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, 2012

or

¨ 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.    ¨  Yes    x  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.

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

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.

2012 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		17
Item 2 – Properties		18
Item 3 – Legal Proceedings		27
Item 4 – Mine Safety Disclosures		27
PART II
Item 5 – Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		27
Item 6 – Selected Financial Data		28
Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operation		29
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		92
Item 9A – Controls and Procedures		92
Item 9B – Other Information		93
PART III
Item 10 – Directors, Executive Officers and Corporate Governance		93
Item 11 – Executive Compensation		97
Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		103
Item 13 – Certain Relationships and Related Transactions, and Director Independence		103
Item 14 – Principal Accounting Fees and Services		104
PART IV
Item 15 – Exhibits and Financial Statement Schedules		105
SIGNATURES		116

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CAUTION REGARDING FORWARD-LOOKING STATEMENTS

Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. Chugach Electric Association, Inc. (Chugach) undertakes no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this report or the effect of those events or circumstances on any of the forward-looking statements contained in this report, except as required by law.

PART I

Item 1 – Business

General

Chugach was organized as an Alaska electric cooperative in 1948. Cooperatives are business organizations that are owned by their members. As not-for-profit organizations (Internal Revenue Code 501 (c)(12)), cooperatives are structured to provide services to their members at cost, in part by eliminating the need to produce profits or a return on equity other than for reasonable reserves and margins. Today, cooperatives in general operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and credit. All cooperatives are based upon similar principles and legal foundations. Because members’ equity is not considered an investment, a cooperative’s objectives and policies are oriented to serving member interests, rather than maximizing return on investment.

Chugach makes its current and periodic reports available, free of charge, on its website at www.chugachelectric.com as soon as practicable after filing with the Securities and Exchange Commission (SEC). Our website 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 82,004 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). Chugach’s hydro project is licensed by the Federal Energy Regulatory Commission (FERC). As such, Chugach is subject to FERC reporting requirements and our account records conform to the Uniform System of Accounts as prescribed by FERC. 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

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preceding year. This tax is accrued monthly and remitted annually. In addition, we currently collect a regulatory cost charge (RCC) of $0.000568 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 28, 2013. 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 three IBEW CBA’s were extended by the Board of Directors (Board) on February 24, 2010. The three extensions provided for 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 had an indirect connection to Chugach’s financial performance. The contract extensions expire on June 30, 2013. On April 28, 2010, the Board approved a three year extension of the HERE agreement. The extension contained an increase in the employer health and welfare contribution in each year of the extension but did not provide for a wage or pension increase. The contract extension also expires on June 30, 2013. Two of the bargaining units have ratified tentative agreements extending their labor agreements through June 30, 2017. Chugach is currently negotiating with the final IBEW bargaining unit. 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, 2012, we had three major wholesale customers and 67,631 retail members receiving service at approximately 82,004 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 Chugach deems it appropriate to do so.

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In 2012, we had 462.6 megawatts (MW) of installed generating capacity provided by 14 generating units at our four owned power plants: Beluga 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.” On February 1, 2013, the Southcentral Power Plant (SPP) began commercial operation, furnishing 183 MW of base capacity provided by 4 generating units. Chugach will own and take approximately 70 percent of this plant’s output and ML&P will own and take the remaining 30 percent. In 2012, approximately 82 percent (by rated capacity) of our generating capacity was fueled by natural gas, which we purchased under gas contracts. The rest of our owned generating resources are hydroelectric facilities. In 2012, 89 percent of our power was generated from gas, which included power generated at Nikiski, and 83 percent of that gas-fired generation took place at Beluga. The Bradley Lake Hydroelectric Project provides up to 27.4 MW for our retail customers and up to 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 and 67 MW from the Bernice Lake power plant on the Kenai Peninsula and up to 17.6 MW from the Fire Island Wind project. 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, 2012, we sold 2.6 billion kWh of electrical power.

Customer Revenue From Sales

The following table shows the MWh energy sales to and electric revenues from our retail, wholesale, and economy energy customers for the year ended December 31, 2012:

	MWh		2012 Revenues		Percent of Sales Revenue
Direct retail sales:
Residential		549,748	$	76,082,694	29%
Commercial		629,088		73,272,498	27%
Total		1,178,836		149,355,192	56%
Wholesale sales:
MEA		782,510		62,278,074	24%
HEA		488,941		38,344,762	15%
Seward		65,671		4,801,814	2%
Total		1,337,122		105,424,650	41%
Economy energy/other1		90,765		9,025,467	3%
Total from sales		2,606,723		263,805,309	100%
Miscellaneous energy revenue				3,166,159
Total energy revenues			$	266,971,468

¹  Economy energy/other includes sales from GVEA.

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Retail 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, including Fire Island, to Whittier on the east and to the Glenn Highway on the north.

Retail Customers

As of December 31, 2012, we had 67,631 members receiving power from approximately 82,004 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 2012, our wholesale power contracts, including the fuel and purchased power components, produced $105.4 million in revenues, representing 39 percent of our total revenues and 51 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 2012, sales to MEA represented approximately 30 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.

The terms of the MEA/Chugach Power Sales Agreement require 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.

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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. After open discussions and proposals regarding power sales possibilities beyond 2014, in February 2012, Chugach received a response from MEA which indicated it is following the path its membership most favored and is moving forward with plans to build its own generation plant.

HEA

We have a power sales contract with Alaska Electric and Energy Cooperative, Inc. (AEEC) for firm, partial-requirement sales to HEA. Our power sales agreement is assigned to AEEC and the Nikiski dispatch agreement is assigned to HEA with certain exceptions with the remaining rights and obligations under the Dispatch Agreement being assigned to AEEC (discussed below). 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. HEA’s remaining resource requirements are provided by AEEC’s Nikiski cogeneration facility, the Bernice Lake Power Plant and AEEC’s contract rights to receive power from the Bradley Lake Hydroelectric Project for the benefit of HEA. In 2012, sales to HEA represented approximately 19 percent of Chugach’s total sales of energy (including both retail and wholesale).

We have a dispatch agreement with 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.

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 was $6.9 million at December 31, 2012.

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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 agreed to sell and AEEC agreed to purchase the Bernice Lake Power Plant located in Nikiski, Alaska. The sale also included associated transmission substation facilities located on the premises. The Bernice Lake facility is located on land that was 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 million 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 gives Chugach the right 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 allowed 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 2012, sales to Seward represented approximately 3 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.

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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.

On October 5, 2012, Chugach and GVEA finalized arrangements for Chugach to provide economy energy to GVEA until March of 2015. Sales will be made under the terms and conditions of Chugach’s economy energy sales tariff. The price to GVEA will include the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin. Chugach has also entered into specific gas supply arrangements to make economy energy sales to GVEA. Non-firm sales to GVEA have been 90,765 MWh, 235,378 MWh and 277,793 MWh for 2012, 2011, and 2010, respectively.

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 quarterly 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 and Purchased Power Recovery.”

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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 Amended Unsecured Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank, ACB and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch, which 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.

For the years ended December 31, 2012, 2011 and 2010, our Margins for Interest/Interest (MFI/I) was 1.23, 1.30 and 1.26, respectively. For the same periods, our TIER was 1.24, 1.58 and 1.44, 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 fertilizer 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 percent share of the plant. 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

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options open. Operations were extended into November of 2011 and exports resumed in the summer of 2012, however, the plant’s future remains unclear. 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)	2013		2014		2015		2016		2017
Retail		1,176,000		1,177,000		1,179,000		1,181,000		1,183,000
Wholesale		1,283,000		838,000		63,000		63,000		63,000
Total		2,459,000		2,015,000		1,242,000		1,244,000		1,246,000

Retail energy sales are expected to remain relatively flat due to slow economic growth and progress in energy efficiency and conservation from 2013 to 2017. At the end of 2013, HEA’s contract to purchase their net requirements from Chugach expires, causing system energy sales to decrease by approximately 18 percent. At the end of 2014, MEA’s contract to purchase their full requirements from Chugach expires, resulting in a decrease of approximately 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. 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.

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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 November 17, 2010, Chugach entered into a $300.0 million Unsecured Credit Agreement, which is used to back Chugach’s Commercial Paper program. Effective May 4, 2012, Chugach reduced the commitment amount to $100.0 million and on June 29, 2012, amended and extended the Credit Agreement to update the pricing and extend the term. The Amended Unsecured Credit Agreement now expires on November 17, 2016. Chugach is expected to continue to issue commercial paper in 2013, 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. If Chugach were unable to access that market, the Amended Unsecured Credit Agreement would be utilized to support Chugach’s Commercial Paper program. 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 $100.6 million, or 39 percent and $104.0 million, or 37 percent in 2012 and 2011, 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 39 percent of the utility’s annual sales revenue. In February 2012, Chugach received a response from MEA which indicated it is following the path its membership most favored and is moving forward with plans to build its own generation plant.

Chugach’s planning process reflects the expected termination of the MEA and HEA wholesale contracts post 2014. Consequently, to mitigate this risk, Chugach plans to pursue 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

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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. 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 deficit reduction contributions to maintain minimum funding standards.

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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 or environmental disasters. 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 Plant (SPP)

On February 1, 2013, the natural gas-fired generation plant being developed jointly with ML&P near our Anchorage headquarters began commercial operation. SPP equipment was procured with warranties and a service plan is in place to provide planned and unplanned maintenance coverage for the plant’s three gas turbines and related generators for a period of fifteen years. While we have these additional safeguards in place, SPP is, nevertheless, subject to equivalent risks as our existing fleet.

Fuel Supply

In 2012, 89 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 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 mobilizing 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 were up and several gas producers new to Cook Inlet have plans to drill in 2013. The State of Alaska recently took in approximately $6.9 million in bids at its area-wide Cook Inlet oil and gas lease sale, the second-highest dollar volume for a Cook Inlet sale since area-wide sales began in 1999. The three major bidders were all large current leaseholders and much of the bidding appeared to be filling in around existing leasehold positions. Hilcorp Alaska, LLC (Hilcorp) purchased Chevron’s subsidiary Union Oil Company of California January 1, 2012, and purchased Marathon Alaska Production assets effective February 1, 2013.

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Chugach, ML&P and ENSTAR, a Southcentral natural gas distribution company, retained a consulting firm to forecast Cook Inlet gas production. A study was issued in October of 2012 that estimated if the current pace of drilling activity were to continue, along with no additional discoveries brought to production, a shortfall in Cook Inlet gas supply in 2015 could result.

Although Railbelt utilities have the ability to utilize existing oil-fired generation to meet a significant portion of the Railbelt load, Chugach is also evaluating the implementation of dual fuel at SPP, gas importation and enhanced storage capabilities. Chugach believes these measures, along with existing incentives to natural gas producers, improves fuel security and supply in Southcentral Alaska.

Chugach, as part of a group of utilities in Southcentral Alaska, has asked for proposals for imported Liquefied Natural Gas (LNG) or Compressed Natural Gas (CNG) to supplement declining production from Cook Inlet gas fields. The proposals are currently in evaluation. The utility group plans to make a decision on the most viable import option in the first quarter of 2013.

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.

The Cook Inlet Natural Gas Storage Alaska (CINGSA) began service April 1, 2012. The facility has 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 was 2.4 BCF in 2012, reducing to 2.3 BCF in 2013. Injections into the facility began in 2012 with limited withdrawals in the third and fourth quarters of 2012. 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 a Firm Storage Service (FSS) Agreement between the seller and Chugach in July of 2011.

Cooper Lake Hydroelectric Project

The Cooper Lake Hydroelectric Project received a 50-year license from 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. If the project is not feasible or if the cost estimate materially exceeds the terms of the license, Chugach has the option to request a license amendment. At the time the project was being relicensed the estimated cost to complete the project was $12.0 million. The current estimate to complete the project is now $21.9 million. As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska. Funding for this project includes $0.6 million in grants received, $5.8 million in grants authorized and $3.5 million in grants requested. The Chugach Board authorized expenditures for the project November 15, 2012. The diversion project will be constructed in 2013 and 2014, and will operate through the duration of the license.

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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, 2012, Chugach had over-recovered $13.7 million and at December 31, 2011, Chugach had under-recovered $1.2 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.

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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 could possibly be responsible for increased frequency of warmer weather, including 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, some members of the U.S. Congress and administrative agencies of the federal government have been pursuing policies that seek 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. Federal administrative agencies, primarily the Environmental Protection Agency may seek to exercise existing authority under the Clean Air Act to limit carbon emissions.

The additional costs related to a GHG tax or cap and trade program, or other regulatory action could affect the relative cost of the energy Chugach produces. At the present time, 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.

Fire Island Wind Project

All construction and commissioning activity necessary for the Fire Island Wind Project to commence regular operation, in accordance with the Power Purchase Agreement (PPA) between Chugach and Fire Island Wind, LLC (FIW) dated June 21, 2011, and the Interconnection & Integration Agreement (I&I Agreement) dated September 13, 2011, has been completed. As of December 31, 2012, the “Commercial Operation Date” was deemed to have occurred under both the PPA and the I&I Agreement.

There are matters that remain outstanding under the PPA, the I&I Agreement and the Build Transfer Agreement (BTA) dated November 16, 2011. Chugach and Cook Inlet Transmission, LLC (CIT) have yet to resolve these issues. It is Chugach’s position that CIT has not satisfied the required conditions for transferring title, risk of loss, care, custody and control of certain facilities to Chugach under the BTA. If Chugach were to take title of certain facilities in their current state, Chugach may incur additional operation and maintenance risk.

Item 1B – Unresolved Staff Comments

None

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Item 2 – Properties

General

In 2012, we had 462.6 MW of installed capacity consisting of 14 generating units at four power plants. These included 385.0 MW of operating capacity at the Beluga facility on the west side of Cook Inlet; 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.” On February 1, 2013, SPP began commercial operation, furnishing 183 MW of base capacity provided by 4 generating units. Chugach will own and take approximately 70 percent of this plant’s output and ML&P will own and take the remaining 30 percent. 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 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, IGT and SPP. 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. Project construction is scheduled for 2013 and 2014.

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Cooper Lake Units 1 and 2 were taken out of service in October of 2012 for annual maintenance and annual inspections were completed at that time. 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. Chugach operates the plant and ML&P maintains the plant.

Our primary generation units at Beluga are units 3, 5, 6, 7, and 8. These units have a combined capacity of 345.8 MW and met most of our load in 2012. 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. In 2011, Unit 3 received a scheduled hot gas path inspection, in which several hot gas path parts were replaced. Combustion inspections were performed on Unit 3 in 2010, 2011 and 2012 in accordance with the existing maintenance plan. Beluga Unit 5 continued to have two combustion inspections in 2010 and 2012. In 2011, Unit 5 received a major inspection which involved replacement of turbine rotor parts. In 2010, Unit 6 received a major inspection in which many of the major components were replaced with new or refurbished ones. Unit 6 had an annual inspection in 2011 and 2012. During the Unit 6 2012 annual inspection, combustion components nearing end of life were also replaced. Beluga Unit 7 had a major inspection in 2012, in which many of the major components were replaced with new or refurbished parts and annual inspections were performed in 2010 and 2011. Beluga Unit 8, a steam turbine generator, received a major inspection in 2012. Annual inspections were performed on Unit 8 in 2010 and 2011.

On February 1, 2013, SPP began commercial operation, furnishing 183 MW of base capacity provided by 4 generating units. Chugach will own and take approximately 70 percent of this plant’s output and ML&P will own and take the remaining 30 percent. Chugach will proportionately account for its ownership in SPP.

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The following matrix depicts nomenclature, run hours for 2012 and percentages of contribution and other historical information for all Chugach generation units.

Facility	Commercial Operation Date	Nomenclature	Rating (MW)(1)			Run Hours (2012)			Percent of Total Run Hours			Percent of Time Available
Beluga Power Plant (3)
1	1968	GE Frame 5		19.6			452.5			0.9			93.7
2	1968	GE Frame 5		19.6			311.4			0.6			95.1
3	1973	GE Frame 7		64.8			6,729.2			13.1			92.9
5	1975	GE Frame 7		68.7			6,665.4			13.0			91.8
6	1976	AP 11DM-EV		79.2			8,429.7			16.4			96.0
7	1978	AP 11DM-EV		80.1			6,522.2			12.8			74.3
8	1981	BBC DK021150(2)		53.0			7,306.6			14.3			88.7
				385.0
Cooper Lake Hydroelectric Project
1	1960	BBC MV 230/10		9.6			5,180.7			10.1			96.3
2	1960	BBC MV 230/10		9.6			4,473.2			8.7			95.1
				19.2
IGT Power Plant
1	1964	GE Frame 5		14.1			2,229.0			4.3			97.3
2	1965	GE Frame 5		14.1			1,810.5			3.5			98.8
3	1969	Westinghouse 191G		18.5			1,165.0			2.3			98.1
				46.7
Eklutna Hydroelectric Project
1	1955	Newport News		5.8	(4)		N/A	(5)		N/A	(5)		96.9
2	1955	Oerlikon custom		5.9	(4)		N/A	(5)		N/A	(5)		98.3
				11.7
System Total				462.6			51,275.4			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 was 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 23.5 MW.

⁽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.

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

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Transmission and Distribution Assets

As of December 31, 2012, our transmission and distribution assets included 43 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. In 2012, Chugach completed a new substation to connect SPP to the Chugach and ML&P systems. We own the land on which 24 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 Point Woronzof substations under rights from the Alaska Department of Transportation and Public Facilities and the Ted Stevens Anchorage 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 Park 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.

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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 $166.0 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 and purchased power adjustment process. The share of Bradley Lake indebtedness for which we are responsible is approximately $28.7 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 $5.1 million as a result of Chugach’s Bradley Lake take-or-pay obligations.

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On July 1, 2010, AEA issued $28.8 million of Power Revenue Refunding Bonds, Sixth Series, for purposes of refunding $30.6 million 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 received its proportionate share of this savings which represented a reduction in debt-service costs recorded as purchased power expense.

The State of Alaska provided an initial grant for work on a project to divert water from Battle Creek into Bradley Lake. The project is being managed by the Alaska Energy Authority and pending financing, could 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 up to 40,000 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 2012, 89 percent of our power was generated from natural gas, which included power generated at Nikiski, and 83 percent of that gas-fired generation took place at Beluga.

Total gas usage in 2012 was approximately 27.2 BCF. In 2012, our sources of natural gas for firm sales were primarily divided among contracts with two major oil and gas companies. All of the production came from Cook Inlet, Alaska. ConocoPhillips Alaska Inc. under their current contract provided 24.2 percent of gas supplied for generation, while Marathon Oil Company provided 72.0 percent. The current contract with ConocoPhillips provided gas beginning in 2010 and will expire December 31, 2016. The current 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 percent of Chugach’s needs through December 31, 2014. Gas to provide economy energy sales to GVEA was supplied by a gas supply arrangement with Hilcorp. The current economy gas supply arrangement with Hilcorp will supply gas during the summer months of 2013 and 2014.

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.

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The 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. These contracts expired on March 31, 2011.

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 2013 the Firm Fixed Quantity value has been calculated at 34,500 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, ($3.327 per Mcf on January 1, 2013). 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.” ($4.214 per Mcf on January 1, 2013), 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.

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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, which includes two contract extension options that were exercised in 2011. The total amount of gas under contract is now estimated to be 40 billion cubic feet (BCF).

Pricing for the second twelve month term of the MAP contract has been set at the contract floor price of $6.10 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, 2012) for the period April 2012 through March 2013 being set at $2.98 per Mcf, which was lower than the price floor making the price floor the pricing level for the second twelve month period.

Chevron/UNOCAL / Hilcorp

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, (Hilcorp) 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 recovered directly from its economy energy customer.

Natural Gas Transportation Contracts

The terms of the COP, MAP and Hilcorp agreements require Chugach to transport gas. Chugach took over the transportation obligation for natural gas shipments for gas supplied under its contracts on October 1, 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 and HEA’s Bernice Lake Power Plant at a transportation rate of $0.6311 per Mcf. The agreement contains a fixed monthly customer charge of $2,600 for firm service.

In November of 2012 Chugach and ENSTAR entered into a Special Contract for Natural Gas Transportation Service to provide for the transport of gas to our Beluga power plant beginning November 1, 2012, through October 31, 2013, on an interruptible basis. This special contract has been approved by the RCA. Chugach expects to recover this cost through the fuel and purchased power recovery process.

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Chugach and ENSTAR entered into a Firm Transportation Service Agreement on May 21, 2012, to provide for the transportation of gas to our Southcentral Power Project. The agreement commenced on August 1, 2012, and shall remain in effect through August 1, 2013, and year to year thereafter until canceled upon a twelve month written notice by either party. The agreement sets a contracted peak demand of 36,000 Mcf per day.

Hilcorp Alaska, LLC

Effective October 1, 2012, Chugach and Hilcorp entered into a gas exchange agreement to exchange gas which Chugach has entered into agreements to deliver on the east side of Cook Inlet with gas that Hilcorp may have on the west side of Cook Inlet. The agreement terminates on September 30, 2013, or within a 30 day notice by either party.

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 Kachemak Pipeline (KKPL). Chugach has entered into tariff agreements to ship gas on the KNPL, BPL and CIGGS.

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 Clean Air Act establish ambient air quality standards and limit the emission of many air pollutants.

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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, or 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.

SPP was required by its Air Quality Permit to collect ambient air background data. Data collection began on September 1, 2011 and continued through August 31, 2012. On December 19, 2012, the Alaska Department of Environmental Conservation (ADEC) determined that the ambient pollutant data at SPP meets the requirements of the Prevention of Significant Deterioration (PSD) program set forth by the EPA. This action completed the data collection requirement.

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

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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	2012			2011			2010			2009			2008
Electric plant, net: In service	$	397,887,119		$	392,080,033		$	407,351,421		$	414,002,926		$	432,460,336
Construction work in progress		263,459,794			206,005,783			100,787,482			48,383,610			25,151,072
Electric plant, net		661,346,913			598,085,816			508,138,903			462,386,536			457,611,408
Other assets		156,626,138			254,843,842			121,588,825			105,958,000			119,080,561
Total assets	$	817,973,051		$	852,929,658		$	629,727,728		$	568,344,536		$	576,691,969
Capitalization: Long-term debt		521,597,086			296,090,108			304,450,318			307,301,819			354,383,506
Equities and margins		166,764,373			161,231,426			161,842,284			156,320,597			153,766,999
Total capitalization	$	688,361,459		$	457,321,534		$	466,292,602		$	463,622,416		$	508,150,505
Equity Ratio1		24.2	%		35.3	%		34.7	%		33.7	%		30.3	%
Operations Data
Operating revenues	$	266,971,468		$	283,618,369		$	258,325,345		$	290,247,308		$	288,292,112
Operating expenses		248,194,955			262,341,866			233,967,201			264,872,577			260,580,365
Interest expense		24,085,371			18,681,680			21,014,387			21,207,600			22,979,276
Capitalized interest		(9,682,440	)		(1,934,703	)		(1,008,689	)		(601,251	)		(446,479	)
Net operating margins		4,373,582			4,529,526			4,352,446			4,768,382			5,178,950
Nonoperating margins		1,151,925			1,043,736			1,057,563			891,966			1,232,800
Assignable margins	$	5,525,507		$	5,573,262		$	5,410,009		$	5,660,348		$	6,411,750
Margins for Interest Ratio2		1.23			1.30			1.26			1.27			1.28

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.

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Item 7 – Management’s Discussion and Analysis

of Financial Condition and Results of Operations

Caution Regarding Forward Looking Statements

Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. We undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this 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, 2012, 2011 and 2010 was $22,944,194, $9,669,656 and $12,377,668, 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. The decrease in TIER in 2012 was due primarily to an increase in long-term interest associated with additional debt. 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.

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, 2012, compared to the years ended December 31, 2011, and December 31, 2010 – Expenses.” We achieved TIERs for the past three years as follows:

Year	TIER
2012		1.24
2011		1.58
2010		1.44

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Rate Regulation and Rates. Our electric rates are made up of two primary components: “base rates” and “fuel and purchased power 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 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 12, 2012, base demand and energy rates decreased 2.1 percent, 1.9 percent and 1.7 percent to HEA, MEA and Chugach retail customers, respectively, and increased 1.6 percent to Seward. The base demand and energy rate changes were the result of Chugach’s SRF utilizing the twelve months ended June 30, 2012, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – June 30, 2012 Test Year Simplified Rate Filing.”

On May 14, 2012, base demand and energy rates decreased 3.0 percent, 2.8 percent and 2.4 percent to HEA, MEA and Seward, respectively, and increased 1.3 percent to Chugach retail customers. The base demand and energy rate changes were the result of Chugach’s SRF utilizing the twelve months ended December 31, 2011, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – December 31, 2011 Test Year Simplified Rate Filing.”

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.

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.

30

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.

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.

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 adjustment 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 adjustment 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 adjustment 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 Sheet 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, 2012, compared to the years ended December 31, 2011, and December 31, 2010

Margins

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

	2012		2011		2010
Net Operating Margins	$	4,373,582	$	4,529,526	$	4,352,446
Nonoperating Margins	$	1,151,925	$	1,043,736	$	1,057,563
Assignable Margins	$	5,525,507	$	5,573,262	$	5,410,009

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The decrease in net operating margins in 2012 from 2011 of $155.9 thousand, or 3.4 percent, was due to an increase in distribution and administrative, general and other expense, which was somewhat offset by a decrease in transmission and net interest expense. 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, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Years ended December 31, 2012, compared to the years ended December 31, 2011, and December 31, 2010 – Expenses.”

Nonoperating margins include interest income, Allowance for Funds Used During Construction (AFUDC), capital credits and patronage capital allocations and other. Nonoperating margins increased in 2012 over 2011. Higher interest income due to higher interest rates on marketable securities and higher AFUDC due to the level of construction activity was offset by a lower patronage capital allocation from CoBank as our investment in CoBank decreases and lower other nonoperating margins caused by a 2012 loss associated with the sale of vehicles and unused land compared to a 2011 gain associated with the sale of a set of turbine rotor blades.

Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2012, operating revenues were $16.6 million, or 5.9 percent lower than in 2011. The decrease was due primarily to lower fuel and purchased power costs recovered in revenue through the fuel and purchased power recovery process and lower economy energy sales, which was slightly offset by an increase in firm kWh sales.

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.

Overall, retail revenue decreased in 2012 from 2011. The decrease was due primarily to lower fuel and purchased power costs recovered in revenue through the fuel and purchased power recovery process, which was somewhat offset by higher kWh sales.

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.

Wholesale revenue decreased in 2012 from 2011. The decrease was due primarily to lower fuel and purchased power costs recovered in revenue through the fuel and purchased power recovery process and lower rates charged to wholesale customers, which was somewhat offset by higher kWh sales.

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.

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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 $27.5 million, $27.6 million and $27.2 million to Chugach’s fixed costs for the years ended December 31, 2012, 2011 and 2010, 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, 2012, and 2011.

	Base Rate Sales Revenue							Fuel and Purchased Power Revenue							Total Revenue
	2012		2011		% Variance			2012		2011		% Variance			2012		2011		% Variance
Retail
Residential	$	45.4	$	45.1		0.7	%	$	30.7	$	32.5		(5.5	%)	$	76.1	$	77.6		(1.9	%)
Small Commercial	$	7.7	$	7.6		1.3	%	$	6.8	$	7.1		(4.2	%)	$	14.5	$	14.7		(1.4	%)
Large Commercial	$	28.6	$	27.5		4.0	%	$	28.6	$	30.2		(5.3	%)	$	57.2	$	57.7		(0.9	%)
Lighting	$	1.3	$	1.2		8.3	%	$	0.3	$	0.2		50.0	%	$	1.6	$	1.4		14.3	%
Total Retail	$	83.0	$	81.4		2.0	%	$	66.4	$	70.0		(5.1	%)	$	149.4	$	151.4		(1.3	%)
Wholesale
HEA	$	12.3	$	12.1		1.7	%	$	26.0	$	27.1		(4.1	%)	$	38.3	$	39.2		(2.3	%)
MEA	$	21.9	$	21.8		0.5	%	$	40.4	$	43.0		(6.0	%)	$	62.3	$	64.8		(3.9	%)
SES	$	1.3	$	1.4		(7.1	%)	$	3.5	$	3.6		(2.8	%)	$	4.8	$	5.0		(4.0	%)
Total Wholesale	$	35.5	$	35.3		0.6	%	$	69.9	$	73.7		(5.2	%)	$	105.4	$	109.0		(3.3	%)
Economy Sales	$	0.6	$	1.6		(62.5	%)	$	8.4	$	18.7		(55.1	%)	$	9.0	$	20.3		(55.7	%)
Miscellaneous	$	1.8	$	2.2		(18.2	%)	$	1.4	$	0.7		100.0	%	$	3.2	$	2.9		10.3	%
Total Revenue	$	120.9	$	120.5		0.3	%	$	146.1	$	163.1		(10.4	%)	$	267.0	$	283.6		(5.9	%)

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	%

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

	2012		2012		2011		2011		2010		2010
	Sales (MWh)		Revenue		Sales (MWh)		Revenue		Sales (MWh)		Revenue
Retail		1,178,836	$	149,355,192		1,166,336	$	151,474,488		1,169,430	$	140,110,304
Wholesale:
HEA		488,941		38,344,762		475,098		39,154,889		454,223		33,189,789
MEA		782,510		62,278,074		763,339		64,818,326		743,212		55,937,931
Seward		65,671		4,801,814		64,261		5,031,622		61,651		4,188,989
Total Wholesale		1,337,122		105,424,650		1,302,698		109,004,837		1,259,086		93,316,709
Economy energy		90,765		9,025,467		235,378		20,270,059		278,093		22,141,341
Other		N/A		3,166,159		N/A		2,868,985		N/A		2,756,991
Total		2,606,723	$	266,971,468		2,704,412	$	283,618,369		2,706,609	$	258,325,345

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. 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 was due to continue through March 31, 2013, however, on October 5, 2012, Chugach and GVEA finalized arrangements for Chugach to provide economy energy sales until March of 2015. Sales will be made under the terms and conditions of Chugach’s economy energy sales tariff approved by the RCA. The price to GVEA will include the cost of fuel, variable operations and maintenance expense and a margin. Chugach has also entered into gas supply arrangements for GVEA economy energy sales.

In 2012, 2011, and 2010, economy sales to GVEA constituted approximately 3 percent, 7 percent, and 9 percent, respectively, of our sales revenues. Economy energy revenue decreased in 2012 from 2011 due to less gas available under Chugach’s interruptible gas contract to make economy sales in the first three quarters of 2012. Economy energy revenue decreased in 2011 from 2010 due to scheduled maintenance and gas supply restrictions that limited our ability to make sales to GVEA.

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Expenses

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

	2012		2011		2010
Fuel	$	125,836,659	$	139,179,413	$	111,718,947
Power production		16,739,931		16,853,232		18,248,656
Purchased power		22,104,687		25,861,814		26,691,968
Transmission		5,802,009		6,809,401		5,697,446
Distribution		15,822,104		13,387,477		12,216,252
Consumer accounts		6,013,419		5,465,315		5,323,551
Administrative, general and other		23,519,246		22,169,039		21,434,273
Depreciation		32,356,900		32,616,175		32,636,108
Total operating expenses	$	248,194,955	$	262,341,866	$	233,967,201

Fuel

Chugach recognizes actual fuel expense as incurred. Fuel expense decreased $13.3 million, or 9.6 percent, in 2012 from 2011 due to a decrease in Mcf used as a result of lower economy energy sales and a lower average effective fuel price. In 2012, Chugach used 27,162,382 Mcf of fuel at an average effective price of $5.03 per Mcf, which did not include 3,113,258 Mcf of fuel that is recorded as purchased power expense. 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.

Power Production

Power production expense did not materially change in 2012 from 2011.

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.

Purchased Power

Purchased power costs, which included the cost of 3,113,258 Mcf of fuel associated with purchases from the Nikiski Cogeneration plant, decreased $3.8 million, or 14.5 percent, in 2012 from 2011. An increase in MWh purchased, due largely to purchases from Bernice Lake and Fire Island, was more than offset by a decrease in the average effective price, caused in part by Bradley Lake refunds for fiscal years 2011 and 2012. In 2012, Chugach purchased 523,476 MWh of energy at an average effective price of 3.89 cents per kWh. 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.

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Transmission

Transmission expense decreased $1.0 million, or 14.8 percent, in 2012 from 2011 due to lower substation maintenance and transmission line clearing caused primarily by a shift in resources needed for distribution line maintenance. Transmission expense increased $1.1 million, or 19.5 percent, in 2011 from 2010 due primarily to higher substation and overhead line maintenance caused by weather related outages and equipment failure response.

Distribution

Distribution expense increased $2.4 million, or 18.2 percent, in 2012 from 2011 due primarily to an increase in substation maintenance and higher costs associated with storm related line maintenance. Distribution expense increased $1.2 million, or 9.6 percent, in 2011 from 2010 due primarily to higher overhead line maintenance caused by weather related outages.

Consumer Accounts

Consumer Accounts increased $0.5 million, or 10.0 percent, in 2012 from 2011 due primarily to costs associated with a new customer information and billing system. Consumer Accounts did not materially change in 2011 from 2010.

Administrative, General and Other Charges

Administrative, general and other charges increased $1.3 million, or 6.1 percent, in 2012 from 2011 due primarily to an increase in labor and costs associated with workers compensation claims and an increase in the write off of obsolete materials, inventory and cancelled projects. 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.

Depreciation

Depreciation expense did not materially change in 2012 from 2011 or in 2011 from 2010.

Interest

Interest on long-term debt and other increased $5.4 million, or 28.9 percent, in 2012 from 2011 due primarily to the interest associated with the 2012 bonds issued in January of 2012, which replaced less expensive commercial paper. The increase was somewhat offset by the rate difference between the 2001 and 2002 Series A Bonds that matured on March 15, 2011 and February 1, 2012, and the 2011 Series A Bonds and the amount of deferred interest associated with the 2012 bonds described in Note 5 to the financial statements, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters-Interest and Financing Costs.” Principal payments on our 2011 bonds and CoBank debt also contributed to offsetting the increase. 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.

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Interest charged to construction increased $7.7 million, or 400.5 percent, in 2012 from 2011 due to a higher average balance in Construction Work in Progress, due primarily to capital spending associated with SPP. Interest charged to construction increased $926.0 thousand, or 91.8 percent, in 2011 from 2010 due primarily to the same reason as the 2012 variance reported above, which was slightly offset by a lower weighted average borrowing rate during 2011.

Patronage Capital (Equity)

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

	2012			2011			2010
Patronage capital at beginning of year	$	148,355,246		$	149,543,952		$	144,228,221
Retirement of capital credits		(48,079	)		(6,761,968	)		(94,278	)
Assignable margins		5,525,507			5,573,262			5,410,009
Patronage capital at end of year		153,832,674			148,355,246			149,543,952
Other equity1		12,931,699			12,876,180			12,298,332
Total equity at end of year	$	166,764,373		$	161,231,426		$	161,842,284

¹  Other equity includes memberships and donated capital 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 $48,079, $309,188, and $94,278 in capital credits for the years ended December 31, 2012, 2011, and 2010, 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 2012, 2011 and 2010, no wholesale capital credits were retired.

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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 approved the deferral of capital credit retirements after 2009, excluding discounted capital credits, due to the construction of SPP and the anticipated loss of wholesale load in 2014.

Changes in Financial Condition

Assets

Total assets decreased $35.0 million, or 4.1 percent, from December 31, 2011, to December 31, 2012. Investments in associated organizations decreased $0.6 million, or 5.2 percent, caused by a CoBank equity retirement in March of 2012 and fuel cost under-recovery decreased $1.2 million, or 83.0 percent, due to the collection of the prior quarter’s fuel and purchased power costs. Restricted cash equivalents decreased $120.1 million, or 98.4 percent, caused by the release of funds held for the retirement of the 2002 Series A Bonds on February 1, 2012. Injections into the CINGSA storage facility contributed to a cash and cash equivalents decrease of $3.1 million, or 17.9 percent, from December 31, 2011, to December 31, 2012. These decreases were offset by a $63.3 million, or 10.6 percent, increase in net utility plant due to extension and replacement of plant in excess of depreciation expense and a $10.1 million, or 100 percent increase in marketable securities caused by a bond and equity investment portfolio executed in September of 2012. Fuel stock increased $9.5 million, or 100 percent caused by injections into the CINGSA storage facility. The increase was also caused by a $4.3 million, or 10.1 percent, increase in accounts receivable caused primarily by higher kWh sales and the timing of customer payments. Deferred charges increased $2.5 million, or 9.9 percent, caused by expenditures associated with financing activities, Beluga Unit 8 maintenance and expenditures associated with a bi-directional fuel project which exceeded the amortization of other deferred charges.

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Liabilities

Total liabilities decreased by $40.5 million, or 5.9 percent, in 2012 as compared to 2011. Commercial paper decreased $163.5 million, or 93.4 percent, due to the proceeds from the 2012 financing which were used to pay the outstanding balance of commercial paper in January of 2012. Fuel payable decreased $3.5 million, or 14.5 percent, due primarily to a decrease in fuel costs and the timing of fuel payments. Accounts payable decreased $6.3 million, or 27.7 percent, due primarily to the timing of cash payments, which was primarily impacted by SPP related expenditures.

The above decreases were offset to some extent by increases in the net of total long-term obligations and current installments of long-term obligations, fuel cost over-recovery, salaries, wages and benefits and other liabilities. The net of total long-term obligations and current installments of long-term obligations increased $116.6 million due to the issuance of the 2012 bonds in January of 2012, which was offset by the retirement of the 2002 Series A Bonds on February 1, 2012 and the principal payments on the 2011 bonds and CoBank debt. Fuel cost over-recovery increased $13.7 million, or 100 percent, caused by the over-recovery of the prior quarter’s fuel and purchased power costs. Salaries, wages and benefits increased $0.7 million, or 10.2 percent, caused by contract labor adjustments and an increase in benefits and other liabilities increased $1.2 million, or 36.1 percent, caused primarily by an increase in the municipal underground ordinance payable.

Equities and Margins

Total margins and equities increased $5.5 million, or 3.4 percent in 2012 from 2011 due to the margins generated in 2012.

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 2012. 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.

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Contractual Obligations and Commercial Commitments

The following are Chugach’s contractual and commercial commitments as of December 31, 2012:

Contractual cash obligations – Payments Due By Period

(In thousands)	Total		2013		2014-2015		2016-2017		Thereafter
Long-term debt, including current portion	$	546,091	$	24,493	$	48,573	$	48,479	$	424,546
Long-term interest expense1		319,931		23,280		43,471		39,432		213,748
Commercial Paper2		11,500		11,500		0		0		0
Bradley Lake3		36,751		3,616		7,224		7,434		18,477
Fuel and fuel transportation expense4		397,453		144,125		153,607		26,815		72,906
SPP Contracts5		13,049		13,049		0		0		0
Stetson Creek Contracts5		14,877		7,688		7,189		0		0
Capital credit retirements6		6,858		0		0		0		6,858
Total	$	1,346,510	$	227,751	$	260,064	$	122,160	$	736,535

¹  Long-term interest expense includes fixed and variable rates. Variable rates are based on rates at December 31, 2012, for years 2013-2017 and thereafter, see “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt.”

²  At December 31, 2012, Chugach’s Commercial Paper Program was backed by a $100.0 million Unsecured Credit Agreement, which funds capital requirements. At December 31, 2012, there was $11.5 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $88.5 million and could be used for future operational and capital funding requirements.

³  Estimated annual debt service requirement

⁴  Estimated committed fuel and fuel transportation expense

⁵  In accordance with contractual commitments associated with SPP or Stetson Creek

⁶  Capital credit retirement commitment

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, Chugach’s share of which has averaged $4.8 million over the past five years. We believe these costs, adjusted for inflation, reasonably reflect anticipated future project costs.

Our primary sources of natural gas are 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 and Purchased Power Recovery.”

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The Cooper Lake Hydroelectric Project received a 50-year license from 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. If the project is not feasible or if the cost estimate materially exceeds the terms of the license, Chugach has the option to request a license amendment. At the time the project was being relicensed the estimated cost to complete the project was $12.0 million. The current estimate to complete the project is now $21.9 million. As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska. Funding for this project includes $0.6 million in grants received, $5.8 million in grants authorized and $3.5 million in grants requested. The Chugach Board authorized expenditures for the project November 15, 2012. Contracts for this project were awarded in 2012. The diversion project will be constructed in 2013 and 2014, and will operate through the duration of the license.

Liquidity And Capital Resources

We ended 2012 with $14.0 million of cash and cash equivalents, down from $17.1 at December 31, 2011 and up from $12.1 million at December 31, 2010. 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:

	2012			2011			2010
Total cash provided by (used in):
Operating activities	$	43,005,234		$	40,811,795		$	39,151,441
Investing activities		1,386,980			(232,988,854	)		(72,903,232	)
Financing activities		(47,462,863	)		197,224,464			42,318,739
Increase (decrease) in cash and cash equivalents	$	(3,070,649	)	$	5,047,405		$	8,566,948

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Operating activities in 2012 were primarily impacted by changes in accounts receivable, fuel cost over recovery, materials and supplies, fuel stock, other assets, deferred charges, consumer deposits, accrued interest and fuel. 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.

Investing activities in 2012 were primarily impacted by restricted cash equivalents, marketable securities and expenditures associated with SPP. Investing activities in 2011 were primarily impacted by restricted cash equivalents and expenditures associated with SPP. Investing activities in 2010 were primarily impacted by expenditures associated with SPP.

Financing activities in 2012 were primarily impacted by proceeds and payments of long-term debt, the amount of commercial paper used to finance expenditures associated with SPP and receipts on consumer advances for construction. 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 SPP. Financing activities in 2010 were primarily impacted by changes in the amount of commercial paper used to finance expenditures associated with SPP.

Sources of Liquidity

Chugach has satisfied its operational and capital cash requirements through internally generated funds, a $50.0 million line of credit from NRUCFC and a $100.0 million Commercial Paper Program. At December 31, 2012, there was no outstanding balance on our NRUCFC line of credit and $11.5 million of outstanding commercial paper. Thus, at December 31, 2012, our available borrowing capacity under our line of credit was $50.0 million and our available commercial paper capacity was $88.5 million.

On September 26, 2012, the Board approved a resolution to renew the NRUCFC line of credit under substantially the same terms as the previous agreement. The NRUCFC line of credit now expires October 12, 2017.

On November 17, 2010, Chugach entered into a $300.0 million Unsecured Credit Agreement, which is used to back Chugach’s Commercial Paper program. Effective May 4, 2012, Chugach reduced the commitment amount to $100.0 million and on June 29, 2012, amended and extended the Credit Agreement. 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. Loans made under this facility 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. At December 31, 2012, Chugach had $31.8 million outstanding with CoBank.

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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, 2012, are set forth below:

Year Ending December 31	Principal Maturities
2013	$	24,493,022
2014		24,682,812
2015		23,889,777
2016		24,115,980
2017		24,362,621
Thereafter		424,545,896
	$	546,090,108

During 2012 we spent approximately $109.2 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.

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Set forth below is an estimate of capital expenditures for the years 2013 through 2017 as contained in the Capital Improvement Plan (CIP), which was approved by the Board on November 15, 2012:

Year	Estimated Expenditures
2013	$	24.2 million
2014	$	28.2 million
2015	$	15.6 million
2016	$	14.2 million
2017	$	13.7 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

Integrating a new, highly efficient power generation facility into our existing operations and rate structure, managing and securing additional 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 future 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 and ML&P have jointly constructed and now own a new natural gas fired power plant. On February 1, 2013, SPP began commercial operation, furnishing 183 MW of base capacity provided by 4 generating units. Chugach owns and will take approximately 70 percent of the plant’s output and ML&P owns and will take the remaining 30 percent. 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 $197.0 million in costs attributable to three principal contracts to build SPP when the plant becomes used and useful. A request to establish and approve SPP depreciation rates was approved by the RCA in August of 2012. On December 21, 2012, Chugach submitted a general rate case with the RCA to recover the additional costs associated with the project, among other things. Chugach also requested SPP fixed costs be synchronized with expected reductions in fuel costs.

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 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

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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:

1) 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.

2) 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 mobilizing 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 were up and several gas producers new to Cook Inlet have plans to drill in 2013. The State of Alaska recently took in approximately $6.9 million in bids at its area-wide Cook Inlet oil and gas lease sale, the second-highest dollar volume for a Cook Inlet sale since area-wide sales began in 1999. The three major bidders were all large current leaseholders and much of the bidding appeared to be filling in around existing leasehold positions. Hilcorp purchased Chevron’s subsidiary Union Oil Company of California January 1, 2012, and purchased Marathon Alaska Production assets effective February 1, 2013.

Chugach, ML&P and ENSTAR, a local natural gas distribution company, retained a consulting firm to forecast Cook Inlet gas production. A study was issued in October of 2012 that estimated if the current pace of drilling activity were to continue, along with no additional discoveries brought to production, a shortfall in Cook Inlet gas supply in 2015 could result.

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Although Railbelt utilities have the ability to utilize existing oil-fired generation to meet a significant portion of the Railbelt load, Chugach is also evaluating the implementation of dual fuel at SPP, gas importation and enhanced storage capabilities. Chugach believes these measures, along with existing incentives to natural gas producers, improves fuel security and supply in Southcentral Alaska.

Chugach, as part of a group of utilities in Southcentral Alaska, has asked for proposals for imported Liquefied Natural Gas (LNG) or Compressed Natural Gas (CNG) to supplement declining production from Cook Inlet gas fields. The proposals are currently in evaluation. The utility group plans to make a decision on the most viable import option in the first quarter of 2013.

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.

ConocoPhillips Alaska purchased Marathon Oil’s 30 percent share of the Kenai Liquefied Natural Gas (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 of 2011 and exports resumed in the summer of 2012, however, the plant’s future remains unclear.

CINGSA began service April 1, 2012. 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 began in 2012 with limited withdrawals in the third quarter of 2012. Chugach was entitled to withdraw gas at a rate of up to 35.0 million cubic feet (MMcf) per day in 2012 and is entitled to the same limits in-2013. The RCA approved inception rates and a tariff for the CINGSA facility on January 31, 2011 and a Firm Storage Service (FSS) 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 49 percent of Chugach’s power sales load and approximately 39 percent of the utility’s annual sales revenue.

HEA’s solely-owned power generation and transmission entity, AEEC, plans to complete its Nikiski generation conversion project in early 2013. 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 approximately 77 MW. HEA intends to purchase all of the output from this unit upon expiration of the Chugach contract in 2013. HEA is also installing a 48 megawatt combustion turbine which will be used as a backup power source. Effective December 31, 2011, Chugach sold the Bernice Lake Power Plant and associated transmission substation facilities to AEEC and HEA. Associated with the sale, Chugach also entered into a purchased power agreement that gives Chugach the right to purchase the capacity and related energy from the Bernice Lake Power Plant from the closing date of the sale of the facility through December 31, 2013. The agreement allowed Chugach to sell the Bernice Lake Power Plant and simultaneously ensures system retail and wholesale deliverability requirements continue to be met through December 31, 2013. All capacity purchased power costs will be recovered through our fuel and purchased power process.

46

After open discussions and proposals regarding power sales possibilities beyond 2014, in February 2012, Chugach received a response from MEA which indicated it is following the path its membership most favored and is moving forward with plans to build its own generation plant. On March 12, 2012, MEA issued a press release announcing an award for power house engineering and engine/generating equipment for their new power plant at Eklutna, Alaska, which is expected to provide 171 MW of base load generation for MEA beginning in 2015.

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. Our 10-year financial forecast results indicate Chugach can sustain operations and meet financial covenants when these two customers leave the system.

Chugach is also pursuing replacement sources of revenue through potential new power sales agreements and transmission wheeling and ancillary services tariff revisions. On October 5, 2012, Chugach and GVEA finalized arrangements for Chugach to provide economy energy to GVEA until March of 2015. Included in its 2012 general rate case filing with the RCA on December 21, 2012, Chugach requested approval to update and expand its operating tariff to include both firm and non-firm transmission wheeling service and attendant ancillary services in support of third-party transactions on the Chugach system. The expansion of the tariff was made, in part, to accommodate wheeling services in anticipation of the expiration of the HEA and MEA wholesale customer contracts in 2014. 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.

In 2011, Chugach entered into a power purchase agreement with 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 are located on the southern part of Fire Island in Anchorage, Alaska. The transmission line was paid for by a grant in the amount of approximately $25.0 million awarded by the State Legislature. Chugach began receiving power from the project on August 17, 2012. Purchased power costs will be recovered through our fuel and purchased power recovery process.

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, and that 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 is the Susitna-Watana Hydroelectric Project. The project is to be located on the Susitna River, approximately halfway between Anchorage and Fairbanks. The project

47

capacity is expected to be 600 megawatts and would provide about 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. The 2014 capital budget proposed by the governor of Alaska includes $95.0 million for AEA to continue moving the project forward. On July 16, 2012, AEA submitted the proposed studies required to meet federal licensing requirements as part of the review process to meet environmental and safety standards. An updated study plan was submitted in December 2012. AEA held public meetings and comments were accepted by FERC during its 45-day review period. In February of 2013 FERC approved forty-four study plans and is expected to make a determination on the remaining studies by April 1, 2013. Chugach will work with AEA and other parties on this effort.

The 2013 fiscal year State of Alaska capital budget contained appropriations for Chugach projects that will help contain the cost of power for ratepayers while improving reliability and increasing the amount of renewable energy on the system. Funding for these projects will flow through either the AEA or the Municipality of Anchorage.

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.

48

The following policies are considered to be critical accounting policies for the year ended December 31, 2012.

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 the relationship between current retail customer consumption and actual daily substation deliveries. Sales equate to total energy delivered to substations, which accounts for total energy production, less losses. Calendar unbilled revenue is determined by multiplying estimated unbilled kWh sales by respective billing class determinants to produce an estimate of calendar month revenue. Chugach accrued $8,548,660 and $8,977,409 of unbilled retail revenue at December 31, 2012 and 2011, respectively.

49

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, 2012, our short- and long- term debt was comprised of our 2011 and 2012 Series A Bonds, our CoBank bond and outstanding commercial paper.

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. The interest rates of our 2012 Series A Bonds due 2032 and 2042 are fixed at 4.01, 4.41 and 4.78 percent, per annum, respectively. At December 31, 2012, we had $264.3 million of 2011 and $250.0 million of 2012 Series A Bonds outstanding. The fair value at December 31, 2012, was $542.2 million.

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, 2012, we had $11.5 million of commercial paper outstanding and $31.8 million outstanding on our CoBank bond. A 100 basis-point rise in interest rates would increase our interest expense by approximately $0.5 million, and a 100 basis point decline in interest rates would decrease our interest expenses by approximately $0.4 million, based on $43.3 million of variable rate debt outstanding at December 31, 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.

50

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, 2012 and 2011, 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, 2012. 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, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2012, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG, LLP

March 22, 2013

Anchorage, Alaska

51

Chugach Electric Association, Inc.

Balance Sheets

December 31, 2012 and 2011

	2012			2011
Assets
Utility plant:
Electric plant in service	$	891,781,509		$	862,362,243
Construction work in progress		263,459,794			206,005,783
Total utility plant		1,155,241,303			1,068,368,026
Less accumulated depreciation		(493,894,390	)		(470,282,210	)
Net utility plant		661,346,913			598,085,816
Other property and investments, at cost:
Nonutility property		84,735			84,735
Investments in associated organizations		10,552,683			11,134,496
Special funds		570,027			420,783
Total other property and investments		11,207,445			11,640,014
Current assets:
Cash and cash equivalents, including repurchase agreements of $100 in 2012 and $100 in 2011		14,047,469			17,118,118
Special deposits		153,233			149,701
Restricted cash equivalents		1,953,085			122,006,738
Marketable securities		10,158,016			0
Fuel cost under-recovery		0			1,213,484
Accounts receivable, less provision for doubtful accounts of $490,413 in 2012 and $408,429 in 2011		46,650,901			42,373,995
Materials and supplies		32,867,971			32,994,454
Fuel stock		9,466,767			0
Prepayments		2,156,862			1,911,789
Other current assets		252,146			229,858
Total current assets		117,706,450			217,998,137
Deferred charges, net		27,712,243			25,205,690
Total assets	$	817,973,051		$	852,929,657

52

Chugach Electric Association, Inc.

Balance Sheets (continued)

December 31, 2012 and 2011

	2012		2011
Liabilities, Equities and Margins
Equities and margins:
Memberships	$	1,559,344	$	1,517,488
Patronage capital		153,832,674		148,355,246
Other		11,372,355		11,358,692
Total equities and margins		166,764,373		161,231,426
Long-term obligations, excluding current installments:
Bonds payable		491,916,666		264,333,333
National Bank for Cooperatives note payable		29,680,420		31,756,775
Total long-term obligations		521,597,086		296,090,108
Current liabilities:
Current installments of long-term obligations		24,493,022		133,360,210
Commercial paper		11,500,000		175,000,000
Accounts payable		16,488,323		22,800,190
Consumer deposits		4,279,901		3,949,052
Fuel cost over-recovery		13,710,049		0
Accrued interest		6,807,207		6,843,473
Salaries, wages and benefits		8,369,203		7,597,691
Fuel		20,868,078		24,399,157
Other current liabilities		4,559,981		3,350,692
Total current liabilities		111,075,764		377,300,465
Deferred compensation		570,027		420,783
Deferred liabilities		1,769,172		1,703,277
Patronage capital payable		6,858,367		6,646,068
Deferred proceeds on sale of asset		9,338,262		9,537,530
Total liabilities, equities and margins	$	817,973,051	$	852,929,657

See accompanying notes to financial statements.

53

Chugach Electric Association, Inc.

Statements of Operations

Years Ended December 31, 2012, 2011 and 2010

	2012			2011			2010
Operating revenues	$	266,971,468		$	283,618,369		$	258,325,345
Operating expenses:
Fuel		125,836,659			139,179,413			111,718,947
Production		16,739,931			16,853,232			18,248,656
Purchased power		22,104,687			25,861,814			26,691,968
Transmission		5,802,009			6,809,401			5,697,446
Distribution		15,822,104			13,387,477			12,216,252
Consumer accounts		6,013,419			5,465,315			5,323,551
Administrative, general and other		23,519,246			22,169,039			21,434,273
Depreciation and amortization		32,356,900			32,616,175			32,636,108
Total operating expenses		248,194,955			262,341,866			233,967,201
Interest expense:
Long-term debt and other		24,085,371			18,681,680			21,014,387
Charged to construction		(9,682,440	)		(1,934,703	)		(1,008,689	)
Interest expense, net		14,402,931			16,746,977			20,005,698
Net operating margins		4,373,582			4,529,526			4,352,446
Nonoperating margins:
Interest income		447,434			297,983			310,964
Allowance for funds used during construction		258,301			159,916			83,966
Capital credits, patronage dividends and other		446,190			585,837			662,633
Total nonoperating margins		1,151,925			1,043,736			1,057,563
Assignable margins	$	5,525,507		$	5,573,262		$	5,410,009

See accompanying notes to financial statements.

54

Chugach Electric Association, Inc.

Statements of Changes in Equities and Margins

Years Ended December 31, 2012, 2011 and 2010

	Memberships		Other Equities and Margins			Patronage Capital			Total
Balance, January 1, 2010	$	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
Assignable margins		0		0			5,525,507			5,525,507
Retirement of capital credits		0		0			(48,079	)		(48,079	)
Unclaimed capital credit retirements		0		(12,949	)		0			(12,949	)
Memberships and donations received		41,856		26,612			0			68,468
Balance, December 31, 2012	$	1,559,344	$	11,372,355		$	153,832,674		$	166,764,373

See accompanying notes to financial statements.

55

Chugach Electric Association, Inc.

Statements of Cash Flows

Years Ended December 31, 2012, 2011 and 2010

	2012			2011			2010
Cash flows from operating activities:
Assignable margins	$	5,525,507		$	5,573,262		$	5,410,009
Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation		32,356,900			32,616,175			32,636,108
Amortization and depreciation cleared to operating expenses		5,882,580			5,472,557			5,457,480
Allowance for funds used during construction		(258,301	)		(159,916	)		(83,966	)
Loss on disposal of assets		991,871			851,756			210,596
Other		(135,739	)		(93,834	)		74,726
(Increase) decrease in assets:
Accounts receivable, net		(4,276,906	)		(7,128,876	)		670,424
Fuel cost under-recovery		1,213,484			1,158,147			(2,093,467	)
Materials and supplies		(189,092	)		2,563,223			(6,061,005	)
Fuel stock		(9,466,767	)		0			0
Prepayments		(245,073	)		13,635			(663,527	)
Other assets		27,937			(2,049,082	)		(96,522	)
Deferred charges		(4,335,252	)		(6,358,154	)		(1,511,639	)
Increase (decrease) in liabilities:
Accounts payable		1,454,677			1,891,089			(1,321,046	)
Consumer deposits		330,849			(1,276,677	)		(267,221	)
Fuel cost over-recovery		13,710,049			0			(3,511,422	)
Accrued interest		(36,266	)		793,942			(18,099	)
Salaries, wages and benefits		771,512			863,849			777,522
Fuel		(3,531,079	)		2,829,619			6,911,480
Other current liabilities		3,094,139			3,011,319			2,701,345
Deferred liabilities		120,204			239,761			(70,335	)
Net cash provided by operating activities		43,005,234			40,811,795			39,151,441
Cash flows from investing activities:
Proceeds on sale of Bernice Lake Power Plant		0			9,537,530			0
Investment in associated organizations		663,697			1,153,470			311,593
Investment in restricted cash equivalents		0			(270,000,000	)		0
Investment in marketable securities		(10,096,304	)		0			0
Proceeds from restricted cash equivalents		120,000,000			150,000,000			0
Extension and replacement of plant		(109,180,413	)		(123,679,854	)		(73,214,825	)
Net cash provided by (used in) investing activities		1,386,980			(232,988,854	)		(72,903,232	)
Cash flows from financing activities:
Payments for debt issue costs		(1,850,199	)		(1,949,027	)		(1,493,572	)
Proceeds from short-term obligations		24,500,000			76,500,000			47,000,000
Proceeds from long-term obligations		250,000,000			275,000,000			0
Repayments of short-term obligations		(188,000,000	)		0			0
Repayments of long-term obligations		(133,360,210	)		(152,851,500	)		(4,118,029	)
Memberships and donations received		55,519			189,385			205,956
Retirement of patronage capital and estate payments		(48,079	)		(309,188	)		(146,596	)
Net receipts of consumer advances for construction		1,240,106			644,794			870,980
Net cash provided by (used in) financing activities		(47,462,863	)		197,224,464			42,318,739
Net changes in cash and cash equivalents		(3,070,649	)		5,047,405			8,566,948
Cash and cash equivalents at beginning of period	$	17,118,118		$	12,070,713		$	3,503,765
Cash and cash equivalents at end of period	$	14,047,469		$	17,118,118		$	12,070,713
Supplemental disclosure of non-cash investing and financing activities:
Retirement of plant	$	10,405,777		$	11,317,319		$	6,666,875
Extension and replacement of plant included in accounts payable	$	10,620,219		$	15,561,199		$	15,919,688
Supplemental disclosure of cash flow information – interest expense paid, net of amounts capitalized	$	13,092,576		$	12,590,296		$	18,057,000

See accompanying notes to financial statements.

56

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(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). 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). Chugach’s retail and wholesale members are the consumers of the electricity sold.

Chugach was organized as an Alaska electric cooperative in 1948 and 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, the 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 and our rates, see Note (2j) – “Deferred Charges and Credits.”

57

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(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 – 12/31/12
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.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(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 4.0 percent during 2012, 4.1 percent during 2011 and 4.8 percent during 2010. Chugach capitalized actual interest expense and related fees associated with the construction of Southcentral Power Plant (SPP).

e. Investments in Associated Organizations

The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) requires 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 2012, 2011 and 2010.

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 (see 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.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(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 $10.0 million, which was subsequently invested in marketable securities in September of 2012. 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 of $8,942,631 and $6,481,639 for the years ended December 31, 2012 and 2011, respectively. The Overnight Repurchase Agreement account had an average balance in 2012 and 2011 of $100 and $5,210,009, at an average interest rate of 0.00 percent and 0.06 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 used the proceeds primarily to fund capital expenditures associated with SPP and closed the account in February of 2013.

Restricted cash equivalents include State of Alaska construction bonds and funds on deposit for future workers compensation claims. In 2011, restricted cash equivalents included $120.0 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.

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 receivable are invoiced amounts to ML&P for fuel and their proportionate share of current SPP costs, which amounted to $3.0 and $4.8 million in 2012 and 2011, respectively. In addition, accounts receivable includes an invoiced amount to the Alaska Energy Authority (AEA) for reimbursable expenditures related to a grant for the Cook Inlet Gas Gathering System (CIGGS) project, which amounted to $4.0 million in 2012.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(2) Significant Accounting Policies (continued)

i. Materials and Supplies

Materials and supplies are stated at average cost.

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 (Board). Retained assignable margins are designated on Chugach’s balance sheet as patronage capital. This patronage capital constitutes the principal equity of Chugach. The Board 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, 2014. 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 $6.9 million at December 31, 2012.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(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 $8,548,660 and $8,977,409 of unbilled retail revenue at December 31, 2012 and 2011, 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 adjustment process, which is adjusted quarterly to reflect increases and decreases of such costs. We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates. The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under or over collection of fuel and purchase power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods. Fuel costs were over-recovered by $13,710,049 in 2012 and under-recovered by $1,213,484 in 2011. Total fuel and purchased power costs in 2012, 2011, and 2010 were $147,941,346, $165,041,227, and $138,410,915, 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, 2012, 2011 and 2010 was in compliance with that provision. In addition, as described in “Note (15) – Commitments and Contingencies,” 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.”

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(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, 2009 through December 31, 2012 for U.S. Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2012.

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, 2012 and 2011, totaled $2.4 million and $2.2 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances for the years ended December 31, 2012 and 2011 totaled $1.9 million and $1.7 million, respectively.

q. Grants

Chugach has received federal and state grants to offset storm related expenditures and 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 while grant proceeds for storm related expenditures are offset against the actual expense incurred, which totaled $30.5 million and $4.3 million in 2012 and 2011, respectively. The assets constructed from grant awards may not be sold, or used as collateral for any reason.

r. Fuel Stock

Fuel Stock is the weighted average cost of fuel injected into the Cook Inlet Natural Gas Storage Alaska (CINGSA), which began service in the second quarter of 2012. Limited withdrawals of gas began in the third quarter of 2012. Chugach’s fuel balance in storage amounted to $9.5 million for the year ended December 31, 2012.

s. Marketable Securities

In September of 2012, Chugach implemented a bond and equity investment portfolio. Chugach’s initial investment was $10.0 million. The investments are classified as marketable securities, reported at fair value with gains and losses included in earnings. At December 31, 2012, the carrying amount and fair value was $10.1 million.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(3) Recent Accounting Pronouncements

ASC Update 2013-02 “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”

In January 2013, the FASB issued ASC Update 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.” ASC Update 2013-02 expands the disclosure requirements for amounts reclassified out of accumulated other comprehensive income. This update is effective for reporting periods beginning after December 15, 2012. Chugach began application of ASC 2013-02 on January 1, 2013. Chugach does not have any items included in other comprehensive income. Therefore, assignable margins and comprehensive income are the same amount and the adoption did not have any effect on results of operations, financial position, and cash flows.

ASC Update 2013-01 “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities)”

In January 2013, the FASB issued ASC Update 2013-01, “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” ASC Update 2013-01 clarifies the scope of Update 2011-11 to apply to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. This update is effective for fiscal years beginning on or after January 1, 2013 and interim periods within those annual periods. Chugach began application of ASC 2013-01 on January 1, 2013. Adoption did not have any incremental effect on results of operations, financial position, and cash flows.

ASC Update 2012-04 “Technical Amendments and Improvements”

In October 2012, the FASB issued ASC Update 2012-04, “Technical Amendments and Improvements.” ASC Update 2012-04 amends a wide range of Topics in the FASB Codification, however the main provisions were to correct source literature guidance, provide clarity by updating and correcting wording and references, relocating guidance to a more appropriate location within the Codification, and conform terminology and clarify guidance to fully reflect the fair value measurement and disclosure requirements of Topic 820. This update is effective for the first interim or annual reporting period beginning after December 15, 2012. Chugach began application of ASC 2012-04 on January 1, 2013. Adoption did not have any incremental effect on results of operations, financial position, and cash flows.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(3) Recent Accounting Pronouncements (continued)

ASC Update 2012-03 “Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs to SEC Staff Accounting Bulletin No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update)”

In August 2012, the FASB issued ASC Update 2012-03, “Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs to SEC Staff Accounting Bulletin No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update).” ASC Update 2012-03 amends various SEC paragraphs pursuant to the issuance of Staff Accounting Bulletin (SAB) No. 114, which revised or removed portions of the interpretive guidance included in the FASB Codification of the SAB Series to ensure consistency of referencing throughout the SAB Series. This update is effective upon issuance. Chugach began application of ASC 2012-03 on its issuance date of August 27, 2012. Adoption did not have any incremental effect on results of operations, financial position, and cash flows.

ASC Update 2011-04 “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS”

In May 2011, the FASB issued ASC Update 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.” ASC Update 2011-04 amends current U.S. GAAP to create more commonality with IFRS by changing some of the wording used to describe requirements for measuring fair value and for disclosing information about fair value measurements. This update is effective for the first interim or annual reporting period beginning after December 15, 2011. Chugach began application of ASC 2011-04 on January 1, 2012. Adoption did not have any incremental effect on results of operations, financial position, and cash flows.

ASC Update 2011-12 “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05”

In December 2011, the FASB issued ASC Update 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05.” ASC Update 2011-12 defers the effective date of the requirements to present separate line items on the income statement for reclassification adjustments of items out of accumulated other comprehensive income into net income for all periods presented. This update does not change the other requirements of ASC Update 2011-05. This update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011. Chugach began application of ASC 2011-12 in the period ended March 31, 2012. Chugach does not have any items included in other comprehensive income. Therefore, assignable margins and comprehensive income are the same amount and the adoption did not have any effect on results of operations, financial position, and cash flows.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(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.

The table below presents the balance of Chugach’s Overnight Repurchase Agreement, marketable securities, money market and restricted cash equivalents assets measured at fair value on a recurring basis at December 31, 2012, and December 31, 2011.

	Total		Level 1		Level 2		Level 3
December 31, 2012
Repurchase agreement	$	100	$	0	$	100	$	0
Money market	$	2,829,397	$	2,829,397	$	0	$	0
Marketable securities	$	10,158,016	$	10,158,016	$	0	$	0
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

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.

66

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(5) Regulatory Matters

Modification to Certificate of Public Convenience and Necessity

On May 29, 2012, Chugach submitted a request to amend its service area contained within its certificate of public convenience and necessity to include Fire Island and the City of Whittier, and to adjust the service area boundary between Chugach and the City of Seward, d/b/a Seward Electric System in the Moose Pass area where both utilities are currently authorized to provide electric service. Chugach also requested that its service area be modified to include the areas of expansion in which electric service is currently being provided but are not described in Chugach’s certificate, and to include other service areas where potential future customer requests for electric service can be reasonably expected. Chugach also proposed that several sections of its certificate be removed as these areas are well outside of any reasonable likelihood of service requests. On July 9, 2012, the City of Seward submitted comments in support of resolving the boundary area overlap between Chugach and Seward. Seward did not oppose the service area changes proposed by Chugach. A hearing was held on September 4, 2012, in which Chugach made a presentation on the proposed modifications to its service territory and responded to questions from the RCA. On January 25, 2013, the RCA approved Chugach’s request.

Petition to Establish Depreciation Rates for SPP

Chugach submitted proposed depreciation rates for SPP on February 22, 2012, with a recommended 35 year life for the project. The filing also included depreciation rates for transmission plant specific to the project with a recommended life consistent with the depreciation rates of Chugach’s existing transmission assets. The RCA opened Docket U-12-009 on March 2, 2012, to adjudicate the case. Petitions to intervene were received from the Attorney General (AG), HEA and MEA. No responsive testimony was received from any of the parties. A hearing was held on July 2, 2012. On August 31, 2012, the RCA issued an order in the case, approving depreciation rates for SPP with an effective date equal to its in-service date, requested filing requirements and closed the docket.

Seward Power Sales Agreement

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.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(5) Regulatory Matters (continued)

Fire Island Wind Project

On October 10, 2011, the RCA issued an order approving Chugach’s request for assurance of cost recovery associated with 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. The PPA is a 25-year agreement whereby Chugach purchases the output of the facility 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 megawatt hours (MWh) per year. The generators are located on the southern part of Fire Island, three miles west of Anchorage, Alaska. Chugach began receiving power from the project on August 17, 2012. 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 approximately $25.0 million appropriated from the State of Alaska. The grant was used to offset construction of the transmission line. Construction expenditures applied against the grant were $20.3 million in 2012 and $3.2 million in 2011. Chugach is not expected to incur any unreimbursed capital costs associated with this line and will acquire the line once construction is successfully completed.

Chugach submitted a specific rate recovery plan in compliance with U-11-100(5) on April 2, 2012, and project status reports on June 30, 2012 and October 31, 2012. The rate recovery plan addressed customer intergenerational impacts resulting from purchases made under the PPA’s fixed pricing structure. The RCA held a hearing on June 5, 2012, for Chugach to supplement its filing with an oral presentation explaining the rate impacts and equities to ratepayers. As a result of the hearing, Chugach submitted an updated rate recovery proposal on July 31, 2012, requesting that purchases made under the PPA be recovered on a direct cost basis for recovery through the fuel and purchased power surcharge process. Chugach withdrew its April 2, 2012, compliance filing.

On September 28, 2012, the RCA opened Docket U-12-134 and issued an order granting Chugach interim approval of its cost disclosure and rate recovery proposals relating to the Fire Island wind project and invited participation from the Attorney General (AG). Chugach and the AG stipulated on key matters of the filing and requested RCA approval in a stipulation submitted to the RCA on November 15, 2012. The RCA held a hearing on January 17, 2013, to review the stipulation, with participation from both Chugach and the AG. On February 12, 2013, the RCA issued Order No. 3 of Docket U-12-134 accepting the stipulation.

68

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(5) Regulatory Matters (continued)

Regulatory Assets

Storm Expenditures

On November 8, 2012, Chugach submitted a petition to the RCA requesting authorization to create a regulatory asset for deferred recovery of expenditures associated with extensive storm damage that occurred in September of 2012. Repeated windstorms were followed by considerable amounts of rain, resulting in outages and flooding, primarily caused by falling and uprooted trees. Chugach requested approval to recover in future electric rates over a twelve month period approximately $1.8 million of costs. On November 19, 2012, the RCA opened Docket U-12-144, designated a commission panel and appointed an administrative law judge. The AG submitted comments on December 14, 2012, opposing Chugach’s request. The RCA held a hearing on January 14, 2013. On January 30, 2013, the RCA issued Order No. 3 of Docket U-12-144 and did not accept Chugach’s request, however, the RCA provided Chugach the opportunity to augment the record and re-submit its petition at a later time. Chugach is evaluating the option of supplementing the record and re-submitting its request.

Interest and Financing Costs

On January 11, 2012, Chugach issued $75.0 million of First Mortgage Bonds (2012 Series A, Tranche A) at an interest rate of 4.01 percent, $125.0 million of First Mortgage Bonds (2012 Series A, Tranche B) at an interest rate of 4.41 percent and $50.0 million of First Mortgage Bonds (2012 Series A, Tranche C) at an interest rate of 4.78 percent. The proceeds of the 2012 Series A Bonds were used to repay outstanding commercial paper and to finance SPP construction.

On March 12, 2012, Chugach submitted a petition to the RCA requesting authorization to create a regulatory asset for deferred recovery of interim interest expense associated with SPP financing and also requested approval to recover the financing transaction costs in future electric rates over the life of the 2012 Series A Bonds. Chugach’s request included the approval to defer the interest expense on the portion of the proceeds not immediately expended on SPP and recover it in future electric rates over the life of the bonds, or between 20 and 30 years. The deferral of interest for the portion of the 2012 bonds not immediately expended totaled approximately $1.1 million. The RCA opened Docket U-12-015 on March 21, 2012. On May 22, 2012, Chugach and the AG of the State of Alaska submitted a stipulation whereby the AG did not oppose the regulatory and accounting treatment requested by Chugach. On June 19, 2012, the RCA issued Order No. 2 accepting the stipulation and closing the docket.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(5) Regulatory Matters (continued)

2012 General Rate Case

In anticipation of commercial operation of SPP, on December 21, 2012, Chugach submitted a general rate case with the RCA to increase system base rate revenues by $30.0 million, or approximately 26 percent on total base rate revenues of $115.0 million. Chugach requested that the proposed rates become effective on an interim and refundable basis beginning in February of 2013. In addition to the base rate increases, the filing requests approval to update and expand Chugach’s operating tariff to include both firm and non-firm transmission wheeling service and attendant ancillary services in support of third-party transactions on the Chugach system. The expansion of the tariff was made, in part, to accommodate wheeling services in anticipation of the expiration of the HEA and MEA wholesale customer contracts in 2014. Because of efficiency improvements associated with the commercial operation of SPP, Chugach also submitted a request in a separate filing to the RCA to adjust its fuel rates effective at the same time as the requested base rate increases contained in the general rate case filing. This allows the interim base rate increases to be synchronized with expected reductions in fuel costs reflected in Chugach’s fuel rates.

On February 1, 2013, Chugach submitted a supplemental filing to the RCA removing the impacts associated with a one-year amortization of distribution storm-related costs (see discussion on Storm Expenditures above) from its retail revenue requirement. On February 6, 2013, the Commission opened Docket U-13-007 and issued Order No. 1 approving Chugach’s supplemental filing for rates effective February 6, 2013 on an interim and refundable basis. In addition, the Commission also approved Chugach’s request to assess transmission wheeling charges on economy energy transactions that originate from the Chugach system.

In total, when factoring both base rate increases and reductions in fuel costs, the net increase to Chugach retail end-users is approximately 6 percent, while the net increase to retail end-users of Chugach’s wholesale customers is approximately 4 percent to 7 percent.

Removal of Margin Cap on Economy Energy Sales

On October 31, 2012, Chugach submitted a request to the RCA for approval to remove the current eight mill margin cap on economy energy transactions but retain the requirement that such transactions must fall between Chugach’s incremental and the purchasing utility’s decremental cost of generation. The RCA approved the filing on January 24, 2013. The expected impact of the approval, in combination with the Chugach-GVEA sales arrangement, is additional system margin contributions in excess of $2 million over the upcoming year.

Recovery of Qualified Facility Purchases and the Establishment of a Balancing Account

On October 31, 2012, Chugach submitted a filing to the RCA requesting approval to include a new cost element in Chugach’s purchased power cost recovery process to recover non-firm energy purchases from Qualified Facilities, and to create a balancing account for use in the development of quarterly buyback rates associated with purchases from Qualified Facilities. On January 30, 2013, the RCA issued a letter order approving the filing.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(5) Regulatory Matters (continued)

Recovery of Natural Gas Compression Costs

Chugach submitted a filing to the RCA on October 31, 2012, requesting approval to add a new cost element in Chugach’s fuel adjustment mechanism to recover charges associated with natural gas compression on the Kenai Nikiski Pipeline needed to allow bidirectional flows on the Cook Inlet Gas Gathering System. The new cost element includes operations and maintenance charges, facility rental charges, fuel and control service charges.

On December 7, 2012, the Regulatory Affairs and Public Advocacy Section of the Office of the Attorney General submitted comments opposing Chugach’s request to recover compression costs through the fuel rate adjustment process. Chugach submitted a response on December 13, 2012. The RCA issued a letter order on January 14, 2013, approving Chugach’s request for purchases through July 31, 2013. After July 31, 2013, a separate tariffed rate is expected to be developed by Hilcorp.

June 30, 2012 Test Year Simplified Rate Filing

On September 28, 2012, Chugach submitted a SRF to the RCA and requested a system demand and energy rate decrease of 1.7 percent, or approximately $1.9 million on an annual basis. The filing was based on the June 30, 2012 test year for proposed rate adjustments effective in November 2012. On a customer class basis, Chugach requested demand and energy rate decreases of 1.7 percent to Chugach retail customers and decreases of 2.1 percent and 1.9 percent to its wholesale customers HEA and MEA, respectively, and a 1.6 percent increase to Seward. The RCA issued a letter order on November 6, 2012, approving the filing. The updated rates were effective on and after November 12, 2012.

December 31, 2011 Test Year Simplified Rate Filing

On March 30, 2012, Chugach submitted a SRF to the RCA and requested a system demand and energy rate decrease of 0.1 percent, or approximately $0.8 million on an annual basis. The filing was based on the December 31, 2011 test year for proposed rate adjustments effective in May 2012. On a customer class basis, Chugach requested demand and energy rate increases of 1.3 percent to Chugach retail customers and decreases of 2.9 percent to its wholesale classes. The RCA issued a letter order on May 10, 2012, approving the filing. The updated rates were effective on and after May 14, 2012.

Economy Energy Sales and Transmission Wheeling Service

On April 23, 2012, Chugach submitted a filing to the RCA requesting approval to update its economy energy and transmission wheeling services tariffs to reflect current costs and operating conditions associated with transactions at the bulk power supply level. After public comments and meetings Chugach withdrew the filing and will file updated rates for transmission and related ancillary services in conjunction with its 2012 general rate case.

71

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(6) Utility Plant

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

	2012		2011
Electric plant in service:
Steam production plant	$	60,462,671	$	60,462,671
Hydraulic production plant		20,513,746		20,456,395
Other production plant		127,980,607		134,434,574
Transmission plant		252,910,740		252,561,598
Distribution plant		257,587,220		257,341,532
General plant		51,901,426		45,144,425
Unclassified electric plant in service1		109,023,464		80,559,413
Intangible plant1		4,710,912		4,710,912
Other1		6,690,723		6,690,723
Total electric plant in service		891,781,509		862,362,243
Construction work in progress 2		263,459,794		206,005,783
Total electric plant in service and construction work in progress	$	1,155,241,303	$	1,068,368,026

¹  Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant. Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment. 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 SPP included in construction work in progress was $245.5 million and $177.4 million at December 31, 2012 and 2011, respectively.

(7) Investments in Associated Organizations

Investments in associated organizations include the following at December 31:

	2012		2011
National Rural Utilities Cooperative Finance Corporation	$	6,095,980	$	6,095,980
CoBank, ACB		4,392,948		4,974,755
NRUCFC capital term certificates / Other		63,755		63,761
Total Investments in Associated Organizations	$	10,552,683	$	11,134,496

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.

72

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(8) Deferred Charges and Credits

Deferred Charges

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

	2012		2011
Debt issuance and reacquisition costs	$	4,126,529	$	3,432,665
Refurbishment of transmission equipment		141,976		151,235
Feasibility Studies		76,390		351,727
Beluga Gas Compression		2,035,466		2,544,332
Cooper Lake Relicensing / projects		5,800,417		5,930,520
Fuel supply negotiations		815,451		1,118,439
Major overhaul of steam generating unit		1,510,046		2,265,069
Other regulatory deferred charges		4,473,037		2,126,335
Bond interest – market risk management		7,527,357		6,034,443
Environmental matters and other		1,205,574		1,250,925
Total deferred charges	$	27,712,243	$	25,205,690

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

	2012		2011
Fuel supply (negotiations/studies/compression)	$	1,072,002	$	0
Studies/Other		236,401		578,327
Wind project		391,285		144,866
Financing related costs		1,757,624		51,129
Beluga Unit 8 inspection		1,061,838		0
Total deferred charges	$	4,519,150	$	774,322

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 or general rate case rate adjustments filed with the RCA. In most cases, deferred charges are recovered over the life of the underlying asset.

73

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(8) Deferred Charges and Credits (continued)

Deferred Credits

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

	2012		2011
Refundable consumer advances for construction	$	777,323	$	727,917
Estimated initial installation costs for meters		92,149		75,660
Post retirement benefit obligation		899,700		899,700
Total deferred credits	$	1,769,172	$	1,703,277

(9) Patronage Capital

Chugach has a Board approved capital credit retirement policy, which is contained in Chugach’s Financial Forecast. 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, 2012, Chugach had $153,832,674 of patronage capital (net of capital credits retired in 2012), which included $148,307,167 of patronage capital that had been assigned and $5,525,507 of patronage capital to be assigned to its members. Approval of actual capital credit retirements is at the discretion of Chugach’s Board. Chugach records a liability when the retirements are approved by the Board. During 2008, the Board 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.

74

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(9) Patronage Capital (continued)

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, 2014. 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 $6.9 million and $6.6 million at December 31, 2012 and 2011, respectively.

Capital credits retired were $48,079, $309,188, and $94,278 for the years ended December 31, 2012, 2011, and 2010, respectively. There was no outstanding liability for capital credits authorized but not paid at December 31, 2012 and 2011, respectively.

(10) Other Equities

A summary of other equities at December 31 follows:

	2012		2011
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		1,647,869		1,621,257
Unclaimed capital credit retirement1		9,700,861		9,713,810
Total other equities	$	11,372,355	$	11,358,692

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.

75

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(11) Debt

	2012		2011
Long-term obligations at December 31 are as follows:
CoBank 3 and 4, 2.55% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003	$	31,756,775	$	33,659,141
CoBank 5, 2.55% variable rate note maturing in 2012, with interest and principal payable monthly		0		791,177
2002 Series A Bond of 6.20%, maturing in 2012, with interest payable semi-annually February 1 and August 1		0		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		85,500,000		90,000,000
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		178,833,333		185,000,000
2012 Series A Bond of 4.01%, maturing in 2032, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2013		75,000,000		0
2012 Series A Bond of 4.41%, maturing in 2042, with interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042		125,000,000		0
2012 Series A Bond of 4.78%, maturing in 2042, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023		50,000,000		0
Total long-term obligations	$	546,090,108	$	429,450,318
Less current installments		24,493,022		133,360,210
Long-term obligations, excluding current installments	$	521,597,086	$	296,090,108

76

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(11) Debt (continued)

Covenants

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.

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, KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank, ACB and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch dated November 17, 2010, and updated June 29, 2012, governing loans and extensions of credit associated with Chugach’s commercial paper program, in an aggregate principal amount not exceeding $100.0 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.

Security

The Second Amended and Restated Indenture of Trust (the Indenture), which became effective on January 20, 2011, imposes 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.

77

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(11) Debt (continued)

Rates

The Second Amended and Restated Indenture of Trust 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.

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 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 Second Amended and Restated Indenture of Trust and the CoBank Amended and Restated Master Loan Agreement 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.

78

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(11) Debt (continued)

Maturities of Long-term Obligations

Long-term obligations at December 31, 2012, mature as follows:

Year ending December 31	2011 Series A Bonds		CoBank Note		2012 Series A Bonds		Total
2013		10,666,667		2,076,355		11,750,000		24,493,022
2014		10,666,667		2,266,145		11,750,000		24,682,812
2015		10,666,667		2,473,110		10,750,000		23,889,777
2016		10,666,667		2,699,313		10,750,000		24,115,980
2017		10,666,667		2,945,954		10,750,000		24,362,621
Thereafter		210,999,998		19,295,898		194,250,000		424,545,896
	$	264,333,333	$	31,756,775	$	250,000,000	$	546,090,108

Lines of credit

Chugach maintains a $50.0 million line of credit with National Rural Utilities Cooperative Finance Corporation (NRUCFC). Chugach did not utilize this line of credit in 2012, and therefore had no outstanding balance at December 31, 2012. In addition, Chugach did not utilize this line of credit during 2011 and had no outstanding balance at December 31, 2011. The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. At December 31, 2012, and December 31, 2011, the borrowing rate was 2.90 percent and 3.20 percent, 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.

On September 26, 2012, the Board approved a resolution to renew this line of credit under substantially the same terms as the previous agreement. The NRUCFC line of credit now expires October 12, 2017.

This line of credit is immediately available for unconditional borrowing.

79

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(11) Debt (continued)

Commercial Paper

On November 17, 2010, Chugach entered into a $300.0 million Unsecured Credit Agreement, which is used to back Chugach’s Commercial Paper program. The participating banks were 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. Effective May 4, 2012, Chugach reduced the commitment amount to $100.0 million and on June 29, 2012, amended and extended the Credit Agreement to update the pricing and extend the term. The new pricing includes an all-in drawn spread of one month London Interbank Offered Rate (LIBOR) plus 107.5 basis points, along with a 17.5 basis points facility fee (based on an A-/A3 unsecured debt rating). The Amended Unsecured Credit Agreement now expires on November 17, 2016. The participating banks include NRUCFC, KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank, ACB and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch. Our commercial paper can be repriced between one day and two hundred seventy days. Chugach is expected to continue to issue commercial paper in 2013, as needed, however, the requirement for short-term borrowing has decreased.

Chugach had $11.5 million and $175.0 million of commercial paper outstanding at December 31, 2012 and 2011, respectively.

The following table provides information regarding 2012 monthly average commercial paper balances outstanding (dollars in millions), as well as corresponding weighted average interest rates:

Month	Average Balance		Weighted Average Interest Rate
January	$	62.7		0.27
February	$	0		0.00
March	$	8.0		0.38
April	$	6.3		0.36
May	$	0.8		0.35
June	$	0		0.00

Month	Average Balance		Weighted Average Interest Rate
July	$	0		0.00
August	$	0		0.00
September	$	4.2		0.34
October	$	9.3		0.29
November	$	14.5		0.28
December	$	11.9		0.29

80

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(11) Debt (continued)

Financing

On January 11, 2012, Chugach issued $75.0 million of First Mortgage Bonds, 2012 Series A, due March 15, 2032 (Tranche A), $125.0 million of First Mortgage Bonds, 2012 Series A, due March 15, 2042 (Tranche B) and $50.0 million of First Mortgage Bonds, 2012 Series A, due March 15, 2042 (Tranche C), for the purpose of repaying outstanding commercial paper used to finance 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 percent per annum. The 2012 Series A Bonds (Tranche B) will mature on March 15, 2042, and will bear interest at 4.41 percent per annum. The 2012 Series A Bonds (Tranche C) will mature on March 15, 2042, and will bear interest at 4.78 percent 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.

On January 21, 2011, Chugach issued $90.0 million of First Mortgage Bonds, 2011 Series A, due March 15, 2031 and $185.0 million 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 percent 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 percent 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 has a term loan facility with CoBank. Loans made under this facility 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.

81

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(11) Debt (continued)

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:

	2012				2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term obligations (including current installments)	$	546,090	$	573,912	$	429,450	$	442,711

(12) 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.

Pension benefits for non-union employees are provided by the National Rural Electric Cooperative Association (NRECA) Retirement and Security Plan (RS Plan). The RS Plan is a defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the Internal Revenue Code. 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, 2012, 2011 and 2010 of $6.6 million, $6.0 million and $6.0 million, respectively. The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2012, 2011 and 2010. The following table provides information regarding pension plans which Chugach considers individually significant:

82

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(12) Employee Benefit Plans (continued)

Pension Plans (continued)

Alaska Electrical Pension Plan3

NRECA Retirement Security Plan3

Employer Identification Number

92-6005171

53-0116145

Plan Number

001

333

Year-end Date

December 31

December 31

Expiration Date of CBA’s

June 30, 2013

N/A2

Subject to Funding Improvement Plan

No

No4

Surcharge Paid

N/A

N/A4

2012

2011

2010

2012

2011

2010

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)

$

3.6

$

3.0

$

2.9

$

3.0

$

3.0

$

3.1

Contributions > 5% of total plan contributions

Yes

Yes

Yes

No

No

No

¹  A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006. In total, the NRECA RS Plan was between 65 percent and 80 percent funded at January 1, 2012 and 2011, respectively, based on the 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 RS Plan is available on Chugach’s website at www.chugachelectric.com.

⁴  The provisions of the PPA do not apply to the RS Plan, therefore, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the plan and may change as a result of plan experience.

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, 2012, 2011, and 2010 were $4.3 million, $3.7 million, and $3.7 million, respectively.

Chugach participates in a multi-employer plan through the Group Benefits Program of NRECA for non-union employees. Amounts charged to benefit cost and contributed to this Plan for those benefits for the years ended December 31, 2012, 2011, and 2010 totaled $2.5 million, $2.4 million, and $2.2 million respectively.

83

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(12) Employee Benefit Plans (continued)

Money Purchase Pension Plan

Chugach participates in a multi-employer defined contribution money purchase pension plan covering some employees who are covered by a collective bargaining agreement. Contributions to the Plan are made based on a percentage of each employee’s compensation. Contributions to the money purchase pension plan for the years ending December 31, 2012, 2011, and 2010 were $141.0 thousand, $128.7 thousand, and $124.1 thousand, respectively.

401(k) Plan

Chugach has a defined contribution 401(k) retirement plan which covers substantially all employees who, effective January 1, 2008, can participate immediately. Employees who elect to participate may contribute up to the Internal Revenue Service’s maximum of $17,000, $16,500, and $16,500 in 2012, 2011, and 2010 respectively, and allowed catch-up contributions for those over 50 years of age of $5,500, $5,500, and $5,500 in 2012, 2011, and 2010, 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, 2012, 2011 and 2010 was $570,027, $420,783 and $395,833, respectively.

Potential Termination Payments

Pursuant to a Chugach Operating Policy, non-represented employees, including the executive officers except the Chief Executive Officer, who are terminated by Chugach for reasons unrelated to employee performance are entitled to severance pay for each year or partial year of service as follows: two weeks for each year of service to a maximum of twenty-six (26) weeks for thirteen (13) years or more of service.

84

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(13) 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 $166.0 million 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 $28.7 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 $5.1 million as a result of Chugach’s Bradley Lake take-or-pay obligations. Management believes that such expenditures, if any, would be recoverable through the fuel recovery process.

On July 1, 2010, AEA issued $28.8 million of Power Revenue Refunding Bonds, Sixth Series, for purposes of refunding $30.6 million 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 $0.7 million, which represents the reduction in debt-service costs recorded as purchased power expense.

The State of Alaska has provided an initial grant for work on a project to divert water from Battle Creek into Bradley Lake. The project is being managed by the Alaska Energy Authority and pending financing, could 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 up to 40,000 MWh. Chugach would be entitled to 30.4 percent of the additional energy produced.

85

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(13) Bradley Lake Hydroelectric Project (continued)

The following represents information with respect to Bradley Lake at June 30, 2012 (the most recent date for which information is available). Chugach’s share of expenses was $4,223,784 in 2012, $4,643,641 in 2011, and $5,120,958 in 2010 and is included in purchased power in the accompanying financial statements.

(In thousands)	Total		Proportionate Share
Plant in service	$	181,587	$	55,202
Long-term debt		87,607		26,633
Interest expense		5,032		1,530

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

(14) 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 2012 includes $4,725,470, net of accumulated depreciation of $1,671,335, which represents Chugach’s share of the Eklutna Hydroelectric Project. In 2011 plant in service included $4,880,583, net of accumulated depreciation of $1,491,704. 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 $682,757, $662,035, and $664,747 in 2012, 2011, and 2010, 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.

(15) 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.

86

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(15) Commitments and Contingencies (continued)

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 three IBEW CBA’s were extended by the Board on February 24, 2010. The contract extensions expire on June 30, 2013. On April 28, 2010, the Board approved a three year extension of the HERE agreement. The contract extension also expires on June 30, 2013. Two of the bargaining units have ratified tentative agreements extending their labor agreements through June 30, 2017. Chugach is currently negotiating with the final IBEW bargaining unit.

Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA. These contracts represented $100.6 million or 39 percent of sales revenue in 2012, $104.0 million or 37 percent in 2011, and $89.1 million or 35 percent in 2010. 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.

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 Marathon Alaska Production, LLC (MAP) effective May 17, 2010. The new MAP contract provided gas beginning April 1, 2011 and will terminate December 31, 2014, which includes two contract extensions that were exercised in 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. All of the production is expected to come from Cook Inlet, Alaska. In 2012, 89 percent of our power was generated from gas, compared to 92 percent and 89 percent in 2011 and 2010 respectively. Of that gas-fired power, 83 percent was generated at Chugach’s Beluga Power Plant in 2012 compared with 79 percent in 2011 and 78 percent in 2010.

87

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(15) Commitments and Contingencies (continued)

The terms of the COP and MAP agreements require Chugach to handle the natural gas transportation over the connecting pipeline systems. Effective October 1, 2012, Chugach and Hilcorp Alaska, LLC (Hilcorp) entered into a gas exchange agreement to exchange gas between the east and west side of Cook Inlet. This agreement terminates on September 30, 2013. We have gas transportation agreements with ENSTAR Natural Gas Company (ENSTAR) and Marathon Oil Company. 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:

	2012			2011			2010
Marathon Oil Company		72.0	%		44.9	%		24.1	%
Chevron/UNOCAL/Hilcorp		1.3	%		16.1	%		26.4	%
ML&P		0.0	%		3.6	%		14.2	%
ConocoPhillips (COP)		24.2	%		31.9	%		35.1	%
ENSTAR		2.2	%		1.3	%		0.2	%
Miscellaneous		0.3	%		2.2	%		0.0	%

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 and is included in the retirement of capital credits on our Statements of Changes in Equities and Margins. HEA’s patronage capital was $6.9 million at December 31, 2012 and $6.6 million at December 31, 2011, and is classified as patronage capital payable on our Balance Sheet.

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 $0.000568, effective July 1, 2012. The tax is reported on a net basis and the tax is not included in revenue or expense.

88

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(15) Commitments and Contingencies (continued)

Sales Tax

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

Gross Receipts Tax

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

Production taxes

Production 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 $3,786,031 and $2,611,110 for this charge at December 31, 2012 and 2011, respectively and will use the funds to offset the costs of the projects.

Environmental Matters

The Clean Air Act and Environmental Protection Agency (EPA) regulations under the Clean Air Act establish ambient air quality standards and limit the emission of many air pollutants.

New Clean Air Act regulations impacting electric utilities may result from future events or 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.

89

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(15) Commitments and Contingencies (continued)

Environmental Matters (continued)

SPP was required by its Air Quality Permit to collect ambient air background data. Data collection began on September 1, 2011 and continued through August 31, 2012. On December 19, 2012, the Alaska Department of Environmental Conservation (ADEC) determined that the ambient pollutant data at SPP meets the requirements of the Prevention of Significant Deterioration (PSD) program set forth by the EPA. This action completed the data collection requirement.

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

Generation Commitments

Chugach is in the process of developing a natural gas-fired generation plant on land owned by Chugach near its Anchorage headquarters. SPP was 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 SPP. 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 steam turbine generator (STG) purchase agreement, an engineering, procurement, and construction (EPC) contract, a once through steam generator (OTSG) equipment and transportation contracts for transportation of all purchased equipment. All equipment, including the spare engine, has been received. 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, the initial building permit was received from the Municipality of Anchorage. Chugach made payments of $85.7 million in 2012 and $130.5 million in 2011 pursuant to its contracts associated with SPP. Additional payments of $13.0 million have been paid or are expected to be paid in 2013. Commercialization of the project occurred on February 1, 2013.

90

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2012 and 2011

(15) Commitments and Contingencies (continued)

Economy Energy Sales

On October 5, 2012, Chugach and GVEA finalized arrangements for Chugach to provide economy energy to GVEA until March of 2015. Sales will be made under the terms and conditions of Chugach’s economy energy sales tariff. The price to GVEA will include the cost of fuel, variable operations and maintenance expense and a margin. Chugach has also entered into gas supply arrangements for GVEA economy energy sales.

Cooper Lake Hydroelectric Project

The Cooper Lake Hydroelectric Project received a 50-year license from 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. If the project is not feasible or if the cost estimate materially exceeds the terms of the license, Chugach has the option to request a license amendment. At the time the project was being relicensed the estimated cost to complete the project was $12.0 million. The current estimate to complete the project is now $21.9 million. As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska. Funding for this project includes $0.6 million in grants received, $5.8 million in grants authorized and $3.5 million in grants requested. The Chugach Board authorized expenditures for the project November 15, 2012. The diversion project will be constructed in 2013 and 2014, and will operate through the duration of the license.

(16) Quarterly Results of Operations (unaudited)

2012 Quarter Ended

	Dec. 31		Sept. 30			June 30			March 31
Operating Revenue	$	74,483,455	$	62,675,511		$	58,631,729		$	71,180,773
Operating Expense		68,250,215		60,200,529			55,725,151			64,019,060
Net Interest		3,492,044		3,495,865			3,542,676			3,872,346
Net Operating Margins		2,741,196		(1,020,883	)		(636,098	)		3,289,367
Nonoperating Margins		632,775		261,487			123,962			133,701
Assignable Margins	$	3,373,971	$	(759,396	)	$	(512,136	)	$	3,423,068

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

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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, 2012, 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, 2012, 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.

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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 (Board) 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 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 may be nominated by a Nominating Committee or by petition. 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, 57, 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 and is currently Chair of Alaska Railbelt Cooperative Transmission & Electric Company (ARCTEC). 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, 64, 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. Her term expires in May of 2013.

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Jim Henderson, 66, Secretary, 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.

P.J. Hill, 68, 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 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, 60, 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 and 2012. He has served as Chairman of the Board and 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 2015.

Harry T. Crawford, Jr., 60, 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.

Sisi Cooper, 32, Director, is a project engineer with Doyon Emerald, LLC. She specializes in process safety and risk management, energy-sector project management, and process/facility engineering and design. Sisi is a former small business owner of North Ridge Home Inspections, LLC where she was the principal inspector. She currently serves as Chugach’s Alaska Power Association (APA) Representative. She was elected to the Board in 2012. Her term expires in May of 2015.

Identification of Executive Officers

Bradley W. Evans, 58, 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.

94

Michael R. Cunningham, 63, was appointed Chief Financial Officer on June 5, 2002. 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. On February 25, 2013, Michael R. Cunningham retired from Chugach.

Ronald K. Vecera, 55, was appointed Interim Chief Financial Officer and Sr. Vice President, Finance and Administration effective February 28, 2013. Prior to this appointment, Mr. Vecera was serving as Director of Renewable Energy Business Development. Mr. Vecera has worked at Chugach for more than 30 years and has held various management positions in the areas of Strategic Planning and Corporate Affairs, Member Services and Planning and Rates. Mr. Vecera has also worked for the Alaska Public Utilities Commission, the predecessor to the RCA, and has an MBA degree, with a concentration in Finance, from Columbia University.

Edward M. Jenkin, 52, 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 25 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, 58, 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.

Lee D. Thibert, 57, 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.

95

Tyler E. Andrews, 47, was appointed Vice President, Human Resources on March 17, 2008. Mr. Andrews has over 17 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.

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. The Board appoints a Nominating Committee each year. The Nominating Committee consists of members selected from different sections of the service area of Chugach. No member of the Board may serve on the committee. The Nominating Committee reviews the qualifications of the Board candidates and nominates candidates for election at the annual meeting. The Nominating 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. Six of our current Board members were nominated by the Nominating Committee and one was nominated by petition.

Audit Committee Financial Expert

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.

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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 2012 Audit Committee include Chair P.J. Hill and Directors Susan Reeves, Janet Reiser and Harry Crawford.

The disclosure required by Rule 10A-3(d) of the Securities Exchange Act of 1934 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 ensure 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 based on performance standards they develop. On January 4, 2012, the Board 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 2012, 2011 and 2010, upon review of the performance of the CEO, Mr. Evans received a discretionary bonus of $25,000, $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.

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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 2012 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,		2012	$	299,998	$	25,000	$	249,325	$	15,924	$	590,247
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
Michael R. Cunningham,		2012	$	208,976	$	20,000	$	312,647	$	66,162	$	607,785
Former Chief Financial Officer		2011	$	200,433	$	20,000	$	205,955	$	13,319	$	439,707
		2010	$	177,012	$	0	$	147,530	$	16,218	$	340,760
Lee D. Thibert,		2012	$	199,919	$	15,000	$	245,090	$	13,278	$	473,287
Sr. Vice President, Strategic		2011	$	193,133	$	10,000	$	205,468	$	7,318	$	415,919
Planning & Corporate Affairs		2010	$	186,121	$	10,000	$	108,314	$	6,218	$	310,653
Tyler E. Andrews,		2012	$	153,056	$	5,000	$	34,865	$	10,375	$	203,296
Vice President,		2011	$	147,619	$	0	$	32,650	$	894	$	181,163
Human Resources		2010	$	136,858	$	5,000	$	20,447	$	3,093	$	165,398
Edward M. Jenkin,		2012	$	173,078	$	5,000	$	205,556	$	3,488	$	387,122
Vice President,		2011	$	167,761	$	0	$	179,247	$	1,444	$	348,452
Power Delivery		2010	$	163,087	$	0	$	90,446	$	1,202	$	254,735
Paul R. Risse,		2012	$	174,410	$	15,000	$	181,842	$	9,038	$	380,290
Sr. Vice President,		2011	$	168,541	$	0	$	137,323	$	2,532	$	308,396
Power Supply		2010	$	163,970	$	0	$	86,543	$	2,281	$	252,794
Ronald K. Vecera,		2012	$	135,136	$	0	$	285,968	$	1,850	$	422,954
Interim, Chief Financial Officer		2011	$	129,698	$	0	$	169,085	$	1,164	$	299,947
		2010	$	128,478	$	0	$	132,791	$	16,689	$	277,958

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

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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.

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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, 2012 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		11.83	$	812,688	$	0
	Pension Restoration		11.83	$	46,347	$	0
Michael R. Cunningham,1 Former Chief Financial Officer	Retirement Security		0.83	$	46,731	$	1,755,330
Lee D. Thibert, Sr. VP, Strategic Planning & Corp Affairs	Retirement Security		24.33	$	1,323,728	$	0
Paul R. Risse, Sr. VP, Power Supply	Retirement Security		16.92	$	790,238	$	0
Edward M. Jenkin, VP, Power Delivery	Retirement Security		22.08	$	950,788	$	0
Tyler E. Andrews, VP, Human Resources	Retirement Security		3.8	$	99,486	$	0
Ronald K. Vecera, Interim, Chief Financial Officer	Retirement Security		29.17	$	1,575,725	$	0

¹  Mr. Cunningham was paid the value of all of his pension benefits attributable to service prior to March 1, 2012.

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 (3.02 percent for 2012 and 4.19 percent for 2011) and the Pension Protection Act (PPA) three-segment yield rates (1.99 percent, 4.47 percent, and 5.26 percent for 2012 and 2.16 percent, 4.77 percent, and 6.05 percent for 2011) 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 2012 and 2011, respectively, combined unisex 50 percent/50 percent mortality in combination with the PPA rates). The lump sum is then discounted at 3.75 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2012, and 3.91 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2011, to determine the present value for the appropriate year.

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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	$	22,500	$	0	$	29	$	0	$	87,266
Michael R. Cunningham, Former Chief Financial Officer	$	22,500	$	0	$	16,451	$	0	$	196,873
Tyler E. Andrews, Vice President, Human Resources	$	9,100	$	0	$	928	$	0	$	15,485
Ronald K. Vecera, Interim, Chief Financial Officer	$	17,500	$	0	$	23,822	$	0	$	182,449

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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 percent 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	$	268,122
Michael R. Cunningham, Former Chief Financial Officer	$	119,413
Lee D. Thibert, Sr. Vice President, Strategic Planning & Corporate Affairs	$	133,574
Tyler E. Andrews, Vice President, Human Resources	$	62,937
Edward M. Jenkin, Vice President, Power Delivery	$	125,648
Paul R. Risse, Sr. Vice President, Power Supply	$	198,902
Ronald K. Vecera Interim, Chief Financial Officer	$	197,577

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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, 2012 to each of our current and former Board members:

Director Compensation Table

Name	Fees Paid In Cash
Janet Reiser, Chairman and Director	$	21,900
Susan Reeves, Vice-Chairman and Director	$	13,850
Jim Henderson, Secretary and Director	$	10,500
P.J. Hill, Treasurer and Director	$	10,700
James Nordlund, Director	$	10,750
Harry Crawford, Jr., Director	$	14,750
Sisi Cooper, Director	$	6,700
Doug Robbins, Former Director	$	5,200

One new Board member was elected, while one current Board member was re-elected at Chugach’s annual membership meeting held on May 17, 2012. Sisi Cooper was elected to a three-year term while James Nordlund was re-elected to a three-year term.

Item 12 – Security Ownership of Certain Beneficial Owners and Management

and Related Stockholder Matters

Not Applicable

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

Not Applicable

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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, 2012.

Fees and Services

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

	2012		2011
Audit and audit-related services:
Audit and quarterly reviews	$	179,555	$	237,990
Audit-related services (Employee benefit plans / power plant sale)		37,750		17,000
Non-audit services:
Tax consulting and return preparation		75,260		64,890
Other services1		21,372		39,752
Total	$	313,937	$	359,632

¹  Other services in 2012 included the review of a new customer accounting system

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

The Audit Committee 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, 2012 and 2011 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:
Report of Independent Registered Public Accounting Firm		51
Balance Sheets, December 31, 2012 and 2011		52-53
Statements of Operations, Years ended December 31, 2012, 2011 and 2010		54
Statements of Changes in Equities and Margins, Years ended December 31, 2012, 2011 and 2010		55
Statements of Cash Flows, Years ended December 31, 2012, 2011 and 2010		56
Notes to Financial Statements		57-91

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 17, 2012, 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.
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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
4.25	Bond Purchase Agreement between the Registrant and the 2012 Series A Bond Purchasers dated January 11, 2012. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.

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4.26	Form of 2012 Series A Bond (Tranche A) due March 15, 2032. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
4.27	Form of 2012 Series A Bond (Tranche B) due March 15, 2042. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
4.28	Form of 2012 Series A Bond (Tranche C) due March 15, 2042. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
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.
10.4.3	Amendment No. 2 to the 2006 Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective March 1, 2012. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2012, 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.
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.

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10.6.1	First Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of February 10, 1995. 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.
10.6.3	Second 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 September 30, 2008. Filed Herewith.
10.7	Power Purchase Agreement by and between Fire Island Wind, LLC and the Registrant dated as of June 21, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
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.

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10.20	Grant Transfer and Delegation Agreement between the Registrant and Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc., Matanuska Electric Association, Inc., Homer Electric Association, Inc., Seward, the State of Alaska, Department of Administration, and AMEA dated November 5, 1993. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1993, SEC File No. 033-42125.
10.22	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.
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.

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10.25.1	Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. 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.
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.

110

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
10.35	FSS Service Agreement between Cook Inlet Natural Gas Storage Alaska, LLC and the Registrant, effective October 26, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
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.

111

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.
10.45.8	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.
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.
10.47.3	Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation dated October 12, 2012. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2012, 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.
10.49.1	Amendment No. 1 to the Credit Agreement between the Registrant and NRUCFC dated effective June 29, 2012. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2012, 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.

112

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.
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.
10.60.2	Letter Of Agreement between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated March 15, 2012. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2012, 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.
10.64.1	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.

113

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.
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.
10.73	Special Contract for Natural Gas Transportation Service between the Registrant and ENSTAR Natural Gas Company effective November 1, 2012. Filed Herewith.
10.74	Firm Transportation Service Agreement between the Registrant and ENSTAR Natural Gas Company effective August 1, 2012. 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.

114

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.

115

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 13, 2013.

CHUGACH ELECTRIC ASSOCIATION, INC.
By:	/s/ Bradley W. Evans
	Bradley W. Evans, Chief Executive Officer
Date:	March 13, 2013

116

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 13, 2013, by the following persons on behalf of the registrant and in the capacities indicated:

/s/ Bradley W. Evans	Chief Executive Officer (Principal Executive Officer)
Bradley W. Evans
/s/ Ronald K. Vecera	Interim, Chief Financial Officer (Principal Financial Officer) (Principal Accounting Officer)
Ronald K. Vecera
/s/ Paul R. Risse	Sr. Vice President, Power Supply
Paul R. Risse
/s/ Lee D. Thibert	Sr. Vice President, Strategic Planning & Corporate Affairs
Lee D. Thibert
/s/ Edward M. Jenkin	Vice President, Power Delivery
Edward M. Jenkin
/s/ Tyler E. Andrews	Vice President, Human Resources
Tyler E. Andrews
/s/ Janet Reiser	Director & Chairman of the Board
Janet Reiser
/s/ Susan Reeves	Director & Vice-Chairman of the Board
Susan Reeves
/s/ P. J. Hill	Director & Treasurer of the Board
P. J. Hill
/s/ Jim Henderson	Director & Secretary of the Board
Jim Henderson

117

/s/ James Nordlund	Director
James Nordlund
/s/ Harry T. Crawford	Director
Harry T. Crawford
/s/ Sisi Cooper	Director
Sisi Cooper

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 2012 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.

118

EX-10.6.3

Exhibit 10.6.3

	STATE OF ALASKA DEPARTMENT OF COMMERCE COMMUNITY AND ECONOMIC DEVELOPMENT	Sarah Palin, Governer Emil Notti, Commissioner Robert M. Pickett, Chairman
	Regulatory Commission of Alaska

October 20, 2008

In reply refer to:	Engineering
	File:	TA365-18
	LO#:	L0800511

Wayne Carmony

General Manager

Matanuska Electric Association, Inc.

P.O. Box 2929

Palmer, AK 99645-2929

Dear Mr. Carmony:

On September 30 2008, the Commission concurred with Staff’s recommendation to approve TA365-18, the request for approval of the Second Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy (the Amendment), filed on July 28, 2008, between Chugach Electric Association, Inc. (Chugach), Matanuska Electric Association, Inc. (MEA), and Alaska Electric Generation and Transmission Cooperative, Inc. (AEG&T). The effective date of the Amendment is September 30, 2008.

Enclosed is a validated copy of the Amendment, filed on July 28, 2008, and a copy of Staffs memorandum. Please note that the tariff advice number “TA365-18” and the effective date of September 30, 2008 have been added to the bottom of the pages of the Amendment.

BY DIRECTION OF THE COMMISSION (Commissioner Kate Giard Not Participating)

Sincerely,
REGULATORY COMMISSION OF ALASKA
	/s/ Robert Picket
	Robert Picket
	Chair

701 W. 8th Avenue, Suite 300, Anchorage, Alaska 99501-3469

Telephone: (907) 276-6222    Fax: (907) 276-0160    Text Telephone: (907) 276-4533

Website: http://rca.alaska.gov/RCAWeb/home.aspx

Enclosures

CC:	Brad Evans, Chief Executive Officer, Chugach Electric Association, Inc.
	560 E. 34th Avenue Suite 200
	Anchorage, Alaska 99503-4196
	Earl Osmond, Polarconsult Alaska, Inc.
	1503 W. 33rd Avenue
	Anchorage, Alaska 99503

SECOND AMENDMENT TO MODIFIED AGREEMENT FOR THE SALE AND

PURCHASE OF ELECTRIC POWER AND ENERGY

dated April 5, 1989 by and among Chugach Electric Association, Inc., Matanuska Electric

Association, Inc. and

Alaska Electric Generation and Transmission Cooperative, Inc.

WHEREAS, Chugach Electric Association, Inc. (Chugach), Matanuska Electric Association, Inc. (MEA) and Alaska Electric Generation and Transmission Cooperative, Inc. (AEG&T) are parties (hereinafter jointly referred to as the “Parties”) to the Modified Agreement For The Sale And Purchase Of Electric Power And Energy dated April 5, 1989 by and among Chugach Electric Association, Inc., Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. (hereinafter “Agreement”; MEA and AEG&T acting collectively with respect to the Agreement are referred to herein as “AEG&T/MEA”);

WHEREAS, the Parties desire to amend the Agreement to facilitate MEA purchasing the electrical output of two hydroelectric facilities planned by South Fork Hydro, LLC and Fishhook Renewable Energy, LLC for location on the South Fork of Eagle River and on Fishook Creek in the Hatcher Pass area, respectively, of Southcentral Alaska (hereinafter “South Fork/Fishhook Hydro Projects”);

WHEREAS, the intent of the Parties in this Second Amendment to the Agreement is to allow MEA to purchase the entire electrical output of the South Fork/Fishhook Hydro Projects, on terms that are financially neutral to both Chugach and AEG&T/MEA for wholesale power service provided to AEG&T/MEA, without changing AEG&T/MEA’s status under the Agreement as an “All Requirements” customer of Chugach;

WHEREAS, the Parties intend that except as specifically stated herein, this Second Amendment to the Agreement shall not in any way change or diminish the Parties’ respective rights and responsibilities under the Agreement, and shall not be considered as agreement to or precedent for future changes in the Parties’ rights and responsibilities under the Agreement; and

WHEREAS, the impact of the South Fork/Fishook Hydro Projects on Chugach’s annual G&T transmission loss factor, when the energy deliveries from the Projects are included and calculated in accordance with the Stipulation on G&T Line Loss Issues that was accepted by the Commission in Order No. 12 of Docket U-99-106, is expected to be immaterial, both individually and collectively;

NOW, THEREFORE, consistent with the above, the Parties agree to the following Second Amendment to the Agreement

A. New Section 7 (e)

The Parties agree to add a new Section 7(e) to the Agreement as follows:

7 (e). Treatment of South Fork/Fishhook Hydro Projects. Provided the installed capacity of two hydroelectric facilities planned by South Fork Hydro, LLC and Fishhook

	1 of 4
TA365-18		Effective September 30, 2008

Renewable Energy, LLC for location on the South Fork of Eagle River and on Fishook Creek in the Hatcher Pass area, respectively, of Southcentral Alaska (South Fork/Fishhook Hydro Projects) in the aggregate does not exceed 4 MW:

(1) Purchase by MEA of Electric Power from one or both of the South Fork/Fishhook Hydro Projects shall not be considered an AEG&T/MEA Resource for purposes of this Agreement.

(2) AEG&T/MEA shall not be obligated to use reasonable best efforts to persuade the developers of the South Fork/Fishhook Hydro Projects to deal directly with Chugach, as otherwise provided for in 7(b).

(3) Chugach’s monthly invoice to AEG&T/MEA shall be reduced by an amount equal to the kWh received by MEA from the South Fork/Fishhook Hydro Projects multiplied by Chugach’s tariffed rate for non-firm power purchases for that billing month. Specifically, unless and until an alternative avoided cost calculation is developed, the “Non­ firm power rate” on the approved Chugach Tariff Sheet No. 97 (Purchase and Sales Rates for Qualified Cogeneration and Small Power Production Facilities) for each month shall be used to determine the amount by which Chugach’s invoice shall be reduced based upon MEA’s purchases from the South Fork/Fishook Hydro Projects. At any time prior to the end of this agreement Chugach may propose to the Commission an alternative avoided cost calculation to apply to MEA’s purchases from the South Fork/Fishhook Hydro Projects. Prior to filing any such proposal, Chugach shall meet with AEG&T/MEA to discuss how the proposed change, if approved, would affect AEG&T/MEA’s monthly invoice. Any changes in the calculation of the avoided cost rate(s) are subject to the standard review and adjudicatory processes of the Regulatory Commission of Alaska. AEG&T/MEA reserves the right to oppose any such proposal before the Commission.

(4) Payments made by MEA for purchases from the South Fork/Fishook Hydro Projects shall be not be less than the reduction to MEA’s billings from Chugach for the kWh received by MEA from the South Fork/Fishhook Hydro Projects described in Section 7(e)(3), above.

(5) Except for the reduction in Chugach’s monthly invoice to AEG&T/MEA computed pursuant to Section 7(e)(3), all rates and resulting invoices charged by Chugach to MEA shall be computed as if the Electric Power received from the South Fork/Fishhook Hydro Projects were received from Chugach. The wholesale billing rates charged by Chugach to AEG&T/MEA shall not be reduced to reflect any contribution of capacity from the South Fork/Fishhook Hydro Projects. Energy-related costs other than fuel and purchased power that are presently included in the rates charged by Chugach to AEG&T/MEA shall not be reduced to reflect Electric Power received by MEA from the South Fork/Fishhook Hydro Projects. For the remainder of the term of the Agreement, Chugach’s rates for AEG&T/MEA’s purchases of energy and capacity (including both monthly Billing Demand and determination of Coincident Peak for ratemaking purposes) shall be computed as if the amounts of capacity and energy taken from the South Fork/Fishhook Hydro Projects by AEG&T/MEA were actually taken from Chugach.

	2 of 4
TA365-18		Effective September 30, 2008

For purposes of Chugach’s quarterly Fuel and Purchased Power Cost Adjustment Factor updates (Chugach Tariff Sheets No. 94 et al), the amounts credited AEG&T/ MEA pursuant to Section 7(e)(3) for MEA’s purchases of Electric Power from the South Fork/Fishhook Hydro Projects will be considered part of Chugach’s system costs. Those costs shall be apportioned to all classes of service, including AEG&T/MEA, consistent with established cost assignment methodologies.

(6) All of Chugach’s remaining obligations under the AEG&T/MEA Agreement, including the obligation to maintain reserves sufficient to support AEG&T/MEA’s entire load, remain unchanged.

(7) Before allowing the South Fork/Fishhook Hydro Projects to interconnect with AEG&T/MEA’s facilities or equipment, or accepting any Electric Power from the South Fork/Fishhook Projects, MEA shall confirm, to Chugach’s satisfaction, its ability to provide Chugach with interval pulse data that are compliant with and subject to all metering requirements of the AEG&T/MEA Agreement. AEG&T/MEA shall ensure that telephone access is installed to Chugach’s specifications at the metering point. The metering installed by Chugach, and the pulse output provided by MEA, shall be:

(A) revenue class capable of measuring the amount of kWh delivered to AEG&T/MEA by the South Fork/Fishhook Hydro Projects

(B) capable of measuring with a frequency of not less than every 15 minutes;

(C) accessible by and compatible with Chugach’s MV90 system; and

(D) accepting of telephonic interrogation.

MEA shall assure by contract with the South Fork/Fishhook Hydro Projects that Chugach-owned meters on the premises of the South Fork/Fishhook Hydro Projects are fully accessible to Chugach, without charge, and that Chugach is afforded all of the same rights as it has with respect to other meters under the Agreement. Chugach shall bear the full cost of installing its meters and collecting metered data from those Chugach-owned and maintained meters.

(8) Once the South Fork/Fishhook Hydro Projects have commenced energy deliveries, they shall be counted as Points of Delivery for which a monthly Customer Charge is payable by AEG&T/MEA, pursuant to Chugach Tariff Sheet No. 99.

(B) The Parties acknowledge that no part of this Second Amendment shall be interpreted to have amended the Agreement, until this Second Amendment has been approved by the Regulatory Commission of Alaska. The Parties agree to use their best efforts to get prompt approval of this Second Amendment by the Regulatory Commission of Alaska.

	3 of 4
TA365-18		Effective September 30, 2008

(C) Notwithstanding Part B of this Second Amendment, Chugach agrees that MEA can begin negotiations with the owners of the South Fork/Fishhook Hydro Projects for agreements to purchase the electrical output of those projects immediately upon the Parties having signed this Second Amendment, and that such negotiations will not be considered a violation of Section 7(b) of the Agreement.

(D) The Parties agree that this Second Amendment does not preclude Chugach from negotiating directly with the South Fork/Fishhook Hydro Projects or with any other power supplier to purchase the electrical output.

Dated this 25th day of June, 2008
CHUGACH ELECTRIC ASSOCIATION, INC.
By:	/s/ Rebecca Logan
Its:	Chairman
MATANUSKA ELECTRIC ASSOCIATION, INC.
By:	/s/ Elsie E. Lester
Its:	President
ALASKA ELECTRIC GENERATION &     TRANSMISSION COOPERATIVE, INC.
By:	/s/ Wayne Carmony
Its:	General Manager / Director

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TA365-18		Effective September 30, 2008

TARIFF ACTION MEMORANDUM

		September 2, 2008
		Date
File No.: TA365-18		Date Filed: July 28. 2008
Name of Utility:	Matanuska Electric Association, Inc.

Tariff Recommendation:

Staff recommends the commission approve the Second Amendment to the Agreement for the Sale and Purchase of Electric Power and Energy, dated April 5, 1989 by and among Chugach, MEA, and AEG&T.

Reason(s) for the above-indicated recommendation:

See attached memorandum.

Signed:	/s/ James Keen	Title:	Utility Engineering Analyst
	James Keen

Commission decision regarding this recommendation:

	Date (if Different from September 30, 2008)	I CONCUR	I DO NOT CONCUR	I WILL WRITE A DISSENTING STATEMENT *
Pickett		/s/ RMP
Giard		/s/ KG
Johnson		/s/ MJ
Price		/s/ AP
Wilson		/s/ JWW

• If this column is initialed, Staff will contact the Commissioner for the statement; otherwise, the dissent will simply be noted at the close of the By Direction letter or order.

TA Memo-MEA, TA365-18

9/30/2008

Page 1 of 4

STATE OF ALASKA

The Regulatory Commission of Alaska

701 West 8^th Ave., Suite 300

Anchorage, Alaska 99501-3469

MEMORANDUM

TO:	Commissioners:	DATE: September 2, 2008
	Bob Pickett, Chairman
	Kate Giard
	Mark K. Johnson
	Anthony A. Price
	Janis W. Wilson

FROM:	James Keen, Utility Engineering Analyst
Subject:	TA365-18, 2nd Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy dated April 5, 1989 by and among Chugach, MEA, and AEG&T.

Statement of Case

Whether the commission should approve the Second Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy dated April 5, 1989 by and among Chugach Electric Association, Inc., Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. (Second Amendment).

Recommendation

Staff recommends the commission approve the Second Amendment.

Background

MEA filed the Second Amendment on behalf of itself, Chugach Electric Association, Inc. (Chugach), and Alaska Electric Generation and Transmission Cooperative, Inc. (AEG&T) on July 28, 2008. The TA was noticed to the public with a comment period closing date of August 29, 2008.

Comments were filed electronically. Two of the comments filed anonymously stated concern about MEA increasing its rates.¹ The third comment was filed by a representative of the Water

¹  TA365-18, filed August 14, 2008; also Public Comment, filed August 15, 2008.

TA Memo-MEA, TA365-18

9/9/2008

Page 2 of 4

Resource Section of the Department of Natural Resources (Water Resources Section).² The Water Resources Section stated that it has no objection to MEA’s petition for the adoption of the Second Amendment and supplied information regarding its processing of applications by South Fork Hydro, LLC, and Fishhook Renewable Energy, LLC³

Discussion

The Second Amendment to the Purchase and Sale Agreement between Chugach, MEA, and AEG&T seeks to allow MEA to purchase power directly from South Fork Hydro, LLC (South Fork) and Fishhook Renewable Energy, LLC (Fishhook). Both hydroelectric projects are located within MEA’s certificated service area, South Fork in Eagle River and Fishhook in Hatcher’s Pass. The planned combined capacity of both projects is 4 MW. Construction of the South Fork project is planned for 2008 and construction of Fishhook is planned for 2009.

As an all-requirements customer under the existing purchase and sale agreement, MEA would normally not be allowed to purchase power directly from South Fork and Fishhook. South Fork and Fishhook would have to sell power to Chugach and also pay wheeling charges to use MEA’s transmission system. Under the proposed Second Amendment, MEA will be able to purchase power directly from South Fork and Fishhook.

The Second Amendment is designed to be financially neutral for both MEA and Chugach. MEA is permitted to negotiate a contract with both South Fork and Fishhook for purchase of electricity for at least the approved non-firm purchase power cost rate in Chugach’s tariff. Chugach has agreed to deduct from its monthly invoice to AEG&T/MEA, an amount equal to the kWh MEA receives from South Fork and Fishhook, multiplied by Chugach’s tariffed rate for non-firm

power purchases for that month. All other Chugach charges, including charges for capacity and demand will remain the same, as if the South Fork and Fishhoak projects were part of the Chugach system.

MEA is also required to ensure that the South Fork and Fishhook systems will meet with Chugach technical specifications to ensure problem-free interconnection with the Railbelt grid.

The Second Amendment does not provide MEA with authority to purchase power from any other sources except South Fork and Fishhook, or beyond the planned 4 MW combined capacity of both facilities. The Second Amendment states that its ratification is subject to RCA approval.

Chugach’s Board of Directors approved the Second Amendment at its June 25, 2008 meeting. MEA’s Board of Directors approved the Second Amendment at its July 8, 2008 meeting. AEG&T’s Class B Membership Board of Directors approved the Second Amendment at its July 8, 2008 meeting.

²  Public Comment for TA365-18 by Natural Resource Manager Patricia Bettis, filed August 20, 2008.

³  The Department of Natural Resources, Water Resources Section issued on August 20, 2007 a permit to appropriate water to South Fork Hydro, LLC for the appropriation of 54.45 cubic-feet of water per second from the South Fork Eagle River for the purpose of hydroelectric power generation. Finally, the Water Resources Section has received an application for water rights in association with the proposed Fishhook Creek hydroelectric project. This case file is currently being processed.

TA Memo-MEA, TA365-18

9/9/2008

Page 3 of 4

Staff reviewed the Second Amendment and found it to be reasonable. The amendment will not raise rates for customers and will not disrupt the relationship between MEA, Chugach, and AEG&T. There is a net benefit to providing local power generation in MEA’s service area as the line loss will not be as great. Additionally, the production of the up to 4 MW of power will offset the production of power using fossil fuels. The Second Amendment will terminate with the full purchase and sale contract on December 31, 2014 pursuant to approved terms in the master agreement. Staff recommends the commission approve the Second Amendment.

TA Memo-MEA, TA365-18

9/30/2008

Page 4 of 4

preclude MEA from using power supplied hereunder to meet its retail electric loads while engaging in contemporaneous off-system sales of capacity or energy available to MEA from other sources.

SECTION 7. NON-EXCLUSIVITY AND PURPA RESOURCES

7(a). Power Purchase Rights And Power Payment Obligations. Nothing in this Agreement shall be construed to prevent AEG&T/MEA from purchasing or acquiring power from any other source or facility, including without limitation the Eklutna and Bradley Lake Hydroelectric Projects, the Soldotna #1 unit, or any purchase or acquisition under the Public Utility Regulatory Policies Act of 1978 (“PURPA”) or other similar statutes, but no such purchase or acquisition, including under PURPA, shall excuse or reduce performance of this Agreement by the parties. In particular, both AEG&T and MEA shall at all times continue performing the purchase and payment obligations set forth in Section 6 and (if applicable) in Exhibit E of this Agreement notwithstanding any other such purchase or acquisition. Any and all purchases or acquisitions under PURPA by MEA, or for or on behalf of MEA by AEG&T, shall be treated as AEG&T/MEA Resources for purposes of this Agreement, with the exception of (1) those potential PURPA purchases and acquisitions listed in Exhibit G attached hereto and resold to Chugach under the provisions of Section 7(c) of this Agreement, and (2) any other PURPA resource whose entire output is sold by MEA to Chugach, AEG&T or any other utility and where no part of such output is used to serve MEA’s retail loads.

7(b). Treatment Of PURPA Resources Generally. Unless and until AEG&T/MEA has exercised the option described in Section 6(b) or the option described in Section 6(f), AEG&T and MEA shall use their reasonable best efforts to persuade developers of potential PURPA resources to deal directly with Chugach rather than attempting to sell the output of such resources to MEA or to AEG&T for service to MEA. AEG&T and/or MEA consents and agrees to the sale of such output from PURPA resources directly to Chugach and agrees to make its facilities available, to the extent available, as necessary to accomplish such sales, in accordance with the terms and provisions of interconnection and wheeling agreements (which shall be subject to Commission approval) among Chugach, AEG&T/MEA, and such developers. Chugach agrees to deal with all such developers in good faith and to purchase energy and capacity from such developers in accordance with the requirements of PURPA, including at Chugach’s avoided cost (or, if then-applicable PURPA regulations no longer require payment at full avoided cost, at such payment level as such regulations may then require) unless Chugach is able to reach agreement with such developers for purchases at lower payment levels. The sale to Chugach of the output from PURPA facilities may be accomplished, as appropriate, by delivering the energy and power from the PURPA

Effective: January 30, 1989 Pursuant to Order No. 12 in Docket U-87-43
MODIFIED TRIPARTITE POWER SALES AGREEMENT (CEA/AEG&T/MEA)	Page 13

Page 18 of 98

resource directly to AEG&T/MEA for service to MEA, and the determination of avoided cost shall recognize such method of delivery.

7(c). Treatment Of Exhibit G Potential PURPA Resources. With respect to the four specific resources listed in Exhibit G (for which PURPA treatment may or may not be appropriate), with whose potential developers MEA had begun engaging in discussions prior to the drafting of this Agreement, the parties agree as follows:

(1) The parties will attempt to persuade such developers to deal directly with Chugach rather than with MEA. If such developers decline to do so, and if MEA subsequently enters into a PURPA contract for one or more of the specific resources so listed, MEA may at its option elect to resell to Chugach, in which event Chugach will buy from MEA the capacity (if any) and energy produced by such resource and for which MEA is obligated to pay under such contract, but only if the following conditions are met and only upon the following terms:

(A) Conditions:

(i) MEA’s contract with the developer is executed by both parties no later than June 30, 1989 (or, if earlier, the date on which Chugach reasonably expects to refinance its existing REA or Federal Financing Bank indebtedness, such date to be specified in a written notice from Chugach to AEG&T/MEA delivered not less than 120 days prior to such date);

(ii) MEA has included Chugach in all formal and informal discussions and negotiations with such developer that take place on or after December 1, 1986;

(iii) Chugach elects not to contest the applicability of PURPA to the specific resource, or PURPA is found to apply to such resource notwithstanding any challenge by Chugach or others and

(iv) MEA’s contract with the developer does not include —

• Rates of payment for capacity and/or energy in excess of Chugach’s avoided cost for the capacity (if any) and/or energy produced by that resource, as such avoided cost is determined by Chugach or as it may lawfully be determined by the Commission;

Effective: January 30, 1989 Pursuant to Order No. 12 in Docket U-87-43
MODIFIED TRIPARTITE POWER SALES AGREEMENT (CEA/AEG&T/MEA)	Page 14

Page 19 of 98

• Financial or other incentives to which Chugach does not specifically consent, including, for example, “levelized” payments or any payment for the alleged capacity of “stochastic” resources of the type described in paragraph B(2) of this Section (unless the Commission, prior to June 30, 1989 (or, if earlier, the date on which Chugach reasonably expects to refinance its existing REA or Federal Financing Bank indebtedness, such date to be specified in a written notice from Chugach to AEG&T/MEA delivered not less than 120 days prior to such date), lawfully orders that such incentives be included in MEA’s contract for that resource); or

• Any provision that would interfere with Chugach’s ability to make effective use of power from the resource in a manner consistent with Chugach’s system operations and Chugach’s treatment of other PURPA resources.

(B) Terms:

(i) Chugach will pay MEA, for capacity and energy produced by any such resource and delivered to Chugach, at Chugach’s avoided cost for that specific resource (as determined by Chugach or as lawfully determined by the Commission}.

(ii) For wind generators and run-of-the-river or small hydroelectic generators and other forms of “stochastic” generation, Chugach has determined and hereby announces that at the present time and for the foreseeable future the output of such generators will not permit Chugach to avoid any capacity costs, and that such resources have actual economic value to Chugach only insofar as their energy output permits Chugach to avoid that portion of the costs included in the energy charge in Chugach’s rates that represents Chugach’s truly variable costs of energy production; provided, however, that notwithstanding the foregoing, the determination of the capacity value of wind generators and run-of-the-river or small hydroelectric generators and other forms of “stochastic” generation remains with the Commission.

Effective: January 30, 1989 Pursuant to Order No. 12 in Docket U-87-43
MODIFIED TRIPARTITE POWER SALES AGREEMENT (CEA/AEG&T/MEA)	Page 15

EX-10.73

Exhibit 10.73

SPECIAL CONTRACT FOR

NATURAL GAS TRANSPORTATION SERVICE

Whereas, ENSTAR Natural Gas Company (“Company”), and Chugach Electric Association, Inc. (“Customer”) desire to enter into a contract for the transportation of Customer’s natural gas; and

Whereas, the Customer is certificated to provide electric public utility service in and around Anchorage, Alaska; and

Whereas, since November 2011, the Company has transported natural gas to the Customer’s Beluga Power Plant under a Special Contract between the Company and Customer, signed on September 15, 2011 (“2011-2012 Special Contract”) ; and

Whereas, the full term of the 2011-2012 Special Contract runs from November 1, 2011 through October 31, 2012; and

Whereas, the Customer has an ongoing need for transportation of Gas by the Company to supply its Beluga Power Plant as a supplement to existing firm service the Customer has from other sources; and

Whereas, the Customer has asked the Company to provide an interruptible transportation service beginning November 1, 2012, through October 31, 2013; and

Whereas, the Company is willing to provide a supplemental interruptible transportation service for the period commencing on November 1, 2012 and ending on October 31, 2013; and

Page 1 of 13

Whereas, the service being provided by the Company is not a backup firm service and is fully interruptible under the terms of Section 1620 of the Company’s Tariff as modified by this Special Contract; and

Whereas, by providing this service, the Company is not undertaking any express or implied commitment to the Customer beyond the term of this Special Contract, and is not agreeing that it has any obligation to serve the Customer beyond the obligations memorialized in this Special Contract;

Whereas, the unique circumstances of the Customer’s transportation service requirements qualify it for this Special Contract; and

Whereas, the Company is willing to provide a supplemental interruptible transportation service to the Customer’s under the terms stated below, provided that it does not interfere with its ability to meet other, existing delivery obligations.

In consideration of the covenants and conditions in this Special Contract, the parties agree as follows:

ARTICLE I

PARTIES

1.1 The parties to this contract are ENSTAR Natural Gas Company, a division of SEMCO Energy, Inc. (“Company”) and Chugach Electric Association, Inc. (“Customer”). Terms which are capitalized in this Special Contract are defined either in the Company’s Tariff or in this Special Contract.

Page 2 of 13

ARTICLE II

TERM

2.1 Term

The full term of this Special Contract shall be from November 1, 2012 through October 31, 2013. Any extension of term will be by mutual agreement of both parties, in writing, at least 90 days prior to the expiration date of the full term.

ARTICLE III

MODIFIED TARIFF PROVISIONS

3.1 Transportation of Gas

The Company agrees to provide interruptible transportation service to the Customer under Section 1620 of the Company’s Tariff as modified below. To assist the Company in providing this service, the Customer shall provide the Company with the forecasts and nominations required by Section 1605c and 1605d of the Company’s Tariff, including but not limited to the Monthly and Daily nominations required by Sections 1605d(1) and 1605d(3) as modified below, and adhere to the balancing provisions as set out in Section 1605e. If Customer requests service for a given Day, the Customer anticipates an intraday rate of up to 10,000 MCF and the maximum delivery in a Day will be a total of 5,000 MCF.

3.2 Price

In consideration of the services provided by the Company to the Customer, the Customer shall pay the Company a Monthly Customer Charge of $11,000 and a

Page 3 of 13

Volumetric Charge of $0.20 for every Mcf of natural gas transported under this Special Contract. Service under this Special Contract will be subject to additional fees and charges as provided for in the Company’s Tariff including, but not limited to, the Regulatory Cost Charge as outlined in Tariff Section 2401 and the additional fees set out in Tariff Section 2561.

3.3 Other Terms

3.3.1 The Company will not be responsible for any damages the Customer may incur as the result of curtailment or interruption of any or all of the transportation service under this Special Contract.

3.3.2 The Company and the Customer will work together to utilize the steps defined in the 2009 Gas Emergency Agreement Letter to maintain adequate transmission and distribution pressures in the Company’s transportation system during any gas supply emergency.

3.3.3 If the Customer incurs Interruption Expense as defined by the Company’s Tariff Section 1205 (Interruption Cost Sharing) as a result of curtailment or interruption of any or all of the transportation service under this Special Contract it is not entitled to reimbursement of those Interruption Expenses by the Company.

3.4 Nominations and Balancing

3.4.1 The Customer agrees to provide the Company notice by 4:00 PM ACT of the Day prior to any Day it wishes to utilize this service. Nominations shall be provided to ENSTAR Gas Control in writing and confirmed with ENSTAR Gas Control before gas flows. The Customer agrees to provide the initial transportation nominations by 4:00 PM each day prior to requesting transportation service. The customer

Page 4 of 13

agrees to use commercially reasonable efforts to nominate gas into the ENSTAR system on a daily basis using four (4) standard nomination periods in a day (24 hour period starting at 12:00 AM (midnight) through 11:59 PM):

a. 12:00 AM to 6:00 AM

b. 6:00 AM to 12:00 PM

c. 12:00 PM to 6:00 AM

d. 6:00 PM to 11:59:59 PM

The Customer will provide estimated hourly set points for Meter 8107 and the Company will apply commercially reasonable efforts to follow.

The Customer will nominate gas based on an average load calculation for each intra-day nomination period. The Company and Customer understand that Customer deliveries will vary from the average based on actual (instantaneous) generation requirements.

3.4.2 Customer will comply with Daily balancing tolerances per the Tariff. The Customer will schedule daily gas balance accrual settlement on a weekly basis.

3.4.3 The Company agrees to notify the Customer two hours prior to interruption except in the case of a Gas flow disruption to the Company from the Beluga River Unit (including a compressor failure) where the Company agrees to notify the Customer 30 minutes prior to interruption.

Page 5 of 13

ARTICLE IV

DELIVERY/RECEIPT POINTS

4.1 Delivery Point

The Delivery Point for this Special Contract is the Customer’s Beluga Power Plant at the Company’s Metering Station #B253, Meter 8107.

4.2 Receipt Points

Receipt Points are as follows:

4.2.1 Interconnection of the KNPL – APC Kenai pipelines: Station K681, Meter 411.

Suppliers and Supplier contact information:

ConocoPhillips Company (“COP”) and ConocoPhillips Alaska, Inc. (“CPAI”)
Attention:	Cook Inlet Marketing
	Cook Inlet Control
Telephone:	(907) 265-1605
	(907) 263-4704 or cell: (907) – 748-5966
Facsimile:	(918) 662-6895
E-mail	Joe Falcone
	Joe.Falcone@conocophillips.com
Marathon Alaska Production LLC
Attention:	Gas Supply and Transportation Representative
Telephone:	(907) 283-1308
Facsimile:	(907) 283-6175
E-mail:	fwbassetti@marathonoil.com

4.2.2 Interconnection of the KKPL – APC Kenai pipelines: Station K680, Meter 601.

Suppliers and Supplier contact information:

Marathon Alaska Production LLC
Attention:	Gas Supply and Transportation Representative
Telephone:	(907) 283-1308
Facsimile:	(907) 283-6175
E-mail:	fwbassetti@marathonoil.com

4.2.3 Kenai Unit Connection: Station K670, Meters 500 & 505.

Suppliers and Supplier contact information:

Marathon Alaska Production LLC
Attention:	Gas Supply and Transportation Representative
Telephone:	(907) 283-1308
Facsimile:	(907) 283-6175
E-mail:	fwbassetti@marathonoil.com

Page 6 of 13

4.2.4 Interconnection of Beluga Pipe Line Company – APC Beluga pipeline: Station B605, Meters 700 & 701.

Suppliers and Supplier contact information:

Marathon Alaska Production LLC
Attention:	Gas Supply and Transportation Representative
Telephone:	(907) 283-1308
Facsimile:	(907) 283-6175
E-mail:	fwbassetti@marathonoil.com

ARTICLE V

APPLICABILITY OF THE COMPANY’S TARIFF

5.1 Tariff

Except as expressly modified by this Special Contract, all of the terms and conditions of the Company’s Tariff (RCA No. 4) shall apply to the Services provided by the Company to the Customer under this Special Contract, including without limitation Section 1200 (Interruption). Further, due to the anticipated average and peak daily demand of the Customer, the following Sections of the Company’s Tariff will apply: Section 1605c (Forecasts), Section 1605d (Nominations), Section 1605e (Balancing), Section 1605f (Pressure), 1605g (Measuring Stations), Section 1605h (Measurement), and Section 1605j (Credit and Billing).

Page 7 of 13

5.2 Balancing

With respect to Section 1605e of the Company’s Tariff, (Balancing) the Customer’s daily nominations will be compared to the actual volumes delivered to the Customer for the purposes of applying the Daily Balancing Tolerances and computing Over or Under Supply pursuant to Sections 1605e(3) and 1605e(4).

5.3 The Company’s Tariff

The Customer acknowledges that it has a copy of the Company’s Tariff RCA No. 4 and is familiar with its provisions.

ARTICLE VI

RCA APPROVAL

6.1 RCA Approval

The Parties understand that this Special Contract does not take effect without the prior approval of the Regulatory Commission of Alaska (“RCA”) and is, at all times, subject to revisions by the Commission. This Special Contract shall be effective on the date of a final order by the RCA approving this Special Contract.

6.2 Termination Due to Form of RCA Approval or Amendment

In the event that revisions to this Special Contract are required by the RCA or any other governmental body acting within its jurisdiction and the revisions are not acceptable to either party, either party may terminate this Special Contract by giving notice under this Article 6.2 within thirty (30) days of receipt of the order requiring the revisions.

Page 8 of 13

ARTICLE VII

ADDRESSES

7.1 Notices

All notices, except as provided for nominations and billings, shall be given in writing at the address set forth below. Notice shall be deemed to have been given when received by the Company or the Customer at those addresses.

7.1.1 FOR THE COMPANY:

For Transportation Nominations from the Customer, Scheduling and Day to Day Operations:

ENSTAR Natural Gas Control
ATTN: Gas Control
Physical Address:
401 E. International Airport Road
Anchorage, AK 99518
Mailing Address:
P.O. Box 190288
Anchorage, AK 99519-0288
Telephone:	907 334-7788
Facsimile:	907 334-7779
E-mail:	EnstarGasControl@enstarnaturalgas.com

For Payments:

ENSTAR Natural Gas Company
ATTN: General Accounting Supervisor
Physical Address:
3000 Spenard Road
Anchorage, AK 99503
Mailing Address:
P.O. Box 190288
Anchorage, AK 99519-0288
Telephone:	907 334-7628
Facsimile:	907 272-3403
E-mail:	natalia.nelson@enstarnaturalgas.com

Page 9 of 13

For all other Notices:

ENSTAR Natural Gas Company
Attention: Manager, Gas Supply &
Director, Business Development
Address: Physical:	3000 Spenard Road
	Anchorage, AK 99503
Mailing:	P.O. Box 190288
	Anchorage, AK 99519
Telephone:	(907) 334-7756
Facsimile:	(907) 334-7671
E-mail:	Mark.Slaughter@enstarnaturalgas.com
	John.Sims@enstarnaturalgas.com

7.1.2 FOR THE CUSTOMER:

For Scheduling and Day to Day Operations:

Attention:	Director System Control
cc:	Manager, Fuel Supply
Address: Physical:	5601 Electron Drive
	Anchorage, AK 99518
Mailing:	P.O. Box 196300
	Anchorage, AK 99519
Telephone:	(907) 762-4779
Facsimile:	(907) 762-4792
E-mail:	burke_wick@chugachelectric.com
	andrew_white@chugachelectric.com

For Billings and Payment:

Attention:	Director System Control
Address: Physical:	5601 Electron Drive
	Anchorage, AK 99518
Mailing:	P.O. Box 196300
	Anchorage, AK 99519
Telephone:	(907) 762-4779
Facsimile:	(907) 762-4792
E-mail:	burke_wick@chugachelectric.com

Page 10 of 13

For All Other Notices:

Attention:	Director System Control
Address: Physical:	5601 Electron Drive
	Anchorage, AK 99518
Mailing:	P.O. Box 196300
	Anchorage, AK 99519
Telephone:	(907) 762-4779
Facsimile:	(907) 762-4792
E-mail:	burke_wick@chugachelectric.com

ARTICLE VIII

OTHER TERMS

8.1 Indemnification

The Customer will indemnify, defend and hold the Company harmless against any and all claims by other Cook Inlet purchasers or producers concerning the purchasing of Gas or the priority of Gas taken under this Special Contract.

8.2 Limit of Obligation

By making this commitment to transport Gas to the Customer, the Company is not agreeing that it has any obligation, beyond the term of this Special Contract, to transport Gas to the Customer’s Beluga Power Plant.

8.3 Gas Availability

This Special Contract is contingent upon the Customer securing delivery of adequate gas to the Receipt Points.

Page 11 of 13

ARTICLE IX

MISCELLANEOUS

9.1 Binding Upon Successors

This Special Contract shall be binding upon and inure to the benefit of the legal representatives, successors and assigns of the parties. Except as provided below, neither party may assign its rights and obligations under this Special Contract without first obtaining the written consent of the other. Consent is not required if all or substantially all of the assets of the Company or the Customer are acquired by another person or the Company or the Customers is merged, consolidated or reorganized with another person, provided that the assignee assumes in writing the assignor’s obligations under this Special Contract. Nothing contained in this Article shall prevent either party form pledging or mortgaging its rights under the Special Contract for security of its indebtedness.

9.2 Special Contract Not to be Construed Against Either Party as Drafter

The parties recognized that this Special Contract is the product of the joint efforts of the parties and agree that it shall be construed according to its plain meeting and shall not be construed against either party as drafter.

9.3 Entire Agreement

This Special Contract and the Company’s Tariff constitute the entire agreement and understanding between the parties concerning the subject matter of this transaction, and all prior agreements, understandings and representations, whether oral or written, concerning this subject matter are superseded by this written Special Contract. No amendment to this Special Contract shall be binding on either party until reduced to writing and signed by the parties.

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9.4 Headings

The headings throughout this Special Contract are for reference purposes only and shall not considered in interpreting this Special Contract.

9.5 No Incidental or Consequential Damages

Neither party shall have any liability to the other for incidental or consequential damages resulting from this Special Contract.

9.6 No Intended Third-Party Beneficiary

The parties understand and agree that no person or entity is an intended third party beneficiary of this Special Contract.

IN WITNESS WHEREOF, the parties have executed this Special Contract in two (2) originals.

Chugach Electric Association, Inc.
By:	/s/ Bradley Evans
Title:	CEO
Date:	November 9, 2012
ENSTAR Natural Gas Company, a Division of SEMCO Energy, Inc.
By:	/s/ M.C. Starring
Title:	President
Date:	10-31-2012

Page 13 of 13

EX-10.74

Exhibit 10.74

CHUGACH ELECTRIC ASSOCIATION, INC.

FIRM TRANSPORTATION

SERVICE AGREEMENT

This Service Agreement is made between Chugach Electric Association (the “Customer) and ENSTAR Natural Gas Company, a division of SEMCO Energy, Inc., (the “Company) on May 21^st , 2012 for natural gas transportation service to be supplied under the Company’s Rate Schedule Very Large Firm Transportation Service (VLFT), which is incorporated by reference.

1. The general terms and conditions for this service are set out in the Company’s tariff, including Sections 1605 and 1640. The rates for this transportation service are set out in the Company’s tariff Section 2150. The monthly rate and customer charge and demand charge applies to each individual Delivery Point receiving service under Schedule VLFT, in accordance with tariff Section 704. Volumes from individual Delivery Points will not be combined or aggregated unless it is for the convenience of the Company.

2. VLFT Service to the Customer will commence on August 1^st, 2012, and this Service Agreement shall remain in effect through August 1^st 2013, and Year to year thereafter until canceled upon twelve Months written notice by either party. Final notice of the commencement date for Service will be documented by e-mail or fax. The gas to be transported is for the ultimate delivery only to the end user(s) listed as Delivery Points in Attachment B.

3. The Customer agrees to a Contracted Peak Demand of 36,300 Mcf per day, and agrees to pay the Company a Demand Charge, as calculated under Schedule VLFT, in accordance with the Company’s tariff Sections 2150b and 2150c. If this Service Agreement is extended by the parties, the Customer will pay a Demand Charge for the period that is extended. If, as a result of the Service commencement date or Service termination date, Service is provided for a partial month, the Demand Charge and Customer Charge will be pro rated based upon the ration of the number of days Service was provided during the Month over the number of Days in the Month.

4. If the Company is unable to deliver the Contracted Peak Demand on any Day due to capacity limitations of its pipeline system, the Demand Charge for that Month will be reduced to reflect the amount that was actually delivered for that Day taking into account the number of Days during the Month that capacity was not limited.

5. Receipt Points for gas transported are listed in Attachment A along with the gas suppliers and a contact for each receipt point. The Delivery Point(s) are listed in Attachment B along with a contact for each Delivery Point. -The Customer agrees to use reasonable effort to notify the Company’s gas control dispatcher of actual production plans and any material change by phone (907) 334-7788, by facsimile at (907) 334-7779, or by e-mail at enstar.gascontrol@enstarnaturalgas.com.

CHUGACH ELECTRIC ASSOCIATION, INC.

SOUTHCENTRAL POWER PLANT

FIRM TRANSPORTATION SERVICE AGREEMENT

MAY 2012

Page 2 of 3

6. The Customer agrees to the terms and conditions of payment provided in the Company’s tariff.

7. Notices to the Customer and Company, and billings for service to the Customer shall be mailed or delivered to the addresses listed below. Telephone and facsimile numbers are provided for other communications.

Notices to Customer:		Notices to Company:
For Scheduling and Day to Day
Plant Operations:
Chugach Electric Association, Inc.		ENSTAR Natural Gas Company
ATTN:	Director System Control	ATTN:	Gas Control
	Manager, Fuel Supply
Address:		Address:
Physical:	5601 Electron Drive	Physical:	401 E. International Airport Road
	Anchorage, AK 99518		Anchorage, AK 99518
Mailing:	P.O. Box 196300	Mailing:	P.O. Box 190288
	Anchorage, AK 99519		Anchorage, AK 99519
Telephone:	(907) 762-4779	Telephone:	(907) 334-7788
Facsimile:	(907) 762-4792	Facsimile:	(907) 334-7779
E-Mail:	burke_wick@chugachelectric.com	E-Mail:	enstar.gascontrol@enstarnaturalgas.com
	andrew_white@chugachelectric.com
For Payments:
ATTN:	Director System Control	ATTN:	General Accounting Supervisor
Address:		Address:
Physical:	5601 Electron Drive	Physical:	3000 Spenard Road
	Anchorage, AK 99518		Anchorage, AK 99503
Mailing:	P.O. Box 196300	Mailing:	P.O. Box 190288
	Anchorage, AK 99519		Anchorage, AK 99519
Telephone:	(907) 762-4779	Telephone:	(907) 334-7628
Facsimile:	(907) 762-4792	Facsimile:	(907) 272-3403
E-Mail:	burke_wick@chugachelectric.com	E-Mail:	natalia.nelson@enstarnaturalgas.com
For All Other Notices:
ATTN:	Director System Control	ATTN:	Manager, Business Development
			Manager, Gas Supply
Address:		Address:
Physical:	5601 Electron Drive	Physical:	3000 Spenard Road
	Anchorage, AK 99518		Anchorage, AK 99503
Mailing:	P.O. Box 196300	Mailing:	P.O. Box 190288
	Anchorage, AK 99519		Anchorage, AK 99519
Telephone:	(907) 762-4779	Telephone:	(907) 264-3794
Facsimile:	(907) 762-4792	Facsimile:	(907) 334-7737
E-Mail:	burke_wick@chugachelectric.com	E-Mail:	inna.johansen@enstarnaturalgas.com
			mark.slaughter@enstarnaturalgas.com

CHUGACH ELECTRIC ASSOCIATION, INC.

SOUTHCENTRAL POWER PLANT

FIRM TRANSPORTATION SERVICE AGREEMENT

MAY 2012

Page 3 of 3

Chugach Electric Association, Inc.			ENSTAR Natural Gas Company
	By:	/s/ Bradley Evans	By:	/s/ M. Colleen Starring
	Title:	CEO	Title:	President
	Date:	July 31, 2012	Date:	May 18, 2012

EX-31.1

Exhibit 31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 302 of

the Sarbanes-Oxley Act of 2002)

I, Bradley W. Evans, certify that:

1. I have reviewed this annual report on Form 10-K of Chugach Electric Association, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of Chugach as of, and for, the periods presented in this report;

4. Chugach’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Chugach and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of Chugach’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in our internal control over financial reporting that occurred during the fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting; and

5. The other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to our auditors and the audit committee of our Board of Directors:

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect our ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in our internal control over financial reporting.

Date: March 13, 2013	/s/ Bradley W. Evans
	Bradley W. Evans
	Chief Executive Officer
	Principal Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 302 of

the Sarbanes-Oxley Act of 2002)

I, Ronald K. Vecera, certify that:

1. I have reviewed this annual report on Form 10-K of Chugach Electric Association, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of Chugach as of, and for, the periods presented in this report;

4. Chugach’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Chugach and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of Chugach’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in our internal control over financial reporting that occurred during the fourth fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting; and

5. The other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to our auditors and the audit committee of our Board of Directors:

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect our ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in our internal control over financial reporting.

Date: March 13, 2013	/s/ Ronald K. Vecera
	Ronald K. Vecera
	Interim, Chief Financial Officer
	Principal Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 906

of the Sarbanes-Oxley Act of 2002)

In connection with the annual report on Form 10-K of Chugach Electric Association, Inc. (the “Company”) for the year ended December 31, 2012, as filed with the Securities and Exchange Commission (the “Report”), I, Bradley W. Evans, Chief Executive Officer and Principal Executive Officer of the Company, hereby certify as the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

Date: March 13, 2013	/s/ Bradley W. Evans
	Bradley W. Evans
	Chief Executive Officer
	Principal Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 906

of the Sarbanes-Oxley Act of 2002)

In connection with the annual report on Form 10-K of Chugach Electric Association, Inc. (the “Company”) for the year ended December 31, 2012, as filed with the Securities and Exchange Commission (the “Report”), I, Ronald K. Vecera, Interim, Chief Financial Officer and Principal Financial Officer of the Company, hereby certify as the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

(1) the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and

(2) the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

Date: March 13, 2013	/s/ Ronald K. Vecera
	Ronald K. Vecera
	Interim, Chief Financial Officer
	Principal Financial Officer

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Regulatory Matters (Details) (USD $)	1 Months Ended		3 Months Ended								12 Months Ended																	12 Months Ended		12 Months Ended
	Dec. 31, 2012	Nov. 30, 2012	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012 MW MWh item	Dec. 31, 2011	Dec. 31, 2010	Sep. 28, 2012	May 14, 2012	Feb. 06, 2013 Retail Customers [Member]	Nov. 12, 2012 Retail Customers [Member]	May 14, 2012 Retail Customers [Member]	Nov. 12, 2012 Homer Electric Association, Inc. [Member]	Nov. 12, 2012 Matanuska Electric Association, Inc. [Member]	Nov. 12, 2012 Seward [Member]	May 14, 2012 Wholesale Customers [Member]	Dec. 31, 2012 2012 Series A First Mortgage Bonds [Member]	Dec. 31, 2012 2012 Series A First Mortgage Bonds [Member] Tranche A [Member]	Dec. 31, 2012 2012 Series A First Mortgage Bonds [Member] Tranche B [Member]	Dec. 31, 2012 2012 Series A First Mortgage Bonds [Member] Tranche C [Member]	Feb. 06, 2013 Minimum [Member] Wholesale Customers [Member]	Dec. 31, 2012 Minimum [Member] 2012 Series A First Mortgage Bonds [Member]	Feb. 06, 2013 Maximum [Member] Wholesale Customers [Member]	Dec. 31, 2012 Maximum [Member] 2012 Series A First Mortgage Bonds [Member]	Dec. 31, 2013 Forecast [Member]
Regulatory Matters [Line Items]
Recommended life of SPP project											35 years
Purchase power agreement, years	25 years		25 years								25 years
Number of wind turbine generators											11
Capacity of wind turbine generators											1.6
Total capacity of wind turbine generators											17.6
Expected annual output of wind turbine generators											50,000
Grant received from State of Alaska											$ 25,000,000
Construction expenditures against state grant											20,300,000	3,200,000
Bonds, face value																								75,000,000	125,000,000	50,000,000
Bonds, interest rate																								4.01%	4.41%	4.78%
Bonds, amortization period																												20 years		30 years
Regulatory asset																							1,100,000
Request for regulatory asset		1,800,000
Operating revenues			74,483,455	62,675,511	58,631,729	71,180,773	76,828,268	68,778,352	68,517,526	69,494,223	266,971,468	283,618,369	258,325,345																		2,000,000
Proposed increase in base rate revenue	30,000,000
Proposed percentage increase in base rate revenue	26
Base rate revenue for proposed rate increase	115,000,000
Increase (decrease) in system demand and energy rate														(1.70%)	(0.10%)	6.00%	(1.70%)	1.30%	(2.10%)	(1.90%)	1.60%	(2.90%)					4.00%		7.00%
Increase (decrease) in system demand and energy rate, amount														$ (1,900,000)	$ (800,000)

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Bradley Lake Hydroelectric Project (Narrative) (Details) (USD $)	12 Months Ended			1 Months Ended	12 Months Ended			1 Months Ended			1 Months Ended	12 Months Ended	1 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Aug. 31, 2010 Bradley Lake Hydroelectric Project [Member]	Dec. 31, 2012 Bradley Lake Hydroelectric Project [Member] MW	Dec. 31, 2011 Bradley Lake Hydroelectric Project [Member]	Dec. 31, 2010 Bradley Lake Hydroelectric Project [Member]	Aug. 31, 2010 Alaska Energy Authority [Member] Bradley Lake Hydroelectric Project [Member]	Dec. 31, 2012 Revenue Bonds [Member] Alaska Energy Authority [Member] Bradley Lake Hydroelectric Project [Member]	Jul. 31, 2010 Power Revenue Refunding Bonds, Sixth Series [Member] Alaska Energy Authority [Member] Bradley Lake Hydroelectric Project [Member]	Aug. 31, 2010 Fifth Series Bonds [Member] Alaska Energy Authority [Member] Bradley Lake Hydroelectric Project [Member]	Dec. 31, 2012 Forecast [Member] Bradley Lake Hydroelectric Project [Member]	Aug. 31, 2010 Forecast [Member] Alaska Energy Authority [Member] Bradley Lake Hydroelectric Project [Member]	Dec. 31, 2012 Maximum [Member] Forecast [Member] Bradley Lake Hydroelectric Project [Member] MWh
Unrecorded Unconditional Purchase Obligation [Line Items]
Bonds, face value									$ 166,000,000	$ 28,800,000
Percentage share of power purchased					30.40%
Amount of committed purchased power					27.4
Portion of outstanding debt					28,700,000
Bonds payable	491,916,666	264,333,333
Refunding bonds											30,600,000
Threshold percentage for increasing plant costs					25.00%
Term of debt service payments								11 years
Aggregate debt service cost savings													3,300,000
Economic gain				700,000				2,400,000
Estimated increase in annual energy output														40,000
Estimated entitled additional energy output percentage												30.40%
Purchased power	$ 22,104,687	$ 25,861,814	$ 26,691,968		$ 4,223,784	$ 4,643,641	$ 5,120,958					$ 5,100,000

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Debt (Schedule Of Long-Term Debt Obligations) (Details) (USD $)			12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 CoBank 3 And 4 Variable Rate Notes Maturing In 2022 [Member]	Dec. 31, 2011 CoBank 3 And 4 Variable Rate Notes Maturing In 2022 [Member]	Dec. 31, 2012 CoBank 5 Variable Rate Notes Maturing In 2012 [Member]	Dec. 31, 2011 CoBank 5 Variable Rate Notes Maturing In 2012 [Member]	Dec. 31, 2012 2002 Series A Bond Of 6.2% Maturing 2012 [Member]	Dec. 31, 2011 2002 Series A Bond Of 6.2% Maturing 2012 [Member]	Dec. 31, 2012 2011 Series A Bond Of 4.2% Maturing 2031 [Member]	Dec. 31, 2011 2011 Series A Bond Of 4.2% Maturing 2031 [Member]	Jan. 21, 2011 2011 Series A Bond Of 4.2% Maturing 2031 [Member]	Dec. 31, 2012 2011 Series A Bond Of 4.75% Maturing 2041 [Member]	Dec. 31, 2011 2011 Series A Bond Of 4.75% Maturing 2041 [Member]	Jan. 21, 2011 2011 Series A Bond Of 4.75% Maturing 2041 [Member]	Dec. 31, 2012 2012 Series A Bond Of 4.01% Maturing 2032 [Member]	Jan. 11, 2012 2012 Series A Bond Of 4.01% Maturing 2032 [Member]	Dec. 31, 2011 2012 Series A Bond Of 4.01% Maturing 2032 [Member]	Dec. 31, 2012 2012 Series A Bond Of 4.41% Maturing 2042 [Member]	Jan. 11, 2012 2012 Series A Bond Of 4.41% Maturing 2042 [Member]	Dec. 31, 2011 2012 Series A Bond Of 4.41% Maturing 2042 [Member]	Dec. 31, 2012 2012 Series A Bond Of 4.78% Maturing 2042 [Member]	Jan. 11, 2012 2012 Series A Bond Of 4.78% Maturing 2042 [Member]	Dec. 31, 2011 2012 Series A Bond Of 4.78% Maturing 2042 [Member]
Debt Instrument [Line Items]
Long-term obligations, including current installments	$ 546,090,108	$ 429,450,318	$ 31,756,775	$ 33,659,141	$ 0	$ 791,177	$ 0	$ 120,000,000	$ 85,500,000	$ 90,000,000		$ 178,833,333	$ 185,000,000		$ 75,000,000		$ 0	$ 125,000,000		$ 0	$ 50,000,000		$ 0
Current installments of long-term obligations	24,493,022	133,360,210
Total long-term obligations, excluding current installments	$ 521,597,086	$ 296,090,108
Variable interest rate			2.55%		2.55%
Bonds, interest rate							6.20%				4.20%			4.75%		4.01%			4.41%			4.78%
Maturity date			2022		2012		2012
Maturity date									Mar. 15, 2031			Mar. 15, 2041			Mar. 15, 2032			Mar. 15, 2042			Mar. 15, 2042
Frequency of payment			interest payable monthly and principal due annually beginning in 2003		interest and principal payable monthly		interest payable semi-annually February 1 and August 1		interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012			interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012			interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2013			interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042			interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023

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Bradley Lake Hydroelectric Project (Bradley Lake Project Financials) (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jun. 30, 2012 Bradley Lake Hydroelectric Project [Member] Alaska Energy Authority [Member]	Jun. 30, 2012 Bradley Lake Hydroelectric Project [Member] Alaska Energy Authority [Member] Proportionate Share [Member]
Electric plant in service	$ 891,781,509				$ 862,362,243				$ 891,781,509	$ 862,362,243		$ 181,587,000	$ 55,202,000
Long term debt	546,090,108				429,450,318				546,090,108	429,450,318		87,607,000	26,633,000
Interest expense	$ 3,492,044	$ 3,495,865	$ 3,542,676	$ 3,872,346	$ 4,102,750	$ 3,544,204	$ 4,209,482	$ 4,890,541	$ 14,402,931	$ 16,746,977	$ 20,005,698	$ 5,032,000	$ 1,530,000

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Other Equities (Details) (USD $)	Dec. 31, 2012		Dec. 31, 2011
Other	$ 11,372,355		$ 11,358,692
Nonoperating Margins Prior To 1967 [Member]
Other	23,625		23,625
Donated Capital [Member]
Other	1,647,869		1,621,257
Unclaimed Capital Credit Retirement [Member]
Other	$ 9,700,861	[1]	$ 9,713,810	[1]

[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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Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies [Abstract]

Schedule Of Costs Of Fuel Purchased And Transported As A Percentage Of Total Fuel Costs

	2012	2011	2010
Marathon Oil Company	72.0%	44.9%	24.1%
Chevron / Unocal / Hilcorp	1.3%	16.1%	26.4%
ML&P	0.0%	3.6%	14.2%
ConocoPhillips (COP)	24.2%	31.9%	35.1%
ENSTAR	2.2%	1.3%	0.2%
Miscellaneous	0.3%	2.2%	0.0%

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Commitments And Contingencies (Narrative) (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012 item	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Beluga Power Plant [Member]	Dec. 31, 2011 Beluga Power Plant [Member]	Dec. 31, 2010 Beluga Power Plant [Member]	Dec. 31, 2012 Cooper Lake Hydroelectric Project [Member]	Dec. 31, 2013 Forecast [Member]	Dec. 31, 2012 Homer Electric Association, Inc. And Matanuska Electric Association, Inc. [Member]	Dec. 31, 2011 Homer Electric Association, Inc. And Matanuska Electric Association, Inc. [Member]	Dec. 31, 2010 Homer Electric Association, Inc. And Matanuska Electric Association, Inc. [Member]	Dec. 31, 2012 Homer Electric Association, Inc. [Member]	Dec. 31, 2011 Homer Electric Association, Inc. [Member]	Dec. 31, 2010 Homer Electric Association, Inc. [Member]	Dec. 31, 2012 ConocoPhillips (COP) [Member] MMcf	Dec. 31, 2012 Marathon Alaska Production, LLC [Member] MMcf
Percentage of employees belonging to unions									70.00%
Number of collective bargaining agreements with IBEW									3
Operating revenues	$ 74,483,455	$ 62,675,511	$ 58,631,729	$ 71,180,773	$ 76,828,268	$ 68,778,352	$ 68,517,526	$ 69,494,223	$ 266,971,468	$ 283,618,369	$ 258,325,345					$ 2,000,000	$ 100,600,000	$ 104,000,000	$ 89,100,000
Customer percentage of operating revenue																	39.00%	37.00%	35.00%
Estimated amount of gas under contract																							60,000	40,000
Expiration date of long term contract for purchase of gas supply																							December 31, 2016	December 31, 2014
Percentage of fuel supply needs filled by contracts, through 2014									100.00%
Percentage of fuel supply needs filled by contracts, in 2015									70.00%
Percentage of fuel supply needs filled by contracts, in 2016									40.00%
Percentage of power generated from gas									89.00%	92.00%	89.00%	83.00%	79.00%	78.00%
Number of years to return patronage capital after expiration of power agreement																				5 years
Patronage Capital	153,832,674				148,355,246				153,832,674	148,355,246										6,900,000	6,600,000	6,500,000
Regulatory initial cost charge per KWH									0.000626
Regulatory current cost charge per KWH									0.000568
Percentage of retail bill collected to move existing overhead lines underground									2.00%
Liability for moving overhead lines underground	3,786,031				2,611,110				3,786,031	2,611,110
Percentage ownership in natural gas-fired generation plant on land owned by Chugach	70.00%								70.00%
Number of gas turbines									3
Payments made on contracts associated with power project									85,700,000	130,500,000						13,000,000
Duration of license agreement with FERC															50 years
Estimated cost to complete project at time of relicense															12,000,000
Estimated project costs															21,900,000
Grants received from state															600,000
Grants authorized from state															5,800,000
Grants requested from state															$ 3,500,000

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Fair Values Of Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2012

Fair Values Of Assets And Liabilities [Abstract]

Schedule Of Assets Measured At Fair Value On A Recurring Basis

		Total		Level 1		Level 2		Level 3
December 31, 2012
Repurchase agreement	$	100	$	0	$	100	$	0
Money market	$	2,829,397	$	2,829,397	$	0	$	0
Marketable securities	$	10,158,016	$	10,158,016	$	0	$	0
December 31, 2011
Repurchase agreement	$	100	$	0	$	100	$	0
Money markets	$	10,000,000	$	10,000,000	$	0	$	0
Restricted cash equivalents	$	122,006,738	$	122,006,738	$	0	$	0

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Debt (Schedule Of Weighted Average Commercial Paper Balances And Weighted Average Interest Rates) (Details) (Commercial Paper [Member], USD $) In Millions, unless otherwise specified	1 Months Ended
	Dec. 31, 2012	Nov. 30, 2012	Oct. 31, 2012	Sep. 30, 2012	Aug. 31, 2012	Jul. 31, 2012	Jun. 30, 2012	May 31, 2012	Apr. 30, 2012	Mar. 31, 2012	Feb. 29, 2012	Jan. 31, 2012
Commercial Paper [Member]
Short-term Debt [Line Items]
Weighted Average Interest Rate	0.29%	0.28%	0.29%	0.34%	0.00%	0.00%	0.00%	0.35%	0.36%	0.38%	0.00%	0.27%
Average Balance	$ 11.9	$ 14.5	$ 9.3	$ 4.2	$ 0	$ 0	$ 0	$ 0.8	$ 6.3	$ 8.0	$ 0	$ 62.7

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Deferred Charges And Credits (Schedule Of Regulatory Assets)(Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Regulatory Assets [Line Items]
Total deferred charges	$ 27,712,243	$ 25,205,690
Debt Issuance And Reacquisition Costs [Member]
Regulatory Assets [Line Items]
Total deferred charges	4,126,529	3,432,665
Refurbishment Of Transmission Equipment [Member]
Regulatory Assets [Line Items]
Total deferred charges	141,976	151,235
Feasibility Studies [Member]
Regulatory Assets [Line Items]
Total deferred charges	76,390	351,727
Beluga Gas Compression [Member]
Regulatory Assets [Line Items]
Total deferred charges	2,035,466	2,544,332
Cooper Lake Relicensing / Projects [Member]
Regulatory Assets [Line Items]
Total deferred charges	5,800,417	5,930,520
Fuel Supply Negotiations [Member]
Regulatory Assets [Line Items]
Total deferred charges	815,451	1,118,439
Major Overhaul Of Steam Generating Unit [Member]
Regulatory Assets [Line Items]
Total deferred charges	1,510,046	2,265,069
Other Regulatory Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	4,473,037	2,126,335
Bond Interest - Market Risk Management [Member]
Regulatory Assets [Line Items]
Total deferred charges	7,527,357	6,034,443
Environmental Matters And Other [Member]
Regulatory Assets [Line Items]
Total deferred charges	$ 1,205,574	$ 1,250,925

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Significant Accounting Policies (Schedule Of Depreciation Rates) (Details)	26 Months Ended	29 Months Ended
	Dec. 31, 2012	Oct. 31, 2010
Minimum [Member] | Steam Production Plant [Member]
Depreciation and amortization rate	4.81%	4.45%
Minimum [Member] | Hydraulic Production Plant [Member]
Depreciation and amortization rate	1.06%	1.22%
Minimum [Member] | Other Production Plant [Member]
Depreciation and amortization rate	3.98%	3.77%
Minimum [Member] | Transmission Plant [Member]
Depreciation and amortization rate	1.58%	1.61%
Minimum [Member] | Distribution Plant [Member]
Depreciation and amortization rate	2.17%	1.95%
Minimum [Member] | General Plant [Member]
Depreciation and amortization rate	1.57%	1.25%
Minimum [Member] | Other Plant [Member]
Depreciation and amortization rate	2.75%	2.75%
Maximum [Member] | Steam Production Plant [Member]
Depreciation and amortization rate	7.04%	5.85%
Maximum [Member] | Hydraulic Production Plant [Member]
Depreciation and amortization rate	3.00%	3.00%
Maximum [Member] | Other Production Plant [Member]
Depreciation and amortization rate	10.15%	10.56%
Maximum [Member] | Transmission Plant [Member]
Depreciation and amortization rate	7.86%	6.67%
Maximum [Member] | Distribution Plant [Member]
Depreciation and amortization rate	9.63%	9.77%
Maximum [Member] | General Plant [Member]
Depreciation and amortization rate	20.00%	26.11%
Maximum [Member] | Other Plant [Member]
Depreciation and amortization rate	2.75%	2.75%

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Employee Benefit Plans (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Deferred compensation	$ 570,027	$ 420,783	$ 395,833
Number of days of severance paid per year of service	10 days
Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	6,600,000	6,000,000	6,000,000
Union Health and Welfare Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit costs and employer contributions	4,300,000	3,700,000	3,700,000
Non-Union Health And Welfare Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit costs and employer contributions	2,500,000	2,400,000	2,200,000
Money Purchase Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	$ 141,000	$ 128,700	$ 124,100
Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of days of severance paid	130 days
Number of years of service severance paid	13 years

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Debt (Narrative) (Details) (USD $)	12 Months Ended		12 Months Ended						12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended			12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended		12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Minimum [Member]	Dec. 31, 2012 Maximum [Member]	Dec. 31, 2012 2010 Credit Agreement [Member] item	Dec. 31, 2012 Second Amended And Restated Indenture Of Trust [Member] item	Dec. 31, 2012 CoBank Master Loan Agreement [member] item	Dec. 31, 2012 2010 Amended And Extended Credit Agreement [Member] Maximum [Member]	Dec. 31, 2012 Unsecured Credit Agreement [Member] Initial Credit Agreement [Member]	Nov. 17, 2010 Unsecured Credit Agreement [Member] Initial Credit Agreement [Member]	Dec. 31, 2012 Unsecured Credit Agreement [Member] Amended Credit Agreement [Member]	May 04, 2012 Unsecured Credit Agreement [Member] Amended Credit Agreement [Member]	Dec. 31, 2012 Unsecured Credit Agreement [Member] Amended And Extended Credit Agreement [Member]	Jun. 29, 2012 Unsecured Credit Agreement [Member] Amended And Extended Credit Agreement [Member]	Dec. 31, 2012 2002 Series A Bond Of 6.2% Maturing 2012 [Member]	Dec. 31, 2012 2011 Series A Bond Of 4.2% Maturing 2031 [Member]	Jan. 21, 2011 2011 Series A Bond Of 4.2% Maturing 2031 [Member]	Dec. 31, 2012 2011 Series A Bond Of 4.75% Maturing 2041 [Member]	Jan. 21, 2011 2011 Series A Bond Of 4.75% Maturing 2041 [Member]	Dec. 31, 2012 2012 Series A Bond Of 4.01% Maturing 2032 [Member]	Jan. 11, 2012 2012 Series A Bond Of 4.01% Maturing 2032 [Member]	Dec. 31, 2012 2012 Series A Bond Of 4.41% Maturing 2042 [Member]	Jan. 11, 2012 2012 Series A Bond Of 4.41% Maturing 2042 [Member]	Dec. 31, 2012 2012 Series A Bond Of 4.78% Maturing 2042 [Member]	Jan. 11, 2012 2012 Series A Bond Of 4.78% Maturing 2042 [Member]	Dec. 31, 2012 Term Loan Facility [Member]
Debt Instrument [Line Items]
Yield margins for interest multiplier to total interest expense					1.1	1.1	1.1
Distribution percentage of patronage capital	5.00%
Distribution percentage of assignable margins	50.00%
Percentage of aggregate equities and margins to total liabilities, equities and margins	30.00%
Line of credit, maximum borrowing capacity	$ 50,000,000							$ 100,000,000		$ 300,000,000		$ 100,000,000
Line of credit, borrowing rate description	The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC.												one month London Interbank Offered Rate (LIBOR) plus 107.5 basis points, along with a 17.5 basis points facility fee (based on an A-/A3 unsecured debt rating).
Line of credit, basis spread on variable rate														1.075%
Line of credit facility, basis points facility fee														0.175%
Line of credit, borrowing rate	2.90%	3.20%
Period of time the line of credit needs to be paid down for five consecutive days	12 months
Number of consecutive days debt needs to be paid down to $0 during a twelve month period	5 days
Line of credit, initiation date									Nov. 17, 2010
Line of credit, amendment date											May 4, 2012		June 29, 2012
Line of credit, expiration date	Oct. 12, 2017												Nov. 17, 2016
Commercial paper	11,500,000	175,000,000
Commercial paper repricing term			1 day	270 days
Debt face amount																	$ 90.0		$ 185.0		$ 75.0		$ 125.0		$ 50.0
Maturity date																Mar. 15, 2031		Mar. 15, 2041		Mar. 15, 2032		Mar. 15, 2042		Mar. 15, 2042
Bonds, interest rate															6.20%		4.20%		4.75%		4.01%		4.41%		4.78%
Frequency of payment															interest payable semi-annually February 1 and August 1	interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012		interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012		interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2013		interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042		interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023
Average life of bond																	10 years		15 years 6 months		10 years 8 months 12 days		15 years 8 months 12 days		20 years 8 months 12 days
Debt, issuance date																										Jan. 19, 2011

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Recent Accounting Pronouncements

12 Months Ended

Dec. 31, 2012

Recent Accounting Pronouncements [Abstract]

Recent Accounting Pronouncements

(3)Recent Accounting Pronouncements

ASC Update 2013-02 “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income”

In January 2013, the FASB issued ASC Update 2013-02, “Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income.”  ASC Update 2013-02 expands the disclosure requirements for amounts reclassified out of accumulated other comprehensive income.  This update is effective for reporting periods beginning after December 15, 2012.  Chugach began application of ASC 2013-02 on January 1, 2013.  Chugach does not have any items included in other comprehensive income.  Therefore, assignable margins and comprehensive income are the same amount and the adoption did not have any effect on results of operations, financial position, and cash flows.

ASC Update 2013-01 “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities)”

In January 2013, the FASB issued ASC Update 2013-01, “Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.”  ASC Update 2013-01 clarifies the scope of Update 2011-11 to apply to derivatives accounted for in accordance with Topic 815, Derivatives and Hedging, including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are either offset in accordance with Section 210-20-45 or Section 815-10-45 or subject to an enforceable master netting arrangement or similar agreement.  This update is effective for fiscal years beginning on or after January 1, 2013 and interim periods within those annual periods.  Chugach began application of ASC 2013-01 on January 1, 2013.  Adoption did not have any incremental effect on results of operations, financial position, and cash flows.

ASC Update 2012-04 “Technical Amendments and Improvements”

In October 2012, the FASB issued ASC Update 2012-04, “Technical Amendments and Improvements.”  ASC Update 2012-04 amends a wide range of Topics in the FASB Codification, however the main provisions were to correct source literature guidance, provide clarity by updating and correcting wording and references, relocating guidance to a more appropriate location within the Codification, and conform terminology and clarify guidance to fully reflect the fair value measurement and disclosure requirements of Topic 820.  This update is effective for the first interim or annual reporting period beginning after December 15, 2012.  Chugach began application of ASC 2012-04 on January 1, 2013.  Adoption did not have any incremental effect on results of operations, financial position, and cash flows.

(3)Recent Accounting Pronouncements (continued)

ASC Update 2012-03 “Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs to SEC Staff Accounting Bulletin No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update)”

In August 2012, the FASB issued ASC Update 2012-03, “Technical Amendments and Corrections to SEC Sections: Amendments to SEC Paragraphs to SEC Staff Accounting Bulletin No. 114, Technical Amendments Pursuant to SEC Release No. 33-9250, and Corrections Related to FASB Accounting Standards Update 2010-22 (SEC Update).”  ASC Update 2012-03 amends various SEC paragraphs pursuant to the issuance of Staff Accounting Bulletin (SAB) No. 114, which revised or removed portions of the interpretive guidance included in the FASB Codification of the SAB Series to ensure consistency of referencing throughout the SAB Series.  This update is effective upon issuance.  Chugach began application of ASC 2012-03 on its issuance date of August 27, 2012.  Adoption did not have any incremental effect on results of operations, financial position, and cash flows.

ASC Update 2011-04 “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS”

In May 2011, the FASB issued ASC Update 2011-04, “Fair Value Measurement (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS.”  ASC Update 2011-04 amends current U.S. GAAP to create more commonality with IFRS by changing some of the wording used to describe requirements for measuring fair value and for disclosing information about fair value measurements.  This update is effective for the first interim or annual reporting period beginning after December 15, 2011.  Chugach began application of ASC 2011-04 on January 1, 2012.  Adoption did not have any incremental effect on results of operations, financial position, and cash flows.

ASC Update 2011-12 “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05”

In December 2011, the FASB issued ASC Update 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05.”  ASC Update 2011-12 defers the effective date of the requirements to present separate line items on the income statement for reclassification adjustments of items out of accumulated other comprehensive income into net income for all periods presented.  This update does not change the other requirements of ASC Update 2011-05.  This update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2011.  Chugach began application of ASC 2011-12 in the period ended March 31, 2012.  Chugach does not have any items included in other comprehensive income.  Therefore, assignable margins and comprehensive income are the same amount and the adoption did not have any effect on results of operations, financial position, and cash flows.

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Deferred Charges And Credits (Schedule Of Regulatory Assets Not Currently Being Recovered In Rates Charged To Consumers) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Regulatory Assets [Line Items]
Total deferred charges	$ 27,712,243	$ 25,205,690
Not Currently Being Recovered In Rates Charged to Consumers [Member]
Regulatory Assets [Line Items]
Total deferred charges	4,519,150	774,322
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Other Regulatory Deferred Charges (Fuel Supply (Negotiations/Studies/Compression)) [Member]
Regulatory Assets [Line Items]
Total deferred charges	1,072,002	0
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Other Regulatory Deferred Charges (Studies / Other) [Member]
Regulatory Assets [Line Items]
Total deferred charges	236,401	578,327
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Other Regulatory Deferred Charges (Wind Project) [Member]
Regulatory Assets [Line Items]
Total deferred charges	391,285	144,866
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Bond Interest - Market Risk Management (Financing Related Costs) [Member]
Regulatory Assets [Line Items]
Total deferred charges	1,757,624	51,129
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Other Regulatory Deferred Charges (Beluga Unit 8 Inspection) [Member]
Regulatory Assets [Line Items]
Total deferred charges	$ 1,061,838	$ 0

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Other Equities (Tables)

12 Months Ended

Dec. 31, 2012

Other Equities [Abstract]

Schedule Of Other Equities

		2012		2011
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		1,647,869		1,621,257
Unclaimed capital credit retirement1		9,700,861		9,713,810
Total other equities	$	11,372,355	$	11,358,692

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

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Deferred Charges And Credits (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Deferred Charges Or Regulatory Assets

		2012		2011
Debt issuance and reacquisition costs	$	4,126,529	$	3,432,665
Refurbishment of transmission equipment		141,976		151,235
Feasibility Studies		76,390		351,727
Beluga Gas Compression		2,035,466		2,544,332
Cooper Lake Relicensing / projects		5,800,417		5,930,520
Fuel supply negotiations		815,451		1,118,439
Major overhaul of steam generating unit		1,510,046		2,265,069
Other regulatory deferred charges		4,473,037		2,126,335
Bond interest - market risk management		7,527,357		6,034,443
Environmental matters and other		1,205,574		1,250,925
Total deferred charges	$	27,712,243	$	25,205,690

Schedule Of Deferred Credits Or Regulatory Liabilities

		2012		2011
Refundable consumer advances for construction	$	777,323	$	727,917
Estimated initial installation costs for meters		92,149		75,660
Post retirement benefit obligation		899,700		899,700
Total deferred costs	$	1,769,172	$	1,703,277

Not Currently Being Recovered In Rates Charged to Consumers [Member]

Schedule Of Deferred Charges Or Regulatory Assets

		2012		2011
Fuel supply (negotiations/studies/compression)	$	1,072,002	$	0
Studies / Other		236,401		578,327
Wind project		391,285		144,866
Financing related costs		1,757,624		51,129
Beluga Unit 8 inspection		1,061,838		0
Total deferred charges	$	4,519,150	$	774,322

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Eklutna Hydroelectric Project (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Jointly Owned Utility Plant Interests [Line Items]
Percentage ownership	70.00%								70.00%
Net utility plant	$ 661,346,913				$ 598,085,816				$ 661,346,913	$ 598,085,816
Net utility plant	661,346,913				598,085,816				661,346,913	598,085,816
Less accumulated depreciation	(493,894,390)				(470,282,210)				(493,894,390)	(470,282,210)
Accumulated depreciation	493,894,390				470,282,210				493,894,390	470,282,210
Total operating expenses	68,250,215	60,200,529	55,725,151	64,019,060	70,143,069	65,509,750	65,592,311	61,096,736	248,194,955	262,341,866	233,967,201
Eklutna Hydroelectric Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage ownership	30.00%								30.00%
Net utility plant	4,725,470				4,880,583				4,725,470	4,880,583
Net utility plant	4,725,470				4,880,583				4,725,470	4,880,583
Less accumulated depreciation	(1,671,335)				(1,491,704)				(1,671,335)	(1,491,704)
Accumulated depreciation	1,671,335				1,491,704				1,671,335	1,491,704
Total operating expenses									$ 682,757	$ 662,035	$ 664,747
Matanuska Electric Association, Inc. [Member] | Eklutna Hydroelectric Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage ownership	16.70%								16.70%
Municipal Light & Power [Member] | Eklutna Hydroelectric Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage ownership	53.30%								53.30%

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Deferred Charges And Credits (Schedule Of Regulatory Liabilities) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 1,769,172	$ 1,703,277
Refundable Consumer Advances For Construction[Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	777,323	727,917
Estimated Initial Installation Costs Of Meters [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	92,149	75,660
Postretirement Benefit Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 899,700	$ 899,700

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Debt (Tables)

12 Months Ended

Dec. 31, 2012

Debt [Abstract]

Schedule Of Long-Term Debt Obligations

Long-term obligations at December 31 are as follows:		2012		2011
CoBank 3 and 4, 2.55% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003	$	31,756,775	$	33,659,141
CoBank 5, 2.55% variable rate notes maturing in 2012, with interest and principal payable monthly		0		791,177
2002 Series A Bond of 6.20%, maturing in 2012, with interest payable semi-annually February 1 and August 1		0		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		85,500,000		90,000,000
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		178,833,333		185,000,000
2012 Series A Bond of 4.01%, maturing in 2032, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2013		75,000,000		0
2012 Series A Bond of 4.41%, maturing in 2042, with interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042		125,000,000		0
2012 Series A Bond of 4.78%, maturing in 2042, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023		50,000,000		0
Total long-term obligations	$	546,090,108	$	429,450,318
Less current installments		24,493,022		133,360,210
Long-term obligations, excluding current installments	$	521,597,086	$	296,090,108

Schedule Of Maturities Of Long-Term Debt Obligations

Year ending December 31		2011 Series A Bonds		CoBank Note		2012 Series A Bonds		Total
2013		10,666,667		2,076,355		11,750,000		24,493,022
2014		10,666,667		2,266,145		11,750,000		24,682,812
2015		10,666,667		2,473,110		10,750,000		23,889,777
2016		10,666,667		2,699,313		10,750,000		24,115,980
2017		10,666,667		2,945,954		10,750,000		24,362,621
Therafter		210,999,998		19,295,898		194,250,000		424,545,896
	$	264,333,333	$	31,756,775	$	250,000,000	$	546,090,108

Schedule Of Average Commercial Paper Balances Outstanding And Weighted Average Interest Rates

Month	Average Balance	Weighted Average Interest Rate	Month	Average Balance	Weighted Average Interest Rate
January	$62.7	0.27	July	$0.0	0.00
February	$0.0	0.00	August	$0.0	0.00
March	$8.0	0.38	September	$4.2	0.34
April	$6.3	0.36	October	$9.3	0.29
May	$0.8	0.35	November	$14.5	0.28
June	$0.0	0.00	December	$11.9	0.29

Schedule Of Carrying Values And Estimated Fair Values Of Long-Term Debt Obligations

	2012				2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term obligations (including current installments)	$	546,090	$	573,912	$	429,450	$	442,711

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2012

Employee Benefit Plans [Abstract]

Schedule Of Information For Significant Pension Plans

	Alaska Electrical Pension Plan3			NRECA Retirement Security Plan3
Employer Identification Number	92-6005171			53-0116145
Plan Number	001			333
Year-end Date	December 31			December 31
Expiration Date of CBA's	June 30,2013			N/A2
Subject to Funding Improvement Plan	No			No
Surcharge Paid	N/A			N/A
	2012	2011	2010	2012	2011	2010
Zone Status	Green	Green	Green	N/A1	N/A1	N/A1
Required minimum contributions	None	None	None	N/A	N/A	N/A
Contributions (in millions)	$3.6	$3.0	$2.9	$3.0	$3.0	$3.1
Contributions > 5% of total plan contributions	Yes	Yes	Yes	No	No	No

¹A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006.  In total, the NRECA RS Plan was between 65 and less than 80 percent funded at January 1, 2012 and 2011, respectively, based on the PPA funding target and PPA actuarial value of assets on those dates.

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

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

⁴The provisions of the PPA do not apply to the RS Plan, therefore, funding improvement plans and surcharges are not applicable.  Future contribution requirements are determined each year as part of the actuarial valuation of the plan and may change as a result of plan experience.

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2012

Significant Accounting Policies [Abstract]

Significant Accounting Policies

(2)    Significant Accounting Policies

a. Management Estimates

In preparing the financial statements in conformity with generally accepted accounting principles, the 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 and our rates, see Note (2j) – “Deferred Charges and Credits.”

(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	-	12/31/12
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%

In 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.

(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 4.0percent during 2012, 4.1 percent during 2011 and 4.8 percent during 2010.  Chugach capitalized actual interest expense and related fees associated with the construction of Southcentral Power Plant (SPP).

e. Investments in Associated Organizations

The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) requires 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 2012, 2011 and 2010.

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 (see 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.

(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 $10.0 million, which was subsequently invested in marketable securities in September of 2012.  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 of $8,942,631 and $6,481,639 for the years ended December 31, 2012 and 2011, respectively.  The Overnight Repurchase Agreement account had an average balance in 2012 and 2011 of $100 and $5,210,009, at an average interest rate of 0.00 percent and 0.06 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 used the proceeds primarily to fund capital expenditures associated with SPP and closed the account in February of 2013.

Restricted cash equivalents include State of Alaska construction bonds and funds on deposit for future workers compensation claims.  In 2011, restricted cash equivalents included $120.0 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.

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 receivable are invoiced amounts to ML&P for fuel and their proportionate share of current SPP costs, which amounted to $3.0and $4.8 million in 2012 and 2011, respectively.  In addition, accounts receivable includes an invoiced amount to the Alaska Energy Authority (AEA) for reimbursable expenditures related to a grant for the Cook Inlet Gas Gathering System (CIGGS) project, which amounted to $4.0 million in 2012.

(2)    Significant Accounting Policies (continued)

i. Materials and Supplies

Materials and supplies are stated at average cost.

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 (Board).  Retained assignable margins are designated on Chugach's balance sheet as patronage capital.  This patronage capital constitutes the principal equity of Chugach.  The Board 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, 2014.  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 $6.9million at December 31, 2012.

(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 $8,548,660and $8,977,409 of unbilled retail revenue at December 31, 2012 and 2011, 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 adjustment process, which is adjusted quarterly to reflect increases and decreases of such costs.  We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates.  The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under or over collection of fuel and purchase power costs.  Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods.  Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods.  Fuel costs were over-recovered by $13,710,049 in 2012 and under-recovered by $1,213,484 in 2011.  Total fuel and purchased power costs in 2012, 2011, and 2010 were $147,941,346, $165,041,227, and $138,410,915, 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, 2012, 2011 and 2010 was in compliance with that provision.  In addition, as described in “Note (15) - Commitments and Contingencies,” 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.”

(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, 2009 through December 31, 2012 for U.S. Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2012.

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, 2012 and 2011, totaled $2.4 million and $2.2 million, respectively.  Consumer deposits also represent customer credit balances as a result of prepaid accounts.  Credit balances for the years ended December 31, 2012 and 2011 totaled $1.9 million and $1.7 million, respectively.

q. Grants

Chugach has received federal and state grants to offset storm related expenditures and 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 while grant proceeds for storm related expenditures are offset against the actual expense incurred, which totaled $30.5million and $4.3 million in 2012 and 2011, respectively.  The assets constructed from grant awards may not be sold, or used as collateral for any reason.

r. Fuel Stock

Fuel Stock is the weighted average cost of fuel injected into the Cook Inlet Natural Gas Storage Alaska (CINGSA), which began service in the second quarter of 2012.  Limited withdrawals of gas began in the third quarter of 2012.  Chugach’s fuel balance in storage amounted to $9.5million for the year ended December 31, 2012.

s. Marketable Securities

In September of 2012, Chugach implemented a bond and equity investment portfolio. Chugach’s initial investment was $10.0 million.  The investments are classified as marketable securities, reported at fair value with gains and losses included in earnings.  At December  31, 2012, the carrying amount and fair value was $10.1million.

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Bradley Lake Hydroelectric Project (Tables)

12 Months Ended

Dec. 31, 2012

Bradley Lake Hydroelectric Project [Abstract]

Bradley Lake Project Financials

(In thousands)	Total	Proportionate Share
Plant in service	$181,587	$55,202
Long-term debt	87,607	26,633
Interest expense	5,032	1,530

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Utility Plant (Schedule Of Major Classes Of Utilty Plant) (Details) (USD $)	Dec. 31, 2012		Dec. 31, 2011
Public Utility, Property, Plant and Equipment [Line Items]
Total electric plant in service	$ 891,781,509		$ 862,362,243
Construction work in progress	263,459,794	[1]	206,005,783	[1]
Total utility plant	1,155,241,303		1,068,368,026
Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing	60,462,671		60,462,671
Hydraulic Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing	20,513,746		20,456,395
Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing	127,980,607		134,434,574
Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	252,910,740		252,561,598
Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution	257,587,220		257,341,532
General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment	51,901,426		45,144,425
Unclassified Electric Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment	109,023,464	[2]	80,559,413	[2]
Intangible Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	4,710,912	[2]	4,710,912	[2]
Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other- land	6,690,723		6,690,723
Southcentral Power Project [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Construction work in progress	$ 245,500,000		$ 177,400,000

[1] The amount associated with the construction of SPP included in construction work in progress was $245.5 million and $177.4 million at December 31, 2012 and 2011, respectively.

[2] 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

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Employee Benefit Plans (Schedule Of Information For Significant Pension Plans) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010
Alaska Electrical Pension Plan [Member]
Multiemployer Plans [Line Items]
Employer Identification Number	926005171	[1]
Plan Number	001	[1]
Year-end Date	December 31	[1]
Expiration Date of CBA's	Jun. 30, 2013	[1]
Subject to Funding Improvement Plan	No	[1]
Surcharge Paid	NA	[1]
Zone Status	Green		Green	Green
Required minimum contributions	None		None	None
Contributions (in millions)	$ 3.6		$ 3.0	$ 2.9
Contributions > 5% of total plan contributions	Yes		Yes	Yes
NRECA Retirement Security Plan [Member]
Multiemployer Plans [Line Items]
Employer Identification Number	530116145	[1]
Plan Number	333	[1]
Year-end Date	December 31	[1]
Subject to Funding Improvement Plan	No
Surcharge Paid	NA
Zone Status	NA	[2]	NA	NA
Required minimum contributions	N/A		N/A	N/A
Contributions (in millions)	$ 3.0		$ 3.0	$ 3.1
Contributions > 5% of total plan contributions	No		No	No
Fund status	Between 65 and less than 80 percent

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

[2] A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006. In total, the NRECA RS Plan was between 65 and less than 80 percent funded at January 1, 2012 and 2011, respectively, based on the PPA funding target and PPA actuarial value of assets on those dates.

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Balance Sheets (USD $)	Dec. 31, 2012		Dec. 31, 2011
Assets
Electric plant in service	$ 891,781,509		$ 862,362,243
Construction work in progress	263,459,794	[1]	206,005,783	[1]
Total utility plant	1,155,241,303		1,068,368,026
Less accumulated depreciation	(493,894,390)		(470,282,210)
Net utility plant	661,346,913		598,085,816
Other property and investments, at cost:
Nonutility property	84,735		84,735
Investments in associated organizations	10,552,683		11,134,496
Special funds	570,027		420,783
Total other property and investments	11,207,445		11,640,014
Current assets:
Cash and cash equivalents, including repurchase agreements of $100 in 2012 and $100 in 2011	14,047,469		17,118,118
Special deposits	153,233		149,701
Restricted cash equivalents	1,953,085		122,006,738
Marketable securities	10,158,016		0
Fuel cost under-recovery	0		1,213,484
Accounts receivable, less provision for doubtful accounts of $490,413 in 2012 and $408,429 in 2011	46,650,901		42,373,995
Materials and supplies	32,867,971		32,994,454
Fuel stock	9,466,767		0
Prepayments	2,156,862		1,911,789
Other current assets	252,146		229,858
Total current assets	117,706,450		217,998,137
Deferred charges, net	27,712,243		25,205,690
Total assets	817,973,051		852,929,657
Equities and Margins
Memberships	1,559,344		1,517,488
Patronage capital	153,832,674		148,355,246
Other	11,372,355		11,358,692
Total equities and margins	166,764,373		161,231,426
Long-term obligations, excluding current installments :
Bonds payable	491,916,666		264,333,333
National Bank for Cooperatives note payable	29,680,420		31,756,775
Total long-term obligations, excluding current installments	521,597,086		296,090,108
Current liabilities:
Current installments of long-term obligations	24,493,022		133,360,210
Commercial paper	11,500,000		175,000,000
Accounts payable	16,488,323		22,800,190
Consumer deposits	4,279,901		3,949,052
Fuel cost over-recovery	13,710,049		0
Accrued interest	6,807,207		6,843,473
Salaries, wages and benefits	8,369,203		7,597,691
Fuel	20,868,078		24,399,157
Other current liabilities	4,559,981		3,350,692
Total current liabilities	111,075,764		377,300,465
Deferred compensation	570,027		420,783
Deferred liabilities	1,769,172		1,703,277
Patronage capital payable	6,858,367		6,646,068
Deferred proceeds on sale of asset	9,338,262		9,537,530
Total liabilities, equities and margins	$ 817,973,051		$ 852,929,657

[1] The amount associated with the construction of SPP included in construction work in progress was $245.5 million and $177.4 million at December 31, 2012 and 2011, respectively.

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Patronage Capital (Details) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Patronage capital	$ 153,832,674	$ 148,355,246
Patronage capital payable	6,858,367	6,646,068
Patronage capital assigned	148,307,167
Patronage capital to be assigned to members	5,525,507
Retirement of capital credits	48,079	6,761,968	94,278
Excluding Homer Electric Association Retirement [Member]
Retirement of capital credits	48,079	309,188	94,278
Assignable Margins [Member]
Percentage of assignable margins distributed to members	50.00%
Patronage Capital Distribution [Member]
Secured debt covenant restriction	5.00%
Homer Electric Association, Inc. [Member]
Patronage capital	6,900,000	6,600,000	6,500,000
Patronage capital payable	$ 6,900,000	$ 6,600,000
Minimum [Member]
Percentage of aggregate equities and margins to total liabilities and equities and margins	30.00%

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Statements Of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Cash flows from operating activities:
Assignable margins	$ 5,525,507	$ 5,573,262	$ 5,410,009
Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation	32,356,900	32,616,175	32,636,108
Amortization and depreciation cleared to operating expenses	5,882,580	5,472,557	5,457,480
Allowance for funds used during construction	(258,301)	(159,916)	(83,966)
Loss on disposal of assets	991,871	851,756	210,596
Other	(135,739)	(93,834)	74,726
(Increase) decrease in assets:
Accounts receivable, net	(4,276,906)	(7,128,876)	670,424
Fuel cost under-recovery	1,213,484	1,158,147	(2,093,467)
Materials and supplies	(189,092)	2,563,223	(6,061,005)
Fuel stock	(9,466,767)	0	0
Prepayments	(245,073)	13,635	(663,527)
Other assets	27,937	(2,049,082)	(96,522)
Deferred charges	(4,335,252)	(6,358,154)	(1,511,639)
Increase (decrease) in liabilities:
Accounts payable	1,454,677	1,891,089	(1,321,046)
Consumer deposits	330,849	(1,276,677)	(267,221)
Fuel cost over-recovery	13,710,049	0	(3,511,422)
Accrued interest	(36,266)	793,942	(18,099)
Salaries, wages and benefits	771,512	863,849	777,522
Fuel	(3,531,079)	2,829,619	6,911,480
Other current liabilities	3,094,139	3,011,319	2,701,345
Deferred liabilities	120,204	239,761	(70,335)
Net cash provided by operating activities	43,005,234	40,811,795	39,151,441
Cash flows from investing activities:
Proceeds on sale of Bernice Lake Power Plant	0	9,537,530	0
Investment in associated organizations	663,697	1,153,470	311,593
Investment in restricted cash equivalents	0	(270,000,000)	0
Investment in marketable securities	(10,096,304)	0	0
Proceeds from restricted cash equivalents	120,000,000	150,000,000	0
Extension and replacement of plant	(109,180,413)	(123,679,854)	(73,214,825)
Net cash provided by (used in) investing activities	1,386,980	(232,988,854)	(72,903,232)
Cash flows from financing activities:
Payments for debt issue costs	(1,850,199)	(1,949,027)	(1,493,572)
Proceeds from short-term obligations	24,500,000	76,500,000	47,000,000
Proceeds from long-term obligations	250,000,000	275,000,000	0
Repayments of short-term obligations	(188,000,000)	0	0
Repayments of long-term obligations	(133,360,210)	(152,851,500)	(4,118,029)
Memberships and donations received	55,519	189,385	205,956
Retirement of patronage capital and estate payments	(48,079)	(309,188)	(146,596)
Net receipts on consumer advances for construction	1,240,106	644,794	870,980
Net cash (used in) provided by financing activities	(47,462,863)	197,224,464	42,318,739
Net change in cash and cash equivalents	(3,070,649)	5,047,405	8,566,948
Cash and cash equivalents at beginning of period	17,118,118	12,070,713	3,503,765
Cash and cash equivalents at end of period	14,047,469	17,118,118	12,070,713
Supplemental disclosure of non-cash investing and financing activities:
Retirement of plant	10,405,777	11,317,319	6,666,875
Extension and replacement of plant included in accounts payable	10,620,219	15,561,199	15,919,688
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized	$ 13,092,576	$ 12,590,296	$ 18,057,000

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Quarterly Results Of Operations (Unaudited) (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statements Of Operations [Abstract]
Operating revenues	$ 74,483,455	$ 62,675,511	$ 58,631,729	$ 71,180,773	$ 76,828,268	$ 68,778,352	$ 68,517,526	$ 69,494,223	$ 266,971,468	$ 283,618,369	$ 258,325,345
Total operating expenses	68,250,215	60,200,529	55,725,151	64,019,060	70,143,069	65,509,750	65,592,311	61,096,736	248,194,955	262,341,866	233,967,201
Net interest	3,492,044	3,495,865	3,542,676	3,872,346	4,102,750	3,544,204	4,209,482	4,890,541	14,402,931	16,746,977	20,005,698
Net operating margins	2,741,196	(1,020,883)	(636,098)	3,289,367	2,582,449	(275,602)	(1,284,267)	3,506,946	4,373,582	4,529,526	4,352,446
Nonoperating margins	632,775	261,487	123,962	133,701	628,697	161,595	120,363	133,081	1,151,925	1,043,736	1,057,563
Assignable margins	$ 3,373,971	$ (759,396)	$ (512,136)	$ 3,423,068	$ 3,211,146	$ (114,007)	$ (1,163,904)	$ 3,640,027	$ 5,525,507	$ 5,573,262	$ 5,410,009

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Description Of Business (Details)	12 Months Ended
	Dec. 31, 2012 customer mi
Description Of Business [Abstract]
Electrification area	400
Number of wholesale customers	3

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Quarterly Results Of Operations (Unaudited)

12 Months Ended

Dec. 31, 2012

Quarterly Results Of Operations (Unaudited) [Abstract]

Quarterly Results Of Operations (Unaudited)

(16)  Quarterly Results of Operations (unaudited)

2012 Quarter Ended

		Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	74,483,455	$	62,675,511	$	58,631,729	$	71,180,773
Operating Expense		68,250,215		60,200,529		55,725,151		64,019,060
Net Interest		3,492,044		3,495,865		3,542,676		3,872,346
Net Operating Margins		2,741,196		(1,020,883)		(636,098)		3,289,367
Nonoperating Margins		632,775		261,487		123,962		133,701
Assignable Margins	$	3,373,971	$	(759,396)	$	(512,136)	$	3,423,068

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

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Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended				1 Months Ended						12 Months Ended			12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2012	Feb. 29, 2012 2002 Series A Bond of 6.2% Maturing 2012 [Member]	Dec. 31, 2012 Unbilled Retail Revenues [Member]	Dec. 31, 2011 Unbilled Retail Revenues [Member]	Dec. 31, 2012 ML&P For Fuel and South Central Power Project Costs [Member]	Dec. 31, 2011 ML&P For Fuel and South Central Power Project Costs [Member]	Dec. 31, 2012 Alaska Energy Authority For Grant [Member]	Dec. 31, 2012 Homer Electric Association, Inc. [Member]	Dec. 31, 2011 Homer Electric Association, Inc. [Member]	Dec. 30, 2011 UBS Financial Services [Member]	Dec. 31, 2012 Concentration Account [Member]	Dec. 31, 2011 Concentration Account [Member]	Dec. 31, 2012 Overnight Repurchase Agreement Account [Member]	Dec. 31, 2011 Overnight Repurchase Agreement Account [Member]	Jan. 12, 2012 Key Bank [Member]
Weighted average capital interest percentage	4.00%	4.10%	4.80%
Money market account	$ 2,829,397	$ 10,000,000											$ 10.0					$ 69,000,000
Average balance of cash account														8,942,631	6,481,639	100	5,210,009
Average interest rate of cash																0.00%	0.06%
Proceeds from issuance of long-term debt obligations					120,000,000
Number of years to return patronage capital after expiration of power agreement											5 years
Patronage capital payable	6,858,367	6,646,068									6,900,000	6,600,000
Minimum number of days past balances reviewed	90 days
Accounts receivable	46,650,901	42,373,995				8,548,660	8,977,409	3,000,000	4,800,000	4,000,000
Fuel cost over-recovery	13,710,049	0
Fuel cost under-recovery	0	1,213,484
Fuel and purchased power costs	147,941,346	165,041,227	138,410,915
Consumer deposits	2,400,000	2,200,000
Customer credits	1,900,000	1,700,000
Grant proceeds included in public utilities property plant and equipment carry value	30,500,000	4,300,000
Fuel stock	9,466,767	0
Marketable securities	$ 10,158,016	$ 0		$ 10,000,000

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2012

Significant Accounting Policies [Abstract]

Schedule Of Depreciation And Amortization Rates

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

XML

Description Of Business

12 Months Ended

Dec. 31, 2012

Description Of Business [Abstract]

Description Of Business

(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).  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).  Chugach’s retail and wholesale members are the consumers of the electricity sold.

Chugach was organized as an Alaska electric cooperative in 1948 and 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).

XML

Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Balance Sheets [Abstract]
Cash and cash equivalent, repurchase agreements	$ 100	$ 100
Provision for doubtful accounts	$ 490,413	$ 408,429

XML

Debt

1 Months Ended

Dec. 31, 2012

Debt [Abstract]

Debt

(11)  Debt

Long-term obligations at December 31 are as follows:		2012		2011
CoBank 3 and 4, 2.55% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003	$	31,756,775	$	33,659,141
CoBank 5, 2.55% variable rate notes maturing in 2012, with interest and principal payable monthly		0		791,177
2002 Series A Bond of 6.20%, maturing in 2012, with interest payable semi-annually February 1 and August 1		0		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		85,500,000		90,000,000
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		178,833,333		185,000,000
2012 Series A Bond of 4.01%, maturing in 2032, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2013		75,000,000		0
2012 Series A Bond of 4.41%, maturing in 2042, with interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042		125,000,000		0
2012 Series A Bond of 4.78%, maturing in 2042, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023		50,000,000		0
Total long-term obligations	$	546,090,108	$	429,450,318
Less current installments		24,493,022		133,360,210
Long-term obligations, excluding current installments	$	521,597,086	$	296,090,108

(11)  Debt (continued)

Covenants

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.

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, KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank, ACB and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch dated November 17, 2010, and updated June 29, 2012, governing loans and extensions of credit associated with Chugach’s commercial paper program, in an aggregate principal amount not exceeding $100.0 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. 

Security

The Second Amended and Restated Indenture of Trust (the Indenture), which became effective on January 20, 2011, imposes 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.

(11)  Debt (continued)

Rates

The Second Amended and Restated Indenture of Trust 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.

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 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 Second Amended and Restated Indenture of Trust and the CoBank Amended and Restated Master Loan Agreement 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.

(11)  Debt (continued)

Maturities of Long‑term Obligations

Long-term obligations at December 31, 2012, mature as follows:

Year ending December 31		2011 Series A Bonds		CoBank Note		2012 Series A Bonds		Total
2013		10,666,667		2,076,355		11,750,000		24,493,022
2014		10,666,667		2,266,145		11,750,000		24,682,812
2015		10,666,667		2,473,110		10,750,000		23,889,777
2016		10,666,667		2,699,313		10,750,000		24,115,980
2017		10,666,667		2,945,954		10,750,000		24,362,621
Therafter		210,999,998		19,295,898		194,250,000		424,545,896
	$	264,333,333	$	31,756,775	$	250,000,000	$	546,090,108

Lines of credit

Chugach maintains a $50.0 million line of credit with National Rural Utilities Cooperative Finance Corporation (NRUCFC).  Chugach did not utilize this line of credit in 2012, and therefore had no outstanding balance at December 31, 2012.  In addition, Chugach did not utilize this line of credit during 2011 and had no outstanding balance at December 31, 2011.  The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC.  At December 31, 2012, and December 31, 2011, the borrowing rate was 2.90 percent and 3.20 percent, 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. 

On September 26, 2012, the Board approved a resolution to renew this line of credit under substantially the same terms as the previous agreement.  The NRUCFC line of credit now expires October 12, 2017.

This line of credit is immediately available for unconditional borrowing.

(11)  Debt (continued)

Commercial Paper

On November 17, 2010, Chugach entered into a $300.0 million Unsecured Credit Agreement,which is used to back Chugach’s Commercial Paper program.  The participating banks were 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.  Effective May 4, 2012, Chugach reduced the commitment amount to $100.0 million and on June 29, 2012, amended and extended the Credit Agreement to update the pricing and extend the term.  The new pricing includes an all-in drawn spread of one month London Interbank Offered Rate (LIBOR) plus 107.5 basis points, along with a 17.5 basis points facility fee (based on an A-/A3 unsecured debt rating).  The Amended Unsecured Credit Agreement now expires on November 17, 2016.  The participating banks include NRUCFC, KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank, ACB and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch.  Our commercial paper can be repriced between one day and two hundred seventy days.  Chugach is expected to continue to issue commercial paper in 2013, as needed, however, the requirement for short-term borrowing has decreased.

Chugach had $11.5million and $175.0 million of commercial paper outstanding at December 31, 2012 and 2011, respectively. 

The following table provides information regarding 2012 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	$62.7	0.27	July	$0.0	0.00
February	$0.0	0.00	August	$0.0	0.00
March	$8.0	0.38	September	$4.2	0.34
April	$6.3	0.36	October	$9.3	0.29
May	$0.8	0.35	November	$14.5	0.28
June	$0.0	0.00	December	$11.9	0.29

(11)  Debt (continued)

Financing

On January 11, 2012, Chugach issued $75.0 million of First Mortgage Bonds, 2012 Series A, due March 15, 2032 (Tranche A), $125.0 million of First Mortgage Bonds, 2012 Series A, due March 15, 2042 (Tranche B) and $50.0 million of First Mortgage Bonds, 2012 Series A, due March 15, 2042 (Tranche C), for the purpose of repaying outstanding commercial paper used to finance 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 percent per annum.  The 2012 Series A Bonds (Tranche B) will mature on March 15, 2042, and will bear interest at 4.41 percent per annum.  The 2012 Series A Bonds (Tranche C) will mature on March 15, 2042, and will bear interest at 4.78 percent 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.

On January 21, 2011, Chugach issued $90.0 million of First Mortgage Bonds, 2011 Series A, due March 15, 2031 and $185.0 million 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 percent 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 percent 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 has a term loan facility with CoBank.  Loans made under this facility are evidenced by the 2011 CoBank Note, which is governed by the Amended and Restated Master Loan Agreement dated January 19, 2011and secured by the Second Amended and Restated Indenture. 

(11)  Debt (continued)

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:

	2012				2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term obligations (including current installments)	$	546,090	$	573,912	$	429,450	$	442,711

XML

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2012
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Entity Registrant Name	CHUGACH ELECTRIC ASSOCIATION INC
Entity Central Index Key	0000878004
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	0
Entity Public Float	$ 0
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Voluntary Filers	Yes

XML

Employee Benefit Plans

12 Months Ended

Dec. 31, 2012

Employee Benefit Plans [Abstract]

Employee Benefit Plans

(12)  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. 

Pension benefits for non-union employees are provided by the National Rural Electric Cooperative Association (NRECA) Retirement and Security Plan (RS Plan).  The RS Plan is a defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the Internal Revenue Code.  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, 2012, 2011 and 2010 of $6.6million, $6.0 million and $6.0 million, respectively.  The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2012, 2011 and 2010.  The following table provides information regarding pension plans which Chugach considers individually significant:

(12)  Employee Benefit Plans (continued)

Pension Plans (continued)

	Alaska Electrical Pension Plan3			NRECA Retirement Security Plan3
Employer Identification Number	92-6005171			53-0116145
Plan Number	001			333
Year-end Date	December 31			December 31
Expiration Date of CBA's	June 30,2013			N/A2
Subject to Funding Improvement Plan	No			No
Surcharge Paid	N/A			N/A
	2012	2011	2010	2012	2011	2010
Zone Status	Green	Green	Green	N/A1	N/A1	N/A1
Required minimum contributions	None	None	None	N/A	N/A	N/A
Contributions (in millions)	$3.6	$3.0	$2.9	$3.0	$3.0	$3.1
Contributions > 5% of total plan contributions	Yes	Yes	Yes	No	No	No

¹A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006.  In total, the NRECA RS Plan was between 65 and less than 80 percent funded at January 1, 2012 and 2011, respectively, based on the PPA funding target and PPA actuarial value of assets on those dates.

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

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

⁴The provisions of the PPA do not apply to the RS Plan, therefore, funding improvement plans and surcharges are not applicable.  Future contribution requirements are determined each year as part of the actuarial valuation of the plan and may change as a result of plan experience.

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, 2012, 2011, and 2010 were $4.3million, $3.7 million, and $3.7 million, respectively.

Chugach participates in a multi-employer plan through the Group Benefits Program of NRECA for non-union employees.  Amounts charged to benefit cost and contributed to this Plan for those benefits for the years ended December 31, 2012, 2011, and 2010 totaled $2.5million, $2.4 million, and $2.2 million respectively.

(12)  Employee Benefit Plans (continued)

Money Purchase Pension Plan

Chugach participates in a multi-employer defined contribution money purchase pension plan covering some employees who are covered by a collective bargaining agreement.  Contributions to the Plan are made based on a percentage of each employee’s compensation.  Contributions to the money purchase pension plan for the years ending December 31, 2012, 2011, and 2010 were $141.0thousand, $128.7 thousand, and $124.1 thousand, respectively.

401(k) Plan

Chugach has a defined contribution 401(k) retirement plan which covers substantially all employees who, effective January 1, 2008, can participate immediately.  Employees who elect to participate may contribute up to the Internal Revenue Service’s maximum of $17,000,  $16,500, and $16,500 in 2012, 2011, and 2010 respectively, and allowed catch-up contributions for those over 50 years of age of $5,500, $5,500, and $5,500 in 2012, 2011, and 2010, 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, 2012, 2011 and 2010 was $570,027, $420,783 and $395,833, respectively.

Potential Termination Payments

Pursuant to a Chugach Operating Policy, non-represented employees, including the executive officers except the Chief Executive Officer, who are terminated by Chugach for reasons unrelated to employee performance are entitled to severance pay for each year or partial year of service as follows:  two weeks for each year of service to a maximum of twenty-six (26) weeks for thirteen (13) years or more of service. 

XML

Statements Of Operations (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Statements Of Operations [Abstract]
Operating revenues	$ 266,971,468	$ 283,618,369	$ 258,325,345
Operating expenses:
Fuel	125,836,659	139,179,413	111,718,947
Production	16,739,931	16,853,232	18,248,656
Purchased power	22,104,687	25,861,814	26,691,968
Transmission	5,802,009	6,809,401	5,697,446
Distribution	15,822,104	13,387,477	12,216,252
Consumer accounts	6,013,419	5,465,315	5,323,551
Administrative, general and other	23,519,246	22,169,039	21,434,273
Depreciation and amortization	32,356,900	32,616,175	32,636,108
Total operating expenses	248,194,955	262,341,866	233,967,201
Interest expense:
Long-term debt and other	24,085,371	18,681,680	21,014,387
Charged to construction	(9,682,440)	(1,934,703)	(1,008,689)
Interest expense, net	14,402,931	16,746,977	20,005,698
Net operating margins	4,373,582	4,529,526	4,352,446
Nonoperating margins:
Interest income	447,434	297,983	310,964
Allowance for funds used during construction	258,301	159,916	83,966
Capital credits, patronage dividends and other	446,190	585,837	662,633
Total nonoperating margins	1,151,925	1,043,736	1,057,563
Assignable margins	$ 5,525,507	$ 5,573,262	$ 5,410,009

XML

Utility Plant

12 Months Ended

Dec. 31, 2012

Utility Plant [Abstract]

Utility Plant

(6)Utility Plant

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

Electric plant in service:		2012		2011
Steam production plant	$	60,462,671	$	60,462,671
Hydraulic production plant		20,513,746		20,456,395
Other production plant		127,980,607		134,434,574
Transmission plant		252,910,740		252,561,598
Distribution plant		257,587,220		257,341,532
General plant		51,901,426		45,144,425
Unclassified electric plant in service1		109,023,464		80,559,413
Intangible plant1		4,710,912		4,710,912
Other1		6,690,723		6,690,723
Total electric plant in service		891,781,509		862,362,243
Construction work in progress2		263,459,794		206,005,783
Total electric plant in service and construction work in progress	$	1,155,241,303	$	1,068,368,026

¹Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant.  Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment.  Intangible plant represents Chugach's share of a Bradley Lake transmission line financed internally.  Other represents Electric Plant Held for Future Use.

²The amount associated with the construction of SPP included in construction work in progress was $245.5million and $177.4 million at December 31, 2012 and 2011, respectively.

XML

Regulatory Matters

12 Months Ended

Dec. 31, 2012

Regulatory Matters [Abstract]

Regulatory Matters

(5)    Regulatory Matters

Modification to Certificate of Public Convenience and Necessity

On May 29, 2012, Chugach submitted a request to amend its service area contained within its certificate of public convenience and necessity to include Fire Island and the City of Whittier, and to adjust the service area boundary between Chugach and the City of Seward, d/b/a Seward Electric

System in the Moose Pass area where both utilities are currently authorized to provide electric service.  Chugach also requested that its service area be modified to include the areas of expansion in which electric service is currently being provided but are not described in Chugach’s certificate, and to include other service areas where potential future customer requests for electric service can be reasonably expected.  Chugach also proposed that several sections of its certificate be removed as these areas are well outside of any reasonable likelihood of service requests.  On July 9, 2012, the City of Seward submitted comments in support of resolving the boundary area overlap between Chugach and Seward.  Seward did not oppose the service area changes proposed by Chugach.  A hearing was held on September 4, 2012, in which Chugach made a presentation on the proposed modifications to its service territory and responded to questions from the RCA.  On January 25, 2013, the RCA approved Chugach’s request.

Petition to Establish Depreciation Rates for SPP

Chugach submitted proposed depreciation rates for SPP on February 22, 2012, with a recommended 35 year life for the project.  The filing also included depreciation rates for transmission plant specific to the project with a recommended life consistent with the depreciation rates of Chugach’s existing transmission assets.  The RCA opened Docket U-12-009 on March 2, 2012, to adjudicate the case.  Petitions to intervene were received from the Attorney General (AG), HEA and MEA.  No responsive testimony was received from any of the parties.  A hearing was held on July 2, 2012.  On August 31, 2012, the RCA issued an order in the case, approving depreciation rates for SPP with an effective date equal to its in-service date, requested filing requirements and closed the docket.

Seward Power Sales Agreement

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.

(5)    Regulatory Matters (continued)

Fire Island Wind Project

On October 10, 2011, the RCA issued an order approving Chugach’s request for assurance of cost recovery associated with 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.  The PPA is a 25-year agreement whereby Chugach purchases the output of the facility commencing January 1, 2013.  The Fire Island Wind project is comprised of eleven1.6- megawatt wind turbine generators with a total nameplate capacity of 17.6 megawatts which are expected to generate approximately 50,000 megawatt hours (MWh) per year.  The generators are located on the southern part of Fire Island, three miles west of Anchorage, Alaska.  Chugach began receiving power from the project on August 17, 2012.  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 approximately $25.0 million appropriated from the State of Alaska.  The grant was used to offset construction of the transmission line.  Construction expenditures applied against the grant were $20.3million in 2012 and $3.2 million in 2011.  Chugach is not expected to incur any unreimbursed capital costs associated with this line and will acquire the line once construction is successfully completed. 

Chugach submitted a specific rate recovery plan in compliance with U-11-100(5) on April 2, 2012, and project status reports on June 30, 2012 and October 31, 2012.  The rate recovery plan addressed customer intergenerational impacts resulting from purchases made under the PPA’s fixed pricing structure.  The RCA held a hearing on June 5, 2012, for Chugach to supplement its filing with an oral presentation explaining the rate impacts and equities to ratepayers.  As a result of the hearing, Chugach submitted an updated rate recovery proposal on July 31, 2012, requesting that purchases made under the PPA be recovered on a direct cost basis for recovery through the fuel and purchased power surcharge process.  Chugach withdrew its April 2, 2012, compliance filing. 

On September 28, 2012, the RCA opened Docket U-12-134 and issued an order granting Chugach interim approval of its cost disclosure and rate recovery proposals relating to the Fire Island wind project and invited participation from the Attorney General (AG).  Chugach and the AG stipulated on key matters of the filing and requested RCA approval in a stipulation submitted to the RCA on November 15, 2012.  The RCA held a hearing on January 17, 2013, to review the stipulation, with participation from both Chugach and the AG.  On February 12, 2013, the RCA issued Order No. 3 of Docket U-12-134 accepting the stipulation.

(5)    Regulatory Matters (continued)

Regulatory Assets

Storm Expenditures

On November 8, 2012, Chugach submitted a petition to the RCA requesting authorization to create a regulatory asset for deferred recovery of expenditures associated with extensive storm damage that occurred in September of 2012.  Repeated windstorms were followed by considerable amounts of rain, resulting in outages and flooding, primarily caused by falling and uprooted trees.  Chugach requested approval to recover in future electric rates over a twelve month period approximately $1.8 million of costs.  On November 19, 2012, the RCA opened Docket U-12-144, designated a commission panel and appointed an administrative law judge.  The AG submitted comments on December 14, 2012, opposing Chugach’s request.  The RCA held a hearing on January 14, 2013.  On January 30, 2013, the RCA issued Order No. 3 of Docket U-12-144 and did not accept Chugach’s request, however, the RCA provided Chugach the opportunity to augment the record and re-submit its petition at a later time.  Chugach is evaluating the option of supplementing the record and re-submitting its request.

Interest and Financing Costs

On January 11, 2012, Chugach issued $75.0 million of First Mortgage Bonds (2012 Series A, Tranche A) at an interest rate of 4.01 percent, $125.0 million of First Mortgage Bonds (2012 Series A, Tranche B) at an interest rate of 4.41 percent and $50.0 million of First Mortgage Bonds (2012

Series A, Tranche C) at an interest rate of 4.78 percent.  The proceeds of the 2012 Series A Bonds were used to repay outstanding commercial paper and to finance SPP construction. 

On March 12, 2012, Chugach submitted a petition to the RCA requesting authorization to create a regulatory asset for deferred recovery of interim interest expense associated with SPP financing and also requested approval to recover the financing transaction costs in future electric rates over the life of the 2012 Series A Bonds.  Chugach’s request included the approval to defer the interest expense on the portion of the proceeds not immediately expended on SPP and recover it in future electric rates over the life of the bonds, or between 20 and 30 years.  The deferral of interest for the portion of the 2012 bonds not immediately expended totaled approximately $1.1 million.  The RCA opened Docket U-12-015 on March 21, 2012.  On May 22, 2012, Chugach and the AG of the State of Alaska submitted a stipulation whereby the AG did not oppose the regulatory and accounting treatment requested by Chugach.  On June 19, 2012, the RCA issued Order No. 2 accepting the stipulation and closing the docket.

(5)    Regulatory Matters (continued)

2012 General Rate Case

In anticipation of commercial operation of SPP, on December 21, 2012, Chugach submitted a general rate case with the RCA to increase system base rate revenues by $30.0 million, or approximately 26 percent on total base rate revenues of $115.0 million.  Chugach requested that the proposed rates become effective on an interim and refundable basis beginning in February of 2013.  In addition to the base rate increases, the filing requests approval to update and expand Chugach’s operating tariff to include both firm and non-firm transmission wheeling service and attendant ancillary services in support of third-party transactions on the Chugach system.  The expansion of the tariff was made, in part, to accommodate wheeling services in anticipation of the expiration of the HEA and MEA wholesale customer contracts in 2014.  Because of efficiency improvements associated with the commercial operation of SPP, Chugach also submitted a request in a separate filing to the RCA to adjust its fuel rates effective at the same time as the requested base rate increases contained in the general rate case filing.  This allows the interim base rate increases to be synchronized with expected reductions in fuel costs reflected in Chugach’s fuel rates. 

On February 1, 2013, Chugach submitted a supplemental filing to the RCA removing the impacts associated with a one-year amortization of distribution storm-related costs (see discussion on Storm Expenditures above) from its retail revenue requirement.  On February 6, 2013, the Commission opened Docket U-13-007 and issued Order No. 1 approving Chugach’s supplemental filing for rates effective February 6, 2013 on an interim and refundable basis.  In addition, the Commission also approved Chugach’s request to assess transmission wheeling charges on economy energy transactions that originate from the Chugach system.

In total, when factoring both base rate increases and reductions in fuel costs, the net increase to Chugach retail end-users is approximately 6 percent, while the net increase to retail end-users of Chugach’s wholesale customers is approximately 4 percent to 7 percent.

Removal of Margin Cap on Economy Energy Sales

On October 31, 2012, Chugach submitted a request to the RCA for approval to remove the current eight mill margin cap on economy energy transactions but retain the requirement that such transactions must fall between Chugach’s incremental and the purchasing utility’s decremental cost of generation.  The RCA approved the filing on January 24, 2013.  The expected impact of the approval, in combination with the Chugach-GVEA sales arrangement, is additional system margin contributions in excess of $2 million over the upcoming year.

Recovery of Qualified Facility Purchases and the Establishment of a Balancing Account

On October 31, 2012, Chugach submitted a filing to the RCA requesting approval to include a new cost element in Chugach’s purchased power cost recovery process to recover non-firm energy purchases from Qualified Facilities, and to create a balancing account for use in the development of quarterly buyback rates associated with purchases from Qualified Facilities.  On January 30, 2013, the RCA issued a letter order approving the filing.

(5)    Regulatory Matters (continued)

Recovery of Natural Gas Compression Costs

Chugach submitted a filing to the RCA on October 31, 2012, requesting approval to add a new cost element in Chugach’s fuel adjustment mechanism to recover charges associated with natural gas compression on the Kenai Nikiski Pipeline needed to allow bidirectional flows on the Cook Inlet Gas Gathering System.  The new cost element includes operations and maintenance charges, facility rental charges, fuel and control service charges. 

On December 7, 2012, the Regulatory Affairs and Public Advocacy Section of the Office of the Attorney General submitted comments opposing Chugach’s request to recover compression costs through the fuel rate adjustment process.  Chugach submitted a response on December 13, 2012.  The RCA issued a letter order on January 14, 2013, approving Chugach’s request for purchases through July 31, 2013.  After July 31, 2013, a separate tariffed rate is expected to be developed by Hilcorp.

June 30, 2012 Test Year Simplified Rate Filing

On September 28, 2012, Chugach submitted a SRF to the RCA and requested a system demand and energy rate decrease of 1.7 percent, or approximately $1.9 million on an annual basis.  The filing was based on the June 30, 2012 test year for proposed rate adjustments effective in November 2012.  On a customer class basis, Chugach requested demand and energy rate decreases of 1.7 percent to

Chugach retail customers and decreases of 2.1percent and 1.9 percent to its wholesale customers HEA and MEA, respectively, and a 1.6 percent increase to Seward.  The RCA issued a letter order on November6, 2012, approving the filing.  The updated rates were effective on and after November  12, 2012.

December 31, 2011 Test Year Simplified Rate Filing

On March 30, 2012, Chugach submitted a SRF to the RCA and requested a system demand and energy rate decrease of 0.1 percent, or approximately $0.8 million on an annual basis.  The filing was based on the December 31, 2011 test year for proposed rate adjustments effective in May 2012.  On a customer class basis, Chugach requested demand and energy rate increases of 1.3 percent to Chugach retail customers and decreases of 2.9 percent to its wholesale classes.  The RCA issued a letter order on May 10, 2012, approving the filing.  The updated rates were effective on and after May 14, 2012.

Economy Energy Sales and Transmission Wheeling Service

On April 23, 2012, Chugach submitted a filing to the RCA requesting approval to update its economy energy and transmission wheeling services tariffs to reflect current costs and operating conditions associated with transactions at the bulk power supply level.  After public comments and meetings Chugach withdrew the filing and will file updated rates for transmission and related ancillary services in conjunction with its 2012 general rate case.

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Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2012

Significant Accounting Policies [Abstract]

Management Estimates

a. Management Estimates

In preparing the financial statements in conformity with generally accepted accounting principles, the 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.

Regulation

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 and our rates, see Note (2j) – “Deferred Charges and Credits.”

Utility Plant And Depreciation

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	-	12/31/12
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%

In 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.

Capitalized Interest

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 4.0percent during 2012, 4.1 percent during 2011 and 4.8 percent during 2010.  Chugach capitalized actual interest expense and related fees associated with the construction of Southcentral Power Plant (SPP).

Investments In Associated Organizations

e. Investments in Associated Organizations

The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) requires 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 2012, 2011 and 2010.

Fair Value Of Financial Instruments

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 (see 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.

Cash And Cash Equivalents / Restricted Cash Equivalents

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 $10.0 million, which was subsequently invested in marketable securities in September of 2012.  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 of $8,942,631 and $6,481,639 for the years ended December 31, 2012 and 2011, respectively.  The Overnight Repurchase Agreement account had an average balance in 2012 and 2011 of $100 and $5,210,009, at an average interest rate of 0.00 percent and 0.06 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 used the proceeds primarily to fund capital expenditures associated with SPP and closed the account in February of 2013.

Restricted cash equivalents include State of Alaska construction bonds and funds on deposit for future workers compensation claims.  In 2011, restricted cash equivalents included $120.0 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.

Accounts Receivable

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 receivable are invoiced amounts to ML&P for fuel and their proportionate share of current SPP costs, which amounted to $3.0and $4.8 million in 2012 and 2011, respectively.  In addition, accounts receivable includes an invoiced amount to the Alaska Energy Authority (AEA) for reimbursable expenditures related to a grant for the Cook Inlet Gas Gathering System (CIGGS) project, which amounted to $4.0 million in 2012.

Materials And Supplies

i. Materials and Supplies

Materials and supplies are stated at average cost.

Deferred Charges and Credits

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. 

Patronage Capital

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 (Board).  Retained assignable margins are designated on Chugach's balance sheet as patronage capital.  This patronage capital constitutes the principal equity of Chugach.  The Board 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, 2014.  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 $6.9million at December 31, 2012.

Operating Revenues

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 $8,548,660and $8,977,409 of unbilled retail revenue at December 31, 2012 and 2011, 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. 

Fuel And Purchased Power Costs Recovery

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 adjustment process, which is adjusted quarterly to reflect increases and decreases of such costs.  We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates.  The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under or over collection of fuel and purchase power costs.  Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods.  Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods.  Fuel costs were over-recovered by $13,710,049 in 2012 and under-recovered by $1,213,484 in 2011.  Total fuel and purchased power costs in 2012, 2011, and 2010 were $147,941,346, $165,041,227, and $138,410,915, respectively.

Environmental Remediation Costs

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.

Income Taxes

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, 2012, 2011 and 2010 was in compliance with that provision.  In addition, as described in “Note (15) - Commitments and Contingencies,” 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.”

(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, 2009 through December 31, 2012 for U.S. Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2012.

Consumer Deposits

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, 2012 and 2011, totaled $2.4 million and $2.2 million, respectively.  Consumer deposits also represent customer credit balances as a result of prepaid accounts.  Credit balances for the years ended December 31, 2012 and 2011 totaled $1.9 million and $1.7 million, respectively.

Grants

q. Grants

Chugach has received federal and state grants to offset storm related expenditures and 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 while grant proceeds for storm related expenditures are offset against the actual expense incurred, which totaled $30.5million and $4.3 million in 2012 and 2011, respectively.  The assets constructed from grant awards may not be sold, or used as collateral for any reason.

Fuel Stock

r. Fuel Stock

Fuel Stock is the weighted average cost of fuel injected into the Cook Inlet Natural Gas Storage Alaska (CINGSA), which began service in the second quarter of 2012.  Limited withdrawals of gas began in the third quarter of 2012.  Chugach’s fuel balance in storage amounted to $9.5million for the year ended December 31, 2012.

Marketable Securities

s. Marketable Securities

In September of 2012, Chugach implemented a bond and equity investment portfolio. Chugach’s initial investment was $10.0 million.  The investments are classified as marketable securities, reported at fair value with gains and losses included in earnings.  At December  31, 2012, the carrying amount and fair value was $10.1million.

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Bradley Lake Hydroelectric Project

12 Months Ended

Dec. 31, 2012

Bradley Lake Hydroelectric Project [Abstract]

Bradley Lake Hydroelectric Project

(13)  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 $166.0 million 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 $28.7 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 $5.1 million as a result of Chugach’s Bradley Lake take-or-pay obligations.  Management believes that such expenditures, if any, would be recoverable through the fuel recovery process.

On July 1, 2010, AEA issued $28.8 million of Power Revenue Refunding Bonds, Sixth Series, for purposes of refunding $30.6 million 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 $0.7 million, 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 pending financing, could 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 up to 40,000 MWh.  Chugach would be entitled to 30.4 percent of the additional energy produced. 

(13)  Bradley Lake Hydroelectric Project (continued)

The following represents information with respect to Bradley Lake at June 30, 2012 (the most recent date for which information is available).  Chugach's share of expenses was $4,223,784in 2012, $4,643,641 in 2011, and $5,120,958 in 2010 and is included in purchased power in the accompanying financial statements.

(In thousands)	Total	Proportionate Share
Plant in service	$181,587	$55,202
Long-term debt	87,607	26,633
Interest expense	5,032	1,530

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

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Patronage Capital

12 Months Ended

Dec. 31, 2012

Patronage Capital [Abstract]

Patronage Capital

(9)    Patronage Capital

Chugach has a Board approved capital credit retirement policy, which is contained in Chugach’s Financial Forecast.  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, 2012, Chugach had $153,832,674 of patronage capital (net of capital credits retired in 2012), which included $148,307,167 of patronage capital that had been assigned and $5,525,507 of patronage capital to be assigned to its members.  Approval of actual capital credit retirements is at the discretion of Chugach's Board.  Chugach records a liability when the retirements are approved by the Board.  During 2008, the Board 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. 

(9)    Patronage Capital (continued)

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, 2014.  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 $6.9 million and $6.6 million at December 31, 2012 and 2011, respectively.

Capital credits retired were $48,079,  $309,188, and $94,278 for the years ended December 31, 2012, 2011, and 2010, respectively.  There was no outstanding liability for capital credits authorized but not paid at December 31, 2012 and 2011, respectively.

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Investments In Associated Organizations

12 Months Ended

Dec. 31, 2012

Investments In Associated Organizations [Abstract]

Investments In Associated Organizations

(7)    Investments in Associated Organizations

Investments in associated organizations include the following at December 31:

		2012		2011
National Rural Utilities Cooperative Finance Corporation	$	6,095,980	$	6,095,980
CoBank, ACB		4,392,948		4,974,755
NRUCFC capital term certificates / Other		63,755		63,761
Total Investments in Associated Organizations	$	10,552,683	$	11,134,496

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. 

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Deferred Charges And Credits

12 Months Ended

Dec. 31, 2012

Deferred Charges And Credits [Abstract]

Deferred Charges And Credits

(8)    Deferred Charges and Credits

Deferred Charges

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

		2012		2011
Debt issuance and reacquisition costs	$	4,126,529	$	3,432,665
Refurbishment of transmission equipment		141,976		151,235
Feasibility Studies		76,390		351,727
Beluga Gas Compression		2,035,466		2,544,332
Cooper Lake Relicensing / projects		5,800,417		5,930,520
Fuel supply negotiations		815,451		1,118,439
Major overhaul of steam generating unit		1,510,046		2,265,069
Other regulatory deferred charges		4,473,037		2,126,335
Bond interest - market risk management		7,527,357		6,034,443
Environmental matters and other		1,205,574		1,250,925
Total deferred charges	$	27,712,243	$	25,205,690

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

		2012		2011
Fuel supply (negotiations/studies/compression)	$	1,072,002	$	0
Studies / Other		236,401		578,327
Wind project		391,285		144,866
Financing related costs		1,757,624		51,129
Beluga Unit 8 inspection		1,061,838		0
Total deferred charges	$	4,519,150	$	774,322

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 or general rate case rate adjustments filed with the RCA. In most cases, deferred charges are recovered over the life of the underlying asset. 

(8)    Deferred Charges and Credits (continued)

Deferred Credits

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

		2012		2011
Refundable consumer advances for construction	$	777,323	$	727,917
Estimated initial installation costs for meters		92,149		75,660
Post retirement benefit obligation		899,700		899,700
Total deferred costs	$	1,769,172	$	1,703,277

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Other Equities

12 Months Ended

Dec. 31, 2012

Other Equities [Abstract]

Other Equities

(10)  Other Equities

A summary of other equities at December 31 follows:

		2012		2011
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		1,647,869		1,621,257
Unclaimed capital credit retirement1		9,700,861		9,713,810
Total other equities	$	11,372,355	$	11,358,692

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

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Quarterly Results Of Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2012

Quarterly Results Of Operations (Unaudited) [Abstract]

Schedule Of Quarterly Results Of Operations

2012 Quarter Ended

		Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	74,483,455	$	62,675,511	$	58,631,729	$	71,180,773
Operating Expense		68,250,215		60,200,529		55,725,151		64,019,060
Net Interest		3,492,044		3,495,865		3,542,676		3,872,346
Net Operating Margins		2,741,196		(1,020,883)		(636,098)		3,289,367
Nonoperating Margins		632,775		261,487		123,962		133,701
Assignable Margins	$	3,373,971	$	(759,396)	$	(512,136)	$	3,423,068

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

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Debt (Schedule Of Carrying Values And Estimated Fair Values Of Long-Term Debt Obligations) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
Long-term obligations, including current installments	$ 546,090,108	$ 429,450,318
Carrying Value [Member]
Debt Instrument [Line Items]
Long-term obligations, including current installments	546,090	429,450
Fair Value [Member]
Debt Instrument [Line Items]
Long-term obligations, including current installments	$ 573,912	$ 442,711

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2012

Commitments And Contingencies [Abstract]

Commitments And Contingencies

(15)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.

(15)Commitments and Contingencies (continued)

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 three IBEW CBA’s were extended by the Board on February 24, 2010.  The contract extensions expire on June 30, 2013.  On April 28, 2010, the Board approved a three year extension of the HERE agreement.  The contract extension also expires on June 30, 2013.Two of the bargaining units have ratified tentative agreements extending their labor agreements through June 30, 2017.  Chugach is currently negotiating with the final IBEW bargaining unit. 

Chugach is the principal supplier of power under long-term wholesale power contracts with MEA and HEA.  These contracts represented $100.6million or 39 percent of sales revenue in 2012, $104.0 million or 37 percent in 2011, and $89.1 million or 35 percent in 2010.  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.

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 Marathon Alaska Production, LLC (MAP) effective May 17, 2010.  The new MAP contract provided gas beginning April 1, 2011 and will terminate December 31, 2014, which includes two contract extensions that were exercised in 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.  All of the production is expected to come from Cook Inlet, Alaska.  In 2012, 89percent of our power was generated from gas, compared to 92 percent and 89 percent in 2011 and 2010 respectively.  Of that gas-fired power, 83 percent was generated at Chugach’s Beluga Power Plant in 2012 compared with 79 percent in 2011 and 78 percent in 2010.

(15)Commitments and Contingencies (continued)

The terms of the COP and MAP agreements require Chugach to handle the natural gas transportation over the connecting pipeline systems.  Effective October 1, 2012, Chugach and Hilcorp Alaska, LLC (Hilcorp) entered into a gas exchange agreement to exchange gas between the east and west side of Cook Inlet.  This agreement terminates on September 30, 2013.  We have gas transportation agreements with ENSTAR Natural Gas Company (ENSTAR) and Marathon Oil Company.  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:

	2012	2011	2010
Marathon Oil Company	72.0%	44.9%	24.1%
Chevron / Unocal / Hilcorp	1.3%	16.1%	26.4%
ML&P	0.0%	3.6%	14.2%
ConocoPhillips (COP)	24.2%	31.9%	35.1%
ENSTAR	2.2%	1.3%	0.2%
Miscellaneous	0.3%	2.2%	0.0%

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 the2005 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 payableand is included in the retirement of capital credits on our Statements of Changes in Equities and Margins.  HEA’s patronage capital was $6.9 million at December 31, 2012 and $6.6 million at December 31, 2011, and is classified as patronage capital payable on our Balance Sheet.

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 $0.000568, effective July 1, 2012. The tax is reported on a net basis and the tax is not included in revenue or expense.

(15)Commitments and Contingencies (continued)

Sales Tax

Chugach collects sales tax on retail electricity sold to Kenai and Whittier consumers.  The tax is

ollected monthly and remitted to the Kenai Peninsula Borough quarterly.  Sales tax is reported

on a net basis and the tax is not included in revenue or expense.

Gross Receipts Tax

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

Production taxes

Production 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 $3,786,031and $2,611,110 for this charge at December 31, 2012 and 2011, respectively and will use the funds to offset the costs of the projects.

Environmental Matters

The Clean Air Act and Environmental Protection Agency (EPA) regulations under the Clean Air Act establish ambient air quality standards and limit the emission of many air pollutants. 

New Clean Air Act regulations impacting electric utilities may result from future events or 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.

(15)Commitments and Contingencies (continued)

Environmental Matters (continued)

SPP was required by its Air Quality Permit to collect ambient air background data.  Data collection began on September 1, 2011 and continued through August 31, 2012.  On December 19, 2012, the Alaska Department of Environmental Conservation (ADEC) determined that the ambient pollutant data at SPP meets the requirements of the Prevention of Significant Deterioration (PSD) program set forth by the EPA.  This action completed the data collection requirement.

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

Generation Commitments

Chugach is in the process of developing a natural gas-fired generation plant on land owned by Chugach near its Anchorage headquarters.  SPP was 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 SPP.  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 steam turbine generator (STG) purchase agreement, an engineering, procurement, and construction (EPC) contract, a once through steam generator (OTSG) equipment and transportation contracts for transportation of all purchased equipment.All equipment, including the spare engine, has been received.  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, the initial building permit was received from the Municipality of Anchorage.  Chugach made payments of $85.7 million in 2012 and $130.5 million in 2011 pursuant to its contracts associated with SPP.  Additional payments of $13.0 million have been paid or are expected to be paid in 2013.  Commercialization of the project occurred on February 1, 2013. 

(15)Commitments and Contingencies (continued)

Economy Energy Sales

On October 5, 2012, Chugach and GVEA finalized arrangements for Chugach to provide economy energy to GVEA until March of 2015.    Sales will be made under the terms and conditions of Chugach’s economy energy sales tariff. The price to GVEA will include the cost of fuel, variable operations and maintenance expense and a margin.  Chugach has also entered into gas supply arrangements for GVEA economy energy sales.

Cooper Lake Hydroelectric Project

The Cooper Lake Hydroelectric Project received a 50-year license from 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.  If the project is not feasible or if the cost estimate materially exceeds the terms of the license, Chugach has the option to request a license amendment.  At the time the project was being relicensed the estimated cost to complete the project was $12.0 million.  The current estimate to complete the project is now $21.9 million.  As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska.  Funding for this project includes $0.6 million in grants received, $5.8 million in grants authorized and $3.5 million in grants requested.  The Chugach Board authorized expenditures for the project November 15, 2012.  The diversion project will be constructed in 2013 and 2014, and will operate through the duration of the license.

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Utility Plant (Tables)

12 Months Ended

Dec. 31, 2012

Utility Plant [Abstract]

Schedule Of Major Classes Of Utility Plant

Electric plant in service:		2012		2011
Steam production plant	$	60,462,671	$	60,462,671
Hydraulic production plant		20,513,746		20,456,395
Other production plant		127,980,607		134,434,574
Transmission plant		252,910,740		252,561,598
Distribution plant		257,587,220		257,341,532
General plant		51,901,426		45,144,425
Unclassified electric plant in service1		109,023,464		80,559,413
Intangible plant1		4,710,912		4,710,912
Other1		6,690,723		6,690,723
Total electric plant in service		891,781,509		862,362,243
Construction work in progress2		263,459,794		206,005,783
Total electric plant in service and construction work in progress	$	1,155,241,303	$	1,068,368,026

¹Unclassified electric plant in service consists of complete unclassified general plant, generation plant, transmission plant and distribution plant.  Depreciation of unclassified electric plant in service has been included in functional plant depreciation accounts in accordance with the anticipated eventual classification of the plant investment.  Intangible plant represents Chugach's share of a Bradley Lake transmission line financed internally.  Other represents Electric Plant Held for Future Use.

²The amount associated with the construction of SPP included in construction work in progress was $245.5million and $177.4 million at December 31, 2012 and 2011, respectively.

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Debt (Schedule Of Maturities Of Long-Term Debt Obligations) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Debt Instrument [Line Items]
2013	$ 24,493,022
2014	24,682,812
2015	23,889,777
2016	24,115,980
2017	24,362,621
Thereafter	424,545,896
Long-term obligations, including current installments	546,090,108	429,450,318
2011 Series A Bonds [Member]
Debt Instrument [Line Items]
2013	10,666,667
2014	10,666,667
2015	10,666,667
2016	10,666,667
2017	10,666,667
Thereafter	210,999,998
Long-term obligations, including current installments	264,333,333
CoBank Note [Member]
Debt Instrument [Line Items]
2013	2,076,355
2014	2,266,145
2015	2,473,110
2016	2,699,313
2017	2,945,954
Thereafter	19,295,898
Long-term obligations, including current installments	31,756,775
2012 Series A Bonds [Member]
Debt Instrument [Line Items]
2013	11,750,000
2014	11,750,000
2015	10,750,000
2016	10,750,000
2017	10,750,000
Thereafter	194,250,000
Long-term obligations, including current installments	$ 250,000,000

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Investments In Associated Organizations (Schedule Of Investments In Associated Organizations) (Details) (USD $)	Dec. 31, 2012	Dec. 31, 2011
Schedule of Cost-method Investments [Line Items]
Investments in associated organizations	$ 10,552,683	$ 11,134,496
National Rural Utilities Cooperative Finance Corporation [Member]
Schedule of Cost-method Investments [Line Items]
Investments in associated organizations	6,095,980	6,095,980
CoBank, ACB [Member]
Schedule of Cost-method Investments [Line Items]
Investments in associated organizations	4,392,948	4,974,755
NRUCFC Capital Term Certificates / Other [Member]
Schedule of Cost-method Investments [Line Items]
Investments in associated organizations	$ 63,755	$ 63,761

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Statements Of Changes In Equities And Margins (USD $)	3 Months Ended				12 Months Ended
	Dec. 31, 2012	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Balance		$ 161,231,426		$ 161,842,284	$ 161,231,426	$ 161,842,284	$ 156,320,597
Assignable margins	3,373,971	3,423,068	3,211,146	3,640,027	5,525,507	5,573,262	5,410,009
Retirement of capital credits					(48,079)	(6,761,968)	(94,278)
Unclaimed capital credit retirements					(12,949)	367,277	90,320
Memberships and donations received					68,468	210,571	115,636
Balance	166,764,373		161,231,426		166,764,373	161,231,426	161,842,284
Memberships [Member]
Balance		1,517,488		1,474,869	1,517,488	1,474,869	1,432,054
Assignable margins					0	0	0
Retirement of capital credits					0	0	0
Unclaimed capital credit retirements					0	0	0
Memberships and donations received					41,856	42,619	42,815
Balance	1,559,344		1,517,488		1,559,344	1,517,488	1,474,869
Other Equities And Margins [Member]
Balance		11,358,692		10,823,463	11,358,692	10,823,463	10,660,322
Assignable margins					0	0	0
Retirement of capital credits					0	0	0
Unclaimed capital credit retirements					(12,949)	367,277	90,320
Memberships and donations received					26,612	167,952	72,821
Balance	11,372,355		11,358,692		11,372,355	11,358,692	10,823,463
Patronage Capital [Member]
Balance		148,355,246		149,543,952	148,355,246	149,543,952	144,228,221
Assignable margins					5,525,507	5,573,262	5,410,009
Retirement of capital credits					(48,079)	(6,761,968)	(94,278)
Unclaimed capital credit retirements					0	0	0
Memberships and donations received					0	0	0
Balance	$ 153,832,674		$ 148,355,246		$ 153,832,674	$ 148,355,246	$ 149,543,952

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Fair Values Of Assets And Liabilities

12 Months Ended

Dec. 31, 2012

Fair Values Of Assets And Liabilities [Abstract]

Fair Values Of Assets And Liabilities

(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.

The table below presents the balance of Chugach’s Overnight Repurchase Agreement, marketable securities, money market and restricted cash equivalents assets measured at fair value on a recurring basis at December 31, 2012, and December 31, 2011.

		Total		Level 1		Level 2		Level 3
December 31, 2012
Repurchase agreement	$	100	$	0	$	100	$	0
Money market	$	2,829,397	$	2,829,397	$	0	$	0
Marketable securities	$	10,158,016	$	10,158,016	$	0	$	0
December 31, 2011
Repurchase agreement	$	100	$	0	$	100	$	0
Money markets	$	10,000,000	$	10,000,000	$	0	$	0
Restricted cash equivalents	$	122,006,738	$	122,006,738	$	0	$	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.

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Commitments And Contingencies (Schedule Of Costs Of Fuel Purchased And Transported As A Percentage Of Total Fuel Costs) (Details)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Marathon Oil Company [Member]
Cost of fuel purchased and transported as a percentage of total fuel costs	72.00%	44.90%	24.10%
Chevron/Unocal/Hilcorp [Member]
Cost of fuel purchased and transported as a percentage of total fuel costs	1.30%	16.10%	26.40%
Municipal Light & Power [Member]
Cost of fuel purchased and transported as a percentage of total fuel costs	0.00%	3.60%	14.20%
ConocoPhillips (COP) [Member]
Cost of fuel purchased and transported as a percentage of total fuel costs	24.20%	31.90%	35.10%
ENSTAR Natural Gas Company [Member]
Cost of fuel purchased and transported as a percentage of total fuel costs	2.20%	1.30%	0.20%
Miscellaneous [Member]
Cost of fuel purchased and transported as a percentage of total fuel costs	0.30%	2.20%	0.00%

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Investments In Associated Organizations (Tables)

12 Months Ended

Dec. 31, 2012

Investments In Associated Organizations [Abstract]

Schedule Of Investments In Associated Organizations

		2012		2011
National Rural Utilities Cooperative Finance Corporation	$	6,095,980	$	6,095,980
CoBank, ACB		4,392,948		4,974,755
NRUCFC capital term certificates / Other		63,755		63,761
Total Investments in Associated Organizations	$	10,552,683	$	11,134,496

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Fair Values Of Assets And Liabilities (Schedule Of Assets Measured At Fair Value On A Recurring Basis) (Details) (USD $)	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Repurchase agreement	$ 100		$ 100
Money market	2,829,397		10,000,000
Marketable securities	10,158,016	10,000,000	0
Restricted cash equivalents	1,953,085		122,006,738
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Repurchase agreement	0		0
Money market	2,829,397		10,000,000
Marketable securities	10,158,016
Restricted cash equivalents			122,006,738
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Repurchase agreement	100		100
Money market	0		0
Marketable securities	0
Restricted cash equivalents			0
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Repurchase agreement	0		0
Money market	0		0
Marketable securities	0
Restricted cash equivalents			$ 0

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Eklutna Hydroelectric Project

12 Months Ended

Dec. 31, 2012

Eklutna Hydroelectric Project [Abstract]

Eklutna Hydroelectric Project

(14)  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 2012 includes $4,725,470, net of accumulated depreciation of $1,671,335, which represents Chugach’s share of the Eklutna Hydroelectric Project.  In 2011 plant in service included $4,880,583, net of accumulated depreciation of $1,491,704.  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 $682,757, $662,035, and $664,747 in 2012, 2011, and 2010, 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.