Chugach Electric Association 10K 2008 Annual report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10K


x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2008

or

o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _________________________ to _________________________

Commission file number 33-42125

Chugach Electric Association, Inc.

(Exact name of registrant as specified in its charter)


	Alaska		92-0014224

	(State or other jurisdiction of		(I.R.S. Employer
	incorporation or organization)		Identification No.)

	5601 Electron Dr., Anchorage, Alaska		99518

	(Address of principal executive offices)		(Zip Code)

	Registrant’s telephone number, including area code		(907) 563-7494

Securities registered pursuant to Section 12(b) of the Act:

	Title of each class	Name of each exchange on which registered





Securities registered pursuant to Section 12(g) of the Act:


(Title of class)


(Title of class)

Indicate by check mark 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 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 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.

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.


	Large accelerated filer o	Accelerated filer o
	Non-accelerated filer x	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

o Yes x No

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

CHUGACH ELECTRIC ASSOCIATION, INC.

2008 Form 10-K Annual Report

Table of Contents


		Page


PART I
Item 1 – Business		3

Item 1A – Risk Factors		11

Item 1B – Unresolved Staff Comments		14

Item 2 – Properties		14

Item 3 – Legal Proceedings		21

Item 4 – Submission of Matters to a Vote of Security Holders		21

PART II
Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		22

Item 6 – Selected Financial Data		22

Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation		23

Item 7A – Quantitative and Qualitative Disclosures About Market Risk		42

Item 8 – Financial Statements and Supplementary Data		44

Item 9 – Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		78

Item 9A – Controls and Procedures		78

Item 9B – Other Information		79

PART III
Item 10 – Directors, Executive Officers and Corporate Governance		79

Item 11 – Executive Compensation		82

Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		90

Item 13 – Certain Relationships and Related Transactions, and Director Independence		91

Item 14 – Principal Accounting Fees and Services		91

PART IV
Item 15 – Exhibits and Financial Statement Schedules		92

SIGNATURES		108

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 80,682 service locations in the Anchorage and upper Kenai Peninsula areas. Through an interconnected regional electrical system, our energy is distributed throughout Alaska’s Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska’s largest cities, Anchorage and Fairbanks. Neither Chugach nor any other electric utility in Alaska has any connection to the electric grid of the continental United States or Canada.

Chugach is a rural electric cooperative that is exempt from federal income taxation as an organization described in Section 501(c)(12) of the Internal Revenue Code (Code). Alaska electric cooperatives must pay to the State of Alaska, a gross receipts tax in lieu of state and local ad valorem, income and excise taxes, a tax at the rate of $0.0005 per 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 $0.000362 per kWh of retail electricity sold. This charge is assessed to fund the operations of the Regulatory Commission of Alaska (RCA). This tax is collected monthly and remitted to the State of Alaska quarterly. We

also collect sales tax on retail electricity sold to Kenai and Whittier consumers. This tax is also collected monthly and remitted to the Kenai Peninsula Borough quarterly. These taxes are a direct pass-through to consumer bills and therefore do not impact our margins.

Our workforce consists of approximately 326 full-time employees. Approximately 70% of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW, which expire on June 30, 2010. We also have an agreement with the Hotel Employees & Restaurant Employees (HERE) which also expires on June 30, 2010. We believe our relationship with our employees is good.

Through direct service to retail customers and indirectly through wholesale and economy energy sales, we provide some or all of the electricity used by approximately two-thirds of Alaska’s electric customers. We supply much of the power requirements of three wholesale customers, Matanuska Electric Association (MEA), Homer Electric Association (HEA) and the City of Seward (Seward). We sell available generation in excess of our own needs to produce electric energy for sale to Golden Valley Electric Association, Inc. (GVEA). In addition, on a periodic basis, we provide electricity to Anchorage Municipal Light & Power (AML&P or ML&P).

Our members are the consumers of the electricity sold by us. As of December 31, 2008, we had three major wholesale customers and 66,116 retail members receiving service at approximately 80,682 service locations. No individual retail customer receives more than 5% of our power.

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.

We have 530.1 megawatts 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% interest. Approximately 85% (by rated capacity) of our generating capacity is fueled by natural gas, which we purchase under long-term gas contracts. The remainder of our generating resources are hydroelectric facilities. In 2008, 91% of our power was generated from gas, which included power generated at Nikiski, and 76% of that gas-fired generation took place at Beluga. The Bradley Lake Hydroelectric Project provides up to 27.4 megawatts for our retail customers and up to 24.1 megawatts for our wholesale customers. For more information concerning Bradley Lake, see “Item 2 – Properties – Other Property – Bradley Lake.” We also purchase approximately 40 megawatts from the Nikiski power plant on the Kenai Peninsula. We operate 1,684 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, 2008, we sold 2.8 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, 2008:


	MWh		2008 Revenues		Percent of Sales Revenue

Direct retail sales:
Residential		560,757	$	80,306,635		28	%
Commercial		645,075		77,242,724		27	%

Total		1,205,832		157,549,359		55	%

Wholesale sales:
MEA		742,666		63,500,034		22	%
HEA		517,368		41,133,287		15	%
Seward		63,734		4,798,286		2	%

Total		1,323,768		109,431,607		39	%

Economy energy/other sales¹		256,105		18,526,481		6	%

Total from sales		2,785,705		285,507,447		100	%

Miscellaneous energy revenue				2,784,665

Total energy revenues			$	288,292,112

¹ Economy 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, 2008, we had 66,116 members receiving power from approximately 80,682 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% of our revenues.

Wholesale Customers

We are the principal supplier of power to MEA, HEA and Seward under separate wholesale power contracts. For 2008, our wholesale power contracts, including the fuel component, produced $109.4 million in revenues, representing 39% of our total revenues and 48% 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. 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 has the right, on advance notice given after RCA approval, to convert to a net-requirements purchaser of power, and as such MEA would be obligated to buy its needed power from us net of its power needs satisfied from any of its own or AEG&T’s resources. The notice period required for such conversion may be up to five years after RCA approval, depending on which non-Chugach resources MEA proposes to use to satisfy its power needs. MEA has not invoked this right at this time.

If MEA converts to a net-requirements purchaser under the contract, MEA cannot reduce its payment for power that it purchases from us below a certain minimum amount. MEA will be required to pay demand charges based upon the highest post-1985 historical coincident peak on the MEA system. Therefore, if MEA converts to net-requirements service, we will continue to recover all or substantially all of the fixed costs now assigned to it. Also, our revenues from energy sales to MEA would partially decline in proportion to the reduction in the energy sold, but this decline would be offset to an extent by savings in the variable costs associated with energy production.

MEA also has the right, on seven years advance notice after RCA approval, to convert to a take-or-pay purchase of a fixed amount of power, also subject to minimum payment requirements associated with prior purchases. The MEA contract is in effect through December 31, 2014. 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.

During the past several years, we have had numerous disputes and engaged in substantial litigation with MEA regarding many aspects of our contractual relationship. For a discussion of material pending litigation between MEA and us, see “Item 3 - Legal Proceedings.”

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 megawatts of capacity, and not less than 350,000 MWh per year. The HEA contract, as interpreted by the Alaska Public Utilities Commission (APUC), the predecessor to the RCA, limits the costs that may be included in our rates charged to HEA. The HEA contract expires on January 1, 2014. HEA’s remaining resource requirements are provided by AEEC’s Nikiski cogeneration facility and AEEC’s contract rights to receive power from the Bradley Lake hydroelectric project for the benefit of HEA. In February 1999, we entered into a dispatch agreement with AEG&T to operate the Nikiski unit as a Chugach system resource. The agreement provides that, in addition to the energy that we already sell to AEEC and HEA, we will sell energy to AEG&T equal to HEA’s residual energy requirements less its allocated share of the Bradley Lake project, up to a maximum of 320,000 MWh per year. A portion of the Nikiski unit output may be dispatched for HEA needs, 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.

Seward

We currently provide nearly all the power needs of the City of Seward. In 2008, sales to Seward represented approximately 2.0% of Chugach’s total sales of energy (including both retail and wholesale). In February 1998, we entered into a power sales agreement (Old Contract) with Seward that allowed us to interrupt service to Seward up to 12 times per year, not to exceed seventy-two cumulative hours annually. 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. The new contract, reflecting different interruptible conditions than the previous agreement, resulted in a 5 percent increase in revenues.

Economy Customers

Since 1989, we have sold economy (non-firm) energy to GVEA under an agreement that expires in 2009. Under the agreement, we use available generation in excess of our own needs to produce electric energy for sale to GVEA, which uses that energy to serve its own loads in place of more expensive energy that it would otherwise generate itself or purchase from other sources. We purchase gas from Marathon Oil Company (Marathon) to produce energy for sale to GVEA, and we charge GVEA a rate sufficient to recover the gas cost, the costs of incremental operations and maintenance expense resulting from increased use of our generators for GVEA, and an agreed-upon margin for each kWh sold.

In 2000, the RCA approved an amendment to our agreement with GVEA and a settlement of an inter-utility dispute. As a result, the market for economy energy sold to GVEA has now been divided into two parts. The larger part continues to be governed by a contractual priority right under our agreement with GVEA. Under this contractual priority right provision, if GVEA requires non-firm energy in sufficient quantities, we have an opportunity to sell and GVEA has a corresponding obligation to purchase two-thirds of the first 450,000 MWh and an additional 80% of the excess over 450,000 MWh of the non-firm energy that GVEA purchases each year if we are capable of producing that energy. Under the above contractual priority right provision, non-

firm sales to GVEA have been 254,372 MWh, 93,753 MWh, and 261,177 MWh for 2008, 2007, and 2006, respectively. For sales not covered by the contractual priority right, no seller enjoys a contractual priority in making such sales and GVEA makes purchases from the seller offering the lowest competitive price.

GVEA has expressed interest in a new firm sales contract with Chugach after the current agreement expires March 31, 2009. Chugach is currently involved in negotiations with GVEA. A new contract is expected to be completed by the second quarter of 2009.

Rate Regulation and Rates

The RCA regulates our rates. We can seek changes in our base rates by filing general rate cases with the RCA. On August 10, 2002, A.S. 42.05.175 imposed timelines for RCA decisions. Among other provisions, it provided that for all dockets commenced on or after July 1, 2002, the RCA shall issue a final order not later than 15 months after a complete tariff filing is made for a tariff filing that changes the utility’s revenue requirement or rate design. It is within the RCA’s authority to authorize, after a notice period, rate changes on an interim, refundable basis. In addition, the RCA has been willing to open limited reviews of matters to resolve specific issues from which expeditious decisions can often be rendered.

The RCA has exclusive regulatory control of our retail and wholesale rates, subject to appeal to the Alaska courts. Under Alaska law, financial covenants of an Alaskan electric cooperative contained in a debt instrument will be valid and enforceable, and rates set by the RCA must be adequate to meet those covenants. Under Alaska law, a cooperative utility that is negotiating to enter into a mortgage or other debt instrument that provides for a Times Interest Earned Ratio (TIER) greater than the ratio the RCA most recently approved for that cooperative must submit the mortgage or debt instrument to the RCA before the instrument takes effect. The rate covenants contained in the instruments that govern our outstanding long-term indebtedness do not impose any greater TIER requirement than those previously approved by the RCA.

We expect to continue to recover changes in our fuel and purchased power expenses through routine fuel surcharge filings with the RCA. See “Item 7 - Management’s Discussion and Analysis - Results of Operations – Overview.”

The Amended and Restated Indenture, which became effective January 22, 2003, governs all of our outstanding bonds and requires us to set rates expected to yield margins for interest equal to at least 1.10 times total interest expense. The CoBank Master Loan Agreement also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. 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, 2008, 2007 and 2006, our Margins for Interest/Interest (MFI/I) was 1.28, 1.12 and 1.41, 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 south central portion of Alaska and is the trade, service and financial center for most of Alaska and serves as a major center for many state governmental functions. Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, air and rail transportation facilities and headquarters support for the petroleum, mining and other basic industries located elsewhere in the state.

The Matanuska-Susitna Borough is immediately north of the Municipality of Anchorage, centered around the communities of Palmer and Wasilla. Although agriculture, tourism, mining and forestry are factors in the economy of the Matanuska-Susitna Borough, the economic well-being of the area is closely tied to that of Anchorage and many Matanuska-Susitna residents commute to jobs in Anchorage.

The Kenai Peninsula is south of Anchorage with an economy substantially independent of the Anchorage area. The most significant basic industry on the Kenai Peninsula is the production and processing of oil and gas from the Cook Inlet region. Consequently, the Kenai Peninsula economy is sensitive to fluctuations in the price and value 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 250 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 oilfield to Valdez. Alyeska Pipeline Company, which operates the Trans-Alaska oil pipeline from Prudhoe Bay to Valdez, has its main operations base in Fairbanks.

Load Forecasts

The following table sets forth our projected load forecasts for the next five years:


Load (MWh)	2009		2010		2011		2012		2013

Retail		1,201,311		1,198,692		1,196,258		1,194,995		1,198,446
Wholesale		1,437,085		1,485,406		1,492,834		1,525,620		1,542,980
Economy		73,000		0		0		0		0
Losses		139,656		147,569		147,578		148,494		149,288

Total		2,851,052		2,831,667		2,836,670		2,869,109		2,890,714

Retail and wholesale energy requirements are expected to increase marginally over the next five years primarily due to two growth opportunities: a new firm wholesale load and the Goose Creek Correctional Center being built in MEA service area. While MEA’s growth has slowed over the last two years, the Matanuska-Susitna (MatSu) Borough economy continues to expand, meeting an increasing suburban population. Our total firm energy requirements are expected to grow at an average annual compounded rate of 1.0% from 2009 to 2013, with retail sales declining at a rate of 0.1% and wholesale sales growing at a rate of 1.8%.

Growth in wholesale energy sales are expected to only be partially offset by expected consumer efficiency/conservancy and declining industrial sales by wholesale customer HEA. Chugach’s economy sales agreement with GVEA expires in 2009. After the economy sales contract terminates, it is intended that Chugach will serve GVEA under a firm wholesale contract. Chugach is currently involved in negotiations with GVEA. A new contract is expected to be completed by the second quarter of 2009. These projections are based on assumptions that management believes to be reasonable as of the date the projections were made. The occurrence of a significant change in any of the assumptions could effect a change in the projected sales forecast.

Item 1A – 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.

Recovery of Fuel and Purchased Power Costs

The fuel and purchased power 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, 2008, Chugach had under-recovered $11.8 million and at December 31, 2007, Chugach had over-recovered $1.6 million. The fuel 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 recovery process does not provide for the timely recovery of fuel costs, Chugach could experience a material negative impact on its cash flows.

Equipment Failures and Other External Factors

The generation and transmission of electricity 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 and purchased power 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 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. This factor, as well as weather, interest rates, economic conditions, fuel supply and prices, are largely beyond our control, but may have a material adverse effect on our consolidated earnings, cash flows and financial position.

Fuel Supply

For 2008, 91% 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, of which we collectively have approximately 83 billion cubic feet (BCF) of gas remaining. Last year, Chugach used approximately 31 BCF of natural gas. We estimate that our contract gas with Marathon will run-out by mid-2010. We estimate that our contract gas with the Beluga River Producers will run-out in 2011.

Chugach is involved in active negotiations to secure additional natural gas supplies once the existing contracts run-out. A gas term sheet was approved by the Chugach Board of Directors on February 25, 2009. The Cook Inlet continues to be a supply basin with adequate reserves for both domestic and foreign utilities. It is likely that Chugach will be able to purchase sufficient natural gas over the next several years because there are adequate reserves in the Cook Inlet. A study by the Department of Energy (DOE) released in 2004 predicts that for a minimal investment an additional 1.4 trillion cubit feet (TCF) of gas can be extracted from existing fields. In a 2005 study released by the United States Geological Survey (USGS) it was estimated that total recoverable reserves remaining are 8.5 TCF, an amount equal to what has been extracted from the Cook Inlet over the last thirty years. Additionally, according to an economic analysis completed by the USGS, at prices above $6, significant volumes of gas can be commercially developed from the North Slope. Even though adequate reserves are available for the future, Chugach will likely experience a change to the existing pricing mechanism from the current contracts. Any new contract is subject

to approval by the RCA. The fuel and purchased power 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.

Financing

Over the next five years Chugach anticipates incurring significant 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. Chugach will be subject to interest rate risk at the time of refinancing. To mitigate this risk, in March of 2008, we issued a Request For Proposal (RFP) for a three to five year interim finance facility. Commercial paper will be issued under this requested facility and will act as a bridge until Chugach converts Commercial Paper balances to long term debt in 2010 and to refinance the 2011 and 2012 Series A bonds. It is anticipated that this facility 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. 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’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. 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.”

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, represent $104.6 million or 37% of sales revenue in 2008 and $93.4 million or 37% in 2007. The HEA contract expires January 1, 2014, and the MEA contract expires December 31, 2014. All rates are approved by the RCA.

Pursuant to provisions of their 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.

In a letter dated January 9, 2007, HEA notified Chugach that HEA would not seek to renew, extend or modify the current Agreement for Sale of Electric Power and Energy (the Agreement) when the Agreement expires on December 31, 2013.

Chugach’s planning process reflects the termination of the MEA and HEA wholesale contracts post 2014. The termination of these contracts will result in a loss of approximately 50%

of Chugach’s power sales load and approximately 40% of its annual sales revenue. 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.

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 we may not be timely informed about the funding status of the plan. We believe the AEPF was 100% funded as of December 31, 2007, however, its assets have likely declined substantially 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. 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 know the financial condition of all employers in the plan.

Item 1B – Unresolved Staff Comments

None

Item 2 - Properties

General

We have 530.1 megawatts of installed capacity consisting of 17 generating units at five power plants. These include 385.0 megawatts of operating capacity at the Beluga facility on the west side of Cook Inlet; 67.5 megawatts of power at the Bernice Lake facility on the Kenai Peninsula; 46.7 megawatts of power at IGT in Anchorage; and 19.2 megawatts at the Cooper Lake facility, which is also on the Kenai Peninsula. We also own rights to 11.7 megawatts of capacity from the two Eklutna Hydroelectric Project generating units that we jointly own with MEA and AML&P. In addition to our own generation, we purchase power from the 126 megawatt Bradley Lake hydroelectric project owned by the Alaska Energy Authority (AEA) through the Alaska Industrial Development and Export Authority. The Bradley Lake facility is operated by HEA and dispatched by us. The Beluga, Bernice Lake and 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 will be 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 in the process of reviewing the lease.

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.

In 1997, we acquired a 30% interest in the Eklutna Hydroelectric Project. The plant is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October 1997.

Our principal generation units are Beluga 3, 5, 6, 7 and 8. These units have a combined capacity of 345.8 MW and meet most of our load. All other units are used principally as reserve. While the Beluga turbine-generators have been in service for many years, they have been maintained in good working order with annual inspections and periodic upgrades. 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 in accordance with the existing maintenance plan. In 2006, Beluga Unit 5 maintenance requirements increased from one to two combustion inspections per year due to high rates of wear observed on aging combustion parts. This maintenance plan continued with two inspections performed in 2007, one of which was a hot gas path inspection involving generator repairs. Two combustion inspections were performed in 2008. Beluga Unit 6 was re-powered in 2000 and had major inspections in 2003 and 2006. During the annual inspection in 2007 the last row of turbine blades was exchanged. Beluga Unit 7 was re-powered in 2001 and had its first major inspection in 2004 and another in 2008. Beluga Unit 8, a steam turbine, received a 25,000-hour inspection in 2005 and a major inspection in 2008.

Chugach is in the process of developing a gas-fired generation plant on land currently owned by Chugach near its Anchorage headquarters. Chugach has partnered with AML&P to construct and jointly own a new 183 megawatt natural gas fired power plant. Chugach will own and take 70% of the new plant’s output and AML&P will own and take the remaining 30%. The plant is scheduled to be placed into service in 2013. 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. In December of 2008, Chugach purchased land adjacent to its Anchorage headquarters. This land will be used as a project laydown area and to relocate materials and equipment previously located on the site of the new power plant. Chugach is currently preparing purchase documentation for engineering, procurement and construction services to be awarded in 2009.

The following matrix depicts nomenclature, run hours for 2008 and percentages of contribution and other historical information for all Chugach generation units.


Facility		Commercial Operation Date	Nomenclature	Rating (MW)(1)		Run Hours (2008)		Percent of Total Run Hours		Percent of Time Available

Beluga Power Plant ⁽³⁾
	1	1968	GE Frame 5		19.6	1,444.8		2.6		90.6
	2	1968	GE Frame 5		19.6	1,420.3		2.5		84.9
	3	1972	GE Frame 7		64.8	8,162.3		14.7		96.9
	5	1975	GE Frame 7		68.7	7,693.0		13.9		93.7
	6	1975	AP 11DM-EV		79.2	8,513.9		15.4		97.0
	7	1978	AP 11DM-EV		80.1	7,188.4		13.0		81.8
	8	1981	BBC DK021150⁽²⁾		53.0	6,092.9		11.0		69.4

					385.0
Bernice Lake Power Plant
	2	1971	GE Frame 5		19.0	0.0		0.0		65.0
	3	1978	GE Frame 5		26.0	2,553.2		4.6		96.0
	4	1981	GE Frame 5		22.5	2,689.9		4.9		92.9

					67.5
Cooper Lake Hydroelectric Plant
	1	1960	BBC MV 230/10		9.6	7,735.8		14.0		93.9
	2	1960	BBC MV 230/10		9.6	1,581.8		2.9		56.9

					19.2
IGT Power Plant
	1	1964	GE Frame 5		14.1	98.1		0.2		96.1
	2	1965	GE Frame 5		14.1	97.7		0.2		97.6
	3	1969	Westinghouse 191G		18.5	79.9		0.1		98.1

					46.7
Eklutna Hydroelectric Plant ⁽⁴⁾
	1	1955	Newport News		5.8	N/A	⁽⁵⁾	N/A	⁽⁵⁾	98.0
	2	1955	Oerlikon custom		5.9	N/A	⁽⁵⁾	N/A	⁽⁵⁾	82.4

					11.7

System Total					530.1	55,352.0		100.00


⁽¹⁾	Capacity rating in MW at 30 degrees Fahrenheit.

⁽²⁾	Steam-turbine powered generator with heat provided by exhaust from natural-gas fueled Units 6 and 7 (combined-cycle).

⁽³⁾	Beluga Unit 4 and Bernice Lake Unit 1 were retired during 1994.

⁽⁴⁾	The Eklutna Hydroelectric Project is jointly owned by Chugach, MEA and AML&P. The capacity shown is our 30% share of the plant’s output.

⁽⁵⁾	Because Eklutna Hydroelectric Project is managed by a committee of the three owners, we do not record run hours or in-commission rates.

Note: GE = General Electric, BBC = Brown Boveri Corporation, AP = Alstom Power

Transmission and Distribution Assets

As of December 31, 2008, 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 768 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% 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 megawatt rated capacity hydroelectric facility near Homer on the southern end of the Kenai Peninsula that was placed into service in September 1991. The project is nominally scheduled below 90 megawatts to minimize losses and ensure system stability. We have a 30.4% (27.4 megawatts as currently operated) share in the Bradley Lake project’s output, and take Seward’s and MEA’s shares which we net bill to them, for a total of 45% of the project’s capacity. We are obligated to pay 30.4% of the annual project costs regardless of project output.

The project was financed and built by AEA through grants from the State of Alaska and the issuance of $166 million principal amount of revenue bonds supported by power sales agreements with six electric utilities that share the output from the facility (AML&P, HEA and MEA (through AEG&T and AEEC), GVEA, Seward and us). The participating utilities have entered into take-or-pay power sales agreements under which AEA has sold percentage shares of the project capacity and the utilities have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt-service costs and amounts required to maintain established reserves). By contract, we also provide transmission and related services to all of the participants in the Bradley Lake project.

The length of our Bradley Lake power sales agreement is fifty years from the date of commercial operation of the facility (September 1991) or when the revenue bond principal is repaid, whichever is the longer. The agreement may be renewed for successive forty-year periods or for the useful life of the project, whichever is shorter. We believe that our maximum annual liability for our take-or-pay obligations is approximately $5.1 million. We believe that so long as this project produces power taken by us for our use that this expense will be recoverable through the fuel and purchased power surcharge process. The share of Bradley Lake indebtedness for which we are responsible is approximately $36 million. Upon the default of a participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs and output pro rata, to the extent necessary to compensate for the failure of the defaulting participant to pay its share, provided that no participant’s percentage share is increased by more than 25%.

Eklutna. We purchased a 30% undivided interest in the Eklutna Hydroelectric Project from the federal government in 1997. MEA owns 17% of the Eklutna Hydroelectric Project. The power MEA purchases from the Eklutna Hydroelectric Project is pooled with our purchases and sold back to MEA to be used in meeting MEA’s overall power requirements. AML&P owns the remaining 53% undivided interest in the Eklutna Hydroelectric Project.

Fuel Supply

In 2008, 91% of our power was generated from natural gas, which included power generated at Nikiski, and 76% of that gas-fired generation took place at Beluga.

Total gas usage in 2008 was approximately 31 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 55%, while ConocoPhillips Alaska Inc., AML&P, and Chevron U.S.A. each provided 15% of Chugach’s gas requirements. Approximately 53 BCF of gas remains on the current contracts. We estimate that our contract gas with Marathon will run-out by mid-2010 and expect the remaining three contracts to run-out in early 2011. Under almost all circumstances the deliverability supplied under our contracts is sufficient to meet all of our generating requirements.

Beluga River Field Producers

We have similar requirements contracts with each of 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% 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% of the price of gas under the Marathon contract (described below) ($6.8574 per thousand cubic feet (MCF) on January 1, 2009), plus taxes. The price during this period under the Chevron contract is approximately 110% of the price of gas under the Marathon contract (described below) ($7.5432 per MCF on January 1, 2009), 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 mid-2010. The base price for gas under the Marathon contract is $1.35 per MCF, adjusted quarterly to reflect the percentage change between the preceding twelve-month period and a base period in the average closing prices of New York Mercantile Exchange (NYMEX) Light, Sweet Crude Oil Futures, the Producer Price Index for natural gas, and the Consumer Price Index for heating fuel oil. The price on January 1, 2009, exclusive of taxes, was $6.8574 per MCF.

Under the terms of the Marathon contract, Marathon generally provides all of the gas required for sales to GVEA, all of Chugach’s requirements at Bernice Lake, IGT and Nikiski and 40% of the requirements at Beluga, not related to sales to GVEA.

Chugach is actively negotiating to secure additional natural gas supplies once the existing contracts run-out beginning in mid-2010. The Cook Inlet continues to be a supply basin with adequate reserves for both domestic and foreign utilities.

ENSTAR

ENSTAR Natural Gas Company (ENSTAR) has a tariff to transport our gas purchased from the Beluga River Field producers or Marathon on a firm basis to our IGT Power Plant at a transportation rate of $0.63 per MCF. The agreement contains a fixed monthly charge of $2,840 for firm service.

Environmental Matters

General

Chugach’s operations are subject to certain federal, state and local environmental laws and regulations, which seek to limit air, water and other pollution and regulate hazardous or toxic waste disposal. While we monitor these laws and regulations to ensure compliance, they frequently change and often become more restrictive. When this occurs, the costs of our compliance generally increase.

We include costs associated with environmental compliance in both our operating and capital budgets. We accrue for costs associated with environmental remediation obligations when those costs are probable and reasonably estimable. We do not anticipate that environmental related expenditures will have a material effect on our results of operations or financial condition. We cannot, however, predict the nature, extent or cost of new laws or regulations relating to environmental matters.

The Clean Air Act and Environmental Protection Agency (EPA) regulations under the act (the “Clean Air Act”) establish ambient air quality standards and limit the emission of many air pollutants. Some Clean Air Act programs that regulate electric utilities, notably the Title IV “acid rain” requirements, do not apply to facilities located in Alaska. 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 that may be established to address problems such as global warming. While we cannot predict whether any new regulation would occur or its limitation, it is possible that new laws or regulations could increase our capital and operating costs. We have obtained or applied for all Clean Air Act permits currently required for the operation of our generating facilities.

In March 2007, Chugach conducted emissions testing at the Bernice Lake Power Plant which indicated that two of the gas turbines at the facility were exceeding the New Source Performance Standards (NSPS) emission limit for nitrogen oxides (NOx). Chugach voluntarily limited the power output of these turbines to ensure interim compliance with the NSPS regulations 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 Conservation (ADEC) issued a Notice of Violation (NOV) on March 26, 2008 regarding the NSPS NOx emission limit exceedances. Chugach has entered into a settlement with ADEC regarding the NOV for the past NSPS non-compliance. As part of the settlement, Chugach has agreed to pay a civil penalty of $112,161 to ADEC. We are currently in the process of resolving the final details of the settlement agreement and anticipate a conclusion in the first quarter of 2009.

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

Matanuska Electric Association, Inc. (MEA) v. State of Alaska, Regulatory Commission of Alaska, Superior Court Case No. 3AN-06-8243 Civil

On May 17, 2006, MEA appealed and on May 30, 2006, HEA cross appealed the RCA’s decision in Docket No. U-04-102, see “Footnote 3, Regulatory Matters – Revision to Current Depreciation Rates (Docket No. U-04-102).” On appeal, MEA claimed the RCA’s decision dated January 10, 2006, to authorize Chugach to implement new depreciation rates as of January 1, 2005, constituted illegal retroactive rate making. MEA further contended that the RCA’s reliance on avoidance of regulatory lag as a basis for its decision was improper. MEA also challenged certain of the RCA’s discovery rulings. Chugach joined the State of Alaska in defending the RCA’s rulings. HEA stipulated with the other parties to dismiss its cross appeal which the Court granted by order dated September 11, 2007. Oral argument was held on July 15, 2008, and on July 21, 2008, the Court issued a decision affirming the RCA’s January 10, 2006 decision. The time for MEA to appeal the Superior Court’s decision to the Alaska Supreme Court has now expired.

Chugach has certain additional litigation matters and pending claims that arise in the ordinary course of Chugach’s business. In the opinion of management, no individual matter or the matters in the aggregate is likely to have a material adverse effect on Chugach’s results of operations, financial condition or liquidity.

Item 4 – Submission of Matters to a Vote of Security Holders

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	2008		2007		2006		2005		2004


Electric plant, net:
In service	$	432,460,336	$	438,239,286	$	439,268,514	$	435,474,237	$	442,552,526

Construction work in Progress		25,151,072		17,712,884		20,683,335		32,505,401		25,278,388


Electric plant, net		457,611,408		455,952,170		459,951,849		467,979,638		467,830,914

Other assets		119,080,561		101,773,948		103,733,881		97,155,862		91,523,673


Total assets	$	576,691,969	$	557,726,118	$	563,685,730	$	565,135,500	$	559,354,587


Capitalization:
Long-term debt		354,383,506		345,423,500		350,803,530		364,532,099		363,357,786

Equities and margins		153,766,999		149,310,436		150,716,100		145,039,152		138,998,799


Total capitalization	$	508,150,505	$	494,733,936	$	501,519,630	$	509,571,251	$	502,356,585


Summary Operations Data

Operating revenues	$	288,292,112	$	257,443,919	$	267,542,713	$	225,697,349	$	201,246,615

Operating expenses		260,580,365		232,367,023		234,969,329		194,823,965		173,340,037

Interest expense, net		22,532,797		23,712,797		24,010,874		22,586,054		21,491,865

Net operating margins		5,178,950		1,364,099		8,562,510		8,287,330		6,414,713

Nonoperating margins		1,232,800		1,521,157		1,476,549		1,227,401		1,187,743


Assignable margins	$	6,411,750	$	2,885,256	$	10,039,059	$	9,514,731	$	7,602,456

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 toward achieving a TIER of 1.25 or greater. For further discussion on factors that contribute to TIER results, see “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations - Years ended December 31, 2008, compared to the years ended December 31, 2007, and December 31, 2006 – Expenses.” We achieved TIERs for the past five years as follows:


Year		TIER

2008		1.28
2007		1.12
2006		1.41
2005		1.42
2004		1.35

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.

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 SES 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 – 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, MEA and HEA, in 2007 and 2006.

Base rates for Seward were modified in accordance with a new power sales agreement on an interim and refundable basis effective June 1, 2006. Prior to the adjudication of our 2005 Test Year Rate Case, a portion of fuel and purchased power costs had been recovered in base energy rates. In the rate case, we modified the rate design so that all fuel and purchased power costs would be recovered through the fuel surcharge. The RCA approved the rates and issued a final order December 20, 2006. (See “Part I – Item 1 – Business – Wholesale Customers – Seward.”)

Revision to Current Depreciation Rates (Docket No. U-04-102)

Chugach implemented new depreciation rates effective January 1, 2004, based on an update of the 1999 Depreciation Study utilizing Electric Plant in Service balances as of December 31, 2002. The 2002 Depreciation Study was submitted to the RCA for approval on November 19, 2004. On March 9, 2005, the RCA ruled in Order No. 2 that depreciation rates may not be implemented without prior approval of the RCA.

In Order No. 9 dated January 10, 2006, the RCA ruled substantially in Chugach’s favor by approving the 2002 Depreciation Study with certain changes to the proposed depreciation rates. The main effect of this decision was to allow Chugach to revise its depreciation rates effective January 1, 2005. Because Chugach did not request changes to the electric rates charged to our customers based on the proposed new depreciation rates, there was no immediate electric rate impact.

Wholesale customers MEA and HEA were active in the proceeding. Subsequently, MEA and HEA filed an appeal of the RCA’s decision in Superior Court, see “Footnote 5, Legal Proceedings – Matanuska Electric Association, Inc. (MEA) v. State of Alaska, Regulatory Commission of Alaska, Superior Court Case No. 3AN-06-8243 Civil.” HEA later dismissed its appeal leaving MEA’s claim focusing mainly on the question of whether implementation of the new depreciation rates as of January 1, 2005 constituted illegal retroactive rate making. Oral argument before the Superior Court was held on July 15, 2008. On July 21, 2008, the Court issued a decision affirming the RCA’s January 10, 2006 decision.

2005 Test Year General Rate Case (Docket No. 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. In this Order, the RCA approved the rates from the Settlement Agreement among Chugach, HEA and Seward that it had previously accepted. MEA did not join the Settlement Agreement and this Order addressed the issues that it had raised. The effect of Order 21 is that overall revenues will decrease by 0.8%, or $0.9 million, with retail base rate revenue decreasing by 4.8%, or $4.2 million and wholesale base rate revenue increasing by 11.0%, or $3.3 million. Order No. 21 was effective June 1, 2008.

On April 21, 2008, Chugach filed a Petition for Reconsideration of Order 21. Chugach asked the RCA to reconsider its decisions regarding the allocation of long-term debt and interest expense and the requirement for specific scenarios in Chugach’s Financial Management Plan (FMP). Chugach also proposed corrections to the RCA calculation of the debt allocator it ordered. No other parties filed for reconsideration of the order.

On May 21, 2008, the RCA issued Order No. 22. The RCA revised the long-term debt allocator from 67.12% to 68.46%. This finding increased MEA’s revenue requirement to Chugach by $107,818. The RCA reaffirmed its requirement for FMP scenarios.

On May 30, 2008, the RCA issued Order No. 23, accepting Chugach’s compliance filing and approving tariff sheets that incorporate the RCA’s findings in Order No. 22.

On June 4, 2008, MEA filed a Petition for Reconsideration of Order No. 23, expressing several concerns about Chugach’s computation of depreciation expenses.

On September 16, 2008, the RCA issued Order No. 24. The RCA reviewed comments submitted by MEA, however, the RCA found that depreciation calculations by Chugach were reasonable.

On October 1, 2008, Chugach submitted three Financial Management Plan scenarios to the Commission in compliance with Order No. 21 in U-06-134. The three scenarios contained in the filing were: Scenario 1: Wholesale relationships continue into the future; Scenario 2: Firm wholesale relationships terminate and are replaced with interruptible sales; and, Scenario 3: Firm wholesale relationships terminate and are not replaced with interruptible sales. On November 7, 2008, the RCA issued Order No. 25, accepting Chugach’s Financial Management Plan as filed and closing docket U-06-134.

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 purchase power costs are primarily due to fuel price adjustment mechanisms in our gas-supply contracts based on natural gas, crude oil and fuel oil indexed price changes. 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.


	*Years ended December 31, 2008, compared to the years ended December 31, 2007, and December 31, 2006*

Margins

Our margins for the years ended December 31 were as follows:


	2008		2007		2006

Net Operating Margins	$	5,178,950	$	1,364,099	$	8,562,510
Non-Operating Margins	$	1,232,800	$	1,521,157	$	1,476,549

Assignable Margins	$	6,411,750	$	2,885,256	$	10,039,059

The increase in assignable margins in 2008 from 2007 of $3.5 million, or 122.2%, was due primarily to a decrease in transmission, distribution and net interest expense. The decrease in assignable margins in 2007 from 2006 of $7.2 million, or 71.3%, was due to a decrease in retail kWh sales and an increase in power production, transmission, distribution and administrative, general and other expense, see “Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Years ended December 31, 2008, compared to the years ended December 31, 2007, and December 31, 2006 – Expenses.”

Non-operating margins include interest income, allowance for funds used in construction, capital credits and patronage capital allocations. Non-operating margins decreased in 2008 from 2007 by $288.4 thousand, or 19.0% 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. Non-operating margins did not materially change in 2007 from 2006.

Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2008, operating revenues were $30.8 million, or 12.0% 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. In 2007, operating revenues were $10.1 million, or 3.8%, lower than in 2006 due to a decrease in economy energy sales and a decrease in retail kWh sales. The decrease was also attributed to lower fuel costs recovered in revenue through the fuel surcharge process due primarily to a reduction and subsequent refund of Cook Inlet power production taxes. These decreases were partially offset by an increase in wholesale kWh sales and demand.

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. Retail revenue decreased in 2007 from 2006 primarily due to lower fuel costs recovered in revenue through the fuel surcharge process due to a reduction and subsequent refund of Cook Inlet power production taxes, as well as lower sales to Chugach’s large commercial customer classes. Several large commercial classes experienced growth, however, one large commercial customer replaced their electric compressors with gas-fired compressors, significantly reducing sales.

Wholesale revenue was higher in 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. Wholesale revenue was higher in 2007 from 2006 due to increased sales and demand. The increase in sales to MEA and HEA was due to increased economic activity while the increase in sales in 2007 to Seward was caused by a decrease in sales due to an avalanche in 2006 that interrupted service on their single transmission line connecting Seward to the grid. These increases were offset by lower fuel costs recovered in revenue through the fuel surcharge process due primarily to a reduction and subsequent refund of Cook Inlet power 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 SES contributed approximately $27.7 million, $26 million and $25 million to Chugach’s fixed costs for the years ended December 31, 2008, 2007 and 2006, 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, 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	0.0	%	$	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 following table shows the base rate sales revenue and fuel and purchased power revenue by customer class that is included in revenue for the years ended December 31, 2007, and 2006.


	Base Rate Sales Revenue						Fuel and Purchased Power Revenue						Total Revenue

	2007		2006		% Variance		2007		2006		% Variance		2007		2006		% Variance

Retail
Residential	$	46.8	$	49.8	(6.0	%)	$	30.1	$	29.9	0.7	%	$	76.9	$	79.7	(3.5	%)
Small Commercial	$	8.5	$	8.8	(3.4	%)	$	6.4	$	6.2	3.2	%	$	14.9	$	15.0	(0.7	%)
Large Commercial	$	29.5	$	29.6	(0.3	%)	$	28.2	$	28.8	(2.1	%)	$	57.7	$	58.4	(1.2	%)
Lighting	$	1.3	$	1.3	0.0	%	$	0.1	$	0.1	0.0	%	$	1.4	$	1.4	0.0	%
Total Retail	$	86.1	$	89.5	(3.8	%)	$	64.8	$	65.0	(0.3	%)	$	150.9	$	154.5	(2.3	%)

Wholesale
HEA	$	10.5	$	10.3	1.9	%	$	26.3	$	24.5	7.3	%	$	36.8	$	34.8	5.7	%
MEA	$	19.0	$	19.1	(0.5	%)	$	37.6	$	36.1	4.2	%	$	56.6	$	55.3	2.4	%
SES	$	1.2	$	1.1	9.1	%	$	3.2	$	2.9	9.8	%	$	4.4	$	4.0	9.6	%
Total Wholesale	$	30.7	$	30.5	0.7	%	$	67.1	$	63.6	5.5	%	$	97.8	$	94.1	4.0	%

Economy Sales	$	1.5	$	4.0	(62.8	%)	$	4.2	$	12.0	(65.0	%)	$	5.7	$	16.0	(64.5	%)
Miscellaneous	$	3.0	$	2.9	1.9	%	$	0.0	$	0.0	n/a		$	3.0	$	2.9	2.5	%

Total Revenue	$	121.3	$	126.9	1.9	%	$	136.1	$	140.6	(3.1	%)	$	257.4	$	267.5	(3.8	%)

The major components of our operating revenue for the year ending December 31 were as follows:


	2008		2008		2007		2007		2006		2006

	Sales (MWh)		Revenue		Sales (MWh)		Revenue		Sales (MWh)		Revenue

Retail		1,205,832	$	157,549,359		1,206,037	$	150,891,863		1,229,977	$	154,549,693
Wholesale:
HEA		517,368		41,133,287		522,901		36,812,475		478,129		34,799,775
MEA		742,666		63,500,034		724,465		56,566,527		723,452		55,269,740
Seward		63,734		4,798,286		63,941		4,454,186		58,671		3,991,430

Total Wholesale		1,323,768		109,431,607		1,311,307		97,833,188		1,260,252		94,060,945
Economy energy		256,105		18,526,481		93,753		5,745,732		263,037		16,014,663
Other		N/A		2,784,665		N/A		2,973,136		N/A		2,917,412

Total revenue		2,785,705	$	288,292,112		2,611,097	$	257,443,919		2,753,266	$	267,542,713

We make economy sales to GVEA. These sales commenced in 1989 and have contributed to our growth in operating revenues. We do not take such economy sales into consideration in our long-range resource planning process because these sales are non-firm sales that depend on GVEA’s need for additional energy and our available generation at the time. In 2008, 2007, and 2006, economy sales to GVEA constituted approximately 6%, 2%, and 6%, respectively, of our sales revenues. We charge GVEA a rate sufficient to recover the gas cost, the costs of incremental operations and maintenance expense resulting from increased use of our generators for GVEA, and an agreed-upon margin for each kWh sold. Consequently, sales to GVEA do not significantly affect margins. Economy energy revenue increased in 2008 from 2007 due to increased sales to GVEA. Transmission line work and maintenance on several Beluga units limited our ability to generate additional output available for economy energy sales in 2007. In 2007 Chugach was also constrained by contracted fuel limitations from our economy sales fuel supplier, which is why economy energy revenue decreased in 2007 from 2006.

Expenses

The major components of our operating expenses for the years ended December 31 were as follows:


	2008		2007		2006

Fuel	$	137,894,553	$	106,023,734	$	120,280,509
Power production		16,718,777		16,171,717		15,050,338
Purchased power		31,486,621		33,947,828		25,979,919
Transmission		5,841,405		6,781,166		6,283,845
Distribution		12,398,832		13,716,105		12,134,087
Consumer accounts		5,396,662		4,899,878		4,982,313
Administrative, general and other		20,014,239		21,776,968		21,728,555
Depreciation		30,829,276		29,049,627		28,529,763

Total operating expenses	$	260,580,365	$	232,367,023	$	234,969,329

Fuel

Chugach recognizes actual fuel expense as incurred. Fuel expense increased by $31.9 million, or 30.1%, 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 in purchased power.

Fuel expense decreased by $14.3 million, or 11.9%, in 2007 from 2006 due primarily to a reduction and subsequent refund of $3.4 million of Cook Inlet power production taxes, which resulted in a lower average fuel price than in 2006. In 2007, Chugach used 27,633,963 MCF of fuel at an average effective price of $4.49 per MCF, which did not include 2,702,879 MCF of fuel that was recorded in purchased power.

Power Production

Power production expense increased $547.1 thousand, or 3.4%, 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.

Power production expense increased $1.1 million, or 7.5%, in 2007 from 2006 due primarily to information services allocated compliance costs in 2007 and the amortization associated with the Beluga River Gas Compression project.

Purchased Power

Purchased power costs decreased $2.5 million, or 7.2%, 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.

Purchased power costs increased $8.0 million, or 30.7%, in 2007 from 2006 due primarily to higher MWh purchased and at a higher average effective price. In 2007, Chugach purchased 523,910 MWh of energy at an average effective price of 6.18 cents per kWh. Higher MWh purchased in 2007 was caused by Dynamite Slough transmission line work and maintenance on several Beluga units which limited our output from Beluga. We also purchased less from Bradley Lake in 2007 due to low water levels and inflows but paid more in Bradley Lake expenses which contributed to the higher average effective price. In 2006, Chugach purchased 475,909 MWh of energy at an average effective price of 5.19 cents per kWh.

Transmission

Transmission expense decreased $939.8 thousand, or 13.9%, in 2008 from 2007 due primarily to lower labor expense related to substation maintenance as well as lower information services allocated compliance costs.

Transmission expense increased $497.3 thousand, or 7.9%, in 2007 from 2006 due primarily to higher information services allocated compliance costs as well as labor contract increases in 2007 over 2006.

Distribution

Distribution expense decreased $1.3 million, or 9.6%, 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.

Distribution expense increased $1.6 million, or 13.0%, in 2007 from 2006 due primarily to information services allocated compliance costs, labor contract increases and costs associated with an outage in the first quarter of 2007.

Consumer Accounts

Consumer accounts expense, which represents costs associated with maintaining customer accounts and membership, increased $496.8 thousand, or 10.1%, in 2008 from 2007 due primarily to an increase in uncollectible accounts and higher advertising and imaging costs associated with capital credit retirements.

Consumer accounts expense did not materially change in 2007 from 2006.

Administrative, General and Other Charges

Administrative, general and other charges decreased $1.8 million, or 8.1%, 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.

Administrative, general and other charges did not materially change in 2007 from 2006, however, labor increased $422.1 thousand in 2007 over 2006 primarily due to administrative cost-of-living labor increases as well as an accrual for estimated severance costs. Professional services increased $1.7 million in 2007 over 2006 primarily due to costs associated with Sarbanes-Oxley compliance and other Board related studies. These increases were offset by a decrease in other deductions due to the $1.6 million write off of obsolete inventory and cancelled projects in 2006.

Depreciation

Depreciation expense increased $1.8 million, or 6.1%, 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.

Depreciation expense did not materially change in 2007 from 2006. We use remaining life rates set forth in the most recent depreciation study, currently the 2005 depreciation study, which has been in effective since June 1, 2008.

Interest

Interest on long-term obligations decreased $2.9 million, or 12.1%, 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 long-term obligations did not materially change in 2007 from 2006.

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 on short-term borrowing increased $90.6 thousand, or 100%, in 2007 from 2006 due primarily to interest paid on an electric account.

Interest charged to construction decreased $170.7 thousand, or 27.7%, in 2008 from 2007 due primarily to a lower weighted average rate during 2008 of 5.1% compared to 6.3% during 2007.

Interest charged to construction increased $168.2 thousand, or 37.5%, in 2007 from 2006 due to a higher average balance in Construction Work In Progress (CWIP), primarily due to more capital spending in 2007 over 2006.

Patronage Capital (Equity)

The following table summarizes our patronage capital and total equity position for the years ended December 31:


	2008			2007			2006


Patronage capital at beginning of year	$	138,713,338		$	141,117,620		$	136,185,378
Retirement of capital credits		(3,115,090	)		(5,289,538	)		(5,106,817	)
Assignable margins		6,411,750			2,885,256			10,039,059

Patronage capital at end of year		142,009,998			138,713,338			141,117,620
Other equity¹		11,757,001			10,597,098			9,598,480

Total equity at end of year	$	153,766,999		$	149,310,436		$	150,716,100


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 $3,115,090, $5,289,538, and $5,106,817 in capital credits for the years ended December 31, 2008, 2007, and 2006, respectively. Prior to 2000, wholesale capital credits had been retired on a 10-year cycle pursuant to an approved capital credit retirement program, which was contained in the Chugach business plan. However, in 2000 we implemented a plan to return the capital credits of wholesale and retail customers on a 15-year rotation. For the years 1997, 1998 and 1999, wholesale capital credits are to be retired on a 10-year cycle pursuant to a prior settlement agreement. In 2008 and 2007, $1,478,779 and $79,079, respectively, of 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% of our patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, our aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of our total liabilities and equities and margins.

Under our Master Loan Agreement with CoBank, Chugach is prohibited from making any distribution of patronage capital to Chugach’s customers if an event of default under the Master Loan Agreement exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins.

The table below sets forth a five-year summary of anticipated capital credit retirements:


Year Ending	Total

2009	$	3,300,000
2010	$	0
2011	$	0
2012	$	0
2013	$	0

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 increased $19.0 million, or 3.4%, from December 31, 2007, to December 31, 2008. The increase was due in part to a $1.7 million, or 0.4%, increase in net utility plant due to extension and replacement of plant in excess of depreciation expense, as well as a $1.3 million, or 20.6%, increase in cash and cash equivalents. The increase was also due to a $1.7 million, or 5.3% increase in accounts receivable caused primarily by higher fuel costs and a $11.8 million, or 100% increase in fuel cost under-recovery due to the under collection of fuel and purchased power costs through the fuel and purchased power surcharge process. The increase in fuel cost under-recovery was due primarily to unplanned maintenance and lower than expected output from our hydro facilities. The increase was also due to a $2.3 million, or 10.9% increase in deferred charges due primarily to the Beluga Unit 8 inspection and charges associated with fuel supply negotiations.

Liabilities

Total liabilities increased by $19.0 million, or 3.4%, in 2008 as compared to 2007. Contributors to this change include a $3.3 million, or 0.9% increase in long-term obligations and current installments of long-term obligations due to the use of the NRUCFC line of credit primarily associated with a land purchase and capital expenditures, which was somewhat off set by principal payments made on CoBank 2, 3, 4 and 5 and the 2002 Series B bonds. Notes payable increased $2.9 million, or 100% due to the property acquired in December of 2008 for, among other purposes, construction of an additional electrical generation facility. Short-term obligations also increased $7.5 million, or 100% to finance the under-recovery of fuel costs. Fuel payable increased $6.2 million, or 27.6% due to the increase in fuel costs. These increases were offset by a $1.6 million, or 100% decrease in fuel cost over-recovery due to the elimination of the over-recovery from 2007 through the fuel and purchased power surcharge process. Accounts payable also decreased $1.0 million, or 11.8% due to the timing of cash payments on invoices for good and services. Other current liabilities also decreased $2.0 million, or 54.7% due to an increase in state and municipal undergrounding activities, which reduced our ordinance liability, as well as a decrease in patronage capital payable. Deferred compensation also decreased $503.6 thousand, or 65.6 percent.

Equities and Margins

Total margins and equities increased $4.4 million, or 3.0%, in 2008 as compared to 2007 due to a $3.3 million, or 2.4%, net increase in patronage capital ($6.4 million increase in margins coupled with a $3.1 million retirement of capital credits). The increase was also due to a $1.1 million, or 12.1%, increase in other margins and equities primarily attributed to the increase of unclaimed capital credits from the 2008 retirement of patronage capital.

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 2008. 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 effect our operations.

Contractual Obligations and Commercial Commitments

The following are Chugach’s contractual and commercial commitments as of December 31, 2008:


	Contractual cash obligations:					(In thousands)


Payments Due By Period

		Total		2009		2010-2011		2012-2013		Thereafter

Long-term debt		$	358,787	$	4,404	$	199,933	$	124,770	$	29,680
Long-term interest expense¹			53,082		19,170		28,487		2,071		3,354
Short-term debt²			7,500		7,500		0		0		0
Bradley Lake³			52,442		3,698		7,390		7,339		34,015
Capital Credit Retirements⁴			3,300		3,300		0		0		0
Fuel and fuel transportation expense⁵			353,570		164,972		188,598		0		0
Gas turbine purchase agreement⁶			46,305		23,520		22,785		0		0
Promissory note⁷			2,860		2,860		0		0		0

Total		$	877,846	$	229,424	$	447,193	$	134,180	$	67,049


	¹ Long-term interest expense includes fixed and estimated variable rates. The variable rates are forecasted using actual December 31, 2008 rates for CoBank 3, 4 and 5 and the NRUCFC line of credit. (See “Part II – Item 8 – Financial Statements and Supplemental Data – Note (8) Debt.”)

	² At December 31, 2008, Chugach had $82.5 million in lines of credit with various financial institutions, which fund capital requirements. At December 31, 2008, there was $50.5 million outstanding on the lines of credit, therefore, the available borrowing capacity under these lines of credit was $32.0 million and could be used for future operational and capital funding requirements.

	³ Estimated annual cost


	⁴ Anticipated capital credit retirements for the next five years. All capital credit retirements require Board approval.

	⁵ Estimated fuel and fuel transportation expense. We estimate that our fuel contracts will last approximately two years, however, we are currently negotiating new fuel contracts.

	⁶ In accordance with the General Electric Packaged Power gas turbine purchase agreement executed on November 17, 2008.

	⁷ In accordance with the promissory note associated with land purchased in December of 2008.

Purchase obligations

Chugach is a participant and has a 30.4% share in the Bradley Lake hydroelectric project (See “Item 2-Properties-Other Property-Bradley Lake.”) This contract runs through 2041. We have agreed to pay a like percentage of annual costs of the project, which has averaged $4.6 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-Fuel Surcharge.”)

Chugach is in the process of jointly developing a gas-fired generation plant with AML&P. Chugach will own and take 70% of the new plant’s output and AML&P will own and take the remaining 30%. 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). Chugach made a payment of $5.1 million in 2008 and will make progress and milestone payments of $23.5 million and $22.8 million in 2009 and 2010, respectively, pursuant to its purchase agreement with GEPP.

Liquidity And Capital Resources

Lines of Credit

Chugach maintains a $7.5 million line of credit with CoBank, ACB (CoBank). The line of credit was renewed by CoBank, extending the expiration date to October 31, 2009, and is subject to annual renewal at the discretion of the parties. Chugach utilized this line of credit in the first quarter of 2008 and had $5.5 million outstanding at March 31, 2008. In April and May of 2008, Chugach had additional line of credit activity, however, in June of 2008, Chugach paid off the outstanding balance. In August and September of 2008 Chugach borrowed $7.5 million on this line of credit, which represented the balance at December 31, 2008. On February 27, 2009, Chugach repaid $4.5 million and on March 3, 2009, Chugach repaid the $3.0 million balance on this line of credit. At December 31, 2007, there was no outstanding balance on this line of credit. The borrowing rate is calculated using the CoBank Base Rate on the first business day of the week plus 3%. The average borrowing rate for 2008 and 2007 was 3.82% and 6.47%, 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 shall be permanently reduced to $50 million upon the earlier of January 1, 2010 or the date Chugach pays down this line of credit to an outstanding balance of not more than $50 million. 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. The borrowing rate at December 31, 2008, on this transaction was 2.75%. Chugach utilized this line of credit in the fourth quarter of 2008 and had a balance of $43.0 million at December 31, 2008. In January of 2009 Chugach had additional line of credit activity and had a balance of $38 million on January 30, 2009, when we repaid $30.0 million on this line of credit by issuing commercial paper under our Commercial Paper program described below. Consequently, effective January 30, 2009, Chugach’s borrowing limit on its NRUCFC line of credit was permanently reduced to $50 million. In February of 2009 Chugach repaid the remaining balance on this line of credit by issuing commercial paper. Chugach did not utilize this line of credit in 2007 so there was no outstanding balance at December 31, 2007. The borrowing rate is calculated using the total rate per annum as may be fixed by CFC and will not exceed the Prevailing Prime Rate, plus one percent per annum. At December 31, 2008 and 2007, the borrowing rate was 5.00% and 6.40%, respectively. The NRUCFC line of credit expires October 14, 2012. Repayment of this line of credit is due on January 1, 2010, and is therefore classified as long-term.

Commercial Paper

Over the next five years Chugach anticipates incurring significant 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 will be issued to act as a bridge until Chugach converts Commercial Paper balances to long term debt in 2010 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. 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

Principal maturities and sinking fund payments of our outstanding indebtedness at December 31, 2008 are set forth below:


Year Ending December 31	Sinking Fund Requirements		Principal Maturities		Total


2009	$	0	$	4,403,653	$	4,403,653
2010		0		47,081,687		47,081,687
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
Thereafter		0		29,680,420		29,680,420

	$	270,000,000	$	88,787,159	$	358,787,159

During 2008 we spent approximately $29.1 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 2009 through 2013 as contained in the Capital Improvement Plan (CIP), which was approved on November 20, 2008:


Year		Estimated Expenditures

2009		$72.1 million
2010		$117.1 million
2011		$93.7 million
2012		$72.6 million
2013		$24.9 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

Some of the challenges facing Chugach in the near and intermediate term include procuring a new, highly efficient power generation facility, natural gas contracts, low cost financing and replacement revenue sources for wholesale customer loads that will terminate in 2014, all while controlling operating expenses to minimize customer rate impacts. 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 megawatt natural gas fired power plant. Chugach will own and take 70% of the new plant’s output and AML&P will own and take the remaining 30%. The plant is scheduled to be placed into service in 2013. Major components have been ordered and Chugach is currently preparing purchase documentation for engineering, procurement and construction services to be awarded in 2009. Chugach’s interim financing for the plant will come from its established lines of credit and a

commercial paper borrowing program that was established via an unsecured $300 million commercial paper credit agreement in 2008. Given the recent 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. This will include federal, state, private placement and the public markets to obtain the lowest cost financing available for the refinancing of the maturing 2011 and 2012 long term bonds and long term financing requirements for our new plant and other capital additions.

Negotiations continue with natural gas producers to obtain new long term natural gas contracts to meet Chugach’s needs for the future. A gas term sheet was approved by Chugach’s Board of Directors on February 25, 2009.

The notification by HEA and MEA that neither organization will renew their current wholesale power contracts post 2014 will result in a loss of approximately 50% of Chugach’s power sales load and approximately 40% of its annual sales revenue. While Chugach’s financial management plan indicates that Chugach can sustain its operations and meet its financial covenants in the event these two customers leave the system, some rate increases will be required of the remaining customers. Consequently, Chugach will be pursuing replacement sources of revenue through potential new power sales agreements and transmission wheeling and ancillary services tariff revisions (see “Item 1A - Risk Factors – Wholesale Contracts”.) 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. HEA recently announced that it will enter into a power sales agreement to purchase power beginning in 2014 from the Healy Clean Coal Project, a 50 megawatt clean coal facility located in interior Alaska. The Healy plant is not in proximity to HEA’s service territory, requiring, at this time, the utilization of Chugach’s transmission system. Successful implementation of new power sales agreements and revised tariffs will mitigate anticipated rate increases in the 2014 and 2015 timeframe.

A State of Alaska Energy Plan recently released by Alaska’s Governor called for a migration to renewable energy 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 % natural gas fuel source – 10% 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.

In recognizing the value to Chugach, and to the electric consumers of the Railbelt as a whole, Chugach is willing to explore with other Railbelt utilities the creation of a public state corporation, organized for the purpose of providing for the unified generation and transmission needs in the Alaska Railbelt. On February 18, 2008, the Board authorized the execution of a Memorandum of Understanding with other Railbelt utilities regarding organization of a Unified Power Provider. In February of 2009, the governor of Alaska issued a statement that she will be sponsoring a bill in the future toward forming a state corporation to oversee power generation in the Railbelt. This central authority would build efficient power plants, coordinate power generation between all facilities and send electricity over a reliable power grid.

Ratings

On December 4, 2008, Moody’s Investors Service downgraded our bond rating from A2 Stable to A3 Stable. Our bond ratings with Fitch Investor Service and Standard & Poors Ratings Services remained unchanged in 2008 at A- Stable and A- Stable, respectively. 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, 2008.

Electric Utility Regulation

Chugach is subject to regulation by the RCA. The RCA sets the rates Chugach is permitted to charge customers based on allowable costs. As a result, Chugach applies Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71). Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of

gains or creation of liabilities and the recording of related regulatory liabilities. The application of Statement No. 71 has a further effect on Chugach’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by the Company; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement benefits have less of a direct impact on Chugach’s results of operations than they would on a non-regulated company. As reflected in the financial statements (See “Item 8 -Financial Statements and Supplementary Data – Note 1k – Deferred Charges and Credits”), significant regulatory assets and liabilities have been recorded. Management reviews the ultimate recoverability of these regulatory assets and liabilities based on applicable regulatory guidelines. However, adverse legislation and judicial or regulatory actions could materially impact the amounts of such regulatory assets and liabilities and could adversely impact Chugach’s financial statements.

Unbilled revenue

Chugach calculates unbilled retail revenue at the end of each month to ensure the recognition of a full 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 $10,024,312 and $8,300,461 of unbilled retail revenue at December 31, 2008 and 2007, respectively.

Allowance for Doubtful Accounts

We maintain an allowance for doubtful accounts for estimated losses resulting from the inability of our customers to make required payments. We base our estimates on the aging of our accounts receivable balances, historical bad debt reserves, historical percent of retail revenue that has been deemed uncollectible, changes in our collections process and regulatory requirements. If the financial condition of our customers were to deteriorate resulting in an impairment of their ability to make payments, additional allowances may be required. If their financial condition improves, allowances may be reduced. Such allowance changes could have a material effect on our consolidated financial condition and results of operations.

New Accounting Standards

SFAS No. 141R “Business Combinations”

In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 141R, “Business Combinations.” SFAS No. 141R replaces FASB Statement No. 141, “Business Combinations.” This statement retains the requirements in SFAS No. 141 that the acquisition method of accounting be used and for an acquirer to be identified for each business combination. This statement defines the acquirer and establishes the acquisition date. This statement applies only to business combinations in which control was obtained by transferring consideration. By applying the same method, this statement improves the comparability of the information about business combinations provided in financial reports. This statement applies prospectively to

business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. Chugach will begin application of SFAS No. 141R on January 1, 2009, and it does not expect to have a material affect on our results of operations, financial position, and cash flows.

SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008. Chugach will begin application of SFAS No. 161 on January 1, 2009, and does not expect it to have a material effect on our results of operations, financial position, and cash flows.

FSP FAS No. 157-2 “Effective Date of FASB Statement No. 157”

In February 2008, the FASB issued FSP FAS No. 157-2, “Effective Date of FASB Statement No. 157.” FSP FAS No. 157-2 deferred the effective date of applying SFAS No. 157 to nonfinancial assets and nonfinancial liabilities, from financial statements issued for fiscal years beginning after November 15, 2007, to fiscal years beginning after November 15, 2008. FSP FAS No. 157-2 is effective upon issuance. Chugach will begin application of SFAS No. 157 to nonfinancial assets and nonfinancial liabilities on January 1, 2009, which is not expected to have a material effect on our results of operations, financial position, and cash flows.

FSP FAS No. 142-3 “Determination of the Useful Life of Intangible Assets”

In April 2008, the FASB issued FSP FAS No. 142-3, “Determination of the Useful Life of Intangible Assets.” FSP FAS No. 142-3 amends SFAS No. 142, “Goodwill and Other Intangible Assets,” to define the factors to be considered in developing the renewal or extension assumptions used to determine the useful life of the recognized intangible assets under SFAS No. 142. SFAS No. 142 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and early adoption is prohibited. Chugach will begin application FSP FAS No. 142-3 to intangible assets on January 1, 2009, which is not expected to have a material effect on our results of operations, financial position, and cash flows.

EITF No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement”

In September 2008, the FASB’s EITF ratified EIFT No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement.” EITF No. 08-5 establishes how to treat the debt issued with a third-party credit enhancement that is inseparable from the debt instrument. In September 2008, the FASB’s EITF reached a consensus to change the effective date of EITF No. 08-5 to be effective on a prospective basis for the first reporting period beginning on or after December 15, 2008. The FASB ratified this consensus at its September 24, 2008 meeting. Therefore, Chugach will begin application of EITF No. 08-5 on January 1, 2009, which is not expected to have a material effect on our results of operations, financial position, and cash flows.

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, 2008:


Total Debt¹	2009			2010			2011			2012			2013			Thereafter				Total			Fair Value


Fixed rate	$	2,000		$	1,500		$	150,000		$	120,000		$	0			$	0		$	273,500		$	285,926

Average interest rate		5.50	%		5.50	%		6.55	%		6.20	%		0.00	%			0.00	%		6.38	%

Annual interest expense	$	17,405		$	17,297		$	9,487		$	620		$	0			$	0

Variable rate	$	2,404		$	45,582		$	2,851		$	2,694		$	2,076			$	29,680		$	85,287		$	85,287

Average interest rate		1.30	%		5.02	%		1.30	%		1.30	%		1.30	%			1.30	%		3.29	%

¹Includes current portion

Chugach is exposed to market risk from changes in interest rates on its variable rate long term debt (NRUCFC line of credit and CoBank notes). A 100 basis-point change (up or down) would increase or decrease our interest expense by approximately $852,872, based on $85,287,159 of variable debt outstanding at December 31, 2008. Management does not believe the downgrade Chugach recently received from Moody’s Investors Service on our bonds will materially affect interest rates associated with future financing.

2002 Series B Bonds

The 2002 Series B Bonds (the “Auction Rate Bonds”) had a maturity date of February 1, 2012. The applicable interest rate for any 28-day auction period was the term rate established by the auction agent based on the terms of the auction. The Auction Rate Bonds could have been converted, in Chugach’s discretion, to a daily, seven-day, 35-day, three-month or a semi-annual period or a flexible auction period. The Auction Rate Bonds were not subject to redemption at the option of the bondholders under any circumstances. Chugach could elect to redeem the bonds and was required to redeem the bonds in pre-established incremental amounts over time through a sinking fund. The Auction Rate Bonds were subject to a remarketing agreement on a best efforts basis, however in the event of unsuccessful remarketing, the bonds would be returned to the bondholders and would continue as auction rate bonds subject to a maximum auction rate (15%). Under no circumstances would Chugach have been obligated to pay off the Bonds in the event of an unsuccessful remarketing effort. Chugach had not provided any protection to the bondholders in the event of an unsuccessful remarketing, therefore, Chugach had classified the Bonds as long-term,

with the exception of the mandatory sinking fund payment. The average interest rate for the 2002 Series B Bonds in 2008, 2007, and 2006 was 4.87%, 5.34%, and 5.07%, respectively.

Certain events affecting bond insurers, including Chugach’s bond insurer, MBIA, had injected some level of uncertainty regarding the success of the auction process. By the terms of the auction securities agreement, should an attempt to reset the interest rate on Chugach’s auction rate bonds fail because there was insufficient bids to establish a market-based price, the interest rate on Chugach’s 2002 Series B Bonds would have been set utilizing an “Auction Mode Multiple” as defined in Exhibit A to Appendix 2 to Eleventh Supplemental Indenture (Auction Procedures Description).

The “Auction Mode Multiple” as of any Auction Date was a percentage of the Index in effect on such auction date (in Chugach’s case, a percentage of the one month London Interbank Offered Rate (LIBOR). That percentage was based on the Prevailing Rating of the 2002 Series B Bonds in effect at the close of business on the Business Day immediately preceding the Auction Date.

In Chugach’s case, the Auction Mode Multiple was based on MBIA’s AAA rating and would have been 150% of one-month LIBOR. That rate would have stayed in effect for 28 days, followed by another auction. On February 20, 2008, the auction was held and failed to obtain sufficient clearing bids. Therefore, the current bondholders continued to hold the bonds and the rate on the 2002 Series B Bonds was set at 4.677% and stayed in effect until March 20, 2008. The failure of the auction did not constitute an event of default under any financing arrangement.

On March 5, 2008, bondholders were notified of the intent of Chugach to redeem the entire outstanding principal amount of the 2002 Series B Bonds. The Board of Directors authorized the redemption using funds obtained from one or more new borrowings under Chugach’s existing lines of credit with CoBank or NRUCFC.

On March 20, 2008, Chugach redeemed the $29.6 million outstanding principal amount of the 2002 Series B Bonds using our NRUCFC line of credit at an initial rate of 3.46%. Repayment of the NRUCFC line of credit is due on January 1, 2010. Accordingly, outstanding borrowings continue to be classified as long-term.

Commercial Paper

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 an additional $10.0 million of commercial paper to repay the balance of its NRUCFC line of credit. 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, 2008 and 2007, 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, 2008. 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, 2008 and 2007, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2008, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG, LLP

March 9, 2009
Anchorage, Alaska

Chugach Electric Association, Inc.

Balance Sheets

December 31, 2008 and 2007


Assets	2008			2007


Utility Plant (notes 1d, 3, 11 and 12):
Electric plant in service	$	821,462,475		$	805,631,207

Construction work in progress		25,151,072			17,712,884

Total utility plant		846,613,547			823,344,091

Less accumulated depreciation		(389,002,139	)		(367,391,921	)

Net utility plant		457,611,408			455,952,170

Other property and investments, at cost:
Nonutility property		24,461			24,461

Special Funds		264,427			768,041

Investments in associated organizations (note 4)		12,177,769			11,993,378

Total other property and investments		12,466,657			12,785,880

Current assets:
Cash and cash equivalents, including repurchase agreements of $9,639,446 in 2008 and $9,730,078 in 2007		7,491,302			6,209,936

Special deposits		114,930			125,117

Fuel cost under-recovery (note 1n)		11,788,078			0

Accounts receivable, less provision for doubtful accounts of $408,632 in 2008 and $541,368 in 2007		33,019,372			31,355,481

Materials and supplies		28,806,641			28,422,088

Prepayments		1,544,025			1,357,980

Other current assets		272,357			264,501

Total current assets		83,036,705			67,735,103

Deferred charges, net (notes 5 and 13)		23,577,199			21,252,965


Total assets	$	576,691,969		$	557,726,118

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Balance Sheets (continued)

December 31, 2008 and 2007


Liabilities, Equities and Margins	2008		2007


Equities and margins (notes 6 and 7):
Memberships	$	1,390,413	$	1,345,013

Patronage capital		142,009,998		138,713,338

Other		10,366,588		9,252,085

Total equities and margins		153,766,999		149,310,436

Long-term obligations, excluding current installments (notes 8 and 9):

Bonds payable		270,000,000		299,600,000

National Bank for Cooperatives promissory notes payable		41,419,847		45,823,500

National Rural Utilities Cooperative Finance Corporation promissory notes payable		42,963,659		0

Total long-term obligations		354,383,506		345,423,500

Current liabilities:
Current installments of long-term obligations (notes 8 and 9)		4,403,653		10,106,804

Promissory notes payable		2,860,000		0

Short-term obligations		7,500,000		0

Accounts payable		6,999,140		7,935,566

Consumer deposits		2,410,980		2,403,051

Fuel cost over-recovery (note 1n)		0		1,596,010

Accrued interest		6,158,927		6,304,609

Salaries, wages and benefits		5,481,621		5,953,873

Fuel		28,494,211		22,337,653

Other current liabilities		1,666,521		3,680,212

Total current liabilities		65,975,053		60,317,778

Deferred compensation		264,427		768,041

Deferred credits (note 5)		2,301,984		1,906,363


Total liabilities, equities and margins	$	576,691,969	$	557,726,118

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Statements of Operations

Years Ended December 31, 2008, 2007 and 2006


	2008			2007			2006

Operating revenues (notes 1m, 2 and 13)	$	288,292,112		$	257,443,919		$	267,542,713

Operating expenses:

Fuel (note 13)		137,894,553			106,023,734			120,280,509

Power production		16,718,777			16,171,717			15,050,338

Purchased power		31,486,621			33,947,828			25,979,919

Transmission		5,841,405			6,781,166			6,283,845

Distribution		12,398,832			13,716,105			12,134,087

Consumer accounts		5,396,662			4,899,878			4,982,313

Administrative, general and other charges		20,014,239			21,776,968			21,728,555

Depreciation		30,829,276			29,049,627			28,529,763


Total operating expenses		260,580,365			232,367,023			234,969,329

Interest expense:

On long-term obligations		21,309,900			24,239,343			24,459,852

On short-term obligations		1,669,376			90,648			0

Charged to construction-credit		(446,479	)		(617,194	)		(448,978	)


Net interest expense		22,532,797			23,712,797			24,010,874


Net operating margins		5,178,950			1,364,099			8,562,510

Nonoperating margins:

Interest income		553,362			710,480			879,481

Capital credits, patronage dividends and other		679,438			810,677			597,068


Total nonoperating margins		1,232,800			1,521,157			1,476,549


Assignable margins	$	6,411,750		$	2,885,256		$	10,039,059

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Statements of Changes in Equities and Margins

Years Ended December 31, 2008, 2007 and 2006


	Memberships		Other Equities and Margins		Patronage Capital			Total

Balance, January 1, 2006	$	1,250,398	$	7,603,376	$	136,185,378		$	145,039,152

Assignable margins		0		0		10,039,059			10,039,059
Retirement of capital credits		0		0		(5,106,817	)		(5,106,817	)
Unclaimed capital credit retirements		0		346,821		0			346,821
Memberships and donations received		47,235		350,650		0			397,885


Balance, December 31, 2006		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

See accompanying notes to financial statements.

Chugach Electric Association, Inc.
Statements of Cash Flows
Years Ended December 31, 2008, 2007 and 2006


	2008			2007			2006

Cash flows from operating activities:
Assignable margins	$	6,411,750		$	2,885,256		$	10,039,059

Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation and amortization		35,858,305			32,426,335			31,494,702
Capitalized interest		(559,090	)		(891,443	)		(1,328,459	)
Property (gains) losses, net		2,231			16,748			(13,919	)
Write-off of deferred charges		18,000			4,439			406,239
Investments in associated organizations		(184,390	)		(105,872	)		(108,989	)

Changes in assets and liabilities:
(Increase) decrease in assets:
Accounts receivable		(1,663,891	)		1,544,090			(5,463,293	)
Fuel cost under-recovery		(11,788,078	)		0			1,781,833
Materials and supplies		(384,553	)		(2,997,595	)		(1,614,802	)
Prepayments		(186,046	)		129,986			313,138
Special deposits/other		2,331			98,159			115,889
Deferred charges		(6,640,741	)		(2,773,198	)		(4,873,727	)

Increase (decrease) in liabilities:
Accounts payable		(1,673,495	)		(124,362	)		276,837
Consumer deposits		7,929			185,438			237,328
Fuel cost over-recovery		(1,596,010	)		1,295,443			300,567
Accrued interest		(145,682	)		(59,491	)		3,448
Salaries, wages and benefits		(472,252	)		(67,600	)		647,977
Fuel		6,156,558			6,178,870			(1,964,356	)
Other liabilities		(12,484	)		(1,525,783	)		947,674
Deferred credits		55,070			16,646			(264,655	)

Net cash provided by operating activities		23,205,462			36,236,066			30,932,491

Investing activities:
Extension and replacement of plant		(29,065,107	)		(27,253,296	)		(18,986,067	)

Net cash used in investing activities		(29,065,107	)		(27,253,296	)		(18,986,067	)

Financing activities:
Proceeds from short-term obligations		7,500,000			0			0
Proceeds from long-term obligations		38,560,006			0			0
Repayments of long-term obligations		(35,303,151	)		(9,001,795	)		(8,325,687	)
Memberships and donations received		70,761			76,969			7,413
Retirement of patronage capital and estate payments		(4,027,156	)		(3,273,914	)		(4,241,093	)
Net receipts of consumer advances for construction		340,551			(419,008	)		(192,737	)

Net cash (used in) provided by financing activities		7,141,011			(12,617,748	)		(12,752,104	)

Net changes in cash and cash equivalents		1,281,366			(3,634,978	)		(805,680	)

Cash and cash equivalents at beginning of period	$	6,209,936		$	9,844,914		$	10,650,594

Cash and cash equivalents at end of period	$	7,491,302		$	6,209,936		$	9,844,914


Supplemental disclosure of non-cash investing and financing activities
Retirement of plant (net of salvage)	$	9,027,644		$	9,473,461		$	8,240,458
Notes payable on land	$	2,860,000		$	0		$	0
Extension and replacement of plant included in accounts payable	$	2,656,989		$	2,084,120		$	3,503,009
Non-cash capital credit retirements	$	1,089,142		$	921,649		$	737,293
Patronage capital retired and estate payments included in other current liabilities	$	415,345		$	2,416,552		$	1,322,577

Supplemental disclosure of cash flow information – interest expense paid, excluding amounts capitalized	$	21,536,503		$	23,772,288		$	24,086,565

See accompanying notes to financial statements.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(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 Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).

	SFAS No. 71 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates. The regulatory assets or liabilities are then reduced as the cost or credit is reflected in rates.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(1)	Description of Business and Significant Accounting Policies (continued)

	d. Utility Plant and Depreciation

	Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. For property replaced or retired, the book value of the property, plus removal cost, less salvage, is charged to accumulated provision for depreciation. Renewals and betterments are capitalized, while maintenance and repairs are charged to expense as incurred.

	In accordance with SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS 144), certain utility plant is reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable in rates. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

	Depreciation and amortization rates have been applied on a straight-line basis and at December 31 are as follows:

Annual Depreciation Rate Ranges


	01/01/2005-05/31/2008						06/01/2008-12/31/2008


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	%


	An update to depreciation rates was included in a general rate case filed by Chugach with the RCA on September 29, 2006. 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, 2008 and 2007


(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 5.1% during 2008, 6.3% during 2007 and 6.1% during 2006.

	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%. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment.

	g. Fair Value of Financial Instruments

	SFAS No. 107, Disclosures About the Fair Value of Financial Instruments, 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, 2008 and 2007


(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 2008 and 2007 of $3,725,224 and $8,179,484, at an average interest rate of 1.43% and 3.13%, respectively.

	i. Accounts Receivable

	Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers.

	j. Materials and Supplies

	Materials and supplies are stated at average cost.

	k. Deferred Charges and Credits

	In accordance with SFAS No. 71, Chugach’s financial statements reflect regulatory assets and liabilities. Continued accounting under SFAS No. 71 requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for rate making purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria. However, if events or circumstances should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on the financial position and results of operations. Deferred charges, 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, 2008 and 2007


(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 $10,024,312 and $8,300,461of unbilled retail revenue at December 31, 2008 and 2007, respectively. Wholesale revenue is recorded from metered locations on a calendar month basis, so no accrual is made. Chugach’s tariffs include provisions for the flow through of gas costs according to existing gas supply contracts, as well as purchased power costs.

	n. Fuel and Purchased Power Costs

	Expenses associated with electric services include fuel used to generate electricity and power purchased from others. Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel surcharge process, which is adjusted quarterly to reflect increases and decreases of such costs. Revenues are adjusted for differences between projected recoverable fuel costs and amounts actually recovered through rates. Fuel costs were under-recovered by $11,788,078 in 2008 and over-recovered by $1,596,010 in 2007. Total fuel and purchased power costs in 2008, 2007, and 2006 were $169,381,174, $139,971,562, and $146,260,428, respectively.

	o. Environmental Remediation Costs

	Chugach accrues for losses and establishes a liability associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. Estimates of future costs for environmental remediation obligations are not discounted to their present value. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(1)	Description of Business and Significant Accounting Policies (continued)

	p. Income Taxes

	Chugach is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code and for the years ended December 31, 2008, 2007 and 2006 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 Emerging Issues Task Force (EITF) No. 06-3 “How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement.”

	q. Recently Issued Accounting Pronouncements

	SFAS No. 141R “Business Combinations”

	In December 2007, the Financial Accounting Standards Board (FASB) issued SFAS No. 141R, “Business Combinations.” SFAS No. 141R replaces FASB Statement No. 141, “Business Combinations.” This statement retains the requirements in SFAS No. 141 that the acquisition method of accounting be used and for an acquirer to be identified for each business combination. This statement defines the acquirer and establishes the acquisition date. This statement applies only to business combinations in which control was obtained by transferring consideration. By applying the same method, this statement improves the comparability of the information about business combinations provided in financial reports. This statement applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. An entity may not apply it before that date. Chugach will begin application of SFAS No. 141R on January 1, 2009, and it does not expect to have a material affect on our results of operations, financial position, and cash flows.

	SFAS No. 161 “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133”

	In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” SFAS No. 161 changes the disclosure requirements for derivative instruments and hedging activities. SFAS No. 161 is effective for financial statements issued for fiscal years beginning after November 15, 2008. Chugach will begin application of SFAS No. 161 on January 1, 2009, and does not expect it to have a material effect on our results of operations, financial position, and cash flows.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(1)	Description of Business and Significant Accounting Policies (continued)

	q. Recently Issued Accounting Pronouncements (continued)

	FSP FAS No. 157-2 “Effective Date of FASB Statement No. 157”

	In February 2008, the FASB issued FSP FAS No. 157-2, “Effective Date of FASB Statement No. 157.” FSP FAS No. 157-2 deferred the effective date of applying SFAS No. 157 to nonfinancial assets and nonfinancial liabilities, from financial statements issued for fiscal years beginning after November 15, 2007, to fiscal years beginning after November 15, 2008. FSP FAS No. 157-2 is effective upon issuance. Chugach will begin application of SFAS No. 157 to nonfinancial assets and nonfinancial liabilities on January 1, 2009, which is not expected to have a material effect on our results of operations, financial position, and cash flows.

	FSP FAS No. 142-3 “Determination of the Useful Life of Intangible Assets”

	In April 2008, the FASB issued FSP FAS No. 142-3, “Determination of the Useful Life of Intangible Assets.” FSP FAS No. 142-3 amends SFAS No. 142, “Goodwill and Other Intangible Assets,” to define the factors to be considered in developing the renewal or extension assumptions used to determine the useful life of the recognized intangible assets under SFAS No. 142. SFAS No. 142 is effective for financial statements issued for fiscal years beginning after December 15, 2008, and early adoption is prohibited. Chugach will begin application FSP FAS No. 142-3 to intangible assets on January 1, 2009, which is not expected to have a material effect on our results of operations, financial position, and cash flows.

	EITF No. 08-5 “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement”

	In September 2008, the FASB’s EITF ratified EITF No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement.” EITF No. 08-5 establishes how to treat the debt issued with a third-party credit enhancement that is inseparable from the debt instrument. In September 2008, the FASB’s EITF reached a consensus to change the effective date of EITF No. 08-5 to be effective on a prospective basis for the first reporting period beginning on or after December 15, 2008. The FASB ratified this consensus at its September 24, 2008 meeting. Therefore, Chugach will begin application of EITF No. 08-5 on January 1, 2009, which is not expected to have a material effect on our results of operations, financial position, and cash flows.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(1)	Description of Business and Significant Accounting Policies (continued)

	r. Fair Values of Assets and Liabilities

	On January 1, 2008, Chugach adopted the provisions of SFAS No. 157, Fair Value Measurements. SFAS No. 157 defines fair value, establishes a consistent framework for measuring fair value and expands disclosure requirements for fair value measurements.

	Fair Value Hierarchy

	In accordance with SFAS No. 157 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
$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.

(2)	Regulatory Matters

	*Revision to Current Depreciation Rates (Docket No. U-04-102)*

	Chugach implemented new depreciation rates effective January 1, 2004, based on an update of the 1999 Depreciation Study utilizing Electric Plant in Service balances as of December 31, 2002. The 2002 Depreciation Study was submitted to the RCA for approval on November 19, 2004. On March 9, 2005, the RCA ruled in Order No. 2 that depreciation rates may not be implemented without prior approval of the RCA.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(2)	Regulatory Matters (continued)

	*Revision to Current Depreciation Rates (Docket No. U-04-102)(continued)*

	In Order No. 9 dated January 10, 2006, the RCA ruled substantially in Chugach’s favor by approving the 2002 Depreciation Study with certain changes to the proposed depreciation rates. The main effect of this decision was to allow Chugach to revise its depreciation rates effective January 1, 2005. Because Chugach did not request changes to the electric rates charged to our customers based on the proposed new depreciation rates, there was no immediate electric rate impact.

	Wholesale customers MEA and HEA were active in the proceeding. Subsequently, MEA and HEA filed an appeal of the RCA’s decision in Superior Court, see “Footnote 5, Legal Proceedings – Matanuska Electric Association, Inc. (MEA) v. State of Alaska, Regulatory Commission of Alaska, Superior Court Case No. 3AN-06-8243 Civil.” HEA later dismissed its appeal leaving MEA’s claim focusing mainly on the question of whether implementation of the new depreciation rates as of January 1, 2005 constituted illegal retroactive rate making. Oral argument before the Superior Court was held on July 15, 2008. On July 21, 2008, the Court issued a decision affirming the RCA’s January 10, 2006 decision.

	*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. In this Order, the RCA approved the rates from the Settlement Agreement among Chugach, HEA and Seward that it had previously accepted. MEA did not join the Settlement Agreement and this Order addressed the issues that it had raised. The effect of Order 21 is that overall revenues will decrease by 0.8%, or $0.9 million, with retail base rate revenue decreasing by 4.8%, or $4.2 million and wholesale base rate revenue increasing by 11.0%, or $3.3 million. Order No. 21 was effective June 1, 2008.

	On April 21, 2008, Chugach filed a Petition for Reconsideration of Order 21. Chugach asked the RCA to reconsider its decisions regarding the allocation of long-term debt and interest expense and the requirement for specific scenarios in Chugach’s Financial Management Plan (FMP). Chugach also proposed corrections to the RCA calculation of the debt allocator it ordered. No other parties filed for reconsideration of the order.

	On May 21, 2008, the RCA issued Order No. 22. The RCA revised the long-term debt allocator from 67.12% to 68.46%. This finding increased MEA’s revenue requirement to Chugach by $107,818. The RCA reaffirmed its requirement for FMP scenarios.

	On May 30, 2008, the RCA issued Order No. 23, accepting Chugach’s compliance filing and approving tariff sheets that incorporate the RCA’s findings in Order No. 22.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(2)	Regulatory Matters (continued)

	*2005 Test Year General Rate Case (Docket U-06-134) (continued)*

	On June 4, 2008, MEA filed a Petition for Reconsideration of Order No. 23, expressing several concerns about Chugach’s computation of depreciation expenses.

	On September 16, the RCA issued Order No. 24. The RCA reviewed comments submitted by MEA, however, the RCA found that depreciation calculations by Chugach were reasonable.

	On October 1, Chugach submitted three Financial Management Plan scenarios to the Commission in compliance with Order No. 21 in U-06-134. The three scenarios contained in the filing were: Scenario 1: Wholesale relationships continue into the future; Scenario 2: Firm wholesale relationships terminate and are replaced with interruptible sales; and, Scenario 3: Firm wholesale relationships terminate and are not replaced with interruptible sales. On November 7, 2008, the RCA issued Order No. 25, accepting Chugach’s Financial Management Plan as filed and closing docket U-06-134.

(3)	Utility Plant

	Major classes of utility plant as of December 31 are as follows:


	2008		2007


Electric plant in service:

Steam production plant	$	60,462,671	$	60,462,671

Hydraulic production plant		19,597,661		20,262,890

Other production plant		137,480,817		133,235,755

Transmission plant		247,685,063		245,914,683

Distribution plant		242,489,152		230,074,513

General plant		46,634,280		47,962,159

Unclassified electric plant in service¹		60,348,939		60,954,644

Other		6,763,892		6,763,892


Total electric plant in service		821,462,475		805,631,207

Construction work in progress		25,151,072		17,712,884


Total electric plant in service and construction work in progress	$	846,613,547	$	823,344,091


¹ Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant. Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(4)	Investments in Associated Organizations

	Investments in associated organizations include the following at December 31:


	2008		2007


National Rural Utilities Cooperative Finance Corporation	$	6,095,980	$	6,095,980

CoBank, ACB		6,022,743		5,841,631

NRUCFC capital term certificates		42,196		39,708

Other		16,850		16,059


Total Investments in Associated Organizations	$	12,177,769	$	11,993,378


	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:


	2008		2007


Debt issuance and reacquisition costs	$	5,254,072	$	6,215,899

Refurbishment of transmission equipment		179,013		188,272

Studies		15,194		729,392

Beluga Gas Compression		4,918,909		5,441,205

Cooper Lake Relicensing / projects		5,857,388		5,919,899

Fuel supply negotiations		1,257,993		225,076

Major overhaul of steam generating unit		4,530,550		787,711

Other regulatory deferred charges		177,103		313,183

Environmental matters and other		1,386,977		1,432,328


Total deferred charges	$	23,577,199	$	21,252,965

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(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, 2008 and 2007:


	2008		2007


Fuel supply negotiations	$	1,092,828	$	37,195

Studies		15,194		729,392

Beluga Gas Compression		0		5,441,205

Cooper Lake Relicensing		5,857,388		5,919,899

Other regulatory deferred charges		177,103		313,183

Debt issuance costs		626,628		0


Total deferred charges	$	7,769,141	$	12,440,874


	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:


	2008		2007


Refundable consumer advances for construction	$	1,545,081	$	1,204,530

Estimated initial installation costs for meters		141,712		121,342

Post retirement benefit obligation		593,600		558,900

Other		21,591		21,591


Total deferred credits	$	2,301,984	$	1,906,363

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(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, 2008, Chugach had $142,009,998 of patronage capital (net of capital credits retired in 2008), which included $135,598,248 of patronage capital that had been assigned and $6,411,750 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% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins.

	Capital credits retired were $3,115,090, $5,289,538, and $5,106,817 for the years ended December 31, 2008, 2007, and 2006, respectively. The outstanding liability for capital credits authorized but not paid was $415,345 and $2,416,552 at December 31, 2008 and 2007, respectively.

	Following is a five-year summary of anticipated capital credit retirements:


Years ending December 31	Total


2009	$	3,300,000

2010	$	0

2011	$	0

2012	$	0

2013	$	0


	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.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(7)	Other Equities

	A summary of other equities at December 31 follows:


	2008		2007


Nonoperating margins, prior to 1967	$	23,625	$	23,625

Donated capital		1,300,277		1,148,907

Unclaimed capital credit retirement¹		9,042,686		8,079,553


Total other equities	$	10,366,588	$	9,252,085


¹ Represents unclaimed capital credits that have met all requirements of section 34.45.200 of Alaska’s unclaimed property law and has therefore reverted to Chugach.


(8)	Debt

Long-term obligations at December 31 are as follows:


	2008		2007

CoBank 2, 5.50% fixed rate note maturing in 2010, with interest and principal payable monthly; unsecured	$	3,500,000	$	5,500,000

CoBank 3 and 4, 2.27% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003; unsecured		38,462,805		39,803,530

CoBank 5, 2.27% variable rate note maturing in 2012, with interest and principal payable monthly; unsecured		3,860,695		4,726,774

2001 Series A Bond of 6.55%, maturing in 2011, with interest payable semi-annually March 15 and September 15; unsecured		150,000,000		150,000,000

2002 Series A Bond of 6.20%, maturing in 2012, with interest payable semi-annually February 1 and August 1; unsecured		120,000,000		120,000,000

2002 Series B Bond of a rate set for 28-day auction periods, with interest payable monthly and principal due annually, redeemed in 2008; unsecured		0		35,500,000

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		42,963,659		0

Total long-term obligations	$	358,787,159	$	355,530,304

Less current installments		4,403,653		10,106,804


Long-term obligations, excluding current installments	$	354,383,506	$	345,423,500

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(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, 2008 and 2007


(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% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins.

	Maturities of Long-term Obligations

	Long-term obligations at December 31, 2008, 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


2009		0		0		4,403,653		4,403,653

2010		0		0		47,081,687		47,081,687

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

Thereafter		0		0		29,680,420		29,680,420


	$	150,000,000	$	120,000,000	$	88,787,159	$	358,787,159

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(8)	Debt (continued)

	Lines of credit

	Chugach maintains a $7.5 million line of credit with CoBank. On October 22, 2008, the Board of Directors approved a resolution to renew this line of credit. The line of credit was also renewed by CoBank, extending the expiration date to October 31, 2009, and is subject to annual renewal at the discretion of the parties. Chugach utilized this line of credit in the first quarter of 2008 and had $5.5 million outstanding at March 31, 2008. In April and May of 2008, Chugach had additional line of credit activity, however, in June of 2008, Chugach paid off the outstanding balance. In August and September of 2008 Chugach borrowed $7.5 million on this line of credit, which represented the balance at December 31, 2008. At December 31, 2007, there was no outstanding balance on this line of credit. The CoBank Master Loan Agreement requires Chugach to establish and collect electric rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense, to achieve a funded debt to operating cash flow ratio not greater than 8 to 1 and achieve an equity to total capitalization ratio greater than 22%. The borrowing rate is calculated using the CoBank Base Rate on the first business day of the week plus 3%. The average borrowing rate for 2008 and 2007 was 3.82% and 6.47%, 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, described further in Note 8, could be met. On December 22, 2008, this line of credit was increased to $75 million, which represented the borrowing limit at December 31, 2008, however, pursuant to the terms of the Amendment To Revolving Line of Credit Agreement with NRUCFC, this line of credit shall be permanently reduced to $50 million upon the earlier of January 1, 2010 or the date Chugach pays down this line of credit to an outstanding balance of not more than $50 million. 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. The borrowing rate at December 31, 2008, on this transaction was 2.75%. Chugach utilized this line of credit in the fourth quarter of 2008 and had a balance of $43.0 million at December 31, 2008. Chugach did not utilize this line of credit in 2007 so there was no outstanding balance at December 31, 2007. The borrowing rate 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. At December 31, 2008 and 2007, the borrowing rate was 5.00% and 6.40%, respectively. The NRUCFC Revolving Line Of Credit Agreement requires that Chugach, for each 12-month period, for a period of at least five consecutive days, pay down the entire outstanding principal balance. The NRUCFC line of credit expires October 14, 2012. Repayment of this line of credit is due on January 1, 2010, and is therefore classified as long-term. Chugach repaid this line using its Commercial Paper program, see Note 15 – “Subsequent Events.”

	The CoBank and NRUCFC lines of credit are immediately available for unconditional borrowing.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(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 is due no later than March 15, 2009, and the final payment of $1,860,000 plus accrued interest is due no later than June 30, 2009. Chugach has the right to prepay any amount of the note in full at any time without penalty. The promissory note is secured by a deed of trust on the property.

	Financing

	Over the next five years Chugach anticipates incurring significant amounts of capital expenditures due to the construction of a gas fired generation unit, on-going capital needs and refinancing of certain existing debt. In March of 2008 we issued a Request For Proposal (RFP) for a three to five year interim finance facility. Commercial paper will be issued under this requested facility and will act as a bridge until Chugach converts Commercial Paper balances to long term debt in 2010 and to refinance the 2011 and 2012 Series A bonds. A recommendation to adopt a proposed financing plan was approved by the Board of Directors on June 25, 2008. The commercial paper program is backed by a $300 million Unsecured Credit Agreement between NRUCFC, KeyBank, CoBank and US Bank. At closing, 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 was executed on October 10, 2008, and expires on October 10, 2011. Chugach began issuing short term Commercial Paper in the first quarter of 2009, see Note 15 – “Subsequent Events”.

	2002 Series B Bonds

	The 2002 Series B Bonds (the “Auction Rate Bonds”) had a maturity date of February 1, 2012. The applicable interest rate for any 28-day auction period was the term rate established by the auction agent based on the terms of the auction. The Auction Rate Bonds could have been converted, in Chugach’s discretion, to a daily, seven-day, 35-day, three-month or a semi-annual period or a flexible auction period. The Auction Rate Bonds were not subject to redemption at the option of the bondholders under any circumstances. Chugach could elect to redeem the bonds and was required to redeem the bonds in pre-established incremental amounts over time through a sinking fund. The Auction Rate Bonds were subject to a remarketing agreement on a best efforts basis, however in the event of unsuccessful remarketing, the bonds would be returned to the bondholders and would continue as auction rate bonds subject to a maximum auction rate (15%). Under no circumstances would Chugach have been obligated to pay off the Bonds in the event of an unsuccessful remarketing effort. Chugach had not provided any protection to the bondholders in the event of an unsuccessful remarketing, therefore, Chugach had classified the Bonds as long-term, with the exception of the mandatory sinking fund payment. The average interest rate for the Bonds in 2008, 2007, and 2006 was 4.87%, 5.34%, and 5.07%, respectively.

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(8)	Debt (continued)

	2002 Series B Bonds (continued)

	Certain events affecting bond insurers, including Chugach’s bond insurer, MBIA, had injected some level of uncertainty regarding the success of the auction process. By the terms of the auction securities agreement, should an attempt to reset the interest rate on Chugach’s auction rate bonds fail because there was insufficient bids to establish a market-based price, the interest rate on Chugach’s 2002 Series B Bonds would have been set utilizing an “Auction Mode Multiple” as defined in Exhibit A to Appendix 2 to Eleventh Supplemental Indenture (Auction Procedures Description).

	The “Auction Mode Multiple” as of any Auction Date was a percentage of the Index in effect on such auction date (in Chugach’s case, a percentage of the one month LIBOR). That percentage was based on the Prevailing Rating of the 2002 Series B Bonds in effect at the close of business on the Business Day immediately preceding the Auction Date.

	In Chugach’s case, the Auction Mode Multiple was based on MBIA’s AAA rating and would have been 150% of one-month LIBOR. That rate would have stayed in effect for 28 days, followed by another auction. On February 20, 2008, the auction was held and failed to obtain sufficient clearing bids. Therefore, the current bondholders continued to hold the bonds and the rate on the 2002 Series B Bonds was set at 4.677% and stayed in effect until March 20, 2008. The failure of the auction did not constitute an event of default under any financing arrangement.

	On March 5, 2008, bondholders were notified of the intent of Chugach to redeem the entire outstanding principal amount of the 2002 Series B Bonds. The Board of Directors authorized the redemption using funds obtained from one or more new borrowings under Chugach’s existing lines of credit with CoBank or NRUCFC.

	On March 20, 2008, Chugach redeemed the $29.6 million outstanding principal amount of the 2002 Series B Bonds using our NRUCFC line of credit at an initial rate of 3.46%. Repayment of the NRUCFC line of credit is due on January 1, 2010. Accordingly, outstanding borrowings continue to be classified as long-term. Management intends to repay this line using its Commercial Paper program described earlier in this note and is currently monitoring the commercial paper market.

	The following table provides information regarding auction dates and rates:


Auction Date		Interest Rate

January 23, 2008		5.06%
February 20, 2008		4.68%

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(9)	Fair Value of Long-Term Obligations

	The estimated fair values (in thousands) of the long-term obligations included in the financial statements at December 31 are as follows:


	2008					2007


	Carrying Value			Fair Value		Carrying Value			Fair Value


Long-term obligations (including current installments)		$	358,787	$	371,213		$	355,530	$	371,868


	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.

(10)	Employee Benefit Plans

	Pension Plans

	Pension benefits for substantially all union employees are provided through the Alaska Electrical Pension Trust Fund and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund, multi-employer plans. Chugach pays an hourly amount per eligible union employee pursuant to the collective bargaining unit agreements. In these master, multi-employer plans, the accumulated benefits and plan assets are not determined or allocated separately to the individual employer.

	The costs for the union plans were approximately $2.9 million, $2.9 million, and $2.5 million in 2008, 2007, and 2006, respectively. Chugach has no responsibility for any unfunded benefit obligation of the Plan at this time.

	Pension benefits for non-union employees are provided by the National Rural Electric Cooperative Association (NRECA) Retirement and Security Program, a multi-employer plan. Chugach makes annual contributions to the pension plan equal to the amounts accrued for pension expense. Chugach contributed $1.8 million, $1.9 million, and $1.6 million in 2008, 2007, and 2006, respectively, to the NRECA plan. Chugach has no responsibility for any unfunded benefit obligation of the Plan at this time.

	Health and Welfare Plans

	Health and welfare benefits for union employees are provided through the Alaska Electrical Health and Welfare Trust and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund. Chugach participates in multi-employer plans that provide substantially all union workers with health care and other welfare benefits during their employment with Chugach. Chugach pays a defined amount per union employee pursuant to collective bargaining unit agreements. Amounts charged to benefit costs and contributed to the


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007

(10)	Employee Benefit Plans (continued)

	Health and Welfare Plans (continued)

	health and welfare plans for these benefits for the years ending December 31, 2008, 2007, and 2006 were $3.5 million, $3.3 million, and $2.9 million respectively.

	Chugach participates in a multi-employer plan through the Group Benefits Program of NRECA for non-union employees. Amounts charged to benefit cost and contributed to this Plan for those benefits for the years ended December 31, 2008, 2007, and 2006 totaled $1.9 million, $1.9 million, and $2.0 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, 2008, 2007, and 2006 were $91.8 thousand, $142.1 thousand, and $85.4 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 $15,500, $15,500, and $15,000 in 2008, 2007, and 2006 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, 2008, 2007 and 2006 was $264,427, $768,041 and $645,582, respectively.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007

(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 (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% share of the project’s capacity. The share of debt service exclusive of interest, for which Chugach has guaranteed, is approximately $36 million. The share of annual interest expense on that debt service is approximately $3.6 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%. Upon default, Chugach could be faced with annual expenditures of approximately $5.1 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, 2008 (the most recent date for which information is available). Chugach’s share of expenses was $4,746,965 in 2008, $4,816,790 in 2007, and $4,219,321 in 2006 and is included in purchased power in the accompanying financial statements.


			Proportionate

(In thousands)	Total		Share


Plant in service	$	203,226	$	61,781

Long-term debt		112,454		34,186

Interest expense		7,577		2,303


	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, 2008 and 2007

(12)	Eklutna Hydroelectric Project

	During October 1997, the ownership of the Eklutna Hydroelectric Project formally transferred from the Alaska Power Administration to the participating utilities. This group, including their corresponding interest in the project, consists of Chugach (30%), MEA (16.7%) and Anchorage Municipal Light & Power (AML&P) (53.3%).

	Plant in service in 2008 includes $2,476,755, net of accumulated depreciation of $816,606, which represents Chugach’s share of the Eklutna Hydroelectric Plant. In 2007 plant in service included $2,540,275, net of accumulated depreciation of $719,186. 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 $886,261, $712,552, and $638,465 in 2008, 2007, and 2006, respectively and is included in power production and depreciation in the accompanying financial statements. Chugach provides personnel for the daily operation and maintenance of the power plant. AML&P performs major maintenance at the plant. Chugach personnel perform daily plant inspections, meter reading, monthly report preparation, and other activities as required.

(13)	Commitments, Contingencies and Concentrations

	Contingencies

	Chugach is a participant in various legal actions, rate disputes, personnel matters and claims both for and against Chugach’s interests. Management believes the outcome of any such matters will not materially impact Chugach’s financial condition, results of operations or liquidity.

	Long-Term Fuel Supply Contracts

	Chugach has 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 by mid 2010. The 180 BCF commitment for the 2025 contracts is expected to run out in early 2011. Chugach is currently working with Cook Inlet producers on future natural gas supply contracts. A gas term sheet was approved by Chugach’s Board of Directors on February 25, 2009. In 2008, 91% of our power was generated from gas, compared to 93% and 90% in 2007 and 2006 respectively. 76% of the gas-fired power was generated at Chugach’s Beluga Power Plant compared with 85% in 2007 and 87% in 2006.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007

(13)	Commitments, Contingencies and Concentrations (continued)

	Long-Term Fuel Supply Contracts (continued)

	Fuel is purchased directly from Marathon Oil Company, ChevronTexaco, AML&P and ConocoPhillips. The following represents the cost of fuel purchased from these vendors as a percentage of total fuel costs for the years ended December 31:


	2008	2007	2006


Marathon Oil Company	49.7%	46.4%	49.2%
Chevron Texaco	19.1%	20.4%	19.4%
Anchorage Municipal Light & Power (AML&P)	15.4%	16.1%	15.7%
ConocoPhillips	15.8%	16.9%	15.7%


	Concentrations

	Approximately 70% of Chugach’s employees are represented by the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW which expire on June 30, 2010.

	Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts represented $104.6 million or 37% of sales revenue in 2008, $93.4 million or 37% in 2007, and $90.1 million or 34% in 2006. The HEA contract expires January 1, 2014, and the MEA contract expires December 31, 2014. All rates are established by the RCA.

	Legal Proceedings

	Matanuska Electric Association, Inc. (MEA) v. State of Alaska, Regulatory Commission of Alaska, Superior Court Case No. 3AN-06-8243 Civil

	On May 17, 2006, MEA appealed and on May 30, 2006, HEA cross appealed the RCA’s decision in Docket No. U-04-102, see “Footnote 3, Regulatory Matters – Revision to Current Depreciation Rates (Docket No. U-04-102).” On appeal, MEA claimed the RCA’s decision dated January 10, 2006, to authorize Chugach to implement new depreciation rates as of January 1, 2005, constituted illegal retroactive rate making. MEA further contended that the RCA’s reliance on avoidance of regulatory lag as a basis for its decision was improper. MEA also challenged certain of the RCA’s discovery rulings. Chugach joined the State of Alaska in defending the RCA’s rulings. HEA stipulated with the other parties to dismiss its cross appeal which the Court granted by order dated September 11, 2007. Oral argument was held on July 15, 2008, and on July 21, 2008, the Court issued a decision affirming the RCA’s January 10, 2006 decision. The time for MEA to appeal the Superior Court’s decision to the Alaska Supreme Court has now expired.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007

(13)	Commitments, Contingencies and Concentrations (continued)

	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 $0.000362, effective July 1, 2008. The tax is reported on a net basis and the tax is not included in revenue or expense.

	Sales Tax

	Chugach collects sales tax on retail electricity sold to Kenai and Whittier consumers. The tax is collected monthly and remitted to the Kenai Peninsula Borough quarterly. Sales tax is reported on a net basis and the tax is not included in revenue or expense.

	Gross Receipts Tax

	Chugach pays to the State of Alaska a gross receipts tax in lieu of state and local ad valorem, income and excise taxes on electricity sold in the retail market. The tax is accrued monthly and remitted annually. The tax is reported on a net basis and the tax is not included in revenue.

	Excise taxes

	Excise taxes on Chugach fuel purchases are paid directly to our gas producers and are recorded under “Fuel” in Chugach’s financial statements and are not directly passed through to our consumers.

	Underground Compliance Charge

	In 2005 the Anchorage Municipal Assembly adopted an ordinance to require utilities to convert overhead distribution lines to underground. To comply with the ordinance, Chugach must invest two percent of gross retail revenue in the Municipality of Anchorage annually in moving existing distribution overhead lines underground. Consistent with State of Alaska undergrounding requirement, Chugach is permitted to amend its rates by adding a 2% surcharge to its retail members’ bills to recover the actual costs of the program. The rate amendments are not subject to RCA review or approval. Chugach implemented the surcharge in June 2005. Chugach’s liability was $468,173 and $571,530 for this surcharge at December 31, 2008 and December 31, 2007, respectively and will use the funds to offset the costs of the projects.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007

(13)	Commitments, Contingencies and Concentrations (continued)

	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 that may be established to address problems such as global warming. While we cannot predict whether any new regulation would occur or its limitation, it is possible that new laws or regulations could increase our capital and operating costs. We have obtained or applied for all Clean Air Act permits currently required for the operation of our generating facilities.

	In March 2007, Chugach conducted emissions testing at the Bernice Lake Power Plant which indicated that two of the gas turbines at the facility were exceeding the New Source Performance Standards (NSPS) emission limit for nitrogen oxides (NOx). Chugach voluntarily limited the power output of these turbines to ensure interim compliance with the NSPS regulations 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 Conservation (ADEC) issued a Notice of Violation (NOV) on March 26, 2008 regarding the NSPS NOx emission limit exceedances. Chugach has entered into a settlement with ADEC regarding the NOV for the past NSPS non-compliance. As part of the settlement, Chugach has agreed to pay a civil penalty of $112,161 to ADEC. We are currently in the process of resolving the final details of the settlement agreement and anticipate a conclusion in the first quarter of 2009.

	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.


Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007

(13)	Commitments, Contingencies and Concentrations (continued)

	Generation Commitments

	Chugach is in the process of developing a gas-fired generation plant on land currently owned by Chugach near its Anchorage headquarters. The generation plant will be developed jointly with AML&P. 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). In December of 2008, Chugach purchased land adjacent to its Anchorage headquarters. This land will be used as a project laydown area and to relocate materials and equipment previously located on the site of the new power plant. Chugach is currently preparing purchase documentation for engineering, procurement and construction services to be awarded in 2009.

	Chugach made a payment of $5.1 million in 2008 and will make progress and milestone payments of $23.5 million and $22.8 million in 2009 and 2010, respectively, pursuant to its purchase agreement with GEPP.

(14)	Quarterly Results of Operations (unaudited)


	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


	2007 Quarter Ended


	Dec. 31		Sept. 30			June 30			March 31


Operating Revenue	$	69,809,448	$	57,053,772		$	59,127,575		$	71,453,124
Operating Expense		62,808,159		53,280,744			55,162,909			61,115,211
Net Interest		5,770,903		5,960,305			5,962,574			6,019,015

Net Operating Margins		1,230,386		(2,187,277	)		(1,997,908	)		4,318,898
Non-Operating Margins		766,720		250,880			233,637			269,920


Assignable Margins	$	1,997,106	$	(1,936,397	)	$	(1,764,271	)	$	4,588,818

Chugach Electric Association, Inc.
Notes to Financial Statements
December 31, 2008 and 2007


(15)	Subsequent Events


	Commercial Paper

	Over the next five years Chugach anticipates incurring significant 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 will be issued to act as a bridge until Chugach converts Commercial Paper balances to long term debt in 2010 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. 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


	Lines of credit

	NRUCFC

	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. 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 shall be permanently reduced to $50 million upon the earlier of January 1, 2010 or the date Chugach pays down this line of credit to an outstanding balance of not more than $50 million. In January of 2009 Chugach had additional line of credit activity and had a balance of $38 million on January 30, 2009, when we repaid $30.0 million on this line of credit by issuing commercial paper under our Commercial Paper program. Consequently, effective January 30, 2009, Chugach’s borrowing limit on its NRUCFC line of credit was permanently reduced to $50 million. In February of 2009 Chugach repaid the remaining balance on this line of credit by issuing commercial paper.

	CoBank

	On February 27, 2009, Chugach repaid $4.5 million and on March 3, 2009, Chugach repaid the $3.0 million balance on its CoBank line of credit.

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 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, 2008, 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, 2008, 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. No member of the Board is an employee of the company nor does any member of the Board have a material relationship with the company. Therefore, the Chugach Board has determined that all members are independent.

Identification of Directors

Rebecca Logan, 45, 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. She also serves as Chugach’s Alaska Power Association Resolutions/Government Affairs representative.

Jim Nordlund, 56, Vice Chairman, is 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 as chair of the Operations Committee and is Chugach’s Alaska Power Association representative. He is a National Rural Electric Cooperative Credentialed Cooperative Director.

Alex Gimarc, 57, 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. He is also Chugach’s Joint Action Agency representative.

P.J. Hill, 64, 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.

Jeff Lipscomb, 57, Director, is a project management consultant with JWL Engineering. He was elected to the board in 2000 and re-elected in 2003 and 2006. Lipscomb currently serves on the board’s Finance and Audit committees. He also serves on Northwest Public Power Association’s board of trustees and is a National Rural Electric Cooperative Association Credentialed Cooperative Director.

Janet Reiser, 53, 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 serves on the Operations Committee and is board liaison to the Renewable Energy Committee.

Elizabeth Vazquez, 57, 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. Vazquez also serves on the board’s Operations, Finance and Audit committees. She is a National Rural Electric Cooperative Association Credentialed Cooperative Director and has earned her Board Leadership Certificate.

Identification of Executive Officers

�� Bradley W. Evans, 54, 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, 59, 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 Jenkin, 48, 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 Risse, 54, 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, 62, 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, 53, 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, 43, 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 developed a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer and any person performing similar functions. The code of ethics was finalized June 16, 2004. It is also posted on Chugach’s website at www.chugachelectric.com.

Nominating Committee

Chugach has not made any material changes to the procedures by which our membership may recommend nominees to our Board of Directors.

Audit Committee Financial Expert

Chugach is a cooperative and each Board member must be a member of the cooperative. The Board relies on the advice of all members of the Finance and Audit Committees, therefore the Board has not formally designated an Audit Committee financial expert.

Identification of the Audit Committee

Chugach Board Policy No. 127, “Audit Committee Charter,” defines the Audit Committee as follows:


	The Audit Committee shall be comprised of three or more directors as determined by the Board. Unless otherwise determined by the Board, the members of the Board Finance Committee shall be the members of the Audit Committee. Committee members may enhance their familiarity with finance and accounting by participating in educational programs conducted by the Association or an outside consultant or other programs. The Committee may also retain the services of a qualified accounting professional with auditing expertise to assist it in the performance of its responsibilities.

The Board shall appoint members of the Committee. Unless a Chair is designated by the Board, the members of the Committee may appoint their own Chair by majority vote. Members of the 2009 Audit Committee include Chair P.J. Hill and Directors Alex Gimarc, Jeffrey Lipscomb, Rebecca Logan, and Elizabeth Vazquez.

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, National Rural Electric Cooperative Association (NRECA) developed the COMPensate wage and salary plan to provide its members with a systematic and standardized method to evaluate jobs in their specific cooperative, grade them, compare wages and salaries with those in similar electric utility systems and in the external marketplace and then create and apply statistically determined, equitable pay scales. In 1988, the Chugach Board approved implementation of NRECA’s COMPensate wage and salary plan for non-bargaining unit employees with the objective of establishing wages and salaries for non-bargaining unit

employees that would attract and retain qualified personnel and encourage their superior performance, growth and development.

Each year the regression analysis/compensation model is updated with current salary survey values to insure that the ranges reflect fair market value. The overall change to the salary ranges reflects market changes to the midpoint of the salary ranges and creates an opportunity for but not a guarantee of salary increases. Salary increases are not automatic and are based on performance. Salary increases are awarded to non-represented employees based on individual performance and their compa-ratio. The compa-ratio indicates where an individual’s annual salary is in relationship to the mid-point of their salary grade. The mid-point represents the market value of the individual position. Any changes to the COMPensate wage and salary plan for Chugach are approved by the Chugach Board.

CEO Brad Evans will be eligible for performance based bonuses at the discretion of the Board of Directors based on performance standards to be determined by the Board. The Board is in the process of determining those performance standards. CEO Brad Evans’ Memorandum of Agreement provided for a one time bonus of $10,000 plus tax gross up (Ref. Exhibit 10.57).

In 2008 the Board of Directors reviewed the interim performance of the CEO on a variety of categories which included health, safety and environment, organization management and planning, leadership and vision, board relations and communication, electric system operations, member/community relations, financial management and performance and employee relations. Each category had a performance percentage between one and five percent. The review provided for a possible bonus maximum of 45% of the CEO’s compensation. Based on this review, the CEO received a discretionary bonus of 21% of his current salary based on seven months or $16,230, which was net of tax withholdings of $6,264.

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 2008 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,	2008	$	224,218	$	16,230		$	55,256		$	7,873	$	303,577
Chief Executive Officer	2007	$	155,028	$	10,000		$	43,043		$	6,070	$	214,141
	2006	$	150,145	$	0		$	37,674		$	1,107	$	188,926

Michael R. Cunningham,	2008	$	166,468	$	3,000		$	147,412		$	13,438	$	330,318
Chief Financial Officer	2007	$	157,819	$	0		$	121,763		$	16,798	$	296,380
	2006	$	145,745	$	0		$	111,532		$	10,084	$	267,361

Tyler Andrews,	2008	$	103,276	$	2,000		N/A			$	1,295	$	106,571
Vice President,	2007	$	0	$	0		N/A			$	0	$	0
Human Resources	2006	$	0	$	0		N/A			$	0	$	0

Edward Jenkin,	2008	$	153,249	$	0		$	64,145		$	721	$	218,115
Vice President,	2007	$	129,358	$	0		$	44,781		$	587	$	174,726
Power Delivery	2006	$	124,957	$	0		$	42,710		$	12,587	$	180,254

Paul Risse,	2008	$	155,791	$	3,000		$	54,445		$	2,554	$	215,790
Sr. Vice President,	2007	$	121,279	$	2,000		$	41,415		$	838	$	165,532
Power Supply	2006	$	115,576	$	0		$	38,736		$	820	$	155,132

Dave Smith,	2008	$	152,717	$	2,000		$	82,657		$	4,129	$	241,503
Sr. Vice President,	2007	$	134,589	$	0		$	71,941		$	8,458	$	214,988
Administration	2006	$	124,013	$	0		$	67,375		$	16,343	$	207,731

Lee D. Thibert,	2008	$	119,951	$	0		$	99,323		$	3,830	$	223,104
Sr. Vice President,	2007	$	174,235	$	0		$	75,324		$	9,610	$	259,169
Strategic Planning & Corporate Affairs	2006	$	161,983	$	0		$	70,874		$	8,709	$	241,566

William R. Stewart,	2008	$	405,015	$	0		$	32,230		$	0	$	437,245
Former, Chief Executive	2007	$	213,115	$	0		$	80,138		$	48,960	$	342,213
Officer	2006	$	217,208	$	33,000		$	60,454		$	30,863	$	341,525


¹ Includes costs for life insurance premiums, tax withholdings on bonuses and payment for unused vacation days.

On December 5, 2007, the Board of Directors of Chugach Electric Association voted to terminate the contract of Chugach’s former Chief Executive Officer, Mr. William Stewart. Subsequent to Mr. Stewart’s termination, a dispute arose between Chugach and Mr. Stewart as to the amount owed Mr. Stewart as a result of his termination. On August 27, 2008, the Board of Directors of Chugach ratified a Settlement Agreement with Mr. Stewart relating to the amount owed Mr. Stewart. Mr. Stewart will receive the amount of $263,725 payable in twelve equal monthly installments. Chugach will also reimburse Mr. Stewart for withholding taxes that were repaid by Mr. Stewart to Chugach in the amount of $173,855.35. Chugach will also release to Mr. Stewart Pension Restoration Plan funds in the amount of $317,106.34 that had been paid to Chugach for the benefit of Mr. Stewart. 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 National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (the “Plan”), a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. Under FAS 87, the plan is a multi employer plan, in which the accumulated benefits and plan assets are not determined or allocated separately to individual employers. The Plan is intended to be a qualified pension plan under Section 401(a) of the Code. All our employees not covered by a union agreement become participants in the Plan on the first day of the month following completion of one year of eligibility service. An employee is credited with one year of eligibility service if he or she completes 1,000 hours of service either in his or her first twelve consecutive months of employment or in any calendar year for us or certain other employers in rural electrification (related employers). Pension benefits vest at the rate of 10% for each of the first four years of vesting service and become fully vested and nonforfeitable on the earlier of the date a participant has five years of vesting service or the date the participant attains age fifty-five while employed by us or a related employer. A participant is credited with one year of vesting service for each calendar year in which he or she performs at least one hour of service for us or a related employer. Pension benefits are generally paid upon the participant’s retirement or death. A participant may also elect to receive pension benefits while still employed by us if he or she has reached his normal retirement date by completing thirty years of benefit service (defined below) or, if earlier, by attaining age sixty-two. A participant may elect to receive actuarially reduced early retirement pension benefits before his or her normal retirement date provided he or she has attained age fifty-five.

Pension benefits paid in normal form are paid monthly for the remaining lifetime of the participant. Unless an actuarially equivalent optional form of benefit payment to the participant is elected, upon the death of a participant the participant’s surviving spouse will receive pension benefits for life equal to 50% of the participant’s benefit. The annual amount of a participant’s pension benefit and the resulting monthly payments the participant receives under the normal form of payment are based on the number of his or her years of participation in the Plan (benefit service) and the highest five-year average of the annual rate of his or her base salary during the last ten years of his or her participation in the Plan (final average salary). Annual compensation in excess of $200,000, as adjusted by the Internal Revenue Service for cost of living increases, is disregarded after January 1, 1989. The participant’s annual pension benefit at his or her normal retirement date is equal to the product of his or her years of benefit service times final average salary times 2%. In 1998, NRECA notified us that there were employees whose pension benefits from NRECA’s Retirement & Security Program would be reduced because of limitations on retirement benefits payable under Section 401(a)(17) or 415 of the Code. NRECA made available a Pension Restoration Severance Pay Plan and a Pension Restoration Deferred Compensation Plan for cooperatives to adopt in order to make employees whole for their lost benefits. In May 1998, we adopted both of these plans to protect the benefits of current and future employees whose pension benefits would be reduced because of these limitations.

On October 16, 2002, the Board authorized an amendment to the Plan with an effective date of November 1, 2002. Under the amended Plan, the retirement benefit payable to any Participant whose retirement is postponed beyond his or her Normal Retirement Date shall be computed as of the Participant’s actual retirement date. The retirement benefit payable to any Participant under the 30-Year Plan shall be computed as of the first day of the month in which the Participant’s actual retirement date occurs.

Benefit service as of December 31, 2008 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	Number of Credited Years of Service	Present Value of Accumulated Benefit		Payments During Last Fiscal Year


Bradley W. Evans, Chief Executive Officer	Retirement Security	7.83	$	239,577	$	0

Michael R. Cunningham, Chief Financial Officer	Retirement Security	25.08	$	951,282	$	0

Lee D. Thibert, Sr. Vice President, Strategic Planning & Corporate Affairs	Retirement Security	20.33	$	637,645	$	0

Paul R. Risse, Sr. Vice President, Power Supply	Retirement Security	12.92	$	299,886	$	0

Dave Smith,¹Sr. Vice President, Administration	Retirement Security	0.5	$	19,333	$	482,533

Edward M. Jenkin, Vice President, Power Delivery	Retirement Security	18.08	$	322,738	$	0

Tyler Andrews, Vice President, Human Resources	Retirement Security	N/A		N/A		N/A

William R. Stewart, (Former) Chief Executive Officer	Retirement Security	0.00	$	0	$	287,144

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 (4.52% for 2008 and 4.69% for 2007) and the PPA three-segment yield rates (4.60%, 4.82%, and 4.91% for 2008 only) and the required IRS mortality table for lump sum payments (1994 GAR, projected to 2002, blended 50%/50% for unisex mortality in combination with the 30-year Treasury rates and RP 2000 PPA at 2008 combined unisex 50%/50% mortality in combination with the PPA rates). The lump sum is then discounted at 5.54% interest only (no mortality is assumed)

from assumed retirement date back to December 31, 2008, and 5.75% interest only (no mortality is assumed) from assumed retirement date back to December 31, 2007, 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	$	15,500		$ 0	$	31		$	0	$	15,531

Michael R. Cunningham, Chief Financial Officer	$	15,500		$ 0	$	(18,148	)	$	0	$	73,169

William R. Stewart, (Former) Chief Executive Officer	$	0		$ 0	$	0		$	317,106	$	0

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	$	287,280

Michael R. Cunningham, Chief Financial Officer	$	104,185

Tyler Andrews, Vice President, Human Resources	$	9,891

Edward Jenkin, Vice President, Power Delivery	$	112,792


Paul R. Risse, Sr. Vice President, Power Supply	$	150,628

Dave Smith, Sr. Vice President, Administration	$	95,140

Lee Thibert, Sr. Vice President, Strategic Planning & Corporate Affairs	$	99,719

repaid by Mr. Stewart to Chugach in the amount of $173,855.35. Chugach will also release to Mr. Stewart Pension Restoration Plan funds in the amount of $317,106.34 that had been paid to Chugach for the benefit of Mr. Stewart. 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, 2008 to each of our current and former Board members:

Director Compensation Table


Name	Fees Paid In Cash

Rebecca Logan, Chairman and Director	$	12,400

Jim Nordlund, Vice-Chairman and Director	$	12,950

P. J. Hill, Treasurer and Director	$	9,200

Alex Gimarc, Secretary and Director	$	9,200

Jeff Lipscomb, Director	$	13,050

Janet Reiser, Director	$	10,850

Elizabeth Vazquez, Director	$	18,700

Uwe Kalenka, Former Director	$	1,800

One new Board member was elected at Chugach’s annual membership meeting held on April 24, 2008. Janet Reiser was elected to a three-year term, replacing director Uwe Kalenka.

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, 2008.

Fees and Services

KPMG LLP has provided certain audit, audit-related, tax and non-audit services, the fees for which are as follows:


	2008		2007

Audit and audit-related services:
Audit and quarterly reviews	$	160,180	$	209,940
Audit-related services (Single audit and employee benefit plans)		70,465		34,925
Non-audit services:
Tax consulting and return preparation		17,250		3,750
Other services*		83,056		21,238

Total	$	330,951	$	269,853

* Other services in 2008 included Sarbanes-Oxley documentation and 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, 2008 and 2007 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		44
Balance Sheets, December 31, 2008 and 2007		45-46
Statements of Operations, Years ended December 31, 2008, 2007 and 2006		47
Statements of Changes in Equities and Margins, Years ended December 31, 2008, 2007 and 2006		48
Statements of Cash Flows, Years ended December 31, 2008, 2007 and 2006		49
Notes to Financial Statements		50-77

Financial Statement Schedules

Included in Part IV of this Report:
Report of Independent Registered Public Accounting Firm		93
Schedule II - Valuation and Qualifying Accounts, Years ended December 31, 2008, 2007 and 2006		94

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 9, 2009, we reported on the balance sheets of Chugach Electric Association, Inc. as of December 31, 2008 and 2007, 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, 2008, which are included in the 2008 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 2008 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 9, 2009

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, 2008		(541,368	)		(295,313	)		428,049			(408,632	)
December 31, 2007		(586,221	)		(21,817	)		66,670			(541,368	)
December 31, 2006		(398,321	)		(44,942	)		(142,958	)		(586,221	)

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. (27)

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)

100


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. 3(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)

101


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)

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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.

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)

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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)

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)

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)

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)

14		Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. (21)

31.1		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99		Press release announcing plans to explore a possible merger or joint operations between the Registrant and Municipal Light & Power dated effective June 15, 2007. (28)

99.1		Press release announcing a panel recommendation that the Municipality of Anchorage and the registrant explore joint generation and operations dated effective February 8, 2008. (31)

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		(1) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1996.

		(2) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 1997.

		(3) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1997.

		(4) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 1998.

		(5) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1998.

		(6) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1998.

		(7) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 1999.

		(8) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999.

		(9) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2000.

		(10) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2000.

		(11) Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (File No. 333-57400) dated March 22, 2001.

		(12) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2001.

		(13) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2001.

		(14) Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 (File No. 333-75840) dated December 21, 2001.

		(15) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2002.

105


		(17) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2002.

		(18) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2003.

		(19) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003.

		(20) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2004.

		(21) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2004.

		(22) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2005.

		(23) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2005.

		(24) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2005.

		(25) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2006.

		(26) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2006.

		(27) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2007.

		(28) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated June 21, 2007

		(29) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2007.

		(30) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2007.

		(31) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated February 8, 2008.

106


		(32) Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007.

		(33) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2008.

		(34) Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated August 27, 2008.

		(35) Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2008.

107

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 4, 2009.


	CHUGACH ELECTRIC ASSOCIATION, INC.

	By:	/s/ Bradley W. Evans

	Bradley W. Evans, Chief Executive Officer

	Date:	March 4, 2009

108

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 4, 2009, by the following persons on behalf of the registrant in the capacities indicated:


/s/ Bradley W. Evans

Bradley W. Evans		Chief Executive Officer
		(Principal Executive Officer)

/s/ Michael R. Cunningham

Michael R. Cunningham		Chief Financial Officer
		(Principal Financial Officer)
		(Principal Accounting Officer)
/s/ Paul Risse

Paul Risse		Sr. Vice President, Power Supply

/s/ Lee Thibert

Lee Thibert		Sr. Vice President, Strategic Planning &
		Corporate Affairs
/s/ Dave Smith

Dave Smith		Sr. Vice President, Administration

For /s/ William J. Bernier

Edward M. Jenkin		Vice President, Power Delivery

/s/ Tyler Andrews

Tyler Andrews		Vice President, Human Resources

/s/ Rebecca Logan

Rebecca Logan		Director & Chairman of the Board

/s/ James Nordland

James Nordland		Director & Vice-Chairman of the Board

/s/ P. J. Hill

P. J. Hill		Director & Treasurer of the Board

/s/ Alex Gimarc

Alex Gimarc		Director & Secretary of the Board

109



Jeffrey Lipscomb		Director

/s/ Janet Reiser

Janet Reiser		Director

/s/ Elizabeth Vazquez

Elizabeth Vazquez		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 2008 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.

110

Positive
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Uncertain
Constraining
Legalese
Litigous
Readability	7th grade Avg

Chugach Electric Association 10-K2008 FY Annual report

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