UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

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

For the fiscal year endedDecember 31, 2014

or

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

For the transition period from  ____________ to ____________

Commission file number33-42125

Chugach Electric Association, Inc.

(Exact name of registrant as specified in its charter)

Alaska	92-0014224
(State or other jurisdiction of	(I.R.S. Employer
incorporation or organization)	Identification No.)
5601 Electron Dr., Anchorage, Alaska	99518
(Address of principal executive offices)	(Zip Code)
Registrant’s telephone number, including area code	(907) 563-7494

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

Title of each class	Name of each exchange on which registered
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☒ 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.

☒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☒ 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).

☒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.☒

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

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☐

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

☐Yes ☒ 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. 2014 Form 10-K Annual Report
Table of Contents
PART I			Page
	Item 1.	Business	2
	Item 1A.	Risk Factors	10
	Item 1B.	Unresolved Staff Comments	16
	Item 2.	Properties	16
	Item 3.	Legal Proceedings	24
	Item 4.	Mine Safety Disclosures	24
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matter and Issuer Purchases of Equity Securities	24
	Item 6.	Selected Financial Data	25
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	44
	Item 8.	Financial Statements and Supplementary Data	45
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	80
	Item 9A.	Controls and Procedures	80
	Item 9B.	Other Information	81
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	81
	Item 11.	Executive Compensation	85
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	91
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	91
	Item 14.	Principal Accounting Fees and Services	92
PART IV
	Item 15.	Exhibits and Financial Statement Schedule	93
		SIGNATURES	105

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CAUTION REGARDING FORWARD-LOOKING STATEMENTS

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

PART I

Item 1 – Business

General

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

Chugach makes its current and periodic reports available, free of charge, on its website at www.chugachelectric.com as soon as practicable after filing with the Securities and Exchange Commission (SEC).  The information on Chugach’s website is not a part of this Annual Report on Form 10-K.  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 in the Anchorage and upper Kenai Peninsula 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 Peninsula to the interior of the state, including Alaska’s largest cities, Anchorage and Fairbanks.  Neither Chugach nor any other electric utility in Alaska’s Railbelt has any connection to the electric grid of the continental United States or Canada.  Our principal executive offices are located at 5601 Electron Drive, Anchorage, Alaska 99518.  Our telephone number is (907) 563-7494.

Chugach is a rural electric cooperative that is exempt from federal income taxation as an organization described in Section 501(c)(12) of the Internal Revenue Code (Code).  Chugach’s 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.  In lieu of state and local ad valorem, income and excise taxes, Alaska electric cooperatives must pay a gross revenue tax to the State of Alaska at the rate of $0.0005 per kilowatt-hour (kWh) of electricity sold in the retail market during the

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preceding year.  This tax is accrued monthly and remitted annually.  In addition, we currently collect a regulatory cost charge (RCC) of $0.000754 per kWh of retail electricity sold.  The RCC is assessed to fund the operations of the Regulatory Commission of Alaska (RCA) and is collected monthly and remitted to the State of Alaska quarterly.  We also collect sales tax monthly on retail electricity sold to consumers in Whittier and in the Kenai Peninsula Borough.  This tax is remitted to the City of Whittier monthly and to the Kenai Peninsula Borough quarterly.  These taxes are a direct pass-through to consumer bills and therefore do not impact our margins.

We had 301 employees as of March 5, 2015.  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 have been renewed through June 30, 2017.  The three CBA 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, 2014, we had two major wholesale customers, 68,241retail members, and approximately 83,081 service locations, including idle services.  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 2014, 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,

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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 2014, 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 2014,  87 percent of our power was generated from gas. Of that gas-fired generation, 57 and 43 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 the first quarter of 2015,  is expected to provide an additional 13.3 MW for our wholesale customers. In the second quarter of 2015, the project is expected to provide up to 0.9 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), annually.  We purchased approximately 40 MW from the Nikiski Power Plant and approximately 67 MW from the Bernice Lake Power Plant on the Kenai Peninsuladuring the year ended December 31, 2013. We operate 1,699 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, 2014, we sold 2.3 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, 2014:

	MWh	2014 Revenues		Percent of Sales Revenue
Direct retail sales:
Residential	513,748	$	81,880,150	30	%
Commercial	620,779		80,454,791	29	%
Total	1,134,527		162,334,941	59	%
Wholesale sales:
MEA	764,025		70,694,965	26	%
Seward	61,499		4,833,205	2	%
Total	825,524		75,528,170	28	%
Economy energy/other1	358,988		36,896,019	13	%
Total from sales	2,319,039		274,759,130	100	%
Miscellaneous energy revenue			6,559,383
Total energy revenues		$	281,318,513

1Economy energy/other includes sales toGVEA.

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Retail Service Territory

Our retail service area covers much of the populated areas of Anchorage (other than downtown Anchorage) as well as remote mountain areas and villages.  The service area ranges from the northern Kenai Peninsula on the south, to Tyonek on the west, including Fire Island, to Whittier on the east and to the Glenn Highway on the north.

Retail Customers

As of December 31, 2014, we had 68,241members receiving power from approximately 83,081 services, including idle services (some members are served by more than one service).  Our customers are a mix of 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.  The revenue contributed by retail customers for the years ended December 31, 2014, 2013 and 2012 is discussed in Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Year ended December 31, 2014, compared to the year ended December 31, 2013, and the year ended December 31, 2013, compared to the year ended December 31, 2012 – Revenues.

Wholesale Customers

We are the principal supplier of power to MEA and Seward under separate wholesale power contracts.  We were also the principal supplier of power to HEA through December 31, 2013.  Our wholesale power contracts, including the fuel and purchased power components, contributed$75.5 million, $108.0 million, and $105.4 millionin revenues for the years ended December 31, 2014, 2013 and 2012, respectively.

MEA

We currently have a power sales contract with Alaska Electric Generation & Transmission Cooperative, Inc., (AEG&T) for firm, all-requirement sales to MEA.  AEG&T is a generation and transmission cooperative that was formed by MEA and HEA in the mid 1980’s.  Under this contract, we sell power to AEG&T for resale to MEA.  Under this contract, MEA is obligated to purchase all of its electric power and energy requirements from us.  This MEA contract was in effect through December 31, 2014.  Under this contract, MEA was  obligated to pay us for power sold to AEG&T even if AEG&T did not pay.Sales to MEA represented approximately 33 percent, 27 percent, and 30 percent of Chugach’s total energy sales for the years ended December 31, 2014, 2013, and 2012, respectively.

The terms of the Power Sales Agreement with MEA required 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.  In 2004, pursuant to this provision of the contract, MEA communicated to Chugach that MEA did not desire to renew, extend or modify the agreement. 

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After open discussions and proposals regarding power sales possibilities beyond 2014, in February of 2012, Chugach received a response from MEA which indicated it would follow the path its membership most favored and move forward with plans to build its own generation plant and confirmed it would not renew the contract.

On August 12, 2014, MEA notified Chugach that their newly constructed power plant, the Eklutna Generation Station (EGS), would not be completed by January 1, 2015.  On September 30, 2014, Chugach entered into an Interim Power Sales Agreement to provide MEA with all demand and energy requirements on a firm basis based on existing tariff rates for a minimum one quarter period beginning on January 1, 2015, and ending on March 31, 2015.

Pursuant to the agreement, MEA was required to notify Chugach if it planned to exercise an option to extend the agreement an additional quarter.  On January 5, 2015, MEA notified Chugach that it would not be extending the agreement.  On January 30, 2015, MEA notified Chugach that it had four units available to pool with Chugach units to meetthe combined system load of Chugach and MEA. These units were subsequently placed into economic dispatch. 

On December 22, 2014, Chugach entered into a dispatch services agreement with MEA to provide electric and natural gas dispatch services for EGS, electric dispatch services for MEA’s share of the Bradley Lake Hydroelectric Project and electric dispatch coordination services for MEA’s share of the Eklutna Hydroelectric Project effective on or about April 1, 2015.  The term of the agreement expires on March 31, 2016, unless extended by MEA through March 31, 2017.  The agreement is currently awaiting RCA approval.

In an agreement reached in May of 2014 with MEA, capital credits retired to MEA are classified as patronage capital payable on Chugach’s Balance Sheet.  MEA’s patronage capital payable was $2.3 million at 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.  Sales to HEA represented approximately 16 percent and 19 percent of Chugach’s total energy sales for the years ended December 31, 2013 and 2012, respectively.

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 previously leased to Chugach by HEA. 

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.

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Chugach continued to dispatch the power plant until the expiration of its power sales agreement with HEA, therefore, in December of 2013, Chugach recognized the gain associated with this sale which amounted to $6.4 million.

HEA’s resource requirements are now 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 also had a dispatch agreement with AEEC to operate the Nikiski unit as a Chugach system resource, which 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 payable was $7.9 million at December 31, 2014, and must be returned to HEA by December 31, 2018.

Seward

We currently provide nearly all the power needs of the City of Seward.  Sales to Seward represented approximately 3 percent, 2 percent, and 3 percentof Chugach’s total energy sales for the years ended December 31, 2014, 2013, and 2012, respectively.  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 an obligation to provide reserves (MEA and Chugach retail customers).  The price under the 2006 Agreement reflects the reduced level of service because no costs of generation in excess of that needed to meet the system peak is assigned to Seward.

Economy Customers

Since 1989, we have sold economy (non-firm) energy to GVEA.  We use available generation in excess of our own needs to produce electric energy for sale to GVEA, which uses that energy to serve its own loads.

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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 were 358,988 MWh,  351,390 MWh and 90,765 MWh for 2014, 2013, and 2012, 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 no later than 15 months after a complete tariff filing is made for a tariff filing that changes the utility’s revenue requirement or rate design.  It is within the RCA’s authority to authorize, after a notice period, rate changes on an interim, refundable basis.  In addition, the RCA has been willing to open limited reviews of matters to resolve specific issues from which expeditious decisions can often be rendered.

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

We expect to continue to recover changes in our fuel and purchased power expenses through routine quarterly filings with the RCA, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations – Overview – Rate Regulation and Rates – Fuel and Purchased Power Recovery.”

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The Second Amended and Restated Indenture of Trust (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, 2014, 2013 and 2012, our Margins for Interest/Interest (MFI/I) was 1.28, 1.43, and 1.23, respectively.  For the same periods, our TIER was 1.29, 1.43, and 1.24, respectively.  The increase in MFI/I and TIER in 2013 was caused by the recognition of the gain on the sale of the Bernice Lake Power Plant.

Our Service Areas and Local Economy

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

Anchorage is located in the Southcentral region of Alaska and is the trade, service, medical and financial center for most of Alaska and serves as a major center for many state governmental functions.  Other significant contributing factors to the Anchorage economy include a large federal government and military presence, tourism, medical, financial and educational facilities, air and rail transportation facilities and headquarters support for the petroleum, mining and other basic industries located elsewhere in the state.

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

Seward is a city located at the head of Resurrection Bay on the Kenai Peninsula. Seward, which is approximately 127 miles south of Anchorage, is a major fisheries port and also serves as the ocean terminus of the Alaska Railroad. Seward’s other major industry is tourism.

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. 

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Sales Forecasts

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

Sales (MWh)	2015	2016	2017	2018	2019
Retail	1,154,546	1,156,000	1,157,000	1,159,000	1,161,000
Wholesale	284,335	64,000	64,000	64,000	64,000
Economy	95,220	0	0	0	0
Total	1,534,101	1,220,000	1,221,000	1,223,000	1,225,000

Retail energy sales are expected to remain relatively flat due to slow economic growth and progress in energy efficiency and conservation from 2015 to 2019.  At the end of March 2015, MEA’s contract to purchase their full requirements from Chugach expires, resulting in a decrease of approximately 77 percent in wholesale energy sales from 2015 to 2016.  The decrease in economy energy sales is due to the expected expiration of GVEA’s contract at the end of March 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, 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 2015, 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.  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.If Chugach’s effort to recover the remaining fixed cost contribution as result of the termination of the wholesale power contracts with MEA and HEA is not successful,ourability to obtain future financing or the cost associated with future financing efforts could be negatively impacted.

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Wholesale Contracts

As previously discussed, MEA terminated its wholesale power contract with Chugach effective December 31, 2014, but subsequently entered into an interim wholesale power contract that will run through March 31, 2015.  MEA’s contract with Chugach, including the fuel component, represented $70.7 million, or 26 percent,of total sales revenuein 2014.Upon expiration of the Interim Power Sales Agreement on March 31, 2015, MEA intends to leave the Chugach system. This is expected to result in a loss of approximately 33 percent of Chugach’s power sales and approximately 26 percent of the utility’s annual sales revenue.

Chugach’s planning process reflects the expected termination of the MEA wholesale contract.  Consequently, to mitigate this risk, Chugach continues to pursue replacement sources of revenue through potential new power sales and dispatch agreements and transmission wheeling and ancillary services tariff revisions.  On December 22, 2014, Chugach entered into a dispatch services agreement with MEA to provide electric and natural gas dispatch services for EGS, electric dispatch services for MEA’s share of the Bradley Lake Hydroelectric Project and electric dispatch coordination services for MEA’s share of the Eklutna Hydroelectric Project effective on or about April 1, 2015.  The term of the agreement expires on March 31, 2016, unless extended by MEA through March 31, 2017.  The agreement is currently awaiting RCA approval.

The impending loss of MEA, as a wholesale customer, required Chugach to file a general rate case on February 13, 2015, to recover total costs and restructure rates.  Since the general rate case could take up to fifteen months to be completed, Chugach requested an interim and refundable rate increase.  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 results of operations, financial condition, and 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.

War, acts and threats of terrorism, sabotage, cyber security breach, natural disaster, and other significant events could adversely affect our operations

We cannot predict the impact that any future terrorist attacks, sabotage, or natural disaster may have on the energy industry in general, or on our business in particular.  Any such event may affect our operations in unpredictable ways, such as changes in insurance markets.  Furthermore, electric generation, transmission and distribution facilities could be direct targets of, or indirect casualties of, an act of terror, sabotage, or cyber security breach.  The physical or cyber security compromise of our facilities could adversely affect our ability to manage our

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facilities effectively.  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.

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).  The RS Plan’s funding status is governed by plan rules as provided by ERISA.Chugach receives information concerning its funding status biannually.  The RS Plan is not subject to the Pension Protection Act of 2006 under a permanent exemption from Congress as of December 16, 2014.  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 a service plan 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.

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Fuel Supply

In 2014, 87 percent of our power was generated from natural gas.  Our primary suppliers of natural gas are ConocoPhillips and Hilcorp. Chugach currently has gas contracts in place to fill up to 100 percent of Chugach’s needs through March 31, 2019.  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.  These incentives have resulted in significant improvement in gas production from existing fields and exploration for new supplies.  The two major Cook Inlet area gas producers, Hilcorp and ConocoPhillips, have gas supply agreements with local utilities for deliveries into the year 2019.  Furie Operating Alaska, LLC has constructed an offshore gas production platform and procured undersea gas pipe that it expects to install in the summer of 2015.  Other gas producers are actively developing on-shore gas supplies in Cook Inlet.  The State of Alaska received approximately $6.3 million in bids at its Cook Inlet 2014 area-wide oil and gas lease sale.  Chugach is encouraged with these developments but continues to explore other alternatives to diversify its portfolio.

Since 2012, Hilcorp has acquired significant oil and gas assets in the Cook Inlet and reworked those assets to increase production, and several other developers have brought new sources of gas production online.  As a result, 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 liquefied natural gas (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.  ConocoPhillips exported approximately 13 Bcf of gas as LNG in 2014.

Hilcorp consolidated the operations and tariff for the four major gas pipelines in the Cook Inlet basin into the Kenai-Beluga Pipeline (KBPL) in 2014.  On November 1, 2014, the RCA approved the consolidation.  Prior to consolidation, gas transportation cost could make development of new gas fields cost prohibitive because the gas transport rates varied with flow and the number of pipelines the gas had to cross to transport gas.  The consolidation provides gas producers a single rate for shipping gas on all of the four pipelines, which makes development of gas fields anywhere on the gas pipeline system more attractive to gas producers.

A project commenced by Alaska Gasline Development Corporation and affiliates of BP, ConocoPhillips, ExxonMobil and TransCanada (together, project participants) to construct a liquefaction facility, gas pipeline, and gas treatment plant is underway through a pre-filing process accepted by FERC.  The mainline gas pipeline is expected to include off-take points to allow for the opportunity for future in-state deliveries of natural gas.  The project participants are targeting to file a formal application with FERC in the fall of 2016.  FERC authorizations for the project and commencement of construction are anticipated in the 2018-2019 timeframe, with operation in the 2024-2025 timeframe.

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Cook Inlet Natural Gas Storage Alaska (CINGSA) began service April 1, 2012.  The facility ensures local utilities, including Chugach, have gas available to meet deliverability requirements during peak periods and store gas during low demand periods.  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.  Injections into the facility began in 2012. Chugach's share of the capacity is 1.9 Bcf.  Chugach is entitled to withdraw gas at a rate of up to 35 million cubic feet (MMcf) per day.

Cooper Lake Hydroelectric Project

In August of 2007, Chugach received 50-year license from FERC for the Cooper Lake Hydroelectric Project.  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 total project cost is now estimatedat $22.3 million.  As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska.  Funding for this project includes $9.9 million in grants awarded.  The Chugach Board authorized expenditures for the project on November 15, 2012.  The diversion project began construction in 2013 and will be completed in 2015.  Chugach expects to operate the hydroelectric project through the duration of the license.

Other Environmental Regulations

Chugach is currently required to comply with numerous federal, state and local laws and regulations relating to the protection of the environment. While we believe Chugach has obtained all material environmental-related approvals currently required to own and operate our facilities, Chugach 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 Chugach, 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 facilitiescould result in significant additional costs to Chugach and a material negative impact to Chugach’s results of operations, financial condition, and cash flows.

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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, 2014, Chugach had over-recovered $1.5 million and at December 31, 2013, Chugach had over-recovered $1.6 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 2013 General Rate Case on November 19, 2013, to reflect revenue and cost changes resulting from the expiration of HEA’s wholesale contract.  On January 2, 2014, the proposed rates became effective on an interim and refundable basis for retail and wholesale customers in January 2014 and February 2014, respectively.  On November 13, 2014, the RCA accepted the stipulation entered into among the parties in the case.  On February 12, 2015, the RCA issued a final order,  see  “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – 2013 General Rate Case.”

To reflect revenue and cost changes resulting from the impending expiration of MEA’s wholesale contract, Chugach filed a 2014 Test Year General Rate Case with the RCA on February 13, 2015, with interim and refundable rates effective April 1, 2015.  To the extent the RCA does not allow for the recovery of our costs associated with our current or anticipated 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, the 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.  On June 2, 2014, the EPA released a proposed regulation aimed at reducing emissions of carbon dioxide (CO₂) from existing power

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plants that provide electricity for utility customers.  In the draft rule, the EPA took the approach of making individual states responsible for the development and implementation of plans to reduce the rate of CO₂ emissions from the power sector.  A final rule is expected in June 2015, with state plans due to the EPA in June 2016.  Chugach is subject to this proposed regulation, however, in its current form, we do not expect the regulation to have a material effect on our results of operations, financial position, and cash flows.

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 2014, 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 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 2014, we also purchased power from Fire Island Wind, LLC (FIW).  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.”

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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, 2013, and 2014.  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, 2013 and 2014.  Beluga Unit 8, a steam turbine generator, received a major inspection in 2012.  Annual inspections were performed on Unit 8 in 2011, 2013, and 2014.

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 and 2014, 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 replace 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 2015.

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 inspections in October of 2012 and 2013.  In 2014, both units again received annual maintenance in October.  The 2014 annual maintenance included generator testing and inspection by the OEM.

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.

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The following matrix depicts nomenclature, run hours for 2014, percentages of contribution and other historical information for all Chugach generation units.

Facility	Commercial Operation Date	Nomenclature	Rating (MW)(1)	Run Hours (2014)	Percent of Total Run Hours	Percent of Time Available
(3)
1	1968	GE Frame 5	19.6	431.9	0.66	97.1
2	1968	GE Frame 5	19.6	427.7	0.66	93.2
3	1973	GE Frame 7	64.8	2,484.9	3.81	94.1
5	1975	GE Frame 7	68.7	2,774.3	4.25	94.1
6	1976	AP 11DM-EV	79.2	5,683.5	8.70	91.0
7	1978	AP 11DM-EV	80.1	7,505.2	11.49	94.6
8	1981	BBC DK021150(2)	53.0	8,032.2	12.30	92.3
Cooper Lake Hydroelectric Project			385.0
1	1960	BBC MV 230/10	9.6	1,681.0	2.57	95.7
2	1960	BBC MV 230/10	9.6	2,995.0	4.59	95.7
IGT Power Plant			19.2
1	1964	GE Frame 5	14.1	100.1	0.15	69.8
2	1965	GE Frame 5	14.1	57.8	0.09	98.0
3	1969	Westinghouse 191G	18.5	23.4	0.04	98.4
Southcentral Power Project			46.7
10	2013	Mitsubishi SC1F-29.5(7)	40.2(6)	8,513.8	13.04	99.9
11	2013	GE LM6000 PF	33.3(6)	8,125.8	12.45	96.3
12	2013	GE LM6000 PF	33.3(6)	8,242.3	12.62	97.1
13	2013	GE LM6000 PF	33.3(6)	8,215.4	12.58	96.1
Eklutna Hydroelectric Project			140.1
1	1955	Newport News	5.8(4)	N/A(5)	N/A(5)	96.6
2	1955	Oerlikon custom	5.9(4)	N/A(5)	N/A(5)	92.1
			11.7
System Total			602.7	65,294.3	100.00

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

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

(3)Beluga Unit 4 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 23.5MW.

(5)Run hours 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.

(7)Steam-turbine powered generator with heat provided by exhaust from natural gas fueled Units 11, 12 and 13 and additional heat from supplemental duct firing in the once through steam generators associated with the respective gas turbines (combined cycle).

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

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Transmission and Distribution Assets

As of December 31, 2014, 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, 901 miles of overhead distribution lines and 798 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 generation sites and many of its substation sites are on Chugach-owned lands.  The rights for the sites not on Chugach-owned lands are as follows:  the Postmark and Point Woronzof 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 on State land under rights from the Federal Bureau of Land Management; the Hope and Daves Creek Substations are under rights from the State; the Portage Substation is under rights from the Alaska Railroad Corporation (ARRC); the Summit Lake Substation is on State land under rights from the United States Forest Service; the Dowling and Raspberry Substations are on Municipality of Anchorage land under rights from the State; and, the Indian Substation will be under rights from the Chugach State Park upon approval.  The Cooper Lake Power Plant,  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.

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

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

Other Property

Bradley Lake.  We are a participant in the Bradley Lake Hydroelectric Project, which is a 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 currently 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 $24.0 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 $5.5 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.

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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).  In 2014 and through March 31, 2015, 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 2014, 87 percent of our power was generated from natural gas.Total gas purchased in 2014 was approximately 20 Bcf.  In 2014, our sources of natural gas for firm sales were primarily divided among contracts with two major oil and gas companies.  All of the production came from Cook Inlet, Alaska.  ConocoPhillips under their current contract provided 46 percent of gas supplied for generation, while Hilcorp provided 54 percent.  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, 2019.  ConocoPhillips and Hilcorp, together, fill up to 100 percent of Chugach’s firm needs through March 31, 2019.  Gas to provide economy energy sales to GVEA is supplied by a gas supply arrangement with Hilcorp through March of 2015.

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.  All of the gas purchased under the contract is now firm fixed since firm variable gas was 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 involved 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 was 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 is 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.

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.

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Marathon Alaska Production/Hilcorp

We entered into a contract with MAP effective May 17, 2010, to provide gas beginning April 1, 2011, through December 31, 2014, which included 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 2014 term of the Hilcorp contract was set at the contract floor price of $6.18 per Mcf. Pricing for the 2015 term is $7.13 per Mcf.

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, 2012, Chugach entered into a Gas Sales and Purchase Agreement with Hilcorp for the purchase of gas with an effective period of April 1, 2013, 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 process.

The agreement may supply gas from April 1, 2014, through March 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:

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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.

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.

Harvest 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 through Harvest Alaska, LLC, in the Cook Inlet basin, including the Kenai-Nikiski Pipeline (KNPL), the Beluga Pipeline (BPL), the 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. 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 a firm capacity rate of $2.13 per Mcf.  This agreement ended effective October 31, 2014. 

On November 1, 2014, the RCA approved consolidation of these four pipelines into a single pipeline, the KBPL.  Chugach has entered into tariff agreements to ship gas on the KBPL.

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 EPA regulations under the Clean Air Act establish ambient air quality standards and limit the emission of many air pollutants.  New Clean Air Act regulations impacting electric utilities may result from future events or new regulatory programs.  On June 2, 2014, the EPA released a proposed regulation aimed at reducing emissions of CO₂ from existing power plants that provide electricity for utility customers.  In the draft rule, the EPA took the approach of making individual states responsible for the development and implementation of plans to reduce the rate of CO₂ emissions from the power sector.  A final rule is expected in June 2015,

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with state plans due to the EPA in June 2016.  Chugach is subject to this proposed regulation, however, in its current form, we do not expect the regulation to have a material effect on our financial condition, results of operations, or cash flows.  While Chugach cannot predict the implementation of any additional new law or regulation, or the limitations thereof, it is possible that new laws or regulations could increase capital and operating costs.  Chugach has obtained or applied for all Clean Air Act permits currently required for the operation of 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.  Chugach does not believe that compliance with these statutes and regulations to date has had a material impact on its financial condition, results of operation or cash flows.  However, the implementation of any new law or regulation, or limitation thereof, or changes in or new interpretations of laws or regulations could result in significant additional capital or operating expenses.  Chugach monitors proposed new regulations and existing regulation changes through industry associations and professional organizations.

Item 3 – LegalProceedings

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.  MEA fundamentally asked 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 parties reached an agreement to settle this litigation and on June 5, 2014, the Court issued an order dismissing the case without prejudice.

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 repatriated to customers at the discretion of Chugach’s Board of Directors, typically many years after the margins are earned.  With this litigation, MEA sought to accelerate the return of its capital credits.

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 – MineSafety Disclosures

Not Applicable

PART II

Item 5 – Marketfor Registrant's

Common Equity, Related Stockholder Matters and

Issuer Purchases of Equity Securities

Not Applicable

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Item 6 – SelectedFinancial 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	2014		2013		2012		2011		2010
Electric plant, net:
In service	$	657,899,592	$	670,476,634	$	442,515,434	$	392,080,033	$	407,351,421
Construction work in progress		21,567,341		28,674,163		263,459,794		206,005,783		100,787,482
Electric plant, net		679,466,933		699,150,797		705,975,228		598,085,816		508,138,903
Other assets		126,244,688		139,033,241		156,626,138		254,843,842		121,588,825
Total assets	$	805,711,621	$	838,184,038	$	862,601,366	$	852,929,658	$	629,727,728
Capitalization:
Long-term debt		472,024,497		496,914,274		521,597,086		296,090,108		304,450,318
Equities and margins		176,925,299		175,795,865		166,764,373		161,231,426		161,842,284
Total capitalization	$	648,949,796	$	672,710,139	$	688,361,459	$	457,321,534	$	466,292,602
Equity Ratio1		27.3%		26.1%		24.2%		35.3%		34.7%
Operations Data
Operating revenues	$	281,318,513	$	305,308,427	$	266,971,468	$	283,618,369	$	258,325,345
Operating expenses		252,972,879		278,738,497		248,194,955		262,341,866		233,967,201
Interest expense		23,264,041		24,691,582		24,085,371		18,681,680		21,014,387
Capitalized interest		(463,335)		(1,310,110)		(9,682,440)		(1,934,703)		(1,008,689)
Net operating margins		5,544,928		3,188,458		4,373,582		4,529,526		4,352,446
Nonoperating margins		970,617		7,355,585		1,151,925		1,043,736		1,057,563
Assignable margins	$	6,515,545	$	10,544,043	$	5,525,507	$	5,573,262	$	5,410,009
Margins for Interest Ratio2		1.28		1.43		1.23		1.30		1.26

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.

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Item 7 – Management's Discussion and Analysis

of Financial Condition and Results of Operations

Caution Regarding Forward Looking Statements

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

Results of Operations

Overview

Margins.  We operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to pay operating and maintenance costs, the cost of fuel and purchased power, capital expenditures, depreciation and principal and interest on our indebtedness and to provide for reserves.  These amounts are referred to as “margins.”  Patronage capital, the retained margins of our members, constitutes our principal equity.

Times Interest Earned Ratio (TIER).Alaska electric cooperatives generally set their rates on the basis of TIER, which is a debt service coverage approach to ratemaking.  TIER is determined by dividing the sum of assignable margins plus long-term interest expense (excluding capitalized interest) by long-term interest expense (excluding capitalized interest).  Chugach’s long-term interest expense for the years ended December 31, 2014, 2013 and 2012 was $22,820,866,$24,378,162, and $22,944,194, 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 increase in TIER in 2013 was caused by the recognition of the gain on the sale of the Bernice Lake Power Plant.  The increase in 2011 and 2010 was due to certain debt classified as short-term, which was replaced with long-term debt in 2012.

Chugach’s achieved TIER includes nonoperating margins that are not generated by electric rates. We manage our business with a view towards achieving our authorized TIER (currently 1.30) averaged over a 5-year period.  For further discussion on factors that contribute to TIER results, see “Item 7 – Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Year ended December 31, 2014, compared to the year ended December 31, 2013, and the year ended December 31, 2013 compared to the year ended December 31, 2012 – Expenses.”  We achieved TIERs for the past five years as follows:

1	24
Year	TIER
2014	1.29
2013	1.43
2012	1.24
2011	1.58
2010	1.44

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

On November 12, 2012, base demand and energy rates decreased 2.1 percent, 1.9 percent and 1.7 percent to HEA, MEA and Chugach retail customers, respectively, and increased 1.6 percent to Seward.  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.

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 fixed price or fuel price adjustment processes in our gas-supply contracts.  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

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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.

Year ended December 31, 2014, compared to the year ended December 31, 2013, and the year ended December 31, 2013 compared to the year ended December 31, 2012

Margins

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

	2014		2013		2012
Net Operating Margins	$	5,544,928	$	3,188,458	$	4,373,582
Nonoperating Margins	$	970,617	$	7,355,585	$	1,151,925
Assignable Margins	$	6,515,545	$	10,544,043	$	5,525,507

The increase in net operating margins in 2014 from 2013 of $2.4 million, or 73.9%, was due primarily to a decrease in depreciation expense associated with Beluga Unit 8 assets, and a decrease in net interest,and was somewhat offset by a decrease in revenue.  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 SPP, which was somewhat offset by an increase in economy revenue and a decrease in distribution expense.

Nonoperating margins include interest income, Allowance for Funds Used During Construction (AFUDC), capital credits and patronage capital allocations and other.  Nonoperating margins decreased in 2014 over 2013 and increased in 2013 over 2012 due primarily by the recognition of the gain on the sale of the Bernice Lake Power Plant on December 31, 2013.

Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues.  In 2014, operating revenues were $24.0 million, or 7.9% percent lower than 2013.  The decrease was due primarily to lower wholesale revenue caused by the expiration of the HEA wholesale contract, which was somewhat offset by higher rates charged to both retail and wholesale customers as a result of Chugach’s 2013 Test Year Rate Case and higher economy energy sales.

In 2013, operating revenues were $38.3 million, or 14.3% 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 energy sales.

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Retail revenue increased $7.1 million, or 4.6%, in 2014 from 2013.  Base revenue increased due to an increase in rates charged to retail customers as a result of Chugach’s 2013 Test Year General Rate Case, which was somewhat offset by lower retail energy sales caused by warmer weather.  Fuel and purchased power revenue did not materially change in 2014 from 2013.

Wholesale revenue decreased $32.5 million, or 30.1%, in 2014 from 2013, due primarily to the expiration of HEA’s wholesale contract.

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 firm 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.

Based on the results of fixed and variable cost recovery established in Chugach’s rate filings, wholesale sales to MEA, HEA and Seward in total contributed approximately $27.5 million, $35.5 million, and $27.5 million to Chugach’s fixed costs for the years ended December 31, 2014, 2013 and 2012, respectively.

The following table shows base rate sales revenue and fuel and purchased power revenue by customer class included in revenue for the years ended December 31, 2014, and 2013.

	Base Rate Sales Revenue							Fuel and Purchased Power Revenue							Total Revenue
		2014		2013		% Variance			2014		2013		% Variance			2014		2013		% Variance
Retail
Residential		$	54.4	$	50.9	6.9	%		$	27.5	$	28.3	(2.8	%)		$	81.9	$	79.2	3.4	%
Small Commercial		$	9.6	$	8.8	9.1	%		$	6.4	$	6.5	(1.5	%)		$	16.0	$	15.3	4.6	%
Large Commercial		$	36.1	$	32.5	11.1	%		$	26.6	$	26.6	0.0	%		$	62.7	$	59.1	6.1	%
Lighting		$	1.5	$	1.4	7.1	%		$	0.2	$	0.2	0.0	%		$	1.7	$	1.6	6.3	%
Total Retail		$	101.6	$	93.6	8.5	%		$	60.7	$	61.6	(1.5	%)		$	162.3	$	155.2	4.6	%
Wholesale
HEA		$	0.0	$	15.5	(100.0	%)		$	0.0	$	22.3	(100.0	%)		$	0.0	$	37.8	(100.0	%)
MEA		$	34.6	$	28.4	21.8	%		$	36.1	$	37.0	(2.4	%)		$	70.7	$	65.4	8.1	%
SES		$	1.9	$	1.7	11.8	%		$	2.9	$	3.1	(6.5	%)		$	4.8	$	4.8	0.0	%
Total Wholesale		$	36.5	$	45.6	(20.0	%)		$	39.0	$	62.4	(37.5	%)		$	75.5	$	108.0	(30.1	%)
Economy		$	2.6	$	2.7	(3.7	%)		$	34.3	$	35.1	(2.3	%)		$	36.9	$	37.8	(2.4	%)
Miscellaneous		$	1.7	$	2.0	(15.0	%)		$	4.9	$	2.3	113.0	%		$	6.6	$	4.3	53.5	%
Total Revenue		$	142.4	$	143.9	(1.0	%)		$	138.9	$	161.4	(13.9	%)		$	281.3	$	305.3	(7.9	%)

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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		$	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	10.5	%		$	305.3	$	267.0	14.3	%

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

	2014	2014		2013	2013		2012	2012
	Sales (MWh)	Revenue		Sales (MWh)	Revenue		Sales (MWh)	Revenue
Retail	1,134,527	$	162,334,941	1,162,364	$	155,208,714	1,178,836	$	149,355,192
Wholesale:
HEA	0		0	463,582		37,788,679	488,941		38,344,762
MEA	764,025		70,694,965	773,836		65,352,294	782,510		62,278,074
Seward	61,499		4,833,205	64,507		4,830,063	65,671		4,801,814
Total Wholesale	825,524		75,528,170	1,301,925		107,971,036	1,337,122		105,424,650
Economy energy	358,988		36,896,019	351,390		37,764,494	90,765		9,025,467
Other	N/A		6,559,383	N/A		4,364,183	N/A		3,166,159
Total	2,319,039	$	281,318,513	2,815,679	$	305,308,427	2,606,723	$	266,971,468

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 through 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.

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In 2014, 2013, and 2012, economy sales to GVEA constituted approximately 13percent, 12 percent, and 3 percent, respectively, of our sales revenues.  Economy energy revenue did not materially change in 2014 from 2013.  Economy energy revenue increased in 2013 from 2012 due to additional sales to GVEA as a result of a new contract.

Expenses

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

	2014		2013		2012
Fuel	$	126,038,350	$	136,610,262	$	125,836,659
Power production		21,082,176		21,911,324		16,739,931
Purchased power		15,608,396		27,836,680		22,104,687
Transmission		6,138,658		6,624,836		5,802,009
Distribution		13,002,157		13,225,242		15,822,104
Consumer accounts		5,887,713		6,014,888		6,013,419
Administrative, general and other		25,036,248		23,131,149		23,519,246
Depreciation		40,179,181		43,384,116		32,356,900
Total operating expenses	$	252,972,879	$	278,738,497	$	248,194,955

Fuel

Chugach recognizes actual fuel expense as incurred.  Fuel expense decreased $10.6 million, or 7.7%, in 2014 from 2013.  The decrease was due primarily to a decrease in the natural gas used, due primarily to the expiration of HEA’s wholesale contract, and lower transportation costs which was somewhat offset by an increase in the average effective delivered price.  In 2014, Chugach used 20,216,736 Mcf of fuel at an average effective delivered price of $5.95 per Mcf.  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.

Power Production

Power production expense did not materially change in 2014 from 2013.  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.

Purchased Power

Purchased power expense decreased $12.2 million, or 43.9%, in 2014 from 2013, due primarily to less energy purchased caused by a decrease in purchase requirements as a result of the expiration of HEA’s wholesale contract, which was somewhat offset by an increase in the average effective price.  In 2014, Chugach purchased 240,887 MWh of energy at an average effective price of 5.38 cents per kWh.  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.

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Transmission

Transmission expense decreased $0.5 million, or 7.3%, in 2014 from 2013, due primarily to less substation and overhead line maintenance, as well as the expiration of leases associated with HEA’s wholesale and other related contracts.  Transmission expense increased $0.8 million, or 14.2%, in 2013 from 2012, due primarily to an increase in substation maintenance.

Distribution

Distribution expense did not materially change in 2014 from 2013.  Distribution expense decreased $2.6 million, or 16.4% in 2013 from 2012, due primarily to lower costs associated with storm related line maintenance.

Consumer Accounts

Consumer Accounts expense did not materially change in 2014 from 2013 or in 2013 from 2012.

Administrative, General and Other Expense

Administrative, general and other expense increased  $1.9 million, or 8.2%, in 2014 from 2013, due primarily to accrued workers’ compensation, higher labor expense and costs associated with projectstudies.  Administrative, general and other expense did not materially change in 2013 from 2012.

Depreciation

Depreciation and amortization expense decreased $3.2 million, or 7.4%, in 2014 from 2013, due primarily to depreciation associated with Beluga Unit 8 assets.  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 were placed into service in 2013.

Interest

Interest on long-term debt and other decreased $1.4 million, or 5.8%, in 2014 from 2013, reflecting the principal payments made on long-term debt.  Interest on long-term and other debt did not materially change in 2013 from 2012.

Interest charged to construction decreased $0.8 million, or 64.6%, in 2014 from 2013 due primarily to a decrease in the average construction work in progress (CWIP) balance caused by the timing of commercial operation of SPP in 2013.Interest charged to construction decreased $8.4 million, or 86.5%, in 2013 from 2012, due primarily to a decrease in the average CWIP balance caused by the commercial operation of SPP in February of 2013.

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Patronage Capital (Equity)

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

	2014		2013		2012
Patronage capital at beginning of year	$	162,749,889	$	153,832,674	$	148,355,246
Retirement/net transfer of capital credits		(5,130,381)		(1,626,828)		(48,079)
Assignable margins		6,515,545		10,544,043		5,525,507
Patronage capital at end of year		164,135,053		162,749,889		153,832,674
Other equity1		12,790,246		13,045,976		12,931,699
Total equity at end of year	$	176,925,299	$	175,795,865	$	166,764,373

1Other 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.

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.  Capital credits retired, net of HEA’s allocations, were $5,130,381, $1,626,828, and $48,079 for the years ended December 31, 2014, 2013, and 2012, 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.

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Changes in Financial Condition

Assets

Total assets decreased $32.5 million, or 3.9%, in 2014 from 2013.  Net utility plant decreased $19.7 million, or 2.8%, caused by depreciation expense in excess of extension and replacement of plant.  Cash and cash equivalents increased $12.0 million, or 276.5%, in 2014 over 2013 due primarily to the investment in a money market fund as a result of the sale of marketable securities and further increased due to various changes described below.  Marketable securities decreased $10.3 million, or 100.0%, in 2014 from 2013, due to the aforementioned sale and accounts receivable decreased $8.6 million, or 19.2%, due primarily to the receipt of grant funding and state and municipal relocation projects accrued in 2013.  Restricted cash equivalents decreased $0.9 million, or 23.2%, in 2014 from 2013 as a result of the reserve requirements for workers’ compensation and the refund of interim rates collected from customers and escrowed as required by the RCA.  Fuel stock decreased $3.4 million, or 25.9%, due primarily to the use of fuel from the fuel storage facility.  Deferred charges decreased $2.6 million, or 10.9%, due primarily to annual amortization and recovery of such costs from customers.

Liabilities and Equity

Total liabilities, equities and margins decreased $32.5 million, or 3.9%, in 2014 as compared to 2013.  Long term obligations decreased $24.9 million, or 5.0%, caused by principal payments on Chugach’s bonds and commercial paper decreased $9.0 million, or 30.0%, due primarily to the increase in cash and cash equivalents.  Fuel payable decreased $3.7 million, or 24.9%, as a result of less fuel purchased and other liabilities decreased $0.5 million, or 10.7%, due primarily to the payment of capital credits retired.  These decreases were somewhat offset by an increase in total equities and margins, other liabilities, patronage capital payable, and cost of removal obligations.  Total equities and margins increased $1.1 million, or 0.6%, primarily due to the margins generated in 2014.  Patronage capital payable increased $2.3 million or 28.7%, due to the assignment of MEA’s 2014 patronage.  Cost of removal obligation increased $3.6 million, or 7.6%, 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 2014.  Chugach’s gas contracts provide for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel recovery process, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not significantly affect our operations.

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Contractual Obligations and Commercial Commitments

The following are Chugach’s contractual and commercial commitments as of December 31, 2014:

Contractual cash obligations – Payments Due By Period

(In thousands)	Total		2015		2016-2017		2018-2019		Thereafter
Long-term debt, including current portion	$	496,914	$	23,890	$	48,479	$	49,557	$	374,988
Long-term interest expense1		270,608		20,939		38,861		34,766		176,042
Commercial Paper2		21,000		21,000		0		0		0
Bradley Lake3		29,520		3,609		7,434		7,492		10,985
Fuel and fuel transportation expense4		227,016		54,770		123,280		48,966		0
Stetson Creek Commitments5		2,141		2,141		0		0		0
Capital Credit Retirements6		7,931		0		0		7,931		0
Total	$	1,055,130	$	126,349	$	218,054	$	148,712	$	562,015

1Long-term interest expense includes fixed and variable rates.  Variable rates are based on rates at December 31, 2014, for years 2015-2019 and thereafter, see “Item 8 – Financial Statements and Supplementary Data – Note 11 – Debt.”

2At December 31, 2014, Chugach’s Commercial Paper Program was backed by a $100.0 million Unsecured Credit Agreement, which funds capital requirements.  At December 31, 2014, there was $21.0 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $79.0 million and could be used for future operational and capital funding requirements.

3Estimated 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 indices used to index the price of our ConocoPhillips contract and is inherently difficult to predict. We pass fuel costs directly to our wholesale and retail customers through the fuel recovery process, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Overview – Rate Regulation and Rates – Fuel and Purchased Power Recovery.”

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In August of 2007, Chugach received a 50-year license from FERC for the Cooper Lake Hydroelectric Project.  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 total project cost is now estimatedat  $22.3 million.  As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska. Funding for this project includes $9.9 million in grants awarded.  The Chugach Board authorized expenditures for the project November 15, 2012.  The diversion project began construction in 2013 and will be completed in 2015.Chugach expects to operate the hydroelectric project through the duration of the license.

Liquidity and Capital Resources

We ended 2014 with $16.4 million of cash and cash equivalents, up from $4.3 at December 31, 2013 and up from $14.0 million at December 31, 2012.  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.

	2014		2013		2012
Total cash provided by (used in):
Operating activities	$	61,956,858	$	39,882,861	$	43,005,234
Investing activities		(12,687,167)		(44,046,875)		1,386,980
Financing activities		(37,251,892)		(5,536,292)		(47,462,863)
Increase/(Decrease) in cash and cash equivalents	$	12,017,799	$	(9,700,306)	$	(3,070,649)

Cash provided by operating activities was $62.0 million in 2014 compared to $39.9 million in 2013 and $43.0 million in 2012.  The increase in cash provided by operating activities was due primarily to changes associated with fuel.  The changes in fuel stock were due to the use of fuel storage, 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, and the changes in fuel were due primarily to the timing of payments and the difference in price and quantity of fuel purchased, as a result of the expiration of HEA’s wholesale contract.  Changes in assignable margins were due primarily to the gain on the sale of the Bernice Lake Power Plant at the end of 2013.  Changes in depreciation were due primarily to Beluga Unit 8 assets and the commercial operation of SPP in 2013.  Changes in accounts receivable were due primarily to amounts outstanding for wholesale energy sales to HEA, economy energy sales to GVEA, and SPP costs billed to ML&P.  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.

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Cash used in investing activities was $12.7 million in 2014 compared to $44.0 million of cash provided by investing activities in 2013 and $1.4 million of cash used in investing activities in 2012.  The change in cash provided by or used in investing activities in 2014 from 2013 and in 2013 from 2012 was due primarily to the impact of expenditures associated with SPP, proceeds for capital grants, 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 activity in marketable securities in 2012.

Cash used in financing activities was $37.3 million in 2014 compared to $5.5 million in 2013 and $47.5 million in 2012.  The change in cash used in financing activities in 2014 from 2013 and 2012 was due primarily to our refinancing in 2011 and our interim bridge and subsequent financing associated with SPP in 2012, as well as Chugach’s capital credit retirement in 2014.

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, 2014, there was no outstanding balance on our NRUCFC line of credit and $21.0 million of outstanding commercial paper.  Thus, at December 31, 2014, our available borrowing capacity under our line of credit was $50.0 million and our available commercial paper capacity was $79.0 million.  The NRUCFC line of credit 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, 2014, Chugach had $27.4 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

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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, 2014, are set forth below:

Year Ending December 31	Principal    Maturities
2015	$ 23,889,777
2016	24,115,980
2017	24,362,621
2018	24,631,934
2019	24,925,809
Thereafter	374,988,153
	$ 496,914,274

During 2014, we spent approximately $30.3 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 internal funding for capital expenditures for the years 2015 through 2019 as contained in the CIP, which was approved by the Board on November 18, 2014:

Year	Estimated Expenditures
2015	$33.4 million
2016	$17.4 million
2017	$15.2 million
2018	$18.3 million
2019	$11.4 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.

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Outlook

In the near term, Chugach continues to face the challenges of controlling operating expenses to minimize adverse customer rate impacts and securing replacement revenue sources for an additional wholesale customer load expected to leave by the second quarter of 2015.  These issues, along with energy issues and plans at the state level, will shape how Chugach proceeds into the future.

Chugach is currently focused on providing information about the benefits of grid unification for the Railbelt.  Grid unification signifies operating the regional transmission system under a common set of standards and rules, funded by a universal tariff authorized by regulators and collected from all Railbelt ratepayers.  Studies have noted significant savings for customers can be achieved through economic dispatch, or using the most efficient generating units on the system to meet the needs of collective customers. However, those same studies note that the full benefits of economic dispatch cannot be achieved without additional investments in new regional transmission lines. Today’s system of utility governing bodies, however, does not lend itself to making regional decisions.

Currently, each of the six electric utilities in the Railbelt owns a portion of the transmission grid, as does the Alaska Energy Authority. Chugach is a proponent of following other successful business models to successfully unify the grid. Discussions of the issue led the State Legislature in 2014 to appropriate $250,000 to the RCA to look deeper into the issue and report back to legislators by July 1, 2015.

Chugach actively manages its fuel supply needs, and while it currently has contracts in place to meet 100 percent of its fuel needs through March 2019, is working with state regulators and gas producers to secure a more long-term supply solution.  Chugach has been working closely with the State of Alaska on energy policies to promote gas development in Cook Inlet and other in-state gas options including a proposed spur line off a larger line from the North Slope or a bullet line to Southcentral Alaska.

The 2010 Alaska Legislature passed legislation that provides incentives to natural gas producers to enhance Cook Inlet oil and gas production.  These incentives have resulted in significant improvement in gas production from existing fields and exploration for new supplies.  The two major Cook Inlet area gas producers, Hilcorp and ConocoPhillips, have gas supply agreements with local utilities for deliveries into 2019.  Furie Operating Alaska, LLC has constructed an offshore gas production platform and procured undersea gas pipe to install in the summer of 2015.  Other gas producers are actively developing on-shore gas supplies in Cook Inlet.  The State of Alaska received approximately $6.3 million in bids at its Cook Inlet 2014 areawide oil and gas lease sale.  Chugach is encouraged with these developments but continues to explore other alternatives to diversify its portfolio.

Since 2012, Hilcorp acquired significant oil and gas assets in the Cook Inlet and reworked those assets to increase production, and several other developers have brought new sources of gas production online.  As a result, 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 liquefied natural gas (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

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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.  ConocoPhillips exported approximately 13 Bcf of gas as LNG in 2014.

Hilcorp consolidated the operations and tariff for the four major gas pipelines in the Cook Inlet basin into the KBPL in 2014.  On November 1, 2014 the RCA approved the consolidation.  Prior to consolidation, gas transportation cost could make development of new gas fields cost prohibitive because the gas transport rates varied with flow and the number of pipelines the gas had to cross to transport gas.  The consolidation provides gas producers a single rate for shipping gas on all of the four pipelines, which makes development of gas fields anywhere on the gas pipeline system more attractive to gas producers.

A project commenced by Alaska Gasline Development Corporation and affiliates of BP, ConocoPhillips, ExxonMobil and TransCanada (together, project participants) to construct a liquefaction facility, gas pipeline, and gas treatment plant is underway through a pre-filing process accepted by FERC.  The mainline gas pipeline is expected to include off-take points to allow for the opportunity for future in-state deliveries of natural gas.  The project participants are targeting to file a formal application with FERC in the fall of 2016.  FERC authorizations for the project and commencement of construction are anticipated in the 2018-2019 timeframe, with operation in the 2024-2025 timeframe.

CINGSA began service April 1, 2012.  The facility ensures local utilities, including Chugach, have gas available to meet deliverability requirements during peak periods and store gas during low demand periods.  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.  Injections into the facility began in 2012. Chugach's share of the capacity is 1.9 Bcf.  Chugach is entitled to withdraw gas at a rate of up to 35 MMcf per day.

Pursuant to provisions of their contract, MEA notified Chugach in 2004 that it did not intend to be on the Chugach system, as a wholesale power customer post 2014.MEA began construction of a new power plant at Eklutna, Alaska, which is expected to provide 170 MW of base load generation for MEA.  On August 12, 2014, MEA notified Chugach that their newly constructed power plant, EGS, would not be completed by January 1, 2015.  On September 30, 2014, Chugach entered into an Interim Power Sales Agreement to provide MEA with all demand and energy requirements on a firm basis based on existing tariff rates for a minimum one quarter period beginning on January 1, 2015, and ending on March 31, 2015.  Upon expiration of the Interim Power Sales Agreement on March 31, 2015, MEA intends to leave the Chugach system. This will result in a loss of approximately 33 percent of Chugach’s power sales and approximately 26 percent of the utility’s annual sales revenue.  On December 22, 2014, Chugach entered into a dispatch services agreement with MEA to provide electric and natural gas dispatch services for EGS, electric dispatch services for MEA’s share of the Bradley Lake Hydroelectric Project and electric dispatch coordination services for MEA’s share of the Eklutna Hydroelectric Project effective on or about April 1, 2015.  The term of the agreement expires on March 31, 2016, unless extended by MEA through March 31, 2017.  The agreement is currently awaiting RCA approval.

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Chugach has been preparing for the loss of HEA and MEA, as wholesale power customers, for some time and has taken steps to reduce costs in order to mitigate the rate impact to its remaining customers.  Chugach’s 10-year financial forecast results indicate it can sustain operations and meet financial covenants without these wholesale contracts.  In addition, because Chugach’s rates are established by the RCA, Chugach expects to continue to be able to recover Chugach’s specific costs of providing service despite the loss of these customers.

Chugach is also pursuing replacement sources of revenue through potential new power sales and dispatch agreements, as well as transmission wheeling and ancillary services tariff revisions.  Chugach has updated and expanded its operating tariff to include both firm and non-firm transmission wheeling services 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 as HEA’s wholesale customer contract expired and in anticipation of the expiration of MEA’s wholesale customer contract.  Chugach believes that cost reduction and containment, successful implementation of new power sales and dispatch agreements and revised tariffs will mitigate additional rate increases.  However, Chugach cannot assure that it will be able to replace sources of revenue or that any replacement of revenue sources, revised tariffs or 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 now expected to be 459 MW, which would still provide about half the electric energy needed in the Railbelt.  The 2012 fiscal year State of Alaska capital budget contained $65.7 million for the Alaska Energy Authority (AEA) to conduct planning, design and permitting for this project and on December 29, 2011, AEA filed an application with FERC to begin the licensing process.  The 2014 capital budget included $95.0 million for AEA to continue moving the project forward.  In the spring of 2014, the Alaska Legislature approved an additional $20.0 million for AEA to continue to move 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 2014, AEA filed an Initial Study Report with FERC.  On December 26, 2014, the Governor of the State of Alaska issued an Administrative Order to suspend discretionary spending on a number of capital projects including the Susitna-Watana Hydroelectric Project, due to the large state budget deficit.  Accordingly, the AEA requested the FERC to suspend the schedule in this proceeding for 60 days pending further notice from AEA regarding future plans for this project. In addition, AEA provided notice that the Initial Study Report meetings previously scheduled for January 2015

41

were postponed until further notice.  Chugach has been working with and will continue to work with AEA and other parties on this effort.

The 2015 fiscal year State of Alaska capital budget contained $3.5 million in appropriations for Chugach’s Stetson Creek Diversion project. The 2014 fiscal year State of Alaska capital budget contained $287.5 thousand in appropriations for Chugach. 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, 2014.  

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 recognition 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 regulatory liabilities. The application of FASB ASC 980 has a further effect on Chugach's financial statements as a result of the estimates

42

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 $9,885,526 and $9,274,135 of unbilled retail revenue at December 31, 2014 and 2013, 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.”

43

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 one of our 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, 2014, 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 Chugach’s 2011 Series A Bonds and 2012 Series A Bonds are fixed and set forth in the table below with carrying value and fair value, measured as Level 1 liabilities, (dollars in millions) at December 31, 2014.

	Maturing	Interest Rate		Carrying Value		Fair Value
2011 Series A, Tranche A	2031	4.20	%	$	76,500	$	79,409
2011 Series A, Tranche B	2041	4.75	%		166,500		187,029
2012 Series A, Tranche A	2032	4.01	%		67,500		69,289
2012 Series A, Tranche B	2042	4.41	%		109,000		117,638
2012 Series A, Tranche C	2042	4.78	%		50,000		57,312
Total				$	469,500	$	510,677

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, 2014, we had $21.0 million of commercial paper outstanding and $27.4 million outstanding on our CoBank bond.  A 100 basis-point rise in interest rates would increase our interest expense by approximately $0.5 million, and a 100 basis point decline in interest rates would decrease our interest expenses by approximately $0.3 million, based on $48.4 million of variable rate debt outstanding at December 31, 2014.

Commodity Price Risk

Chugach has a gas contract that provides 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.

44

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, 2014 and 2013, 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, 2014. 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, 2014 and 2013, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

March20, 2015

Anchorage, Alaska

45

Chugach Electric Association, Inc.

Balance Sheets

December 31, 2014 and 2013

Assets	December 31, 2014		December 31, 2013
Utility Plant:
Electric plant in service	$	1,155,500,963	$	1,135,356,956
Construction work in progress		21,567,341		28,674,163
Total utility plant		1,177,068,304		1,164,031,119
Less accumulated depreciation		(497,601,371)		(464,880,322)
Net utility plant		679,466,933		699,150,797
Other property and investments, at cost:
Nonutility property		76,889		76,889
Investments in associated organizations		9,923,552		10,204,193
Special funds		666,967		536,546
Restricted cash equivalents		1,705,086		1,956,578
Total other property and investments		12,372,494		12,774,206
Current assets:
Cash and cash equivalents		16,364,962		4,347,163
Special deposits		79,390		158,265
Restricted cash equivalents		1,143,000		1,750,254
Marketable securities		0		10,308,533
Accounts receivable, less provisions for doubtful accounts
of $346,749 in 2014 and $541,747 in 2013		36,060,256		44,633,981
Materials and supplies		26,774,512		25,856,395
Fuel stock		9,652,073		13,029,848
Prepayments		2,178,723		1,863,407
Other current assets		242,682		320,658
Total current assets		92,495,598		102,268,504
Deferred charges, net		21,376,596		23,990,531
Total assets	$	805,711,621	$	838,184,038

46

Chugach Electric Association, Inc.

Balance Sheets (continued)

December 31, 2014 and 2013

Liabilities, Equities and Margins	December 31, 2014		December 31, 2013
Equities and margins:
Memberships	$	1,631,569	$	1,600,058
Patronage capital		164,135,053		162,749,889
Other		11,158,677		11,445,918
Total equities and margins		176,925,299		175,795,865
Long-term obligations, excluding current installments:
Bonds payable		447,083,332		469,499,999
National Bank for Cooperatives note payable		24,941,165		27,414,275
Total long-term obligations		472,024,497		496,914,274
Current liabilities:
Current installments of long-term obligations		24,889,777		24,682,812
Commercial paper		21,000,000		30,000,000
Accounts payable		9,746,175		11,461,303
Consumer deposits		4,914,260		4,851,558
Fuel cost over-recovery		1,462,057		1,635,677
Accrued interest		6,191,608		6,512,860
Salaries, wages and benefits		7,547,316		7,932,363
Fuel		11,137,609		14,834,585
Other current liabilities		4,594,865		5,143,905
Total current liabilities		91,483,667		107,055,063
Deferred compensation		666,967		536,546
Other liabilities, non-current		1,842,000		1,034,777
Deferred liabilities		1,858,455		1,776,826
Patronage capital payable		10,205,739		7,931,295
Cost of removal obligation		50,704,997		47,139,392
Total liabilities, equities and margins	$	805,711,621	$	838,184,038

See accompanying notes to financial statements.

47

Chugach Electric Association, Inc.

Statements of Operations

Years Ended December 31, 2014, 2013 and 2012

	2014		2013		2012
Operating revenues	$	281,318,513	$	305,308,427	$	266,971,468
Operating expenses:
Fuel		126,038,350		136,610,262		125,836,659
Production		21,082,176		21,911,324		16,739,931
Purchased power		15,608,396		27,836,680		22,104,687
Transmission		6,138,658		6,624,836		5,802,009
Distribution		13,002,157		13,225,242		15,822,104
Consumer accounts		5,887,713		6,014,888		6,013,419
Administrative, general and other		25,036,248		23,131,149		23,519,246
Depreciation and amortization		40,179,181		43,384,116		32,356,900
Total operating expenses	$	252,972,879	$	278,738,497	$	248,194,955
Interest expense:
Long-term debt and other		23,264,041		24,691,582		24,085,371
Charged to construction		(463,335)		(1,310,110)		(9,682,440)
Interest expense, net	$	22,800,706	$	23,381,472	$	14,402,931
Net operating margins	$	5,544,928	$	3,188,458	$	4,373,582
Nonoperating margins:
Interest income		566,639		686,460		447,434
Allowance for funds used during construction		163,151		141,014		258,301
Gain on sale of asset		0		6,436,992		0
Capital credits, patronage dividends and other		240,827		91,119		446,190
Total nonoperating margins	$	970,617	$	7,355,585	$	1,151,925
Assignable margins	$	6,515,545	$	10,544,043	$	5,525,507

See accompanying notes to financial statements.

48

Chugach Electric Association, Inc.

Statements of Changes in Equities and Margins

Years Ended December 31, 2014, 2013 and 2012

	Memberships		Other Equities and Margins		Patronage Capital		Total
Balance, January 1, 2012	$	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
Assignable margins		0		0		6,515,545		6,515,545
Retirement/net transfer of capital credits		0		0		(5,130,381)		(5,130,381)
Unclaimed capital credit retirements		0		(350,776)		0		(350,776)
Memberships and donations received		31,511		63,535		0		95,046
Balance, December 31, 2014	$	1,631,569	$	11,158,677	$	164,135,053	$	176,925,299

See accompanying notes to financial statements.

49

Chugach Electric Association, Inc.

Statements of Cash Flows

Years Ended December 31, 2014, 2013 and 2012

	2014		2013		2012
Cash flows from operating activities:
Assignable margins	$	6,515,545	$	10,544,043	$	5,525,507
Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation and amortization		40,179,181		43,384,116		32,356,900
Amortization and depreciation cleared to operating expenses		5,777,628		5,912,254		5,882,580
Allowance for funds used during construction		(163,151)		(141,014)		(258,301)
Write off of inventory, deferred charges and projects		974,062		430,453		991,871
Gain on sale of Bernice Lake Power Plant		0		(6,436,992)		0
Other		56,250		240,836		(135,739)
(Increase) decrease in assets:
Accounts receivable, net		6,879,762		4,823,879		(4,276,906)
Fuel cost under-recovery		0		0		1,213,484
Materials and supplies		(1,197,127)		(907,942)		(189,092)
Fuel stock		3,377,775		(3,563,081)		(9,466,767)
Prepayments		(315,316)		293,455		(245,073)
Other assets		978,338		(1,827,291)		27,937
Deferred charges		(1,050,505)		(317,070)		(4,335,252)
Increase (decrease) in liabilities:
Accounts payable		(420,041)		1,775,412		1,454,677
Consumer deposits		62,702		571,657		330,849
Fuel cost over-recovery		(173,620)		(12,074,372)		13,710,049
Accrued interest		(321,252)		(294,347)		(36,266)
Salaries, wages and benefits		(385,047)		597,937		771,512
Fuel		(3,696,976)		(6,033,493)		(3,531,079)
Other current liabilities		4,843,982		2,901,022		3,094,139
Deferred liabilities		34,668		3,399		120,204
Net cash provided by operating activities		61,956,858		39,882,861		43,005,234
Cash flows from investing activities:
Return of capital from investment in associated organizations		351,162		424,484		663,697
Investment in restricted cash equivalents		(142)		0		0
Investment in marketable securities		(217,817)		(327,175)		(10,096,304)
Proceeds from restricted cash equivalents		0		0		120,000,000
Proceeds from the sale of marketable securities		10,522,620		0		0
Proceeds from capital grants		6,960,143		20,329,782		23,117,721
Extension and replacement of plant		(30,303,133)		(64,473,966)		(132,298,134)
Net cash (used in) provided by investing activities		(12,687,167)		(44,046,875)		1,386,980
Cash flows from financing activities:
Payments for debt issue costs		0		0		(1,850,199)
Proceeds from short-term obligations		22,000,000		45,500,000		24,500,000
Proceeds from long-term obligations		0		0		250,000,000
Repayments of short-term obligations		(31,000,000)		(27,000,000)		(188,000,000)
Repayments of long-term obligations		(24,682,812)		(24,493,022)		(133,360,210)
Memberships and donations received		(255,730)		114,277		55,519
Retirement of patronage capital and estate payments		(4,114,541)		(156,565)		(48,079)
Net receipts on consumer advances for construction		801,191		499,018		1,240,106
Net cash used in financing activities		(37,251,892)		(5,536,292)		(47,462,863)
Net change in cash and cash equivalents		12,017,799		(9,700,306)		(3,070,649)
Cash and cash equivalents at beginning of period	$	4,347,163	$	14,047,469	$	17,118,118
Cash and cash equivalents at end of period	$	16,364,962	$	4,347,163	$	14,047,469
Supplemental disclosure of non-cash investing and financing activities:
Retirement of plant	$	5,814,886	$	24,095,596	$	10,405,777
Cost of removal obligation	$	3,565,605	$	2,511,077	$	3,148,135
Extension and replacement of plant included in accounts payable	$	2,382,117	$	3,817,788	$	10,620,219
Patronage capital retired and included in other current liabilities and patronage capital payable	$	2,572,670	$	2,512,753	$	0
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized	$	21,835,216	$	21,839,391	$	13,092,576

See accompanying notes to financial statements.

50

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

(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.”

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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, 2014 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.

52

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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 4.3 percent during 2014, 3.7 percent during 2013 and 4.0 percent during 2012.  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 2014, 2013 and 2012.

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.

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.

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.  Chugach has a concentration account with First National Bank Alaska (FNBA).  There is no rate of return or fees on this account.  The concentration account had an average balance of $6,300,149 and $6,262,978 during the years ended December 31, 2014 and 2013, respectively.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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.

In September of 2012, Chugach invested $10.0 million in marketable securities with UBS Financial Services, Inc. (UBS).  In 2014, these securities were used to invest in a money market fund.

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.  At December 31, 2014 and 2013, restricted cash equivalents included $2.8 million and $3.2 million, respectively, of funds on deposit for future workers’ compensation claims.  At December 31, 2014, there were no restricted cash equivalents representing interim rates collected from customers.  At December 31, 2013, restricted cash equivalents included $0.5 million of 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 $0.9 and $1.8 million in 2014 and 2013, 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 $1.1 million in 2014 and $2.8 million in 2013.

i. Materials and Supplies

Materials and supplies are stated at average cost.

j. Deferred Charges and Credits

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

54

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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, results of operations or cash flows. 

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 operations 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.

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 $9,885,526 and $9,274,135 of unbilled retail revenue at December 31, 2014 and 2013, 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

55

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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 $1,462,057 and by $1,635,677 in 2014 and 2013, respectively.  Total fuel and purchased power costs in 2014, 2013, and 2012 were $141,646,746, $164,446,942, and $147,941,346, 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, 2014, 2013 and 2012 was in compliance with that provision.  In addition, as described in Note (15) – “Commitments and Contingencies,” Chugach collects sales tax and is assessed gross revenue and excise taxes which are presented on a net basis in accordance with FASB ASC 605-45-50, “Topic 605 - Revenue Recognition – Subtopic 45 - Principal Agent Considerations – Section 50 - Disclosure.”

Chugach applies a more-likely-than-not recognition threshold for all tax uncertainties.  FASB ASC 740, “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, 2012 through December 31, 2014 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2014.

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, 2014 and 2013, totaled $2.9 millionand $2.5 million, respectively.  Consumer deposits also represent customer credit balances as a result of prepaid accounts.  Credit balances for the years ended December 31, 2014 and 2013 totaled $2.0 million and $2.4 million, respectively.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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 $4.8 millionand $17.4 million in 2014 and 2013, respectively.

r. Fuel Stock

Fuel Stock is the weighted average cost of fuel injected into 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, 2014 and 2013 amounted to $9.7 million and $13.0 million, respectively.

s. Marketable Securities

Chugach had a bond investment portfolio, which consisted of marketable securities reported at fair value with gains and losses included in earnings.  On August 12, 2014, Chugach sold its marketable securities portfolio and therefore had no balance at December 31, 2014.  At December 31, 2013, the carrying amount and fair value was $10.3 million.

t. Reclassifications

For the year ended December 31, 2014, Chugach recorded the following reclassification for the year ended December 31, 2013:

A reclassification representing the long-term portion of funds on deposit for future workers’ compensation claims, included as restricted cash equivalents, previously reported as a current asset and now reported as other property and investments.  The impact of this reclassification was an increase to total other property and investments and a decrease to current assets of $2.0 million in 2013.  A reclassification representing the long-term portion of the liability for future workers’ compensation claims previously reported as salaries, wages and benefits and now included as other liabilities, non-current.  The impact of this reclassification was an increase to other liabilities, non-current, and a decrease to current liabilities of $1.0 million in 2013.

For the year ended December 31, 2014, Chugach recorded the following reclassifications for the years ended December 31, 2013 and 2012:

A reclassification representing the gross versus net presentation of cash received for capital grants, included as cash flows from investing, previously reported as extension and replacement of plant and now reported as proceeds from capital grants.  These reclassifications had no impact on net cash used in investing activities.

57

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

(3)Recent Accounting Pronouncements

ASC Update 2014-09 “Revenue from Contracts with Customers (Topic 606)”

In May of 2014, the FASB issued ASC Update 2014-09, “Revenue from Contracts with Customers (Topic 606).”  ASC Update 2014-09 provides guidance for the recognition, measurement and disclosure of revenue related to the transfer of promised goods or services to customers.  This update is effective for fiscal years beginning after December 15, 2016, for which early adoption is prohibited.  Chugach will begin application of ASC 2014-09 on January 1, 2017.  Chugach is evaluating the effect on its results of operations, financial position, and cash flows.

(4)    Fair Value of Assets and Liabilities

Fair Value Hierarchy

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

Level 1 – Valuation is based upon quoted prices for identical instruments traded in active exchange markets, such as the New York Stock Exchange.  Level 1 also includes 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.

Chugach had a Level 1 bond investment portfolio, which consisted of marketable securities reported at fair value with gains and losses included in earnings.  At December 31, 2013, the bond portfolio had a balance of $10,308,533 measured at fair value on a recurring basis.  On August 12, 2014, Chugach sold the bond portfolio and invested the proceeds in a money market fund.

Chugach had no Level 2 or 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.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

(5)    Regulatory Matters

Operation and Regulation of the Alaska Railbelt Transmission System

On February 11, 2015, the RCA voted in favor of opening a docket to investigate and receive input on alternative transmission structures for the Railbelt.  On February 27, 2015, the RCA issued Order No. 1 to docket I-15-001 requiring interested parties to respond by March 31, 2015, to questions outlined in the order regarding the creation of an independent system operator for Railbelt transmission.

June 2014 Test Year General Rate Case

Chugach’s June 2014 test year rate case was finalized and submitted to the RCA on February 13, 2015.  Chugach requested a system base rate increase of approximately $21.3 million, or 20 percent on total base rate revenues for rates effective in April 2015.  The filing also includes updates to firm and non-firm transmission wheeling rates and attendant ancillary services in support of third-party transactions on the Chugach transmission system.  The primary driver of the rate changes is the reduction in fixed-cost contributions resulting from the March 31, 2015 expiration of the Interim Power Sales Agreement between Chugach and MEA.

Chugach submitted proposed adjustments to its fuel and purchased power rates under a separate tariff advice letter to become effective at the same time which allows interim base rate increases to be synchronized with reductions in fuel costs resulting from system heat rate improvements and a greater share of hydroelectric generation used to meet the load requirements of the remaining customers on the system.  In combination with Chugach’s fuel and purchased power rate adjustment filing for rates effective in April 2015, the effective increase to retail customer bills is approximately 2.0 to 5.0 percent.

Amended Eklutna Generation Station 2015 Dispatch Services Agreement

On February 13, 2015, Chugach submitted the Amended Eklutna Generation Station 2015 Dispatch Services Agreement to the RCA for dispatch services to be provided by Chugach to MEA for a one-year period.  If approved by the RCA, the Agreement becomes effective April 1, 2015 and remains in effect through March 31, 2016, unless extended by MEA.   MEA may extend the Agreement through March 31, 2017 by providing written notice to Chugach on or before December 31, 2015.  Under the Agreement, Chugach provides electric and natural gas dispatch services for MEA’s Eklutna Generation Station (EGS), electric dispatch services for the Bradley Lake Hydroelectric Project (Bradley Lake), and electric dispatch coordination services for the Eklutna Hydroelectric Project (Eklutna Hydro) beginning with EGS’ Full Commercial Operation.  If approved, Chugach will receive $40,000 per month from MEA for these services.

MEA Interim Power Sales Agreement

On August 12, 2014, MEA notified Chugach that their newly constructed power plant, the Eklutna Generation Station (EGS), would not be completed by January 1, 2015.  On September 30, 2014, Chugach entered into an Interim Power Sales Agreement (Agreement) to provide MEA with all demand and energy requirements on a firm basis based on existing tariffed rates for a minimum one quarter period beginning on January 1, 2015, and ending on March 31, 2015.

59

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

Under the terms of the agreement, Chugach agreed to purchase from MEA the output of up to four units from their plant upon commercial operation through the term of the agreement.  Chugach proposed to purchase the pooled energy and recover the costs from its members,including MEA, through Chugach’s fuel and purchased power adjustment process.  MEA willsupply and deliver any and all additional gas and attendant transportation necessary for Chugachto produce electric service to MEA arising as a result of the electric services to be provided byChugach pursuant to the Agreement.

On December 22, 2014, the RCA issued a letter order approving both the Agreement and Chugach’s proposal to recover costs incurred under the Agreement through its fuel and purchased power rate adjustment process.  As part of the approval, the RCA required Chugach to provide monthly information on MEA gas deliveries to Chugach, system heat rates with and without EGS, and the number of EGS units made commercially available during each month of the contract.

Pursuant to the agreement, MEA was required to notify Chugach if it planned to exercise an option to extend the agreement an additional quarter. On January 5, 2015, MEA notified Chugach that it would not be extending the agreement.

On January 30, 2015, MEA notified Chugach that it had four units available to pool with Chugach units to meetthe combined system load of Chugach and MEA. These units were subsequently placed into economic dispatch. 

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.  On July 25, 2014, the RCA issued Order No. 4 approving Chugach’s request to file its next status update by September 30, 2014.  Chugach filed a status report with the RCA on September 26, 2014.  In the filing, Chugach informed the RCA that it had received notification from ML&P that they believe no further proceedings on this matter are necessary.  ML&P indicated that fluctuations from the wind project are impacting system frequency but the attendant costs associated with quantifying the impacts likely exceed the attendant benefit.  ML&P reserved the right to open this issue at a later time.  In the filing, Chugach indicated that it will continue to evaluate the potential impact of the Fire Island Wind Project on the grid and requested that the RCA accept the status report on the integration and cost reimbursement issues and close the docket.

The RCA issued an order on February 27, 2015, requiring ML&P to file a separate report addressing the nature and estimate of any adverse cost impacts attributable to FIW integration, as well as the estimated costs and equipment needed for measurement.  ML&P’s report to the RCA is due April 28, 2015.

60

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

AIX, Energy LLC

On December 22, 2014, Chugach executed an agreement with AIX, Energy LLC (“AIX Agreement”) which allows for natural gas purchases by Chugach from AIX Energy from March 1, 2015 through February 29, 2016.  The AIX Agreement provides flexibility in both the purchase price and volumes, with specific prices and volumes to be determined by each transaction.  However, the price of gas cannot exceed $6.24 per thousand cubic feet (Mcf) and the total volume of gas is capped at 300,000 Mcf, or a maximum total outlay of approximately $1.9 million.  As the AIX Agreement is for a term less than one year, approval of the agreement by the RCA is not required; however, Chugach submitted a filing to the RCA seeking approval to recover purchases made under the agreement as a new cost element in its fuel and purchased power adjustment process.

First Amendment to the Gas Sale and Purchase Agreement with Hilcorp

On July 31, 2014, Chugach filed the First Amendment to the Gas Sale and Purchase Agreement (Amendment) between Hilcorp Alaska, LLC (Hilcorp) and Chugach for gas delivery from February 1, 2015, through March 31, 2019, for RCA review and approval.  The RCA approved the original Gas Sale and Purchase Agreement between Hilcorp and Chugach in September 2013, which provided up to 100 percent of Chugach’s unmet gas needs from January 1, 2015, through March 31, 2018.  The Amendment extends the contract term for firm deliveries by one year and expands the time horizon for non-firm purchases.  Specifically, the Amendment provides a firm gas supply for a significant portion of Chugach’s gas supply needs from April 1, 2018, through March 31, 2019, and gives Chugach the right to purchase additional portions of its firm gas supply needs, if requested.  The Amendment also provides a non-firm gas supply for deliveries through March 2019, if both parties agree.

Chugach received notification on September 11, 2014, that the Amendment was approved by the RCA.  The RCA also approved Chugach’s request to recover gas costs incurred under the Amendment through its fuel and purchased power adjustment process.

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.

On April 18, 2014, Chugach submitted an update to its 2013 general rate case to reflect the final results contained in Chugach’s compliance filing in the 2012 general rate case that was submitted to the RCA on April 14, 2014.  The update reflects final rate design changes contained in the 2012 rate case.  On May 30, 2014, the RCA issued Order No. 3 approving Chugach’s motion and update to retail and wholesale base rates effective with the first billing cycle in June 2014.  There was no

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

impact to the system revenue requirement contained in the 2013 Test Year General Rate Case filing.

Chugach and the parties to the docket entered into a stipulation resolving revenue requirement and cost of service matters contained in the case.  The stipulation was filed with the RCA on October 16, 2014, and requires Chugach to issue refunds totaling $1.1 million (annualized) for service provided beginning January 2014, with an expected financial impact to Chugach of approximately $0.2 million on an annual basis.  The stipulation contained a provision that Chugach be permitted to create a regulatory asset for approximately $0.9 million of storm-related costs and be permitted to recover $0.2 million per year over the next five years.  On November 13, 2014, the RCA accepted the stipulation.

On February 12, 2015, the RCA issued Order No. 9 of U-14-001 accepting the stipulation on revenue requirement matters and resolving the remaining issues in the docket.

The RCA required Chugach to submit updated tariffs reflecting the results of the RCA order and the stipulations entered into the case, including a detailed refund plan, which Chugach submitted on March 13, 2015.

(6)Utility Plant

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

Electric plant in service:	2014		2013
Steam production plant	$	60,516,027	$	60,462,671
Hydraulic production plant		20,594,429		20,546,809
Southcentral Power Project plant		248,970,341		5,153,237
Other production plant		130,356,979		116,898,472
Transmission plant		261,173,934		249,483,480
Distribution plant		281,706,456		258,474,600
General plant		53,452,136		48,517,709
Unclassified electric plant in service1		91,446,881		369,280,657
Intangible plant1		5,455,371		4,710,912
Other1		1,828,409		1,828,409
Total electric plant in service		1,155,500,963		1,135,356,956
Construction work in progress		21,567,341		28,674,163
Total electric plant in service and construction work in progress	$	1,177,068,304	$	1,164,031,119

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

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

(7)    Investmentsin Associated Organizations

Investments in associated organizations include the following at December 31:

	2014		2013
NRUCFC	$	6,095,980	$	6,095,980
CoBank		3,763,697		4,044,338
NRUCFC Capital Term Certificates and other		63,875		63,875
Total investments in associated organizations	$	9,923,552	$	10,204,193

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.

(8)    Deferred Charges and Credits

Deferred Charges

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

	2014		2013
Debt issuance and reacquisition costs	$	3,263,937	$	3,611,498
Refurbishment of transmission equipment		123,457		132,717
Feasibility studies		578,806		912,537
Beluga gas compression		1,017,733		1,526,599
Cooper Lake relicensing / projects		5,540,212		5,670,314
Fuel supply		898,849		971,209
Major overhaul of steam generating unit		0		1,285,942
Other regulatory deferred charges		2,435,855		1,759,448
Bond interest - market risk management		6,402,875		6,960,044
Environmental matters and other		1,114,872		1,160,223
Total deferred charges	$	21,376,596	$	23,990,531

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

	2014		2013
Fuel supply (negotiations/studies/compression)	$	0	$	231,712
Studies and other		387,253		336,017
Storm damage		971,071		0
Wind project		34,543		34,543
Total deferred charges	$	1,392,867	$	602,272

63

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

The amount related to storm damage was subsequently approved by the RCA on February 21, 2015, see Note (5) – Regulatory Matters – 2013 General Rate Case.”

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.

Deferred Credits

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

	2014		2013
Refundable consumer advances for construction	$	787,824	$	773,089
Estimated initial installation costs for meters		98,964		104,037
Post retirement benefit obligation		874,000		899,700
Other		97,667		0
Total deferred costs	$	1,858,455	$	1,776,826

(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, 2014, Chugach had $164,135,053 of patronage capital (net of capital credits retired in 2014), which included $157,619,508 of patronage capital that had been assigned and $6,515,545 of patronage capital to be assigned to its members.  Approval of actual capital credit retirements is at the discretion of the Chugach 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.

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  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 at December 31, 2014 and 2013, respectively.

In an agreement reached in May of 2014 with MEA, capital credits retired to MEA are classified as patronage capital payable on Chugach’s Balance Sheet.  MEA’s patronage capital payable was $2.3 million at December 31, 2014.

64

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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.Capital credits retired, net of HEA’s allocations, were $5,130,381,  $1,626,828, and $48,079 for the years ended December 31, 2014, 2013, and 2012, respectively.  With the exception of HEA’s patronage capital payable, the outstanding liability for capital credits authorized but not paid at December 31, 2014, and 2013 was $1,042,064and $1,470,263, respectively.

(10)  Other Equities

A summary of other equities at December 31 follows:

A summary of other equities at December 31 follows:
	2014		2013
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		1,806,424		1,742,889
Unclaimed capital credit retirement1		9,328,628		9,679,404
Total other equities	$	11,158,677	$	11,445,918

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

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

(11)  Debt

Long-term obligations at December 31 are as follows:	2014		2013
2011 CoBank bond, 2.51% variable rate notes maturing in 2022, with interest payable monthly and principal due annually beginning in 2003	$	27,414,275	$	29,680,420
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		76,500,000		81,000,000
2011 Series A Bond of 4.75%, maturing in 2041, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012		166,499,999		172,666,666
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		67,500,000		71,250,000
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		109,000,000		117,000,000
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	$	496,914,274	$	521,597,086
Less current installments		24,889,777		24,682,812
Long-term obligations, excluding current installments	$	472,024,497	$	496,914,274

Covenants

Chugach is required to comply with all covenants set forth in the Indenture that secures the 2011 Series A Bonds, the 2012 Series A Bonds and the 2011 CoBank bond.

The CoBank bond is governed by the Amended and Restated Master Loan Agreement, which is now secured by the Indenture dated January 20, 2011.

66

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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 as amended 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 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.

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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

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.

Maturities of Long‑term Obligations

Long-term obligations at December 31, 2014, mature as follows:

Year ending December 31		2011 Series A Bonds		CoBank Note		2012 Series A Bonds		Total
2015		10,666,667		2,473,110		11,750,000		24,889,777
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
2019		10,666,667		3,509,142		10,750,000		24,925,809
Thereafter		189,666,664		12,571,489		171,750,000		373,988,153
	$	242,999,999	$	27,414,275	$	226,500,000	$	496,914,274

Lines of credit

Chugach maintains a $50.0 million line of credit with NRUCFC.  Chugach did not utilize this line of credit in 2014 or 2013, and therefore had no outstanding balance at December 31, 2014 and 2013.  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, 2014 and 2013.

The NRUCFC Revolving Line Of Credit Agreement requires that Chugach, for each 12-month period, for a period of at least five consecutive days, pay down the entire outstanding principal balance.  The NRUCFC line of credit expires October 12, 2017, and is immediately available for unconditional borrowing.

68

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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 2015, as needed, however, the requirement for short-term borrowing has decreased.

Chugach had $21.0 million and $30.0 million of commercial paper outstanding at December 31, 2014 and 2013, respectively. 

The following table provides information regarding 2014 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 2014	$	28.8	0.20	July 2014	$	31.2	0.19
February 2014	$	23.8	0.19	August 2014	$	27.4	0.19
March 2014	$	35.2	0.19	September 2014	$	33.3	0.19
April 2014	$	39.2	0.19	October 2014	$	34.6	0.20
May 2014	$	33.2	0.19	November 2014	$	28.7	0.20
June 2014	$	30.2	0.20	December 2014	$	25.2	0.25

69

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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 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.

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.

70

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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)	$	496,914	$	538,091

(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, 2014, 2013 and 2012 of $6.8 million, $6.8 million and $6.6 million, respectively.  The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2014, 2013 and 2012.

71

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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			December 31
Expiration Date of CBA's	June 30, 2017			N/A2
Subject to Funding Improvement Plan	No			No4
Surcharge Paid	N/A			N/A4
	2014	2013	2012	2014	2013	2012
Zone Status	Green	Green	Green	N/A1	N/A1	N/A1
Required minimum contributions	None	None	None	N/A	N/A	N/A
Contributions (in millions)	$3.3	$3.4	$3.6	$3.5	$3.4	$3.0
Contributions > 5% of total plan contributions	Yes	Yes	Yes	No	No	No

1A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006. 

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

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

4The provisions of the PPA do not apply to the RS Plan, therefore, funding improvement plans and surcharges are not applicable.  Future contribution requirements are determined each year as part of the actuarial valuation of the 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, 2014, 2013, and 2012 were $4.5 million, $4.1 million, and $4.3 million, respectively.

Chugach participates in a multi-employer plan through the Group Benefits Program of NRECA for non-union employees.  Amounts charged to benefit cost and contributed to this plan for those benefits for the years ended December 31, 2014, 2013, and 2012 totaled $2.9 million, $2.9 million, and $2.5 million respectively.

72

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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, 2014, 2013 and 2012 were $149.2 thousand, $147.9 thousand and $141.0 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, $17,500 and $17,000 in 2014, 2013 and 2012 respectively, and allowed catch-up contributions for those over 50 years of age of $5,500 in 2014, 2013 and 2012.  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, 2014, 2013 and 2012 was $666,967, $536,546 and $570,027, respectively.

Potential Termination Payments

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

73

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

(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  $24.0 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 $5.4 million as a result of Chugach’s Bradley Lake take-or-pay obligations.  Management believes that such expenditures, if any, would be recoverable through the fuel 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, 2014 (the most recent date for which information is available).  Chugach's share of expenses was $5,228,907in 2014, $4,882,163 in 2013, and $4,223,784 in 2012 and is included in purchased power in the accompanying financial statements.

(In thousands)	Total		Proportionate Share
Plant in service	$	173,058	$	52,610
Long-term debt		71,155		21,631
Interest expense		4,127		1,255

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

74

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

(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).

Plant in service in 2014 included  $4,442,440, net of accumulated depreciation of $2,017,032, which represents Chugach’s share of the Eklutna Hydroelectric Project. In 2013, plant in service included $4,562,310, net of accumulated depreciation of $1,854,083.  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 $761,613, $730,122, and $682,757 in 2014, 2013, and 2012, 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.  The MEA contract, including the fuel component, represented$70.7 million, or 26 percent, of sales revenue in 2014.  The MEA and HEA contracts, including the fuel component, represented $103.1 million, or 34 percent, in 2013, and $100.6 million, or 39 percent, in 2012.  The HEA contract expired December 31, 2013, and the MEA contract now expires March 31, 2015.  Pursuant to contract provisions, notification was made by MEA that they did not intend to renew their contract.  All rates are established by the RCA.

75

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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, 2019.  The total amount of gas under contract is now estimated up to 49 Bcf.  These contracts fill 100 percent of Chugach’s needs through March 31, 2019.  All of the production is expected to come from Cook Inlet, Alaska.

In 2014, 87 percent of our power was generated from gas, with 57 percent generated at the Beluga Power Plant and 43 percent generated at SPP.  In 2013 and 2012, 87 percent and 89 percent of our power was generated from gas, respectively, with 47 percent and 83 percent generated at Beluga, and 31 percent generated at SPP in 2013.

The terms of the ConocoPhillips and Hilcorp agreements require Chugach to handle the natural gas transportation over the connecting pipeline systems.  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:

	2014		2013		2012
Marathon Oil Company	0.0	%	4.5	%	72.0	%
Chevron / Unocal / Hilcorp	50.4	%	46.4	%	1.3	%
ConocoPhillips (COP)	43.6	%	42.8	%	24.2	%
ENSTAR	2.0	%	2.1	%	2.2	%
Hilcorp Pipeline	3.0	%	3.8	%	0.0	%
Miscellaneous	1.0	%	0.4	%	0.3	%

Patronage Capital Payable

Pursuant to agreements reached with HEA and MEA, and discussed in Note (9) – “Patronage Capital,” patronage capital allocated or retired to HEA or MEA is classified as patronage capital payable on Chugach’s balance sheet.  HEA’s patronage capital payable was $7.9 million at December 31, 2014 and 2013.MEA’s patronage capital payable was $2.3 million at December 31, 2014.

76

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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 $0.000754, effective July 1, 2014.  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 Revenue Tax

Chugach pays to the State of Alaska a gross revenue 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.

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 program.  The rate amendments are not subject to RCA review or approval.  Chugach’s liability was $2,761,921 and $2,898,558 for this charge at December 31, 2014 and 2013, respectively.  These funds are used to offset the costs of the undergrounding program.

77

Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

Environmental Matters

The Clean Air Act and Environmental Protection Agency (EPA) regulations under the Clean Air Act establish ambient air quality standards and limit the emission of many air pollutants.  New Clean Air Act regulations impacting electric utilities may result from future events or new regulatory programs.  On June 2, 2014, the EPA released a proposed regulation aimed at reducing emissions of carbon dioxide (CO2) from existing power plants that provide electricity for utility customers.  In the draft rule, the EPA took the approach of making individual states responsible for the development and implementation of plans to reduce the rate of CO2 emissions from the power sector.  A final rule is expected in June 2015, with State plans due to the EPA in June 2016.  Chugach is subject to this proposed regulation, in its current form, and does not expect it to have a material effect on its results of operations, financial position, and cash flows.  While Chugach cannot predict the implementation of any additional new law or regulation, or the limitations thereof, it is possible that new laws or regulations could increase capital and operating costs.  Chugach has obtained Clean Air Act permits currently required for the operation of 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.  Chugach does not believe that compliance with these statutes and regulations to date has had a material impact on its financial condition, results of operation or cash flows.  However, the implementation of any additional new law or regulation, or the limitations thereof, or changes in or new interpretations of laws or regulations could result in significant additional capital or operating expenses.  Chugach monitors proposed new regulations and existing regulation changes through industry associations and professional organizations.

Economy Energy Sales

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

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Chugach Electric Association, Inc.

Notes to Financial Statements

December 31, 2014 and 2013

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 total project cost is now estimated at$22.3 million.  As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska.  Funding for this project includes  $9.9 million in grants awarded.  The Chugach Board authorized expenditures for the project November 15, 2012.  The diversion project began construction in 2013 and will be completed in 2015.  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)

2014 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	69,272,422	$	65,677,900	$	70,269,305	$	76,098,886
Operating Expense		58,795,411		61,712,934		66,997,011		65,467,523
Net Interest		5,673,940		5,622,892		5,661,316		5,842,558
Net Operating Margins		4,803,071		(1,657,926)		(2,389,022)		4,788,805
Nonoperating Margins		411,590		96,181		249,820		213,026
Assignable Margins	$	5,214,661	$	(1,561,745)	$	(2,139,202)	$	5,001,831

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

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Item 9 –Changes in and Disagreements with

Accountants on Accounting and Financial Disclosure

None

Item 9A – Controls and Procedures

Evaluation of Controls and Procedures

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

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal controls over financial reporting as defined in Rule 13a-15(f) under the Exchange Act.  Our internal controls over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with 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, 2014, 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, 2014, Chugach maintained effective internal controls over financial reporting.  In addition, there were no changes in Chugach’s internal controls over financial reporting (as defined in Rules 13a-15(f) or 15d-15(f) of the Exchange Act) identified in connection with the evaluation that occurred during the fourth quarter that has materially affected, or is reasonably like to materially affect, Chugach’s internal controls over financial reporting.

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While Chugach’s transition to the 2013 COSO framework is substantially complete, the transition was not finalized as of December 31, 2014, therefore management, including our CEO and CFO, assessed the effectiveness of our internal controls over financial reporting using the criteria set forth in the 1992 COSO framework.

Item 9B – Other Information

On March 17, 2015, the Chugach Board of Directors (Board) appointed Bruce Dougherty to fill the seat vacated by David Gillespie.  Pursuant to Chugach’s bylaws, Mr. Dougherty’s current appointed term expires May 14, 2015.  The committees on which Mr. Dougherty will serve have yet to be determined. 

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, 59, Chair, was elected to the Board in 2008, and re-elected in 2011 and 2014. She currently serves on the Audit and Finance, Governance, and Operations Committees and is currently the Alaska Railbelt Cooperative Transmission & Electric Company (ARCTEC) representative.  She is a National Rural Electric Cooperative Association Credentialed Cooperative Director and has earned her Board Leadership Certificate.  Her term expires in May of 2018. 

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Susan Reeves, 66, 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 as the Vice Chair of the Operations Committee and 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, 68, 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 and re-elected in 2014.  He currently serves as the Vice Chair of the Audit and Finance Committee and as a member on the Governance Committee.  He is a National Rural Electric Cooperative Association Credentialed Cooperative Director.  His term expires in May of 2018.

James Nordlund, 62, 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 as a member on  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., 62, Director, is a former Alaska State Legislator, retired iron worker and a small-real estate developer.  He was elected to the Board in 2011 and re-elected in 2014.  He currently serves on the Governance and Audit and Finance Committees. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director.  His term expires in May of 2017.

Sisi Cooper, 34, 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 as a member of the Operations Committee. Her term expires in May of 2015.

Bruce Dougherty, 55, Director, is a health facilities inspector with the State of Alaska and a retired Lieutenant Colonel with the US Air Force Reserves.  He has extensive experience in the field of health care, serving at various levels in senior care, disease intervention, and disability adjudication.  He was appointed to the Board on March 17, 2015.  His term expires in May of 2015.

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Identification of Executive Officers

Bradley W. Evans,  60, 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.

Sherri McKay-Highers, 46, 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 16 years and has held various accounting management positions.

Paul R. Risse,  60, 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, 59, 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, 49, 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.

William J. Bernier,  67, was appointed Vice President, Power Delivery on November4, 2014.  Prior to that appointment he served as Acting Vice President, Power Delivery since June9, 2014, and Director, Substations and Line Operations since August 30, 1999.  Mr. Bernier has more than 45 years of experience in the Transmission, Distribution and Substation field.  Prior to his employment at Chugach, Mr. Bernier served in various management positions at Alcan Electrical & Engineering, Inc., Norcon, Inc., New England Power Service Company, and Commonwealth Electric Company, Inc.

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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 2014 Audit and Finance Committee include Chair Sisi Cooper and Directors Janet Reiser, James Nordlund, Jim Henderson 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.

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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 2014, 2013 and 2012, upon review of the performance of the CEO, Mr. Evans received bonuses of $95,000,$45,000 and $25,000, 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.

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Cash Compensation

The following table sets forth all remuneration paid by us for the last three fiscal years to each of our executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2014 and for all such executive officers as a group:

Summary Compensation Table

Name	Year	Salary		Bonus		Change in Pension Value and Nonqualified Deferred Compensation		All Other Compensation 1		Total
Bradley W. Evans,	2014	$	314,284	$	95,000	$	132,305	$	7,193	$	548,782
Chief Executive Officer	2013	$	305,192	$	45,000	$	248,897	$	4,542	$	603,631
	2012	$	299,998	$	25,000	$	249,325	$	15,924	$	590,247
Sherri L. McKay-Highers,	2014	$	154,275	$	7,000	$	37,000	$	4,214	$	202,489
Chief Financial Officer	2013	$	118,088	$	4,000	$	7,830	$	2,607	$	132,525
	2012	$	100,540	$	6,000	$	44,000	$	8,279	$	158,819
Paul R. Risse	2014	$	202,298	$	15,000	$	96,615	$	11,748	$	325,661
Sr. Vice President,	2013	$	187,960	$	20,000	$	152,114	$	12,389	$	372,463
Power Supply	2012	$	174,410	$	15,000	$	181,842	$	9,038	$	380,290
Lee D. Thibert,	2014	$	232,252	$	15,000	$	126,569	$	10,648	$	384,469
Sr. Vice President, Strategic	2013	$	214,773	$	12,500	$	153,767	$	9,120	$	390,160
Development & Regulatory Affairs	2012	$	199,919	$	15,000	$	245,090	$	13,278	$	473,287
Tyler E. Andrews,	2014	$	171,088	$	8,000	$	28,300	$	4,785	$	212,173
Vice President,	2013	$	158,777	$	10,000	$	29,760	$	5,692	$	204,229
Member and Employee Services	2012	$	153,056	$	5,000	$	34,865	$	10,375	$	203,296
William J. Bernier,	2014	$	166,913	$	1,000	$	50,174	$	8,682	$	226,769
Vice President,	2013	$	147,887	$	0	$	44,853	$	6,481	$	199,221
Power Delivery	2012	$	154,463	$	4,500	$	43,006	$	8,721	$	210,690
Edward M. Jenkin	2014	$	181,385	$	5,000	$	47,470	$	56,085	$	289,940
Former Vice President,	2013	$	177,269	$	12,500	$	123,923	$	7,747	$	321,439
Power Delivery	2012	$	173,078	$	5,000	$	205,556	$	3,488	$	387,122

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

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Pension Benefits

We have elected to participate in the NRECA 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.

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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, 2014 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	13.83	$	1,069,031	$	0
	Pension Restoration	13.83	$	133,084	$	0
Sherri L. McKay-Highers, Chief Financial Officer	Retirement Security	15.08	$	253,672	$	0
Paul R. Risse, Sr. VP, Power Supply	Retirement Security	18.92	$	1,006,556	$	0
Lee D. Thibert, Sr. VP, Strategic Dev & Reg Affairs	Retirement Security	26.33	$	1,564,546	$	0
Tyler E. Andrews, VP, Member and Employee Services	Retirement Security	5.75	$	174,302	$	0
William J. Bernier, VP, Power Delivery	Retirement Security	5.42	$	232,589	$	0
Edward M. Jenkin, Former VP, Power Delivery	Retirement Security	23.58	$	1,117,163	$	0

It is assumed that participants retire at the earlier of age 62 or 30 years of benefit service and elect a lump sum benefit.

Lump sum amounts are calculated using the 30-year Treasury rate (3.80 percent for 2014 and 2.80 percent for 2013) and the Pension Protection Act (PPA) three-segment yield rates (1.19 percent, 4.53 percent, and 5.66 percent for 2014 and 0.97 percent, 3.50 percent, and 4.60 percent for 2013) 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 2014 and 2013, respectively, combined unisex 50 percent/50 percent mortality in combination with the

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PPA rates). The lump sum is then discounted at 3.80 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2014, and 4.67 percent interest only (no mortality is assumed) from assumed retirement date back to December 31, 2013, 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 Change in last FY		Aggregate Withdrawals/ Distributions		Aggregate balance at FYE
Bradley W. Evans,	$	17,500	$	0	$	(5,966)	$	0	$	125,478
Chief Executive Officer
Tyler E. Andrews,	$	17,500	$	0	$	1,365	$	0	$	52,399
Vice President, Member and
Employee Services

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.

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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,	$	302,557
Chief Executive Officer
Sherri L. McKay-Highers,	$	119,879
Chief Financial Officer
Paul R. Risse,	$	237,278
Sr. Vice President, Power Supply
Lee D. Thibert,	$	166,367
Sr. Vice President, Strategic Development
& Regulatory Affairs
Tyler E. Andrews,	$	95,390
Vice President, Member and Employee
Services
William J. Bernier,	$	99,190
Vice President, Power Delivery

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.

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The following table sets forth the dollar amounts of all fees paid in cash by us for the fiscal year ending December 31, 2014, to each of our current and former Board members:

Director Compensation Table

Name	Fees Paid In Cash
Janet Reiser, Chair and Director	$	20,800
Susan Reeves, Vice-Chair and Director	$	12,250
Jim Henderson, Secretary and Director	$	13,700
Sisi Cooper, Treasurer and Director	$	14,700
James Nordlund, Director	$	10,450
Harry Crawford, Jr., Director	$	17,050
David Gillespie, Former Director	$	13,000

Threeincumbent Board members  werere-elected at Chugach’s annual membership meeting held on May 22, 2014.  Janet Reiser and Jim Henderson were elected to four year terms, while Harry Crawford was elected to a three-year term. David Gillespie resigned on February 5, 2015.

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

Not Applicable

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

Not Applicable

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Item 14 – Principal Accounting Fees and Services

The Audit 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, 2014.

Fees and Services

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

	2014		2013
Audit and audit-related services:
Audit and quarterly reviews	$	181,975	$	170,195
Audit-related services		36,105		48,705
Non-audit services:
Tax consulting and return preparation		10,350		12,175
Other services		0		0
Total	$	228,430	$	231,075

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, 2014 and 2013 were approved by the Audit and Finance Committee.

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PART IV

Item 15 – Exhibits and Financial Statement Schedules

	Page
Financial Statements
Included in Part II of this Report
Report of Independent Registered Public Accounting Firm	45
Balance Sheets, December 31, 2014 and 2013	46-47
Statements of Operations
Years ended December 31, 2014, 2013 and 2012	48
Statements of Changes in Equities and Margins
Years ended December 31, 2014, 2013 and 2012	49
Statements of Cash Flows
Years ended December 31, 2014, 2013 and 2012	50
Notes to Financial Statements	51-79

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

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EXHIBITS

Listed below are the exhibits, which are filed as part of this Report:

Exhibit Number	Description
3.1	Articles of Incorporation of the Registrant. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2001, SEC File No. 033-42125.
3.2	Bylaws of the Registrant. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated May 22, 2014, 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.

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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.
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.
4.29	Fourth Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated February 3, 2015. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated February 3, 2015, 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.
10.6	Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of January 30, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.

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10.6.1	First Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective as of February 10, 1995. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 1994, SEC File No. 033-42125.
10.6.2	Net Billing Agreement by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 16, 1987. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.6.3	Second Amendment to Modified Agreement for the Sale and Purchase of Electric Power and Energy by and among the Registrant, Matanuska Electric Association, Inc. and Alaska Electric Generation and Transmission Cooperative, Inc. dated effective September 30, 2008.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.

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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.
	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.

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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.
	Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.
10.26	Transmission Sharing Agreement by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.27	Amendment to Agreement for Sale of Transmission Capability by and among the Registrant, Homer Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power dated March 7, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.28	Bradley Lake Hydroelectric Agreement for the Dispatch of Electric Power and for Related Services between the Registrant and the Alaska Energy Authority dated February 19, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125.
10.29	Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated September 29, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.
10.29.1	Assignment of Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.

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10.30	Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated December 2, 1983. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.30.1	Addendum No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated August 8, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.30.2	Amendment No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated November 28, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.31	Gas Transportation Agreement by and among the Registrant, Alaska Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.
10.32	Eklutna Purchase Agreement by and among the Registrant, Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power and Alaska Power Administration. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
	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.
10.35	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.

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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 March 31, 2010, SEC File No. 033-42125.

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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 September 30, 2013, SEC File No. 033-42125.
10.59	Agreement Covering Terms and Conditions of Employment for Office and Engineering Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective September 13, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.
10.59.1	Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Office and Engineering Personnel dated effective July 1, 2010.Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125.
10.59.2	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 March 31, 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 March 31, 2013, SEC File No. 033-42125.

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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 March 31, 2013, 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.

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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.
10.75.1	First Amendment to the Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska, LLC effective September 15, 2014. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2014, 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 Annual Report on Form 10-K dated December 31, 2013, SEC File No. 033-42125.
10.77	2015 Interim Power Sales Agreement between the Registrant and Matanuska Electric Association, Inc. effective December 31, 2014. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated December 22, 2014, SEC File No. 033-42125.
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 Princpal 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.

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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

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on March 20, 2015.  

	CHUGACH ELECTRIC ASSOCIATION, INC.
By:	/s/ Bradley W. Evans
	Bradley W. Evans
	Chief Executive Officer
Date:	March 20, 2015

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Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 17, 2015, by the following persons on behalf of the registrant and in the capacities indicated:

/s/ Bradley W. Evans
Bradley W. Evans	Chief Executive Officer
	(Principal Executive Officer)
/s/ Sherri L. McKay-Highers
Sherri L. McKay-Highers	Chief Financial Officer
	(Principal Financial Officer)
	(Principal Accounting Officer)
/s/ Paul R. Risse
Paul R. Risse	Sr. Vice President, Power Supply
/s/ Brian Hickey for LDT
Lee D. Thibert	Sr. Vice President, Strategic Development &
	Regulatory Affairs
/s/ William J. Bernier
William J. Bernier	Vice President, Power Delivery
/s/ Tyler E. Andrews
Tyler E. Andrews	Vice President, Member and Employee Services
/s/ Janet Reiser
Janet Reiser	Director & Chair of the Board
Susan Reeves	Director & Vice Chair of the Board
/s/ Sisi Cooper
Sisi Cooper	Director & Treasurer of the Board
/s/ Jim Henderson
Jim Henderson	Director & Secretary of the Board

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/s/ James Nordlund
James Nordlund	Director
/s/ Harry T. Crawford, Jr.
Harry T. Crawford, Jr.	Director
/s/ Bruce Dougherty
Bruce Dougherty	Director

Supplemental Information to be Furnished With Reports Filed

Pursuant to Section 15(d) of the Act by Registrants

Which Have Not Registered Securities Pursuant to Section 12 of the Act

Chugach has not made an Annual Report to securities holders for 2014 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.

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