Form 10-K

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

10-K 1 d317480d10k.htm FORM 10-K Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2011

¨	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 incorporation or organization)		(I.R.S. Employer 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
N/A		N/A

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

N/A

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ¨ 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 ¨ No

Indicate by check mark whether registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes ¨ No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Registration S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the last practicable date. NONE

CHUGACH ELECTRIC ASSOCIATION, INC.

2011 Form 10-K Annual Report

Table of Contents


	Page
PART I
Item 1 – Business		3

Item 1A – Risk Factors		12

Item 1B – Unresolved Staff Comments		18

Item 2 – Properties		19

Item 3 – Legal Proceedings		28

Item 4 – Mine Safety Disclosures		28

PART II
Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		28

Item 6 – Selected Financial Data		29

Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation		30

Item 7A – Quantitative and Qualitative Disclosures About Market Risk		50

Item 8 – Financial Statements and Supplementary Data		51

Item 9 – Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		89

Item 9A – Controls and Procedures		89

Item 9B – Other Information		90

PART III
Item 10 – Directors, Executive Officers and Corporate Governance		90

Item 11 – Executive Compensation		94

Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		101

Item 13 – Certain Relationships and Related Transactions, and Director Independence		101

Item 14 – Principal Accounting Fees and Services		101

PART IV

Item 15 – Exhibits and Financial Statement Schedules		102

SIGNATURES		115

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 also provides a link to the SEC’s website at http://www.sec.gov.

Chugach is the largest electric utility in Alaska. We are engaged in the generation, transmission and distribution of electricity to approximately 81,644 service locations in the Anchorage and upper Kenai Peninsula areas. We also provide service to three wholesale customers. Through an interconnected regional electrical system, our energy is distributed throughout Alaska’s Railbelt, a 400-mile-long area stretching from the coastline of the southern Kenai Peninsula to the interior of the state, including Alaska’s largest cities, Anchorage and Fairbanks. Neither Chugach nor any other electric utility in Alaska’s Railbelt has any connection to the electric grid of the continental United States or Canada. Our principal executive offices are located at 5601 Electron Drive, Anchorage, Alaska 99518. Our telephone number is (907) 563-7494.

Chugach is a rural electric cooperative that is exempt from federal income taxation as an organization described in Section 501(c)(12) of the Internal Revenue Code (Code). Alaska electric cooperatives must pay to the State of Alaska, a gross receipts tax in lieu of state and local ad valorem, income and excise taxes, a tax at the rate of $0.0005 per kilowatt-hour (kWh) of electricity sold in the retail market during the preceding year. This tax is accrued monthly and remitted annually. In addition, we currently collect a regulatory cost charge (RCC) of $0.000492 per kWh of

retail electricity sold. This charge is assessed to fund the operations of the Regulatory Commission of Alaska (RCA). This tax is collected monthly and remitted to the State of Alaska quarterly. We also collect sales tax on retail electricity sold to Kenai Peninsula and Whittier consumers. This tax is also collected monthly and remitted to the City of Whittier monthly and the Kenai Peninsula Borough quarterly. These taxes are a direct pass-through to consumer bills and therefore do not impact our margins.

We had 318 full-time employees as of February 29, 2012. Approximately 70 percent of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW. We also have an agreement with the Hotel Employees and Restaurant Employees (HERE). All agreements were due to expire on June 30, 2010. On February 24, 2010, the Board of Directors approved three year extensions of all three IBEW CBA’s. The three extensions provide no wage increase in the first year and wage increases tied to changes in the Consumer Price Index (CPI) in the second and third years, with a floor on the minimum increase and a cap on the maximum increase. The wage increases also have an indirect connection to Chugach’s financial performance. The contract extensions expire on June 30, 2013. On April 28, 2010, the Board of Directors approved a three year extension of the HERE agreement. The extension contains an increase in the employer health and welfare contribution in each year of the extension but does not provide for a wage or pension increase. The contract extension expires on June 30, 2013. We believe our relationship with our employees is good.

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

Our members are the consumers of the electricity sold by us. As of December 31, 2011, we had three major wholesale customers and 66,941 retail members receiving service at approximately 81,644 service locations. No individual retail customer receives more than 5 percent of our power. Our customers’ requirements for capacity and energy generally increase in fall and winter as home heating and lighting needs increase and then decline in the spring and summer as the weather becomes milder and hours of daylight increase.

Our customers are billed on a monthly basis per a tariffed rate for electrical power consumed during the preceding period. Billing rates are approved by the RCA, see “Item 1 – Business – Rate Regulation and Rates.”

Base rates (derived on the basis of historic cost of service including margins) are established to generate revenues in excess of current period costs in any year and such excess is designated on our Statements of Revenues, Expenses and Patronage Capital as “assignable margins.” Retained assignable margins are designated on our balance sheet as “patronage capital” that is assigned to each member on the basis of patronage. Patronage capital is held for the account of the members without interest and returned when the board of directors of Chugach deems it appropriate to do so.

In 2011, we had 530.1 megawatts (MW) of installed generating capacity provided by 17 generating units at our five owned power plants: Beluga Power Plant, Bernice Lake Power Plant, International Station Power Plant (historically known as “IGT”), Cooper Lake Hydroelectric Project and Eklutna Hydroelectric Project, in which we own a 30 percent interest. Effective December 31, 2011, we sold the Bernice Lake Power Plant to Alaska Electric and Energy Cooperative, Inc. (AEEC) and HEA, see “Item 1 – Business – Wholesale Customers – HEA.” In 2011, approximately 85 percent (by rated capacity) of our generating capacity was fueled by natural gas, which we purchased under gas contracts. The rest of our generating resources are hydroelectric facilities. In 2011, 92 percent of our power was generated from gas, which included power generated at Nikiski, and 79 percent of that gas-fired generation took place at Beluga. The Bradley Lake Hydroelectric Project provides up to 27.4 MW for our retail customers and up to an additional 24.1 MW for our wholesale customers. For more information concerning Bradley Lake, see “Item 2 – Properties – Other Property – Bradley Lake.” We also purchase approximately 40 MW from the Nikiski power plant on the Kenai Peninsula. We operate 1,688 miles of distribution line and 539 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, 2011, we sold 2.7 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, 2011:


	MWh		2011 Revenues		Percent of Sales Revenue
Direct retail sales:

Residential		545,129	$	77,575,401		28	%
Commercial		621,207		73,899,087		26	%

Total		1,166,336		151,474,488		54	%

Wholesale sales:

MEA		763,339		64,818,326		23	%
HEA		475,098		39,154,889		14	%
Seward		64,261		5,031,622		_2	%

Total		1,302,698		109,004,837		39	%

Economy energy/other¹		235,378		20,270,059		7	%


Total from sales		2,704,412		280,749,384		100	%

Miscellaneous energy revenue				2,868,985


Total energy revenues			$	283,618,369

¹	Economy energy/other includes sales or revenue from GVEA and ML&P.

Retail Customers

Service Territory

Our retail service area covers much of 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, 2011, we had 66,941 members receiving power from approximately 81,644 services (some members are served by more than one service). Our customers are primarily urban and suburban. The urban nature of our customer base means that we have a relatively high customer density per line mile. Higher customer density means that fixed costs can be spread over a greater number of customers. As a result of lower average costs attributable to each customer, we benefit from a greater stability in revenue, as compared to a less dense distribution system in which each individual customer would have a more significant impact on operating results. For the past five years no retail customer accounted for more than 5 percent of our revenues.

Wholesale Customers

We are the principal supplier of power to MEA, HEA and Seward under separate wholesale power contracts. For 2011, our wholesale power contracts, including the fuel and purchased power components, produced $109.0 million in revenues, representing 39 percent of our total revenues and 48 percent of our total MWh sales to customers.

MEA

We currently have a power sales contract with Alaska Electric Generation & Transmission Cooperative, Inc., (AEG&T) for firm, all-requirement sales to MEA. In 2011, sales to MEA represented approximately 28 percent of Chugach’s total sales of energy (including both retail and wholesale). AEG&T is a generation and transmission cooperative that was formed by MEA and HEA in the mid 1980’s. Under this contract, we sell power to AEG&T for resale to MEA. Under this contract, MEA is obligated to purchase all of its electric power and energy requirements from us. MEA had the right under the contract to alter the terms on which it purchased power from Chugach. MEA did not invoke any of these rights and time periods in which MEA could exercise these rights have expired. 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 ML&P invited MEA to participate in the development of a gas-fired generation plant near Chugach’s Anchorage headquarters. On November 21, 2008, MEA elected to not participate in the project. At an August 26, 2009, Chugach Board of Directors’ meeting and in a letter dated September 3, 2009, MEA’s then Interim General Manager advised Chugach that MEA desires to open discussions regarding power sales possibilities beyond 2014. Chugach proposed a power supply offer on January 11, 2011, and again on January 31, 2012. Chugach received a response on February 29, 2012, indicating that MEA was following the path its membership most favored and is moving forward with plans to build its own generation plant.

HEA

We had a power sales contract with AEG&T for firm, partial- requirement sales to HEA until June 19, 2002, when the RCA approved the request by Alaska Electric and Energy Cooperative, Inc. (AEEC) and AEG&T to transfer Certificate of Public Convenience and Necessity No. 345 to serve as the power supplier of HEA to AEEC, instead of AEG&T. HEA is the sole member of AEEC. As part of this transaction our power sales agreement was assigned to AEEC and the Nikiski dispatch agreement was assigned to HEA with certain exceptions with the remaining rights and obligations under the Dispatch Agreement being assigned to AEEC (discussed below). Chugach has not experienced a decline in revenue as a result of this transfer. Under our contract, HEA is obligated to pay us for the power sold to AEEC even if AEEC does not pay. Under this contract, HEA is obligated (through AEEC) to take or pay for 73 MW of capacity, and not less than 350,000 MWh per year. The HEA contract, as interpreted by the Alaska Public Utilities Commission, 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. In 2011, HEA’s remaining resource requirements were 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 2011, sales to HEA represented approximately 17 percent of Chugach’s total sales of energy (including both retail and wholesale).

In February 1999, we entered into a dispatch agreement with AEG&T, now AEEC, 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 AEEC equal to HEA’s residual energy requirements less its allocated share of the Bradley Lake project, up to a maximum of 320,000 MWh per year. A portion of the Nikiski unit output may be dispatched for HEA needs, provided HEA supplies the fuel, in excess of the sum of our contract demand plus HEA’s share of energy from the Bradley Lake project. The dispatch agreement will terminate on January 1, 2014, when our power supply contract with HEA terminates. In a letter dated January 9, 2007, HEA notified Chugach that HEA would not seek to renew, extend or modify the current Agreement for Sale of Electric Power and Energy (the Agreement) when the Agreement expires on January 1, 2014. On January 15, 2008, Chugach and HEA signed an agreement entitled Settlement of Dispute over Nikiski Cogeneration Plant System Use and Dispatch Agreement and Premium Demand Charges under HEA’s Power Sales Agreement. This resolved a dispute over the interpretation of the Nikiski Cogeneration Plant System Use and Dispatch agreement. As part of the Settlement Agreement, Chugach agreed to dispatch HEA’s share of Bradley Lake output for $30,000 per year to minimize, to the extent possible, any premium demand charges to be paid to Chugach by HEA.

On February 18, 2008, Chugach offered AEEC the opportunity to participate in the development of a gas-fired generation plant in order to partially satisfy its power requirements. In June 2008, AEEC elected to withdraw from further participation discussions and pursue its own generation project.

On July 12, 2011, Chugach, AEEC and HEA entered into an Asset Purchase and Sale Agreement whereby Chugach has agreed to sell and AEEC has agreed to purchase the Bernice Lake Power Plant located in Nikiski, Alaska. The sale also includes associated transmission substation facilities located on the premises. The Bernice Lake facility is located on land that is leased to Chugach by HEA. The current lease expired on November 30, 2011, but was extended by HEA to be consistent with the closing date contained in the Asset Purchase and Sale Agreement. The sale and book value of assets was equal to approximately $11.9 and $4.4 million, respectively.

Associated with the Asset Purchase and Sale Agreement described above, Chugach also entered into an Agreement for Sale of Electric Capacity with AEEC and HEA (Capacity Agreement). The agreement is a purchased power agreement that allows Chugach to purchase the capacity and related energy from the Bernice Lake Power Plant from the closing date of the sale of the facility (Asset Purchase and Sale Agreement) to AEEC through December 31, 2013. This agreement allows Chugach to sell the Bernice Lake Power Plant and simultaneously ensure system retail and wholesale deliverability requirements are met through December 31, 2013. Chugach submitted the Asset Purchase and Capacity Agreement to the RCA on July 21, 2011. The agreements were approved by the RCA on December 23, 2011, with an effective date of December 31, 2011.

Seward

We currently provide nearly all the power needs of the City of Seward. In 2011, sales to Seward represented approximately 2 percent of Chugach’s total sales of energy (including both retail and wholesale). We entered into a 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. On May 6, 2011, Chugach submitted a request to the RCA to extend the term of the 2006 Agreement to December 31, 2016. The RCA issued a letter order on May 26, 2011, approving the extension. The 2006 Agreement is an interruptible, all-requirements/no generation capacity 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 is assigned to Seward.

Economy Customers

Since 1989, we have sold economy (non-firm) energy to GVEA. 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 have otherwise generated itself or purchased from other sources.

On April 6, 2010, Chugach and GVEA finalized an agreement for Chugach to provide a minimum of 20 MW of economy energy to GVEA on a non-firm basis based on an interruptible gas supply arrangement. The agreement commenced on May 1, 2010, and will continue through March 31, 2013. The price to GVEA will include the cost of fuel (based on a system average heat rate), plus variable operations and maintenance expense, plus a margin. Sales will be made under the terms and conditions of Chugach’s economy energy sales tariff.

Non-firm sales to GVEA have been 235,378 MWh, 277,793 MWh and 76,968 MWh for 2011, 2010, and 2009, respectively. For sales not covered by a contractual priority right, no seller enjoys a contractual priority in making such sales and GVEA makes purchases from the seller offering the lowest competitive price.

Rate Regulation and Rates

The RCA regulates our rates. We seek changes in our base rates by submitting semi-annual Simplified Rate Filings (SRF) or through general rate cases filed with the RCA on an as-needed basis. Chugach’s base rates, whether set under a general rate case or an SRF, are established to allow the continued recovery of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs and those rates are then collected from our retail and wholesale customers.

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. The regulatory environment in Alaska requires cooperatives to use a debt service coverage approach to ratemaking. Times Interest Earned Ratio (TIER) is designed to ensure Chugach maintains a debt service coverage ratio that allows Chugach to remain in compliance with its debt covenants. 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 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 recovery filings with the RCA, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Overview – Rate Regulation and Rates – Fuel Recovery.”

The Second Amended and Restated Indenture of Trust (Indenture), which became effective January 20, 2011, 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 Amended and Restated Master Loan Agreement with CoBank, which became effective January 19, 2011, 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 2010 Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch, and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, which became effective November 17, 2010, and governs the unsecured credit facility Chugach may use to meet its obligations under its 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. The Revolving Line of Credit Agreement with NRUCFC requires Chugach to maintain an average TIER of not less than 1.10 times total interest expense.

For the years ended December 31, 2011, 2010 and 2009, our Margins for Interest/Interest (MFI/I) was 1.30, 1.26 and 1.27, respectively. For the same periods, our TIER was 1.58, 1.44 and 1.28, respectively. The temporary increase in TIER in 2011 and 2010 was due to certain debt classified as short term, which was replaced with long-term debt in 2012.

Our Service Areas and Local Economy

Our service areas and those of our wholesale and economy energy customers are often described collectively as the Railbelt region of Alaska because the three geographic areas (the Southcentral, the Kenai Peninsula and the Interior) are linked by the Alaska Railroad.

Anchorage is located in the Southcentral region of Alaska and is the trade, service, medical and financial center for most of Alaska and serves as a major center for many state governmental functions. Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, medical, financial and educational facilities, 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 oil and gas price trends. Recent examples of the impact from these trends include the closure of Agrium’s Kenai facilities in 2008 due to Agrium’s inability to acquire an economic supply of gas. Up until the closure, the Agrium facility was the largest value-added product exporter in Alaska. A more recent example of the impact of world markets is the jointly-owned liquefied natural gas (LNG) export facility located in the City of Kenai. This facility, the only one operating in the United States, has been exporting LNG to Japan for 41 years. Effective September 26, 2011, ConocoPhillips Alaska purchased Marathon Oil’s 30% share of the plant. ConocoPhillips and Marathon Oil had previously announced they would be ceasing exports from the LNG facility and putting it in “preservation mode,” leaving future options open. Operations were extended into November and in December ConocoPhillips announced that exports are expected to resume in the second half of 2012. Partially offsetting these losses, Tesoro’s Kenai refinery (one of the largest Alaska refiners producing gasoline, jet fuel, heavy fuel oils, propane and asphalt) expanded its operations and capacity to include the production of ultra low sulfur gasoline and diesel. Third party oil and gas developers have shown increased interests in multiple developments across the Kenai, which will also help offset the loss of long-time industrial consumers. Other important basic industries include tourism and commercial fishing and processing. Principal communities on the Kenai Peninsula are Homer, Seward, Kenai and Soldotna.

Fairbanks is the center of economic activity for the central part of the state, known as the Interior. Fairbanks, which is approximately 350 miles north of Anchorage, is Alaska’s second largest city. Economic activities in the Fairbanks region include federal and state government and military operations, coal mining, the University of Alaska, tourism and support of natural resource development in the Interior and northern parts of the state. Several gold mines, served by GVEA, operate near Fairbanks. The Trans-Alaska Pipeline System, which transports crude oil, passes near Fairbanks on its route from the North Slope oilfields to Valdez.

Sales Forecasts

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


Sales (MWh)	2012		2013		2014		2015		2016
Retail		1,174,000		1,176,000		1,177,000		1,179,000		1,181,000
Wholesale		1,274,000		1,283,000		838,000		63,000		63,000

Total		2,448,000		2,459,000		2,015,000		1,242,000		1,244,000

Retail and wholesale energy sales are expected to remain relatively flat due to slow economic growth and progress in energy efficiency and conservation. Firm system sales are expected to grow at an average annual compounded rate of 0.4 percent from 2012 to 2013, with retail energy sales expected to increase at a rate of 0.1 percent and wholesale energy sales at a rate of 0.7 percent. At the end of 2013, HEA’s contract to purchase their net requirements from Chugach expires, causing system energy sales to decrease by about 18 percent. At the end of 2014, MEA’s contract to purchase their full requirements from Chugach expires, resulting in a decrease of about 38 percent in system energy sales from 2014 to 2015. Overall, the expiration of these contracts amounts to a 49 percent decrease in Chugach system sales from 2013 to 2015. Chugach retail sales

from 2012 to 2016 are expected to increase at an average annual compounded growth rate of 0.1 percent. 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 affect 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, results of operations and cash flows. The statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Financing

On January 11, 2012, Chugach issued $250,000,000 of First Mortgage Bonds, 2012 Series A, due March 15, 2032 and 2042 for the purpose of repaying outstanding commercial paper and for general corporate purposes.

On January 21, 2011, Chugach issued $275 million of First Mortgage Bonds, 2011 Series A, due 2031 and 2041 for the purpose of refinancing the 2001 and 2002 Series A Bonds due March 15, 2011, and February 1, 2012, respectively, and for general corporate purposes. As anticipated, on February 1, 2012, Chugach retired its 2002 Series A Bonds with proceeds from the 2011 Series A bond issuance.

On November 17, 2010, Chugach replaced the $300 million unsecured Credit Agreement executed on October 10, 2008, which was due to expire on October 10, 2011. The 2010 Credit Agreement will expire on November 17, 2013. The Credit Agreement is used to back Chugach’s Commercial Paper program. Chugach began issuing short term commercial paper in the first quarter of 2009. Chugach is expected to continue to issue commercial paper in 2012, as needed, however, the requirement for short-term borrowing has decreased. For additional information concerning our Commercial Paper Program, see “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt – Commercial Paper.”

No assurance can be given that Chugach will be able to continue to access the commercial paper market. Global financial markets and economic conditions have been volatile due to a variety of factors, including current weak economic conditions. As a result, the cost of raising money in the debt capital markets could increase while the availability of funds from those markets could diminish. The termination of the wholesale power contracts with MEA and HEA could negatively impact our future ability to finance or could impact the cost associated with financing efforts in the future.

Wholesale Contracts

Chugach is the principal supplier of power under wholesale power contracts with MEA and HEA. These contracts, including the fuel component, represented $104.0 million, or 37 percent and $89.1 million, or 35 percent in 2011 and 2010, respectively, of total sales revenue. The HEA and MEA contracts expire January 1, 2014, and December 31, 2014, respectively. Pursuant to provisions of their contracts, notification was made by MEA in 2004 and by HEA in 2007 that neither organization intends to be on the Chugach system under the current contractual arrangements post 2014. This would result in a loss of approximately 49 percent of Chugach’s power sales and approximately 40 percent of the utility’s annual sales revenue. At the August 26, 2009, Chugach Board of Directors’ meeting and in a letter dated September 3, 2009, MEA’s then-Interim General Manager advised Chugach that MEA desires to open discussions regarding power sales possibilities beyond 2014. Chugach proposed a power supply offer to MEA on January 11, 2011, and again on January 31, 2012. Chugach received a response on February 29, 2012, indicating that MEA was following the path its membership most favored and is moving forward with plans to build its own generation plant. Chugach’s planning process, however, reflects the termination of the MEA and HEA wholesale contracts post 2014. Consequently, to mitigate this risk, Chugach will be pursuing replacement sources of revenue through potential new power sales agreements and 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.

Credit Ratings

Changes in our credit ratings could affect our ability to access capital. We maintain a rating from Standard & Poor’s Rating Services (S&P) and Fitch Ratings (Fitch) of “A-” (Stable) and “A-” (Positive), respectively. Moody’s Investors Service (Moody’s) withdrew its rating when Chugach repaid the 2002 Series A Bonds on February 1, 2012. We are currently evaluating whether we will obtain a rating from Moody’s on any of our current long-term secured debt. S&P and Moody’s currently rate our commercial paper at “A-1” and “P-2”, respectively. If these agencies were to downgrade our ratings, particularly below investment grade, we may be required to pay higher interest rates on financings which we need to undertake in the future, and our potential pool of investors and funding sources could decrease.

Cybersecurity

Chugach’s operations are dependent on certain telecommunication and data processing technologies. Chugach has not experienced any disruptions or significant costs associated with intentional attacks or unauthorized access to any of our systems. Chugach has numerous programs in place to safeguard our operating systems and the personal information of our customers and employees. No assurance can be given that Chugach will never experience an intentional attack or unauthorized access, however, we believe our preventive actions are adequate to manage this risk.

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. Chugach receives information concerning its funding status annually. If a funding shortfall in the AEPF exists, we may 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.

We also participate in the National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (the “Plan”), a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. All our employees not covered by a union agreement become participants in the Plan. We do not have control over the Plan. The Plan updates contribution rates on an annual basis to maintain the health of the plan consistent with Pension Protection Act of 2006 minimum funding standards. Currently, the plan does not require accelerated catch-up contributions to maintain minimum funding standards.

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. 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 recovery 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 recovery to recover those costs at the time of the next quarterly fuel recovery 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 regulatory process does not provide for the timely recovery of purchased power costs, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and commercial paper borrowing capacity to mitigate this risk.

Southcentral Power Project (SPP)

We are currently in the process of developing a natural gas-fired generation plant near our Anchorage headquarters. The generation plant is being developed jointly with ML&P. All projects of this size and nature are subject to numerous schedule and cost risks including weather conditions, delays in obtaining key materials, labor difficulties, permitting, construction delays, difficulties with partners or other factors beyond our control. Any of these events could cause the total costs of construction to be higher than anticipated and the performance of our business following the construction to not meet expectations, hence hindering our ability to timely and effectively integrate the SPP into our operations, resulting in unforeseen operating difficulties or unanticipated costs. Any of these or other factors could adversely affect our ability to realize the anticipated benefits from the project. Chugach received a construction permit from the Alaska Department of Environmental Conservation in December of 2010 and its initial building permit from the Municipality of Anchorage in March of 2011.

Fuel Supply

In 2011, 92 percent of our power was generated from natural gas, which included power generated at Nikiski. Our primary suppliers of natural gas are ConocoPhillips and Marathon. Chugach currently has contracts in place to fill 100 percent of Chugach’s needs through December 2014, approximately 70 percent of Chugach’s needs through 2015 and approximately 40 percent in 2016.

The State of Alaska Department of Natural Resources (DNR) completed a preliminary engineering and geological evaluation of the remaining Cook Inlet gas reserves in December of 2009. The study identified 863 billion cubic feet (BCF) of proven, developed, producing reserves, additional probable reserves of 279 BCF and an additional increment of 353 BCF in high-confidence pay intervals. Combined, these 1.5 trillion cubic feet of gas reserves are similar to the 1.4 trillion cubic feet of gas reserves identified in a 2004 study undertaken by the Department of Energy in 2004. Given current demand and deliverability, DNR estimates a minimum 10-year supply of gas exists in currently producing leases. DNR does note that economic considerations will play a major role in whether producers continue undertaking additional drilling and development activities to meet demand. An updated June 2011 DNR report titled “Cook Inlet Natural Gas Production Cost Study” further quantified the economic considerations and came to two key conclusions:

Based on currently available information, the assumptions made in this study, and absent any exploration success, the Cook Inlet basin is capable given sufficient continued investments of supplying the regional natural gas needs until 2018-2020 at a price below that of currently contemplated alternatives. However, failure to make appropriate investments in lockstep with demand requirements will necessitate alternative sources of natural gas to be made available sooner. Therefore, transition to alternative sources of natural gas may begin to occur before the 2018-2020 time-frame as part of a comprehensive supply and risk management plan.

Natural gas storage will play an increasingly important role in optimizing and managing deliverability and economics of the natural gas supply for south-central Alaska. Just-in-time production reduces the amount of time between investment and return, and improves the economics of supplying natural gas. If gas purchases can be made in summer in advance of peak winter needs, storage allows these dynamics to be managed effectively by allowing production in summer to exceed the demand and storing the excess production until it is needed in winter.

Chugach has been working closely with the State of Alaska and producers to develop a comprehensive Cook Inlet management plan that will meet this goal. Chugach continues to explore its options for future fuel supply needs by working with developers on commercial terms for future gas supply and the state of Alaska on energy policies to promote gas development in Cook Inlet and other in-state gas options such as a Spur Line off a larger line from the North Slope or a Bullet Line to Southcentral Alaska.

The 2010 Alaska Legislature passed legislation that provides incentives to natural gas producers to enhance Cook Inlet oil and gas production. There are currently two independent producers who are in the process of mobilizing to-or using-jack-up drill rigs in Cook Inlet to take advantage of those incentives. Other producers have recently drilled conventional wells. Although it is too early to tell if the incentives will pay off, independent producers do seem to be taking steps to enter the market. 2011 Cook Inlet petroleum lease sales are up three-fold from last year and Buccaneer Energy recently announced success of the Kenai Loop No. 1 gas well in the city of Kenai, Alaska. Chugach, other utilities and industrial customers have formed a study group to evaluate liquefied natural gas (LNG) import options. LNG imports could be necessary by 2015. In addition to following exploration and production activity in the Cook Inlet area, Chugach is also closely monitoring potential pipeline options from the North Slope and is reviewing LNG options if Cook Inlet production does not keep pace with current field decline levels.

Utility plans for additional gas storage are on schedule for completion in April of 2012. The RCA approved inception rates and a tariff for the Cook Inlet Natural Gas Storage Alaska (CINGSA) facility on January 31, 2011. CINGSA is a project to develop a gas storage facility using a partially depleted underground reservoir. The facility will have an initial storage capacity of 11 BCF so that local utilities, including Chugach, will have gas available to meet deliverability requirements during peak periods. Chugach’s share of the initial capacity is 2.4 BCF in 2012, reducing to 2.3 BCF in 2013. Injections into the facility are expected to begin in mid 2012 and withdrawals of gas are expected to begin in the winter of 2012-2013. Chugach is entitled to withdraw gas at a rate of up to 35 million cubic feet (MMcf) per day in 2012-2013.

Cooper Lake Hydroelectric Project

The Cooper Lake Hydroelectric Project received a 50-year license from the Federal Energy Regulatory Commission (FERC) in August of 2007. A condition of that license is a requirement to construct a Stetson Creek diversion structure, a pipeline to Cooper Lake, and a bypass structure to release warmer water from Cooper Lake into Cooper Creek. The cost and feasibility of this project are currently being assessed. If the project is not feasible or if the cost estimate materially exceeds the terms of the license it may require a license amendment.

Other Environmental Regulations

We currently are required to comply with numerous federal, state and local laws and regulations relating to the protection of the environment. While we believe that we have obtained all material environmental-related approvals currently required to own and operate our facilities, we may incur significant additional costs because of compliance with these requirements in addition to costs related to any costs of compliance with laws or regulations relating to CO2 emissions. Failure to comply with environmental laws and regulations could have a material effect on us, including potential civil or criminal liability and the imposition of fines or expenditures of funds to bring our facilities into compliance. Delay in obtaining, or failure to obtain and maintain in effect any environmental approvals, or the delay or failure to satisfy any applicable environmental regulatory requirements related to the operation of our existing facilities could result in significant additional costs to us.

Recovery of Fuel and Purchased Power Costs

The RCA approved inclusion of all fuel and transportation costs related to our current contracts in the calculation of Chugach’s fuel and purchased power recovery which will ensure, in advance, that costs incurred under the contracts can be recovered from Chugach’s customers. The fuel and purchased power recovery process recovers under-recoveries and refunds over-recoveries from prior periods with minimal regulatory lag. Chugach’s fuel recovery 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 recovery. At December 31, 2011, Chugach had under-recovered $1.2 million and at December 31, 2010, Chugach had under-recovered $2.4 million, net. To the extent the regulated fuel and purchased power recovery process does not provide for the timely recovery of costs, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and commercial paper borrowing capacity to mitigate this risk.

Accounting Standards or Practices

We cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or our operations specifically. New accounting standards could be issued that could change the way we record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect our reported earnings or could increase reported liabilities.

Green House Gas Regulations, Carbon Emission and Climate Change

Substantial uncertainty remains regarding the potential impacts of greenhouse gas (GHG) regulations, carbon emissions, and climate change on Chugach’s operations. These issues are potentially responsible for increased frequency of warmer weather, including potentially decreased hydroelectric generation resulting from reduced runoff from snow pack. If climate change reduces Chugach’s hydroelectric energy production, there may be a need for additional production even if there is no change in average load.

In response to public concerns over these issues, the federal government has been pursuing legislation that calls for the reduction of GHG emissions. The proposed legislation typically consists of either a tax on GHG emissions or a cap and trade program that requires allowances to emit GHG. Proposals that implement a GHG emission tax vary widely as to the amount of the tax. Proposed cap and trade programs vary greatly regarding the number of allowances existing facilities would receive at “no cost”, similar to other Clean Air Act regulations. Some proposals do not provide “no cost” allowances to existing facilities.

The additional costs related to a GHG tax or cap and trade program could affect the relative cost of the energy Chugach produces. Because no applicable federal laws regulating GHG emissions have become effective, we cannot predict the cost or effect of future legislation or regulation. In the event that some form of federal law or regulation regarding GHG emissions is enacted in the future, it could have a material adverse effect on our operations, financial position, and cash flows.

These factors, as well as weather, interest rates and economic conditions are largely beyond our control, but may have a material adverse effect on our earnings, cash flows and financial position.

Item 1B – Unresolved Staff Comments

Not applicable

Item 2 – Properties

General

In 2011, we had 530.1 MW of installed capacity consisting of 17 generating units at five power plants. These included 385.0 MW of operating capacity at the Beluga facility on the west side of Cook Inlet; 67.5 MW of power at the Bernice Lake facility on the Kenai Peninsula; 46.7 MW of power at IGT in Anchorage; and 19.2 MW at the Cooper Lake facility, which is also on the Kenai Peninsula. We also owned rights to 11.7 MW of capacity from the two Eklutna Hydroelectric Project generating units that we jointly own with MEA and ML&P. Effective December 31, 2011, we sold the Bernice Lake Power Plant to AEEC and HEA, see “Item 1 – Business – Wholesale Customers – HEA.” In addition to our own generation, we purchased power from the 126 MW Bradley Lake hydroelectric project owned by the Alaska Energy Authority (AEA). 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 2008 and 2009 we purchased land adjacent to our Anchorage headquarters for use during the construction of a new gas fired generation plant we are jointly developing with ML&P. Effective December 31, 2011, we sold the Bernice Lake Power Plant to AEEC and HEA, see “Item 1 – Business – Wholesale Customers – HEA.”

The Cooper Lake Hydroelectric Project is partially located on Federal lands. Chugach operates and maintains the Cooper Lake project pursuant to a 50-year license granted to us by FERC in August 2007. As part of the relicensing process, there was a negotiated Relicensing Settlement Agreement (RSA) entered into in August of 2005. A requirement of the RSA requires Chugach to establish a flow regime in Cooper Creek below the Cooper Lake Dam. This is a project that includes a Stetson Creek Diversion (Dam), Pipeline (Conveyance System) and Cooper Lake Outlet Works. The project is designed to remove colder water flowing into the Cooper Creek drainage and replace it with warmer Cooper Lake water. The final design package will be submitted to FERC in June 2012. Project construction is scheduled for 2013 and 2014.

Cooper Lake Unit 2 was taken out of service in August of 2008 to perform repairs and major maintenance. The unit was put back into service in May of 2009. Unit 1 was taken out of service in May of 2009, shortly after the return to service of Unit 2, to perform repairs and major maintenance, and returned back into service in February of 2010. Unit 2 was taken out of service in July of 2011 for a bearing replacement and annual inspections were completed on both units in August of 2011.

In 1997, we acquired a 30 percent interest in the Eklutna Hydroelectric Project. The plant is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October 1997. MEA owns 17 percent of the project and ML&P owns the remaining 53 percent undivided interest and performs maintenance on the units as needed.

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 scheduled inspections and periodic upgrades. Several hot gas path parts were replaced in Unit 3 during a routine hot gas path inspection in 2011. Combustion inspections were performed on Unit 3 in 2009, 2010 and 2011 in accordance with the existing maintenance plan. Beluga Unit 5 continued to have two combustion inspections in 2009 and 2010. In 2011, this unit received a major inspection which involved replacement of parts of the turbine rotor. Beluga Unit 6 received annual inspections in 2008, 2009 and 2011. In 2010, Unit 6 received a major inspection in which many of the major components were replaced with new or refurbished parts. Beluga Unit 7 had a major inspection in 2008 with annual inspections in 2009, 2010 and 2011. Beluga Unit 8, a steam turbine generator, received a major inspection in 2008 with annual inspections in 2009, 2010, and 2011.

Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines and a spare engine for maintenance purposes with GE Packaged Power, Inc. (GEPP). Chugach has also executed an owner’s engineer services contract, a services contract for the shipment of the combustion turbine generators and related accessories, a steam turbine generator (STG) purchase agreement, an engineering, procurement, and construction (EPC) contract, a once through steam generator (OTSG) equipment and transportation contract and amended the contract for transportation of combustion turbine generators to include transportation of the steam turbine generator. Chugach received an air quality permit from the Alaska Department of Environmental Conservation in 2010, allowing the project to begin construction in the spring of 2011 as planned. On March 15, 2011, Chugach received its initial building permit from the Municipality of Anchorage.

The following matrix depicts nomenclature, run hours for 2011 and percentages of contribution and other historical information for all Chugach generation units.


		Commercial Operation	Nomenclature	Rating (MW)⁽¹⁾			Run Hours (2011)			Percent of Total Run Hours			Percent of Time Available
Facility		Date	Nomenclature	Rating (MW)⁽¹⁾			Run Hours (2011)			Percent of Total Run Hours			Percent of Time Available
Beluga Power Plant ⁽³⁾
	1	1968	GE Frame 5		19.6			2,130.2			4.2			84.2
	2	1968	GE Frame 5		19.6			2,951.3			5.8			98.9
	3	1973	GE Frame 7		64.8			6,976.1			13.8			84.2
	5	1975	GE Frame 7		68.7			5,876.2			11.6			77.2
	6	1976	AP 11DM-EV		79.2			8,359.8			16.5			95.4
	7	1978	AP 11DM-EV		80.1			8,413.5			16.6			96.1
	8	1981	BBC DK021150⁽²⁾		53.0			7,930.5			15.6			90.9

Bernice Lake Power Plant ⁽³⁾⁽⁶⁾					385.0
	2	1971	GE Frame 5		19.0			691.8			1.4			98.8
	3	1978	GE Frame 5		26.0			198.0			0.4			98.1
	4	1981	GE Frame 5		22.5			1,312.6			2.6			98.9

Cooper Lake Hydroelectric Project					67.5
	1	1960	BBC MV 230/10		9.6			2,521.0			5.0			95.9
	2	1960	BBC MV 230/10		9.6			1,280.3			2.5			83.6

IGT Power Plant					19.2

	1	1964	GE Frame 5		14.1			677.4			1.3			98.0
	2	1965	GE Frame 5		14.1			634.7			1.3			99.2
	3	1969	Westinghouse 191G		18.5			723.3			1.4			99.0

Eklutna Hydroelectric Project					46.7
	1	1955	Newport News		5.8	⁽⁴⁾		N/A	⁽⁵⁾		N/A	⁽⁵⁾		98.2
	2	1955	Oerlikon custom		5.9	⁽⁴⁾		N/A	⁽⁵⁾		N/A	⁽⁵⁾		93.2

					11.7


System Total					530.1			50,676.7			100.0

⁽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 ML&P. The capacity shown is our 30 percent share of the plant’s output under normal operating conditions. The actual nameplate rating on each unit is 23.5MW.

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

⁽⁶⁾	Effective December 31, 2011, the Bernice Lake Power Plant was sold to AEEC and HEA.

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

Transmission and Distribution Assets

As of December 31, 2011, our transmission and distribution assets included 42 substations and 539 miles of transmission lines, which included 128 miles of leased transmission lines and Chugach’s share of the Eklutna transmission line, 912 miles of overhead distribution lines and 776 miles of underground distribution line. We own the land on which 22 of our substations are located and a portion of the right-of-way connecting our Beluga plant to Anchorage. As part of our 1997 acquisition of 30 percent of the Eklutna facility, we also acquired a partial interest in two substations and additional transmission facilities.

Many substations and a substantial portion of our transmission and distribution system are subject to federal, state or borough permits, leases or licenses, Alaska Railroad Corporation (ARRC) permits and private lands via easements. We operate the Postmark and Woronzof substations under rights from the Alaska Department of Transportation and Public Facilities and the Ted Stevens International Airport. The University Substation is operated under rights from the Federal Bureau of Land Management. The Dowling Substation is operated under rights from the State Department of Natural Resources, and many distribution lines and transmission corridors are operated under a combination of private and public rights, to include the Matanuska-Susitna Borough and the United States Army/Air Force. Outside of Anchorage, the Portage Substation is operated under rights from the ARRC and the Cooper Lake Power Plant, Quartz Creek Substation and transmission corridors are operated under a federal license. The Hope and Daves Creek substations are operated under rights from the Alaska Department of Natural Resources, and other portions of the transmission and distribution system are operated under rights from the US Forest Service, the Kenai Peninsula Borough, Chugach State Parks and other public entities.

Title

On January 20, 2011, Chugach and the indenture trustee entered into a Second Amended and Restated Indenture of Trust (the Indenture) granting a lien on substantially all of Chugach’s assets to secure Chugach’s long-term debt. Assets that are generally not subject to the lien of the Indenture include cash (other than cash deposited with the indenture trustee); instruments and securities; patents, trademarks, licenses and other intellectual property; vehicles and other movable equipment; inventory and consumable materials and supplies; office furniture, equipment and supplies; computer equipment and software; office leases; other leasehold interests for an original term of less than five years; contracts (other than power sales agreements with members having an original term exceeding three years, certain contracts specifically identified in the indenture, and other contracts relating to the ownership, operation or maintenance of generation, transmission or distribution facilities); non-assignable permits, licenses and other contract rights; timber and minerals separated from land; electricity, gas, steam, water and other products generated, produced or purchased; other property in which a security interest cannot legally be perfected by the filing of a Uniform Commercial Code financing statement, and certain parcels of real property specifically excepted from the lien of the Indenture. The lien of the Indenture may be subject to various permitted encumbrances that include matters existing on the date of the Indenture or the date on which property is later acquired; reservations in U.S. patents; non-delinquent or contested taxes, assessments and contractors’ liens; and various leases, rights-of-way, easements, covenants, conditions, restrictions, reservations, licenses and permits that do not materially impair Chugach’s use of the mortgaged property in the conduct of Chugach’s business.

Many of Chugach’s properties are burdened by easements, plat restrictions, mineral reservation, water rights and similar title exceptions common to the area or customarily reserved in conveyances from federal or state governmental entities, and by additional minor title encumbrances and defects. We do not believe that any of these title defects will materially impair the use of our properties in the operation of our business.

Under the Alaska Electric and Telephone Cooperative Act, we possess the power of eminent domain for the purpose and in the manner provided by Alaska condemnation laws for acquiring private property for public use.

Other Property

Bradley Lake. We are a participant in the Bradley Lake hydroelectric project, which is a 126 MW rated capacity hydroelectric facility near Homer on the southern end of the Kenai Peninsula that was placed into service in September 1991. The project is nominally scheduled below 90 MW to minimize losses and ensure system stability. We have a 30.4 percent (27.4 MW as currently operated) share in the Bradley Lake project’s output, and take Seward’s and MEA’s shares which we net bill to them, for a total of 45.2 percent of the project’s capacity. We are obligated to pay 30.4 percent of the annual project costs regardless of project output.

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

The term of our Bradley Lake power sales agreement is fifty years from the date of commercial operation of the facility (September 1991) or when the revenue bond principal is repaid, whichever is the longer. The agreement may be renewed for successive forty-year periods or for the useful life of the project, whichever is shorter. We believe that so long as this project produces power taken by us for our use that this expense will be recoverable through the fuel recovery process. The share of Bradley Lake indebtedness for which we are responsible is approximately $31 million. Upon the default of a participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs and output pro rata, to the extent necessary to compensate for the failure of the defaulting participant to pay its share, provided that no participant’s percentage share is increased by more than 25 percent. Upon default, Chugach could be faced with annual expenditures of approximately $4.9 million as a result of Chugach’s Bradley Lake take-or-pay obligations.

On July 1, 2010, AEA issued $28,800,000 of Power Revenue Refunding Bonds, Sixth Series, for purposes of refunding $30,640,000 of the Fifth Series Bonds. The refunded Fifth Series Bonds were called on August 2, 2010. The refunding resulted in aggregate debt service payments over the next eleven years in a total amount approximately $3.3 million less than the debt service payments which would have been due on the refunded bonds. Refunding the Fifth Series Bonds resulted in an economic gain of approximately $2.4 million. Chugach’s share of these savings will be approximately $714,300, which represents the reduction in debt-service costs recorded as purchased power expense.

The State of Alaska has provided grants for a project to divert water from Battle Creek into Bradley Lake. The project is being managed by the Alaska Energy Authority and is expected to be completed in 2014. Based on stream flow measurements from 1991 through 1993, diverting a portion of Battle Creek into Bradley Lake has the potential to increase annual energy output by 27,000 to 45,000 MWh. Chugach would be entitled to 30.4 percent of the additional energy produced.

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

Fuel Supply

In 2011, 92 percent of our power was generated from natural gas, which included power generated at Nikiski, and 79 percent of that gas-fired generation took place at Beluga.

Total gas usage in 2011 was approximately 29.3 BCF. In 2011, our sources of natural gas were divided among four contracts with three major oil and gas companies and one utility. All of the production came from Cook Inlet, Alaska. ConocoPhillips Alaska Inc. under their Beluga River Unit (BRU) and new contract provided 49.8 percent of gas supplied for generation, while Marathon Oil Company provided 33.9 percent. Chevron/UNOCAL provided 12.2 percent and ML&P provided 4.1 percent of Chugach’s gas requirements. Our prior contract with Marathon expired in 2010 and our contract with the Beluga River Field Producers expired March 31, 2011. The new contract with ConocoPhillips provided gas beginning in 2010 and will expire December 31, 2016. A new contract with Marathon Alaska Production, LLC (MAP) provided gas, now estimated to be 40 BCF, beginning in April of 2011, and will expire December 31, 2014. ConocoPhillips and Marathon, together, will fill 100% of Chugach’s needs through December 31, 2014.

ConocoPhillips

We entered into a contract with ConocoPhillips Alaska Inc. (COP) in 2009. The contract provided gas starting January 1, 2010, and will terminate December 31, 2016. The total amount of gas under the contract is now estimated to be 60 BCF.

The gas supplied by COP under the contract is separated into two volume tranches for pricing purposes. “Firm Fixed Quantity” gas meets a portion of Chugach’s base load requirements, while “Firm Variable Quantity” gas meets peaking needs. Chugach expects that ninety percent of the gas purchased under the contract will be firm fixed and ten percent will be firm variable. The dividing line between firm fixed and firm variable volumes will be calculated based on a methodology that involves using a multiplier and the simple average of Chugach’s average daily volumes for the thirty lowest volume days during the last calendar year. For example, in 2012 the Firm Fixed Quantity value has been calculated at 35,994 thousand cubic feet (Mcf) per day.

Pricing for firm fixed gas will be based on the average of five Lower 48 natural gas production areas. The contract price will be calculated on a quarterly basis as the trailing average of the simple daily average of the Platts Gas Daily midpoint prices for each “flow day” in these market areas during the last quarter. For the first half of 2010 there was a price collar, floor of $5.75 per Mcf and cap of $6.25 per Mcf, on the firm fixed gas between January 1, 2010 and June 30, 2010.

Pricing for firm variable gas purchased between January 1, 2010, and March 31, 2011, was set based on one quarter trailing average of ninety-five percent of the average monthly price of Kenai liquefied natural gas delivered to Japan, as officially reported to the U.S. Department of Energy. Hourly volumes delivered up to this hourly rate will be priced based on the Firm Fixed Quantity price. Hourly volumes delivered in excess of this hourly rate will be priced based on the Firm Variable Quantity price. For the first quarter of 2011, the Firm Fixed Quantity was calculated at $3.689 per Mcf. Pricing for firm variable gas purchased from April 1, 2011, to December 31, 2013, will be 120 percent of the one calendar quarter trailing average of “Platts National Average Price” as published in Platts Gas Daily for each “flow day.” ($3.23 per Mcf on January 1, 2012), plus taxes in excess of $0.25 per Mcf. The price for firm variable gas is capped at two-hundred percent of the firm fixed price. Firm variable gas is not provided by the contract after December 31, 2013.

Chugach also has the option to receive a fixed price quote from COP and lock that price of any quantity as long as the quantity does not exceed the “Firm Fixed Quantity” and for any term up to December 31, 2016, for which price is to be locked.

Beluga River Field Producers

We had similar requirements contracts with each of the one third working interest owners of the Beluga River Field, ConocoPhillips, ML&P and Chevron, which were executed in April 1989, superseding contracts that had been in place since 1973.

The current contracts continued until the earlier of the delivery of 180 BCF of natural gas or December 31, 2013. Chugach was entitled to 180 BCF of natural gas (60 BCF per Beluga River Field producer). During the term of the contracts, we were required to take 60 percent of our total fuel requirements at Beluga Power Plant from the three Beluga River Field producers, exclusive of gas purchased at Beluga Power Plant under the Marathon contract for use in making sales to GVEA. The BRU contracts expired on March 31, 2011.

Chevron/UNOCAL

In May of 2010, Chugach entered into an interruptible gas purchase agreement with UNOCAL to supply gas for economy energy sales to GVEA. The agreement was due to terminate on March 31, 2012. Effective December 28, 2011, the gas purchase agreement was assigned to Hilcorp Alaska, LLC, who purchased Chevron/UNOCAL’s assets in Cook Inlet. On January 30, 2012, Hilcorp extended the term of the contract to March 31, 2013. Chugach has no exposure to the cost of gas related to economy energy sales since the cost of gas is directly paid for by its economy energy gas customer.

Marathon Alaska Production

We entered into a contract with MAP effective May 17, 2010. The MAP contract provided gas beginning April 1, 2011 and will terminate December 31, 2014. MAP had two contract extension options that could be exercised during the first year of the initial contract. MAP extended the contract to December 31, 2013, by exercising the first contract extension on January 12, 2011, and extended the contract to December 31, 2014, by exercising the second contract extension on October 25, 2011. The total amount of gas under contract is now estimated to be 40 billion cubic feet (BCF).

Pricing for the first twelve month term of the MAP contract has been set at the contract floor price of $5.90 per Mcf. This was established based on the average price point of the Platts Gas Daily NYMEX twelve month forward curve (PLATTS report as of February 1, 2011) for the period April 2011 through March 2012 being set at $4.68 per Mcf, which was lower than the price floor making the price floor the pricing level for the first twelve month period.

Natural Gas Transportation Contracts

The terms of the COP, MAP and UNOCAL agreements require Chugach to handle the natural gas transportation over the connecting pipeline systems. Chugach took over the transportation obligation for natural gas shipments for gas supplied under its contracts on October 1, 2010. Chugach started shipping significant quantities of gas over Marathon Pipe Line Company (MPL) operated pipelines and ENSTAR Natural Gas pipeline system. Chugach entered into tariff supported contracts to serve its power plants through MPL effective October 1, 2010, and ENSTAR November 15, 2010. The following information summarizes the transportation obligations for Chugach:

ENSTAR (Alaska Pipeline Company)

ENSTAR Natural Gas Company (ENSTAR) has a tariff to transport our gas purchased from gas suppliers on a firm basis to our IGT Power Plant at a transportation rate of $0.63 per Mcf. The agreement contains a fixed monthly charge of $2,840 for firm service. In December of 2010, Chugach applied for extension of this tariffed rate with ENSTAR to service the Bernice Lake Power Plant. The RCA approved the request in February of 2011.

Chugach and ENSTAR have negotiated a Gas Transportation Agreement. On September 15, 2011, ENSTAR filed the Gas Transportation Agreement with the RCA, subject to Chugach Board approval by October 31, 2011. Chugach’s Board of Directors approved the agreement on October 26, 2011. The agreement provides for transport of up to 20,000 Mcf of gas per day to Chugach’s Beluga power plant. The total cost for the one year period is expected to be approximately $1 million. Chugach will recover this cost through the fuel and purchased power recovery process.

Marathon Pipeline System

Marathon Oil Company, through its subsidiary Marathon Pipe Line Company, operates four major pipelines in the Cook Inlet basin, including the Kenai Nikiski Pipeline (KNPL), Granite Point Beluga Line (BPL), Cook Inlet Gas Gathering System (CIGGS) and the Kenai Katchemak Pipeline (KKPL). Chugach has entered into two tariff agreements to ship gas over the KNPL and BPL.

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.

Chugach is subject to this new regulation, which is not expected to have a material effect on our results of operations, financial position, or cash flows. While we cannot predict whether any additional new regulation would occur or the effect of that regulation, it is possible that new laws or regulations could increase our capital and operating costs. We have obtained or applied for all Clean Air Act permits currently required for the operation of our generating facilities.

Chugach 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, results of operation or cash flows. However, new laws or regulations, implementation of final regulations or changes in or new interpretations of these laws or regulations could result in significant additional capital or operating expenses.

Item 3 – Legal Proceedings

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

Item 4 – Mine Safety Disclosures

Not Applicable

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	2011			2010			2009			2008			2007

Electric plant, net:
In service	$	392,080,033		$	407,351,421		$	414,002,926		$	432,460,336		$	438,239,286

Construction work in progress		206,005,783			100,787,482			48,383,610			25,151,072			17,712,884


Electric plant, net		598,085,816			508,138,903			462,386,536			457,611,408			455,952,170

Other assets		254,843,842			121,588,825			105,958,000			119,080,561			101,773,948


Total assets	$	852,929,658		$	629,727,728		$	568,344,536		$	576,691,969		$	557,726,118


Capitalization:
Long-term debt		296,090,108			304,450,318			307,301,819			354,383,506			345,423,500

Equities and margins		161,231,426			161,842,284			156,320,597			153,766,999			149,310,436


Total capitalization	$	457,321,534		$	466,292,602		$	463,622,416		$	508,150,505		$	494,733,936


Equity Ratio¹		35.3	%		34.7	%		33.7	%		30.3	%		30.2	%

Operations Data

Operating revenues	$	283,618,369		$	258,325,345		$	290,247,308		$	288,292,112		$	257,443,919

Operating expenses		262,341,866			233,967,201			264,872,577			260,580,365			232,367,023

Interest expense		18,681,680			21,014,387			21,207,600			22,979,276			24,329,991

Capitalized interest		(1,934,703	)		(1,008,689	)		(601,251	)		(446,479	)		(617,194	)

Net operating margins		4,529,526			4,352,446			4,768,382			5,178,950			1,364,099

Nonoperating margins		1,043,736			1,057,563			891,966			1,232,800			1,521,157


Assignable margins	$	5,573,262		$	5,410,009		$	5,660,348		$	6,411,750		$	2,885,256


Margins for Interest Ratio²		1.30			1.26			1.27			1.28			1.12

¹	Equity ratio equals equities and margins divided by the sum of our long-term debt and equities and margins.

²	Margins for interest ratio equals the sum of long and short-term interest expense and assignable margins divided by the sum of long and short-term interest expense, excluding amounts capitalized.

Equity ratios and margins for interest ratios are considered non-GAAP measures. We consider these ratios to be useful to users of Chugach’s financial statements and are components of financial covenants contained in Chugach’s Second Amended and Restated Indenture of Trust and debt agreements.

Item 7 – Management’s Discussion and Analysis

of Financial Condition and Results of Operations

Caution Regarding Forward Looking Statements

Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. We undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this report 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, which is a debt service coverage approach to ratemaking. 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 long-term interest expense for the years ended December 31, 2011, 2010 and 2009 was $9,669,656, $12,377,668 and $20,159,196, respectively. Chugach’s authorized TIER for ratemaking 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 includes nonoperating margins that are not generated by electric rates. We manage our business with a view towards achieving our authorized TIER (currently 1.30) averaged over a 5-year period. For further discussion on factors that contribute to TIER results, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Years ended December 31, 2011, compared to the years ended December 31, 2010, and December 31, 2009 – Expenses.” We achieved TIERs for the past three years as follows:


Year	TIER
2011		1.58
2010		1.44
2009		1.28

The temporary increase in TIER in 2011 and 2010 was due to certain debt classified as short term, which was replaced with long-term debt in 2012.

Rate Regulation and Rates. Our electric rates are made up of two primary components: “base rates” and “fuel and purchased power recovery rates.” Base rates provide the recovery of fixed and variable costs (excluding fuel and purchased power) related to providing electric service. Fuel and purchased power recovery rates provide the recovery of fuel and purchased power costs.

The RCA approves both base rates and fuel and purchased power recovery rates paid by our retail and wholesale customers. In addition, an 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. Chugach’s base rates, whether set under a general rate case or an SRF, are established to allow the continued recovery of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs, other than fuel and purchased power, and those rates are then collected from our retail and wholesale customers. Under SRF, base rate increases are limited to 8 percent over a 12-month period and 20 percent over a 36-month period. Chugach is still permitted to submit general rate case filings while participating in the SRF process. However, during these periods, rate adjustments under SRF would temporarily cease. The RCA may authorize, after a notice period, rate changes on an interim and refundable basis. Chugach implemented the SRF filing process, after receiving approval from the RCA, in the fourth quarter of 2010. Chugach has been requesting base rate adjustments under SRF on a semi-annual basis utilizing the twelve months ended June and December as the test periods in each year since that time.

On November 14, 2011, base demand and energy rates increased 2.4 percent to HEA and decreased 1.7 percent, 1.9 percent and 5.8 percent to Chugach retail customers, MEA and Seward, respectively. The base demand and energy rate changes were the result of Chugach’s SRF utilizing the twelve months ended June 30, 2011, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – June 30, 2011 Test Year Simplified Rate Filing.”

On May 16, 2011, base demand and energy rates increased 0.3 percent to Chugach retail customers and 2.2 percent to its wholesale customers. The base demand and energy rate changes were the result of Chugach’s SRF utilizing the twelve months ended December 31, 2010, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – December 31, 2010 Test Year Simplified Rate Filing.”

On November 15, 2010, base demand and energy rates increased 0.2 percent to Chugach retail customers and 0.3 percent to Seward and decreased 0.6 percent and 1.2 percent to HEA and MEA, respectively. The base demand and energy rate changes were the result of Chugach’s SRF utilizing the twelve months ended June 30, 2010, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Request for Participation in the Simplified Rate Filing Process.”

On November 1, 2010, base demand and energy rates charged to retail customers decreased 1.5 percent and base rates charged to wholesale customers HEA, MEA and Seward decreased 2.3 percent, 2.2 percent and 1.8 percent, respectively. The base demand and energy rate changes were the result of final rates associated with Chugach’s 2008 Test Year Rate Case, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2008 Test Year Rate Case.”

On October 9, 2009, base demand and energy rates charged to retail customers increased 3.3 percent and base rates charged to wholesale customers HEA, MEA and Seward increased 7.8 percent, 2.0 percent and 9.7 percent, respectively. The base demand and energy rate changes were effective on an interim and refundable basis and were the result of proposed rates included in Chugach’s 2008 Test Year Rate Case filed with the RCA on June 23, 2009, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2008 Test Year Rate Case.”

Fuel and Purchased Power Recovery. We recover fuel and purchased power costs directly from our wholesale and retail customers through the fuel and purchased power rate recovery process. Changes in fuel and purchased power costs are primarily due to fuel price adjustment mechanisms in our gas-supply contracts based on natural gas, crude oil and fuel oil indexed price changes. Other factors, including generation unit availability also impact fuel and purchased power recovery rate levels. The fuel and purchased power recovery is approved on a quarterly basis by the RCA. There are no limitations on the number or amount of fuel and purchased power recovery 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 and purchased power recovery process does not impact margins. We recognize differences between projected recoverable fuel and purchased power costs and amounts actually recovered through rates. The fuel cost under/over recovery on our Balance Sheets represent the net accumulation of any under or over collection of fuel and purchase power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods.

Years ended December 31, 2011, compared to the years ended December 31, 2010, and December 31, 2009

Margins

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


	2011		2010		2009

Net Operating Margins	$	4,529,526	$	4,352,446	$	4,768,382
Nonoperating Margins	$	1,043,736	$	1,057,563	$	891,966

Assignable Margins	$	5,573,262	$	5,410,009	$	5,660,348

The increase in net operating margins in 2011 from 2010 of $177.1 thousand, or 4.1 percent, was due to a decrease in interest and power production expense, which was somewhat offset by an increase in transmission, distribution and administrative, general and other expense. The decrease in net operating margins in 2010 from 2009 of $415.9 thousand, or 8.7 percent, was due to an increase in power production and administrative, general and other expense, which was partially offset by a decrease in interest expense, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Years ended December 31, 2011, compared to the years ended December 31, 2010, and December 31, 2009 – Expenses.”

Nonoperating margins include interest income, Allowance for Funds Used During Construction (AFUDC), capital credits and patronage capital allocations and other. Nonoperating margins did not materially change in 2011 from 2010. Higher AFUDC due to more construction activity was offset by a lower patronage capital allocation from CoBank as our investment in CoBank decreased. Nonoperating margins increased in 2010 from 2009 by $165.6 thousand, or 18.6 percent due primarily to higher interest income as a result of a higher cash balance and higher interest rates, higher Allowance for Funds Used During Construction (AFUDC) due to more construction activity and higher other nonoperating margins caused by a gain associated with the sale of land and settlement funds, which was partially offset by a lower patronage capital allocation from CoBank as our investment in CoBank decreased.

Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2011, operating revenues were $25.3 million, or 9.8 percent higher than in 2010. The increase was due primarily to higher fuel costs recovered in revenue through the fuel and purchased power recovery process, which was slightly offset by changes in rates charged to our retail and wholesale customers.

In 2010, operating revenues were $31.9 million, or 11.0 percent lower than in 2009. The decrease was due primarily to lower fuel and purchased power costs recovered in revenue through the fuel recovery process.

Overall, retail revenue increased in 2011 from 2010. The increase was due primarily to higher fuel costs recovered in revenue through the fuel and purchased power recovery process, which was slightly offset by lower kWh sales and lower net rates charged to retail customers.

Overall, retail revenue decreased in 2010 from 2009. The decrease was due primarily to lower fuel and purchased power costs recovered in revenue through the fuel recovery process. Lower kWh sales, which also contributed to the variance was somewhat offset by higher net rates charged to retail customers as a result of the 2008 Test Year Rate Case and September 28, 2010, SRF.

Wholesale revenue increased in 2011 from 2010. The increase was due primarily to higher fuel costs recovered in revenue through the fuel and purchased power recovery process and higher kWh sales.

Wholesale revenue decreased in 2010 from 2009. The decrease was due primarily to lower fuel and purchased power costs recovered in revenue through the fuel recovery process. Lower kWh sales were somewhat offset by higher net rates charged to wholesale customers as a result of the 2008 Test Year Rate Case and September 28, 2010, SRF.

Based on the results of fixed and variable cost recovery established in Chugach’s rate filings, wholesale sales to MEA, HEA and Seward contributed approximately $27.6 million, $27.2 million and $28.6 million to Chugach’s fixed costs for the years ended December 31, 2011, 2010 and 2009, 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, 2011, and 2010.


	Base Rate Sales Revenue							Fuel and Purchased Power Revenue							Total Revenue
	2011		2010		% Variance			2011		2010		% Variance			2011		2010		% Variance

Retail
Residential	$	45.1	$	45.5		(0.9	%)	$	32.5	$	26.9		20.8	%	$	77.6	$	72.4		7.2	%
Small Commercial	$	7.6	$	7.5		1.3	%	$	7.1	$	5.8		22.4	%	$	14.7	$	13.3		10.5	%
Large Commercial	$	27.5	$	28.3		(2.8	%)	$	30.2	$	24.6		22.8	%	$	57.7	$	52.9		9.1	%
Lighting	$	1.2	$	1.3		(7.7	%)	$	0.2	$	0.2		0.0	%	$	1.4	$	1.5		(6.7	%)
Total Retail	$	81.4	$	82.6		(1.5	%)	$	70.0	$	57.5		21.7	%	$	151.4	$	140.1		8.1	%

Wholesale
HEA	$	12.1	$	11.9		1.7	%	$	27.1	$	21.3		27.2	%	$	39.2	$	33.2		18.1	%
MEA	$	21.8	$	21.4		1.9	%	$	43.0	$	34.5		24.6	%	$	64.8	$	55.9		15.9	%
SES	$	1.4	$	1.4		0.0	%	$	3.6	$	2.8		28.6	%	$	5.0	$	4.2		19.0	%
Total Wholesale	$	35.3	$	34.7		1.7	%	$	73.7	$	58.6		25.8	%	$	109.0	$	93.3		16.8	%

Economy Sales	$	1.6	$	4.0		(60.0	%)	$	18.7	$	18.1		3.3	%	$	20.3	$	22.1		(8.1	%)
Miscellaneous	$	2.2	$	2.8		(21.4	%)	$	0.7	$	0.0		100.0	%	$	2.9	$	2.8		3.6	%

Total Revenue	$	120.5	$	124.1		(2.9	%)	$	163.1	$	134.2		21.5	%	$	283.6	$	258.3		9.8	%

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, 2010, and 2009.


	Base Rate Sales Revenue							Fuel and Purchased Power Revenue							Total Revenue
	2010		2009		% Variance			2010		2009		% Variance			2010		2009		% Variance

Retail
Residential	$	45.5	$	45.0		1.1	%	$	26.9	$	37.3		(27.9	%)	$	72.4	$	82.3		(12.0	%)
Small Commercial	$	7.5	$	8.0		(6.3	%)	$	5.8	$	7.9		(26.6	%)	$	13.3	$	15.9		(16.4	%)
Large Commercial	$	28.3	$	27.8		1.8	%	$	24.6	$	34.5		(28.7	%)	$	52.9	$	62.3		(15.1	%)
Lighting	$	1.3	$	1.3		0.0	%	$	0.2	$	0.3		(33.3	%)	$	1.5	$	1.6		(6.3	%)
Total Retail	$	82.6	$	82.1		0.6	%	$	57.5	$	80.0		(28.1	%)	$	140.1	$	162.1		(13.6	%)

Wholesale
HEA	$	11.9	$	11.8		0.8	%	$	21.3	$	31.1		(31.5	%)	$	33.2	$	42.9		(22.6	%)
MEA	$	21.4	$	21.9		(2.3	%)	$	34.5	$	47.8		(27.8	%)	$	55.9	$	69.7		(19.8	%)
SES	$	1.4	$	1.3		7.7	%	$	2.8	$	4.4		(36.4	%)	$	4.2	$	5.7		(26.3	%)
Total Wholesale	$	34.7	$	35.0		(0.9	%)	$	58.6	$	83.3		(29.7	%)	$	93.3	$	118.3		(21.1	%)

Economy Sales	$	4.0	$	1.2		233.3	%	$	18.1	$	6.1		196.7	%	$	22.1	$	7.3		202.7	%
Miscellaneous	$	2.8	$	2.6		7.7	%	$	0.0	$	0.0		0.0	%	$	2.8	$	2.6		7.7	%

Total Revenue	$	124.1	$	120.9		2.6	%	$	134.2	$	169.4		(20.8	%)	$	258.3	$	290.3		(11.0	%)

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


	2011		2011		2010		2010		2009		2009
	Sales (MWh)		Revenue		Sales (MWh)		Revenue		Sales (MWh)		Revenue

Retail		1,166,336	$	151,474,488		1,169,430	$	140,110,304		1,183,705	$	162,101,007
Wholesale:
HEA		475,098		39,154,889		454,223		33,189,789		472,136		42,865,550
MEA		763,339		64,818,326		743,212		55,937,931		740,358		69,685,271
Seward		64,261		5,031,622		61,651		4,188,989		62,509		5,711,358

Total Wholesale		1,302,698		109,004,837		1,259,086		93,316,709		1,275,003		118,262,179
Economy energy		235,378		20,270,059		278,093		22,141,341		76,968		7,280,870
Other		N/A		2,868,985		N/A		2,756,991		N/A		2,603,252

Total		2,704,412	$	283,618,369		2,706,609	$	258,325,345		2,535,676	$	290,247,308

Since 1989, we have sold economy (non-firm) energy to GVEA under an agreement that expired on March 31, 2009. Under that agreement, we used available generation in excess of our own needs to produce electric energy for sale to GVEA, which used that energy to serve its own loads in place of more expensive energy that it would have otherwise generated itself or purchased from other sources. We purchased gas from Marathon to produce energy for sale to GVEA. Chugach negotiated a three-month gas sales agreement, spanning September through November of 2009, which was later extended through December 31, 2009, with Marathon, to provide between 5,000 and 7,000 Mcf per day to facilitate a 20 MW economy energy sale to GVEA. On April 6, 2010, Chugach and GVEA finalized an agreement for Chugach to provide a minimum of 20 MW of economy energy to GVEA on a non-firm basis based on an interruptible gas supply arrangement, which Chugach entered into with UNOCAL to supply gas for economy energy sales to GVEA. The agreement commenced on May 1, 2010, and will continue through March 31, 2013. The price to GVEA will include the cost of fuel (based on a system average heat rate), plus variable operations and maintenance expense, plus a margin. Sales will be made under the terms and conditions of Chugach’s economy energy sales tariff approved by the RCA.

In 2011, 2010, and 2009, economy sales to GVEA constituted approximately 7 percent, 9 percent, and 3 percent, respectively, of our sales revenues. Economy energy revenue decreased in 2011 from 2010 due to scheduled maintenance and gas supply restrictions that limited our ability to makes sales to GVEA. Economy energy revenue increased in 2010 from 2009 due to the agreement Chugach finalized with GVEA on April 6, 2010.

Expenses

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


	2011		2010		2009
Fuel	$	139,179,413	$	111,718,947	$	136,416,761
Power production		16,853,232		18,248,656		16,406,911
Purchased power		25,861,814		26,691,968		35,690,476
Transmission		6,809,401		5,697,446		5,709,578
Distribution		13,387,477		12,216,252		12,740,381
Consumer accounts		5,465,315		5,323,551		5,259,348
Administrative, general and other		22,169,039		21,434,273		20,518,688
Depreciation		32,616,175		32,636,108		32,130,434

Total operating expenses	$	262,341,866	$	233,967,201	$	264,872,577

Fuel

Chugach recognizes actual fuel expense as incurred. Fuel expense increased $27.5 million, or 24.6 percent, in 2011 from 2010 due primarily to a higher average effective fuel price and an increase in Mcf used as a result of scheduled maintenance on our more efficient units and less hydro availability in 2011. In 2011, Chugach used 29,264,342 Mcf of fuel at an average effective price of $5.41 per Mcf, which did not include 3,584,001 Mcf of fuel that is recorded as purchased power expense. Fuel expense decreased $24.7 million, or 18.1 percent, in 2010 from 2009 due primarily to a lower average effective fuel price, which was somewhat offset by an increase in Mcf used as a result of higher economy sales. In 2010, Chugach used 28,908,216 Mcf of fuel at an average effective price of $4.38 per Mcf, which did not include 3,409,580 Mcf of fuel that is recorded as purchased power expense.

Power Production

Power production expense decreased $1.4 million, or 7.6 percent, in 2011 from 2010. Maintenance on Beluga units 1 and 3 and costs associated with the Bernice Lake water injection system in 2011 were lower than maintenance associated with Beluga unit 6 and Bernice Lake units 3 and 4 in 2010. Power production expense increased $1.8 million, or 11.2 percent, in 2010 from 2009 due primarily to maintenance associated with Beluga unit 6 and Bernice Lake units 3 and 4, which was partially offset by a decrease in maintenance associated with Beluga unit 8.

Purchased Power

Purchased power costs, which included the cost of 3,584,001 Mcf of fuel associated with purchases from the Nikiski Cogeneration plant, did not materially change in 2011 from 2010. A decrease in MWh purchased was offset by an increase in the average effective price. In 2011, Chugach purchased 440,254 MWh of energy at an average effective price of 5.49 cents per kWh. Purchased power costs, which included the cost of 3,409,580 Mcf of fuel associated with purchases from the Nikiski Cogeneration plant, decreased $9.0 million, or 25.2 percent, in 2010 from 2009 due primarily to a lower average effective price caused by lower fuel prices. In 2010, Chugach purchased 504,205 MWh of energy at an average effective price of 5.01 cents per kWh.

Transmission

Transmission expense increased $1.1 million, or 19.5%, in 2011 from 2010 due primarily to higher substation and overhead line maintenance caused by weather related outages and equipment failure response. Transmission expense did not materially change in 2010 from 2009.

Distribution

Distribution expense increased $1.2 million, or 9.6%, in 2011 from 2010 due primarily to higher overhead line maintenance caused by weather related outages. Distribution expense did not materially change in 2010 from 2009.

Consumer Accounts

Consumer Accounts did not materially change in 2011 from 2010 or in 2010 from 2009.

Administrative, General and Other Charges

Overall, administrative, general and other charges did not materially change in 2011 from 2010, however, an increase in legal fees associated with the Fire Island Wind Purchase Power Agreement and the write off of obsolete materials, inventory and cancelled projects was offset by a decrease in the amortization of deferred gas contract negotiations and workers compensation claims. Overall, administrative, general and other charges did not materially change in 2010 from 2009, however, an increase in current costs associated with prior workers compensation claims, labor and indirect labor associated with vacation and cash in lieu and the amortization of gas contract negotiations was offset by a decrease in other deductions caused by the write off of obsolete inventory and cancelled projects in 2009.

Depreciation

Depreciation expense did not materially change in 2011 from 2010 or in 2010 from 2009.

Interest

Interest on long-term debt and other decreased $2.3 million, or 11.1 percent, in 2011 from 2010 due primarily to the rates associated with the 2011 bonds which were used to refinance the 2001 Series A Bonds on March 15, 2011, which was somewhat offset by an increase in the amount of commercial paper outstanding in 2011 compared to 2010. Interest on long-term debt and other did not materially change in 2010 from 2009.

Interest charged to construction increased $926.0 thousand, or 91.8 percent, in 2011 from 2010 due primarily to a higher average balance in Construction Work In Progress, primarily due to capital spending associated with the SPP, which was slightly offset by a lower weighted average rate during 2011 of 4.1 percent compared to 4.8 percent during 2010.

Interest charged to construction increased $407.4 thousand, or 67.8 percent, in 2010 from 2009 due primarily to a higher average balance in Construction Work In Progress, primarily due to capital spending associated with the SPP, which was slightly offset by a lower weighted average rate during 2010 of 4.8 percent compared to 4.9 percent during 2009.

Patronage Capital (Equity)

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


	2011			2010			2009

Patronage capital at beginning of year	$	149,543,952		$	144,228,221		$	142,009,998
Retirement of capital credits		(6,761,968	)		(94,278	)		(3,442,125	)
Assignable margins		5,573,262			5,410,009			5,660,348

Patronage capital at end of year		148,355,246			149,543,952			144,228,221
Other equity¹		12,876,180			12,298,332			12,092,376

Total equity at end of year	$	161,231,426		$	161,842,284		$	156,320,597

¹	Other equity includes memberships, donated capital and gain on capital credit retirements.

We credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves. These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of distributions of these amounts to members, also known as capital credits, is at the discretion of our Board. We currently have a practice of retiring patronage capital on a first-in, first-out basis for retail customers. The Board may also return capital credits to former members and estates who have requested early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September 2002. Chugach retired $309,188, $94,278, and $3,442,125 in capital credits for the years ended December 31, 2011, 2010, and 2009, respectively. The 2011 retirement of capital credits includes the reclassification of HEA’s patronage capital to patronage capital payable of $6.5 million, see “Item 8 – Financial Statements and Supplementary Data – Note 15 – Commitments and Contingencies – Patronage Capital Payable.” 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. In 2011 and 2010, no wholesale capital credits were retired. In 2009, $1,674,809 of 1999 wholesale capital credits was retired to MEA, HEA and SES pursuant to a prior settlement agreement.

Under the Second Amended and Restated Indenture of Trust, which became effective January 20, 2011, and the Amended and Restated Master Loan Agreement with CoBank, which became effective January 19, 2011, Chugach is prohibited from making any distribution of patronage capital to Chugach’s customers if an event of default under the Amended and Restated Master Loan Agreement exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30 percent of Chugach’s total liabilities and equities and margins.

During 2008, the Board of Directors approved the deferral of capital credit retirements after 2009, excluding discounted capital credits, due to the construction of new generation and the anticipated loss of wholesale load in 2014.

Changes in Financial Condition

Assets

Total assets increased $223.2 million, or 35.4 percent, from December 31, 2010, to December 31, 2011. The increase was due in part to a $89.9 million, or 17.7 percent, increase in net utility plant due to extension and replacement of plant in excess of depreciation expense and a $122.0 million, or 100 percent, increase in restricted cash equivalents caused by the funds held to retire the 2002 Series A Bonds due February 1, 2012. The increase was also caused by a $7.2 million, or 20.6 percent, increase in accounts receivable caused primarily by higher fuel costs recovered through the fuel and purchased power recovery process. Deferred charges increased $4.2 million, or 20.1 percent, caused by costs associated with financing and commercial paper renewal which exceeded the amortization of other deferred charges. The sale of the Bernice Lake power plant contributed to a cash and cash equivalents increase of $5.0 million, or 41.8 percent, from December 31, 2010, to December 31, 2011. These increases were offset by a $1.0 million, or 8.5 percent, decrease in investments in associated organizations caused by a CoBank equity retirement in March of 2011 and a $1.2 million, or 48.8 percent, decrease in fuel cost under-recovery due to the collection of fuel and purchased power costs through the fuel recovery process. The increases were also offset by a $3.0 million, or 8.3 percent, decrease in materials and supplies caused primarily by the use of inventory for generation projects in 2011.

Liabilities

Total liabilities increased by $223.2 million, or 35.4 percent, in 2011 as compared to 2010. Contributors to this change include a $76.5 million, or 77.7 percent, increase in commercial paper outstanding due to the continued construction of the SPP and a $3.9 million, or 20.9 percent, increase in accounts payable primarily caused by the timing of cash payments on invoices for goods and services and capital spending. Accrued interest increased $793.9 thousand, or 13.1 percent, due primarily to the additional interest associated with the 2011 bonds. The net of total long-term obligations and current installments of long-term obligations increased $122.1 million due primarily to the scheduled payment of the 2002 Series A Bonds. Fuel payable increased by $2.8 million, or 13.1 percent, caused by an increase in fuel costs and the timing of cash payments on invoices for fuel and salaries, wages and benefits payable increased $863.8 thousand, or 12.8 percent, caused by an increase in benefit costs and the timing of cash payments on accrued labor. Other liabilities increased $1.5 million, or 79.0 percent, due primarily to an increase in the municipal underground ordinance payable. Patronage capital payable increased $6.6 million, or 100 percent, caused by the reclassification of HEA’s patronage from equities and margins and deposit on sale of asset increased $9.5 million, or 100 percent, due to the sale of the Bernice Lake power plant. Deferred credits also increased by $327.4 thousand, or 23.8 percent, caused by an increase in Chugach’s postretirement benefit obligation. These increases were offset by a $1.3 million, or 24.4 percent, decrease in consumer deposits caused by a decrease in customer prepaid accounts.

Equities and Margins

Total margins and equities did not materially change in 2011 from 2010. The increase in patronage capital caused by the margins generated in 2011 was offset by the reclassification of HEA’s patronage to patronage capital payable.

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 2011. 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 recovery process, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not significantly affect our operations.

Contractual Obligations and Commercial Commitments

The following are Chugach’s contractual and commercial commitments as of December 31, 2011:

Contractual cash obligations – Payments Due By Period


(In thousands)	Total		2012		2013-2014		2015-2016		Thereafter

Long-term debt, including current portion	$	429,450	$	133,360	$	25,676	$	26,506	$	243,908
Long-term interest expense¹		343,999		23,985		45,606		41,526		232,882
Commercial Paper²		175,000		175,000		0		0		0
Bradley Lake³		40,371		3,621		7,230		7,326		22,194
Fuel and fuel transportation expense⁴		474,634		132,692		195,690		54,530		91,722
SPP Contracts⁵		96,100		96,100		0		0		0
Capital credit retirements⁶		7,396		250		250		250		6,646

Total	$	1,566,950	$	565,008	$	274,452	$	130,138	$	597,352

¹	Long-term interest expense includes fixed and variable rates. Variable rates are based on rates at December 31, 2011, for years 2012-2016 and thereafter, see “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt.”

At December 31, 2011, Chugach’s Commercial Paper Program was backed by a $300 million Unsecured Credit Agreement between NRUCFC, Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, which funds capital requirements. At December 31, 2011, there was $175.0 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $125.0 million and could be used for future operational and capital funding requirements.

³	Estimated annual cost

⁴	Estimated committed fuel and fuel transportation expense

⁵	In accordance with contractual commitments associated with the SPP

⁶	Estimated capital credit retirements

Purchase obligations

Chugach is a participant and has a 30.4 percent share in the Bradley Lake hydroelectric project, see “Item 2 – Properties-Other Property-Bradley Lake.” This contract runs through 2041. We have agreed to pay a like percentage of annual costs of the project, which has averaged $4.9 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 ConocoPhillips and Marathon, see “Item 2 – Properties-Fuel Supply-ConocoPhillips-Marathon Alaska Production.” 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 recovery process, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations-Results of Operations-Overview-Rate Regulation and Rates-Fuel Recovery.”

Chugach is in the process of developing a natural gas-fired generation plant on land owned by Chugach near its Anchorage headquarters. The SPP will be developed and owned by Chugach and ML&P as tenants in common. Chugach will own and take approximately 70 percent of the new plant’s output and ML&P will own and take the remaining output. Chugach will proportionately account for its ownership in the SPP. On November 17, 2008, Chugach executed a gas turbine purchase agreement for the purchase of three gas turbines with General Electric Packaged Power (GEPP). During 2009 Chugach executed several amendments associated with its purchase agreement with GEPP, which included the purchase of a spare engine for maintenance purposes. Chugach executed an Owner’s Engineer Services Contract on May 12, 2009. On January 5, 2010, Chugach executed a Services Contract for the shipment of the combustion turbine generators and related accessories. On February 25, 2010, Chugach purchased land adjacent to its Anchorage headquarters for the laydown of equipment displaced by the new power plant. On April 13, 2010, Chugach executed a steam turbine generator (STG) purchase agreement. On June 18, 2010, Chugach executed an Engineering, Procurement, and Construction (EPC) contract with SNC-Lavalin Constructors, Inc. (SLCI). On August 27, 2010, Chugach executed a Once Through Steam Generator (OTSG) equipment contract with Innovative Steam Technologies (IST). Chugach amended the contract for transportation of combustion turbine generators on September 28, 2010, to include transportation of the steam turbine generator. On December 20, 2010, Chugach received a construction permit from the Alaska Department of Environmental Conservation allowing the project to begin construction in spring of 2011 as planned. On March 15, 2011, Chugach received its initial building permit from the Municipality of Anchorage. Chugach made payments of $130.5 million in 2011 and $74.3 million in 2010, with additional payments of $96.1 million expected in 2012, pursuant to all these contracts.

Liquidity And Capital Resources

We ended 2011 with $17.1 million of cash and cash equivalents, up from $12.1 and $3.5 million at December 31, 2010 and 2009, respectively. Cash equivalents consist of all highly liquid debt instruments with a maturity of three months or less when purchased, an Overnight Repurchase Agreement and Concentration account with First National Bank Alaska (FNBA) and a money market account with UBS Financial Services.

The following table summarizes our cash flows from operating, investing and financing activities for the periods ended December 31:


	2011			2010			2009
Total cash provided by (used in):

Operating activities	$	40,811,795		$	39,151,441		$	42,409,427
Investing activities		(232,988,854	)		(72,903,232	)		(38,100,312	)
Financing activities		197,224,464			42,318,739			(8,296,652	)


Increase (decrease) in cash and cash equivalents	$	5,047,405		$	8,566,739		$	(3,987,537	)

Operating activities in 2011 were primarily impacted by changes in accounts receivable, fuel cost over and under recovery, materials and supplies, other assets, deferred charges, accounts payable, consumer deposits and fuel. Operating activities in 2010 were primarily impacted by changes in fuel cost over and under recovery, materials and supplies, fuel and other liabilities. In 2009, changes included fuel cost over and under recovery, materials and supplies and fuel.

Investing activities in 2011 were primarily impacted by restricted cash equivalents and expenditures associated with the SPP. Investing activities in 2010 and 2009 were primarily impacted by expenditures associated with the SPP.

Financing activities in 2011 were primarily impacted by proceeds and payments of long-term debt and the amount of commercial paper used to finance expenditures associated with the SPP. Financing activities in 2010 and 2009 were primarily impacted by changes in the amount of commercial paper used to finance expenditures associated with the SPP and the retirement of patronage capital and estate payments.

Sources of Liquidity

Chugach has satisfied its operational and capital cash requirements through internally generated funds, a $50 million line of credit from NRUCFC and a $300 million Commercial Paper Program. At December 31, 2011, there was no outstanding balance on our NRUCFC line of credit and $175.0 million of outstanding commercial paper. Thus, at December 31, 2011, our available borrowing capacity under our line of credit was $50 million and our available commercial paper capacity was $125.0 million. On January 12, 2012, Chugach had $181 million of outstanding commercial paper, which Chugach repaid with proceeds from the $250 million 2012 Series A Bond issuance, that will amortize through 2042. The balance of the proceeds from the 2012 Series A Bond issuance is expected to be sufficient to fund the remaining expenditures associated with the SPP. Our available commercial paper capacity on January 12, 2012, was $300 million.

On November 17, 2010, Chugach replaced the $300 million unsecured Credit Agreement executed on October 10, 2008, which was due to expire on October 10, 2011. Information concerning our Commercial Paper Program and the 2010 Credit Agreement are described in Note 11 to the financial statements, see “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt – Commercial Paper.”

A table providing information regarding monthly average commercial paper balances outstanding and corresponding weighted average interest rates are described in Note 11 to the financial statements, see “Item 8 – Financial Statements and Supplementary Data- Note 11 – Debt – Commercial Paper.”

Chugach has a term loan facility with CoBank. Since January 22, 2003, loans made under that facility were evidenced by promissory notes governed by a Master Loan Agreement. On January 19, 2011, Chugach and CoBank amended and restated the existing Master Loan Agreement. The existing obligations under the loan are evidenced by a promissory note dated January 19, 2011, and secured by the Second Amended and Restated Indenture of Trust dated January 20, 2011. At December 31, 2010, Chugach had $34.5 million outstanding with CoBank.

Under the Second Amended and Restated Indenture of Trust, additional obligations may be sold by Chugach upon the basis of bondable additions and the retirement or defeasance of or principal payments on previously outstanding obligations. The beginning balance of bondable additions on January 20, 2011, was $322.2 million, which would support the issuance of additional debt of approximately $293.0 million. On March 15, 2011, Chugach used $5.5 million of bondable additions to pay financing costs associated with the 2011 Series A Bond transaction. On January 11, 2012, Chugach used $275.0 million of bondable additions when it issued $250.0 million of 2012 Series A Bonds. The balance of bondable additions after the January 11, 2012, transaction was $38.2 million, which would support the issuance of additional debt of approximately $35.0 million. Chugach’s bondable additions balance is a reflection of its beginning balance less property retirements. Chugach has yet to certify additional property additions since September 30, 2010. Chugach’s ability to sell debt obligations will be dependent on the market’s perception of Chugach’s financial condition and credit rating, and Chugach’s continuing compliance with the financial covenants, including the rate covenant, contained in the Second Amended and Restated Indenture of Trust and its other credit documents. No assurance can be given that Chugach will be able to sell additional debt obligations even if otherwise permitted under the Second Amended and Restated Indenture of Trust.

Financing

Information concerning our Financings are described in Note 11 to the financial statements, see “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt – Financing.”

Principal maturities of our outstanding long-term indebtedness at December 31, 2011, including the subsequent $250 million 2012 Series A Bonds issued on January 11, 2012, are set forth below:


Year Ending December 31	Principal Maturities		2012 Series A Bonds		Total

2012	$	133,360,210	$	0	$	133,360,210
2013		12,743,022		11,750,000		24,493,022
2014		12,932,812		11,750,000		24,682,812
2015		13,139,777		10,750,000		23,889,777
2016		13,365,980		10,750,000		24,115,980
Thereafter		243,908,517		205,000,000		448,908,517

	$	429,450,318	$	250,000,000		679,450,318

During 2011 we spent approximately $123.7 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 2012 through 2016 as contained in the Capital Improvement Plan (CIP), which was approved by the board on November 17, 2011:


Year	Estimated Expenditures
2012	$	103.6 million
2013	$	32.3 million
2014	$	29.8 million
2015	$	15.8 million
2016	$	15.1 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

Completing the construction of a new, highly efficient power generation facility, finalizing our financing plans, managing natural gas contracts and securing replacement revenue sources for wholesale customer loads that will be leaving in 2014, all while controlling operating expenses to minimize adverse customer rate impacts, are some of the major challenges Chugach has faced and will continue to face in the near and intermediate term. These issues, along with energy issues and plans at the state level, will shape how Chugach proceeds into the future.

Chugach has partnered with ML&P to construct and jointly own a new 183-megawatt (MW) natural gas fired power plant. Chugach will own and take 70 percent of the new plant’s output and ML&P will own and take the remaining 30 percent. The plant is scheduled to be placed into service in 2012. Chugach’s financing for the project was primarily completed in January of 2012 with the issuance of the 2012 Series A Bonds. In 2010, the RCA concluded that Chugach may include in future rates $197 million in costs attributable to three principal contracts to build the SPP when the plant becomes used and useful. Chugach will request approval of the additional costs associated with the project in a general rate case that is expected to be filed in 2012.

We continue to actively manage our fuel supply needs. We currently have contracts in place to fill 100 percent of our needs through December 2014, approximately 70 percent of our needs through 2015 and approximately 40 percent in 2016. The State of Alaska Department of Natural Resources (DNR) completed a preliminary engineering and geological evaluation of the remaining Cook Inlet gas reserves in December of 2009. The study identified 863 billion cubic feet (BCF) of proven, developed, producing reserves, additional probable reserves of 279 BCF and an additional increment of 353 BCF in high-confidence pay intervals. Combined, these 1.5 trillion cubic feet of gas reserves are similar to the 1.4 trillion cubic feet of gas reserves identified in a 2004 study undertaken by the Department of Energy. Given current demand and deliverability, DNR estimates a minimum 10-year supply of gas exists in currently producing leases. DNR does note that economic considerations will play a major role in whether producers continue undertaking additional drilling and development activities to meet demand. An updated June 2011 DNR report titled “Cook Inlet Natural Gas Production Cost Study” further quantified the economic considerations, see “Item 1A – Risk Factors – Fuel Supply.”

The 2010 Alaska Legislature passed legislation that provides incentives to natural gas producers to enhance Cook Inlet oil and gas production. There are currently two independent producers who are in the process of mobilizing to-or using-jack-up drill rigs in Cook Inlet to take advantage of those incentives. Other producers have recently drilled conventional wells. Although it is too early to tell if the incentives will pay off, independent producers do seem to be taking steps to enter the market. 2011 Cook Inlet petroleum lease sales are up three-fold from last year and Buccaneer Energy recently announced success of the Kenai Loop No. 1 gas well in the city of Kenai, Alaska. Chugach, other utilities and industrials have formed a study group to evaluate liquefied natural gas (LNG) import options. LNG imports could be necessary by 2015. In addition to following exploration and production activity in the Cook Inlet area, Chugach is also closely monitoring potential pipeline options from the North Slope and is reviewing LNG options if Cook Inlet production does not keep pace with current field decline levels.

ConocoPhillips Alaska purchased Marathon Oil’s 30% share of the Kenai LNG plant effective September 26, 2011. ConocoPhillips and Marathon Oil had previously announced they would be ceasing exports from the LNG facility at Nikiski and putting it in “preservation mode,” leaving future options open. Operations were extended into November and in December ConocoPhillips announced that exports are expected to resume in the second half of 2012.

Utility plans for additional gas storage are on schedule for completion in April of 2012. Cook Inlet Natural Gas Storage Alaska (CINGSA) is a project to develop a gas storage facility using a partially depleted underground reservoir. The facility will have an initial storage capacity of 11 BCF so that local utilities, including Chugach, will have gas available to meet deliverability requirements during peak periods. Chugach’s share of the initial capacity is 2.4 BCF in 2012, reducing to 2.3 BCF in 2013. Injections into the facility are expected to begin in mid 2012 and withdrawals of gas are expected to begin in the winter of 2012-2013. Chugach is entitled to withdraw gas at a rate of up to 35 million cubic feet (MMcf) per day in 2012-2013. The RCA approved inception rates and a tariff for the CINGSA facility on January 31, 2011 and an FSS Service Agreement between the seller and Chugach in July of 2011.

Notification was made by MEA in 2004 and by HEA in 2007 that neither organization intends to be on the Chugach system under the current contractual arrangements post 2014. This would result in a loss of approximately 50 percent of Chugach’s power sales load and approximately 40 percent of the utility’s annual sales revenue.

On April 13, 2010, HEA issued a press release stating that HEA’s solely-owned power generation and transmission entity, AEEC, approved a design engineer to complete design for the Nikiski generation conversion project. AEEC currently owns a 40 MW natural gas-fired generation plant that is dispatched as part of Chugach’s overall system. The conversion project entails adding a steam turbine and increasing the output of the plant to 77 MW. HEA intends to purchase all of the output from this unit upon expiration of the Chugach contract in 2013. On July 12, 2011, Chugach, AEEC and HEA entered into an Asset Purchase and Sale Agreement

whereby Chugach has agreed to sell and AEEC has agreed to purchase the Bernice Lake Power Plant and associated transmission substation facilities located in Nikiski. The Bernice Lake facility is located on land that is leased to Chugach by HEA. The current lease expires on November 30, 2011 but has been extended by HEA to be consistent with the closing date contained in the Asset Purchase and Sale Agreement. Associated with the Asset Purchase and Sale Agreement described above, Chugach also entered into an Agreement for Sale of Electric Capacity with AEEC and HEA (Capacity Agreement). The agreement is a purchased power agreement that allows Chugach to purchase the capacity and related energy from the Bernice Lake Power Plant from the closing date of the sale of the facility (Asset Purchase and Sale Agreement) to AEEC through December 31, 2013. This agreement allows Chugach to sell the Bernice Lake Power Plant and simultaneously ensure system retail and wholesale deliverability requirements are met through December 31, 2013. Chugach submitted the Capacity Agreement to the RCA on July 21, 2011. The agreements were approved by the RCA on December 23, 2011, with an effective date of December 31, 2011. In the order, the RCA approved Chugach’s request to recover all capacity purchased power costs through its fuel and purchased power process.

Chugach proposed a power supply offer to MEA on January 11, 2011, and again on January 31, 2012. Chugach received a response on February 29, 2012, indicating that MEA was following the path its membership most favored and is moving forward with plans to build its own generation plant. Chugach has been preparing for the loss of two of its wholesale customers for some time and has taken steps to reduce costs in order to mitigate the rate impact to our remaining customers. Financial management plan scenarios indicate Chugach can sustain operations and meet financial covenants in the event these two customers leave the system. Chugach is also pursuing replacement sources of revenue through potential new firm power sales agreements and transmission wheeling and ancillary services tariff revisions. We believe that cost reduction and containment, successful implementation of new power sales agreements and revised tariffs will mitigate anticipated rate increases in the 2014 and 2015 timeframe. However, we cannot assure that we will be able to replace sources of revenue or that any replacement of revenue sources, revised tariffs or our cost reduction and containment measures will fully counteract any anticipated rate increases in this timeframe.

On June 23, 2011, Chugach submitted a request to the RCA for approval of a new power purchase agreement between Chugach and Fire Island Wind, LLC (FIW), a special purpose entity wholly-owned by Cook Inlet Region, Inc. The project is comprised of eleven 1.6-megawatt wind turbine generators with a total nameplate capacity of 17.6 megawatts. The generators will be located on the southern part of Fire Island in Anchorage, Alaska. The transmission line will be paid for by a $25 million grant awarded by the State Legislature. The project is scheduled to be commercially operational by October 1, 2012. On October 10, 2011, the RCA issued an order approving Chugach’s request for assurance of cost recovery associated with the PPA and also granted approval for Chugach to recover costs associated with the PPA through its fuel and purchased power recovery process. Chugach is also investigating the potential development of a green pricing program related to this project. Negotiations between Chugach and FIW will continue in 2012 to finalize construction of the transmission interconnection and allow FIW to acquire financing.

Five Railbelt electric utilities have joined together to create a new organization that will help plan, construct and operate key components of the regional electric grid. The organization, Alaska Railbelt Cooperative Transmission and Electric Company (ARCTEC) is a generation and

transmission cooperative organized under existing state law. Chugach, GVEA, HEA, MEA and Seward organized the G&T to provide a framework for collective action on projects of mutual benefit. Each of the organizations has two seats on the 10-member board of directors. Another advantage of ARCTEC is its ability to prioritize capital project requests and speak with a unified regional voice at the state Capitol. ARCTEC was incorporated on December 23, 2010.

A State of Alaska Energy Policy approved by the legislature in 2010 included legislative intent that the state achieve a 15 percent increase in energy efficiency on a per capita basis between 2010 and 2020, receive 50 percent of its electric generation from renewable and alternative energy sources by 2025, work to ensure a reliable in-state gas supply for residents of the state, the state power project fund serve as the main source of state assistance for energy projects, remain a leader in petroleum and natural gas production and become a leader in renewable and alternative energy development. The main project moving Alaska toward its renewable energy goals includes the Susitna-Watana Hydroelectric Project. The project is to be located on the Susitna River, approximately halfway between Anchorage and Fairbanks. The project capacity is expected to be between 600 to 800 megawatts and could provide up to half the electric energy needed in the Railbelt. The 2012 fiscal year State of Alaska capital budget contained $65.7 million for the Alaska Energy Authority (AEA) to conduct planning, design and permitting for this project and on December 29, 2011, AEA filed an application with FERC to begin the licensing process. Chugach will work with AEA and other parties on this effort.

Many other energy projects also received funding in the 2012 fiscal year State of Alaska capital budget, including nine Railbelt projects supported by ARCTEC. The $36 million in grants for these projects will also flow through the AEA. Chugach continues to coordinate with other parties, including private developers and other utilities in the planning and potential development of other renewable energy resources, including geothermal, tidal, wind power, hydro and waste-to-energy projects.

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 2 to the financial statements, see “Item 8 – Financial Statements and Supplementary Data – Significant Accounting Policies.” 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, 2011.

Electric Utility Regulation

Chugach is subject to regulation by the RCA. The RCA sets the rates Chugach is permitted to charge customers based on our specific allowable costs. As a result, Chugach applies FASB ASC 980, “Topic 980 – Regulated Operations.” Through the ratemaking process, the regulators may require the inclusion of costs or revenues in periods different than when they would be recognized by a non-regulated company. This treatment may result in the deferral of expenses and the recording of related regulatory assets based on anticipated future recovery through rates or the deferral of gains or creation of liabilities and the recording of related regulatory liabilities. The application of FASB ASC 980 has a further effect on Chugach’s financial statements as a result of the estimates of allowable costs used in the ratemaking process. These estimates may differ from those actually incurred by Chugach; therefore, the accounting estimates inherent in specific costs such as depreciation and pension and post-retirement benefits have less of a direct impact on Chugach’s results of operations than they would on a non-regulated company. As reflected in the financial statements, see “Item 8 -Financial Statements and Supplementary Data – Note 2j – 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 $8,977,409 and $8,612,454 of unbilled retail revenue at December 31, 2011 and 2010, respectively.

New Accounting Standards

Information concerning New Accounting Standards are described in Note 3 to the financial statements, see “Item 8 -Financial Statements and Supplementary Data – Note 3 – Recent Accounting Pronouncements.”

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

At December 31, 2011, our short- and long- term debt was comprised of our 2002 and 2011 Series A Bonds, our CoBank bond and outstanding commercial paper.

The interest rate of our 2002 Series A Bonds is fixed at 6.20 percent, per annum. The interest rates of our 2011 Series A Bonds due 2031 and 2041 are fixed at 4.20 and 4.75 percent, per annum, respectively. At December 31, 2011, we had $120.0 million of 2002 and $275.0 million of 2011 Series A Bonds outstanding. The fair value at December 31, 2011, was $408.3 million. On January 11, 2012, Chugach issued $250 million of 2012 Series A Bonds. The interest rates of our 2012 Series A Bonds due 2032 and 2042 are fixed at 4.01, 4.41 and 4.78 percent.

Chugach is exposed to market risk from changes in interest rates associated with our other credit facilities. Our credit facilities’ interest rates may be reset due to fluctuations in a market-based index, such as the London Interbank Offered Rate (LIBOR) or the base rate or prime rate of our lenders. At December 31, 2011, we had $175.0 million of commercial paper outstanding and $34.5 million outstanding on our CoBank bond. On January 12, 2012, Chugach paid the outstanding balance of commercial paper with proceeds from the $250 million 2012 Series A Bond issuance, therefore, a 100 basis-point change in interest rates would change our interest expense by approximately $344.5 thousand, based on $34.5 million of variable rate debt outstanding at January 12, 2012.

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 and purchased power recovery process, fluctuations in the price paid for gas pursuant to 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, 2011 and 2010, 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, 2011. 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, 2011 and 2010, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG, LLP

March 19, 2012

Anchorage, Alaska

Chugach Electric Association, Inc.

Balance Sheets

December 31, 2011 and 2010


	2011			2010
Assets
Utility plant :
Electric plant in service	$	862,362,243		$	853,933,739

Construction work in progress		206,005,783			100,787,482

Total utility plant		1,068,368,026			954,721,221

Less accumulated depreciation		(470,282,210	)		(446,582,318	)

Net utility plant		598,085,816			508,138,903

Other property and investments, at cost:
Nonutility property		84,735			84,735

Special funds		420,783			395,833

Investments in associated organizations		11,134,496			12,163,097

Total other property and investments		11,640,014			12,643,665

Current assets:
Cash and cash equivalents, including repurchase agreements of $100 in 2011 and $12,008,821 in 2010		17,118,118			12,070,713

Special deposits		149,701			211,858

Restricted cash equivalents		122,006,738			0

Fuel cost under-recovery		1,213,484			2,371,631

Accounts receivable, less provision for doubtful accounts of $408,429 in 2011 and $307,169 in 2010		42,373,995			35,140,119

Materials and supplies		32,994,454			35,974,170

Prepayments		1,911,789			1,925,424

Other current assets		229,858			256,290

Total current assets		217,998,137			87,950,205

Deferred charges, net		25,205,690			20,994,955


Total assets	$	852,929,657		$	629,727,728

Chugach Electric Association, Inc.

Balance Sheets (continued)

December 31, 2011 and 2010


	2011		2010
Liabilities, Equities and Margins

Equities and margins :

Memberships	$	1,517,488	$	1,474,869

Patronage capital		148,355,246		149,543,952

Other		11,358,692		10,823,463

Total equities and margins		161,231,426		161,842,284

Long-term obligations, excluding current installments :

Bonds payable		264,333,333		270,000,000

National Bank for Cooperatives note payable		31,756,775		34,450,318


Total long-term obligations		296,090,108		304,450,318

Current liabilities:

Current installments of long-term obligations		133,360,210		2,851,500

Commercial paper		175,000,000		98,500,000

Accounts payable		22,800,190		18,860,926

Consumer deposits		3,949,052		5,225,729

Accrued interest		6,843,473		6,049,531

Salaries, wages and benefits		7,597,691		6,733,842

Fuel		24,399,157		21,569,538

Other current liabilities		3,350,692		1,872,314

Total current liabilities		377,300,465		161,663,380

Deferred compensation		420,783		395,833

Deferred credits		1,703,277		1,375,913

Patronage capital payable		6,646,068		0

Deferred proceeds on sale of asset		9,537,530		0


Total liabilities, equities and margins	$	852,929,657	$	629,727,728

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Statements of Operations

Years Ended December 31, 2011, 2010 and 2009


	2011			2010			2009
Operating revenues	$	283,618,369		$	258,325,345		$	290,247,308

Operating expenses:

Fuel		139,179,413			111,718,947			136,416,761

Power production		16,853,232			18,248,656			16,406,911

Purchased power		25,861,814			26,691,968			35,690,476

Transmission		6,809,401			5,697,446			5,709,578

Distribution		13,387,477			12,216,252			12,740,381

Consumer accounts		5,465,315			5,323,551			5,259,348

Administrative, general and other charges		22,169,039			21,434,273			20,518,688

Depreciation		32,616,175			32,636,108			32,130,434


Total operating expenses		262,341,866			233,967,201			264,872,577

Interest expense:

Long-term debt and other		18,681,680			21,014,387			21,207,600

Charged to construction		(1,934,703	)		(1,008,689	)		(601,251	)


Interest expense, net		16,746,977			20,005,698			20,606,349


Net operating margins		4,529,526			4,352,446			4,768,382

Nonoperating margins:

Interest income		297,983			310,964			250,958

Allowance for funds used during construction		159,916			83,966			145,281

Capital credits, patronage dividends and other		585,837			662,633			495,727


Total nonoperating margins		1,043,736			1,057,563			891,966


Assignable margins	$	5,573,262		$	5,410,009		$	5,660,348

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Statements of Changes in Equities and Margins

Years Ended December 31, 2011, 2010 and 2009


	Memberships		Other Equities and Margins		Patronage Capital			Total
Balance, January 1, 2009	$	1,390,413	$	10,366,588	$	142,009,998		$	153,766,999

Assignable margins		0		0		5,660,348			5,660,348
Retirement of capital credits		0		0		(3,442,125	)		(3,442,125	)
Unclaimed capital credit retirements		0		213,527		0			213,527
Memberships and donations received		41,641		80,207		0			121,848


Balance, December 31, 2009		1,432,054		10,660,322		144,228,221			156,320,597


Assignable margins		0		0		5,410,009			5,410,009
Retirement of capital credits		0		0		(94,278	)		(94,278	)
Unclaimed capital credit retirements		0		90,320		0			90,320
Memberships and donations received		42,815		72,821		0			115,636


Balance, December 31, 2010		1,474,869		10,823,463		149,543,952			161,842,284


Assignable margins		0		0		5,573,262			5,573,262
Retirement of capital credits		0		0		(6,761,968	)		(6,761,968	)
Unclaimed capital credit retirements		0		367,277		0			367,277
Memberships and donations received		42,619		167,952		0			210,571


Balance, December 31, 2011	$	1,517,488	$	11,358,692	$	148,355,246		$	161,231,426

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Statements of Cash Flows

Years Ended December 31, 2011, 2010 and 2009


	2011			2010			2009
Cash flows from operating activities:
Assignable margins	$	5,573,262		$	5,410,009		$	5,660,348
Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation		32,616,175			32,636,108			32,130,434
Amortization and depreciation cleared to operating expenses		5,472,557			5,457,480			4,755,265
Allowance for funds used during construction		(159,916	)		(83,966	)		(145,281	)
Write off of inventory, deferred charges and projects		851,756			210,596			1,461,349
Other		(93,834	)		74,726			(121,417	)
(Increase) decrease in assets:
Accounts receivable		(7,128,876	)		670,424			35,367
Fuel cost under-recovery		1,158,147			(2,093,467	)		11,509,914
Materials and supplies		2,563,223			(6,061,005	)		(1,407,931	)
Prepayments		13,635			(663,527	)		282,128
Other assets		(2,049,082	)		(96,522	)		16,409
Deferred charges		(6,358,154	)		(1,511,639	)		(2,522,027	)
Increase (decrease) in liabilities:
Accounts payable		1,891,089			(1,321,046	)		169,466
Consumer deposits		(1,276,677	)		(267,221	)		585,618
Fuel cost over-recovery		0			(3,511,422	)		3,511,422
Accrued interest		793,942			(18,099	)		(91,297	)
Salaries, wages and benefits		863,849			777,522			474,699
Fuel		2,829,619			6,911,480			(13,836,153	)
Other liabilities		3,011,319			2,701,345			(70,105	)
Deferred liabilities		239,761			(70,335	)		11,219

Net cash provided by operating activities		40,811,795			39,151,441			42,409,427
Cash flows from investing activities:
Proceeds on sale of Bernice Lake Power Plant		9,537,530			0			0
Investment in associated organizations		1,153,470			311,593			0
Investment in restricted cash equivalents		(270,000,000	)		0			0
Proceeds from restricted cash equivalents		150,000,000			0			0
Extension and replacement of plant		(123,679,854	)		(73,214,825	)		(38,100,312	)

Net cash used in investing activities		(232,988,854	)		(72,903,232	)		(38,100,312	)
Cash flows from financing activities:
Payments of notes payable		0			0			(2,860,000	)
Payments for debt issue costs		(1,949,027	)		(1,493,572	)		0
Proceeds from short-term obligations		76,500,000			47,000,000			66,998,000
Proceeds from long-term obligations		275,000,000			0			0
Repayments of short-term obligations		0			0			(22,998,000	)
Repayments of long-term obligations		(152,851,500	)		(4,118,029	)		(47,367,312	)
Memberships and donations received		189,385			205,956			21,624
Retirement of patronage capital and estate payments		(309,188	)		(146,596	)		(3,022,246	)
Net receipts of consumer advances for construction		644,794			870,980			931,282

Net cash provided by (used in) financing activities		197,224,464			42,318,739			(8,296,652	)
Net changes in cash and cash equivalents		5,047,405			8,566,948			(3,987,537	)
Cash and cash equivalents at beginning of period	$	12,070,713		$	3,503,765		$	7,491,302
Cash and cash equivalents at end of period	$	17,118,118		$	12,070,713		$	3,503,765

Supplemental disclosure of non-cash investing and financing activities:
Retirement of plant (net of salvage)	$	11,317,319		$	6,666,875		$	991,011
Extension and replacement of plant included in accounts payable	$	15,561,199		$	15,919,688		$	5,712,404
Non-cash transmission assets	$	3,204,257		$	804,928		$	0
Supplemental disclosure of cash flow information – interest expense paid, including amounts capitalized	$	22,006,369		$	19,173,013		$	19,710,442

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(1)

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).

(2)

Significant Accounting Policies

a. Management Estimates

In preparing the financial statements in conformity with generally accepted accounting principles, 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, workers compensation, deferred charges and credits, unbilled revenue and the estimated useful life of utility plant. Actual results could differ from those estimates.

b. Regulation

The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 980, “Topic 980 – Regulated Operations.”

FASB ASC 980 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates. Our regulated rates are established to recover all of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs and those rates are then collected from our retail and wholesale customers. The regulatory assets or liabilities are then reduced as the cost or credit is reflected in earnings, see Note (2j) – “Deferred Charges and Credits.”

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(2)

Significant Accounting Policies (continued)

c. 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 depreciation. Renewals and betterments are capitalized, while maintenance and repairs are normally charged to expense as incurred.

In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain utility plant is reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset may not be recoverable in rates. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset exceeds the fair value of the asset.

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

Annual Depreciation Rate Ranges


	06/01/08 - 10/31/10	11/01/10 - 12/31/11

Steam production plant	4.45% - 5.85%	4.81% - 7.04%
Hydraulic production plant	1.22% - 3.00%	1.06% - 3.00%
Other production plant	3.77% - 10.56%	3.98% - 10.15%
Transmission plant	1.61% - 6.67%	1.58% - 7.86%
Distribution plant	1.95% - 9.77%	2.17% - 9.63%
General plant	1.25% - 26.11%	1.57% - 20.00%
Other	2.75% - 2.75%	2.75% - 2.75%

On November 1, 2010, the RCA approved revised depreciation rates effective November 1, 2010 in Docket U-09-097. Chugach’s depreciation rates include a provision for cost of removal. Given that the estimated timing and amount cannot be reasonably estimated, Chugach does not record a separate liability for its obligation associated with the retirement of plant.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(2)

Significant Accounting Policies (continued)

d. Capitalized Interest

Allowance for funds used during construction (AFUDC) and interest charged to construction - credit (IDC) are the estimated costs of the funds used during the period of construction from both equity and borrowed funds. AFUDC and IDC are applied to specific projects during construction. AFUDC and IDC calculations use the net cost of borrowed funds when used and is recovered through RCA approved rates as utility plant is depreciated. Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 4.1 percent during 2011, 4.8 percent during 2010 and 4.9 percent during 2009. Chugach capitalized actual interest expense and related fees associated with the construction of the Southcentral Power Project (SPP).

e. Investments in Associated Organizations

The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) require as a condition of the extension of credit, that an equity ownership position be established by all borrowers. Chugach’s equity ownership in these organizations is less than 1 percent. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment. No impairment was recorded during 2011, 2010 and 2009.

f. Fair Value of Financial Instruments

FASB ASC 825, “Topic 825 – Financial Instruments,” requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments:

Cash and cash equivalents – the carrying amount approximates fair value because of the short maturity of those instruments.

Consumer deposits – the carrying amount approximates fair value because of the short refunding term.

Long-term obligations – the fair value is estimated based on the quoted market price for same or similar issues (note 11).

Restricted cash – the carrying amount approximates fair value because of the short maturity of those instruments.

Repurchase agreement – the carrying amount approximates fair value because of the short maturity of those instruments.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(2)

Significant Accounting Policies (continued)

g. Cash and Cash Equivalents / Restricted Cash Equivalents

For purposes of the statement of cash flows, Chugach considers all highly liquid instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. In November of 2011, Chugach opened a Concentration account with First National Bank Alaska (FNBA). There is no rate of return or fees on this account. On December 30, 2011, Chugach opened a money market account with UBS Financial Services, Inc. (UBS) with an initial deposit of $10,000,000. Chugach also maintains an Overnight Repurchase Agreement with FNBA, however, in November of 2011 this account was placed into an inactive status. Prior to November of 2011 the daily balance was invested by FNBA and Chugach received varying interest rates for our investment pursuant to our Overnight Purchase Agreement. The Concentration account had an average balance since November of 2011 of $6,481,639. The Overnight Repurchase Agreement account had an average balance in 2011 and 2010 of $5,210,009 and $5,092,665, at an average interest rate of 0.06 percent and 0.14 percent, respectively.

On January 12, 2012, Chugach opened a money market account with KeyBank with the balance of proceeds from the 2012 Series A bond purchase, after repaying the outstanding balance of commercial paper. Chugach’s initial deposit was $69.0 million. Chugach plans to use these proceeds primarily to fund the remaining capital expenditures associated with SPP.

Restricted cash equivalents include $120 million of proceeds from the issuance of the 2011 Series A Bonds, which was used to retire the 2002 Series A Bonds on February 1, 2012, State of Alaska construction bonds and funds on deposit for future workers compensation claims.

h. 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. Included in accounts receivables are invoiced amounts to ML&P for fuel and their proportionate share of current SPP costs, which amounted to $4.8 and $4.5 million in 2011 and 2010, respectively.

i. Materials and Supplies

Materials and supplies are stated at average cost.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(2)

Significant Accounting Policies (continued)

j. Deferred Charges and Credits

In accordance with FASB ASC 980, Chugach’s financial statements reflect regulatory assets and liabilities. Continued accounting under FASB ASC 980, requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for ratemaking purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria.

Chugach regulatory asset recoveries are embedded in base rates approved by the RCA. Specific costs incurred and recorded as Regulatory Assets, including the amortization period for recovery, are approved by the RCA either in standard SRFs, general rate case filings or specified independent requests. The rates approved related to the regulatory assets are matched to the amortization of actual expenditures recognized on the books. The regulatory assets are amortized and collected through rates over differing periods depending upon the period of benefit as established by the RCA. Deferred credits, primarily representing regulatory liabilities, are amortized to operating expense over the period required for ratemaking purposes. It also includes refundable 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. 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 Chugach’s financial position or results of operations.

k. 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.

In 2007, Chugach entered into an agreement with HEA to return all of its patronage capital within five years after expiration of its power sales agreement, which is January 1, 2013. This patronage capital retirement was related to a settlement agreement associated with the 2005 Test Year General Rate Case (Docket U-06-134). The RCA accepted the parties’ settlement agreement on August 9, 2007. HEA’s patronage capital is classified as patronage capital payable and was $6.6 million at December 31, 2011.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(2)

Significant Accounting Policies (continued)

l. 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 $8,977,409 and $8,612,454 of unbilled retail revenue at December 31, 2011 and 2010, respectively. Wholesale revenue is recorded from metered locations on a calendar month basis, so no estimation is required. Chugach’s tariffs include provisions for the recovery of gas costs according to gas supply contracts, as well as purchased power costs.

m. Fuel and Purchased Power Costs Recovery

Expenses associated with electric services include fuel used to generate electricity and power purchased from others. Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel and purchased power recovery process, which is adjusted quarterly to reflect increases and decreases of such costs. We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates. The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under or over collection of fuel and purchase power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods. Fuel costs were under-recovered by $1,213,484 in 2011 and under-recovered by $2,371,631 in 2010. Total fuel and purchased power costs in 2011, 2010, and 2009 were $165,041,227, $138,410,915, and $172,107,237, respectively.

n. 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.

o. 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, 2011, 2010 and 2009 was in compliance with that provision. In addition, as described in “Note (15) – Commitments, Contingencies and Concentrations,” Chugach collects sales tax and is assessed gross receipts and excise taxes which are presented on a net basis in accordance with FASB ASC 605-45-50, “Topic 605 – Revenue Recognition – Subtopic 45 – Principal Agent Considerations – Section 50 – Disclosure.”

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(2)

Significant Accounting Policies (continued)

o. Income Taxes (continued)

Chugach applies a more-likely-than-not recognition threshold for all tax uncertainties. FASB ASC 740, “Topic 740 – Income Taxes,” only allows the recognition of those tax benefits that have a greater than fifty percent likelihood of being sustained upon examination by the taxing authorities. Chugach’s management reviewed Chugach’s tax positions and determined there were no outstanding, or retroactive tax positions, that were not highly certain of being sustained upon examination by the taxing authorities.

Management has concluded that there are no significant uncertain tax positions requiring recognition in its financial statements for all periods presented. Chugach’s evaluation was performed for the tax periods ended December 31, 2008 through December 31, 2011 for U.S. Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2011.

p. Consumer deposits

Consumer deposits are the amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 2011 and 2010, totaled $2.2 million and $2.1 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances for the years ended December 31, 2011 and 2010 totaled $1.7 million and $3.1 million, respectively.

q. Grants

Chugach has received grants from the Alaska Energy Authority to support the construction of facilities to transport fuel, divert water and transmit electricity to its consumers. Grant proceeds used to construct or acquire equipment are offset against the carrying amount of the related assets, which totaled $4.3 and $0.9 million in 2011 and 2010, respectively. The assets constructed from grant awards may not be sold, or used as collateral for any reason.

(3)

Recent Accounting Pronouncements

ASC Update 2011-09 “Compensation – Retirement Benefits – Multiemployer Plans (Subtopic 715-80): Disclosures about an Employer’s Participation in a Multiemployer Plan”

In September 2011, the FASB issued ASC Update 2011-09, “Compensation – Retirement Benefits – Multiemployer Plans (Subtopic 715-80): Disclosures about an Employer’s Participation in a Multiemployer Plan.” ASC Update 2011-09 expands the disclosure requirements for those employers participating in multiemployer plans to increase the awareness of the employer’s commitments and potential future cash flow impacts. This update is effective for annual reporting periods ending after December 15, 2011. Chugach began application of ASC 2011-09 in the annual report for the period ended December 31, 2011. Adoption did not have any incremental effect on results of operations, financial position, and cash flows.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(3)

Recent Accounting Pronouncements (continued)

ASC Update 2010-06 “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements”

In January 2010, the FASB issued ASC Update 2010-06, “Fair Value Measurements and Disclosures (Topic 820): Improving Disclosures about Fair Value Measurements.” ASC Update 2010-06 applies to all entities that are required to make disclosures about recurring or nonrecurring fair value measurements and expands the disclosures required based on the measurement Level. This update is effective for the first reporting period (including interim periods) beginning after December 15, 2009, except for certain Level 3 transactions. Those transaction disclosure requirements were effective for fiscal years beginning after December 15, 2010, and for interim periods within those fiscal years. Chugach began application of ASC Update 2010-06 for the period ended March 31, 2010, which did not have any effect on our results of operations, financial position, and cash flows. Chugach began application of the Level 3 transaction disclosures on January 1, 2011. Adoption did not have any effect on results of operations, financial position and cash flows.

(4)

Fair Value of Assets and Liabilities

Fair Value Hierarchy

In accordance with FASB ASC 820, Chugach groups its financial assets and liabilities measured at fair value in three levels, based on the markets in which the assets and liabilities are traded and the reliability of the assumptions used to determine fair value. These levels are:

Level 1 – Valuation is based upon quoted prices for identical instruments traded in active exchange markets, such as the New York Stock Exchange. Level 1 also includes U.S. Treasury and federal agency securities, which are traded by dealers or brokers in active markets. Valuations are obtained from readily available pricing sources for market transactions involving identical assets or liabilities.

Level 2 – Valuation is based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-based valuation techniques for which all significant assumptions are observable in the market.

Level 3 – Valuation is generated from model-based techniques that use significant assumptions not observable in the market. These unobservable assumptions reflect Chugach’s estimates of assumptions that market participants would use in pricing the asset or liability. Valuation techniques include use of option pricing models, discounted cash flow models and similar techniques.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(4)

Fair Value of Assets and Liabilities (continued)

The table below presents the balance of Chugach’s non-qualified deferred compensation plan, Overnight Repurchase Agreement, money market and restricted cash equivalents assets measured at fair value on a recurring basis at December 31, 2011, and December 31, 2010.


	Total		Level 1		Level 2		Level 3
December 31, 2011
Repurchase agreement	$	100	$	0	$	100	$	0
Money market	$	10,000,000	$	10,000,000	$	0	$	0
Restricted cash equivalents	$	122,006,738	$	122,006,738	$	0	$	0

December 31, 2010
Repurchase agreement	$	12,008,821	$	0	$	12,008,821	$	0

Chugach had no Level 3 assets or liabilities measured at fair value on a recurring basis. Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions. The fair value of long-term debt has been determined using discounted future cash flows at borrowing rates currently available to Chugach. The fair value of cash and cash equivalents, accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature.

(5)

Regulatory Matters

June 30, 2011 Test Year Simplified Rate Filing

On September 28, 2011, Chugach submitted a SRF to the RCA and requested a system demand and energy rate decrease of 1.3 percent, or approximately $1.5 million on an annual basis. The filing was based on the June 30, 2011 test year for proposed rate adjustments effective mid November 2011. The RCA approved the filing on November 7, 2011. The updated rates became effective November 14, 2011.

December 31, 2010 Test Year Simplified Rate Filing

On March 31, 2011, Chugach submitted a Simplified Rate Filing (SRF) to the RCA and requested a system demand and energy rate increase of 0.9 percent, or approximately $1.0 million on an annual basis. The filing was based on the December 31, 2010 test year for proposed rate adjustments effective in mid May 2011. On a customer class basis, Chugach requested demand and energy rate increases of 0.3 percent to Chugach retail customers and 2.2 percent to its wholesale classes. The RCA issued a letter order on May 13, 2011 approving the filing. The updated rates became effective May 16, 2011.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(5)

Regulatory Matters (continued)

2008 Test Year Rate Case

On June 23, 2009, Chugach filed a general rate case with the RCA to increase base demand and energy rate revenue by $4.2 million, with increases of $2.7 million to Chugach retail customers and $1.5 million to wholesale customers. On October 9, 2009, the RCA granted an increase to base demand and energy rates of 3.3 percent, 7.8 percent, 2.0 percent and 9.7 percent to Chugach’s retail customers and wholesale customers HEA, MEA and Seward, respectively, on an interim and refundable basis. On October 15, 2009, the RCA consolidated Docket U-09-080 (General Rate Case) and Docket U-09-097 (Depreciation Study Update). Chugach reached a settlement with its wholesale customers, HEA, MEA and Seward, which resolved issues in both the general rate case and the depreciation study update. After a June 2010 hearing, the RCA issued a final order in the consolidated case (2008 Test Year General Rate Case and Revision to Current Depreciation Rates) on September 16, 2010. The RCA accepted Chugach’s settlements with its wholesale customers, HEA, MEA and Seward and resolved depreciation issues disputed by the Attorney General, which resulted in no change to the depreciation rates contained in the settlement agreements. As a result of the RCA accepting the settlement agreements and resolving depreciation issues, Chugach refunded its wholesale and retail customers approximately $0.7 million, including interest. Base rate changes were approved effective November 1, 2010.

Request for Participation in the Simplified Rate Filing Process

On December 15, 2009, Chugach submitted a request to the RCA for approval to implement the Simplified Rate Filing (SRF) process for the adjustment of base energy and demand rates in accordance with Alaska Statute 42.05.381(e). Chugach requested that base rate adjustments under SRF be completed on a semi-annual basis, utilizing the twelve months ended June and December as the test periods in each year. Chugach requested that its initial SRF be submitted on the June 2010 test year for rate adjustments, if necessary, during fourth quarter, 2010. A public hearing was held on July 19, 2010. The parties to the docket entered into a stipulation on the outstanding issues in the case and the RCA issued a bench order at the hearing approving the stipulation. A formal written order was issued on July 26, 2010.

June 30, 2010 Test Year Simplified Rate Filing

On September 28, 2010, Chugach filed its initial filing under the Simplified Rate Filing process to decrease base demand and energy rate revenue by $0.2 million, with increases of 0.2 percent to Chugach retail customers and 0.3 percent to Seward and decreases of 0.6 percent and 1.2 percent to HEA and MEA, respectively. The RCA approved Chugach’s Simplified Rate Filing on November 4, 2010, for base rate changes effective November 15, 2010.

Seward Power Sales Agreement

On May 6, 2011, Chugach submitted a request to the RCA to extend the term of the 2006 Agreement for the Sale and Purchase of Electric Power and Energy between Chugach and the City of Seward to December 31, 2016. The current contract expires on December 31, 2011. The RCA issued a letter order on May 26, 2011, approving the extension.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(5)

Regulatory Matters (continued)

Seward Power Sales Agreement (continued)

Effective March 1, 2012, the RCA approved Amendment No. 2 to the 2006 Agreement for the Sale and Purchase of Electric Power and Energy between Chugach and the City of Seward (2006 Agreement). Amendment No. 2 allows Seward to accept power from Small Power Projects on terms that are financially neutral to both Chugach and Seward for wholesale power service provided to Seward, without changing Seward’s status under the 2006 Agreement as a partially interruptible requirements customer of Chugach. In addition, Amendment No. 2 facilitates Seward offering net metering service from eligible on-site generation sources to its retail customers without attendant compensation to Chugach. Chugach and Seward have structured the net metering conditions to be consistent with the net metering regulations adopted by the RCA.

Request for Regulatory Asset

On January 21, 2011, Chugach issued $90 million of First Mortgage Bonds (2011 Series A, Tranche A) at an interest rate of 4.20 percent and $185 million of First Mortgage Bonds (2011 Series A, Tranche B) at an interest rate of 4.75 percent. The proceeds of the 2011 Series A Bonds were used for the refinancing of Chugach’s $150 million of 2001 Series A Bonds that matured on March 15, 2011 and will be used for the refinancing of Chugach’s $120 million of 2002 Series A Bonds that mature on February 1, 2012.

On March 22, 2011, Chugach submitted a petition to the RCA requesting authorization to create regulatory assets for the deferral of interim interest expense associated with the refinancing of its 2001 and 2002 Series A Bonds. The 2011 financing reduced interest rate risk and allowed Chugach to capitalize on historic lows in long-term interest rates to minimize the long-term financial cost to members. Chugach deferred the interim interest expense and recognized regulatory assets as it believed that recovery through future rates was probable as we had received approval for similar costs historically. The requested amortization period was over the life of the bonds or between 20 and 30 years.

The deferral of interest for the portion of the 2011 bonds used to pay off the 2001 Series A Bonds that matured on March 15, 2011, totaled approximately $1.0 million. The deferral of interest for the portion of the 2011 bonds used to pay off the 2002 Series A Bonds that matured on February 1, 2012, was estimated at $5.7 million. Chugach also requested approval to recover the associated refinancing costs in electric rates through amortization over the life of the new 2011 Series A Bonds.

The RCA issued a final order in this docket on September 16, 2011, approving Chugach’s request.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(5)

Regulatory Matters (continued)

ENSTAR (Alaska Pipeline Company)

ENSTAR Natural Gas Company (ENSTAR) has a tariff to transport our gas purchased from gas suppliers on a firm basis to our International Station Power Plant (historically known as “IGT”) at a transportation rate of $0.63 per thousand cubic feet (Mcf). The agreement contains a fixed monthly charge of $2,840 for firm service. In December of 2010, ENSTAR applied for an extension of this tariffed rate to provide gas transportation to Chugach to service the Bernice Lake Power Plant. Previously, transportation was provided as part of a natural gas supply contract. Under the new contract, Chugach is responsible for transportation of the natural gas. The RCA approved the request in February of 2011.

Bernice Lake Asset Purchase and Capacity Agreement

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(5)

Regulatory Matters (continued)

Fire Island Wind Project

On June 23, 2011, Chugach submitted a request to the RCA for approval of a new power purchase agreement (PPA) between Chugach and Fire Island Wind, LLC (FIW), a special purpose entity wholly-owned by Cook Inlet Region, Inc. Chugach also requested authorization from the RCA to recover the costs of all energy purchases under the PPA through its retail quarterly fuel and purchased power recovery process at the time the project becomes commercially operational, which is currently expected to occur before October 1, 2012. Annual cost of these purchases is expected to be about $4.7 million. An affiliate of FIW is responsible for the construction of the interconnection between the project and Chugach’s transmission system. Chugach is the recipient of a grant in the amount of $25.0 million appropriated from the State of Alaska. The grant will be used to offset construction of the transmission line. Chugach is not expected to incur any capital costs associated with this line. The PPA is a 25 year agreement whereby Chugach purchases the output of the facility over a 25 year term, commencing January 1, 2013. The Fire Island Wind project is comprised of eleven 1.6 megawatt wind turbine generators with a total nameplate capacity of 17.6 megawatts which are expected to generate approximately 50,000 MWh per year. The generators will be located on the southern part of Fire Island in Anchorage, Alaska.

The RCA held a public hearing from September 27 through September 30, 2011. On October 10, 2011, the RCA issued an order approving Chugach’s request for assurance of cost recovery associated with the PPA. The RCA order also granted approval for Chugach to recover costs associated with the PPA through its fuel and purchased power recovery process. The RCA order also required Chugach to submit a project status report by November 10, 2011 and a specific rate recovery plan by March 31, 2012.

Chugach submitted its initial status report to the RCA on November 10, 2011. On November 22, 2011, the RCA issued Order No. 1 of Docket U-11-129 to monitor the project.

Petition to Establish Depreciation Rates for the SPP

On February 22, 2012, Chugach submitted a filing to the RCA requesting approval to establish depreciation rates for the Southcentral Power Project and related transmission plant. If approved, the depreciation rates will be effective on the commercial operation date of the SPP, which is currently expected by year-end 2012. Chugach expects a decision by third quarter, 2012.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(6)

Utility Plant

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


Electric plant in service:	2011		2010
Steam production plant	$	60,462,671	$	60,462,671
Hydraulic production plant		20,456,395		20,402,466
Other production plant		134,434,574		134,400,210
Transmission plant		252,561,598		248,084,767
Distribution plant		257,341,532		249,408,094
General plant		45,144,425		49,275,336
Unclassified electric plant in service¹		80,559,413		80,498,560
Intangible plant¹		4,710,912		4,710,912
Other¹		6,690,723		6,690,723

Total electric plant in service		862,362,243		853,933,739
Construction work in progress²		206,005,783		100,787,482

Total electric plant in service and construction work in progress	$	1,068,368,026	$	954,721,221

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. Intangible plant represents Chugach’s share of a Bradley Lake transmission line financed internally. Other represents Electric Plant Held for Future Use.

²	The amount associated with the construction of the SPP included in construction work in progress was $177.4 and $84.9 million at December 31, 2011 and 2010, respectively.

(7)

Investments in Associated Organizations

Investments in associated organizations include the following at December 31:


	2011		2010
National Rural Utilities Cooperative Finance Corporation	$	6,095,980	$	6,095,980
CoBank, ACB		4,974,755		6,003,555
NRUCFC capital term certificates / Other		63,761		63,562

Total Investments in Associated Organizations	$	11,134,496	$	12,163,097

The Farm Credit Administration, CoBank’s federal regulators, requires minimum capital adequacy standards for all Farm Credit System institutions. Loan agreements and financing arrangements with CoBank and NRUCFC require, as a condition of the extension of credit, that an equity ownership position be established by all borrowers.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(8)

Deferred Charges and Credits

Deferred Charges

Deferred charges, or regulatory assets, net of amortization, consisted of the following at December 31:


	2011		2010
Debt issuance and reacquisition costs	$	3,432,665	$	2,851,601
Refurbishment of transmission equipment		151,235		160,495
Feasibility Studies		351,727		334,853
Beluga Gas Compression		2,544,332		3,053,198
Cooper Lake Relicensing / projects		5,930,520		6,052,811
Fuel supply negotiations		1,118,439		1,467,986
Major overhaul of steam generating unit		2,265,069		3,020,092
Other regulatory deferred charges		2,126,335		2,757,644
Bond interest – market risk management		6,034,443		0
Environmental matters and other		1,250,925		1,296,275

Total deferred charges	$	25,205,690	$	20,994,955

Deferred charges, or regulatory assets, not currently being recovered in rates charged to consumers, consisted of the following at December 31:


	2011		2010
Fuel supply negotiations	$	0	$	203,231
Studies/Other		578,327		334,853
Cooper Lake Unit 1 Major Overhaul		0		1,356,489
Cooper Lake Relicensing		0		491,091
Wind project		144,866		0
Financing costs		51,129		350,380

Total deferred charges	$	774,322	$	2,736,044

We believe all regulatory assets not currently being recovered in rates charged to consumers are probable of recovery in the future based upon prior recovery of similar costs allowed by our regulator. The recovery of regulatory assets is requested in SRF rate adjustments filed with the RCA on a semi-annual basis. In most cases, deferred charges are recovered over the life of the underlying asset.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(8)

Deferred Charges and Credits (continued)

Deferred Credits

Deferred credits, or regulatory liabilities, at December 31 consisted of the following:


	2011		2010
Refundable consumer advances for construction	$	727,917	$	447,025
Estimated initial installation costs for meters		75,660		89,208
Post retirement benefit obligation		899,700		824,700
Other		0		14,980

Total deferred credits	$	1,703,277	$	1,375,913

(9)

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, 2011, Chugach had $148,355,246 of patronage capital (net of capital credits retired in 2011), which included $142,781,984 of patronage capital that had been assigned and $5,573,262 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. During 2008, the Board of Directors approved the deferral of capital credit retirements after 2009, excluding discounted capital credits, due to the construction of new generation and the anticipated loss of wholesale load in 2014. The Second Amended and Restated Indenture of Trust and the CoBank Amended and Restated Master Loan Agreement prohibit Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Second Amended and Restated Indenture of Trust or CoBank Amended and Restated Master Loan Agreement exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30 percent of Chugach’s total liabilities and equities and margins.

Chugach entered into an agreement with HEA to return all of its patronage capital within five years after expiration of its power sales agreement, which is January 1, 2013. This patronage capital retirement was related to a settlement agreement associated with the 2005 Test Year General Rate Case (Docket U-06-134). The RCA accepted the parties’ settlement agreement on August 9, 2007. HEA’s patronage capital payable was $6.6 million at December 31, 2011.

Capital credits retired were $309,188, $94,278, and $3,442,125 for the years ended December 31, 2011, 2010, and 2009, respectively. The outstanding liability for capital credits authorized but not paid was $0 and $388,463 at December 31, 2011 and 2010, respectively.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Other Equities

A summary of other equities at December 31 follows:


	2011		2010
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		1,621,257		1,453,305
Unclaimed capital credit retirement¹		9,713,810		9,346,533

Total other equities	$	11,358,692	$	10,823,463

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.

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Debt


Long-term obligations at December 31 are as follows:	2011		2010

CoBank 3 and 4, 2.64% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003	$	33,659,141	$	35,402,290

CoBank 5, 2.64% variable rate note maturing in 2012, with interest and principal payable monthly		791,177		1,899,528

2001 Series A Bond of 6.55%, maturing in 2011, with interest payable semi-annually March 15 and September 15		0		150,000,000

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

2011 Series A Bond of 4.20%, maturing in 2031, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012		90,000,000		0

2011 Series A Bond of 4.75%, maturing in 2041, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012		185,000,000		0


Total long-term obligations	$	429,450,318	$	307,301,818

Less current installments		133,360,210		2,851,500


Long-term obligations, excluding current installments	$	296,090,108	$	304,450,318

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Debt (continued)

Covenants

Chugach was required to comply with all covenants set forth in the Amended and Restated Indenture, dated April 1, 2001, and effective January 22, 2003. Effective January 20, 2011, Chugach is required to comply with all covenants set forth in the Second Amended and Restated Indenture of Trust that secured the 2002 Series A Bonds through February 1, 2012, and now secures the 2011 Series A Bonds, the 2012 Series A Bonds and the 2011 promissory note to CoBank, which has replaced the outstanding CoBank 3, 4 and 5 promissory notes.

Chugach was also required to comply with the Master Loan Agreement between Chugach and CoBank dated December 27, 2002, which governed the outstanding CoBank 3, 4 and 5 promissory notes. On January 19, 2011, CoBank and Chugach replaced the CoBank 3, 4 and 5 promissory notes with a promissory note that is governed by the Amended and Restated Master Loan Agreement, which is now secured by the Second Amended and Restated Indenture of Trust dated January 20, 2011.

Chugach is also required to comply with the 2010 Credit Agreement, between Chugach and NRUCFC, Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch dated November 17, 2010, governing loans and extensions of credit associated with Chugach’s commercial paper program, in an aggregate principal amount not exceeding $300 million at any one time outstanding.

Chugach is also required to comply with other covenants set forth in the Revolving Line of Credit Agreement with NRUCFC.

Chugach was also required to comply with covenants set forth in the Reimbursement and Indemnity Agreement with MBIA Insurance Corporation until February 1, 2012, when Chugach repaid the outstanding 2002 Series A bonds.

Security

Under the Amended and Restated Indenture of Trust, Chugach was 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 secured the Bonds subject to the Amended and Restated Indenture, except that Chugach was permitted to incur secured indebtedness in an amount not to exceed $5 million or enter into sale and leaseback or similar agreements.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Debt (continued)

On January 20, 2011, Chugach and the indenture trustee entered into a Second Amended and Restated Indenture of Trust (the Indenture) imposing a lien on substantially all of Chugach’s assets to secure Chugach’s long-term debt obligations. Assets that are generally not subject to the lien of the Indenture include cash (other than cash deposited with the indenture trustee); instruments and securities; patents, trademarks, licenses and other intellectual property; vehicles and other movable equipment; inventory and consumable materials and supplies; office furniture, equipment and supplies; computer equipment and software; office leases; other leasehold interests for an original term of less than five years; contracts (other than power sales agreements with members having an original term exceeding three years, certain contracts specifically identified in the indenture, and other contracts relating to the ownership, operation or maintenance of generation, transmission or distribution facilities); non-assignable permits, licenses and other contract rights; timber and minerals separated from land; electricity, gas, steam, water and other products generated, produced or purchased; other property in which a security interest cannot legally be perfected by the filing of a Uniform Commercial Code financing statement, and certain parcels of real property specifically excepted from the lien of the Indenture. The lien of the Indenture may be subject to various permitted encumbrances that include matters existing on the date of the Indenture or the date on which property is later acquired; reservations in U.S. patents; non-delinquent or contested taxes, assessments and contractors’ liens; and various leases, rights-of-way, easements, covenants, conditions, restrictions, reservations, licenses and permits that do not materially impair Chugach’s use of the mortgaged property in the conduct of Chugach’s business.

Rates

Under the Amended and Restated Indenture of Trust, dated April 1, 2001, Chugach was required, 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 occurred any material change in the circumstances contemplated at the time rates were most recently reviewed, the Amended and Restated Indenture required Chugach to seek appropriate adjustment to those rates so that they would generate revenues reasonably expected to yield margins for interest equal to at least 1.10 times interest charges.

The Second Amended and Restated Indenture of Trust, which became effective on January 20, 2011, also 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 Second Amended and Restated Indenture of Trust requires Chugach to seek appropriate adjustment to those rates so that they would generate revenues reasonably expected to yield margins for interest equal to at least 1.10 times interest charges, provided, however, upon review of rates based on a material change in circumstances, rates are required to be revised in order to comply and there are less than six calendar months remaining in the current fiscal year, Chugach can revise its rates so as to reasonably expect to meet the covenant for the next succeeding twelve-month period after the date of any such revision.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Debt (continued)

The CoBank Master Loan Agreement also required Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense. The Amended and Restated Master Loan Agreement with CoBank, which became effective on January 19, 2011, did not change this requirement.

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 2010 Credit Agreement governing the unsecured facility providing liquidity for Chugach’s Commercial paper program requires Chugach to maintain a minimum margins for interest of at least 1.10 times interest charges for each fiscal year. 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 prohibited 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 could make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent of assignable margins for the prior fiscal year. This restriction did not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter were equal to at least 30 percent of Chugach’s total liabilities and equities and margins.

The Second Amended and Restated Indenture of Trust, which became effective on January 20, 2011, and the CoBank Amended and Restated Master Loan Agreement, which became effective on January 19, 2011, prohibits Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Second Amended and Restated Indenture of Trust or CoBank Amended and Restated Master Loan Agreement exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30 percent of Chugach’s total liabilities and equities and margins.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Debt (continued)

Maturities of Long-term Obligations

Long-term obligations at December 31, 2011, including the subsequent $250 million 2012 Series A Bonds issued on January 11, 2012, mature as follows:


Year ending December 31	2002 Series A Bonds		2011 Series A Bonds		CoBank Note		2012 Series A Bonds		Total
2012		120,000,000		10,666,667		2,693,543		0		133,360,210
2013		0		10,666,667		2,076,355		11,750,000		24,493,022
2014		0		10,666,667		2,266,145		11,750,000		24,682,812
2015		0		10,666,667		2,473,110		10,750,000		23,889,777
2016		0		10,666,667		2,699,313		10,750,000		24,115,980
Thereafter		0		221,666,665		22,241,852		205,000,000		448,908,517

	$	120,000,000	$	275,000,000	$	34,450,318	$	250,000,000	$	679,450,318

Lines of credit

Chugach maintains a $50 million line of credit with National Rural Utilities Cooperative Finance Corporation (NRUCFC). Chugach did not utilize this line of credit in 2011, and therefore had no outstanding balance at December 31, 2011. In addition, Chugach did not utilize this line of credit during 2010 and had no outstanding balance at December 31, 2010. The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC and will not exceed the Prevailing Prime Rate, plus one percent per annum. At December 31, 2011, and December 31, 2010, the borrowing rate was 3.20% and 4.95%, 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.

This line of credit is immediately available for unconditional borrowing.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Debt (continued)

Commercial Paper

On November 17, 2010, Chugach replaced the $300 million unsecured Credit Agreement executed on October 10, 2008, which was due to expire on October 10, 2011. The 2010 Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, will expire on November 17, 2013. The Credit Agreement is used to back Chugach’s Commercial Paper program. The 2010 Credit Agreement was priced with an all-in drawn spread of one month LIBOR plus 150 basis points, along with a 25 basis points facility fee (based on an A-/A3 unsecured debt rating). Chugach had $175.0 and $98.5 million of commercial paper outstanding at December 31, 2011 and 2010, respectively. Our commercial paper can be repriced between one day and two hundred seventy days. The following table provides information regarding 2011 monthly average commercial paper balances outstanding (dollars in millions), as well as corresponding weighted average interest rates:


Month	Average Balance		Weighted Average Interest Rate		Month	Average Balance		Weighted Average Interest Rate
January	$	100.3		0.30	July	$	125.9		0.27
February	$	111.3		0.30	August	$	141.7		0.28
March	$	117.4		0.30	September	$	152.6		0.28
April	$	113.0		0.30	October	$	159.6		0.27
May	$	116.0		0.27	November	$	170.7		0.25
June	$	116.7		0.29	December	$	175.0		0.27

Financing

On January 11, 2012, Chugach issued $75,000,000 of First Mortgage Bonds, 2012 Series A, due March 15, 2032 (Tranche A), $125,000,000 of First Mortgage Bonds, 2012 Series A, due March 15, 2042 (Tranche B) and $50,000,000 of First Mortgage Bonds, 2012 Series A, due March 15, 2042 (Tranche C), for the purpose of repaying outstanding commercial paper used to finance the Southcentral Power Project (SPP) construction and for general corporate purposes. The 2012 Series A Bonds (Tranche A) will mature on March 15, 2032, and will bear interest at 4.01% per annum. The 2012 Series A Bonds (Tranche B) will mature on March 15, 2042, and will bear interest at 4.41% per annum. The 2012 Series A Bonds (Tranche C) will mature on March 15, 2042, and will bear interest at 4.78% per annum. Interest will be paid each March 15 and September 15, commencing on September 15, 2012. The 2012 Series A Bonds (Tranche A) will pay principal in equal installments on an annual basis beginning March 15, 2013, resulting in an average life of approximately 10.7 years. The 2012 Series A Bonds (Tranche B) will pay principal between March 15, 2013 and March 15, 2020 and between March 15, 2032 and March 15, 2042, resulting in an average life of approximately 15.7 years. The 2012 Series A Bonds (Tranche C) will pay principal in equal installments on an annual basis beginning March 15, 2023, resulting in an average life of approximately 20.7 years. The bonds and all other long-term debt obligations are secured by a lien on substantially all of Chugach’s assets, pursuant to the Second Amended and Restated Indenture of Trust, which became effective on January 20, 2011.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Debt (continued)

Financing (continued)

On January 21, 2011, Chugach issued $90,000,000 of First Mortgage Bonds, 2011 Series A, due March 15, 2031 and $185,000,000 of First Mortgage Bonds, 2011 Series A, due March 15, 2041 for the purpose of refinancing the 2001 and 2002 Series A Bonds due March 15, 2011, and February 1, 2012, respectively, and for general corporate purposes. As anticipated, on February 1, 2012, Chugach retired its 2002 Series A Bonds with proceeds from the 2011 Series A bond issuance. The 2011 Series A Bonds due March 15, 2031, will bear interest at 4.20% per annum, payable semi-annually on March 15 and September 15 of each year commencing on September 15, 2011. Principal on the 2011 Series A Bonds due March 15, 2031 will be paid in equal annual installments beginning March 15, 2012, resulting in an average life of approximately 10 years. The 2011 Series A Bonds due March 15, 2041, will bear interest at 4.75% per annum, payable semi-annually on March 15 and September 15 of each year commencing on September 15, 2011. Principal on the 2011 Series A Bonds due March 15, 2041 will be paid in equal annual installments beginning March 15, 2012, resulting in an average life of approximately 15.5 years.

Chugach had a term loan facility with CoBank. Loans made under that facility were evidenced by promissory notes governed by the Master Loan Agreement, which was effective January 22, 2003. On January 19, 2011, Chugach and CoBank amended and restated the existing Master Loan Agreement. The existing obligations under the existing loan are evidenced by the 2011 CoBank Note, which is governed by the Amended and Restated Master Loan Agreement dated January 19, 2011 and secured by the Second Amended and Restated Indenture.

Fair Value of Debt Instruments

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


	2011				2010
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term obligations (including current installments)	$	429,450	$	442,711	$	307,302	$	315,401

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Employee Benefit Plans

Pension Plans

Pension benefits for substantially all union employees are provided through the Alaska Electrical Pension Trust Fund and the UNITE HERE National Retirement 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.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Employee Benefit Plans (continued)

Pension Plans (continued)

Pension benefits for non-union employees are provided by the National Rural Electric Cooperative Association (NRECA) Retirement and Security Program. Under ASC 960, “Topic 960 – Plan Accounting – Defined Benefit Pension Plans,” the plan is a multi-employer plan, in which the accumulated benefits and plan assets are not determined or allocated separately to individual employers. Chugach makes annual contributions to the pension plan equal to the amounts accrued for pension expense. Chugach made contributions to all significant pension plans for the years ended December 31, 2011, 2010 and 2009 of $6.0 million, $6.0 million and $5.0 million, respectively. The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2011, 2010 and 2009. The following table provides information regarding pension plans which Chugach considers individually significant:

Alaska Electrical
Pension Plan³

NRECA Retirement
Security Plan³

Employer Identification Number

92-6005171

53-0116145

Plan Number

001

333

Year-end Date

December 31

Expiration Date of CBA’s

June 30, 2013

N/A²

Subject to Funding Improvement Plan

Surcharge Paid

N/A


	2011		2010		2009		2011			2010			2009
Zone Status		Green		Green		Green		N/A	¹		N/A	¹		N/A	¹
Required minimum contributions		None		None		None		N/A			N/A			N/A
Contributions (in millions)	$	3.0	$	2.9	$	2.9	$	3.0		$	3.1		$	2.1
Contributions > 5% of total plan contributions		Yes		Yes		Yes		No			No			No

¹	In total, the NRECA Retirement Security Plan was between 65 percent and 80 percent funded at January 1, 2011. 2010 and 2009 are based on the Pension Protection Act (PPA) funding target and PPA actuarial value of assets on those dates.

²	The CEO is the only non-union employee subject to an employment agreement, which is effective through July 1, 2013.

³	The Alaska Electrical Pension Plan is publically available. The NRECA Retirement Security Plan is available on Chugach’s website at www.chugachelectric.com.

Health and Welfare Plans

Health and welfare benefits for union employees are provided through the Alaska Electrical Health and Welfare Trust and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund. Chugach participates in multi-employer plans that provide substantially all union workers with health care and other welfare benefits during their employment with Chugach. Chugach pays a defined amount per union employee pursuant to collective bargaining unit agreements. Amounts charged to benefit costs and contributed to the health and welfare plans for these benefits for the years ending December 31, 2011, 2010, and 2009 were $3.7 million, $3.7 million, and $3.4 million, respectively.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Employee Benefit Plans (continued)

Health and Welfare Plans (continued)

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, 2011, 2010, and 2009 totaled $2.4 million, $2.2 million, and $2.1 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, 2011, 2010, and 2009 were $128.7 thousand, $124.1 thousand, and $99.7 thousand, respectively.

401(k) Plan

Chugach has a defined contribution 401(k) retirement plan which covers substantially all employees who, effective January 1, 2008, can participate immediately. Employees who elect to participate may contribute up to the Internal Revenue Service’s maximum of $16,500, $16,500, and $16,500 in 2011, 2010, and 2009 respectively, and allowed catch-up contributions for those over 50 years of age of $5,500, $5,500, and $5,500 in 2011, 2010, and 2009, 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, 2011, 2010 and 2009 was $420,783, $395,833 and $345,792, respectively.

Potential Termination Payments

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Bradley Lake Hydroelectric Project

Chugach is a participant in the Bradley Lake Hydroelectric Project (Bradley Lake). Bradley Lake was built and financed by the Alaska Energy Authority (AEA) through State of Alaska grants and $166,000,000 of revenue bonds. Chugach and other participating utilities have entered into take-or-pay power sales agreements under which shares of the project capacity have been purchased and the participants have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt service costs and amounts required to maintain established reserves). Under these take-or-pay power sales agreements, the participants have agreed to pay all project costs from the date of commercial operation even if no energy is produced. Chugach has a 30.4 percent share, or 27.4 megawatts as currently operated, of the project’s capacity. The share of Bradley Lake indebtedness for which we are responsible is approximately $31 million. Upon the default of a Bradley Lake participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs pro rata, to the extent necessary to compensate for the failure of another participant to pay its share, provided that no participant’s percentage share is increased by more than 25 percent. Upon default, Chugach could be faced with annual expenditures of approximately $4.9 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 recovery process.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Bradley Lake Hydroelectric Project (continued)

The following represents information with respect to Bradley Lake at June 30, 2011 (the most recent date for which information is available). Chugach’s share of expenses was $4,643,641 in 2011, $5,120,958 in 2010, and $5,152,716 in 2009 and is included in purchased power in the accompanying financial statements.


(In thousands)	Total		Proportionate Share

Plant in service	$	185,627	$	56,431

Long-term debt		94,676		28,782

Interest expense		5,540		1,684

Chugach’s share of a Bradley Lake transmission line financed internally is included in Other Electric Plant.

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Eklutna Hydroelectric Project

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

Plant in service in 2011 includes $4,880,583, net of accumulated depreciation of $1,491,704, which represents Chugach’s share of the Eklutna Hydroelectric Project. In 2010 plant in service included $2,386,571, net of accumulated depreciation of $996,593. Chugach and ML&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 $662,035, $664,747, and $615,060 in 2011, 2010, and 2009, respectively and is included in power production and depreciation expense in the accompanying financial statements. ML&P performs major maintenance at the plant. Chugach provides personnel for the daily operation and maintenance of the power plant, who perform daily plant inspections, meter reading, monthly report preparation, and other activities as required.

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Commitments and Contingencies

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.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

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Commitments and Contingencies (continued)

Fuel Supply Contracts

Chugach has fuel supply contracts from various producers at market terms. Previous contracts expired at the end of the currently committed volumes in 2010 and 2011. A gas supply contract between Chugach and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively “COP”), was approved by the RCA effective August 21, 2009. The new contract provided gas beginning in 2010 and will terminate December 31, 2016. The total amount of gas under the contract is now estimated to be 60 BCF. The RCA approved a new natural gas supply contract with MAP effective May 17, 2010. The new MAP contract provided gas beginning April 1, 2011 and will terminate December 31, 2014. MAP had two contract extension options that could be exercised during the first year of the initial contract. MAP extended the contract to December 31, 2013, by exercising the first contract extension on January 12, 2011, and extended the contract to December 31, 2014, by exercising the second contract extension on October 25, 2011. The total amount of gas under contract is now estimated up to 40 billion cubic feet (BCF). These contracts fill 100 percent of Chugach’s needs through December 2014, approximately 70 percent of Chugach’s needs through December 2015 and approximately 40 percent in 2016. In 2011, 92 percent of our power was generated from gas, compared to 89 percent and 90 percent in 2010 and 2009 respectively. Of that gas-fired power, 79 percent was generated at Chugach’s Beluga Power Plant in 2011 compared with 78 percent in 2010 and 83 percent in 2009.

The following represents the cost of fuel purchased and or transported from these vendors as a percentage of total fuel costs for the years ended December 31:


	2011			2010			2009

Marathon Oil Company		44.9	%		24.1	%		44.6	%
Chevron/UNOCAL/Hilcorp Alaska		16.1	%		26.4	%		20.9	%
ML&P		3.6	%		14.2	%		16.7	%
ConocoPhillips (COP)		31.9	%		35.1	%		17.8	%
ENSTAR Natural Gas Company		1.3	%		0.2	%		0.0	%
Kenai Nikiski Pipeline (KNPL) / Misc.		2.2	%		0.0	%		0.0	%

Concentrations

Approximately 70 percent of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW. We also have an agreement with the Hotel Employees and Restaurant Employees (HERE). All agreements were due to expire on June 30, 2010. On February 24, 2010, the Board of Directors approved three year extensions of all three IBEW CBA’s. The three extensions provide no wage increase in the first year and wage increases tied to changes in the Consumer Price Index (CPI) in the second and third years, with a floor on the minimum increase and a cap on the maximum increase. The wage increases also have an indirect connection to Chugach’s financial performance. The contract extensions expire on June 30, 2013. On April 28, 2010, the Board of Directors approved a three year extension of the HERE agreement. The extension contains an increase in the employer health and welfare contribution in each year of the extension but does not provide for a wage or pension increase. This contract extension also expires on June 30, 2013.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(15)

Commitments and Contingencies (continued)

Concentrations (continued)

Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts represented $104.0 million or 37 percent of sales revenue in 2011, $89.1 million or 35 percent in 2010, and $112.6 million or 39 percent in 2009. The HEA contract expires January 1, 2014, and the MEA contract expires December 31, 2014. Non-renewal of these contracts could have a negative impact on the rates charged to other Chugach customers. Notification was made by MEA and HEA that neither organization intends to renew these contracts. MEA advised Chugach that it desired to open discussions regarding power sales possibilities beyond 2014. Chugach proposed a power supply offer to MEA on January 11, 2011, and again on January 31, 2012. Chugach received a response on February 29, 2012, indicating that MEA was following the path its membership most favored and is moving forward with plans to build its own generation plant. All rates are established by the RCA.

Patronage Capital Payable

In 2007, Chugach entered into an agreement with HEA to return all of its patronage capital within five years after expiration of its power sales agreement, which was related to a settlement agreement associated with the 2005 Test Year General Rate Case (Docket U-06-134). The agreement was contingent on the RCA accepting the parties’ settlement agreement in Docket U-06-134, which occurred on August 9, 2007. HEA’s patronage capital should have been classified as a liability at that time. HEA’s patronage capital was $6.5 million at December 31, 2010. As the amount of the patronage capital was not material for any period, Chugach recorded an adjustment in the first quarter of 2011 to reclassify the amount of $6.5 million from patronage capital to patronage capital payable. HEA’s patronage capital was $6.6 million at December 31, 2011, and is classified as patronage capital payable on our Balance Sheet and is included in the retirement of capital credits on our Statements of Changes in Equities and Margins.

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 $0.000492, effective July 1, 2011. 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.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(15)

Commitments and Contingencies (continued)

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.

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 2 percent of gross retail revenue in the Municipality of Anchorage annually in moving existing distribution overhead lines underground. Consistent with State of Alaska undergrounding requirement, Chugach is permitted to amend its rates by adding a 2 percent charge 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’s liability was $2,611,110 and $726,209 for this charge at December 31, 2011 and 2010, respectively and will use the funds to offset the costs of the projects.

Environmental Matters

New Clean Air Act regulations impacting electric utilities may result from future events or may result from new regulatory programs. On October 30, 2009, the EPA published new federal regulations requiring the mandatory reporting of greenhouse gases from all sectors of the economy. Chugach is subject to this new regulation, which is not expected to have a material effect on our results of operations, financial position, and cash flows. While we cannot predict whether any additional new regulation would occur or its limitation, it is possible that new laws or regulations could increase our capital and operating costs. We have obtained or applied for all Clean Air Act permits currently required for the operation of our generating facilities.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(15)

Commitments and Contingencies (continued)

Environmental Matters (continued)

Chugach is subject to numerous other environmental statutes including the Clean Water Act, the Resource Conservation and Recovery Act, the Toxic Substances Control Act, the Endangered Species Act, and the Comprehensive Environmental Response, Compensation and Liability Act and to the regulations implementing these statutes. We do not believe that compliance with these statutes and regulations to date has had a material impact on our financial condition or results of operation. However, new laws or regulations, implementation of final regulations or changes in or new interpretations of these laws or regulations could result in significant additional capital or operating expenses.

Generation Commitments

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2011 and 2010

(16)

Reclassifications

For the year ended December 31, 2011, Chugach recorded a reclassification representing the amount of patronage returned from CoBank previously included as an increase of cash provided by operating activities and now included as a decrease of cash used in investing activities. Chugach also recorded a reclassification representing the non-cash change in accounts payable associated with capital expenditures. The impact of the reclassifications was to decrease cash provided by operating activities and decrease cash used in investing activities by $2.0 million in 2010.

(17)

Quarterly Results of Operations (unaudited)

2011 Quarter Ended


	Dec. 31		Sept. 30			June 30			March 31
Operating Revenue	$	76,828,268	$	68,778,352		$	68,517,526		$	69,494,223
Operating Expense		70,143,069		65,509,750			65,592,311			61,096,736
Net Interest		4,102,750		3,544,204			4,209,482			4,890,541

Net Operating Margins		2,582,449		(275,602	)		(1,284,267	)		3,506,946
Nonoperating Margins		628,697		161,595			120,363			133,081

Assignable Margins	$	3,211,146	$	(114,007	)	$	(1,163,904	)	$	3,640,027

2010 Quarter Ended


	Dec. 31		Sept. 30			June 30			March 31
Operating Revenue	$	73,895,221	$	58,274,912		$	59,444,167		$	66,711,045
Operating Expense		65,584,673		55,445,222			55,716,842			57,220,464
Net Interest		5,015,213		4,949,813			5,023,767			5,016,905

Net Operating Margins		3,295,335		(2,120,123	)		(1,296,442	)		4,473,676
Nonoperating Margins		753,600		110,850			98,250			94,863

Assignable Margins	$	4,048,935	$	(2,009,273	)	$	(1,198,192	)	$	4,568,539

Item 9 – Changes in and Disagreements with

Accountants on Accounting and Financial Disclosure

None

Item 9A – Controls and Procedures

Evaluation of Controls and Procedures

As of the end of the period covered by this Annual Report on Form 10-K, we carried out an evaluation of the effectiveness of the design and operation of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 (“Exchange Act”) Rule 13a-15(e)) under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO). Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective in timely alerting them to material information required to be disclosed in our periodic reports to the SEC, ensures that such information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and such information is accumulated and communicated to our management, including our CEO and CFO, to allow timely decisions regarding required disclosure. 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 were no changes in Chugach’s internal controls over financial reporting identified in connection with the evaluation that occurred during the fourth quarter that has materially affected, or is reasonably likely to materially affect, Chugach’s internal controls over financial reporting.

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 controls 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 controls 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 controls over financial reporting as of December 31, 2011, 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, 2011, Chugach maintained effective internal controls over financial reporting. In addition, there were no changes in Chugach’s internal controls over financial reporting (as defined in Rules 13a-15(f) or 15d-15(f) of the Exchange Act) identified in connection with the evaluation that occurred during the fourth quarter that has materially affected, or is reasonably like to materially affect, Chugach’s internal controls over financial reporting.

Item 9B – Other Information

None

PART III

Item 10 – Directors, Executive Officers and Corporate Governance

Chugach operates under the direction of a Board of Directors that is elected at large by our membership. Day-to-day business and affairs are administered by the CEO. Our seven-member Board sets policy and provides direction to the CEO. Each statutory officer must be a member of the Board, but these officers do not participate in the day-to-day management of Chugach. No member of the Board is an employee of the company nor does any member of the Board have a material relationship with the company. Therefore, the Chugach Board has determined that all members are independent. Our Board of Directors oversees Chugach’s risk management, satisfying itself that our risk management practices are consistent with our corporate strategy.

Identification of Directors

Candidates for our Board of Directors must be nominated by a Nominating Committee. The Nominating Committee is comprised of members selected from different sections of the service area of Chugach. No member of the Board may serve on such committee. The committee reviews the qualifications of the Board candidates and nominates candidates for election at the annual meeting. Any fifty or more members, acting together, may make other nominations by petition.

As required by our bylaws, all of the members of our Board of Directors are elected solely by the vote of our members. We do not have any direct role in the nomination of the candidates or the election of members to our Board of Directors. Therefore, the following director biographies do not include a discussion of the specific experience, qualifications, attributes or skills that led our members to the conclusion that a person should serve as a director on our Board of Directors.

Janet Reiser, 56, Chairman, is a small business owner and management consultant in the emerging technology field. She was elected to the board in 2008, and re-elected in 2011. She currently serves on the Operations, Audit and Finance Committees. She is a National Rural Electric Cooperative Association Credentialed Cooperative Director and has earned her Board Leadership Certificate. Her term expires in May of 2014.

Susan Reeves, 63, Vice Chairman, is the managing member of Reeves Amodio LLC, where she practices law. She has been active on Alaska non-profit boards and commissions for many years. She was elected to the board in 2010. She currently serves on the board’s Finance and Audit Committees. She is a National Rural Electric Cooperative Association Credentialed Cooperative Director and is also Chugach’s Alaska Power Association (APA) Representative. Her term expires in May of 2013.

Doug Robbins, 56, Secretary, is a retired petroleum geologist and manager with 26 years’ experience at Marathon Oil Company. Robbins was appointed by the board to fill a vacant director’s position in 2010, and elected to a 1-year term in the 2011 election. He serves as the Chair of the Audit Committee and Vice Chair of the Operations Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director and is also Chugach’s ARCTEC Representative. His term expires in May of 2012.

P.J. Hill, 67, Treasurer, is a retired professor from the School of Business and Public Policy at the University of Alaska Anchorage. He is also an economic consultant and a commercial fisherman. He was elected to the board in 2007 and re-elected in 2010. Hill is the Board Treasurer and Chairs the Finance Committee and serves on the Audit Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director and has completed the Board Leadership Program. His term expires in May of 2013.

James Nordlund, 59, Director, is Alaska state director of U.S. Department of Agriculture (USDA) Rural Development, as well as the owner of Nordlund Carpentry, LLC. He was elected to the board in 2006 and re-elected in 2009. Mr. Nordlund is a former legislator and state Director of Public Assistance. He currently serves as Chair of the Operations Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2012.

Harry T. Crawford, Jr., 59, Director, is a former Alaska State Legislator, retired iron worker and a small-real estate developer. He was elected to the board in 2011. He currently serves on the Operations and Audit Committees and is the board liaison to the Bylaws Committee and the Renewable Energy Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2014.

Jim Henderson, 65, Director, is a principal with New American Financial Group in the financial services industry. He specializes in asset-based finance products, reorganization and refinancing of distressed companies, and accounting and disposition of capital assets. His primary emphasis is transportation, industrial machinery and aviation operations, assets and industry development. He has over 30 years of experience in consulting and analysis and finance of capital assets. Mr. Henderson has served on various committees for Chugach in the past. Mr. Henderson was elected to the board in 2011. He currently serves on the Operations and Finance Committees. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2014.

Identification of Executive Officers

Bradley W. Evans, 57, 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, 62, was appointed Chief Financial Officer on June 5, 2002. Upon the retirement of the Sr. Vice President, Administration in January of 2011, Mr. Cunningham assumed the responsibilities of the administration department. Prior to the CFO appointment he served as Controller since 1986. Prior to that, he was Budget Analyst and Manager of Accounting since beginning his Chugach employment in 1982. Prior to his Chugach employment, Mr. Cunningham spent 15 years in various capacities with Pacific Northwest Bell Telephone Company.

Edward M. Jenkin, 51, was appointed Vice President, Power Delivery on August 22, 2008. Prior to that appointment he had served as Acting Sr. Vice President, Power Delivery since January 14, 2008. Mr. Jenkin has over 20 years utility experience in engineering, system operations, and planning. He is a Registered Engineer in the State of Alaska. Mr. Jenkin was promoted from the position of the Director, Engineering Services Division that he held since July of 2004. Prior to that Mr. Jenkin served as System Operations Supervisor beginning in February of 2000 and was the Senior Planning Engineer starting August of 1995. Mr. Jenkin began his utility career as an Engineering Technician for Matanuska Electric Association in April of 1982.

Paul R. Risse, 57, 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, 65, retired from Chugach Electric Association, Inc. on January 14, 2011, after more than 16 years of service. Mr. Smith 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 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, 56, 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, 46, was appointed Vice President, Human Resources on March 17, 2008. Mr. Andrews has over 15 years of experience in Human Resources and Labor Relations. Since June of 2008, Mr. Andrews has also served as an appointed board member of the State of Alaska’s labor relations agency. Prior to his employment with Chugach, Mr. Andrews served as the Sr. Manager of Labor Relations for Alaska Communications Systems. Prior to that, he served 10 years with the State of Alaska in a wide range of Human Resources and Labor Relations functions including Human Resources Manager and Chief Spokesperson on numerous collective bargaining teams. Mr. Andrews holds a bachelor’s degree in economics from the University of North Carolina Chapel Hill.

Code of Ethics

Chugach finalized a code of ethics that applies to its principal executive officer, principal financial officer, principal accounting officer and any person performing similar functions on June 16, 2004. In February of 2009, Chugach contracted with an outside firm to provide a financial reporting hotline to support the code of ethics. It is also posted on Chugach’s website at www.chugachelectric.com.

Nominating Committee

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

The Board appoints a nominating committee each year. The committee consists of members selected from different sections of the service area of Chugach. No member of the Board may serve on such committee. The committee reviews the qualifications of the Board candidates and nominates candidates for election at the annual meeting. The committee considers diversity, skills, and such other factors as it deems appropriate given the current needs of the Board and Chugach. Any fifty or more members, acting together, may make other nominations by petition. All seven of our current board members were nominated by the Nominating Committee.

Audit Committee Financial Expert

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

Identification of the Audit Committee

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

The Audit Committee shall be comprised of three or more directors as determined by the Board. Unless otherwise determined by the Board, the members of the Board Finance Committee shall be the members of the Audit Committee. Committee members may enhance their familiarity

with finance and accounting by participating in educational programs conducted by the Association or an outside consultant or other programs. The Committee may also retain the services of a qualified accounting professional with auditing expertise to assist it in the performance of its responsibilities.

The Board Chairman shall appoint the Audit Committee chairperson, with the consent of the Board, who need not be the Board Treasurer. The Audit Committee shall elect from its members a vice chairman, and appoint a recording secretary as needed. Members of the 2011 Audit Committee include Chair Doug Robbins and Directors P.J. Hill, Susan Reeves, Janet Reiser and Harry Crawford.

The disclosure required by §240.10A-3(d) regarding exemption from the listing standards for the audit committees is not applicable to the Chugach Audit Committee.

Item 11 – Executive Compensation

Compensation Discussion and Analysis

In 1986, the NRECA developed the COMPensate wage and salary plan to provide its members with a systematic and standardized method to evaluate jobs in their specific cooperative, grade them, compare wages and salaries with those in similar electric utility systems and in the external marketplace and then create and apply statistically determined, equitable pay scales. In 1988, the Chugach Board approved implementation of NRECA’s COMPensate wage and salary plan for non-bargaining unit employees with the objective of establishing wages and salaries for non-bargaining unit employees that would attract and retain qualified personnel and encourage their superior performance, growth and development.

Each year the regression analysis/compensation model is updated with current salary survey values to insure that the ranges reflect fair market value. The overall change to the salary ranges reflects market changes to the midpoint of the salary ranges and creates an opportunity for but not a guarantee of salary increases. Salary increases are not automatic and are based on performance. Any changes to the COMPensate wage and salary plan for Chugach are approved by the Chugach Board.

CEO Brad Evans is eligible for performance based bonuses at the discretion of the Board of Directors based on performance standards they develop. On January 4, 2012, the Board of Directors adopted a CEO Incentive Program to provide additional bonus opportunities to the CEO outside of the annual CEO performance review. The program sets goals, with specified criteria to be achieved during the 2012 calendar year. Each category of goals; fuel security, financial performance, safety, reliability, renewable energy long range plan, job approval and renewable energy integration is allocated a percentage of a total bonus amount of $50,000. In 2011 and 2010, upon review of the performance of the CEO, Mr. Evans received a discretionary bonus of $20,000 and $12,500, respectively.

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 2011 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, Chief Executive Officer		2011	$	273,266	$	20,000	$	162,766	$	4,407	$	460,439
		2010	$	251,938	$	12,500	$	108,663	$	3,612	$	376,713
		2009	$	250,029	$	40,000	$	98,704	$	3,612	$	392,345

Michael R. Cunningham, Chief Financial Officer		2011	$	200,433	$	20,000	$	205,955	$	13,319	$	439,707
		2010	$	177,012	$	0	$	147,530	$	16,218	$	340,760
		2009	$	172,263	$	15,000	$	184,648	$	9,027	$	380,938

Tyler E. Andrews, Vice President, Human Resources		2011	$	147,619	$	0	$	32,650	$	894	$	181,163
		2010	$	136,858	$	5,000	$	20,447	$	3,093	$	165,398
		2009	$	136,821	$	5,000	$	11,525	$	2,855	$	156,201

Edward M. Jenkin, Vice President, Power Delivery		2011	$	167,761	$	0	$	179,247	$	1,444	$	348,452
		2010	$	163,087	$	0	$	90,446	$	1,202	$	254,735
		2009	$	160,570	$	5,000	$	152,802	$	18,641	$	337,013

Paul R. Risse, Sr. Vice President, Power Supply		2011	$	168,541	$	0	$	137,323	$	2,532	$	308,396
		2010	$	163,970	$	0	$	86,543	$	2,281	$	252,794
		2009	$	163,660	$	10,000	$	84,645	$	7,083	$	265,388

David R. Smith, Former Sr. Vice President, Administration		2011	$	12,386	$	5,000	$	52,126	$	25,871	$	95,383
		2010	$	161,162	$	0	$	45,407	$	20,243	$	226,812
		2009	$	160,949	$	10,000	$	38,558	$	17,154	$	226,661

Lee D. Thibert, Sr. Vice President, Strategic Planning & Corporate Affairs		2011	$	193,133	$	10,000	$	205,468	$	7,318	$	415,919
		2010	$	186,121	$	10,000	$	108,314	$	6,218	$	310,653
		2009	$	185,786	$	15,000	$	127,212	$	7,288	$	335,286

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

Pension Benefits

We have elected to participate in the NRECA Retirement Security Plan (the “Plan”), a multiple employer defined benefit master pension plan maintained and administered by the NRECA for the benefit of its members and their employees. Under ASC 960, “Topic 960 – Plan Accounting – Defined Benefit Pension Plans,” the plan is a multi- employer plan, in which the accumulated benefits and plan assets are not determined or allocated separately to individual employers. The Plan is intended to be a qualified pension plan under Section 401(a) of the Code. All our employees not covered by a union agreement become participants in the Plan on the first day of the month following completion of one year of eligibility service. An employee is credited with one year of eligibility service if he or she completes 1,000 hours of service either in his or her first twelve consecutive months of employment or in any calendar year for us or certain other employers in rural electrification (related employers). Pension benefits vest at the rate of 10 percent for each of the first four years of vesting service and become fully vested and non-forfeitable on the earlier of the date a participant has five years of vesting service or the date the participant attains age fifty-five while employed by us or a related employer. A participant is credited with one year of vesting service for each calendar year in which he or she performs at least one hour of service for us or a related employer. Pension benefits are generally paid upon the participant’s retirement or death. A participant may also elect to receive pension benefits while still employed by us if he or she has reached his normal retirement date by completing thirty years of benefit service (defined below) or, if earlier, by attaining age sixty-two. A participant may elect to receive actuarially reduced early retirement pension benefits before his or her normal retirement date provided he or she has attained age fifty-five.

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

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

Benefit service as of December 31, 2011 that is taken into account under the Plan for the executive officers is shown below with the assumptions for calculation of the present value of accumulated benefits.

Pension Benefits Table


Name	Plan	Credited Years of Service		Present Value of Accumulated Benefit		Payments During Last Fiscal Year

Bradley W. Evans, Chief Executive Officer	Retirement Security		10.83	$	601,082	$	0
Bradley W. Evans, Chief Executive Officer	Pension Restoration		10.83	$	8,628	$	0

Michael R. Cunningham, Chief Financial Officer	Retirement Security		28.08	$	1,489,414	$	0

Lee D. Thibert, Sr. Vice President, Strategic Planning & Corporate Affairs	Retirement Security		23.33	$	1,078,638	$	0

Paul R. Risse, Sr. Vice President, Power Supply	Retirement Security		15.92	$	608,396	$	0

David R. Smith,¹ Former Sr. Vice President, Administration	Retirement Security		3.5	$	0	$	155,424

Edward M. Jenkin, Vice President, Power Delivery	Retirement Security		21.08	$	745,232	$	0

Tyler E. Andrews, Vice President, Human Resources	Retirement Security		2.8	$	64,622	$	0

¹	Mr. Smith retired as of January 14, 2011 and was paid the value of all of his pension benefits.

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 (4.19 percent for 2011 and 4.31 percent for 2010) and the Pension Protection Act (PPA) three-segment yield rates (2.16 percent, 4.77 percent, and 6.05 percent for 2011 and 3.13 percent, 5.07 percent, and 5.50 percent for 2010) and the required IRS mortality table for lump sum payments (1994 Guaranteed Annuity Rate (GAR), projected to 2002, blended 50 percent/50 percent for unisex mortality in combination with the 30-year Treasury rates and Retirement Plan (RP) 2000 PPA at 2011 and

2010, respectively, combined unisex 50 percent/50 percent mortality in combination with the PPA rates). The lump sum is then discounted at 3.91 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2011, and 5.15 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2010, to determine the present value for the appropriate year.

Deferred Compensation

Prior to 2011 Chugach participated in NRECA’s Deferred Compensation Plan. Effective January 1, 2011, Chugach transferred to Vanguard, an 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), the 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 Vanguard Funds, a family of no-load mutual funds. Each participant in the Program determines the investment fund or funds into which their accounts are invested. The amounts credited to the deferred compensation account, including gains and losses, are retained by Chugach until the entire amount credited to the account has been distributed to the Participant or to the Participant’s beneficiary.

Deferred Compensation Table


Name	Executive Contributions in last FY		Registrant Contributions in last FY		Aggregate Earnings in last FY			Aggregate Withdrawals/ Distributions		Aggregate balance at FYE

Bradley W. Evans, Chief Executive Officer	$	16,500	$	0	$	(360	)	$	0	$	64,736

Michael R. Cunningham, Chief Financial Officer	$	22,000	$	0	$	(147	)	$	0	$	157,922

Tyler E. Andrews, Vice President, Human Resources	$	6,000	$	0	$	(543	)	$	0	$	5,457

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. If Mr. Evans is terminated by Chugach without cause, he will receive a lump sum payment equal to 50% of his annual Base Salary and the full cost of health and welfare coverage for a period not in excess of 6 months.

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	$	259,421

Michael R. Cunningham, Chief Financial Officer	$	158,870

Tyler E. Andrews, Vice President, Human Resources	$	46,309

Edward M. Jenkin, Vice President, Power Delivery	$	119,372

Paul R. Risse, Sr. Vice President, Power Supply	$	184,586

Lee D. Thibert, Sr. Vice President, Strategic Planning & Corporate Affairs	$	133,013

Director Compensation

Directors are compensated for their services at the rate of $300 per Board meeting and $200 per other meeting at which they are representing the Association in an official capacity within the State of Alaska, and $350 per day when attending meetings or training outside of the State, including a fee for 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, 2011 to each of our current and former Board members:

Director Compensation Table


Name	Fees Paid In Cash

Janet Reiser, Chairman and Director	$	14,800

Susan Reeves, Vice-Chairman and Director	$	11,350

Doug Robbins, Secretary and Director	$	11,750

P.J. Hill, Treasurer and Director	$	10,000

James Nordlund, Director	$	9,200

Harry Crawford, Jr., Director	$	7,250

Jim Henderson, Director	$	8,700

Rebecca Logan, Former Director	$	4,400

Elizabeth Vazquez, Former Director	$	4,400

Two new board members were elected, one current board member who was previously appointed to fill a vacancy was elected and one current board member was re-elected at Chugach’s annual membership meeting held on May 26, 2011. Harry Crawford and James Henderson were elected to three-year terms, Doug Robbins was elected to fill the remaining term of Director Elizabeth “Pat” Kennedy, who passed away on October 23, 2010, and Janet Reiser was re-elected to a three-year term.

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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, 2011.

Fees and Services

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


	2011		2010
Audit and audit-related services:
Audit and quarterly reviews	$	237,990	$	155,675
Audit-related services (Employee benefit plans)		17,000		17,000
Non-audit services:
Tax consulting and return preparation		64,890		14,430
Other services¹		39,752		10,000

Total	$	359,632	$	197,105

¹	Other services in 2011 included the review of a new customer accounting system

Other services in 2010 included Sarbanes-Oxley implementation

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, 2011 and 2010 were approved by the Audit Committee.

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PART IV

Item 15 – Exhibits and Financial Statement Schedules


	Page
Financial Statements

Included in Part II of this Report:		51
Report of Independent Registered Public Accounting Firm
Balance Sheets, December 31, 2011 and 2010		52-53
Statements of Operations, Years ended December 31, 2011, 2010 and 2009		54
Statements of Changes in Equities and Margins, Years ended December 31, 2011, 2010 and 2009		55
Statements of Cash Flows, Years ended December 31, 2011, 2010 and 2009		56
Notes to Financial Statements		57-88

Other schedules are omitted as they are not required or are not applicable, or the required information is shown in the applicable financial statements or notes thereto.

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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. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2001, SEC File No. 033-42125.

3.2		Bylaws of the Registrant. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated May 26, 2011, SEC File No. 033-42125.

4.11		Tenth Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.

4.12		Eleventh Supplemental Indenture of Trust between the Registrant and U.S. Bank Trust National Association. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated December 21, 2001, SEC File No. 333-75840.

4.13		Amended and Restated Indenture between the Registrant and U.S. Bank Trust National Association dated April 1, 2001. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.

4.14		Form of 2001 Series A Bond due 2011. Previously filed as an exhibit to the Registrant’s Amendment No. 1 to Registration Statement on Form S-1 dated April 10, 2001, SEC File No. 333-57400.

4.15		Form of 2002 Series A Bond due 2012. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated December 21, 2001, SEC File No. 333-75840.

4.17		First Supplemental Indenture to the Amended and Restated Indenture dated April 1, 2001 between the Registrant and U.S. Bank National Association dated January 19, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

4.18		Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated January 20, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

4.19		First Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated January 20, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

4.20		Bond Purchase Agreement between the Registrant and the 2011 Series A Bond Purchasers dated January 21, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

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4.21		Form of 2011 Series A Bond (Tranche A) due March 15, 2031. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

4.22		Form of 2011 Series A Bond (Tranche B) due March 15, 2041. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

4.23		Second Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated September 30, 2011. Filed Herewith.

4.24		Third Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated January 5, 2012. Filed Herewith.

4.25		Bond Purchase Agreement between the Registrant and the 2012 Series A Bond Purchasers dated January 11, 2012. Filed Herewith.

4.26		Form of 2012 Series A Bond (Tranche A) due March 15, 2032. Filed Herewith.

4.27		Form of 2012 Series A Bond (Tranche B) due March 15, 2042. Filed Herewith.

4.28		Form of 2012 Series A Bond (Tranche C) due March 15, 2042. Filed Herewith.

10.2		Joint Use Agreement between the Registrant and the City of Seward dated effective as of September 11, 1998. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.3		Net Billing Agreement among the Registrant and the City of Seward dated effective as of September 11, 1998. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125.

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 February 27, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.

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10.6		Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of January 30, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1994, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.7		Power Purchase Agreement by and between Fire Island Wind, LLC and the Registrant dated as of June 21, 2011. Filed Herewith.

10.8		Agreement for the Sale and Purchase of Natural Gas between the Registrant and ARCO Alaska, Inc. dated April 21, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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

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. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999, SEC File No. 033-42125.

10.9		Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and ARCO Alaska, Inc. dated October 3, 1991. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.10		Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company dated September 26, 1988. (Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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10.10.1		Letter Agreement dated September 26, 1988 between the Registrant and Marathon Oil Company, amending the Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Oil Company. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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

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

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. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999, SEC File No. 033-42125.

10.11		Agreement for the Sale and Purchase of Natural Gas between the Registrant and Shell Western E&P Inc. dated April 25, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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10.11.3		Amendatory Agreement No. 3 to the Agreement for the Sale of Natural Gas between the Registrant and Shell Western E&P Inc. dated October 14, 1996. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1996, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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). Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999, SEC File No. 33-42125.

10.14		Agreement for the Sale and Purchase of Supplemental Natural Gas between the Registrant and Chevron USA, Inc. dated September 25, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.15.1		Amended and Restated Alaska Intertie Agreement Among Alaska Energy Authority, Municipality of Anchorage d/b/a Municipal Light and Power, the Registrant, Golden Valley Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc. dated November 18, 2011. Filed Herewith.

10.16		Addendum No. 1 to the Alaska Intertie Agreement-Reserve Capacity and Operating Reserve Responsibility dated December 23, 1985. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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10.17		Memorandum of Understanding Regarding Intertie Upgrades among Alaska Energy Authority, the Registrant, Golden Valley Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power, and the City of Seward d/b/a Seward Electric System dated March 21, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.18		Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1993, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1993, SEC File No. 033-42125.

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

10.22		Amendment No. 1 to the 1993 Alaska Intertie Project Participants Agreement dated December 10, 1999. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.

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

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10.24		Bradley Lake Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated December 8, 1987. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125.

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10.29		Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated September 29, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.

10.30		Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated December 2, 1983. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.30.1		Addendum No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated August 8, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.30.2		Amendment No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated November 28, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.31		Gas Transportation Agreement by and among the Registrant, Alaska Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.33		Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. Previously reported as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1997, SEC File No. 033-42125.

10.34		Amended and Restated Agreement for Sale of Electric Capacity between the Registrant and Alaska Electric and Energy Cooperative, Inc. effective December 31, 2011. Filed Herewith.

10.35		FSS Service Agreement between Cook Inlet Natural Gas Storage Alaska, LLC and the Registrant, effective October 26, 2011. Filed Herewith.

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10.36		Agreement by and among the Registrant, Municipality of Anchorage d/b/a Anchorage Municipal Light and Power, Matanuska Electric Association, Inc., U.S. Fish and Wildlife Service, National Marine Fisheries Service, Alaska Energy Authority and the State of Alaska re: the Eklutna and Snettisham Hydroelectric Projects. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125.

10.37		Daves Creek Substation Agreement between the Registrant and the Alaska Energy Authority dated March 13, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1999, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2001, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.

10.39.4		Third Amendment to the Nikiski Cogeneration Plant System Use and Dispatch Agreement between the Registrant and Homer Electric Association, Inc. dated effective November 6, 2009. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2009, SEC File No. 033-42125.

10.40		Lease Amendment between the Registrant and Standard Oil Company of California dated June 1, 1975. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.41		Lease Amendment between the Registrant and Chevron USA, Inc. dated September 1, 1985. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

10.45.8		Amended and Restated Master Loan Agreement between the Registrant and CoBank, ACB dated January 19, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

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10.45.9		Second Amended and Restated Supplement between the Registrant and CoBank, ACB, dated January 19, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

10.45.10		Form of 2011 CoBank Note dated January 19, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

10.47.1		Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 14, 2007. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2007, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2008, SEC File No. 033-42125.

10.49		2010 Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch dated November 17, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.

10.59.1		Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Office and Engineering Personnel dated effective July 1, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125.

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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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.

10.60.1		Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Generation Plant Personnel dated effective July 1, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.

10.61.1		Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Outside Plant Personnel dated effective July 1, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125.

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.

10.64		Employment Agreement between the Registrant and Bradley W. Evans dated effective July 1, 2008. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated August 27, 2008, SEC File No. 033-42125.

10.64.1		Employment Agreement between the Registrant and Bradley W. Evans dated effective July 1, 2011. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated June 15, 2011, SEC File No. 033-42125.

10.65		Agreement for the Sale and Purchase of Natural Gas between the Registrant and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively, ConocoPhillips) effective August 21, 2009. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated August 21, 2009, SEC File No. 033-42125.

10.66		Agreement for the Sale and Purchase of Natural Gas between the Registrant and Marathon Alaska Production, LLC (MAP) effective May 17, 2010. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated May 17, 2010, SEC File No. 033-42125.

10.67		Engineering, Procurement and Construction Contract between the Registrant and SNC-Lavalin Constructors, Inc. dated effective June 18, 2010. Confidential portions have been omitted and filed separately with the Commission on a Confidential Treatment Request. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2010, SEC File No. 033-42125.

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10.68		Transportation Agreement between the Registrant and Beluga Pipeline Company dated effective October 1, 2010. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125.

10.69		Transportation Agreement For Interruptible Transportation Of Natural Gas between the Registrant and Kenai Nikiski Pipeline dated effective October 1, 2010. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125.

10.70		Gas Exchange Contract between the Registrant and Union Oil Company of California dated effective October 1, 2010. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125.

10.71		Gas Transportation Agreement between the Registrant and Alaska Pipeline Company and ENSTAR Natural Gas Company effective November 17, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2010, SEC File No. 033-42125.

10.72		Gas Transportation Agreement between the Registrant and ENSTAR Natural Gas Company effective November 1, 2011. Filed Herewith.

14		Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2004, SEC File No. 033-42125.

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.

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

XBRL (“Extensible Business Reporting Language”) information is furnished and not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

114

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 14, 2012.


CHUGACH ELECTRIC ASSOCIATION, INC.

By:		/s/ Bradley W. Evans
		Bradley W. Evans, Chief Executive Officer

Date:		March 14, 2012

115

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 14, 2012, by the following persons on behalf of the registrant and 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 R. Risse
Paul R. Risse		Sr. Vice President, Power Supply

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

/s/ Edward M. Jenkin
Edward M. Jenkin		Vice President, Power Delivery

/s/ Tyler E. Andrews
Tyler E. Andrews		Vice President, Human Resources

/s/ Janet Reiser
Janet Reiser		Director & Chairman of the Board


Susan Reeves		Director & Vice-Chairman of the Board


P. J. Hill		Director & Treasurer of the Board

/s/ Doug Robbins
Doug Robbins		Director & Secretary of the Board

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/s/ James Nordlund
James Nordlund		Director

/s/ Harry T. Crawford
Harry T. Crawford		Director


Jim Henderson		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 2011 and will not make such a report after the filing of this Form 10-K. As a consequence, no copies of any such report will be furnished to the Securities and Exchange Commission.

117