we adopted both of these plans to protect the benefits of current and future employees whose pension benefits would be reduced because of these limitations.
On October 16, 2002, the Board authorized an amendment to the Plan with an effective date of November 1, 2002. Under the amended Plan, the retirement benefit payable to any Participant whose retirement is postponed beyond his or her Normal Retirement Date shall be computed as of the Participant’s actual retirement date. The retirement benefit payable to any Participant under the 30-Year Plan shall be computed as of the first day of the month in which the Participant’s actual retirement date occurs.
Benefit service as of December 31, 2009 that is taken into account under the Plan for the executive officers is shown below with the assumptions for calculation of the present value of accumulated benefits.
Pension Benefits Table
|
Name
|
Plan
|
Credited Years
of Service
|
Present Value of Accumulated Benefit
|
Payments
During Last Fiscal Year
|
||||||||||||
|
Bradley W. Evans,
Chief Executive Officer
|
Retirement
Security
|
8.83 | $ | 336,296 | $ | 0 | ||||||||||
|
Pension
Restoration
|
8.83 | $ | 1,986 | |||||||||||||
|
Michael R. Cunningham,
Chief Financial Officer
|
Retirement
Security
|
26.08 | $ | 1,135,929 | $ | 0 | ||||||||||
|
Lee D. Thibert,
Sr. Vice President, Strategic Planning &
Corporate Affairs
|
Retirement
Security
|
21.33 | $ | 764,857 | $ | 0 | ||||||||||
|
Paul R. Risse,
Sr. Vice President, Power Supply
|
Retirement
Security
|
13.92 | $ | 384,530 | $ | 0 | ||||||||||
|
David R. Smith,1
Sr. Vice President, Administration
|
Retirement
Security
|
1.5 | $ | 57,891 | $ | 0 | ||||||||||
|
Edward M. Jenkin,
Vice President, Power Delivery
|
Retirement
Security
|
19.08 | $ | 475,540 | $ | 0 | ||||||||||
|
Tyler E. Andrews,
Vice President, Human Resources
|
Retirement
Security
|
0.8 | $ | 11,525 | $ | 0 | ||||||||||
|
1 Mr. Smith was paid the value of all of his pension benefits attributable to service prior to July 1, 2008.
|
It is assumed that participants retire at the earlier of age 62 or 30 years of benefit service and elect a lump sum benefit.
Lump sum amounts are calculated using the 30-year Treasury rate (4.00 percent for 2009 and 4.52 percent for 2008) and the Pension Protection Act (PPA) three-segment yield rates (5.24 percent, 5.69 percent, and 5.37 percent for 2009 and 4.60 percent, 4.82 percent, and 4.91 percent for 2008) and the required IRS mortality table for lump sum payments (1994 Guaranteed Annuity Rate (GAR), projected to 2002, blended 50 percent/50 percent for unisex mortality in combination with the 30-year Treasury rates and Retirement Plan (RP) 2000 PPA at 2009 and 2008, respectively, combined unisex 50 percent/50 percent mortality in combination with the PPA rates). The lump sum is then discounted at 5.50 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2009, and 5.54 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2008, to determine the present value for the appropriate year.
Deferred Compensation
Chugach adopted NRECA’s unfunded Deferred Compensation Program (the Program) to allow highly compensated employees who elect to participate in the Program to defer a portion of their current compensation and avoid paying tax on the deferrals until received. As a non-qualified plan under Internal Revenue Code 457(b), NRECA’s Deferred Compensation Plan is not subject to non-discrimination testing. The Program is designed to help decrease current taxable income, take advantage of tax deferred compounding and set aside additional money for retirement. The money is accessible only upon separation of service, disability or death (in which case it is paid to the designated beneficiary). The distribution is taxable as income in the year received.
Deferred compensation accounts are established for the individual employees, however, they are considered to be owned by Chugach until a distribution is made. Deferred compensation plan assets would be subject to creditors’ demands in the case of bankruptcy. Deferred compensation assets are invested with Homestead Funds, a family of no-load mutual funds. Homestead Funds’ investment managers, RE Advisers, is a wholly-owned subsidiary of NRECA. Each participant in the Program determines the investment fund or funds into which their accounts are invested. The amounts credited to the deferred compensation account, including gains and losses, are retained by Chugach until the entire amount credited to the account has been distributed to the Participant or to the Participant’s beneficiary.
Deferred Compensation Table
|
Name
|
Executive Contributions in last FY
|
Registrant Contributions in last FY
|
Aggregate Earnings
in last FY
|
Aggregate Withdrawals/
Distributions
|
Aggregate balance at
FYE
|
|||||||||||||||
|
Bradley W. Evans,
Chief Executive Officer
|
$ | 16,500 | $ | 0 | $ | 61 | $ | 0 | $ | 32,093 | ||||||||||
|
Michael R. Cunningham,
Chief Financial Officer
|
$ | 16,500 | $ | 0 | $ | 18,017 | $ | 0 | $ | 107,686 | ||||||||||
Potential Termination Payments
Pursuant to a Chugach Operating Policy, non-represented employees, including the executive officers except the Chief Executive Officer, who are terminated by Chugach for reasons unrelated to employee performance are entitled to severance pay for each year or partial year of service as follows: two weeks for each year of service to a maximum of twenty-six (26) weeks for thirteen (13) years or more of service.
The following is a list of the estimated severance payments, including the payment of accrued vacation that would be made to each of the executive officers in the case of termination not related to employee performance:
Potential Termination Payments Table
|
Name
|
Estimated
Severance Payment
|
|||
|
Bradley W. Evans,
Chief Executive Officer
|
$ | 303,922 | ||
|
Michael R. Cunningham,
Chief Financial Officer
|
$ | 126,219 | ||
|
Tyler E. Andrews,
Vice President, Human Resources
|
$ | 23,943 | ||
|
Edward M. Jenkin,
Vice President, Power Delivery
|
$ | 101,866 | ||
|
Paul R. Risse,
Sr. Vice President, Power Supply
|
$ | 162,519 | ||
|
David R. Smith,
Sr. Vice President, Administration
|
$ | 100,967 | ||
|
Lee D. Thibert,
Sr. Vice President, Strategic Planning & Corporate Affairs
|
$ | 116,090 | ||
On December 5, 2007, the Board of Directors voted to terminate the contract of Chugach’s former Chief Executive Officer, Mr. William Stewart. On August 27, 2008, the Board of Directors ratified a Settlement Agreement with Mr. Stewart relating to the amount owed him. Mr. Stewart received the amount of $263,725 paid in twelve equal monthly installments. Chugach also reimbursed Mr. Stewart for withholding taxes that were repaid by him to Chugach in the amount of $173,855.35. Chugach also released to Mr. Stewart Pension Restoration Plan funds in the amount of $317,106.34 that had been paid to Chugach for the benefit of him. Chugach and Mr. Stewart executed mutual releases of all claims each of them may have against the other.
Director Compensation
Directors are compensated for their services at the rate of $200 per Board meeting or other meeting at which they are representing the Association in an official capacity within the State of Alaska, and $250 per day when attending meetings or training outside of the State, including each day of travel, plus reimbursement of reasonable out of pocket expenses, up to a maximum of 70 meetings per year for a director and 85 meetings per year for the Chairman.
The following table sets forth the dollar amounts of all fees paid in cash by us for the fiscal year ending December 31, 2009 to each of our current and former Board members:
Director Compensation Table
|
Name
|
Fees Paid
In Cash
|
|||
|
Rebecca Logan, Chairman and Director
|
$ | 15,900 | ||
|
James Nordlund, Vice-Chairman and Director
|
$ | 11,600 | ||
|
P. J. Hill, Treasurer and Director
|
$ | 13,750 | ||
|
Alex Gimarc, Secretary and Director
|
$ | 10,300 | ||
|
Elizabeth “Pat” Kennedy, Director
|
$ | 8,850 | ||
|
Janet Reiser, Director
|
$ | 13,650 | ||
|
Elizabeth Vazquez, Director
|
$ | 13,950 | ||
|
Jeff Lipscomb, Former Director
|
$ | 5,100 | ||
One new board member was elected, while one current board member was re-elected at Chugach’s annual membership meeting held on April 30, 2009. Elizabeth “Pat” Kennedy was elected to a three-year term, replacing Jeff Lipscomb, and James Nordlund was re-elected to a three-year term.
Item 12 - Security Ownership of Certain Beneficial Owners and Management
and Related Stockholder Matters
Not Applicable
Item 13 - Certain Relationships and Related Transactions, and Director Independence
Not Applicable
Item 14 – Principal Accounting Fees and Services
The Audit Committee of the Board retained KPMG LLP as the independent registered public accounting firm for Chugach during the fiscal year ended December 31, 2009.
Fees and Services
KPMG LLP has provided certain audit, audit-related, tax and non-audit services, the fees for which are as follows:
|
2009
|
2008
|
|||||||
|
Audit and audit-related services:
|
||||||||
|
Audit and quarterly reviews
|
$ | 211,165 | $ | 160,180 | ||||
|
Audit-related services (Single audit and employee benefit plans)
|
30,465 | 70,465 | ||||||
|
Non-audit services:
|
||||||||
|
Tax consulting and return preparation
|
20,305 | 17,250 | ||||||
|
Other services1
|
3,431 | 83,056 | ||||||
|
Total
|
$ | 265,366 | $ | 330,951 | ||||
1Other services in 2009 and 2008 included Sarbanes-Oxley procedure reviews
The Audit Committee of the Board has a policy to pre-approve all services to be provided by Chugach’s independent public accountants. All services from Chugach’s independent registered public accounting firm for fiscal years ended December 31, 2009 and 2008 were approved by the Audit Committee.
PART IV
Item 15 – Exhibits and Financial Statement Schedules
|
Page
|
|
|
|
|
|
Financial Statements
|
|
|
|
|
|
Included in Part II of this Report:
|
|
|
Report of Independent Registered Public Accounting Firm
|
52
|
|
Balance Sheets, December 31, 2009 and 2008
|
53-54
|
|
Statements of Operations, Years ended December 31, 2009, 2008 and 2007
|
55
|
|
Statements of Changes in Equities and Margins, Years ended December 31, 2009, 2008 and 2007
|
56
|
|
Statements of Cash Flows, Years ended December 31, 2009, 2008 and 2007
|
57
|
|
Notes to Financial Statements
|
58-87
|
|
|
|
|
Financial Statement Schedules
|
|
|
|
|
|
Included in Part IV of this Report:
|
|
|
Report of Independent Registered Public Accounting Firm
|
101
|
|
Schedule II - Valuation and Qualifying Accounts,
|
|
|
Years ended December 31, 2009, 2008 and 2007
|
102
|
Other schedules are omitted as they are not required or are not applicable, or the required information is shown in the applicable financial statements or notes thereto.
Report of Independent Registered Public Accounting Firm
The Board of Directors
Chugach Electric Association, Inc.
Under date of March 4, 2010, we reported on the balance sheets of Chugach Electric Association, Inc. as of December 31, 2009 and 2008, and the related statements of operations, changes in equities and margins and cash flows for each of the years in the three-year period ended December 31, 2009, which are included in the 2009 Annual Report on Form 10-K. In connection with our audits of the aforementioned financial statements, we also audited the related financial statement schedule in the 2009 Annual Report on Form 10-K. This financial statement schedule is the responsibility of the Company’s management. Our responsibility is to express an opinion on this financial statement schedule based on our audit.
In our opinion, the financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ KPMG, LLP
Anchorage, Alaska
March 4, 2010
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, 2009
|
(408,632 | ) | (245,157 | ) | 255,974 | (397,815 | ) | |||||||||
|
December 31, 2008
|
(541,368 | ) | (295,313 | ) | 428,049 | (408,632 | ) | |||||||||
|
December 31, 2007
|
(586,221 | ) | (21,817 | ) | 66,670 | (541,368 | ) | |||||||||
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. (37)
|
|
|
4.11
|
Tenth Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. (11)
|
|
|
4.12
|
Eleventh Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association. (14)
|
|
|
4.13
|
Amended and Restated Indenture between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. (11)
|
|
|
4.14
|
Form of 2001 Series A Bond due 2011. (11)
|
|
|
4.15
|
Form of 2002 Series A Bond due 2012. (14)
|
|
|
4.16
|
Form of 2002 Series B Bond due 2012. (14)
|
|
|
10.1
|
Wholesale Power Agreement between the Registrant and the City of Seward. (1)
|
|
|
10.2
|
Joint Use Agreement between the Registrant and the City of Seward dated effective as of September 11, 1998. (1)
|
|
|
10.3
|
Net Billing Agreement among the Registrant and the City of Seward dated effective as of September 11, 1998. (1)
|
|
|
10.4
|
Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective as of September 11, 1998. (8)
|
|
|
10.4.1
|
Amendment No. 1 to Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective as of July 9, 2001. (13)
|
|
|
10.4.2
|
2006 Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective as of June 1, 2006. (32)
|
|
|
10.5
|
Agreement for Sale of Electric Power and Energy by and among the Registrant, Homer Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated September 27, 1985. (1)
|
|
|
10.5.1
|
Assignment of Agreement for Sale of Electric Power and Energy by and among the Registrant, Homer Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19)
|
|
10.6
|
Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of January 30, 1989. (1)
|
|
|
10.6.1
|
First Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of February 10, 1995. (1)
|
|
|
10.6.2
|
Net Billing Agreement by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 16, 1987. (1)
|
|
|
10.7
|
Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc. dated May 18, 1988. (1)
|
|
|
10.7.1
|
Amendatory Agreement No. 1 to Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc., dated December 14, 1989. (11)
|
|
|
10.7.2
|
Letter Agreement dated January 18, 1996 between the Registrant and Golden Valley Electric Association, Inc., amending the Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc. (11)
|
|
|
10.7.3
|
Amendatory Agreement No. 2 to Nonfirm Energy Agreement between the Registrant and Golden Valley Electric Association, Inc., dated February 8, 1999. (11)
|
|
|
10.7.4
|
Settlement Agreement by and among the Registrant, Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Anchorage Municipal Light and Power dated May 6, 1999. (11)
|
|
|
10.8
|
Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. dated April 21, 1989. (1)
|
|
|
10.8.1
|
Amendment No. 1 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc., dated August 1, 1990. (1)
|
|
|
10.8.2
|
Letter Agreement dated April 23, 1999, regarding the Registrant’s consent to the assignment to ARCO Beluga, Inc. of the Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. (11)
|
|
|
10.8.3
|
Amendment No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Beluga, Inc., dated May 6, 1999. (8)
|
|
|
10.9
|
Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and ARCO Alaska, Inc. dated October 3, 1991. (1)
|
|
|
10.10
|
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company dated September 26, 1988. (1)
|
|
|
10.10.1
|
Letter Agreement dated September 26, 1988 between the Registrant and Marathon Oil Company, amending the Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company. (1)
|
|
10.10.2
|
Amendatory Agreement No. 1 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated effective as of February 21, 1990. (1)
|
|
|
10.10.3
|
Amendatory Agreement No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated effective as of February 21, 1990. (1)
|
|
|
10.10.4
|
Amendatory Agreement No. 3 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated January 28, 1991. (1)
|
|
|
10.10.5
|
Amendatory Agreement No. 4 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated October 6, 1993. (11)
|
|
|
10.10.6
|
Letter Agreement dated January 18, 1996 between the Registrant and Marathon Oil Company, amending the Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company. (11)
|
|
|
10.10.7
|
Amendatory Agreement No. 5 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company, dated May 24, 1999. (8)
|
|
|
10.11
|
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Shell Western E&P Inc. dated April 25, 1989. (1)
|
|
|
10.11.1
|
Amendatory Agreement No. 1 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc., dated October 1, 1989. (1)
|
|
|
10.11.2
|
Amendment No. 2 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc., dated June 20, 1990. (1)
|
|
|
10.11.3
|
Amendatory Agreement No. 3 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc. dated October 14, 1996. (1)
|
|
|
10.12
|
Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Shell Western E&P Inc. dated November 2, 1990. (1)
|
|
|
10.13
|
Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron USA Inc. dated April 27, 1989 (including Attachment No. 1 thereto dated December 20, 1989). (1)
|
|
|
10.13.2
|
Amendment No. 2 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron USA Inc., dated June 7, 1990. (1)
|
|
10.13.3
|
Amendment No. 3 to Agreement for the Sale and Purchase of Natural Gas between the Registrant and Chevron U.S.A. Inc., dated May 26, 1999. (8)
|
|
|
10.14
|
Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Chevron USA, Inc. dated September 25, 1990. (1)
|
|
|
10.15
|
Alaska Intertie Agreement between Alaska Power Authority, Municipality of Anchorage, the Registrant, City of Fairbanks, Alaska Municipal Utilities System, Golden Valley Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 23, 1985. (1)
|
|
|
10.16
|
Addendum No. 1 to the Alaska Intertie Agreement-Reserve Capacity and Operating Reserve Responsibility dated December 23, 1985. (1)
|
|
|
10.17
|
Memorandum of Understanding Regarding Intertie Upgrades among Alaska Energy Authority, the Registrant, Golden Valley Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power, and the City of Seward d/b/a Seward Electric System dated March 21, 1990. (1)
|
|
|
10.18
|
Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. (11)
|
|
|
10.19
|
Intertie Grant Agreement between the Registrant, Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Matanuska Electric Association, Inc. and Homer Electric Association, Inc.), City of Seward, the State of Alaska, Department of Administration and Alaska Industrial Development and Export Authority dated August 17, 1993. (1)
|
|
|
10.20
|
Grant Transfer and Delegation Agreement between the Registrant and Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc., Matanuska Electric Association, Inc., Homer Electric Association, Inc., Seward, the State of Alaska, Department of Administration, and AMEA dated November 5, 1993. (1)
|
|
|
10.21
|
1993 Alaska Intertie Project Participants Agreement by and among Alaska Power Authority, Municipality of Anchorage, the Registrant, City of Fairbanks, Alaska Municipal Utilities System, Golden Valley Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., City of Seward d/b/a Seward Electric System, Homer Electric Association, Inc. and Matanuska Electric Association, Inc. dated January 24, 1994. (11)
|
|
|
10.22
|
Amendment No. 1 to the 1993 Alaska Intertie Project Participants Agreement dated December 10, 1999. (11)
|
|
10.23
|
Grant Administration Agreement by and among the Registrant, Alaska Industrial Development and Export Authority, Golden Valley Electric Association, Inc., Fairbanks Municipal Utilities System, Anchorage Municipal Light & Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Homer Electric Association, Inc. and Matanuska Electric Association, Inc.) and City of Seward dated August 30, 1994. (11)
|
|
|
10.24
|
Bradley Lake Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated December 8, 1987. (1)
|
|
|
10.24.1
|
Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated June 30, 2003. (19)
|
|
|
10.25
|
Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 8, 1987. (1)
|
|
|
10.25.1
|
Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19)
|
|
|
10.26
|
Transmission Sharing Agreement by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power. (1)
|
|
|
10.27
|
Amendment to Agreement for Sale of Transmission Capability by and among the Registrant, Homer Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power dated March 7, 1989. (1)
|
|
|
10.28
|
Bradley Lake Hydroelectric Agreement for the Dispatch of Electric Power and for Related Services between the Registrant and the Alaska Energy Authority dated February 19, 1992. (1)
|
|
10.29
|
Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated September 29, 1992. (1)
|
|
|
10.29.1
|
Assignment of Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19)
|
|
|
10.30
|
Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated December 2, 1983. (1)
|
|
|
10.30.1
|
Addendum No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated August 8, 1984. (1)
|
|
|
10.30.2
|
Amendment No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated November 28, 1984. (1)
|
|
|
10.31
|
Gas Transportation Agreement by and among the Registrant, Alaska Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992. (1)
|
|
|
10.32
|
Eklutna Purchase Agreement by and among the Registrant, Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power and Alaska Power Administration. (1)
|
|
|
10.33
|
Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. (3)
|
|
|
10.34
|
Settlement Agreement by and among the Registrant, Homer Electric Association, Inc., Matanuska Electric Association, Inc., the City of Seward and Alaska Electric Generation and Transmission Cooperative, Inc., resolving G&T TIER Level, Equity Level, Capital Credits, Equity Management Plan and Loan Covenant Disputes, dated effective as of February 3, 1993. (1)
|
|
|
10.35
|
First Amendment to “Settlement Agreement Resolving G&T TIER Level, Equity Level, Capital Credits, Equity Management Plan and Loan Covenant Disputes” in APUC Docket U-92-10 between the Registrant, Matanuska Electric Association, Inc., Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated March 1993. (1)
|
|
|
10.36
|
Agreement by and among the Registrant, Municipality of Anchorage d/b/a Anchorage Municipal Light and Power, Matanuska Electric Association, Inc., U.S. Fish and Wildlife Service, National Marine Fisheries Service, Alaska Energy Authority and the State of Alaska re: the Eklutna and Snettisham Hydroelectric Projects. (1)
|
|
|
10.37
|
Daves Creek Substation Agreement between the Registrant and the Alaska Energy Authority dated March 13, 1992. (1)
|
|
|
10.38
|
Settlement Agreement between the Registrant and Intervenor Wholesale Customers in APUC Docket U-93-15 dated September 1993 regarding depreciation of submarine cables. (1)
|
|
|
10.39
|
Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated February 12, 1999. (8)
|
|
10.39.1
|
Second Amendment to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 1, 2001. (13)
|
|
|
10.39.2
|
Assignment of Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. (19)
|
|
|
10.39.3
|
Settlement of Dispute Over Nikiski Cogeneration Plant System Use and Dispatch Agreement and Premium Demand Charges Under HEA PSA between the Registrant and Alaska Electric and Energy Cooperative, Inc. and Homer Electric Association, Inc. dated January 15, 2008. (32)
|
|
|
10.39.4
|
Third Amendment to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Homer Electric Association, Inc. dated effective November 6, 2009. (39)
|
|
|
10.40
|
Lease Amendment between the Registrant and Standard Oil Company of California dated June 1, 1975. (1)
|
|
|
10.41
|
Lease Amendment between the Registrant and Chevron USA, Inc. dated September 1, 1985. (1)
|
|
|
10.42
|
First Amended and Restated Joint Action Agency Agreement Relating To The Alaska Railbelt Energy Authority among the Registrant, Anchorage Municipal Light & Power (AML&P) and Golden Valley Electric Association, Inc. (GVEA) dated August 1, 2005. (22)
|
|
|
10.44
|
Line of Credit Agreement and Promissory Note between the Registrant and the National Bank for Cooperatives dated May 5, 1993. (1)
|
|
|
10.44.1
|
Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated March 11, 1994. (1)
|
|
|
10.44.2
|
Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives and amended and restated Promissory Note dated April 18, 1994. (1)
|
|
|
10.44.3
|
Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated May 1, 1995. (1)
|
|
|
10.44.4
|
Amendment to Line of Credit Agreement between the Registrant and the National Bank for Cooperatives dated May 15, 1995. (1)
|
|
|
10.44.5
|
Amendment to Line of Credit Agreement between the Registrant and CoBank, ACB dated September 30, 2000. (10)
|
|
|
10.44.6
|
Amendment to Line of Credit Agreement between the Registrant and CoBank, ACB dated December 27, 2002. (18)
|
|
10.44.7
|
Promissory Note and Consolidating Committed Resolving Credit Supplement between the Registrant and CoBank, ACB dated May 3, 2005. (22)
|
|
|
10.45.1
|
Master Loan Agreement between the Registrant and CoBank, ACB dated December 27, 2002. (17)
|
|
|
10.45.2
|
Promissory Note and Consolidating Term Loan Supplement between the Registrant and CoBank, ACB dated December 27, 2002. (17)
|
|
|
10.45.3
|
Master Loan Agreement between the Registrant and CoBank, ACB dated May 3, 2005 (22)
|
|
|
10.45.4
|
Promissory Note and Supplement between the Registrant and CoBank, ACB dated August 24, 2005. (23)
|
|
|
10.45.5
|
Amended and Restated Promissory Note and Committed Revolving Credit Supplement between the Registrant and CoBank, ACB dated September 12, 2006. (26)
|
|
|
10.45.6
|
Amended and Restated Promissory Note and Multiple Advance Term Loan Supplement between the Registrant and CoBank, ACB dated June 5, 2007. (30)
|
|
|
10.45.7
|
Amended and Restated Promissory Note and Committed Revolving Credit Supplement between the Registrant and CoBank, ACB dated October 10, 2007. (30)
|
|
|
10.47
|
Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 15, 2002. (17)
|
|
|
10.47.1
|
Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 14, 2007. (30)
|
|
|
10.47.2
|
Amendment to Revolving Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated effective December 22, 2008. (36)
|
|
|
10.48
|
Credit Agreement between the Registrant and National Rural Utilities Cooperative Finance Corporation dated October 10, 2008. (35)
|
|
|
10.52
|
Employment Agreement between the Registrant and Evan J. Griffith dated effective April 21, 2004. (20)
|
|
|
10.53
|
First Amended Memorandum of Agreement between the Registrant and William R. Stewart dated effective March 17, 2006. (24)
|
|
|
10.54
|
Employment Agreement between the Registrant and William R. Stewart dated effective July 1, 2006. (25)
|
|
|
10.55
|
Order accepting settlement agreements, amending procedural schedule, and permitting supplemental testimony and statement of commissioner Dave Harbour dissenting in part and concurring in part. (29)
|
|
10.56
|
Order On Offer Of Settlement And Issuing New License between the Registrant and the Federal Energy Regulatory Commission dated effective August 24, 2007. (32)
|
|
|
10.57
|
Memorandum of Agreement between the Registrant and Bradley Evans dated effective December 6, 2007. (32)
|
|
|
10.58
|
Agreement Covering Terms and Conditions of Employment for Beluga Power Plant Culinary Employees between the Registrant and the Hotel Employees & Restaurant Employees Union Local 878 dated effective December 13, 2007. (32)
|
|
|
10.59
|
Agreement Covering Terms and Conditions of Employment for Office and Engineering Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective September 13, 2007. (32)
|
|
|
Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Office and Engineering Personnel dated effective July 1, 2010.
|
||
|
10.60
|
Agreement Covering Terms and Conditions of Employment for Generation Plant Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective November 9, 2007. (32)
|
|
|
Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Generation Plant Personnel dated effective July 1, 2010.
|
||
|
10.61
|
Agreement Covering Terms and Conditions of Employment for Outside Plant Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective December 12, 2007. (32)
|
|
|
Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Outside Plant Personnel dated effective July 1, 2010.
|
||
|
10.62
|
Memorandum of Understanding Regarding Joint Development of South Anchorage Power Project between the Registrant and Anchorage Municipal Light and Power dated effective February 28, 2008. (32)
|
|
|
10.63
|
Memorandum of Understanding Regarding Organization of a Unified Power Provider between the Registrant and Homer Electric Association, Inc., Golden Valley Electric Association and City of Seward Light & Power Division dated effective April 14, 2008. (33)
|
|
|
10.64
|
Employment Agreement between the Registrant and Bradley W. Evans dated effective July 1, 2008. (34)
|
|
|
10.65
|
Agreement for the Sale and Purchase of Natural Gas between the Registrant and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively, ConocoPhillips) effective August 21, 2009. (38)
|
|
14
|
Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. (21)
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Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
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Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
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99
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Press release announcing plans to explore a possible merger or joint operations between the Registrant and Municipal Light & Power dated effective June 15, 2007. (28)
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99.1
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Press release announcing a panel recommendation that the Municipality of Anchorage and the registrant explore joint generation and operations dated effective February 8, 2008. (31)
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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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(24) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2005.
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(25) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2006.
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(26) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2006.
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(27) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2007.
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(28) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated June 21, 2007
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(29) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2007.
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(30) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2007.
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(31) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated February 8, 2008.
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(32) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007.
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(33) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2008.
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(34) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated August 27, 2008.
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(35) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2008.
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(36) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2008.
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||
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(37) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated April 30, 2009.
|
||
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(38) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated August 21, 2009.
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(39) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2009.
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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 on March 3, 2010.
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CHUGACH ELECTRIC ASSOCIATION, INC.
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||
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By:
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/s/ Bradley W. Evans
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Bradley W. Evans, Chief Executive Officer
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||
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Date:
|
March 3, 2010
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 3, 2010, by the following persons on behalf of the registrant in the capacities indicated:
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/s/ Bradley W. Evans
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Bradley W. Evans
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Chief Executive Officer
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(Principal Executive Officer)
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/s/ Michael R. Cunningham
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Michael R. Cunningham
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Chief Financial Officer
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(Principal Financial Officer)
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(Principal Accounting Officer)
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/s/ Paul R. Risse
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Paul R. Risse
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Sr. Vice President, Power Supply
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/s/ Lee D. Thibert
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Lee D. Thibert
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Sr. Vice President, Strategic Planning &
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Corporate Affairs
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/s/ David R. Smith
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David R. Smith
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Sr. Vice President, Administration
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/s/ Edward M. Jenkin
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Edward M. Jenkin
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Vice President, Power Delivery
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/s/ Tyler E. Andrews
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Tyler E. Andrews
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Vice President, Human Resources
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/s/ Rebecca Logan
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Rebecca Logan
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Director & Chairman of the Board
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/s/ James Nordland
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James Nordland
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Director & Vice-Chairman of the Board
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/s/ P. J. Hill
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P. J. Hill
|
Director & Treasurer of the Board
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/s/ Alex Gimarc
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Alex Gimarc
|
Director & Secretary of the Board
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/s/ Elizabeth Kennedy
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Elizabeth “Pat” Kennedy
|
Director
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/s/ Janet Reiser
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Janet Reiser
|
Director
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|
|
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/s/ Elizabeth Vazquez
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|
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Elizabeth Vazquez
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Director
|
Supplemental information to be furnished with reports filed pursuant to Section 15(d) of the Act by registrants, which have not registered securities pursuant to Section 12, of the Act.
Chugach has not made an Annual Report to securities holders for 2009 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.
117