Form 10-K

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

10-K 1 d696278d10k.htm FORM 10-K Form 10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year ended December 31, 2013

¨	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.

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.

2013 Form 10-K Annual Report

Table of Contents


	Page
PART I
Item 1 – Business		3

Item 1A – Risk Factors		11

Item 1B – Unresolved Staff Comments		16

Item 2 – Properties		17

Item 3 – Legal Proceedings		26

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		48

Item 8 – Financial Statements and Supplementary Data		50

Item 9 – Changes in and Disagreements With Accountants on Accounting and Financial Disclosure		87

Item 9A – Controls and Procedures		87

Item 9B – Other Information		88

PART III
Item 10 – Directors, Executive Officers and Corporate Governance		88

Item 11 – Executive Compensation		92

Item 12 – Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		98

Item 13 – Certain Relationships and Related Transactions, and Director Independence		99

Item 14 – Principal Accounting Fees and Services		99

PART IV
Item 15 – Exhibits and Financial Statement Schedules		100

SIGNATURES		111

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 82,554 service locations in the Anchorage and upper Kenai Peninsula (Kenai) areas. We also provide service to two 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 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 hydroelectric project is licensed by the Federal Energy Regulatory Commission (FERC). As such, Chugach is subject to FERC reporting requirements and our accounting 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

preceding year. This tax is accrued monthly and remitted annually. In addition, we currently collect a regulatory cost charge (RCC) of $0.000578 per kWh of retail electricity sold. This charge is assessed to fund the operations of the Regulatory Commission of Alaska (RCA). This tax is collected monthly and remitted to the State of Alaska quarterly. We also collect sales tax on retail electricity sold to Kenai and Whittier consumers. This tax is also collected monthly and remitted to the 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 319 employees as of March 12, 2014. 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 have been renewed through June 30, 2017. The three CBA’s provide for wage increases in all years and include health and welfare premium cost sharing provisions. The HERE contract has been renewed through June 30, 2016. This contract provides for wage increases in all years. 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 two wholesale customers, Matanuska Electric Association (MEA) and the City of Seward (Seward). We provided most of the power requirements of Homer Electric Association, Inc. (HEA) through their contract expiration date of December 31, 2013. 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, 2013, we had three major wholesale customers, including HEA, and 67,747 retail members receiving service at approximately 82,554 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.

In 2013, we had 602.7 megawatts (MW) of installed generating capacity provided by 18 generating units at our five owned power plants: Beluga Power Plant, International Station Power Plant (historically known as “IGT”), Cooper Lake Hydroelectric Project, Southcentral Power Project (SPP), in which we own a 70 percent interest 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 SPP began commercial operation, furnishing 200.2 MW of capacity. Chugach owns approximately 70 percent of this plant’s output and ML&P owns the remaining 30 percent. In 2013, approximately 79 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 were hydroelectric facilities. In 2013, 87 percent of our power was generated from gas, which included power generated at the Nikiski Power Plant and the Bernice Lake Power Plant, power plants not owned by Chugach. Of that gas-fired generation, 47 and 31 percent took place at Beluga and SPP, respectively. The Bradley Lake Hydroelectric Project, which is not owned by Chugach, provides up to 27.4 MW, as currently operated, for our retail customers and through 2013, provided an additional 24.1 MW for our wholesale customers. In 2014, the project will provide up to 13.3 MW for our remaining wholesale customer. For more information concerning Bradley Lake, see “Item 2 – Properties – Other Property – Bradley Lake.” We purchase up to 17.6 MW from Fire Island Wind, LLC (FIW). We purchased approximately 40 MW from the Nikiski Power Plant and approximately 67 MW from the Bernice Lake Power Plant on the Kenai through December 31, 2013. We operate 1,690 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, 2013, we sold 2.8 billion kWh of electrical power.

Customer Revenue from Sales

The following table shows the megawatt-hour (MWh) energy sales to and electric revenues from our retail, wholesale, and economy energy customers for the year ended December 31, 2013:


	MWh		2013 Revenues		Percent of Sales Revenue
Direct retail sales:
Residential		534,522	$	79,210,246		26	%
Commercial		627,842		75,998,468		25	%

Total		1,162,364		155,208,714		51	%

Wholesale sales:
MEA		773,836		65,352,294		22	%
HEA		463,582		37,788,679		13	%
Seward		64,507		4,830,063		2	%

Total		1,301,925		107,971,036		37	%

Economy energy/other¹		351,390		37,764,494		12	%


Total from sales		2,815,679		300,944,244		100	%

Miscellaneous energy revenue				4,364,183


Total energy revenues			$	305,308,427

¹	Economy energy/other includes sales to GVEA.

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, 2013, we had 67,747 members receiving power from approximately 82,554 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 and Seward under separate wholesale power contracts. We were the principal supplier of power to HEA through December 31, 2013. For 2013, our wholesale power contracts, including the fuel and purchased power components, produced $108.0 million in revenues, representing 35 percent of our total revenues and 46 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 2013, sales to MEA represented approximately 27 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. 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 10 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.

HEA

We had a power sales contract with Alaska Electric and Energy Cooperative, Inc. (AEEC) for firm, partial- requirement sales to HEA through December 31, 2013. That power sales agreement was assigned to AEEC and the Nikiski dispatch agreement was assigned to HEA with certain exceptions with the remaining rights and obligations under the Dispatch Agreement assigned to AEEC (discussed below). Under the power sales agreement, HEA was obligated to pay us for the power sold to AEEC even if AEEC did not pay, and (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, limited the costs that could be included in our rates charged to HEA. The HEA contract expired on December 31, 2013. 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 2013, sales to HEA represented approximately 16 percent of Chugach’s total sales of energy (including both retail and wholesale).

We had a dispatch agreement with AEEC to operate the Nikiski unit as a Chugach system resource. The agreement provided that, in addition to the energy that we already sell to AEEC and HEA, we would 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 was dispatched for HEA needs, provided HEA supplied the fuel, in excess of the sum of our contract demand plus HEA’s share of energy from the Bradley Lake project. 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. The dispatch agreement ended on December 31, 2013.

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 $7.9 million at December 31, 2013, which must be paid by December 31, 2018.

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 Power Plant 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.

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 was a purchased power agreement that gave 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 were 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.

Chugach recognized the proceeds from this sale as a liability on its Balance Sheet and continued to dispatch the power plant until the expiration of its power sales agreement with HEA. In December of 2013 Chugach recognized the gain associated with this sale which amounted to $6.4 million.

Seward

We currently provide nearly all the power needs of the City of Seward. In 2013, sales to Seward represented approximately 2 percent of Chugach’s total sales of energy (including both retail and wholesale). We entered into a power sales agreement (2006 Agreement) with the City of Seward, nominally effective June 1, 2006, with a term of 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 or had an obligation to provide reserves (MEA, HEA and Chugach retail customers). The price under the 2006 Agreement reflects the reduced level of service because no costs of generation in excess of that needed to meet the system peak is assigned to Seward.

Economy Customers

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 351,390 MWh, 90,765 MWh and 235,378 MWh for 2013, 2012, and 2011, 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.”

The Second Amended and Restated Indenture of Trust (the 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, ACB (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 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, 2013, 2012 and 2011, our Margins for Interest/Interest (MFI/I) was 1.43, 1.23, and 1.30, respectively. For the same periods, our TIER was 1.43, 1.24, and 1.58, respectively. The temporary increase in MFI/I and TIER in 2013 was due to the recognition of the gain on the sale of the Bernice Lake Power Plant. The decrease in MFI/I and TIER in 2012 was due primarily to an increase in long-term interest associated with additional debt.

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 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 is south of Anchorage with an economy substantially independent of the Anchorage area. The most significant basic industry on the Kenai is the production and processing of oil and gas from offshore facilities within the Cook Inlet region and onshore facilities that produce oil and gas products to meet local demand and for export to national and international markets. ConocoPhillips Alaska’s (COP) liquefied natural gas (LNG) export facility located in the City of Kenai had been exporting LNG to Japan for over 40 years. Amid reports of significant declines in local gas production, ConocoPhillips announced in 2011 that it would be ceasing LNG exports, which culminated in final shipments during the summer of 2012. Since 2012, with Hilcorp Alaska, LLC (Hilcorp) acquiring significant oil and gas assets in the Cook Inlet and reworking those assets to increase production, along with several third party developers bringing new sources of gas

production online, local gas production trends have changed and indicate a need for an export option to support ongoing development. On December 12, 2013, ConocoPhillips announced that it filed an application with the United States Department of Energy (DOE) to resume LNG exports from Alaska. The application is for a two-year export authorization to export about 40 billion cubic feet (Bcf) of gas per year as LNG. On February 28, 2014, the DOE approved the application to ship 40 Bcf of gas as LNG over a two-year period to countries which have free trade agreements with the United States. Tesoro Corporation is one of the largest independent refiners and marketers of petroleum products in the United States. In response to changes in fuel standards, 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. 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)	2014		2015		2016		2017		2018
Retail		1,232,326		1,179,000		1,181,000		1,183,000		1,185,000
Wholesale		848,837		63,000		63,000		63,000		63,000

Total		2,081,163		1,242,000		1,244,000		1,246,000		1,248,000

Retail energy sales are expected to remain relatively flat due to slow economic growth and progress in energy efficiency and conservation from 2014 to 2018. At the end of 2013, HEA’s contract to purchase their net requirements from Chugach expired. At the end of 2014, MEA’s contract to purchase their full requirements from Chugach expires, resulting in a decrease of approximately 40 percent in system energy sales from 2014 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.

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 2014, 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 a wholesale power contract with MEA and was the principal supplier of power under a wholesale power contract with HEA until December 31, 2013. These contracts, including the fuel component, represented $103.1 million, or 34 percent and $100.6 million, or 39 percent in 2013 and 2012, respectively, of total sales revenue. The HEA contract expired December 31, 2013, and the MEA contract expires December 31, 2014. 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 will result in a loss of approximately 44 percent of Chugach’s power sales and approximately 34 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 continues 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 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-” (Positive) and “A” (Stable), 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. There is no contingent liability at this time. If a funding shortfall in the AEPF exists, we may incur a contingent withdrawal liability.

We also participate in the National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (RS 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 employees not covered by a union agreement become participants in the RS Plan. We do not have control over the RS Plan. The RS Plan updates contribution rates on an annual basis to maintain the health of the plan under the plans rules allowed by the Employee Retirement Income Security Act (ERISA). Currently the funding status is governed by plan rules as provided by ERISA until 2017, when the minimum funding standards may become subject to the Pension Protection Act of 2006. Currently, the RS Plan does not require deficit reduction contributions to maintain minimum funding standards.

Equipment Failures and Other External Factors

The generation and transmission of electricity requires the use of expensive and complex equipment. While we have maintenance programs for existing equipment, along with certain warranties and service plans in place for SPP, 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.

Fuel Supply

In 2013, 87 percent of our power was generated from natural gas, which included power generated at the Nikiski Power Plant and the Bernice Lake Power Plant. Our primary suppliers of natural gas are ConocoPhillips and Hilcorp. Chugach currently has contracts in place to fill up to 100 percent of Chugach’s needs through March 31, 2018. In addition, in September of 2013, Chugach entered into an agreement with Cook Inlet Energy (CIE) which provides a structure to purchase supplemental gas from CIE and provides additional diversity in Chugach’s sources of natural gas to meet system load requirements.

The 2010 Alaska Legislature passed legislation that provides incentives to natural gas producers to enhance Cook Inlet oil and gas production. 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. 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. Cook Inlet lease sales totaled $3.1 million in 2013 and $4.6 million in 2012. Hilcorp purchased Chevron’s subsidiary Union Oil Company of California January 1, 2012, and purchased Marathon Alaska Production assets effective February 1, 2013. Both Hilcorp and ConocoPhillips have entered into gas contracts with a majority of the gas users in Cook Inlet for near-term needs.

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 had an initial storage capacity of 11 Bcf so that local utilities, including Chugach, would have gas available to meet deliverability requirements during peak periods. Injections into the facility began in 2012. Chugach’s share of the capacity is 2.3 Bcf. Chugach is entitled to withdraw gas at a rate of up to 35 million cubic feet (MMcf) per day. 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 $6.4 million in grants received with an additional $1.76 million pending authorization. The Chugach Board authorized expenditures for the project November 15, 2012. The diversion project began construction in 2013 and will be completed in 2014. It will operate through the duration of the license.

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 greenhouse gas (GHG) or carbon 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 and purchased power 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, 2013, Chugach had over-recovered $1.6 million and at December 31, 2012, Chugach had over-recovered $13.7 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.

Regulatory

Our billing rates are approved by the RCA. Chugach filed its 2012 General Rate Case on December 21, 2012, to reflect cost changes resulting from commercial operation of SPP. The proposed rates became effective on an interim and refundable basis in February of 2013. Chugach has been engaged in discussions with the intervening parties to resolve the outstanding issues in the case. The RCA accepted stipulations that resolved the majority of the issues in the case. A hearing on the case took place in December of 2013 to address the remaining limited issues in the case. On March 14, 2014, the RCA issued Order No. 16 affirming acceptance of the stipulations entered among the parties in the case , see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2012 General Rate Case.”

To reflect revenue and cost changes resulting from the expiration of HEA’s wholesale contract, Chugach submitted its 2013 Test Year General Rate Case to the RCA on November 19, 2013. On January 2, 2014, the RCA approved the submitted rates on an interim and refundable basis. To the extent the RCA does not allow for the recovery of our costs associated with our outstanding rate cases, Chugach could experience a material negative impact on its results of operations, financial position and cash flows.

Green House Gas Regulations, Carbon Emission and Climate Change

Uncertainty remains regarding the impacts of potential regulations regarding GHG, carbon emissions, and climate change on Chugach’s operations. The United States Environmental Protection Agency (EPA) is moving forward with regulations that seek to limit carbon emissions in the United States. Power plants are the single largest source of carbon emissions in the United States. In September of 2013, EPA announced a proposal to establish the first uniform national limits on carbon pollution from future power plants. These regulations will not apply to existing power plants. For existing power plants, EPA is engaged in outreach to a broad group of stakeholders who can inform the development of proposed guidelines, which are expected to be issued in June of 2014.

Additional costs related to a GHG tax or cap and trade program, if enacted by Congress, 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. Federal law or regulation regarding GHG emissions could have a material adverse effect on our operations, financial position, and cash flows.

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

Item 1B – Unresolved Staff Comments

None

Item 2 – Properties

General

In 2013, we had 602.7 MW of installed capacity consisting of 18 generating units at five power plants. These included 385.0 MW of operating capacity at the Beluga facility on the west side of Cook Inlet; 140.1 MW at SPP in Anchorage, which we jointly own with ML&P; 46.7 MW at IGT in Anchorage; and 19.2 MW at the Cooper Lake facility, which is also on the Kenai Peninsula. We also own rights to 11.7 MW of capacity from the two Eklutna Hydroelectric Project generating units that we jointly own with MEA and ML&P. Effective December 31, 2011, we sold the Bernice Lake Power Plant to AEEC and HEA, see “Item 1 – Business – Wholesale Customers – HEA.” In addition to our own generation, we purchased power from the 120 MW Bradley Lake Hydroelectric Project, which is owned by the Alaska Energy Authority (AEA), operated by HEA and dispatched by Chugach. In 2013, we also purchased power from Fire Island Wind, LLC (FIW) and the Nikiski Power Plant, which is owned by HEA. The Beluga, IGT and SPP facilities are all fueled by natural gas. We own our offices and headquarters, located adjacent to IGT and SPP 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.”

Our principal generation assets are in two plants, Beluga and SPP. Our principal generation units at Beluga are Units 6, 7, and 8. These units have a combined capacity of 212.3 MW. All other units at Beluga 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 2010, Unit 6 received a major inspection in which many of the major components were replaced with new or refurbished parts. Unit 6 had an annual inspection in 2011, 2012, and 2013. During the 2012 annual inspection of Unit 6, 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. Annual inspections were performed on this unit in 2011 and 2013. Beluga Unit 8, a steam turbine generator, received a major inspection in 2012 which included rotor life extension activities. Annual inspections were performed on Unit 8 in 2011 and 2013.

On February 1, 2013, SPP began commercial operation, furnishing 200.2 MW of capacity provided by 4 generating units. Chugach owns and takes approximately 70 percent of this plant’s output and ML&P owns and takes the remaining 30 percent. Chugach proportionately accounts for its ownership in SPP. Our principal generation units at SPP are Units 10, 11, 12, and 13. Throughout 2013, SPP units received preventative maintenance inspections consistent with original equipment manufacturer (OEM) recommendations. Units 11, 12, and 13, which have gas turbine generators, received two internal combustion system inspections each and one full annual inspection of the turbine systems. All three steam-generating boilers were internally inspected as well as hydrotested in accordance with initial OEM recommendations.

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 of 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 began in 2013 and will be completed in 2014.

The two generating units at Cooper Lake, Units 1 and 2, have a combined capacity of 19.2 MW. Both units were taken out of service for annual maintenance and annual inspections in October of 2012 and 2013. 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.

The Eklutna Hydroelectric Project is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in October of 1997. The facility is jointly owned by Chugach (30 percent), MEA (17 percent) and ML&P (53 percent). The facility is operated by Chugach and maintained jointly by Chugach and ML&P. Chugach owns rights to 11.7 MW of capacity from the two Eklutna Hydroelectric Project generating units.

The following matrix depicts nomenclature, run hours for 2013, percentages of contribution and other historical information for all Chugach generation units.


Facility	Commercial Operation Date	Nomenclature	Rating (MW)⁽¹⁾			Run Hours (2013)			Percent of Total Run Hours			Percent of Time Available
Beluga Power Plant⁽³⁾
1	1968	GE Frame 5		19.6			719.6			1.03			93.0
2	1968	GE Frame 5		19.6			757.4			1.08			97.0
3	1973	GE Frame 7		64.8			3,418.0			4.88			93.0
5	1975	GE Frame 7		68.7			4,258.6			6.08			97.7
6	1976	AP 11DM-EV		79.2			6,308.9			9.00			85.9
7	1978	AP 11DM-EV		80.1			6,466.7			9.23			92.5
8	1981	BBC DK021150⁽²⁾		53.0			7,606.2			10.85			89.8

Cooper Lake Hydroelectric Project				385.0
1	1960	BBC MV 230/10		9.6			2,582.3			3.67			90.1
2	1960	BBC MV 230/10		9.6			5,338.3			7.62			89.6

IGT Power Plant				19.2

1	1964	GE Frame 5		14.1			1,126.0			1.61			98.9
2	1965	GE Frame 5		14.1			841.2			1.20			99.0
3	1969	Westinghouse 191G		18.5			179.0			0.26			99.0

Southcentral Power Project				46.7
10	2013	Mitsubishi SC1F-29.5⁽²⁾		40.2	⁽⁶⁾		7,303.5			10.42			91.1
11	2013	GE LM6000 PF		33.3	⁽⁶⁾		7,621.6			10.88			96.5
12	2013	GE LM6000 PF		33.3	⁽⁶⁾		7,711.0			11.00			96.6
13	2013	GE LM6000 PF		33.3	⁽⁶⁾		7,839.6			11.19			97.8

Eklutna Hydroelectric Project				140.1
1	1955	Newport News		5.8	⁽⁴⁾		N/A	⁽⁵⁾		N/A	⁽⁵⁾		95.6
2	1955	Oerlikon custom		5.9	⁽⁴⁾		N/A	⁽⁵⁾		N/A	⁽⁵⁾		98.4

				11.7


System Total				602.7			70,077.9			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⁾	Run hours or in-commission rates are not recorded by Chugach for the Eklutna Hydroelectric Project as it is managed by a committee of three owners.

⁽⁶⁾	The Southcentral Power Project is jointly owned by Chugach and ML&P. The capacity shown is our 70 percent share of the plant’s output under normal operating conditions. The actual nameplate rating for the project is 200.2 MW.

Note: BBC = Brown Boveri Corporation, AP = Alstom Power

Transmission and Distribution Assets

As of December 31, 2013, 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, 909 miles of overhead distribution lines and 781 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 Hydroelectric Project, we also acquired a partial interest in two substations and additional transmission facilities.

Most of Chugach’s substation and generation sites are on Chugach-owned lands. The rights for the sites not on Chugach-owned lands are as follows: The Postmark, Point Woronzof and Raspberry Substations, and the East Terminal Site (N/S runway) are under rights from the State Department of Transportation and Public Facilities/Ted Stevens Anchorage International Airport; the East Terminal Site (6 mile) is under rights from the Matanuska-Susitna Borough; the West Terminal Site is under rights from the Army/Air Force; the University Substation is under rights from the Federal Bureau of Land Management; the Dowling, Hope and Daves Creek Substations are under rights from the State Department of Natural Resources; the Portage Substation is under rights from the Alaska Railroad Corporation (ARRC); the Summit Lake Substation is under rights from the United States Forest Service, and the Indian Substation will be under rights from the Chugach State Park upon approval. The Cooper Lake Power Plant and Quartz Creek Substation, and the 69kV transmission line between them, are operated under a federal license. Most of Chugach’s transmission, sub-transmission and distribution lines are either on public lands under rights from the federal, state, municipal, borough or ARRC, or on private lands via easements.

Title

On January 20, 2011, Chugach and the indenture trustee entered into 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 United States patents; non-delinquent or contested taxes, assessments and contractors’ liens; and various leases, rights-of-way, easements, covenants, conditions, restrictions, reservations, licenses and permits that do not materially impair Chugach’s use of the mortgaged property in the conduct of Chugach’s business.

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

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

Other Property

Bradley Lake. We are a participant in the Bradley Lake Hydroelectric Project, which is a 120 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 50 years from the date of commercial operation of the facility (September of 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 $26.6 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 $5.2 million as a result of Chugach’s Bradley Lake take-or-pay obligations.

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. 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. Along with two other utilities, Chugach purchased the Eklutna Hydroelectric Project from the federal government in 1997. Ownership was transferred from the DOE’s Alaska Power Administration jointly to Chugach (30 percent), MEA (17 percent) and ML&P (53 percent). The power MEA purchases from the Eklutna Hydroelectric Project is pooled with Chugach’s purchases and sold back to MEA to be used to meet MEA’s overall power requirements.

Fuel Supply

In 2013, 87 percent of our power was generated from natural gas, which included power generated at the Nikiski Power Plant and the Bernice Lake Power Plant.

Total gas purchased in 2013 was approximately 26.2 Bcf. In 2013, our sources of natural gas for firm sales were primarily divided among contracts with three major oil and gas companies. All of the production came from Cook Inlet, Alaska. ConocoPhillips under their current contract provided 45 percent of gas supplied for generation, Hilcorp provided 49 percent and MAP provided 5 percent (prior to the sale of MAP to Hilcorp). The current gas contract with ConocoPhillips provided gas beginning in 2010 and will expire December 31, 2016. The current gas contract with Hilcorp, provided gas beginning in April of 2011, and will expire March 31, 2018. ConocoPhillips and Hilcorp, together, fill up to 100 percent of Chugach’s firm needs through March 31, 2018. Gas to provide economy energy sales to GVEA is supplied by a gas supply arrangement with Hilcorp through March of 2015.

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 of 1989, superseding contracts that had been in place since 1973.

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 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 ConocoPhillips 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 100 percent of the gas purchased under the contract will be firm fixed and no purchases will be made under firm variable gas since firm variable gas is not provided by the contract after December 31, 2013. The dividing line between firm fixed and firm variable volumes was calculated based on a methodology that involves using a multiplier and the simple average of

Chugach’s average daily volumes for the 30 lowest volume days during the last calendar year. The ConocoPhillips contract during 2014 will be subject to a fixed volume delivery of 25,000 thousand cubic feet (Mcf) per day at the Firm Fixed Quantity price.

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.

Pricing for firm variable gas purchased between January 1, 2010, and March 31, 2011, was set based on one quarter trailing average of 95 percent of the average monthly price of Kenai liquefied natural gas delivered to Japan, as officially reported to the DOE. Hourly volumes delivered up to this hourly rate will be priced based on the “Firm Fixed Quantity” price of $3.784 per Mcf on January 1, 2014. Hourly volumes delivered in excess of this hourly rate will be priced based on the “Firm Variable Quantity” price. For the first quarter of 2011, the “Firm Fixed Quantity” was calculated at $3.689 per Mcf. Pricing for firm variable gas purchased from April 1, 2011, to December 31, 2013, was 120 percent of the one calendar quarter trailing average of “Platts National Average Price” as published in Platts Gas Daily for each “flow day.” 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 ConocoPhillips 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.

Marathon Alaska Production/Hilcorp

We entered into a contract with MAP effective May 17, 2010, to provide gas beginning April 1, 2011, and terminate December 31, 2014, including two contract extension options that were exercised in 2011. Effective February 1, 2013, the gas purchase agreement was assigned to Hilcorp who purchased MAP’s assets in Cook Inlet. The total amount of gas under contract is now estimated to be 40 Bcf. Pricing for the second 12-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 12-month forward curve (PLATTS report as of February 1, 2012) for the period of April of 2012 through March of 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 12-month period. Pricing from April of 2013 through December 31, 2013, was $5.98 per Mcf. Pricing for January 1, 2014, through December 31, 2014, is priced at $6.18 per Mcf. This was established based on the average price point of the Platt’s Gas Daily NYMEX 12-month forward curve (PLATTS report as of November 1, 2013) for the period covering January of 2014 through December of 2014.

Chevron/UNOCAL/Hilcorp

In May of 2010, Chugach entered into an interruptible gas purchase agreement with UNOCAL to supply gas to Chugach to produce economy energy for GVEA. The agreement was due to terminate on March 31, 2012. Effective December 28, 2011, the gas purchase agreement was assigned to 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.

On October 1, 2013, Chugach entered into a Gas Sales and Purchase Agreement with Hilcorp for the purchase of gas with an effective period of April 1, 2014 through March 31, 2015. This agreement is intended for Chugach to produce economy energy for GVEA. GVEA reimburses Chugach for the cost of gas related to economy energy sales

Cook Inlet Energy, LLC

On November 25, 2013, the RCA approved the Gas Sale and Purchase Agreement (GSPA) between Chugach and Cook Inlet Energy, LLC (CIE), which was filed with the RCA on September 30, 2013, and effective December 2, 2013. The RCA also approved inclusion of all gas costs incurred under the GSPA through Chugach’s fuel and purchased power cost adjustment mechanism.

The agreement may supply gas from April 1, 2014 through December 31, 2018, with an option to extend for an additional five years by mutual agreement during the term of the GSPA. The GSPA with CIE provides Chugach with an opportunity to diversify its gas supply portfolio, and minimize its current dependence on the gas agreements in place with two vendors. The gas that may be purchased under the GSPA with CIE is not required, however it introduces a new pricing mechanism.

The GSPA identifies and defines two types of gas purchases. Base Gas is defined by the volume of gas purchased on a firm or interruptible basis at an agreed delivery rate. Pricing for base gas purchases ranges from $6.12 to $7.31 per Mcf. Swing Gas is gas sold to Chugach at a delivery rate in excess of the applicable Base Gas agreed delivery rate. Pricing for swing gas purchases ranges from $7.65 to $9.14 per Mcf.

Natural Gas Transportation Contracts

The terms of the ConocoPhillips 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 SPP 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 was

approved by the RCA. Chugach recovered this cost through the fuel and purchased power recovery process. In November of 2013, Chugach and ENSTAR entered into a Special Contract for Natural Gas Transporation Service to provide for the interruptible transportation of gas to our Beluga Power Plant beginning December 15, 2013. Service under this agreement continues through December 15, 2014, and continues thereafter until canceled upon 90 days written notice by either party. This special contract has been approved by the RCA. Chugach recovers this cost through the fuel and purchased power recovery process.

Chugach and ENSTAR entered into a Firm Transportation Service Agreement on May 21, 2012, to provide for the transportation of gas to SPP. The agreement commenced on August 1, 2012, and remains in effect until canceled upon a 12-month written notice by either party. The agreement sets a contracted peak demand of 36,300 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 terminated on September 30, 2013.

Marathon Pipeline System

Marathon Oil Company, through its subsidiary Marathon Pipe Line Company, operates four major gas 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.

Hilcorp Alaska, LLC Pipeline System

Marathon Oil Company sold its share of its subsidiary pipeline company Marathon Pipe Line Company as part of a Cook Inlet asset divestiture effective February 1, 2013, to Hilcorp. Hilcorp now operates four major gas pipelines in the Cook Inlet basin, including the KNPL, the BPL, the CIGGS and the KKPL. Chugach has entered into tariff agreements to ship gas on the KNPL, BPL and CIGGS. Effective August 1, 2013, Chugach entered into a special contract with KNPL for Firm Service capacity over the Kenai Pipeline Junction (KPL) compressor of 35,000 Mcf per month for the movement of gas to its Beluga power plant at firm capacity rate of $2.13 per Mcf. This agreement is effective through July 31, 2014 and is subject to renewal through an open season bid process.

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 the United States Environmental Protection Agency (EPA) regulations under the Clean Air Act establish ambient air quality standards and limit the emission of many air pollutants. EPA is moving forward with regulations that seek to limit carbon emissions in the United States. Power plants are the single largest source of carbon emissions in the United States. In September of 2013, EPA announced a proposal to establish the first uniform national limits on carbon pollution from future power plants. These regulations will not apply to existing power plants. For existing power plants, EPA is engaged in outreach to a broad group of stakeholders who can inform the development of proposed guidelines, which are expected to be issued in June of 2014.

New Clean Air Act regulations impacting electric utilities may result from future events or new regulatory programs. Chugach is subject to these regulations, which have not had and are 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. Chugach has obtained Clean Air Act permits currently required for the operation of our generating facilities.

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

Item 3 – Legal Proceedings

Matanuska Electric Association, Inc. v. Chugach Electric Association, Inc., Superior Court Case No. 3PA-13-1006 Civil

On May 14, 2013, MEA served Chugach with a Summons and Complaint in the above referenced case. Chugach filed its Answer to the Complaint on June 21, 2013. With its Complaint, MEA fundamentally asks that Chugach be required to repatriate MEA’s capital credits on the same basis as it promised, in a 2007 settlement, that it would repatriate HEA capital credits.

The margins Chugach earns each year are allocated to the customers who contribute them and are booked as capital credits to those customers’ accounts. Capital credits are eventually repatriated to customers at the discretion of Chugach’s Board of Directors, typically many years after the margins are earned. With this litigation, MEA seeks to accelerate the return of its capital credits.

Chugach believes the claims are without merit and will vigorously defend against them. Management is uncertain of the outcome of the proceeding before the Superior Court. The ultimate resolution of this matter is not currently determinable. In the opinion of management, an adverse outcome is not likely to have a material adverse effect on Chugach’s results of operations or financial condition, however, an adverse outcome could impact Chugach’s equity ratio, which could, in turn, adversely impact our debt covenant compliance, in addition to our ability to borrow additional debt or refinance existing debt.

Chugach has certain other litigation matters and pending claims that arise in the ordinary course of Chugach’s business. In the opinion of management, none of these other matters, individually, or in the aggregate, is or are likely to have a material adverse effect on Chugach’s results of operations, financial condition or cash flows.

Item 4 – Mine Safety Disclosures

Not Applicable

PART II

Item 5 – Market for Registrant’s

Common Equity, Related Stockholder Matters and

Issuer Purchases of Equity Securities

Not Applicable

Item 6 – Selected Financial Data

The following table presents selected historical information relating to financial condition and results of operations for the years ended December 31:


Balance Sheet Data	2013			2012			2011			2010			2009

Electric plant, net:
In service	$	670,476,634		$	442,515,434		$	392,080,033		$	407,351,421		$	414,002,926

Construction work in progress		28,674,163			263,459,794			206,005,783			100,787,482			48,383,610


Electric plant, net		699,150,797			705,975,228			598,085,816			508,138,903			462,386,536

Other assets		139,033,241			156,626,138			254,843,842			121,588,825			105,958,000


Total assets	$	838,184,038		$	862,601,366		$	852,929,658		$	629,727,728		$	568,344,536


Capitalization:
Long-term debt		496,914,274			521,597,086			296,090,108			304,450,318			307,301,819

Equities and margins		175,795,865			166,764,373			161,231,426			161,842,284			156,320,597


Total capitalization	$	672,710,139		$	688,361,459		$	457,321,534		$	466,292,602		$	463,622,416


Equity Ratio¹		26.1	%		24.2	%		35.3	%		34.7	%		33.7	%

Operations Data

Operating revenues	$	305,308,427		$	266,971,468		$	283,618,369		$	258,325,345		$	290,247,308

Operating expenses		278,738,497			248,194,955			262,341,866			233,967,201			264,872,577

Interest expense		24,691,582			24,085,371			18,681,680			21,014,387			21,207,600

Capitalized interest		(1,310,110	)		(9,682,440	)		(1,934,703	)		(1,008,689	)		(601,251	)

Net operating margins		3,188,458			4,373,582			4,529,526			4,352,446			4,768,382

Nonoperating margins		7,355,585			1,151,925			1,043,736			1,057,563			891,966


Assignable margins	$	10,544,043		$	5,525,507		$	5,573,262		$	5,410,009		$	5,660,348


Margins for Interest Ratio²		1.43			1.23			1.30			1.26			1.27

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 Indenture and debt agreements.

Item 7 – Management’s Discussion and Analysis

of Financial Condition and Results of Operations

Caution Regarding Forward Looking Statements

Statements in this report that do not relate to historical facts, including statements relating to future plans, events or performance, are forward-looking statements that involve risks and uncertainties. Actual results, events or performance may differ materially. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date of this report and the accuracy of which is subject to inherent uncertainty. We undertake no obligation to publicly release any revisions to these forward-looking statements to reflect events or circumstances that may occur after the date of this 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, 2013, 2012 and 2011 was $24,378,162, $22,944,194, and $9,669,656, 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 temporary increase in TIER in 2013 was due to the recognition of the gain on the sale of the Bernice Lake Power Plant. The decrease in TIER in 2012 was due primarily to an increase in long-term interest associated with additional debt.

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, 2013, compared to the years ended December 31, 2012, and December 31, 2011 – Expenses.” We achieved TIERs for the past three years as follows:


Year	TIER
2013		1.43
2012		1.24
2011		1.58

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.

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.

On January 3, 2014, base demand and energy rates increased 11.5 percent to Chugach retail customers. Effective February 1, 2014, base demand and energy rates increased 19.3 percent and 13.8 percent to MEA and Seward, respectively. These changes were the result of Chugach’s 2013 Test Year General Rate Case, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2013 General Rate Case.”

On February 6, 2013, base demand and energy rates increased 26 percent, 40 percent, 35 percent and 20 percent to HEA, MEA, Seward and Chugach retail customers, respectively. These changes were the result of Chugach’s 2012 Test Year General Rate Case, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2012 General Rate Case.”

On November 12, 2012, base demand and energy rates decreased 2.1 percent, 1.9 percent and 1.7 percent to HEA, MEA and Seward retail customers, respectively, and increased 1.6 percent to Seward. These changes were the result of Chugach’s SRF utilizing the 12 months ended June 30, 2012.

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. These changes were the result of Chugach’s SRF utilizing the 12 months ended December 31, 2011.

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. These changes were the result of Chugach’s SRF utilizing the 12 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. These changes were the result of Chugach’s SRF utilizing the 12 months ended December 31, 2010.

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. These changes were the result of Chugach’s SRF utilizing the 12 months ended June 30, 2010.

Fuel and Purchased Power Recovery. We recover fuel and purchased power costs directly from our wholesale and retail customers through the fuel and purchased power rate 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. A fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, a 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, 2013, compared to the years ended December 31, 2012, and December 31, 2011

Margins

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


	2013		2012		2011

Net Operating Margins	$	3,188,458	$	4,373,582	$	4,529,526
Nonoperating Margins	$	7,355,585	$	1,151,925	$	1,043,736

Assignable Margins	$	10,544,043	$	5,525,507	$	5,573,262

The decrease in net operating margins in 2013 from 2012 of $1.2 million, or 27.1%, percent, was due primarily to an increase in depreciation expense associated with generation assets which was somewhat offset by an increase in economy revenue and a decrease in distribution expense. 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, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Years ended December 31, 2013, compared to the years ended December 31, 2012, and December 31, 2011 – 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 2013 over 2012 caused primarily by the recognition of the gain on the sale of the Bernice Lake Power Plant, which was deferred through the end of the dispatch agreement, December 31, 2013. 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 2013, operating revenues were $38.3 million, or 14.4% percent higher than 2012. The increase was due primarily to an increase in rates to both retail and wholesale customers as a result of Chugach’s 2012 Test Year Rate Case, higher economy energy revenue and higher fuel and purchased power expense recovered through the fuel and purchased power adjustment process, which was somewhat offset by lower firm kWh sales.

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.

Overall, retail and wholesale revenue increased in 2013 from 2012. Base retail and wholesale revenue increased due to an increase in rates charged to all customers as discussed above, which was somewhat offset by lower kWh sales caused by warmer weather. An increase in fuel and purchased power expense recovered through the fuel and purchased power adjustment process was more than offset by the effect of economy energy and wheeling transactions.

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.

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.

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 $35.5 million, $27.5 million, and $27.6 million to Chugach’s fixed costs for the years ended December 31, 2013, 2012 and 2011, 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, 2013, and 2012.


	Base Rate Sales Revenue							Fuel and Purchased Power Revenue							Total Revenue
	2013		2012		% Variance			2013		2012		% Variance			2013		2012		% Variance
Retail
Residential	$	50.9	$	45.4		12.1	%	$	28.3	$	30.7		(7.8	%)	$	79.2	$	76.1		4.1	%
Small Commercial	$	8.8	$	7.7		14.3	%	$	6.5	$	6.8		(4.4	%)	$	15.3	$	14.5		5.5	%
Large Commercial	$	32.5	$	28.6		13.6	%	$	26.6	$	28.6		(7.0	%)	$	59.1	$	57.2		3.3	%
Lighting	$	1.4	$	1.3		7.7	%	$	0.2	$	0.3		(33.3	%)	$	1.6	$	1.6		(0.0	%)
Total Retail	$	93.6	$	83.0		12.8	%	$	61.6	$	66.4		(7.2	%)	$	155.2	$	149.4		3.9	%

Wholesale
HEA	$	15.5	$	12.3		26.0	%	$	22.3	$	26.0		(14.2	%)	$	37.8	$	38.3		(1.3	%)
MEA	$	28.4	$	21.9		29.7	%	$	37.0	$	40.4		(8.4	%)	$	65.4	$	62.3		5.0	%
SES	$	1.7	$	1.3		30.8	%	$	3.1	$	3.5		(11.4	%)	$	4.8	$	4.8		0.0	%
Total Wholesale	$	45.6	$	35.5		28.5	%	$	62.4	$	69.9		(10.7	%)	$	108.0	$	105.4		2.5	%

Economy Sales	$	2.7	$	0.6		350.0	%	$	35.1	$	8.4		317.9	%	$	37.8	$	9.0		320.0	%
Miscellaneous	$	2.0	$	1.8		11.1	%	$	2.3	$	1.4		64.3	%	$	4.3	$	3.2		34.4	%

Total Revenue	$	143.9	$	120.9		19.0	%	$	161.4	$	146.1		10.4	%	$	305.3	$	267.0		14.3	%

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


	2013		2013		2012		2012		2011		2011
	Sales (MWh)		Revenue		Sales (MWh)		Revenue		Sales (MWh)		Revenue

Retail		1,162,364	$	155,208,714		1,178,836	$	149,355,192		1,166,336	$	151,474,488
Wholesale:
HEA		463,582		37,788,679		488,941		38,344,762		475,098		39,154,889
MEA		773,836		65,352,294		782,510		62,278,074		763,339		64,818,326
Seward		64,507		4,830,063		65,671		4,801,814		64,261		5,031,622

Total Wholesale		1,301,925		107,971,036		1,337,122		105,424,650		1,302,698		109,004,837
Economy energy		351,390		37,764,494		90,765		9,025,467		235,378		20,270,059
Other		N/A		4,364,183		N/A		3,166,159		N/A		2,868,985

Total		2,815,679	$	305,308,427		2,606,723	$	266,971,468		2,704,412	$	283,618,369

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, wheeling charges and a margin. Chugach has also entered into gas supply arrangements for GVEA economy energy sales.

In 2013, 2012, and 2011, economy sales to GVEA constituted approximately 12 percent, 3 percent, and 7 percent, respectively, of our sales revenues. Economy energy revenue increased in 2013 from 2012 due to additional sales to GVEA as a result of a new contract. 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.

Expenses

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


	2013		2012		2011
Fuel	$	136,610,262	$	125,836,659	$	139,179,413
Power production		21,911,324		16,739,931		16,853,232
Purchased power		27,836,680		22,104,687		25,861,814
Transmission		6,624,836		5,802,009		6,809,401
Distribution		13,225,242		15,822,104		13,387,477
Consumer accounts		6,014,888		6,013,419		5,465,315
Administrative, general and other		23,131,149		23,519,246		22,169,039
Depreciation		43,384,116		32,356,900		32,616,175

Total operating expenses	$	278,738,497	$	248,194,955	$	262,341,866

Fuel

Chugach recognizes actual fuel expense as incurred. Fuel expense increased $10.8 million, or 8.6%, in 2013 from 2012. The increase was due primarily to an increase in the average effective delivered price. Additional fuel associated with higher economy energy sales was more than offset by a reduction in fuel used as a result of the efficiency of SPP. In 2013, Chugach used 23,285,518 Mcf of fuel at an average effective delivered price of $5.61 per Mcf. 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 24,049,124 Mcf of fuel at an average effective delivered price of $5.03 per Mcf.

Power Production

Production expense increased $5.2 million, or 30.9%, in 2013 from 2012 due primarily to operating and maintenance expense at SPP which was somewhat offset by a decrease in operating and maintenance expense at the Beluga Power Plant. Power production expense did not materially change in 2012 from 2011.

Purchased Power

Purchased power expense, which included the cost of 2,731,159 Mcf of fuel associated with purchases from Nikiski, increased $5.7 million, or 25.9%, in 2013 from 2012, due to an increase in the average effective price, caused primarily by purchases from FIW and higher Bradley Lake operating and maintenance expense. In 2013, Chugach purchased 541,645 MWh of energy at an average effective price of 4.67 cents per kWh. 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 3,113,258 Mcf of fuel associated with purchases from Nikiski, decreased $3.8 million, or 14.5%, in 2012 from 2011. An increase in MWh purchased, due largely to purchases from the Bernice Lake Power Plant and FIW, 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.

Transmission

Transmission expense increased $0.8 million, or 14.2%, in 2013 from 2012, due primarily to an increase in substation maintenance. 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.

Distribution

Distribution expense decreased $2.6 million, or 16.4% in 2013 from 2012, due primarily to lower costs associated with storm related line maintenance. 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.

Consumer Accounts

Consumer Accounts expense did not materially change in 2013 from 2012. 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.

Administrative, General and Other Expense

Administrative, general and other expense did not materially change in 2013 from 2012. Administrative, general and other expense 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 canceled projects.

Depreciation

Depreciation and amortization expense increased $11.0 million, or 34.1%, in 2013 from 2012, due primarily to depreciation associated with generation assets, including SPP, which was placed into service in 2013. Depreciation expense did not materially change in 2012 from 2011.

Interest

Interest on long-term and other debt did not materially change in 2013 from 2012. 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. Principal payments on our 2011 bonds and CoBank debt also contributed to offsetting the increase.

Interest charged to construction decreased $8.4 million, or 86.5%, in 2013 from 2012, due primarily to a decrease in the average construction work in progress (CWIP) balance caused by the commercial operation of SPP in February of 2013.

Interest charged to construction increased $7.7 million, or 400.5 percent, in 2012 from 2011 due to a higher average balance in CWIP, due primarily to capital spending associated with SPP.

Patronage Capital (Equity)

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


	2013			2012			2011

Patronage capital at beginning of year	$	153,832,674		$	148,355,246		$	149,543,952
Retirement/net transfer of capital credits		(1,626,828	)		(48,079	)		(6,761,968	)
Assignable margins		10,544,043			5,525,507			5,573,262

Patronage capital at end of year		162,749,889			153,832,674			148,355,246
Other equity¹		13,045,976			12,931,699			12,876,180

Total equity at end of year	$	175,795,865		$	166,764,373		$	161,231,426

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. In 2011, Chugach reclassified $6.5 million of HEA’s patronage capital to patronage capital payable, 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.

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. In December of 2013 the Board resumed its capital credit retirement program. While honoring previously established agreements, Chugach’s intent is to return capital credits to wholesale and retail customers on the same rotation schedule. Capital credits retired, net of HEA’s allocations, were $1,626,828, $48,079, and $309,188 for the years ended December 31, 2013, 2012, and 2011, respectively.

Under the Indenture and debt agreements, Chugach is prohibited from making any distribution of patronage capital to Chugach’s customers if an event of default under the Indenture or debt agreements 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.

Changes in Financial Condition

Assets

Total assets decreased $24.4 million, or 2.8%, in 2013 from 2012. Net utility plant decreased $6.8 million, or 1.0%, caused by depreciation expense in excess of extension and replacement of plant. Cash and cash equivalents decreased $9.7 million or 69.1% in 2013 over 2012 due to various changes described below. Materials and supplies decreased $7.0 million or 21.3% in 2013 from 2012, primarily due to the classification of other Beluga generation assets and an SPP spare turbine engine to electric plant in service and deferred charges decreased $3.7 million or 13.4% as a result of annual amortization. Those decreases were somewhat offset by an increase in restricted cash equivalents and fuel stock. Restricted cash equivalents increased $1.8 million, or 89.8%, in 2013 from 2012 as a result of the reserve requirements for workers compensation and interim rates billed to all customers. Fuel stock increased $3.6 million, or 37.6%, due to gas supply contractual changes and new peaking reserve requirements.

Liabilities and Equity

Total liabilities, equities and margins decreased $24.4 million, or 2.8%, in 2013 as compared to 2012. Long term obligations decreased $24.7 million, or 4.7%, caused by the principal payments on the 2011 and 2012 bonds and accounts payable decreased $5.0 million, or 30.5%, due primarily to retainage payments made during 2013. Fuel cost over-recovery decreased $12.1 million, or 88.1%, due to the payment of the prior quarter’s over-recovery of fuel and purchased power costs and fuel payable decreased $6.0 million or 28.9% as a result of the timing of fuel payments. Deferred proceeds on sale of asset decreased $9.3 million or 100% as a result of recognizing the gain on the sale of the Bernice Lake Power Plant. These decreases were somewhat offset by an increase in total equities and margins, commercial paper, salaries, wages and benefits, other liabilities, patronage capital payable, and cost of removal obligations. Total equities and margins increased $9.0 million, or 5.4%, primarily due to the recognition of the gain on the sale of Bernice Lake Power Plant, as well as the margins generated in 2013. Commercial paper increased $18.5 million, or 160.9%, due primarily to the interval between bond payments and timing of rate recovery. Salaries, wages and benefits increased $0.6 million, or 7.1%, due to an increase in labor and labor related costs. Other liabilities increased $0.6 million, or 12.8%, primarily due to the authorization of a general capital credit retirement, which was somewhat offset by a decrease in the municipal underground ordinance payable. Patronage capital payable increased $1.1 million or 15.6%, due to the assignment of HEA’s 2013 patronage contribution. Cost of removal obligation increased $2.5 million, or 5.6%, as a result of annual removal costs of electric plant in service included in depreciation rates.

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 2013. Chugach’s gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel recovery process, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not significantly affect our operations.

Contractual Obligations and Commercial Commitments

The following are Chugach’s contractual and commercial commitments as of December 31, 2013:

Contractual cash obligations – Payments Due By Period


(In thousands)	Total		2014		2015-2016		2017-2018		Thereafter

Long-term debt, including current portion	$	521,597	$	24,683	$	48,006	$	48,994	$	399,914
Long-term interest expense¹		296,606		22,220		41,474		37,305		195,607
Commercial Paper²		30,000		30,000		0		0		0
Bradley Lake³		33,134		3,614		7,326		7,409		14,785
Fuel and fuel transportation expense⁴		400,072		113,496		118,899		99,978		67,699
Stetson Creek contracts⁵		7,255		7,255		0		0		0
Capital credit retirements⁶		7,899		0		0		7,899		0

Total	$	1,296,563	$	201,268	$	215,705	$	201,585	$	678,005

¹	Long-term interest expense includes fixed and variable rates. Variable rates are based on rates at December 31, 2013, for years 2014-2018 and thereafter, see “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt.”

At December 31, 2013, Chugach’s Commercial Paper Program was backed by a $100.0 million Unsecured Credit Agreement, which funds capital requirements. At December 31, 2013, there was $30.0 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $70.0 million and could be used for future operational and capital funding requirements.

³	Estimated annual debt service requirements.

⁴	Estimated committed fuel and fuel transportation expense

⁵	In accordance with contractual commitments associated with 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 Hilcorp, see “Item 2 – Properties – Fuel Supply – ConocoPhillips-Hilcorp Alaska, LLC.” 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.”

Liquidity and Capital Resources

We ended 2013 with $4.3 million of cash and cash equivalents, down from $14.0 at December 31, 2012 and down from $17.1 million at December 31, 2011. 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.


	2013			2012			2011
Total cash provided by (used in):

Operating activities	$	39,882,861		$	43,005,234		$	40,811,795
Investing activities		(44,046,875	)		1,386,980			(232,988,854	)
Financing activities		(5,536,292	)		(47,462,863	)		197,224,464


Increase (decrease) in cash and cash equivalents	$	(9,700,306	)	$	(3,070,649	)	$	5,047,405

Cash provided by operating activities was $39.9 million in 2013 compared to $43.0 million in 2012 and $40.8 million in 2011. The changes in accounts receivable were due primarily to amounts outstanding for grant activities, economy energy sales to GVEA and SPP costs billed to ML&P. The changes in materials and supplies were due primarily to certain transfers and the inventory needed for projects. The changes in fuel stock were due primarily to the addition of fuel storage and the changes in other assets were due primarily to the cash collected from interim and refundable rates and the required reserves associated with workers compensation. Changes in deferred charges were due primarily to financing costs, projects related to maintenance and fuel and subsequent amortization. Changes in consumer deposits were due primarily to the change in customer prepaid accounts and the changes in fuel cost over and under recovery were due to the payment of the over-collection of fuel and purchased power costs recovered through the fuel and purchased power surcharge process. Changes in accrued interest were due primarily to the 2011 and 2012 financing activities and related principal payments. Changes in fuel were due primarily to the timing of payments and the difference in price and quantity of fuel purchased.

Cash used in investing activities was $44.0 million in 2013 compared to $1.4 million of cash provided by investing activities in 2012 and $233.0 million of cash used in investing activities in 2011. The change in cash provided by or used in investing activities in 2013 from 2012 and in 2012 from 2011 was due primarily to the impact of expenditures associated with SPP, the change in restricted funds associated with the 2011 financing, the proceeds associated with the sale of the Bernice Lake Power Plant in 2011 and our investment in marketable securities in 2012.

Cash used in financing activities was $5.5 million in 2013 compared to $47.5 million in 2012 and $197.2 million provided by financing activity in 2011. The change in cash provided by or used in financing activities in 2013 from 2012 and 2011 was due primarily to our refinancing in 2011 and our interim bridge and subsequent financing associated with SPP in 2012.

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, 2013, there was no outstanding balance on our NRUCFC line of credit and $30.0 million of outstanding commercial paper. Thus, at December 31, 2013, our available borrowing capacity under our line of credit was $50.0 million and our available commercial paper capacity was $70.0 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 as the requirement for short-term borrowing has decreased 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 Indenture. At December 31, 2013, Chugach had $29.7 million outstanding with CoBank.

Under the Indenture, 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 Indenture 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 Indenture.

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, 2013, are set forth below:


Year Ending December 31	Principal Maturities

2014	$	24,682,812
2015		23,889,777
2016		24,115,980
2017		24,362,621
2018		24,631,934
Thereafter		399,913,962

	$	521,597,086

During 2013, we spent approximately $44.1 million on capital-construction projects, net of reimbursements, which includes interest capitalized during construction. We develop five-year capital improvement plans that are updated every year. Our capital improvement requirements are based on long-range plans and other supporting studies and are executed through the five-year Capital Improvement Plan (CIP).

Set forth below is an estimate of capital expenditures for the years 2014 through 2018 as contained in the CIP, which was approved by the Board on November 20, 2013:


Year	Estimated Expenditures
2014	$	25.0 million
2015	$	20.8 million
2016	$	13.9 million
2017	$	13.5 million
2018	$	15.1 million

We expect that cash flows from operations and external funding sources, including our available line 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 rate structure, managing our natural gas contracts and securing replacement revenue sources for an additional wholesale customer load that will be leaving at the end of 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 200.2 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 became 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 that included the recovery of additional costs associated with the project. Chugach also requested SPP fixed costs be synchronized with expected reductions in fuel costs. On March 14, 2014, the RCA issued Order No. 16 affirming acceptance of the stipulations entered among the parties in the case, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2012 General Rate Case.”

We continue to actively manage our fuel supply needs. We currently have contracts in place to fill 100 percent of our needs through March of 2018. 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 DOE. Given current demand and deliverability, DNR estimates a minimum 10-year supply of gas exists in currently producing leases. DNR does note that economic considerations will play a major role in whether producers continue undertaking additional drilling and development activities to meet demand. In June of 2011, an updated DNR report titled “Cook Inlet Natural Gas Production Cost Study” further quantified the economic considerations and came to two key conclusions:

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

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

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

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 LNG plant effective September 26, 2011. Amid reports of significant declines in local gas production, ConocoPhillips announced in 2011 that it would be ceasing LNG exports, which culminated in final shipments during the summer of 2012. Since 2012, with Hilcorp acquiring significant oil

and gas assets in the Cook Inlet and reworking those assets to increase production, along with several third party developers bringing new sources of gas production online, local gas production trends have changed and indicate a need for an export option to support ongoing development. On December 12, 2013, ConocoPhillips announced that it filed an application with the DOE to resume LNG exports from Alaska. The application is for a two-year export authorization to export about 40 Bcf of gas per year as LNG. On February 28, 2014, the DOE approved the application to ship 40 Bcf of gas as LNG over a two-year period to countries which have free trade agreements with the US.

CINGSA began service April 1, 2012. The facility had an initial storage capacity of 11 Bcf so that local utilities, including Chugach, would have gas available to meet deliverability requirements during peak periods. Injections into the facility began in 2012. Chugach’s share of the capacity is 2.3 Bcf. Chugach is entitled to withdraw gas at a rate of up to 35 MMcf per day. 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 after the expiration of their contracts. This will result in a loss of approximately 44 percent of Chugach’s power sales load and approximately 34 percent of the utility’s annual sales revenue.

HEA’s solely-owned power generation and transmission entity, AEEC, completed its Nikiski generation conversion project in 2013. AEEC currently owns a 40 MW natural gas-fired generation plant that was previously dispatched as part of Chugach’s overall system. The conversion project entailed adding a steam turbine and increasing the output of the plant to approximately 77 MW. HEA has been purchasing all of the output from this unit since the expiration of the Chugach contract. HEA also installed a 48 MW combustion turbine which is being used as a backup power source. During 2013, Chugach and AEEC finalized an agreement to accommodate HEA’s commissioning efforts at Nikiski.

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 gave 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. Chugach deferred the gain associated with the sale, reflecting a liability on its Balance Sheet and continued to dispatch the power plant until the expiration of its power sales agreement with HEA. In December of 2013, Chugach recognized the gain associated with the sale which amounted to $6.4 million. All capacity purchased power costs were recovered through our fuel and purchased power process.

After open discussions and proposals regarding power sales possibilities beyond 2014, in February of 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 170 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. In addition, because Chugach’s rates are established by the RCA, we expect to continue to be able to recover our specific costs of providing service despite the loss of these customers.

Chugach is also pursuing replacement sources of revenue through potential new power sales agreements, as well as 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. Chugach has also entered into a gas supply arrangement for GVEA economy energy sales, which was approved by the RCA on March 1, 2013.

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. 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.

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 capacity is expected to be 600 MW 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 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 included $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 44 study plans and approved the remaining studies shortly after. In February of 2014, AEA filed a draft Initial Study Report with FERC. Chugach will work with AEA and other parties on this effort.

The 2013 fiscal year State of Alaska capital budget contained $7.4 million in 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 United States 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 and Finance Committee. The following policies are considered to be critical accounting policies for the year ended December 31, 2013.

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 $9,274,135 and $8,548,660 of unbilled retail revenue at December 31, 2013 and 2012, respectively.

New Accounting Standards

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

Item 7A – Quantitative and Qualitative Disclosures About Market Risk

Chugach is exposed to a variety of risks, including changes in interest rates and changes in commodity prices due to repricing mechanisms inherent in gas supply contracts. In the normal course of our business, we manage our exposure to these risks as described below. We do not engage in trading market risk-sensitive instruments for speculative purposes.

Interest Rate Risk

At December 31, 2013, 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, 2013, we had $253.7 million of 2011 and $238.2 million of 2012 Series A Bonds outstanding. The fair value at December 31, 2013, was $482.8 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, 2013, we had $30.0 million of commercial paper outstanding and $29.7 million outstanding on our CoBank bond. A 100 basis-point rise in interest rates would increase our interest expense by approximately $0.6 million, and a 100 basis point decline in interest rates would decrease our interest expenses by approximately $0.4 million, based on $59.7 million of variable rate debt outstanding at December 31, 2013.

Commodity Price Risk

Chugach’s gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel and purchased power recovery process, fluctuations in the price paid for gas pursuant to gas supply contracts does not normally impact margins.

Item 8 – Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

The Board of Directors

Chugach Electric Association, Inc.

We have audited the accompanying balance sheets of Chugach Electric Association, Inc. as of December 31, 2013 and 2012, 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, 2013. 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, 2013 and 2012, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

March 20, 2014

Anchorage, Alaska

Chugach Electric Association, Inc.

Balance Sheets

December 31, 2013 and 2012


Assets	2013			2012

Utility Plant:
Electric plant in service	$	1,135,356,956		$	891,781,509
Construction work in progress		28,674,163			263,459,794

Total utility plant		1,164,031,119			1,155,241,303
Less accumulated depreciation		(464,880,322	)		(449,266,075	)

Net utility plant		699,150,797			705,975,228

Other property and investments, at cost:
Nonutility property		76,889			84,735
Investments in associated organizations		10,204,193			10,552,683
Special funds		536,546			570,027

Total other property and investments		10,817,628			11,207,445

Current assets:
Cash and cash equivalents, including repurchase agreements of $100 in 2013 and 2012		4,347,163			14,047,469
Special deposits		158,265			153,233
Restricted cash equivalents		3,706,832			1,953,085
Marketable securities		10,308,533			10,158,016
Accounts receivable, less provisions for doubtful accounts of $541,747 in 2013 and $490,413 in 2012		44,633,981			46,650,901
Materials and supplies		25,856,395			32,867,971
Fuel stock		13,029,848			9,466,767
Prepayments		1,863,407			2,156,862
Other current assets		320,658			252,146

Total current assets		104,225,082			117,706,450

Deferred charges, net		23,990,531			27,712,243


Total assets	$	838,184,038		$	862,601,366

Chugach Electric Association, Inc.

Balance Sheets (continued)

December 31, 2013 and 2012


Liabilities, Equities and Margins	2013		2012
Equities and margins:
Memberships	$	1,600,058	$	1,559,344
Patronage capital		162,749,889		153,832,674
Other		11,445,918		11,372,355

Total equities and margins		175,795,865		166,764,373

Long-term obligations, excluding current installments:
Bonds payable		469,499,999		491,916,666
National Bank for Cooperatives note payable		27,414,275		29,680,420

Total long-term obligations		496,914,274		521,597,086

Current liabilities:
Current installments of long-term obligations		24,682,812		24,493,022
Commercial paper		30,000,000		11,500,000
Accounts payable		11,461,303		16,488,323
Consumer deposits		4,851,558		4,279,901
Fuel cost over-recovery		1,635,677		13,710,049
Accrued interest		6,512,860		6,807,207
Salaries, wages and benefits		8,967,140		8,369,203
Fuel		14,834,585		20,868,078
Other current liabilities		5,143,905		4,559,981

Total current liabilities		108,089,840		111,075,764

Deferred compensation		536,546		570,027
Deferred liabilities		1,776,826		1,769,172
Patronage capital payable		7,931,295		6,858,367
Cost of removal obligation		47,139,392		44,628,315
Deferred proceeds on sale of asset		0		9,338,262


Total liabilities, equities and margins	$	838,184,038	$	862,601,366

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Statements of Operations

Years Ended December 31, 2013, 2012 and 2011


	2013			2012			2011

Operating revenues	$	305,308,427		$	266,971,468		$	283,618,369

Operating expenses:
Fuel		136,610,262			125,836,659			139,179,413
Production		21,911,324			16,739,931			16,853,232
Purchased power		27,836,680			22,104,687			25,861,814
Transmission		6,624,836			5,802,009			6,809,401
Distribution		13,225,242			15,822,104			13,387,477
Consumer accounts		6,014,888			6,013,419			5,465,315
Administrative, general and other		23,131,149			23,519,246			22,169,039
Depreciation and amortization		43,384,116			32,356,900			32,616,175

Total operating expenses	$	278,738,497		$	248,194,955		$	262,341,866

Interest expense:
Long-term debt and other		24,691,582			24,085,371			18,681,680
Charged to construction		(1,310,110	)		(9,682,440	)		(1,934,703	)

Interest expense, net	$	23,381,472		$	14,402,931		$	16,746,977

Net operating margins	$	3,188,458		$	4,373,582		$	4,529,526

Nonoperating margins:
Interest income		686,460			447,434			297,983
Allowance for funds used during construction		141,014			258,301			159,916
Gain on sale of asset		6,436,992			0			0
Capital credits, patronage dividends and other		91,119			446,190			585,837

Total nonoperating margins	$	7,355,585		$	1,151,925		$	1,043,736


Assignable margins	$	10,544,043		$	5,525,507		$	5,573,262

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Statements of Changes in Equities and Margins

Years Ended December 31, 2013, 2012 and 2011


	Memberships		Other Equities and Margins			Patronage Capital			Total
Balance, January 1, 2011	$	1,474,869	$	10,823,463		$	149,543,952		$	161,842,284

Assignable margins		0		0			5,573,262			5,573,262
Retirement/net transfer 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/net transfer 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


Assignable margins		0		0			10,544,043			10,544,043
Retirement/net transfer of capital credits		0		0			(1,626,828	)		(1,626,828	)
Unclaimed capital credit retirements		0		(21,456	)		0			(21,456	)
Memberships and donations received		40,714		95,019			0			135,733

Balance, December 31, 2013	$	1,600,058	$	11,445,918		$	162,749,889		$	175,795,865

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Statements of Cash Flows

Years Ended December 31, 2013, 2012 and 2011


	2013			2012			2011
Cash flows from operating activities:
Assignable margins	$	10,544,043		$	5,525,507		$	5,573,262


Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation		43,384,116			32,356,900			32,616,175
Amortization and depreciation cleared to operating expenses		5,912,254			5,882,580			5,472,557
Allowance for funds used during construction		(141,014	)		(258,301	)		(159,916	)
Write off of inventory, deferred charges and projects		430,453			991,871			851,756
Gain on sale of Bernice Lake Power Plant		(6,436,992	)		0			0
Other		240,836			(135,739	)		(93,834	)

(Increase) decrease in assets:
Accounts receivable, net		4,823,879			(4,276,906	)		(7,128,876	)
Fuel cost under-recovery		0			1,213,484			1,158,147
Materials and supplies		(907,942	)		(189,092	)		2,563,223
Fuel stock		(3,563,081	)		(9,466,767	)		0
Prepayments		293,455			(245,073	)		13,635
Other assets		(1,827,291	)		27,937			(2,049,082	)
Deferred charges		(317,070	)		(4,335,252	)		(6,358,154	)

Increase (decrease) in liabilities:
Accounts payable		1,775,412			1,454,677			1,891,089
Consumer deposits		571,657			330,849			(1,276,677	)
Fuel cost over-recovery		(12,074,372	)		13,710,049			0
Accrued interest		(294,347	)		(36,266	)		793,942
Salaries, wages and benefits		597,937			771,512			863,849
Fuel		(6,033,493	)		(3,531,079	)		2,829,619
Other current liabilities		2,901,022			3,094,139			3,011,319
Deferred liabilities		3,399			120,204			239,761

Net cash (used in) provided by operating activities		39,882,861			43,005,234			40,811,795


Cash flows from investing activities:
Proceeds on sale of Bernice Lake Power Plant		0			0			9,537,530
Investment in associated organizations		424,484			663,697			1,153,470
Investment in restricted cash equivalents		0			0			(270,000,000	)
Investment in marketable securities		(327,175	)		(10,096,304	)		0
Proceeds from restricted cash equivalents		0			120,000,000			150,000,000
Extension and replacement of plant		(44,144,184	)		(109,180,413	)		(123,679,854	)

Net cash (used in) provided by investing activities		(44,046,875	)		1,386,980			(232,988,854	)


Cash flows from financing activities:
Payments for debt issue costs		0			(1,850,199	)		(1,949,027	)
Proceeds from short-term obligations		45,500,000			24,500,000			76,500,000
Proceeds from long-term obligations		0			250,000,000			275,000,000
Repayments of short-term obligations		(27,000,000	)		(188,000,000	)		0
Repayments of long-term obligations		(24,493,022	)		(133,360,210	)		(152,851,500	)
Memberships and donations received		114,277			55,519			189,385
Retirement of patronage capital and estate payments		(156,565	)		(48,079	)		(309,188	)
Net receipts on consumer advances for construction		499,018			1,240,106			644,794

Net cash (used in) provided by financing activities		(5,536,292	)		(47,462,863	)		197,224,464


Net change in cash and cash equivalents		(9,700,306	)		(3,070,649	)		5,047,405

Cash and cash equivalents at beginning of period	$	14,047,469		$	17,118,118		$	12,070,713


Cash and cash equivalents at end of period	$	4,347,163		$	14,047,469		$	17,118,118


Supplemental disclosure of non-cash investing and financing activities:
Retirement of plant	$	24,095,596		$	10,405,777		$	11,317,319
Cost of removal obligation	$	2,511,077		$	3,148,135		$	3,160,851
Extension and replacement of plant included in accounts payable	$	3,817,788		$	10,620,219		$	15,561,199
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized	$	21,839,391		$	13,092,576		$	12,590,296

See accompanying notes to financial statements.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(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 two wholesale customers, Matanuska Electric Association, Inc. (MEA) and the City of Seward (Seward). We provided much of the power requirements of Homer Electric Association, Inc. (HEA) through their contract expiration date of December 31, 2013. 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 United States generally accepted accounting principles (GAAP), 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, the estimated useful life of utility plant and the cost of removal obligation. 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.”

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(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, less salvage, is charged to accumulated depreciation. The removal cost is charged to cost of removal obligation. 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 asset groups are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset group may not be recoverable in rates. Recoverability of asset groups to be held and used is measured by a comparison of the carrying amount of an asset group to estimated undiscounted future cash flows expected to be generated by the asset group. If the carrying amount of an asset group exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset group exceeds the fair value of the asset.

Depreciation and amortization rates have been applied on a straight-line basis and at December 31, 2013 are as follows:

Annual Depreciation Rate Ranges


Steam production plant		4.81% - 7.04%
Hydraulic production plant		1.06% - 3.00%
Other production plant		3.98% - 10.15%
Transmission plant		1.58% - 7.86%
Distribution plant		2.17% - 9.63%
General plant		1.57% - 20.00%
Other		2.75% - 2.75%
Southcentral Power Project (SPP) steam production plant		3.09% - 3.46%
SPP other production plant		3.15% - 3.84%

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. Chugach records a separate liability for the estimated obligation related to the cost of removal.

On August 31, 2012, in Docket U-12-009, the RCA approved SPP depreciation rates effective February 1, 2013, the date the SPP plant was placed in service.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(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. For all projects excluding SPP, Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 3.7 percent during 2013, 4.0 percent during 2012 and 4.1 percent during 2011. For SPP, Chugach capitalized actual interest expense and related fees associated with its construction.

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 2013, 2012 and 2011.

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.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(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. The concentration account had an average balance of $6,262,978 and $8,942,631 for the years ended December 31, 2013 and 2012, 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 funds on deposit for future workers compensation claims and interim rates collected from customers and escrowed as required by the RCA.

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 their proportionate share of current SPP costs, which amounted to $1.8 and $3.0 million in 2013 and 2012, respectively. In addition, accounts receivable includes invoiced amounts for grants to support the construction of facilities to divert water and safely transmit electricity, which amounted to $2.8 million in 2013 and $4.0 million in 2012.

i. Materials and Supplies

Materials and supplies are stated at average cost.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(2)

Significant Accounting Policies (continued)

j. Deferred Charges and Credits

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

Chugach regulatory asset recoveries are embedded in base rates approved by the RCA. Specific costs incurred and recorded as Regulatory Assets, including the amortization period for recovery, are approved by the RCA either in standard Simplified Rate Filings (SRF), general rate case filings or specified independent requests. The rates approved related to the regulatory assets are matched to the amortization of actual expenses recognized. 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 of 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 December 31, 2013. This patronage capital retirement was related to a settlement agreement associated with the 2005 Test Year General Rate Case (Docket U-06-134). The RCA accepted the parties’ settlement agreement on August 9, 2007. HEA’s patronage capital is classified as patronage capital payable and was $7.9 million at December 31, 2013.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 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 $9,274,135 and $8,548,660 of unbilled retail revenue at December 31, 2013 and 2012, 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 $1,635,677 in 2013 and over-recovered by $13,710,049 in 2012. Total fuel and purchased power costs in 2013, 2012, and 2011 were $164,446,942, $147,941,346, and $165,041,227, 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, 2013, 2012 and 2011 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.”

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(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 50 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, 2010 through December 31, 2013 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2013.

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, 2013 and 2012, totaled $2.5 million and $2.4 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances for the years ended December 31, 2013 and 2012 totaled $2.4 million and $1.9 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 safely 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 $17.4 million and $30.5 million in 2013 and 2012, 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. Chugach’s fuel balance in storage for the years ended December 31, 2013 and 2012 amounted to $13.0 million and $9.5 million, respectively.

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, 2013 and 2012, the carrying amount and fair value was $10.3 million and $10.1 million, respectively.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(2)

Significant Accounting Policies (continued)

t. Reclassifications

For the year ended December 31, 2013, Chugach recorded the following reclassification for the year ended December 31, 2012:

A reclassification representing the expected future cost of removal of our regulated assets previously included as an increase in accumulated depreciation and now included as an increase in cost of removal obligations. The impact of the reclassification was to decrease accumulated depreciation and increase cost of removal obligations by $44.6 million in 2012.

(3)

Recent Accounting Pronouncements

ASC Update 2013-06 “Not-for-Profit Entities (Topic 958): Services Received from Personnel of an Affiliate (a consensus of the Emerging Issues Task Force)”

In April of 2013, the FASB issued ASC Update 2013-06, “Not-for-Profit Entities (Topic 958): Services Received from Personnel of an Affiliate (a consensus of the FASB Emerging Issues Task Force)” (ASC Update 2013-06). ASC Update 2013-06 provides guidance for recognizing and measuring services received from personnel of an affiliate. This update is effective prospectively for fiscal years beginning after June 15, 2014. Chugach will begin application of ASC 2013-06 on January 1, 2015. Adoption is not expected to have any incremental effect on results of operations, financial position, and cash flows.

ASC Update 2013-04 “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (a consensus of the FASB Emerging Issues Task Force)”

In February of 2013, the FASB issued ASC Update 2013-04, “Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation is Fixed at the Reporting Date (a consensus of the FASB Emerging Issues Task Force.)” ASC Update 2013-04 provides guidance on the measurement and disclosure of obligations resulting from joint and several liability arrangements for which the total obligation is fixed at the reporting date. This update is effective for reporting periods beginning after December 15, 2013. Chugach will begin application of ASC 2013-04 on January 1, 2014. Adoption is not anticipated to have any incremental effect on results of operations, financial position, and cash flows.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(3)

Recent Accounting Pronouncements (continued)

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

In January of 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 of 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 of 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.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(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 United States 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 marketable securities, money market and restricted cash equivalents assets measured at fair value on a recurring basis at December 31, 2013, and December 31, 2012.


	Total		Level 1		Level 2		Level 3
December 31, 2013
Marketable securities	$	10,308,533	$	10,308,533	$	0	$	0

December 31, 2012
Money market	$	2,829,397	$	2,829,397	$	0	$	0
Marketable securities	$	10,158,016	$	10,158,016	$	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 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.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(5)

Regulatory Matters

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.

Associated with the approval of the PPA, Chugach submitted project status reports on March 31, 2012, June 29, 2012, October 31, 2012, and January 16, 2013. On January 30, 2014, Chugach submitted a status report regarding FIW integration and a cost reimbursement agreement related to possible impacts to an interconnected utility as a result of the project. Chugach also requested that the RCA accept further updates beginning no later than July 31, 2014.

2013 General Rate Case

To reflect revenue and cost changes resulting from the expiration of HEA’s wholesale contract, Chugach submitted its 2013 Test Year General Rate Case to the RCA on November 19, 2013, to increase system base rate revenues by $16.0 million, or approximately 12.5 percent on total retail, MEA, and Seward base rate revenues of $127.4 million. On January 2, 2014, the RCA approved the submitted rates on an interim and refundable basis. Retail rates were effective January 2, 2014, and wholesale rate changes were effective February 1, 2014, for purchases beginning January 1, 2014. The increase, net of both base rate increases and fuel savings, to Chugach retail end-users is approximately 6 percent, while the net increase to retail end-users of MEA and Seward is approximately 8 percent and 5 percent, respectively.

2012 General Rate Case

To reflect cost changes resulting from commercial operation of SPP, Chugach submitted a general rate case to the RCA on December 21, 2012, to increase system base rate revenues by $30.0 million, or approximately 26 percent on total base rate revenues of $115.0 million. The proposed rates became effective on an interim and refundable basis beginning in February of 2013. In a separate filing Chugach adjusted fuel rates to reflect efficiency improvements associated with the commercial operation of SPP and made these reduced fuel rates effective at the same time as the requested general rate case increases. This allowed the interim base rate increases to be synchronized with expected reductions in fuel cost recovery rates.

The filing also requested approval of a major expansion of 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 main purpose of the expansion is to accommodate anticipated wheeling services after expiration of the HEA and MEA wholesale customer contracts.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(5)

Regulatory Matters (continued)

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 from its retail revenue requirement. On February 6, 2013, the RCA 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 RCA also approved Chugach’s request to assess transmission wheeling charges on economy energy transactions that originate from the Chugach system.

The increase, net of both base rate increases and fuel savings, 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. Consistent with its practice the RCA required Chugach, at its option, to either place the interim and refundable amounts received into an escrow account or pay an annualized interest rate of 10.5 percent on any future refunds required in the docket. Chugach elected to place the interim and refundable amounts into escrow.

Intervener testimony was filed with the RCA on August 23, 2013. Both before and after those filings, Chugach has been engaged in discussions with the intervening parties to resolve the outstanding issues in the case. The RCA accepted stipulations that resolved the majority of the issues in the case. Chugach filed reply testimony on October 23, 2013, which proposed changes to its rate increase request, including a downward adjustment to its system revenue requirement by $0.2 million, which represents a 0.1 percent reduction to its system base rate revenue requirement of $143.0 million.

On December 10, 2013, Chugach submitted a petition to the RCA to release all escrowed funds in excess of $0.5 million, which Chugach will keep in escrow to cover any refunding required at the conclusion of the case. This $0.5 million is well in excess of the approximately $0.2 million needed to cover the refunds under the settlement. The RCA approved Chugach’s petition on December 27, 2013.

A hearing on the case took place in December of 2013 to resolve the remaining transmission issues in the case.

On March 14, 2014, the RCA issued Order No. 16 affirming the acceptance of the stipulations entered among the parties in the case. In the order, the RCA approved Chugach’s requested ratemaking treatment of select transmission facilities on its system. In conjunction with the approval, Chugach is required to notify the RCA upon the completion of its transmission power flow study required by stipulation. The RCA required Chugach to submit by April 14, 2014, a retail refund plan, updated rate calculations and attendant tariff revisions reflecting the results of the stipulations that were accepted by the RCA.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(5)

Regulatory Matters (continued)

Natural Gas Contract Submittals

Gas Sale and Purchase Agreement between Chugach and Hilcorp Alaska, LLC

On July 12, 2013, Chugach submitted a new gas purchase agreement with Hilcorp Alaska, LLC (Hilcorp) to the RCA. The new agreement will supply gas from January 1, 2015, through March 31, 2018. The total amount of gas under the contract is estimated to be 17.7 billion cubic feet (Bcf). The new agreement is designed to fill the balance of Chugach’s unmet needs in 2015 and 2016, up to 100% of unmet needs in 2017 and up to 100% of its total needs in the first quarter of 2018.

On September 10, 2013, the RCA issued an order approving the agreement and the recovery of the gas costs incurred under the agreement through Chugach’s fuel and purchased power cost adjustment process.

Gas Sale and Purchase Agreement between Chugach and Cook Inlet Energy, LLC

On September 30, 2013, Chugach submitted a new gas purchase agreement with Cook Inlet Energy, LLC (CIE) to the RCA for natural gas deliveries commencing April 1, 2014, and terminating on March 31, 2018. The agreement does not provide a current commitment to purchase any volume of gas but rather provides for the parties to meet and confer each year on the possible volumes of gas that could be sold and delivered in the next contract year or such other period as may be agreed. This structure accommodates on-going gas development work by CIE and provides additional diversity in Chugach’s sources of natural gas to meet system load requirements. On November 25, 2013, the RCA approved the agreement and the recovery of all gas costs incurred under the agreement through Chugach’s fuel and purchased power cost adjustment process.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(6)

Utility Plant

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


	2013		2012
Electric plant in service:
Steam production plant	$	60,462,671	$	60,462,671
Hydraulic production plant		20,546,809		20,513,746
Other production plant		122,051,709		127,980,607
Transmission plant		249,483,480		252,910,740
Distribution plant		258,474,600		257,587,220
General plant		48,517,709		51,901,426
Unclassified electric plant in service¹		369,280,657		109,023,464
Intangible plant¹		4,710,912		4,710,912
Other¹		1,828,409		6,690,723

Total electric plant in service		1,135,356,956		891,781,509
Construction work in progress²		28,674,163		263,459,794

Total electric plant in service and construction work in progress	$	1,164,031,119	$	1,155,241,303

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 at December 31, 2012.

(7)

Investments in Associated Organizations

Investments in associated organizations include the following at December 31:


	2013		2012
NRUCFC	$	6,095,980	$	6,095,980
CoBank		4,044,338		4,392,948
NRUCFC Capital Term Certificates and other		63,875		63,755

Total investments in associated organizations	$	10,204,193	$	10,552,683

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

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(8)

Deferred Charges and Credits

Deferred Charges

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


	2013		2012
Debt issuance and reacquisition costs	$	3,611,498	$	4,126,529
Refurbishment of transmission equipment		132,717		141,976
Feasibility studies		912,537		76,390
Beluga gas compression		1,526,599		2,035,466
Cooper Lake relicensing / projects		5,670,314		5,800,417
Fuel supply negotiations		971,209		815,451
Major overhaul of steam generating unit		1,285,942		1,510,046
Other regulatory deferred charges		1,759,448		4,473,037
Bond interest - market risk management		6,960,044		7,527,357
Environmental matters and other		1,160,223		1,205,574

Total deferred charges	$	23,990,531	$	27,712,243

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


	2013		2012
Fuel supply (negotiations/studies/compression)	$	231,712	$	1,072,002
Studies and other		336,017		236,401
Wind project		34,543		391,285
Financing related costs		0		1,757,624
Beluga Unit 8 inspection		0		1,061,838

Total deferred charges	$	602,272	$	4,519,150

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 approved by the RCA either in standard SRFs, general rate case filings or specified independent requests. In most cases, deferred charges are recovered over the life of the underlying asset.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(8)

Deferred Charges and Credits (continued)

Deferred Credits

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


	2013		2012
Refundable consumer advances for construction	$	773,089	$	777,323
Estimated initial installation costs for meters		104,037		92,149
Post retirement benefit obligation		899,700		899,700

Total deferred costs	$	1,776,826	$	1,769,172

(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, 2013, Chugach had $162,749,889 of patronage capital (net of capital credits retired in 2013), which included $152,205,846 of patronage capital that had been assigned and $10,544,043 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 SPP and the anticipated loss of wholesale load in 2013 and 2014. In December of 2013, the Board resumed its capital credit retirement program. Capital credits retired, net of HEA’s allocations, were $1,626,828, $48,079, and $309,188 for the years ended December 31, 2013, 2012, and 2011, respectively.

The Second Amended and Restated Indenture of Trust (the Indenture) 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 Indenture or debt agreements exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5 percent of Chugach’s patronage capital or 50 percent of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30 percent of Chugach’s total liabilities and equities and margins.

Chugach entered into an agreement with HEA to return all of its patronage capital within five years after expiration of its power sales agreement, which is December 31, 2013. This patronage capital retirement was related to a settlement agreement associated with the 2005 Test Year General Rate Case (Docket U-06-134). The RCA accepted the parties’ settlement agreement on August 9, 2007. HEA’s patronage capital payable was $7.9 million and $6.9 million at December 31, 2013 and 2012, respectively.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(9)

Patronage Capital (continued)

Capital credits retired, net of HEA’s allocations, were $1,626,828, $48,079, and $309,188 for the years ended December 31, 2013, 2012, and 2011, respectively. With the exception of HEA’s patronage capital payable, the outstanding liability for capital credits authorized but not paid at December 31, 2013 was $1,470,263. With the exception of HEA’s patronage capital payable, there was no outstanding liability for capital credits authorized but not paid at December 31, 2012.

(10)

Other Equities

A summary of other equities at December 31 follows:


	2013		2012
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		1,742,889		1,647,869
Unclaimed capital credit retirement¹		9,679,404		9,700,861

Total other equities	$	11,445,918	$	11,372,355

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.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(11)

Debt


	2013		2012

Long-term obligations at December 31 are as follows:

CoBank 3 and 4, 2.52% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003	$	29,680,420	$	31,756,775

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		81,000,000		85,500,000

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		172,666,666		178,833,333

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		71,250,000		75,000,000

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		117,000,000		125,000,000

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		50,000,000


Total long-term obligations	$	521,597,086	$	546,090,108

Less current installments		24,682,812		24,493,022


Long-term obligations, excluding current installments	$	496,914,274	$	521,597,086

Covenants

Effective January 20, 2011, Chugach is required to comply with all covenants set forth in the Indenture that secured the 2002 Series A Bonds through February 1, 2012, and now secures the 2011 Series A Bonds, the 2012 Series A Bonds and the 2011 promissory note to CoBank, which has replaced the outstanding CoBank 3, 4 and 5 promissory notes.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(11)

Debt (continued)

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 Indenture 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 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 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 United States patents; non-delinquent or contested taxes, assessments and contractors’ liens; and various leases, rights-of-way, easements, covenants, conditions, restrictions, reservations, licenses and permits that do not materially impair Chugach’s use of the mortgaged property in the conduct of Chugach’s business.

Rates

The Indenture 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 Indenture 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

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(11)

Debt (continued)

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 12-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 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

Maturities of Long-term Obligations

Long-term obligations at December 31, 2013, mature as follows:


Year ending December 31	2011 Series A Bonds		CoBank Note		2012 Series A Bonds		Total
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
2018		10,666,667		3,215,267		10,750,000		24,631,934
Thereafter		200,333,331		16,080,631		183,500,000		399,913,962

	$	253,666,666	$	29,680,420	$	238,250,000	$	521,597,086

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(11)

Debt (continued)

Lines of credit

Chugach maintains a $50.0 million line of credit with NRUCFC. Chugach did not utilize this line of credit in 2013, and therefore had no outstanding balance at December 31, 2013. In addition, Chugach did not utilize this line of credit during 2012 and had no outstanding balance at December 31, 2012. The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. The borrowing rate was 2.90 percent at December 31, 2013, and December 31, 2012.

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.

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- 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 and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch. Our commercial paper can be repriced between one day and 270 days. Chugach is expected to continue to issue commercial paper in 2014, as needed, however, the requirement for short-term borrowing has decreased.

Chugach had $30.0 million and $11.5 million of commercial paper outstanding at December 31, 2013 and 2012, respectively.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(11)

Debt (continued)

The following table provides information regarding 2013 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	$	5.9		0.27	July	$	33.4		0.23
February	$	0.1		0.25	August	$	35.0		0.21
March	$	23.2		0.29	September	$	42.1		0.21
April	$	40.0		0.26	October	$	49.9		0.23
May	$	39.7		0.24	November	$	52.7		0.19
June	$	34.3		0.24	December	$	53.1		0.20

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 semi-annually 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 Indenture, 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 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

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(11)

Debt (continued)

due March 15, 2041, will bear interest at 4.75 percent per annum, payable semi-annually on March 15 and September 15, 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.

Fair Value of Debt Instruments

The fair value of long-term debt has been determined using discounted future cash flows at borrowing rates currently available to Chugach. Level 1 measurement was used to determine the fair value of the 2011 and 2012 Series A Bonds. Level 2 measurements were used to determine all other long-term obligations. The estimated fair value (in thousands) of the long-term obligations included in the financial statements at December 31 is as follows:


	Carrying Value		Fair Value
Long-term obligations (including current installments)	$	521,597	$	512,435

(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 RS 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 RS Plan equal to the amounts accrued for pension expense.

Chugach made contributions to all significant pension plans for the years ended December 31, 2013, 2012 and 2011 of $6.8 million, $6.6 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, 2013, 2012 and 2011.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(12)

Employee Benefit Plans (continued)

Pension Plans (continued)

The following table provides information regarding pension plans which Chugach considers individually significant:

Alaska Electrical
Pension Plan³

NRECA Retirement
Security Plan³

Employer Identification Number

92-6005171

53-0116145

Plan Number

001

333

Year-end Date

December 31

Expiration Date of CBA’s

June 30, 2017

N/A²

Subject to Funding Improvement Plan

No⁴

Surcharge Paid

N/A

N/A⁴


	2013		2012		2011		2013			2012			2011
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)	$	3.4	$	3.6	$	3.0	$	3.4		$	3.0		$	3.0
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.

²	The CEO is the only non-union employee subject to an employment agreement, which is effective through July 17, 2016.

³	The Alaska Electrical Pension Plan is publicly available. The NRECA Retirement Security 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 RS 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, 2013, 2012, and 2011 were $4.1 million, $4.3 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, 2013, 2012, and 2011 totaled $2.9 million, $2.5 million, and $2.4 million respectively.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(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, 2013, 2012 and 2011 were $147.9 thousand, $141.0 thousand and $128.7 thousand, respectively.

401(k) Plan

Chugach has a defined contribution 401(k) retirement plan which covers substantially all employees who, effective January 1, 2008, can participate immediately. Employees who elect to participate may contribute up to the Internal Revenue Service’s maximum of $17,500, $17,000 and $16,500 in 2013, 2012 and 2011 respectively, and allowed catch-up contributions for those over 50 years of age of $5,500 in 2013, 2012 and 2011. Chugach does not make contributions to the plan.

Deferred Compensation

Effective January 1, 2011, Chugach participates in Vanguard’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, 2013, 2012 and 2011 was $536,546, $570,027 and $420,783, respectively.

Potential Termination Payments

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(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 (MW) as currently operated, of the project’s capacity. The share of Bradley Lake indebtedness for which we are responsible is approximately $26.6 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 $5.2 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.

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. 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 megawatt-hours (MWh). Chugach would be entitled to 30.4 percent of the additional energy produced.

The following represents information with respect to Bradley Lake at June 30, 2013 (the most recent date for which information is available). Chugach’s share of expenses was $4,882,163 in 2013, $4,223,784 in 2012, and $4,643,641 in 2011 and is included in purchased power in the accompanying financial statements.


(In thousands)	Total		Proportionate Share
Plant in service	$	177,968	$	54,102
Long-term debt		80,117		24,356
Interest expense		4,618		1,404

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

(14)

Eklutna Hydroelectric Project

Along with two other utilities, Chugach purchased the Eklutna Hydroelectric Project from the federal government in 1997. Ownership was transferred from the United States Department of Energy’s Alaska Power Administration jointly to Chugach (30 percent), MEA (17 percent) and ML&P (53 percent).

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(14)

Eklutna Hydroelectric Project (continued)

Plant in service in 2013 includes $4,562,310, net of accumulated depreciation of $1,854,083, which represents Chugach’s share of the Eklutna Hydroelectric Project. In 2012, plant in service included $4,725,470, net of accumulated depreciation of $1,671,335. The facility is operated by Chugach and maintained jointly by Chugach and ML&P. 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 $730,122, $682,757, and $662,035 in 2013, 2012, and 2011, respectively, and is included in purchased power, power production and depreciation expense in the accompanying financial statements. ML&P performs major maintenance at the plant. Chugach performs the daily operation and maintenance of the power plant, providing personnel 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.

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 have been renewed through June 30, 2017. The HERE contract has been renewed through June 30, 2016.

Chugach is the principal supplier of power under a wholesale power contract with MEA and was the principal supplier of power under a wholesale power contract with HEA until December 31, 2013. These contracts, including the fuel component, represented $103.1 million or 34 percent of sales revenue in 2013, $100.6 million or 39 percent in 2012, and $104.0 million or 37 percent in 2011. The HEA contract expired December 31, 2013, and the MEA contract expires December 31, 2014. Pursuant to contract provisions, notifications were made by MEA and HEA that neither organization intended to renew their 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.

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(15)

Commitments and Contingencies (continued)

Fuel Supply Contracts

Chugach has fuel supply contracts from various producers at market terms. Previous contracts expired at the end of the currently committed volumes in 2010 and 2011. A gas supply contract between Chugach and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively “ConocoPhillips”), 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. This contract includes two contract extensions that were exercised in 2011. Effective February 1, 2013, this gas purchase agreement was assigned to Hilcorp, who purchased MAP’s assets in Cook Inlet. This contract provided gas beginning April 1, 2011, and will expire March 31, 2018. The total amount of gas under contract is now estimated up to 40 Bcf. These contracts fill 100 percent of Chugach’s needs through March 31, 2018. All of the production is expected to come from Cook Inlet, Alaska. In 2013, 87 percent of our power was generated from gas, with 47 percent generated at the Beluga Power Plant and 31 percent generated at SPP. In 2012 and 2011, 89 percent and 92 percent, respectively, of our power was generated from gas, with 83 percent and 79 percent generated at Beluga.

The terms of the ConocoPhillips and Hilcorp agreements require Chugach to handle the natural gas transportation over the connecting pipeline systems. Effective October 1, 2012, Chugach and Hilcorp entered into a gas exchange agreement to exchange gas between the east and west side of Cook Inlet. This agreement terminated on September 30, 2013. We have gas transportation agreements with ENSTAR Natural Gas Company (ENSTAR) and Hilcorp. The following represents the cost of fuel purchased and or transported from various vendors as a percentage of total fuel costs for the years ended December 31:


	2013			2012			2011
Marathon Oil Company		4.5	%		72.0	%		44.9	%
Chevron / Unocal / Hilcorp		46.4	%		1.3	%		16.1	%
ML&P		0.0	%		0.0	%		3.6	%
ConocoPhillips (COP)		42.8	%		24.2	%		31.9	%
ENSTAR		2.1	%		2.2	%		1.3	%
Hilcorp Pipeline		3.8	%		0.0	%		0.0	%
Miscellaneous		0.4	%		0.3	%		2.2	%

Patronage Capital Payable

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(15)

Commitments and Contingencies (continued)

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 $7.9 million at December 31, 2013 and $6.9 million at December 31, 2012, 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 of 1992) from an initial rate of $0.000626 per kWh to the current rate of $0.000578, effective July 1, 2013. The tax is reported on a net basis and the tax is not included in revenue or expense.

Sales Tax

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

Gross Receipts Tax

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

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 expend two percent of a three-year average of gross retail revenue within the Municipality of Anchorage annually in moving existing distribution overhead lines underground. Consistent with Alaska Statutes regarding undergrounding programs, Chugach is permitted to amend its rates by adding a two percent charge to its retail members’ bills to recover the actual costs of the

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(15)

Commitments and Contingencies (continued)

program. The rate amendments are not subject to RCA review or approval. Chugach’s liability was $2,898,558 and $3,786,031 for this charge at December 31, 2013 and 2012, respectively. These funds are used to offset the costs of the undergrounding program.

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. Chugach is subject to these regulations, which have not had and are 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. Chugach has obtained Clean Air Act permits currently required for the operation of our generating facilities.

Economy Energy Sales

Cooper Lake Hydroelectric Project

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2013 and 2012

(15)

Commitments and Contingencies (continued)

this project includes $6.4 million in grants received with an additional $1.76 million pending authorization. The Chugach Board authorized expenditures for the project November 15, 2012. The diversion project began construction in 2013 and will be completed in 2014. It will operate through the duration of the license.

(16)

Gain on Sale of Asset

On July 12, 2011, Chugach sold the Bernice Lake Power Plant to AEEC and HEA. Chugach recognized the proceeds from this sale as a liability on its Balance Sheet and continued to dispatch the power plant until the expiration of its power sales agreement with HEA. In December of 2013, Chugach recognized the gain associated with this sale which amounted to $6.4 million.

(17)

Quarterly Results of Operations (unaudited)

2013 Quarter Ended


	Dec. 31		Sept. 30			June 30			March 31
Operating Revenue	$	81,068,132	$	71,715,353		$	74,776,425		$	77,748,517
Operating Expense		73,756,307		67,061,684			70,076,488			67,844,018
Net Interest		6,014,808		6,016,792			6,058,246			5,291,626

Net Operating Margins		1,297,017		(1,363,123	)		(1,358,309	)		4,612,873
Nonoperating Margins		6,918,314		226,803			(18,235	)		228,703

Assignable Margins	$	8,215,331	$	(1,136,320	)	$	(1,376,544	)	$	4,841,576

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

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 GAAP. 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, 2013, using the criteria set forth in “Internal Control Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (1992 framework). Based on this assessment, management believes that, as of December 31, 2013, Chugach maintained effective internal controls over financial reporting. In addition, there were no changes in Chugach’s internal controls over financial reporting (as defined in Rules 13a-15(f) or 15d-15(f) of the Exchange Act) identified in connection with the evaluation that occurred during the fourth quarter that has materially affected, or is reasonably like to materially affect, Chugach’s internal controls over financial reporting.

Item 9B – Other Information

None

PART III

Item 10 – Directors, Executive Officers and Corporate Governance

Chugach operates under the direction of a Board of Directors (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 50 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, 58, Chair, is the Director of Business and Resource Development for the Aleut Corporation. She was elected to the Board in 2008, and re-elected in 2011. She currently serves on the Audit and Finance, Governance, and Operations Committees and is currently Vice 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, 65, Vice Chair, 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 and re-elected in 2013. She currently serves on the Board’s Operations Committee and serves as the Chair of the Governance Committee. She is a National Rural Electric Cooperative Association Credentialed Cooperative Director. Her term expires in May of 2016.

Jim Henderson, 67, 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. He was elected to the Board in 2011. He currently serves on the Governance and Operations Committees. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2014.

David Gillespie, 53, Director, is the CEO of the Aleut Corporation. His background includes President and Chief Executive Officer for DAG Associates, LLC and New Generation Biofuels Holding, Inc.; and Vice President of Business Development and Asset Management of Duke Energy Corporation. He was elected to the Board in 2013. He currently serves on the Governance and Operations Committees. His term expires in May of 2016.

James Nordlund, 61, Director, is the 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 Chair of the Board, currently serves as Chair of the Operations Committee and is a member of the Audit and Finance Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2015.

Harry T. Crawford, Jr., 61, 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 as the Vice Chair of the Audit and Finance Committee and is a member of the Governance Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2014.

Sisi Cooper, 33, Treasurer, 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. She currently serves as the Chair of the Audit and Finance Committee and the Vice Chair of the Operations Committee. Her term expires in May of 2015.

Identification of Executive Officers

Bradley W. Evans, 59, was appointed Chief Executive Officer on July 1, 2008. Prior to that appointment, Mr. Evans served as Interim CEO since December 5, 2007. Prior to that appointment, he served as Sr. Vice President, Power Supply since March 20, 2006, General Manager, G&T Division since January 31, 2005, Sr. Vice President, Energy Supply since June 5, 2002, and Director, Energy Supply since February 26, 2001. Prior to his current Chugach employment, Mr. Evans served as Manager, System Dispatch for Golden Valley Electric Association.

Michael R. Cunningham, 64, was appointed Chief Financial Officer on June 5, 2002. Prior to the CFO appointment he served as Controller since 1986. Prior to that, he served as 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, 56, was appointed Interim Chief Financial Officer and Sr. Vice President, Finance and Administration from February 28, 2013 until July 23, 2013. After this appointment, Mr. Vecera returned to his previously held position 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.

Sherri McKay-Highers, 45, was appointed Chief Financial Officer and Vice President, Finance and Administration effective July 23, 2013. Prior to this appointment, Ms. McKay-Highers was serving as Manager, Budget and Financial Reporting, guiding Chugach’s financial planning and reporting responsibilities. Ms. McKay-Highers has worked at Chugach for more than 15 years and has held various accounting management positions.

Edward M. Jenkin, 53, was appointed Vice President, Power Delivery on August 22, 2008. Prior to that appointment he served as Acting Sr. Vice President, Power Delivery since January 14, 2008. Mr. Jenkin has 30 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 MEA in April of 1982.

Paul R. Risse, 59, was appointed Sr. Vice President, Power Supply on October 27, 2008. Prior to that appointment, he served as Acting Sr. Vice President, Power Supply since December 6, 2007. Prior to that appointment, Mr. Risse 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, 58, was appointed Sr. Vice President, Strategic Development and Regulatory Affairs on July 1, 2013. Prior to that appointment he served as Sr. Vice President, Strategic Planning and Corporate Affairs since June 11, 2008, Sr. Vice President, Power Delivery from March 20, 2006, to February 1, 2008, General Manager, Distribution Division since January 31, 2005, Sr. Vice President, Power Delivery since June 3, 2002, Executive Manager, Transmission & Distribution Network Services since June 1, 1997, Executive Manager, Operating Divisions from June of 1994. Before moving up to the Executive Manager position, he served as Director of Operations from May of 1987.

Tyler E. Andrews, 48, was appointed Vice President, Member and Employee Services on September 9, 2013. Prior to that appointment he served as Vice President, Human Resources since March 17, 2008. Mr. Andrews has over 20 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 more than 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 50 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 and Finance Committee Financial Expert

The Board relies on the advice of all members of the Audit and Finance Committee therefore the Board has not formally designated an Audit and Finance Committee financial expert.

Identification of the Audit and Finance Committee

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

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

The Board Chair shall appoint the Board Treasurer as Audit and Finance Committee Chairperson. The Audit and Finance Committee shall elect from its members a Vice Chair, and appoint a recording secretary as needed. Members of the 2013 Audit and Finance Committee include Chair Sisi Cooper and Directors Janet Reiser, James Nordlund 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 audit committees is not applicable to the Chugach Audit and Finance 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 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 objectives and incentive-based bonuses to a maximum of $50,000. 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 each 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 to a maximum of $50,000. In 2013, 2012 and 2011, upon review of the performance of the CEO, Mr. Evans received a discretionary bonus of $45,000, $25,000 and $20,000, 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.

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 2013 and for all such executive officers as a group:

Summary Compensation Table


Name	Year		Salary		Bonus		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation¹		Total

Bradley W. Evans, Chief Executive Officer		2013 2012 2011	$ $ $	305,192 299,998 273,266	$ $ $	45,000 25,000 20,000	$ $ $	248,897 249,325 162,766	$ $ $	4,542 15,924 4,407	$ $ $	603,631 590,247 460,439

Sherri L. McKay-Highers, Chief Financial Officer		2013 2012 2011	$ $ $	118,088 100,540 97,117	$ $ $	4,000 6,000 5,000	$ $ $	7,830 44,000 49,932	$ $ $	2,607 8,279 11,644	$ $ $	132,525 155,819 163,693

Michael R. Cunningham, Former Chief Financial Officer		2013 2012 2011	$ $ $	40,240 208,976 200,433	$ $ $	0 20,000 20,000	$ $ $	69,054 312,647 205,955	$ $ $	20,312 66,162 13,319	$ $ $	129,606 607,785 439,707

Lee D. Thibert, Sr. Vice President, Strategic Development & Regulatory Affairs		2013 2012 2011	$ $ $	214,773 199,919 193,133	$ $ $	12,500 15,000 10,000	$ $ $	153,767 245,090 205,468	$ $ $	9,120 13,278 7,318	$ $ $	390,160 473,287 415,919

Tyler E. Andrews, Vice President, Member and Employee Services		2013 2012 2011	$ $ $	158,777 153,056 147,619	$ $ $	10,000 5,000 0	$ $ $	29,760 34,865 32,650	$ $ $	5,692 10,375 894	$ $ $	204,229 203,296 181,163

Edward M. Jenkin, Vice President, Power Delivery		2013 2012 2011	$ $ $	177,269 173,078 167,761	$ $ $	12,500 5,000 0	$ $ $	123,923 205,556 179,247	$ $ $	7,447 3,488 1,444	$ $ $	321,139 387,122 348,452

Paul R. Risse, Sr. Vice President, Power Supply		2013 2012 2011	$ $ $	187,960 174,410 168,541	$ $ $	20,000 15,000 0	$ $ $	152,114 181,842 137,323	$ $ $	12,389 9,038 2,532	$ $ $	372,463 380,290 308,396

Ronald K. Vecera, Interim Chief Financial Officer		2013 2012 2011	$ $ $	142,809 135,136 129,698	$ $ $	5,000 0 0	$ $ $	242,315 285,968 169,085	$ $ $	4,405 1,850 1,164	$ $ $	394,529 422,954 299,947

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

Pension Benefits

We have elected to participate in the NRECA RS 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 RS Plan is intended to be a qualified pension plan under Section 401(a) of the Code. All employees not covered by a union agreement become participants in the RS 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 12 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 55 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 30 years of benefit service (defined below) or, if earlier, by attaining age 62. 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 55.

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 RS Plan (benefit service) and the highest five-year average of the annual rate of his or her base salary during the last 10 years of his or her participation in the RS 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 and 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 of 1998, we adopted both of these plans to protect the benefits of current and future employees whose pension benefits would be reduced because of these limitations.

On October 16, 2002, the Board authorized an amendment to the RS Plan with an effective date of November 1, 2002. Under the amended RS 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 RS 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, 2013 that is taken into account under the RS 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		NRECA RS Payments During Last Fiscal Year
Bradley W. Evans, Chief Executive Officer	Retirement Security		12.83	$	1,017,671	$	0
	Pension Restoration		12.83	$	90,261	$	0
Sherri L. McKay-Highers, Chief Financial Officer	Retirement Security		14.08	$	207,730	$	0
Michael R. Cunningham,¹ Former Chief Financial Officer	Retirement Security		0	$	0	$	115,785
Lee D. Thibert, Sr. VP, Strategic Dev & Reg Affairs	Retirement Security		25.33	$	1,477,495	$	0
Paul R. Risse, Sr. VP, Power Supply	Retirement Security		17.92	$	942,352	$	0
Edward M. Jenkin, VP, Power Delivery	Retirement Security		23.08	$	1,074,710	$	0
Tyler E. Andrews, VP, Member and Employee Services	Retirement Security		4.80	$	129,246	$	0
Ronald K. Vecera,² Interim, Chief Financial Officer	Retirement Security		0.08	$	4,342	$	1,813,699

¹	Mr. Cunningham retired on February 25, 2013.

²	Mr. Vecera quasi-retired on November 1, 2013.

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 (2.80 percent for 2013 and 3.02 percent for 2012) and the Pension Protection Act (PPA) three-segment yield rates (0.97 percent, 3.50 percent, and 4.60 percent for 2013 and 1.99 percent, 4.47 percent, and 5.26 percent for 2012) 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 2013 and 2012, respectively, combined unisex 50 percent/50 percent mortality in combination with the PPA rates). The lump sum is then discounted at 4.67 percent interest only (no mortality is

assumed) from assumed retirement date back to December 31, 2013, and 3.75 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2012, to determine the present value for the appropriate year.

Deferred Compensation

Chugach participates in Vanguard’s unfunded Deferred Compensation Program (the Program) to allow highly compensated employees who elect to participate in the Program to defer a portion of their current compensation and avoid paying tax on the deferrals until received. As a non-qualified plan under Internal Revenue Code 457(b), 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	$	23,000	$	0	$	3,378	$	0	$	113,644

Michael R. Cunningham, Former Chief Financial Officer	$	4,423	$	0	$	9,782	$	211,078	$	0

Tyler E. Andrews, Vice President, Member and Employee Services	$	17,500	$	0	$	550	$	0	$	33,534

Ronald K. Vecera, Interim, Chief Financial Officer	$	23,000	$	0	$	45,213	$	0	$	250,662

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 26 weeks for 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 payable within 90 days, and the full cost of health and welfare coverage for a period not in excess of six 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	$	277,465

Sherri L. McKay-Highers, Chief Financial Officer	$	91,335

Lee D. Thibert, Sr. Vice President, Strategic Development & Regulatory Affairs	$	151,963

Tyler E. Andrews, Vice President, Member and Employee Services	$	83,706

Edward M. Jenkin, Vice President, Power Delivery	$	135,489

Paul R. Risse, Sr. Vice President, Power Supply	$	229,169

Ronald K. Vecera Interim, Chief Financial Officer	$	197,179

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 Chugach 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 Chair. The Chair of the Board receives an additional $50 per day for each day of each meeting if the Chair performs the duties of Chair at the meeting.

The following table sets forth the dollar amounts of all fees paid in cash by us for the fiscal year ending December 31, 2013, to each of our current and former Board members:

Director Compensation Table


Name	Fees Paid In Cash

Janet Reiser, Chair and Director	$	20,400

Susan Reeves, Vice-Chair and Director	$	14,800

Jim Henderson, Secretary and Director	$	14,450

Sisi Cooper, Treasurer and Director	$	12,100

James Nordlund, Director	$	10,950

Harry Crawford, Jr., Director	$	19,200

David Gillespie, Director	$	6,100

P.J. Hill, Former Director	$	4,800

One new Board member was elected, while one current Board member was re-elected at Chugach’s annual membership meeting held on May 16, 2013. David Gillespie was elected to a three-year term while Susan Reeves was re-elected to a three-year term.

Item 12 – Security Ownership of Certain Beneficial Owners and Management

and Related Stockholder Matters

Not Applicable

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

Not Applicable

Item 14 – Principal Accounting Fees and Services

The Audit and Finance Committee of the Board retained KPMG LLP as the independent registered public accounting firm for Chugach during the fiscal year ended December 31, 2013.

Fees and Services

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


	2013		2012
Audit and audit-related services:
Audit and quarterly reviews	$	170,195	$	179,555
Audit-related services		48,705		37,750
Non-audit services:
Tax consulting and return preparation		12,175		75,260
Other services¹		0		21,372

Total	$	231,075	$	313,937

¹	Other services in 2012 included the quality control GAAP analysis of a new customer accounting system

The Audit and Finance 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, 2013 and 2012 were approved by the Audit and Finance Committee.

PART IV

Item 15 – Exhibits and Financial Statement Schedules


	Page

Financial Statements

Included in Part II of this Report:
Report of Independent Registered Public Accounting Firm		50
Balance Sheets, December 31, 2013 and 2012		51-52
Statements of Operations, Years ended December 31, 2013, 2012 and 2011		53
Statements of Changes in Equities and Margins, Years ended December 31, 2013, 2012 and 2011		54
Statements of Cash Flows, Years ended December 31, 2013, 2012 and 2011		55
Notes to Financial Statements		56-86

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.

100

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 16, 2013, 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.

101



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.

102



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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2012, SEC File No. 033-42125.

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.

103



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.

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.

104



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.

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.

105



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.

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.

106



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.

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.

10.58.1		Letter of Agreement By and Between the Registrant and the Hotel Employees and Restaurant Employees Union Local 878 dated effective July 1, 2010. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated May 14, 2010, SEC File No. 033-42125.

10.58.2		Letter of Agreement By and Between the Registrant and the Hotel Employees and Restaurant Employees Union Local 878 dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated November 12, 2013, SEC File No. 033-42125.

107



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.

10.59.2		Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 Representing Office and Engineering Bargaining Unit dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated May 13, 2013, 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.

10.60.3		Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 Representing Generation Bargaining Unit dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated May 13, 2013, 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.

10.61.2		Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 Representing Outside Plant Bargaining Unit dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated May 13, 2013, SEC File No. 033-42125.

108



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.

10.64.2		Employment Agreement between the Registrant and Bradley W. Evans dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated May 16, 2013, SEC File No. 033-42125.

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

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

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

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. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2012, SEC File No. 033-42125.

10.74		Firm Transportation Service Agreement between the Registrant and ENSTAR Natural Gas Company effective August 1, 2012. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2012, SEC File No. 033-42125.

10.75		Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska LLC effective September 10, 2013. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated September 10, 2013, SEC File No. 033-42125.

10.76		Agreement between the Registrant and Cook Inlet Energy Inc. effective December 2, 2013. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated November 25, 2013, SEC File No. 033-42125.

109



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

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

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

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

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

101.INS*		XBRL Instance Document

101.SCH*		XBRL Taxonomy Extension Schema Document

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document

110

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 20, 2014.


CHUGACH ELECTRIC ASSOCIATION, INC.

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

Date:		March 20, 2014

111

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 12, 2014, by the following persons on behalf of the registrant and in the capacities indicated:


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

/s/ Sherri L. McKay-Highers				Chief Financial Officer
Sherri L. McKay-Highers				(Principal Financial Officer) (Principal Accounting Officer)

/s/ Burke Wick for Paul 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, Member and Employee Services
Tyler E. Andrews

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

112


/s/ Susan Reeves				Director & Vice-Chairman of the Board
Susan Reeves

/s/ Sisi Cooper				Director & Treasurer of the Board
Sisi Cooper

/s/ Jim Henderson				Director & Secretary of the Board
Jim Henderson

/s/ James Nordlund				Director
James Nordlund

/s/ Harry T. Crawford, Jr.				Director
Harry T. Crawford, Jr.

/s/ David Gillespie				Director
David Gillespie

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 2013 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.

113