10-K

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, 2016

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.

2016 Form 10-K Annual Report

Table of Contents

PART I			Page
	Item 1.	Business	2
	Item 1A.	Risk Factors	8
	Item 1B.	Unresolved Staff Comments	14
	Item 2.	Properties	14
	Item 3.	Legal Proceedings	22
	Item 4.	Mine Safety Disclosures	22
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matter and Issuer Purchases of Equity Securities	23
	Item 6.	Selected Financial Data	23
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	40
	Item 8.	Financial Statements and Supplementary Data	41
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	85
	Item 9A.	Controls and Procedures	85
	Item 9B.	Other Information	86
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	86
	Item 11.	Executive Compensation	90
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	96
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	96
	Item 14.	Principal Accounting Fees and Services	97
PART IV
	Item 15.	Exhibits, Financial Statement Schedules	98
		SIGNATURES	110

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

Chugach is one of the largest electric utilities in Alaska. We are engaged in the generation, transmission and distribution of electricity in the Anchorage and upper Kenai Peninsula areas. Chugach is on an interconnected regional electrical system referred to as the Alaska 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 preceding year. This tax is collected monthly and remitted annually. In addition, we currently collect a regulatory cost charge (RCC) of $0.000675 per kWh of retail electricity sold. The RCC is

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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 on retail electricity sold to consumers in Whittier, seasonally (April through September), and in the Kenai Peninsula Borough, monthly. 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 288 employees as of March 3, 2017. Approximately 70% of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW. We also have an agreement with the Hotel Employees and Restaurant Employees (HERE). All three IBEW CBA have been renewed through June 30, 2021. The three CBA provide for wage and pension contribution increases in all years and include health and welfare premium cost sharing provisions. The HERE contract was renewed through June 30, 2021, and provides for wage, pension contribution, and health and welfare contribution increases in all years.We believe our relationship with our employees is good.

Our members are the consumers of the electricity sold by us. As of December 31, 2016, we had one wholesale customer, 68,215 retail members, and 83,855 service locations, including idle services. No individual retail customer accounts for more than ten percent of our revenue. Our customers’ requirements for capacity and energy generally peak in fall and winter as home heating and lighting needs rise and then decline in the spring and summer as the weather becomes milder and daylight hours increase.

We supply power to the City of Seward (Seward) as a wholesale customer, and provided most of the power requirements of Matanuska Electric Association, Inc. (MEA) through the expiration of their contract on April 30, 2015. Through March 31, 2015, we sold economy (non-firm) energy to Golden Valley Electric Association, Inc. (GVEA), which used that energy to serve its own load.

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 Consolidated Statements of Operations and Changes in Equities and Margins 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 Chugach Board of Directors deems it appropriate to do so.

In 2016, we had 531.2 megawatts (MW) of installed generating capacity (rated capacity) provided by 16 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% interest, and Eklutna Hydroelectric Project, in which we own a 30% interest. Of the 531.2 MW of installed generating capacity, approximately 87% was fueled by natural gas. The rest of our owned generating resources were hydroelectric facilities. In 2016, 77% of Chugach’s power, including purchased power, was generated from gas. Of that gas-fired generation, 88% took place at SPP and 9% took place at Beluga. The SPP furnishes up to 200.2 MW of capacity; Chugach owns 70% of this plant’s output and Anchorage Municipal Light & Power (ML&P) owns the remaining 30%. 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 up

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to 0.9 MW for our remaining wholesale customer. For more information concerning Bradley Lake, see “Item 2 – Properties – Other Property – Bradley Lake.” In addition, we purchase up to 17.6 MW from Fire Island Wind, LLC (FIW), annually. We operate 1,719 miles of distribution line and 434 miles of transmission line, which includes Chugach’s share of the Eklutna transmission line. For the year ended December 31, 2016, we sold 1.2 billion kWh of electrical power.

Customer Revenue from Sales

Economy energy/other includes sales to GVEA, MEA and ML&P.

Retail Service Territory

Our retail service area covers most of Anchorage,excluding downtown Anchorage, as well as remote mountain areas and villages. The service area ranges from the northern Kenai Peninsula westward to Tyonek, including Fire Island, and eastward to Whittier.

Retail Customers

As of December 31, 2016, we had 68,215 members receiving power from 83,855 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 ten percent of our revenues. The revenue contributed by retail customers for the years ended December 31, 2016, 2015 and 2014 is discussed in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Year ended December 31, 2016, compared to the year ended December 31, 2015, and the year ended December 31, 2015, compared to the year ended December 31, 2014 – Revenues.”

Wholesale Customers

We are the principal supplier of power to Seward under a wholesale power contract. We were the principal supplier of power to MEA through April 30, 2015. Our wholesale power contracts, including the fuel and purchased power components, contributed $4.9 million, $30.9 million, and $75.5 million in revenues for the years ended December 31, 2016, 2015 and 2014, respectively.

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MEA

We had a power sales contract with MEA, which was in effect through December 31, 2014. In 2004, pursuant to terms of this contract, MEA communicated to Chugach that MEA did not desire to renew, extend or modify the agreement. MEA indicated it would follow the path its membership most favored and move forward with plans to build its own generation plant.

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.

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 Dispatch Services Agreement was in effect through March 31, 2016.

On March 31, 2015, Chugach entered into a Memorandum of Understanding (MOU) with MEA to extend the Interim Power Sales Agreement for one month while MEA continued to prepare its EGS and supervisory control and data acquisition (SCADA) system for commercial operation. This MOU also delayed the implementation of the Dispatch Services Agreement to May 1, 2015. The Interim Power Sales Agreement with MEA expired on April 30, 2015. Wholesale power sales to MEA represented approximately 0%, 17%, and 33% of Chugach’s total energy sales for the years ended December 31, 2016, 2015, and 2014, 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 $4.1 million and $3.2 million at December 31, 2016, and 2015, respectively.

Seward

We currently provide nearly all the power needs of the City of Seward. Sales to Seward represented approximately 5%, 4%, and 3% of Chugach’s total energy sales for the years ended December 31, 2016, 2015, and 2014, respectively. We entered into the 2006 Agreement for the Sale and Purchase of Electric Power and Energy between Chugach Electric Association, Inc. and the City of Seward (2006 Agreement), effective June 1, 2006. The 2006 Agreement contains an evergreen clause providing for an automatic five-year extension unless written notice is provided at least one year prior to the expiration date. Neither Chugach nor Seward provided written notice to terminate as both utilities desired to extend the term of the agreement.

On June 2, 2016, Chugach submitted an updated listing of its special contracts to reflect the extension of the expiration date of the 2006 Agreement from December 31, 2016, to December 31, 2021. On July 18, 2016, the RCA approved the filing.

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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 retail customers for whom Chugach has an obligation to provide reserves. 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

Periodically, Chugach sells available generation, in excess of its own needs, to other electric utilities. Sales are made under the terms and conditions of Chugach’s economy energy sales tariff. The price includes the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin.

From 1989 through March 31, 2015, we sold, under contract, economy (non-firm) energy to GVEA, which used that energy to serve its own loads. During 2016, we continued to make non-firm, economy energy sales to GVEA on an as needed basis.Non-firm sales to GVEA were 25,000 MWh, 96,259 MWh and 358,988 MWh for 2016, 2015, and 2014, respectively.

Rate Regulation and Rates

The RCA regulates our rates. We seek changes in our base rates by submitting 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 a 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.

Alaska Statute 42.05.175 requires the RCA to issue a final order no later than 15 months after a complete tariff filing is made for a tariff filing that changes a 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 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 governing our outstanding long-term indebtedness do not impose any greater TIER requirement than those previously approved by the RCA.

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

The Second Amended and Restated Indenture of Trust (the Indenture), which became effective January 20, 2011, governs all of our outstanding bonds and requires us to set rates expected to yield margins for interest equal to at least 1.10 times total interest expense. The Second Amended and Restated Master Loan Agreement with CoBank, ACB (CoBank) which became effective June 30, 2016, also requires Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. The Credit Agreement with National Rural Utilities Cooperative Finance Corporation (NRUCFC), KeyBank National Association, Bank of America, N.A., and CoBank, 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, 2016, 2015 and 2014, our Margins for Interest/Interest (MFI/I) was 1.27, 1.29, and 1.28, respectively. For the same periods, our TIER was 1.27, 1.30, and 1.29, respectively.

Our Service Areas and Local Economy

Our service areas and the service area of our wholesale customer reside within the Alaska Railbelt region of Alaska which is 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.

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.

Sales Forecasts

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

Sales (MWh)	2017	2018	2019	2020	2021
Retail	1,093,147	1,082,901	1,072,072	1,061,351	1,064,005
Wholesale	58,259	58,889	58,300	57,717	57,861
Total	1,151,406	1,141,790	1,130,372	1,119,068	1,121,866

Energy sales are expected to slightly decline due to slow economic growth and progress in energy efficiency and conservation from 2017 to 2020. These projections are based on assumptions that management believes to be reasonable as of the date the projections were made. The occurrence of a significant change in any of the assumptions could affect a change in the projected sales forecast.

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Item 1A – Risk Factors

Chugach’s consolidated financial results will be impacted by weather, the economy of our service territory, fuel availability and prices, 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, in the view of management, may significantly affect our consolidated financial condition, results of operations and cash flows. This discussion is not exhaustive. You may view risks differently than we do, or there may be other risks and uncertainties which you consider important which are not discussed. These risks, whether discussed below or those unknown, could negatively affect our business operations and financial condition.  The statements below must be read together with factors discussed elsewhere in this document and in our other filings with the SEC.

Financing

On June 13, 2016, Chugach replaced the $100 million unsecured Credit Agreement, amended and extended on June 29, 2012, and due to expire on November 17, 2016. The new Credit Agreement is a $150 million senior unsecured credit facility under which Chugach may borrow funds necessary for general corporate purposes, to issue standby letters of credit or to pay amounts due under short-term promissory notes (commercial paper) issued by Chugach, in the event of a disruption in the commercial paper markets. The new Credit Agreement is due to expire on June 13, 2021.

On June 30, 2016, Chugach entered into the Second Amended and Restated Master Loan Agreement with respect to a $45.6 million term loan with CoBank, ACB, due April 30, 2031. This agreement was entered into for the purpose of repaying outstanding commercial paper used to finance Chugach’s investment in the Beluga River Unit. The term loan bears an interest rate of 2.58% per annum. Interest and principal is paid quarterly and commenced on July 20, 2016.

On July 13, 2016, Chugach used commercial paper to pay down the outstanding balance on its 2011 CoBank Note.Chugach is expected to continue to issue commercial paper in 2017, as needed.  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 Credit Agreement would effectively replace 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.

Credit Ratings

Changes in our credit ratings could affect our ability to access capital. We maintain a rating from Standard & Poor's Rating Services (S&P) and Fitch Ratings (Fitch) of "A-" (Stable) and "A" (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, our commercial paper rates could increase immediately and we may be required to pay higher interest rates on financings which we need to undertake in the future. Additionally our potential pool of investors and funding sources could decrease.

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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. Chugach has not experienced any disruptions or significant costs associated with intentional attacks or unauthorized access to any of our systems. While Chugach has numerous programs in place to safeguard our operating systems and the personal information of our customers and employees, the physical or cyber security compromise of our facilities could adversely affect our ability to manage our facilities effectively.

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 multi-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.

On December 14, 2016 the Chugach Board of Directors approved a prepayment of $7.9 million to the NRECA Retirement Security plan. Using the low interest rate environment, this prepayment will mitigate the impact of future contribution increases and will lower annual budgetary impacts of current contributions over an eleven year term.

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 contractual 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, which is not otherwise available from the fleet of Chugach generators, from other sources at unpredictable costs in order to supply our customers and comply with our contractual agreements. The fuel and purchased power rate adjustment process allows Chugach to recover current purchased power costs and to recover under-recoveries or 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 rate adjustment to recover those costs at the time of the next

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quarterly fuel and purchased power rate adjustment filing. As a result, cash flows may be impacted due to the lag in payments for purchased power costs and the corresponding collection of those costs from customers. To the extent the regulatory process does not provide for the timely recovery of purchased power costs, Chugach could experience a material negative impact on its cash flows. Chugach has line of credit and commercial paper borrowing capacity to mitigate this risk.

Fuel Supply

In 2016, 77% of our power was generated from natural gas. Our primary sources of natural gas in 2016 were Hilcorp ConocPhillips, ML&P, and Chugach’s 10% share of the Beluga River Unit. Chugach currently has gas contracts in place to fill up to 100% of Chugach’s needs through March 31, 2023. Chugach also has agreements with Cook Inlet Energy (CIE), AIX Energy, LLC, and ML&P which provide a structure to purchase supplemental gas, adding diversity in Chugach’s sources of natural gas to meet system load requirements.

On April 21, 2016, the RCA approved the acquisition of the Beluga River Unit effective January 1, 2016, as discussed in “Item 8 - Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Beluga River Unit and Note 15 – Beluga River Unit.” The acquisition complements existing gas supplies and is expected to provide greater fuel diversity at an effective annual cost that is $2 million to $3 million less than alternative sources of gas in the Cook Inlet region.

The acquisition is expected to provide gas to meet Chugach’s on-going generation requirements over an approximate 18-year period. Gas associated with the acquisition is expected to provide about 15% of Chugach’s gas requirements through 2033, although actual gas quantities produced are expected to vary on a year-by-year basis.

The State of Alaska’s Department of Natural Resources (DNR) published a study in September of 2015, “Updated Engineering Evaluation of Remaining Cook Inlet Gas Reserves,” to provide an estimate of Cook Inlet’s gas supply. The study estimated there are 1,183 Bcf of proved and probable reserves remaining in Cook Inlet’s legacy fields. This is higher than the 2009 DNR study estimate of 1,142 Bcf. Effectively, Cook Inlet gas supply has slightly increased from 2009. The 2015 DNR estimate does not include reserves from a large gas field under development by Furie Operating Alaska, LLC (Furie) and another considered for development by BlueCrest Energy, Inc. Furie has constructed an offshore gas production platform and has achieved production. The platform and other production facilities are designed for up to 200 million cubic feet (MMcf) per day. Other gas producers are actively developing gas supplies in the Cook Inlet. Chugach is encouraged with these developments but continues to explore other alternatives to diversify its portfolio.

The Alaska Gasline Development Corporation (AGDC) is investigating a project to deliver North Slope gas to Southcentral Alaska for export. AGDC expects to complete the FERC license application and assess gas markets by mid-2018. The gas pipeline is expected to include off-take points to allow for the opportunity for future in-state deliveries of natural gas. If the project moves forward, the pipeline is expected to be completed in the mid 2020’s.

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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 was 1.7 Bcf in 2016. Chugach is entitled to withdraw gas at a rate of up to 35 million cubic feet (MMcf) per day.

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 adjustment process which will ensure, in advance, that costs incurred under the contracts can be recovered from Chugach’s customers. The fuel and purchased power adjustment process collects under-recoveries and refunds over-recoveries from prior periods with minimal regulatory lag. Chugach's fuel and purchased power adjustment process includes quarterly filings with the RCA, which set 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 filing. Chugach over-recovered $3.8 million and $5.1 million at December 31, 2016, and 2015, respectively. To the extent the regulated fuel and purchased power adjustment 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.

Regulatory

Chugach’s billing rates are approved by the RCA. Chugach filed its June 2014 General Rate Case on February 13, 2015, to reflect revenue and cost changes resulting from the April 30, 2015, expiration of the 2015 Interim Power Sales Agreement between MEA and Chugach. Chugach requested a system base rate increase of approximately $21.3 million on total base rate revenues. The RCA issued Order U-15-081(1) on April 30, 2015, suspending the filing and granting Chugach’s request for interim and refundable rate increases effective May 1, 2015. On May 2, 2016, the RCA issued Order U-15-081(8) accepting a stipulation between Chugach and the Attorney General (AG). On May 20, 2016, Chugach submitted updated revenue requirement, cost of service and tariffs reflecting the results of the stipulation, with proposed final rates effective July 5, 2016, which were subsequently approved by the RCA.

On June 27, 2016, the RCA issued Order U-15-081(11) resolving the outstanding issues related to transmission and ancillary services. On July 15, 2016, Chugach submitted updated tariff sheets and supporting exhibits for the calculation of transmission and ancillary service rates. On August 23, 2016, the RCA approved final rates contained in Chugach’s July 15, 2016, compliance filing. A final order closing the docket was issued on October 6, 2016. See “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – June 2014 Test Year General Rate Case.”

On July 1, 2016, Chugach returned to the SRF process filing its first energy and demand rate adjustment, with rates effective August 15, 2016. This filing was subsequently approved by the RCA on August 12, 2016. Chugach submitted its June 2016 and September 2016 test year SRFs with the RCA on August 29, 2016, and December 1, 2016, respectively, as informational filings with no changes to the demand and energy rates. See “Item 8-Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Simplified Rate Filings.”

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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.

Accounting Standards or Practices

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

Green House Gas Regulations, Carbon Emission and Climate Change

Uncertainty remains regarding the impacts of potential regulations regarding greenhouse gases (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. On August 3, 2015, the EPA released the final 111(d) regulation aimed at reducing emissions of carbon dioxide (CO₂) from existing power plants. Alaska is not bound by the 111(d) regulation, however Alaska may be required to comply at some future date. On February 9, 2016 the U.S. Supreme Court issued a stay on the proposed EPA 111(d) regulations until the DC Circuit decides the case, or until the disposition of a petition to the Supreme Court on the issue. On September 27, 2016, the US Court of Appeals for the District of Columbia Circuit heard oral arguments challenging the legality of the Clean Power Plan. The court is expected to issue a decision in the near future. The EPA 111(d) regulation, in its current form, is not expected to have a material effect on Chugach’s financial condition, results of operations, or 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. 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.

Other Environmental Regulations

Since January 1, 2007, transformer manufacturers have been required to meet the United States Department of Energy (DOE) efficiency levels as defined by the Energy Act of 2005 (Energy Act) for all “Distribution Transformers.” As of January 1, 2016, the specific efficiency levels are increasing from the original “TP1” levels to the new “DOE-2016” levels. All new transformers are DOE-2016 compliant. At this time a small increase in capital costs is anticipated along with a reduction in energy losses.

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 GHG or carbon emissions. Failure to comply with environmental laws and regulations could have a material effect on

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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 facilities could result in significant additional costs to Chugach and a material adverse impact to Chugach’s results of operations, financial condition, and cash flows.

Aging Plant

Many of our facilities were constructed over 30 years ago and, as a result, may require significant capital expenditures to maintain efficiency and reliability. As plant equipment ages, the potential for operational issues such as unscheduled outages increases which could negatively impact our cost of electric service. With the addition of the SPP generating facility which began operation in 2013, we are able to significantly reduce the reliance on some of the older facilities. The older units are used for peaking, and, in the future, may be primarily used as a reserve. Mitigating the aging risk is Chugach’s experienced work force, extensive maintenance program, and predictive maintenance measures. Also mitigating the risk of significant unanticipated capital expenditures associated with generation maintenance is a long-term service agreement smoothing major maintenance costs for our largest power producer, SPP. Additionally, we are working to establish the Power Pooling and Joint Dispatch Agreement which will allow us to buy power from other utilities if it is more efficient and economical than generating it on our own.

Distributed Generation

Distributed generation technologies, such as combined heat and power, solar cells, micro turbines, fuel cells, batteries, and wind turbines currently exist or are in development. Significant technological advancements or positive perceptions regarding the environmentally friendly benefits of self-generation and distributed energy technologies could lead to the adoption of these technologies by our members. Increased adoption of these technologies could reduce demand for electricity and the pool of customers from whom we recover fixed costs. This could have a negative impact on our business, financial condition, or cost of electric service.

Constraints on Transmission

We currently experience occasional constraints on our transmission system and those of other utilities used to transmit energy from our remote generators to loads due to periodic maintenance activities, equipment failures and other system conditions. We manage these constraints using alternative generation dispatch and energy purchasing patterns. The long-term solution for reducing transmission constraints can include purchasing additional wheeling service from other utilities, or construction of additional transmission lines which would require significant capital expenditures.

Construction of new transmission lines presents numerous challenges. Environmental and state and local permitting processes can result in significant inefficiencies and delays in construction. These issues are unavoidable and are addressed through long-term planning. We typically begin planning new transmission at least 10 years in advance of the need and foster and participate in regional and interregional transmission planning and cost allocation discussions with neighboring transmission providers. In the event that we are unable to complete construction of planned transmission expansion, we must rely on purchases of electric power, which could put increased pressure on electric rates.

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Counterparties

We rely on other entities in the production of power and supply of fuel and therefore, we are exposed to the risk that these counterparties may default in performance of their obligations to us. As a 70% owner in SPP, a 30% owner in the Eklutna Hydroelectric Project, and a 10% owner in the Beluga River Unit (BRU), we rely upon the other owners to fulfill their contractual and financial obligations. Additionally we rely on numerous other entities with whom we have purchased power agreements. Failure of our counterparties to perform their obligations could increase the cost of electric service we provide to our members as we, for example, may be forced to enter into alternative contractual arrangements or purchase energy or natural gas at prices that may exceed the prices previously agreed upon with the defaulting counterparty.

Legal Proceedings

Chugach has certain litigation matters and pending claims that arise in the ordinary course of business as discussed under “Item 3 – Legal Proceedings.” We cannot predict the outcome of any current or future legal proceedings. Our business, financial condition, and results of operations could be materially adversely affected by unfavorable resolution or adverse results of legal matters.

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

As of December 31, 2016, we had 531.2 MW of installed capacity consisting of 16 generating units at five power plants. These included 332.0 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; 28.2 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.

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 Homer Electric Association, Inc. (HEA) and dispatched by Chugach, and MEA’s newly constructed 171 MW EGS, which is also dispatched by Chugach. In 2016, we also purchased power from 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).

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Generation Assets

We own the land and improvements comprising our generating facilities at Beluga, IGT and SPP. Our principal generation assets are in two plants, Beluga and SPP. With SPP in operation, the Beluga units are used for peaking, ad, in the future, may be primarily used 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.  All Beluga units have been inspected annually with combustion and hot gas path parts replaced according to their condition or as recommended by the manufacturer. Units 6 and 7, the largest Beluga units, are approaching their recommended major inspection intervals based on fired hours. Units 3 and 5 are most often run for peak demand and are being considered for major parts replacements and generator inspections over the next three years.

On February 1, 2013, SPP began commercial operation, contributing 200.2 MW of capacity provided by 4 generating units. Chugach owns 70% of this plant and ML&P owns the remaining 30%. Each owner takes a proportionate share of power from SPP. Our principal generation units at SPP are Units 10, 11, 12, and 13. Since the units have been in commercial operation, SPP units have received preventative maintenance inspections consistent with original equipment manufacturer (OEM) recommendations through 2016. The gas turbine generators of Units 11, 12, and 13 receive two internal combustion system inspections each and one full package inspection annually. In 2016, Unit 11 gas turbine was replaced with a spare gas turbine. The removed gas turbine was prepared for another full cycle of operation by the OEM and Chugach technicians under our Contractual Service Agreement. The turbine was then staged at the power plant awaiting the next engine rotation. All three steam-generating boilers were internally inspected as well as hydrotested in accordance with OEM recommendations.

The Cooper Lake Hydroelectric Project is partially located on federal lands. Chugach owns, 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 required Chugach to establish a flow regime in Cooper Creek below the Cooper Lake Dam. This project included a Stetson Creek Diversion (Dam), Pipeline (Conveyance System) and Cooper Lake Outlet Works. The project was designed to replace colder water flowing into the Cooper Creek drainage from Stetson Creek with warmer Cooper Lake water. Project construction was completed in July 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 in October 2015 and August 2016.

The Eklutna Hydroelectric Project is located on federal land pursuant to a United States Bureau of Land Management right-of-way grant issued in Octoberof 1997. The facility is jointly owned, operated and maintained by Chugach, MEA, and ML&P with ownership shares of 30%, 17%, and 53%, respectively. 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 2016, percentages of contribution and other historical information for all Chugach generation units.

Facility	Commercial Operation Date	Nomenclature	Rating (MW)(1)		Run Hours (2016)		Percent of Total Run Hours	Percent of Time Available
Beluga Power Plant (2)
1	1968	GE Frame 5	19.6		219.2		0.44	96.7
2	1968	GE Frame 5	19.6		575.9		1.16	96.1
3	1973	GE Frame 7	64.8		1,793.6		3.61	92.5
5	1975	GE Frame 7	68.7		1,492.7		3.00	90.4
6	1976	GE 11DM-EV	79.2		42.8		0.09	72.8
7	1978	GE 11DM-EV	80.1		76.2		0.15	90.4
			332.0
Cooper Lake Hydroelectric Project
1	1960	BBC MV 230/10	9.6		4,843.0		9.74	98.6
2	1960	BBC MV 230/10	9.6		6,682.0		13.43	98.6
			19.2
IGT Power Plant (7)
1	1964	GE Frame 5	14.1		9.1		0.02	57.6
2	1965	GE Frame 5	14.1		8.2		0.02	91.8
			28.2
Southcentral Power Project
10	2013	Mitsubishi SC1F-29.5 (6)	40.2	(5)	8,776.0		17.64	95.7
11	2013	GE LM6000 PF	33.3	(5)	8,194.0		16.47	93.1
12	2013	GE LM6000 PF	33.3	(5)	8,438.0		16.96	93.1
13	2013	GE LM6000 PF	33.3	(5)	8,593.0		17.27	95.3
			140.1
Eklutna Hydroelectric Project
1	1955	Newport News	5.8	(3)	N/A	(4)		94.4
2	1955	Oerlikon custom	5.9	(3)	N/A	(4)		94.1
			11.7
System Total			531.2		49,743.7		100.00
(1) Capacity rating in MW at 30 degrees Fahrenheit.
(2) Beluga Unit 4 was retired during 1994.  Beluga Unit 8 was retired in April of 2015.
(3) The Eklutna Hydroelectric Project is jointly owned by Chugach, MEA and ML&P. The capacity shown is our 30% share of the plant's output under normal operating conditions. The actual nameplate rating on each unit is 23.5 MW.
(4) Run hours are not recorded by Chugach for the Eklutna Hydroelectric Project as it is maintained by a committee of three owners.
(5) The Southcentral Power Project is jointly owned by Chugach and ML&P. The capacity shown is our 70% share of the plant's output under normal operating conditions. The actual nameplate rating for the project is 200.2 MW.
(6) 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).
(7) IGT Unit 3 was retired in August of 2015.
Note: GE = General Electric, BBC = Brown Boveri Corporation

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Transmission and Distribution Assets

As of December 31, 2016, our transmission and distribution assets included 42 substations and 434miles of transmission lines, which included Chugach’s share of the Eklutna transmission line, 896 miles of overhead distribution lines and 823 miles of underground distribution line. 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% 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 Joint Base Elmendorf-Richardson; the West Terminal Site is under rights from the Matanuska-Susitna Borough; 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 is under rights by FERC License, until a permit is issued by Chugach State Park. The Cooper Lake Power Plant, Quartz Creek Substation, and the 69kV transmission line between them are operated under a FERC 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% (27.4 MW as currently operated) share in the Bradley Lake project’s output, and currently take Seward’s share which we net bill to them, for a total of 31.4% of the project’s capacity. We are obligated to pay 30.4% of the annual project costs regardless of project output.

The project was financed and built by AEA through grants from the State of Alaska and the issuance of $166.0 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 Alaska Electric Generation & Transmission Cooperative, Inc. (AEG&T) and Alaska Electric and Energy Cooperative, Inc.(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 $19.0 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%. Upon default, Chugach could be faced with annual expenditures of approximately $6.0 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. Diverting a portion of Battle Creek into Bradley Lake is currently estimated to increase annual energy output by 37,000 MWh. Chugach would be entitled to 30.4% 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%), MEA (17%) and ML&P (53%). Through April 30, 2015, the power MEA purchased from the Eklutna Hydroelectric Project was pooled with Chugach’s purchases and sold back to MEA to be used to meet MEA’s overall power requirements.

Beluga River Unit (BRU)

On April 22, 2016, Chugach commenced receiving gas from the BRU as a Working Interest Owner (WIO) of the gas production field. Chugach acquired a  10% working interest in the Beluga River Unit by jointly purchasing, in partnership with ML&P, ConocoPhillips’ 1/3 Working Interest Ownership of the BRU. From April 22, 2016 Chugach received 1.2 Bcf from the BRU field at the field’s delivery meter as a WIO. Of that gas volume received Chugach allocated gas deliveries of 380 MMcf to the COP/APC (ENSTAR) contract (average price of $7.27 per Mcf), 608 MMcf to the COP/Chugach contract (average price of $2.214 per Mcf), and retained 219 MMcf for Chugach native use in thermal generation, which had a calculated transfer price of $5.88 per Mcf.

Fuel Supply

In 2016, 77% of our power was generated from natural gas. Total gas purchased and produced in 2016 was approximately 8.8 Bcf. All of the production came from Cook Inlet, Alaska. The contract with Hilcorp provided 54%, with ConocoPhillips (assigned to Chugach and ML&P in 2016) provided 40% and the balance from Chugach’s 10% share of the Beluga River Unit gas field, with minor purchases from AIX and CIE. Of the 8.8 Bcf of gas purchased and produced, 0.4 Bcf was sold to ENSTAR as part of an existing ConocoPhillips-ENSTAR gas contract that was assumed with Chugach’s share of the BRU acquisition. The gas contract with ConocoPhillips began providing gas in 2010 and expired December 31, 2016. On April 22, 2016, 70% of the Chugach-ConocoPhillips contract was assigned to ML&P. The current gas contract with Hilcorp began providing gas in 2011 and will expire March 31, 2023. The BRU and Hilcorp, together, fill 100% of Chugach’s firm needs through March 31, 2023. Gas to provide economy energy sales to GVEA was supplied by a gas supply arrangement with Hilcorp through March of 2015.

ConocoPhillips and ML&P

Chugach entered into a contract with ConocoPhillips in 2009, which started providing gas January 1, 2010, and expired December 31, 2016. This contract was assumed by Chugach and ML&P as part of the BRU acquisition, on the basis of ownership share. As such, Chugach paid ML&P for 70% of gas purchased under this contract.

The gas supplied by ConocoPhillips/ML&P under the contract was separated into two volume tranches for pricing purposes. “Firm Fixed Quantity” gas met a portion of Chugach’s base load requirements, while “Firm Variable Quantity” gas met peaking needs. After December 31, 2013, all of the gas purchased under the contract was firm fixed since firm variable gas was not provided by the contract. The ConocoPhillips/ML&P contract during 2016 had a fixed volume delivery of 18,000 thousand cubic feet (Mcf) per day at the Firm Fixed Quantity price.

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Pricing for firm fixed gas was based on the average of five Lower 48 natural gas production areas. The contract price was 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.

Hilcorp

Chugach entered into a contract with Hilcorp to provide gas beginning January 1, 2015, through March 31, 2018. In September 2014, the RCA approved an amendment to extend through March 31, 2019, then another amendment in September 2015 to extend through March 31, 2023. The total amount of gas under contract is currently estimated to be 60 Bcf. Pricing for the 2016 term of the Hilcorp contract was set at $7.42 per Mcf.

Chugach entered into a Gas Sales and Purchase Agreement with Hilcorp for the purchase of gas.  This agreement was intended for Chugach to produce economy energy for GVEA. GVEA reimbursed Chugach for the cost of gas related to economy energy sales.

Cook Inlet Energy, LLC

Chugach entered into a Gas Sale and Purchase Agreement (GSPA) with CIE in 2013, to 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. In an extension letter agreement dated February 17, 2017, both parties agreed to extend the term of the agreement until March 31, 2023. 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.

AIX Energy, LLC

Chugach entered into a contract with AIX Energy, LLC (AIX) in 2014, to supply gas from March 1, 2015, through February 29, 2016. This agreement caps the price of gas at $6.24 per Mcf and the total volume at 300,000 Mcf. In anticipation of this agreement’s expiration, Chugach entered into another gas sale and purchase agreement with AIX in November of 2015, to provide gas beginning April 1, 2016, through March 31, 2023, with the option to extend to March 31, 2029. The AIX agreements provide flexibility in both the purchase price and volumes and allow Chugach to further diversify its gas supply portfolio, with no minimum purchase requirements.

Municipality of Anchorage, dba Municipal Light and Power

Chugach entered into a contract with Municipality of Anchorage, DBA Municipal Light and Power (ML&P) in 2016, to supply gas from June 6, 2016, through March 31, 2017. This agreement caps the price of gas at $5.75 per Mcf and the total volume at 500,000 Mcf. The ML&P agreement provides Chugach the ability to further diversify its gas supply portfolio, with no minimum purchase requirements.

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Natural Gas Transportation Contracts

The terms of the ConocoPhillips/ML&P and Hilcorp agreements require Chugach to transport gas. Chugach took over the transportation obligation for natural gas shipments for gas supplied under its contracts on October 1, 2010. The following information summarizes the transportation obligations for Chugach:

ENSTAR (Alaska Pipeline Company)

ENSTAR Natural Gas Company (ENSTAR) has a tariff to transport our gas purchased from gas suppliers on a firm basis to our IGT Power Plant and SPP.

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

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.

21

Since January 1, 2007, transformer manufacturers have been required to meet the DOE efficiency levels as defined by the Energy Act for all “Distribution Transformers.” As of January 1, 2016, the specific efficiency levels are increasing from the original “TP1” levels to the new “DOE-2016” levels. All new transformers are DOE-2016 compliant. At this time a small increase in capital costs is anticipated along with a reduction in energy losses.

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 August 3, 2015, the EPA released the final 111(d) regulation language aimed at reducing emissions of CO₂ from existing power plants that provide electricity for utility customers. In the final rule, the EPA took the approach of making the individual states responsible for the development and implementation of plans to reduce the rate of CO₂ emissions from the power sector. The EPA has initially applied the final rule to 47 of the contiguous states. At this time Alaska, Hawaii, Vermont, Washington D.C. and two U.S. territories are not bound by the regulation. Alaska may be required to comply at some future date. On February 9, 2016 the U.S. Supreme Court issued a stay on the proposed EPA 111(d) regulations until the DC Circuit decides the case, or until the disposition of a petition to the Supreme Court on the issue. On September 27, 2016, the US Court of Appeals for the District of Columbia Circuit heard oral arguments challenging the legality of the Clean Power Plan. The court is expected to issue a decision in the near future. The EPA 111(d) regulation, in its current form, is not expected to have a material effect on Chugach’s 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 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.

Item 3 – LegalProceedings

Chugach has certain 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

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PART II

Item 5 – Marketfor Registrant'sCommon Equity, Related Stockholder Matters

andIssuer Purchases of Equity Securities

Not Applicable

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	2016		2015		2014		2013		2012
Electric plant, net:
In service	$	696,415,738	$	659,275,066	$	657,899,592	$	670,476,634	$	442,515,434
Construction work in progress		18,455,940		15,601,374		21,567,341		28,674,163		263,459,794
Electric plant, net		714,871,678		674,876,440		679,466,933		699,150,797		705,975,228
Other assets		121,284,452		110,437,674		126,244,688		139,033,241		156,626,138
Total assets	$	836,156,130	$	785,314,114	$	805,711,621	$	838,184,038	$	862,601,366
Capitalization:
Long-term debt		442,890,253		446,227,620		473,024,497		496,914,274		521,597,086
Equities and margins		185,515,525		181,637,381		176,925,299		175,795,865		166,764,373
Total capitalization	$	628,405,778	$	627,865,001	$	649,949,796	$	672,710,139	$	688,361,459
Equity Ratio1		29.5%		28.9%		27.2%		26.1%		24.2%
Operations Data
Operating revenues	$	197,747,579	$	216,421,152	$	281,318,513	$	305,308,427	$	266,971,468
Operating expenses		171,140,389		188,791,558		252,972,879		278,738,497		248,194,955
Interest expense		21,856,095		22,194,290		23,264,041		24,691,582		24,085,371
Capitalized interest		(454,798)		(379,845)		(463,335)		(1,310,110)		(9,682,440)
Net operating margins		5,205,893		5,815,149		5,544,928		3,188,458		4,373,582
Nonoperating margins		607,963		687,703		970,617		7,355,585		1,151,925
Assignable margins	$	5,813,856	$	6,502,852	$	6,515,545	$	10,544,043	$	5,525,507
Margins for Interest Ratio2		1.27		1.29		1.28		1.43		1.23

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 dividedby the sum of long and short-term interest expense, excluding amounts capitalized.

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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, 2016, 2015 and 2014 was $21,168,967, $21,811,573 and $22,820,866, respectively. Chugach’s authorized TIER for ratemaking purposes on a system basis was 1.30 through July 4, 2016, which was established by the RCA in order U-01-08(26) on January 31, 2003. Pursuant to RCA order U-15-081(8), Chugach’s authorized TIER for ratemaking purposes on a system basis was increased to 1.35 effective July 5, 2016. The increase in the 2013 achieved TIER was caused by the recognition of the gain on the sale of the Bernice Lake Power Plant.

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 (recently established at 1.35) 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, 2016, compared to the year ended December 31, 2015, and the year ended December 31, 2015 compared to the year ended December 31, 2014 – Expenses.” We achieved TIERs for the past five years as follows:

1	24
Year	TIER
2016	1.27
2015	1.30
2014	1.29
2013	1.43
2012	1.24

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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% over a 12-month period and 20% 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.

On August 15, 2016, base demand and energy rates increased approximately 4.2% to Chugach’s retail customers and wholesale customer, Seward. These changes were the result of Chugach’s SRF, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Simplified Rating Filings.”

On May 1, 2015, base demand and energy rates increased approximately 22.0% to Chugach’s retail customers. Effective June 1, 2015, base demand and energy rates increased 16.9% to Chugach’s wholesale customer, Seward. These changes were the result of Chugach’s June 2014 Test Year General Rate Case, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – June 2014 Test Year General Rate Case.”

On January 3, 2014, base demand and energy rates increased 11.5% to Chugach retail customers. Effective February 1, 2014, base demand and energy rates increased 19.3% and 13.8% to wholesale customers, MEA and Seward, respectively. These changes were the result of Chugach’s 2013 Test Year General Rate Case.

Fuel and Purchased Power Rates.  We recover fuel and purchased power costs directly from our retail and wholesale 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 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 purchased 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.

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Year ended December31, 2016, compared to the year ended December 31, 2015, and the year ended December 31, 2015 compared to the year ended December 31, 2014

Margins

Our margins for the years ended December31, were as follows:

	2016		2015		2014
Net Operating Margins	$	5,205,893	$	5,815,149	$	5,544,928
Nonoperating Margins	$	607,963	$	687,703	$	970,617
Assignable Margins	$	5,813,856	$	6,502,852	$	6,515,545

The decrease in net operating margins in 2016 from 2015 of $0.6 million, or 10.5%, was primarily due to lower operating revenue, which was somewhat offset by decreases in production, transmission, and administrative, general and other expense. Net operating margins did not materially change in 2015 from 2014.

Nonoperating margins include interest income, Allowance for Funds Used During Construction (AFUDC), capital credits and patronage capital allocations and other. The decrease in nonoperating margins in 2016 from 2015 was primarily due to the unrealized loss on marketable securities during 2016 following Chugach’s return to this investment portfolio in September. The decrease in nonoperating margins in 2015 over 2014 was primarily due to lower interest income as a result of marketable securities sold in August of 2014.

Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2016, operating revenues were $18.7 million, or 8.6% lower than 2015. The decrease was primarily due to lower wholesale revenue as a result of the expiration of MEA’s wholesale contract and our contract with GVEA.

In 2015, operating revenues were $64.9 million, or 23.1% lower than 2014. The decrease was primarily due to lower wholesale revenue caused by the expiration of the MEA wholesale contract, which was somewhat offset by higher rates charged to our remaining customers as a result of Chugach’s 2014 Test Year Rate Case. Lower economy energy sales, as a result of the expiration of the GVEA contract, also contributed to this decrease.

Retail revenue increased $10.7 million, or 6.3%, in 2016 from 2015. Base revenue increased due to an increase in rates charged to retail customers as a result of Chugach’s June 2014 Test Year General Rate Case and SRFs, which was somewhat offset by lower retail energy sales. Retail revenue increased $7.8 million, or 4.8%, in 2015 from 2014. Base revenue increased due to an increase in rates charged to retail customers as a result of Chugach’s June 2014 Test Year General Rate Case.

Wholesale revenue decreased $26.0 million, or 84.1%, in 2016 from 2015, and $44.6 million, or 59.1%, in 2015 from 2014, primarily due to the expiration of MEA’s wholesale contract on April 30, 2015.

Economy revenue decreased $6.9 million, or 84.1%, in 2016 from 2015, and $28.7 million, or 77.8%, in 2015 from 2014, due primarily to the expiration of GVEA’s contract at the end of the first quarter of 2015.

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Miscellaneous revenue increased $3.5 million, or 48.6%, in 2016 from 2015 primarily due to sales of natural gas to ENSTAR as a result of Chugach’s investment in the BRU in April 2016. Additional wheeling revenue from MEA also contributed to the increase. Miscellaneous revenue did not materially change in 2015 from 2014.

Based on the results of fixed and variable cost recovery established in Chugach’s rate filings,wholesale sales to Seward contributed approximately $1.3 million for the years ended December 31, 2016, 2015 and 2014.Wholesale sales to MEA contributed approximately $9.5 million and $26.2 million, for the years ended December 31, 2015 and 2014, 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, 2016, and 2015.

	Base Rate Sales Revenue							Fuel and Purchased Power Revenue							Total Revenue
		2016		2015		% Variance			2016		2015		% Variance			2016		2015		% Variance
Retail
Residential		$	64.8	$	61.1	6.1	%		$	26.7	$	24.8	7.7	%		$	91.5	$	85.9	6.5	%
Small Commercial		$	11.6	$	10.9	6.4	%		$	6.4	$	5.9	8.5	%		$	18.0	$	16.8	7.1	%
Large Commercial		$	43.7	$	41.7	4.8	%		$	25.8	$	24.0	7.5	%		$	69.5	$	65.7	5.8	%
Lighting		$	1.6	$	1.5	6.7	%		$	0.2	$	0.2	0.0	%		$	1.8	$	1.7	5.9	%
Total Retail		$	121.7	$	115.2	5.6	%		$	59.1	$	54.9	7.7	%		$	180.8	$	170.1	6.3	%
Wholesale
MEA		$	0.0	$	12.8	(100.0	%)		$	0.0	$	13.4	(100.0	%)		$	0.0	$	26.2	(100.0	%)
SES		$	2.2	$	2.0	10.0	%		$	2.8	$	2.7	3.7	%		$	5.0	$	4.7	6.4	%
Total Wholesale		$	2.2	$	14.8	(85.1	%)		$	2.8	$	16.1	(82.6	%)		$	5.0	$	30.9	(83.8	%)
Economy		$	0.5	$	0.9	(44.4	%)		$	0.8	$	7.3	(89.0	%)		$	1.3	$	8.2	(84.1	%)
Miscellaneous		$	2.2	$	2.2	0.0	%		$	8.4	$	5.0	68.0	%		$	10.6	$	7.2	47.2	%
Total Revenue		$	126.6	$	133.1	(4.9	%)		$	71.1	$	83.3	(14.6	%)		$	197.7	$	216.4	(8.6	%)

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, 2015, and 2014.

	Base Rate Sales Revenue							Fuel and Purchased Power Revenue							Total Revenue
		2015		2014		% Variance			2015		2014		% Variance			2015		2014		% Variance
Retail
Residential		$	61.1	$	54.4	12.3	%		$	24.8	$	27.5	(9.8	%)		$	85.9	$	81.9	4.9	%
Small Commercial		$	10.9	$	9.6	13.5	%		$	5.9	$	6.4	(7.8	%)		$	16.8	$	16.0	5.0	%
Large Commercial		$	41.7	$	36.1	15.5	%		$	24.0	$	26.6	(9.8	%)		$	65.7	$	62.7	4.8	%
Lighting		$	1.5	$	1.5	0.0	%		$	0.2	$	0.2	0.0	%		$	1.7	$	1.7	0.0	%
Total Retail		$	115.2	$	101.6	13.4	%		$	54.9	$	60.7	(9.6	%)		$	170.1	$	162.3	4.8	%
Wholesale
MEA		$	12.8	$	34.6	(63.0	%)		$	13.4	$	36.1	(62.9	%)		$	26.2	$	70.7	(62.9	%)
SES		$	2.0	$	1.9	5.3	%		$	2.7	$	2.9	(6.9	%)		$	4.7	$	4.8	(2.1	%)
Total Wholesale		$	14.8	$	36.5	(59.5	%)		$	16.1	$	39.0	(58.7	%)		$	30.9	$	75.5	(59.1	%)
Economy		$	0.9	$	2.6	(65.4	%)		$	7.3	$	34.3	(78.7	%)		$	8.2	$	36.9	(77.8	%)
Miscellaneous		$	2.2	$	1.7	29.4	%		$	5.0	$	4.9	2.0	%		$	7.2	$	6.6	9.1	%
Total Revenue		$	133.1	$	142.4	(6.5	%)		$	83.3	$	138.9	(40.0	%)		$	216.4	$	281.3	(23.1	%)

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

	2016	2016		2015	2015		2014	2014
	Sales (MWh)	Revenue		Sales (MWh)	Revenue		Sales (MWh)	Revenue
Retail	1,113,020	$	180,838,811	1,133,427	$	170,147,462	1,134,527	$	162,334,941
Wholesale:
MEA	0		0	275,362		26,177,627	764,025		70,694,965
Seward	59,063		4,938,175	61,347		4,770,129	61,499		4,833,205
Total Wholesale	59,063		4,938,175	336,709		30,947,756	825,524		75,528,170
Economy energy	25,000		1,340,750	105,815		8,150,983	358,988		36,896,019
Other	N/A		10,629,843	N/A		7,174,951	N/A		6,559,383
Total	1,197,083	$	197,747,579	1,575,951	$	216,421,152	2,319,039	$	281,318,513

Since 1989, we have sold economy (non-firm) energy to GVEA, which uses that energy to serve its own loads. Chugach provided economy energy sales through March of 2015 under contract, and continues to provide economy energy on an as needed basis. Sales are made under the terms and conditions of Chugach’s economy energy sales tariff approved by the RCA. The price to GVEA includes the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin. Chugach also entered into gas supply arrangements for GVEA economy energy sales.

In 2016, 2015, and 2014, economy sales to GVEA constituted approximately 1%, 4%, and 13%, respectively, of our sales revenues. Economy energy revenue decreased in 2016 from 2015 and 2015 from 2014 due to the expiration of the contract with GVEA at the end of the first quarter of 2015.

Expenses

The major components of our operating expenses for the years ended December31 were as follows:

	2016		2015		2014
Fuel	$	54,778,582	$	66,534,877	$	126,038,350
Power production		15,809,168		16,886,257		21,082,176
Purchased power		15,774,733		19,599,994		15,608,396
Transmission		5,590,737		6,287,558		6,138,658
Distribution		13,991,997		14,089,862		13,002,157
Consumer accounts		6,073,710		6,117,625		5,887,713
Administrative, general and other		22,888,048		23,623,299		25,036,248
Depreciation		36,233,414		35,652,086		40,179,181
Total operating expenses	$	171,140,389	$	188,791,558	$	252,972,879

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Fuel

Chugach recognizes actual fuel expense as incurred. Fuel expense decreased $11.8 million, or 17.7%, in 2016 from 2015. The decrease was primarily due to a decrease in the natural gas used, as a result of the expiration of MEA’s wholesale contract and GVEA’s economy energy contract, which was somewhat offset by an increase in the average effective delivered price due in part to higher transportation costs. In 2016, Chugach used 8,546,043 Mcf of fuel at an average effective delivered price of $5.63 per Mcf compared to 13,058,423 Mcf at an average effective price of $4.69 per Mcf in 2015. Fuel expense decreased $59.5 million, or 47.2%, in 2015 from 2014. The decrease was primarily due to a decrease in the natural gas used, as a result of the expiration of MEA’s wholesale contract and GVEA’s economy energy contract, lower transportation costs, and a decrease 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.

Power Production

Power production expense decreased $1.1 million, or 6.4%, in 2016 from 2015, primarily due to a decrease in the maintenance for the SPP. Additionally, there was a decrease in operating and maintenance costs at Beluga Power Plant as a result of the retirement of Beluga Unit 8 during the second quarter of 2015 and the change in the use of Beluga’s remaining units from base load to peaking units, coinciding with the expiration of MEA’s interim wholesale contract.  Power production expense decreased $4.2 million, or 19.9%, in 2015 from 2014, primarily due to a decrease in operating and maintenance costs at Beluga, as a result of the retirement of Beluga Unit 8 during the second quarter of 2015.

Purchased Power

Purchased power expense decreased $3.8 million, or 19.5%, in 2016 from 2015, primarily due to a decrease in purchases associated with MEA’s EGS, which was somewhatoffset by a higher average effective price. In 2016, Chugach purchased 182,651 MWh of energy at an average effective price of 7.17 cents per kWh. Purchased power expense increased $4.0 million, or 25.6%, in 2015 from 2014, primarily due to purchases associated with MEA’s EGS and a higher average effective price. In 2015, Chugach purchased 295,925 MWh of energy at an average effective price of 5.68 cents per kWh.

Transmission

Transmission expense decreased $0.7 million, or 11.1%, in 2016 from 2015, primarily due to less labor expense associated with substation and overhead line maintenance. Transmission expense did not materially change in 2015 from 2014.

Distribution

Distribution expense did not materially change in 2016 from 2015. Distribution expense increased $1.1 million, or 8.4%, in 2015 from 2014, primarily due to the transfer of costs associated with storm damages to a regulatory asset deferred project in 2014.

Consumer Accounts

Consumer Accounts expense did not materially change in 2016 from 2015 or in 2015 from 2014.

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Administrative, General and Other Expense

Administrative, general and other expense did not materially change in 2016 from 2015. Administrative, general and other expense decreased $1.4 million, or 5.6%, in 2015 from 2014, primarily due to a reduction in workers’ compensation and costs associated with preliminary survey and investigation charges of projects.

Depreciation

Depreciation and amortization expense did not materially change in 2016 from 2015. Depreciation and amortization expense decreased $4.5 million, or 11.3%, in 2015 from 2014, primarily due to the retirement of Beluga Unit 8 assets during the first quarter of 2015, as well as a change in depreciation rates associated with the use of Beluga’s remaining units from base load to peaking units, coinciding with the expiration of MEA’s interim wholesale contract.

Interest

Interest on long-term debt and other did not materially change in 2016 from 2015. Interest on long-term debt and other decreased $1.1 million, or 4.6%, in 2015 from 2014, reflecting the principal payments made on long-term debt.

Non-Operating Margins

Non-operating marginsdecreased $0.1 million, or 11.6% in 2016 from 2015 primarily due to lower patronage capital allocations as a result of the payment of the 2011 CoBank note.Non-operating margins decreased $0.3 million, or 29.1%, in 2015 from 2014 primarily due to lower interest income as a result of marketable securities sold in August of 2014.

Interest charged to construction did not materially change in 2016 from 2015 or in 2015 from 2014.

Patronage Capital (Equity)

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

	2016		2015		2014
Patronage capital at beginning of year	$	167,447,781	$	164,135,053	$	162,749,889
Retirement/net transfer of capital credits		(3,265,201)		(3,190,124)		(5,130,381)
Assignable margins		5,813,856		6,502,852		6,515,545
Patronage capital at end of year		169,996,436		167,447,781		164,135,053
Other equity1		15,519,089		14,189,600		12,790,246
Total equity at end of year	$	185,515,525	$	181,637,381	$	176,925,299
1 Other equity includes memberships and donated capital on capital credit retirements.

We credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves. These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of distributions of these amounts to members, also known as capital credits, is at the

30

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.

Capital credits retired were $3,265,201 and $3,190,124 for the years ended December 31, 2016, and 2015, 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% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins.

Changes in Financial Condition

Assets

Total assets increased $50.8 million, or 6.5%, in 2016 from 2015, primarily due to increases in net utility plant, investments – other, marketable securities, accounts receivable, and deferred charges, which was somewhat offset by decreases in cash and cash equivalents. Net utility plant increased $40.0 million, or 5.9%, in 2016 from 2015 primarily due to the acquisition of the BRU. Investments – other increased $3.1 million, or 100%, marketable securities increased $7.4 million, or 100%, and cash and cash equivalents decreased $10.9 million, or 70.1%, in 2016 from 2015 primarily due to Chugach resuming its mutual fund investment portfolio. Accounts receivable increased $4.8 million, or 16.9%, in 2016 from 2015 primarily due to an increase in energy sales and system rates charged to retail, an increase in economy energy sales to GVEA, and gas sales associated with the BRU. Deferred charges increased $8.3 million, or 49.5%, in 2016 from 2015 primarily due to an NRECA pension plan prepayment.

Liabilities and Equity

Total liabilities, equities and margins increased $50.8 million, or 6.5%, in 2016 from 2015. Increases in total equities and margins, commercial paper, fuel payable, and cost of removal obligation / ARO were somewhat offset by decreases in long-term obligations, fuel cost over-recovery, and other liabilities. Total equities and margins increased $3.9 million, or 2.1%, in 2016 from 2015 primarily due to the margins generated in 2016. Commercial paper increased $48.2 million, or 241%, in 2016 from 2015 primarily due to the funds used to extinguish long-term debt and the semi-annual interest payment on the 2011 and 2012 Series A Bonds. Fuel payable increased $1.3 million, or 27.2%, in 2016 from 2015 as a result of more fuel purchased and at a higher price in December 2016 compared to December 2015. Cost of removal obligation increased $6.5 million, or 12.5%, in 2016 from 2015 primarily due to the ARO liability assumed as part of the BRU acquisition. Long term obligations decreased $3.3 million, or 0.7%, in 2016 from 2015 caused by principal payments on Chugach’s bonds, which was somewhat offset by theissuance of the 2016 CoBank Note. Fuel cost over-recovery decreased $1.3 million, or 25.5%, in 2016 from 2015 due to refunding of the prior quarter’s over-collection of fuel and purchased power costs. Other liabilities decreased $5.7 million, or 59.6%, in 2016 from 2015 primarily due to a decrease in the payables associated with the underground ordinance andcapital credit retirements.

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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 2016. One of Chugach’s gas contracts provided for adjustments to gas prices based on fluctuations of certain commodity prices and indices. Because fuel and purchased power costs are passed directly to our wholesale and retail customers through a fuel recovery process, fluctuations in the price paid for gas pursuant to long-term gas supply contracts does not significantly affect our operations.

Contractual Obligations and Commercial Commitments

The following table presents Chugach’s contractual and commercial commitments as of December 31, 2016:

Contractual cash obligations – Payments Due By Period

(In thousands)	Total		2017		2018-2019		2020-2021		Thereafter
Long-term debt, including current portion1	$	470,442	$	24,837	$	49,217	$	42,901	$	353,487
Long-term interest expense1		235,114		19,491		35,906		32,040		147,677
Commercial Paper2		68,200		68,200		0		0		0
Bradley Lake3		22,194		3,717		7,493		7,591		3,393
Fuel and fuel transportation expense4		541,290		80,768		130,702		121,068		208,752
BRU5		10,200		600		1,200		1,200		7,200
Capital Credit Retirements6		7,931		0		7,931		0		0
Total	$	1,355,371	$	197,613	$	232,449	$	204,800	$	720,509
1 The issuance of the 2017 Series A First Mortgage Bonds in March 2017 increases the long-term debt payments by $2.0 million annually beginning in 2018 and increases long-term interest expense by $14.4 million in total, with $1.1 million in 2017, $2.6 million in 2018-2019, and $2.3 million in 2020-2021.
2 At December 31, 2016, Chugach's Commercial Paper Program was backed by a $150.0 million Unsecured Credit Agreement, which funds capital requirements. At December 31, 2016, there was $68.2 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $81.8 million and could be used for future operational and capital funding requirements.
3 Estimated annual debt service requirements
4 Estimated committed fuel and fuel transportation expense
5 Estimate of operating and maintenance costs only and does not include capital improvements at this time.

Purchase obligations

Chugach is a participant and has a 30.4% share in the Bradley Lake Hydroelectric Project, see “Item 2 – Properties – Other Property – Bradley Lake.” This contract runs through 2041. We have agreed to pay a like percentage of annual costs of the project, Chugach’s share of which has averaged $5.1 million over the past five years. We believe these costs, adjusted for inflation, reasonably reflect anticipated future project costs.

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Our primary sources of natural gas are the BRU and Hilcorp, see “Item 2 – Properties – Fuel Supply.” We pass fuel costs directly to our wholesale and retail customers through the fuel recovery process, see “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Overview – Rate Regulation and Rates – Fuel and Purchased Power Recovery.”

Liquidity and Capital Resources

We ended 2016 with $4.7 million of cash and cash equivalents, down from $15.6 at December 31, 2015 and down from $16.4 million at December 31, 2014. 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.

	2016		2015		2014
Total cash provided by (used in):
Operating activities	$	32,494,336	$	52,096,436	$	58,766,300
Investing activities		(89,488,707)		(32,347,745)		(12,687,167)
Financing activities		46,040,387		(20,486,734)		(34,061,334)
(Decrease) Increase in cash and cash equivalents	$	(10,953,984)	$	(738,043)	$	12,017,799

Cash provided by operating activities was $32.5 million in 2016 compared to $52.1 million in 2015 and $58.8 million in 2014. The decrease in cash provided by operating activitiesin 2016 from 2015 was primarily due to an increase in the receivable from retail and Seward as a result of higher system rates, and from GVEA caused by higher economy energy sales in late 2016, as well as the prepayment of the NRECA pension plan. These were somewhat offset by the decrease in cash used for accounts payable primarily due to the timing of cash payments. The decrease in cash provided by operating activities in 2015 from 2014 was primarily due to the expiration of the MEA and GVEA contracts in 2015, exclusive of fuel and purchased power revenue and expense, as well as more cash used for fuel. These were somewhat offset by an increase in cash provided by the over-collection of fuel and purchased power costs recovered through the fuel and purchased power adjustment process in 2015 from 2014.

Cash used in investing activities was $89.5 million in 2016 compared to $32.3 million in 2015 and $12.7 million in 2014. The change in cash used in investing activities in 2016 from 2015 and in 2015 from 2014 was primarily due to the impact of Chugach’s investment in the BRU and our investment activity with marketable securities in 2016 and 2014.

Cash provided by financing activities was $46.0 million in 2016 compared to cash used of $20.5 million in 2015 and $34.1 million in 2014. The change in 2016 from 2015 was primarily due to the issuance of the 2016 CoBank Note used to finance Chugach’s investment in the BRU, use of commercial paper to pay off the 2011 CoBank Note, and the retirement of capital credits. The change in cash used in financing activities in 2015 from 2014 was primarily due to a decrease in the average commercial paper balance in 2015 and Chugach’s capital credit retirement in 2014.

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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 $150.0 million Commercial Paper Program. At December 31, 2016, there was no outstanding balance on our NRUCFC line of credit and $68.2 million of outstanding commercial paper under the Commercial Paper Program. Thus, at December 31, 2016, our available borrowing capacity under our line of credit was $50.0 million and our available commercial paper capacity was $81.8 million. The NRUCFC line of credit expires October 12, 2017.

Chugach had maintained a $100.0 million Amended Unsecured Credit Agreement, which was used to back Chugach’s commercial paper program and was due to expire on November 17, 2016.On June 13, 2016, Chugach entered into a $150.0 million senior unsecured credit facility, the Credit Agreement, whichreplaced the Amended Unsecured Credit Agreement. The new Credit Agreement will expire on June 13, 2021. Information concerning our commercial paper program and the 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 2016 CoBank Note, which is governed by the Amended and Restated Master Loan Agreement dated June 30, 2016, and secured by the Indenture. At December 31, 2016, Chugach had $43.8 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. On October 9, 2015, Chugach certified bondable additions of $261.9 million. The balance of bondable additions is now $300.1 million, which would support the issuance of approximately $272.9 million in additional debt. Chugach’s bondable additions balance is a reflection of its beginning balance less property retirements. On June 30, 2016, Chugach used $45.6 million of principal payments to finance the acquisition of the BRU. The balance of retired debt on previously outstanding obligations at December 31, 2016 was $67.8 million.

On March 17, 2017, Chugach issued $40.0 million of First Mortgage Bonds, 2017 Series A, due March 15, 2037 for general corporate purposes. See “Item 8 – Financial Statements and Supplementary Data – Note 17 – Subsequent Events.”

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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, 2016, are set forth below:

Year Ending December 31	Principal Maturities
2017	$	24,836,667
2018		24,608,667
2019		24,608,667
2020		24,836,667
2021		18,064,667
Thereafter		353,487,330
	$	470,442,665

During 2016, we spent approximately $37.0 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 2017 through 2021 as contained in the CIP, which was approved by the Board on November 30, 2016:

Year	Estimated Expenditures
2017	$29.5 million
2018	$59.2 million
2019	$21.7 million
2020	$17.8 million
2021	$20.2 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.

Chugach Operations

In the near term, Chugach continues to face the challenges of operating in a flat load growth environment and securing replacement revenue sources. These challenges, along with energy issues and plans at the state level, will shape how Chugach proceeds into the future.

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Chugach prepared for the expiration of its second wholesale power contract for some time and took steps to reduce costs in order to mitigate the rate impacts to its remaining customers. Despite the loss of two large wholesale power contracts, the combination of which accounted for approximately 50% of energy sales and 40% of sales revenue, the net system rate increase for Chugach’s remaining customers was approximately 20% over the three-year transition period. Chugach’s 10-year financial forecast indicates 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 maintain its ability to recover Chugach’s specific costs of providing service despite the loss of these customers.

Chugach is 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. Chugach believes that cost reduction and containment, successful implementation of new power sales and dispatch agreements and revised tariffs will mitigate additional future rate increases.

Railbelt Grid Unification

Chugach is focused on efforts in Alaska’s Railbelt to explore the benefits of grid unification. Currently, each of the six electric utilities in the Alaska’s Railbelt own a portion of the transmission grid, as does the AEA. Chugach is a proponent of following other successful business models to effectively unify the grid. Discussions on the issue led the Alaska State Legislature in 2014 to appropriate $250,000 to the RCA to explore the issue and report back to legislators. The RCA expects to analyze and review present efforts in order to assess the organizational and governance structure needed for an independent consolidated system operator, see “Item 8 - Financial Statements and Supplementary Data - Note 5 – Regulatory Matters - Operation and Regulation of the Alaska Railbelt Transmission System.” Beginning in 2016, progress reports associated with system-wide economic dispatch are required. With the support of the RCA, Chugach and several other Alaska’s Railbelt utilities are evaluating possible transmission business model opportunities and associated economic dispatch models that Chugach believes may lead to more optimal system wide operations. Chugach intends to finalize this review and evaluation during 2017.  While Chugach cannot determine the materiality of any effect on its results of operations, financial condition, and cash flows until a business model and plan are adopted, it anticipates a positive outcome.

Fuel Supply

Chugach actively manages its fuel supply needs and currently has contracts in place to meet up to 100% of its anticipated needs through March of 2023. Chugach continues its efforts to secure long-term reliable gas supply solutions and encourages new development and continued investment in Cook Inlet. The DNR published a study in September 2015, “Updated Engineering Evaluation of Remaining Cook Inlet Gas Reserves,” to provide an estimate of Cook Inlet’s gas supply. The study estimated there are 1,183 Bcf of proved and probable reserves remaining in Cook Inlet’s legacy fields. This is higher than the 2009 DNR study estimate of 1,142 Bcf. Effectively, Cook Inlet gas supply has slightly increased from 2009. The 2015 DNR estimate does not include reserves from a large gas field under development by Furie Operating Alaska, LLC (Furie) and another considered for development by BlueCrest Energy, Inc. Furie has constructed an offshore gas production platform and has begun production. The platform and

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other production facilities are designed for up to 200 million cubic feet (MMcf) per day. Other gas producers are actively developing gas supplies in the Cook Inlet. Chugach is encouraged with these developments but continues to explore other alternatives to diversify its portfolio.

On April 21, 2016, the RCA approved the acquisition of the Beluga River Unit effective January 1, 2016, as discussed in “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Beluga River Unit and Note 15 –Beluga River Unit.”  Chugach’s interest in the BRU is to reduce the cost of electric service to its retail and wholesale members by securing an additional long-term supply of natural gas to meet on-going generation requirements. The acquisition complements existing gas supplies and is expected to provide greater fuel diversity at an effective annual cost that is $2 million to $3 million less than alternative sources of gas in the Cook Inlet region. Approximately 80% of Chugach’s current generation requirements are met from natural gas, 16% are met from hydroelectric facilities, and 4% are met from wind.

The acquisition is expected to provide gas to meet Chugach’s on-going generation requirements over an approximate 18-year period. Gas associated with the acquisition is expected to provide about 15% of Chugach’s gas requirements through 2033, although actual gas quantities produced are expected to vary on a year-by-year basis.

Chugach had a firm gas supply contract with COP and has a firm gas supply contract with Hilcorp, see “Item 8 –  Financial Statements and Supplementary Data – Note 16 – Commitments and Contingencies – Commitments – Fuel Supply Contracts.”  In addition to these firm contracts, Chugach has gas supply agreements with AIX Energy LLC through March 31, 2024 (with an option to extend the term an additional 5-year period through March 31, 2029), with Cook Inlet Energy LLC through March 31, 2018 (with an option to extend the term an additional 5-year period through March 31, 2023), and with ML&P through March 31, 2017. Collectively, these agreements provide added diversification and optionality for Chugach to minimize costs within its gas supply portfolio.

Renewable Energy Goals

A State of Alaska Energy Policy approved by the legislature in 2010 included legislative intent that the state achieve a 15% increase in energy efficiency on a per capita basis between 2010 and 2020, receive 50% of its electric generation from renewable and alternative energy sources by 2025, work to ensure reliable in-state gas supply for residents of the state, 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 was the Susitna-Watana Hydroelectric Project on the Susitna River, approximately halfway between Anchorage and Fairbanks. The Alaska Legislature appropriated a total of $192.1 million for AEA to plan, design, and obtain permits for the project. On December 26, 2014, the Governor of Alaska issued Administrative Order 271 suspending discretionary spending on the project. On January 8, 2015, the FERC granted AEA’s request to hold the licensing process in abeyance. On July 6, 2015, the Governor’s office authorized AEA to proceed with the Integrated Licensing Process using previously appropriated funds. In August 2015, AEA requested the FERC’s permission to resume the licensing efforts. As per the Governor’s direction on June 29, 2016, AEA has continued to work towards shutting down the project while preserving the State’s investment to date. On August 4, 2016, the Governor issued a letter to FERC requesting FERC to proceed with the Integrated Licensing Process (ILP) to the point of issuing its updated Study Plan

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Determination (SPD) to preserve the State’s investment in the project. On August 26, 2016, FERC responded to the Governor’s letter. FERC will proceed with the ILP to complete the SPD. After issuing the SPD the project will be put into abeyance as requested by the Governor. Chugach intends to continue to work with AEA and other parties on this effort.

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, 2016.

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 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

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operations than they would on a non-regulated company. As reflected in the financial statements, see “Item 8 -Financial Statements and Supplementary Data – Note 2n – Deferred Charges and Liabilities,” 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 $10,940,274 and $10,531,377 of unbilled retail revenue at December 31, 2016, and 2015, 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 –Accounting Pronouncements.”

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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, 2016, our short- and long- term debt was comprised of our 2011 and 2012 Series A Bonds, our CoBank note and outstanding commercial paper.

The interest rates of Chugach’s 2011 and 2012 Series A Bonds and our 2016 CoBank Note are fixed and set forth in the table below with carrying value and fair value, measured as Level 2 liabilities, (dollars in millions) at December 31, 2016.

	Maturing	Interest Rate		Carrying Value		Fair Value
2011 Series A, Tranche A	2031	4.20	%	$	67,500	$	67,607
2011 Series A, Tranche B	2041	4.75	%		154,167		163,450
2012 Series A, Tranche A	2032	4.01	%		60,000		59,391
2012 Series A, Tranche B	2042	4.41	%		95,000		96,774
2012 Series A, Tranche C	2042	4.78	%		50,000		53,077
2016 CoBank Note	2031	2.58	%		43,776		40,921
Total				$	470,443	$	481,220

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, 2016, we had $68.2 million of commercial paper outstanding. A 100 basis-point rise in interest rates would increase our interest expense by approximately $0.7 million, and a 100 basis point decline in interest rates would decrease our interest expenses by approximately $0.5 million, based on $68.2 million of variable rate debt outstanding at December 31, 2016.

Commodity Price Risk

Chugach had a gas contract that provided 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.

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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 consolidated balance sheetsof Chugach Electric Association, Inc.and subsidiary as of December 31, 2016 and 2015, and the related consolidated statements of operations, changes in equities and margins, and cash flows for each of the years in the three-year period ended December 31, 2016. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States) and in accordance with auditing standards generally accepted in the United States of America. 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 consolidated financial statements referred to above present fairly, in all material respects, the financial position of Chugach Electric Association, Inc. and subsidiary as of December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

/s/ KPMG LLP

March24, 2017

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Chugach Electric Association, Inc.

Consolidated Balance Sheets

December 31, 2016 and 2015

Assets	December 31, 2016		December 31, 2015
Utility plant:
Electric plant in service	$	1,192,513,869	$	1,128,474,292
Construction work in progress		18,455,940		15,601,374
Total utility plant		1,210,969,809		1,144,075,666
Less accumulated depreciation		(496,098,131)		(469,199,226)
Net utility plant		714,871,678		674,876,440
Other property and investments, at cost:
Nonutility property		76,889		76,889
Investments in associated organizations		9,349,311		9,635,519
Special funds		907,836		763,913
Restricted cash equivalents		810,559		1,705,760
Investments - other		3,061,434		0
Total other property and investments		14,206,029		12,182,081
Current assets:
Cash and cash equivalents		4,672,935		15,626,919
Special deposits		75,942		74,416
Restricted cash equivalents		899,723		1,143,467
Marketable securities		7,375,381		0
Accounts receivable, less provisions for doubtful accounts
of $484,352 in 2016 and $425,751 in 2015		33,000,919		28,232,930
Materials and supplies		27,889,167		27,611,184
Fuel stock		6,321,676		7,063,541
Prepayments		1,407,026		1,466,301
Other current assets		294,697		225,079
Total current assets		81,937,466		81,443,837
Other non-current assets:
Deferred charges, net		25,140,957		16,811,756
Total other non-current assets		25,140,957		16,811,756
Total other non-current assets	$	836,156,130	$	785,314,114

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Chugach Electric Association, Inc.

Consolidated Balance Sheets (continued)

December 31, 2016 and 2015

Liabilities, Equities and Margins	December 31, 2016		December 31, 2015
Equities and margins:
Memberships	$	1,691,014	$	1,661,744
Patronage capital		169,996,436		167,447,781
Other		13,828,075		12,527,856
Total equities and margins		185,515,525		181,637,381
Long-term obligations, excluding current installments:
Bonds payable		405,249,998		426,666,665
Notes payable		40,356,000		22,241,852
Less unamortized debt issuance costs		(2,715,745)		(2,680,897)
Total long-term obligations		442,890,253		446,227,620
Current liabilities:
Current installments of long-term obligations		24,836,667		24,115,980
Commercial paper		68,200,000		20,000,000
Accounts payable		9,618,630		9,701,088
Consumer deposits		5,207,585		5,000,684
Fuel cost over-recovery		3,824,722		5,135,745
Accrued interest		5,873,368		5,915,580
Salaries, wages and benefits		7,315,898		7,259,806
Fuel		6,284,338		4,942,310
Other current liabilities		3,234,586		8,076,903
Total current liabilities		134,395,794		90,148,096
Other non-current liabilities:
Deferred compensation		907,836		763,913
Other liabilities, non-current		655,277		1,555,329
Deferred liabilities		1,179,414		1,802,389
Patronage capital payable		12,008,499		11,108,071
Cost of removal obligation / asset retirement obligation		58,603,532		52,071,315
Total other non-current liabilities		73,354,558		67,301,017
Total liabilities, equities and margins	$	836,156,130	$	785,314,114

See accompanying notes to financial statements.

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Chugach Electric Association, Inc.

Consolidated Statements of Operations

Years Ended December 31, 2016, 2015 and 2014

	2016		2015		2014
Operating revenues	$	197,747,579	$	216,421,152	$	281,318,513
Operating expenses:
Fuel		54,778,582		66,534,877		126,038,350
Production		15,809,168		16,886,257		21,082,176
Purchased power		15,774,733		19,599,994		15,608,396
Transmission		5,590,737		6,287,558		6,138,658
Distribution		13,991,997		14,089,862		13,002,157
Consumer accounts		6,073,710		6,117,625		5,887,713
Administrative, general and other		22,888,048		23,623,299		25,036,248
Depreciation and amortization		36,233,414		35,652,086		40,179,181
Total operating expenses	$	171,140,389	$	188,791,558	$	252,972,879
Interest expense:
Long-term debt and other		21,856,095		22,194,290		23,264,041
Charged to construction		(454,798)		(379,845)		(463,335)
Interest expense, net	$	21,401,297	$	21,814,445	$	22,800,706
Net operating margins	$	5,205,893	$	5,815,149	$	5,544,928
Nonoperating margins:
Interest income		425,173		296,788		566,639
Allowance for funds used during construction		188,111		142,881		163,151
Capital credits, patronage dividends and other		(5,321)		248,034		240,827
Total nonoperating margins	$	607,963	$	687,703	$	970,617
Assignable margins	$	5,813,856	$	6,502,852	$	6,515,545

See accompanying notes to financial statements.

44

Chugach Electric Association, Inc.

Consolidated Statements of Changes in Equities and Margins

Years Ended December 31, 2016, 2015 and 2014

f
	Memberships		Other Equities and Margins		Patronage Capital		Total
Balance, January 1, 2014	$	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
Assignable margins		0		0		6,502,852		6,502,852
Retirement/net transfer of capital credits		0		0		(3,190,124)		(3,190,124)
Unclaimed capital credit retirements		0		1,298,410		0		1,298,410
Memberships and donations received		30,175		70,769		0		100,944
Balance, December 31, 2015		1,661,744		12,527,856		167,447,781		181,637,381
Assignable margins		0		0		5,813,856		5,813,856
Retirement/net transfer of capital credits		0		0		(3,265,201)		(3,265,201)
Unclaimed capital credit retirements		0		1,175,962		0		1,175,962
Memberships and donations received		29,270		124,257		0		153,527
Balance, December 31, 2016	$	1,691,014	$	13,828,075	$	169,996,436	$	185,515,525

See accompanying notes to financial statements.

45

Chugach Electric Association, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2016, 2015 and 2014

	2016		2015		2014
Cash flows from operating activities:
Assignable margins	$	5,813,856	$	6,502,852	$	6,515,545
Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation and amortization		36,233,414		35,652,086		40,179,181
Amortization and depreciation cleared to operating expenses		4,988,068		4,390,385		5,777,628
Allowance for funds used during construction		(188,111)		(142,881)		(163,151)
Write off of inventory, deferred charges and projects		997,301		691,035		974,062
Other		248,482		(220,496)		56,250
(Increase) decrease in assets:
Accounts receivable, net		(4,926,631)		6,866,956		6,879,762
Materials and supplies		(850,493)		(1,070,896)		(1,197,127)
Fuel stock		741,865		2,588,532		3,377,775
Prepayments		59,275		712,422		(315,316)
Other assets		(71,144)		215,738		978,338
Deferred charges		(10,374,429)		(405,746)		(1,050,505)
Increase (decrease) in liabilities:
Accounts payable		750,538		(270,416)		(420,041)
Consumer deposits		206,901		86,424		62,702
Fuel cost over-recovery		(1,311,023)		3,673,688		(173,620)
Accrued interest		(42,212)		(276,028)		(321,252)
Salaries, wages and benefits		56,092		(287,510)		(385,047)
Fuel		1,342,028		(6,195,299)		(3,696,976)
Other current liabilities		(1,051,220)		(290,715)		1,653,424
Deferred liabilities		(128,221)		(123,695)		34,668
Net cash provided by operating activities		32,494,336		52,096,436		58,766,300
Cash flows from investing activities:
Return of capital from investment in associated organizations		319,233		352,420		351,162
Investment in restricted cash equivalents		(1,398)		(1,141)		(142)
Investment in marketable securities and investments-other		(10,580,000)		0		(217,817)
Investment in Beluga River Unit		(44,403,922)		0		0
Proceeds from restricted cash equivalents		1,140,343		0		0
Proceeds from the sale of marketable securities		0		0		10,522,620
Proceeds from capital grants		1,021,929		2,395,331		6,960,143
Extension and replacement of plant		(36,984,892)		(35,094,355)		(30,303,133)
Net cash used in investing activities		(89,488,707)		(32,347,745)		(12,687,167)
Cash flows from financing activities:
Payments for debt issue costs		(277,155)		0		0
Net increase (decrease) in short-term obligations		48,200,000		(1,000,000)		(9,000,000)
Proceeds from long-term obligations		45,600,000		0		0
Repayments of long-term obligations		(48,181,832)		(23,889,777)		(24,682,812)
Memberships and donations received		1,329,489		357,365		(255,730)
Retirement of patronage capital and estate payments		(4,378,853)		(182,352)		(4,114,541)
Net receipts on consumer advances for construction		3,748,738		4,228,030		3,991,749
Net cash provided by (used in) financing activities		46,040,387		(20,486,734)		(34,061,334)
Net change in cash and cash equivalents		(10,953,984)		(738,043)		12,017,799
Cash and cash equivalents at beginning of period	$	15,626,919	$	16,364,962	$	4,347,163
Cash and cash equivalents at end of period	$	4,672,935	$	15,626,919	$	16,364,962
Supplemental disclosure of non-cash investing and financing activities:
Cost of removal obligation	$	3,008,808	$	1,366,318	$	3,565,605
Asset retirement obligation assumed upon BRU acquisition	$	3,523,409	$	0	$	0
Extension and replacement of plant included in accounts payable	$	1,915,033	$	2,582,947	$	2,382,117
Patronage capital retired and included in other current liabilities	$	0	$	2,105,440	$	2,572,670
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized	$	20,220,317	$	21,891,308	$	21,835,216

See accompanying notes to financial statements.

46

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

(1)    Description of Business

Chugach Electric Association, Inc. (Chugach) is one of the largest electric utilities in Alaska. Chugach is engaged in the generation, transmission and distribution of electricity in the Anchorage and upper Kenai Peninsula areas. Chugach is on an interconnected regional electrical system referred to as the Alaska 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’s retail and wholesale members are the consumers of the electricity sold. Chugach supplies much of the power requirements to the City of Seward (Seward), as a wholesale customer. Chugach also served Matanuska Electric Association, Inc. (MEA) through their contract expiration onApril 30, 2015.  Through March 31, 2015, we sold economy (non-firm) energy to Golden Valley Electric Association, Inc. (GVEA), which used that energy to serve its own load. Periodically, Chugach sells available generation, in excess of its own needs, to MEA, GVEA and Anchorage Municipal Light & Power (ML&P).

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 authority of the Regulatory Commission of Alaska (RCA).

The consolidated financial statements include the activity of Chugach and the activity of the Beluga River Unit (BRU). Chugach accounts for its share of BRU activity using proportional consolidation (see Note 15 – “Beluga River Unit”). Intercompany activity has been eliminated for presentation of the consolidated financial statements.

(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 the allowance for doubtful accounts, workers’ compensation liability, deferred charges and liabilities, unbilled revenue, estimated useful life of utility plant, cost of removal and asset retirement obligation (ARO), purchase price allocation for BRU, and remaining proved BRU reserves. Actual results could differ from those estimates.

47

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

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 (2n) – “Deferred Charges and Liabilities.”

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, 2016 are as follows:

Annual Depreciation Rate Ranges

Steam production plant	3.15%	-	3.84%
Hydroelectric production plant	1.06%	-	3.00%
Other production plant	3.15%		8.85%
Transmission plant	1.58%	-	7.86%
Distribution plant	2.16%	-	9.63%
General plant	1.57%	-	20.00%
Other	2.75%	-	2.75%

On November 1, 2010, the RCA approved revised depreciation rates effective November 1, 2010 in Docket U-09-097. Chugach’s depreciation rates include a provision for cost of removal. Chugach records a separate liability for the estimated obligation related to the cost of removal.

48

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

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

Chugach records Depreciation, Depletion and Amortization (DD&A) expense on the BRU assets based on units of production using the following formula: ten percent of the total production from the BRU as provided by the operator divided by ten percent of the estimated remaining proved reserves (in thousand cubic feet (Mcf)) in the field multiplied by Chugach’s total assets in the BRU.

d. Full Cost Method

Pursuant to Accounting Standards Codification (ASC) 932-360-25, “Extractive Activities-Oil and Gas – Property, Plant and Equipment – Recognition,” Chugach has elected the Full Cost method, rather than the Successful Efforts method, to account for exploration and development costs of gas reserves. This is the first time Chugach has invested in oil or gas activities, so there is no prior policy of using the Successful Efforts method.

e. Asset Retirement Obligation (ARO)

Chugach calculated and recorded an Asset Retirement Obligation associated with the BRU. Chugach uses its BRU financing rate as its credit adjusted risk free rate and the expected cash flow approach to calculate the fair value of the ARO liability. The ARO asset is depreciated using the DD&A formula previously discussed. The ARO liability is accreted using the interest method of allocation.

f. 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 one percent. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment. No impairment was recorded during 2016, 2015 and 2014.

g. Investments – Other

Investments –other consists of certificates of deposit with an original maturity of 18 months.

h. 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 $5,897,767and $6,218,015 during the years ended December 31, 2016 and 2015, respectively.

49

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Restricted cash equivalents include funds on deposit for future workers’ compensation claims. At December 31, 2016 and 2015, restricted cash equivalents included $0.8 million and $1.7 million, respectively, of funds on deposit for future workers’ compensation claims.

i. Marketable Securities

In September 2016, Chugach resumed its mutual fund investment portfolio. The investments are classified as trading securities, reported at fair value with gains and losses in earnings, and include bond funds.

	Twelve months ended December 31, 2016
Net gains and losses recognized during the period on trading securities	$	(143,185)
Less: Net gains and losses recognized during the period on trading securities sold during the period		0
Unrealized gains and losses recognized during the reporting period on trading securities still held at the reporting date	$	(143,185)

j. 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 Anchorage Municipal Light & Power (ML&P) for their proportionate share of current SPP costs, which amounted to $1.4 million and $1.1 million in 2016 and 2015, respectively. In addition, accounts receivable includes invoiced amounts for grants to support investigating means of mitigating the impact of renewable generation variability on the grid as well as the construction of facilities to divert water and safely transmit electricity, which amounted to $0.0 million and $0.2 million in 2016 and 2015, respectively. At December 31, 2016, accounts receivable also included $0.7 million from BRU operations primarily associated with gas sales to ENSTAR.

k. Materials and Supplies

Materials and supplies are stated at average cost.

l. 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, 2016 and 2015 amounted to $6.3 million and $7.1 million, respectively.

50

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

m. Fuel and Purchased Power Cost Recovery

Expenses associated with electric services include fuel purchased from others and produced from Chugach’s interest in the BRU, both of which are used to generate electricity, as well as 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 purchased power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods.

n. Deferred Charges and Liabilities

Included in deferred charges and liabilities on Chugach’s financial statements are regulatory assets and liabilities recorded in accordance with FASB ASC 980.  See Note 8 – Deferred Charges and Liabilities. Continued accounting under FASB ASC 980 requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for ratemaking purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria.

Chugach’s 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 liabilities include 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.

On December 29, 2016, Chugach made a prepayment of $7.9 million to the National Rural Electric Cooperative Association (NRECA) Retirement and Security (RS) Plan, which is included in deferred charges. Chugach recorded the long term prepayment in deferred charges and is amortizing the deferred charge to administrative, general and other expense, over 11 years, which represents the difference between the normal retirement age of 62 and the average age of Chugach’s employees in the RS Plan.

51

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

o. 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.

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, 2016 and 2015, totaled $3.3 million and $3.1 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances totaled $1.9 million for the years ended December 31, 2016 and 2015.

q. 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.

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

Marketable securities – the carrying amount approximates fair value as changes in the market value are recorded monthly and gains or losses are reported in earnings (see note 2i and note 4).

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

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

The fair value of accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature.

52

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

r. Operating Revenues

Revenues are recognized upon delivery of electricity. Operating revenues are based on billing rates authorized by the RCA, which are applied to customers’ usage of electricity. Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results. Chugach calculates unbilled revenue at the end of each month to ensure the recognition of a calendar year’s revenue. Chugach accrued $10,940,274 and $10,531,377 of unbilled retail revenue at December 31, 2016 and 2015, respectively, which is included in accounts receivable on the balance sheet. 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.

s. 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 Chugach capitalized such funds at the weighted average rate of 4.3% during 2016, 2015 and 2014.

t. 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.

u. 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, 2016, 2015 and 2014 was in compliance with that provision. In addition, as described in Note (16) – “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 fifty percent likelihood of being sustained upon examination by the taxing authorities. Chugach’s management reviewed Chugach’s tax positions and determined there were no outstanding or retroactive tax positions that were not highly certain of being sustained upon examination by the taxing authorities.

53

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

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, 2014 through December 31, 2016 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2016.

v. Grants

Chugach has received federal and state grants to offset storm related expenditures and to support investigating means of mitigating the impact of renewable generation variability on the grid as well as 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, both of which totaled $0.6 million and $1.6 million in 2016 and 2015, respectively.

(3)Accounting Pronouncements

Issued and adopted:

ASC Update 2015-03 “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs”

In April of 2015, the FASB issued ASC Update 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASC Update 2015-03 revised the presentation guidance for debt issuance costs related to a recognized debt liability. The effect of this update was to present the debt issuance costs as a direct deduction to the liability on the balance sheet and was adopted by retrospective application. This update did not change the recognition and measurement guidance for debt issuance costs. This update was effective for fiscal years beginning after December 15, 2015, and interim periods beginning after December 15, 2016, with early adoption permitted. Chugach began application of ASC 2015-03 with the fiscal year beginning January 1, 2016. Adoption did not have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2015-15 “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements”

In September of 2015, the FASB issued ASC Update 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” ASC Update 2015-15 amended guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements for SEC reporting. This update was effective for fiscal years beginning after December 15, 2015, and interim periods beginning after December 15, 2016, with early adoption permitted. Chugach began application of ASC 2015-15 with the fiscal year beginning January 1, 2016. Adoption did not have a material effect on its results of operations, financial position, and cash flows.

54

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Adoption of this guidance was applied retrospectively and reduced deferred charges and long-term debt by the unamortized debt issuance costs of $2.7 million at December 31, 2016, and December 31, 2015.

Issued, not yet adopted:

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

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 was effective for fiscal years beginning after December 15, 2016, for which early adoption was prohibited. However, in August of 2015, the FASB issued ASC Update 2014-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” deferring the effective date of ASC Update 2014-09 to fiscal years beginning after December 15, 2017, and permitting early adoption of this update, but only for annual reporting periods beginning after December 15, 2016, and interim reporting periods within that reporting period. The standard permits the use of either the retrospective or cumulative effect transition method. While Chugach has not yet selected a transition method, we currently expect to use the cumulative effect method. Our transition method, and the expected materiality of the impact of adopting this standard on our operations, financial position, and cash flows, will be determined after we further evaluate the impact of this update.

We have evaluated our energy sales contracts, including retail, wholesale, and economy energy, and do not believe there will be a material impact to our recognition of revenue from energy sales. Energy sales are billed monthly per regulator approved tariffs based on the energy consumed by the customer. Total revenue derived from energy sales during 2016 was approximately 99% of our total operating revenue.

The American Institute of Certified Public Accountants (AICPA) Power and Utilities Revenue Recognition Task Force is currently assessing the impact of this update on contributions in aid of construction (CIAC). CIAC represents the funds collected from customers and third parties and recorded as a reduction to the total cost of property, plant and equipment, per industry standard practice. If it is determined that CIAC is within the scope of this update, it could have a material impact on the amount of revenue we recognize.

ASC Update 2016-01  “Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities”

In January of 2016, the FASB issued ASC Update 2016-01, “Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” ASC Update 2016-01 amends guidance related to certain aspects of the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2018, and interim periods beginning after December 15, 2019, with early adoption not permitted with certain exceptions. Chugach will begin application of ASC 2016-01 with the annual report for the year ended December 31, 2018.  

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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2016-02  “Leases (Topic 842): Section A – Leases: Amendments to the FASB Accounting Standards Codification; Section B – Conforming Amendments Related to Leases: Amendments to the FASB Accounting Standards Codification; Section C – Background Information and Basis for Conclusions”

In February of 2016, the FASB issued ASC Update 2016-02, “Leases (Topic 842): Section A – Leases: Amendments to the FASB Accounting Standards Codification; Section B – Conforming Amendments Related to Leases: Amendments to the FASB Accounting Standards Codification; Section C – Background Information and Basis for Conclusions.” ASC Update 2016-02 amends guidance related to the recognition, measurement, presentation and disclosure of leases for lessors and lessees. This update is effective for fiscal years beginning after December 15, 2018,  including the interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2016-02on January 1, 2019.  Chugach expects this update to increase the recorded amounts of assets and liabilities and we are evaluating the significance of the increase. We are also evaluating the impact of this update to our results of operations, financial position, and cash flows.

ASC Update 2016-11 “Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Update 2014-09 and 2014-06 Pursuant to Staff Announcements at the March 3, 2016, EITF Meeting (SEC Update)”

In May 2016, the FASB issued ASC Update 2016-11, “Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Update 2014-09 and 2014-06 Pursuant to Staff Announcements at the March 3, 2016, EITF Meeting (SEC Update).” ASC 2016-11 rescinds and supersedes SEC guidance previously governing revenue and expense recognition for freight services in process, accounting for shipping and handling fees and costs, consideration given by a vendor to a customer, and gas-balancing arrangements. This update affects the guidance in ASC Update 2014-09 and 2014-06 and follows the same effective date and transition requirements. While Chugach has not yet selected a transition method, we currently expect to use the cumulative effect method. Our transition method, and the expected materiality of the impact of adopting this standard on our operations, financial position, and cash flows, will be determined after we further evaluate the impact of this update.

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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

ASC Update 2016-13 “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”

In June 2016, the FASB issued ASC Update 2016-13, “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” ASC Update 2016-13 revised the criteria for the measurement, recognition, and reporting of credit losses on financial instruments to be recognized when expected. This update is effective for fiscal years beginning after December 15, 2019, including the interim periods within those years, with early adoption permitted for fiscal years beginning after December 15, 2018, including interim periods within those years. Chugach will begin application of ASC 2016-13 on January 1, 2020. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)”

In August 2016, the FASB issued ASC Update 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). ASC Update 2016-15 clarifies how certain cash payments and cash proceeds should be classified on the statement of cash flows to limit the diversity in practice. This update is effective fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2016-15 on January 1, 2018. Adoption is not expected to have a material 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.

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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Chugach’s marketable securities classified as trading securities are outlined in the table below. Chugach had no other assets or liabilities measured at fair value on a recurring basis at December 31, 2016. At December 31, 2015, Chugach had no Level 1 or Level 2 assets or liabilities measured at fair value on a recurring basis.

	December 31, 2016		Level 1
Bond funds/Certificates of Deposit	$	10,436,815	$	10,436,815

Fair Value of Financial Instruments

Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions. The fair value of cash and cash equivalents, accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature. The fair value of investments – other approximate their carrying value due to the recency of their acquisition.

The estimated fair values (in thousands) of long-term obligations included in the financial statements at December 31, 2016, are as follows:

	Measurement	Carrying Value		Fair Value
2011 Series A Bonds	Level 2	$	221,667	$	231,057
2012 Series A Bonds	Level 2		205,000		209,242
2016 CoBank Note	Level 2		43,776		40,921
Long-term obligations (including current installments)		$	470,443	$	481,220

(5)    Regulatory Matters

Amended Eklutna Generation Station 2015 Dispatch Services Agreement

On February 13, 2015, Chugach submitted the Amended Eklutna Generation Station 2015 Dispatch Services Agreement (Dispatch Services Agreement) to the RCA for dispatch services to be provided by Chugach to MEA for a one-year period. Under the Dispatch Services 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.

On March 23, 2015, the RCA approved the Dispatch Agreement, conditioned on the requirements that: 1) MEA and Chugach notify the RCA at least one month prior to forming separate Load Balancing Authorities and include in any such notification details on the tie points and any written agreements contemplated by the utilities; and, 2) Chugach file an update to its tariff to reflect any extension of the Dispatch Services Agreement one week from the receipt of such a request from MEA. The Dispatch Services Agreement was in effect through March 31, 2016.

58

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

In December of 2015, MEA notified Chugach that it would not be extending the Dispatch Services Agreement for the dispatch of electric service. Subsequently, Chugach and MEA entered into an agreement entitled, “Gas Dispatch Agreement” in which Chugach provides gas scheduling and dispatch services to MEA. The term of the agreement is April 1, 2016, through March 31, 2017. On April 18, 2016, Chugach requested RCA approval of the special contract. The RCA issued a letter order on June 8, 2016, approving the filing. This agreement was extended through March 31, 2018, in a letter agreement dated July 29, 2016, with a provision to extend the agreement through March 31, 2019, to be exercised on or before August 1, 2017.

June 2014 Test Year General Rate Case

Chugach’s June 2014 test year rate case was submitted to the RCA on February 13, 2015. Chugach requested a system base rate increase of approximately $21.3 million, or 20% on total base rate revenues for rates effective in April 2015. The filing also included 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 was the reduction in fixed-cost contributions resulting from the expiration of the Interim Power Sales Agreement between Chugach and MEA. In addition, Chugach submitted proposed adjustments to its fuel and purchased power rates under a separate tariff advice letter to become effective at the same time. This 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. Collectively, the effective increase to retail customer bills was approximately between two and five percent.

The RCA issued Order U-15-081(1) on April 30, 2015, suspending the filing and granting Chugach’s request for interim and refundable rate increases effective May 1, 2015. A scheduling conference was held on May 27, 2015. On June 4, 2015, the RCA issued Order U-15-081(2), granting approval for intervention by HEA, MEA and GVEA. The RCA indicated that a final order in the case will be issued by May 8, 2016. Intervenor responsive testimony was filed by the Attorney General (AG) and MEA on October 28, 2015. The AG’s testimony focused on revenue requirement matters and MEA’s testimony focused on transmission cost allocation issues. Chugach’s responsive testimony was filed on December 15, 2015.

In January of 2016, Chugach and the Attorney General (AG) for the State of Alaska entered into settlement discussions to resolve revenue requirement matters in the case, which resulted in settlement of all outstanding matters related to the determination of Chugach’s system revenue requirement for both the interim and permanent rate periods. As a result, Chugach agreed to reduce its revenue requirement by 0.5% (approximately $0.6 million). In addition, the stipulation provides for a permanent increase in Chugach’s system Times Interest Earned Ratio (TIER) from 1.30 to 1.35, which represents an approximate margin increase of $1.0 million per year.

The stipulation was filed with the RCA on January 21, 2016. On May 2, 2016, the RCA issued Order U-15-081(8) accepting the stipulation between Chugach and the AG. On May 20, 2016, Chugach submitted updated revenue requirement, cost of service and tariffs reflecting the results of the stipulation, with proposed final rates effective July 5, 2016. On June 17, 2016, the RCA issued Order U-15-081(10) approving final permanent rates effective for Chugach retail

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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

customers and the City of Seward (Seward). Refunds totaling $0.75 million were issued to Chugach retail customers in August 2016. The refund applied to purchases from May 2015 through July 2016. Chugach issued a refund to Seward totaling approximately $28,000 on July 8, 2016.

On June 27, 2016, the RCA issued Order U-15-081(11) resolving the outstanding issues related to transmission and ancillary services. The RCA ruled in Chugach’s favor, affirming continued use of a postage stamp rate methodology for wheeling transactions on the Chugach system and denied MEA’s request for a separate rate for wheeling transactions based on MEA’s claim that it only used a small portion of Chugach’s transmission system. The order was consistent with previous orders on transmission and ancillary services that were issued by the RCA in Chugach’s 2012 and 2013 General Rate Case filings. On July 15, 2016, Chugach submitted updated tariff sheets and supporting exhibits for the calculation of transmission and ancillary service rates. On August 23, 2016, the RCA approved final rates contained in Chugach’s July 15, 2016, compliance filing.

On September 15, 2016, Chugach notified the RCA that it completed the issuance of refunds resulting from settlement of the rate case. A final order closing the docket was issued on October 6, 2016.

Simplified Rate Filing

On June 30, 2016, the Chugach Board of Directors voted to re-enter the SRF process for adjustments to base demand and energy rates for Chugach retail customers and wholesale customer, Seward. SRF is an expedited base rate adjustment process available to electric cooperatives in the State of Alaska. On July 1, 2016, Chugach requested approval to implement the SRF process for energy and demand rate changes, and requested approval for a 4.2% system demand and energy rate increase, or approximately $4.8 million on an annual basis. On a total retail customer bill basis, which includes fuel and purchased power costs, the impact was approximately 2.5%. Chugach requested the proposed rate increase become effective August 15, 2016. Chugach plans to adjust rates through the SRF process on a quarterly basis going forward.

On August 12, 2016, the RCA issued a letter order approving Chugach’s entry into the SRF process for quarterly adjustments to the demand and energy rates of Chugach retail customers and Seward. The RCA also approved Chugach’s request to increase demand and energy rates by 4.2%, effective August 15, 2016.

On August 29, 2016, Chugach submitted its June 2016 test year SRF to the RCA with no changes to the demand and energy rates of Chugach retail and Seward. In the filing, Chugach requested approval to adopt the SRF process for quarterly rate adjustments for non-firm transmission wheeling and ancillary services, and approval to reduce these rates between 9.5% and 14.4% based on the current SRF. The RCA issued an order on October 13, 2016, denying Chugach’s request on the basis that the underlying premise of the SRF does not apply to rates for third-party use of Chugach’s transmission system. Revenues from these transactions do not impact Chugach margin levels, but instead are used to reduce fuel and purchased power costs that are recovered by Chugach retail and Seward. As a result, rate changes to third party transmission and ancillary services will be prospectively made through general rate case filings. This has no impact on Chugach’s continued

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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

use of SRF for quarterly demand and energy rate adjustments to Chugach retail customers and Seward.

Chugach submitted its June 2016 and September 2016 test year SRFs with the RCA on August 29, 2016 and December 1, 2016, respectively, as informational filings with no changes to the demand and energy rates of Chugach retail and Seward.

Operation and Regulation of the Alaska Railbelt Electric and Transmission System

The 2014 Alaska Legislature directed the RCA to provide a recommendation on whether creating an independent system operator or similar structure in the Railbelt area is the best option for effective and efficient electrical transmission. 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 June 30, 2015, the RCA issued its report which recommended an independent transmission company, certificated and regulated as a public utility, be created to operate the transmission system reliably and transparently and to plan and execute major maintenance, transmission system upgrades, and new transmission projects necessary for the reliable delivery of electric power to Railbelt customers. The RCA opened Docket I-15-001 to gather information on power pooling and/or centralized transmission system planning and operation among the Railbelt electric utilities, including economic dispatch of the Railbelt’s electrical generation units.Initial progress reports were filed with the RCA on September 30, 2015. With the support of the RCA, Chugach and several other Railbelt utilities are evaluating possible transmission business model opportunities and associated economic dispatch models that Chugach believes may lead to more optimal Railbelt-wide system operations.

On February 1, 2016, Chugach and the Municipality of Anchorage d/b/a Municipal Light and Power (ML&P) filed a joint report regarding the development of a power pooling and joint dispatch arrangement between the utilities. The filing summarized several of the projected qualitative and quantitative benefits of such an arrangement. Chugach and ML&P filed subsequent joint reports regarding their progress toward joint dispatch and power pooling arrangements on May 2, 2016, and August 10, 2016. On October 31, 2016, Chugach, ML&P, and MEA filed a joint report informing the RCA that they were negotiating a power pooling and joint dispatch agreement.

On January 27, 2017, Chugach, ML&P, and MEA entered into an Amended and Restated Power Pooling and Joint Dispatch Agreement (Agreement) which provides for economic dispatch resulting from coordinated scheduling of generation and transmission assets, including scheduling, dispatch, and settlement transactions at the bulk power level of electric services. The Agreement was submitted to the RCA as an informational filing on January 30, 2017 under Docket I-15-001. The Agreement provides a contractual framework for coordinated scheduling, dispatch, and settlement transactions for the purchase, sale, or exchange of energy, capacity, reserves, and transmission ancillary services on an efficient and economic basis among the signatories to the Agreement.

The Agreement provides for a one-year development period to develop and agree upon specific, detailed generation and transmission dispatch procedures, fuel supply dispatch procedures, and a settlement process. Upon finalization of dispatch procedures and the settlement process in 2018,

61

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Chugach, ML&P and MEA will submit the Agreement to the RCA for approval. The total cost reductions resulting from the pool are estimated to be up to $16 million per year after the development period for all participants combined.

Cook Inlet Natural Gas Alaska:  Found Gas

On January 30, 2015, CINGSA submitted a filing to the RCA providing notice that it had found 14.5 Bcf of gas as a result of directional drilling in the storage facility and now proposes to establish guidelines for commercial sales of at least 2 Bcf of this gas. Chugach submitted comments to the RCA regarding CINGSA’s proposed treatment of found gas. Chugach does not believe CINGSA’s proposal to retain revenues for the sale of found gas should be permitted in recognition of the risk-sharing agreements made by CINGSA and its storage customers that resulted in the development of the CINGSA storage facility.

The RCA issued an order in March of 2015 suspending the filing for further investigation. CINGSA filed direct testimony in the case on April 13, 2015. Chugach and other interveners in the case submitted responsive testimony on June 5, 2015. CINGSA submitted its reply testimony on June 29, 2015. The evidentiary hearing was held in September of 2015.

The RCA issued a final order in the case on December 4, 2015, ruling significantly in favor of the interveners in the case. The RCA granted approval for CINGSA to sell 2 Bcf with 87% of the proceeds allocated to CINGSA’s Firm Storage Service (FSS) customers and 13 percent to CINGSA. The RCA also required CINGSA to file a reservoir engineering study by June 30, 2016, and required CINGSA to file notice of all gas sales within 30 days of any sales, including the transaction price, purchaser, quantities, and the terms and conditions of the sale. The RCA also required that all proceeds to the FSS customers be treated as a reduction in fuel costs that are paid by CINGSA’s customers.

On January 4, 2016, CINGSA filed an appeal in Superior Court to Order U-15-016(14), stating the RCA violated CINGSA’s right to due process of law, erred, and/or acted unreasonably, unfairly, arbitrarily, capriciously, or contrary to applicable law. CINGSA believes additional proceeds resulting from the sale of found native gas should remain with CINGSA. Chugach filed an entry of appearance in the case on January 14, 2016. CINGSA filed its brief on June 6, 2016. Chugach filed its reply brief on October 31, 2016. Oral argument was held on March 6, 2017.

Beluga River Unit

In July of 2015, ConocoPhillips Alaska, Inc. (CPAI) announced the marketing for sale of its North Cook Inlet Unit; its interest in the Beluga River Unit (BRU); and its interest in 5,700 acres of exploration prospects in the Cook Inlet region. In October of 2015, Chugach submitted a joint bid with ML&P for acquisition of CPAI’s one-third working interest in the BRU.

Chugach entered into an agreement entitled, “Purchase and Sale Agreement between ConocoPhillips Alaska, Inc. and Municipality of Anchorage d/b/a Municipal Light & Power and Chugach Electric Association, Inc.” (Purchase and Sale Agreement) on February 4, 2016. The Purchase and Sale Agreement transfers CPAI’s interest in the BRU to Chugach and ML&P. The acquisition and attendant recovery of costs in electric rates was subject to RCA approval.

62

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

On March 11, 2016, Chugach and ML&P submitted a joint request to the RCA for approval of the acquisition of CPAI’s interest in the BRU and the attendant recovery of the acquisition costs in electric rates. Chugach and ML&P requested expedited consideration, asking the RCA to issue a bench ruling by April 21, 2016. The request for expedited consideration was made to provide additional certainty regarding Chugach’s eligibility for a State of Alaska production tax credit.

The RCA opened docket U-15-081 and established an expedited procedural schedule for the case. The RCA held a hearing from April 18 through April 20, 2016, and issued a bench ruling on April 20, 2016, approving the joint request for approval of the Purchase and Sale Agreement. A written order affirming the bench ruling was issued on April 21, 2016.

Separate filings detailing the specific rate recovery process were filed in the second quarter of 2016. The RCA approved the initial gas transfer price of $5.88 per Mcf. Under the recovery structure proposed by Chugach, costs associated with the BRU, including acquisition and on-going operations, maintenance and capital investment, will be recovered on a dollar-for-dollar basis through Chugach’s quarterly fuel adjustment process. Chugach recovers its fuel and purchased power costs as a direct pass-through from its retail and wholesale customers with minimal lag between cost incurrence and recovery.

On June 29, 2016, Chugach filed a petition with the RCA for approval to create a regulatory asset for the deferral of expenses (financial/economic, engineering and legal services) associated with Chugach’s acquisition of the BRU, which was $1.5 million at December 31, 2016, and is included in deferred charges on Chugach’s balance sheet. See Note 8 – Deferred Charges and Liabilities.  Chugach also requested approval to recover the deferred costs in the gas transfer price.

On September 14, 2016, the RCA issued an order combining the BRU cost recovery process and the request to create a regulatory asset into a single docket. The RCA established a procedural schedule and indicated that a final order in the case would be issued by November 17, 2017.

Depreciation Study Update

In compliance with a previous order from the RCA (U-12-009(8)), Chugach submitted a 2015 Depreciation Study Update to the RCA, requesting approval of the depreciation rates resulting from the study for use in Chugach’s financial record keeping and for establishing electric rates. If approved, adoption of the updated depreciation rates would result in a $5.9 million reduction in annual depreciation expense. On a demand and energy rate basis, the impact is a 4.7% reduction to retail customers and a 4.6% reduction to Seward. The reductions on a total customer bill basis, which includes fuel and purchased power costs, are 3.2% and 1.9%, respectively. Chugach requested that the updated depreciation rates be implemented on July 1, 2017, for both accounting and ratemaking purposes.

On October 11, 2016, the RCA issued Order U-16-081(1) to address the depreciation study update. The RCA indicated that a final order in the proceeding would be issued by March 29, 2017.

63

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Beluga Parts Filing

On November 18, 2016, Chugach submitted a petition to the RCA for approval to create a regulatory asset that would allow Chugach to amortize and recover in rates the value of certain plant needed to support power production equipment located at Beluga Power Plant.

Specifically, Chugach requested RCA approval to recover approximately $11.4 million in equipment that supports Beluga generation units. Chugach requested that it be permitted to amortize the value of this plant over a period of 30 months for plant associated with Units 1 and 2 (approximately $0.3 million), and 108 months for all other parts (approximately $11.1 million). The amortization periods are consistent with the proposed depreciation rates for the Beluga units contained in Chugach’s depreciation study that was submitted to the RCA on September 30, 2016.

Furie Agreement

On March 16, 2017, Chugach submitted a request to the RCA for approval of the agreement entitled, “Firm and Interruptible Gas Sale and Purchase Agreement between Furie Operating Alaska, LLC and Chugach Electric Association, Inc.” (Furie Agreement) dated March 3, 2017. As part of the filing, Chugach also requested RCA approval to recover both firm and interruptible purchases under the agreement and all attendant transportation and storage costs through its quarterly fuel and purchased power cost adjustment process.

The Furie Agreement provides Chugach with both firm and non-firm gas supplies over a 16-year period, with firm purchases beginning on April 1, 2023, and ending on March 31, 2033, and interruptible gas purchases available to Chugach immediately upon RCA approval and ending on March 31, 2033. With respect to firm purchases beginning on April 1, 2023, and ending on March 31, 2033, the Furie Agreement provides an Annual Gas Commitment by Furie to sell and Chugach to purchase approximately 1.8 Bcf of gas each year, which represents approximately 20% to 25% of Chugach’s projected gas requirements during this period. The Furie Agreement also provides Chugach with additional purchase options, with on a firm and interruptible basis. The initial price for firm gas is $7.16 per Mcf beginning April 1, 2023 and escalates annually, rising to $7.98 per Mcf on April 1, 2032, the last year of the contract.

64

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

(6)Utility Plant

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

Electric plant in service:	2016		2015
Steam production plant	$	101,116,277	$	100,938,247
Hydroelectric production plant		33,659,129		20,591,678
Other production plant		287,404,484		284,035,865
Transmission plant		282,040,969		277,490,606
Distribution plant		294,641,485		290,680,919
General plant		54,982,432		51,841,582
Unclassified electric plant in service1		83,457,981		95,611,615
Intangible plant1		5,455,371		5,455,371
Beluga River Natural Gas Field (BRU Asset & ARO)		47,927,331		0
Other1		1,828,409		1,828,409
Total electric plant in service		1,192,513,869		1,128,474,292
Construction work in progress		18,455,940		15,601,374
Total electric plant in service and construction work in progress	$	1,210,969,809	$	1,144,075,666

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.

(7)    Investments in Associated Organizations

Investments in associated organizations include the following at December 31:

	2016		2015
NRUCFC	$	6,095,980	$	6,095,980
CoBank		3,188,490		3,475,664
NRUCFC Capital Term Certificates and other		64,841		63,875
Total investments in associated organizations	$	9,349,311	$	9,635,519

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.

65

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

(8)    Deferred Charges and Liabilities

Deferred Charges

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

	2016		2015
Regulatory assets:
Debt issuance and reacquisition costs	$	492,850	$	247,481
Refurbishment of transmission equipment		104,939		114,198
Feasibility studies		1,387,285		551,122
Beluga gas compression		0		508,866
Cooper Lake relicensing / projects		5,280,006		5,410,109
Fuel supply		2,005,052		939,768
Storm damage		647,381		841,595
Other regulatory deferred charges		849,933		1,056,909
Bond interest - market risk management		5,365,190		5,871,286
Environmental matters		1,024,171		1,069,522
Total regulatory assets		17,156,807		16,610,856
Other deferred charges:
NRECA pension plan prepayment		7,925,050		0
Post retirement benefit obligation		59,100		200,900
Total other deferred charges		7,984,150		200,900
Total deferred charges	$	25,140,957	$	16,811,756

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

	2016		2015
Regulatory assets:
Multi-stage Energy Storage	$	1,117,860	$	124,569
Regulatory studies and other		46,721		360,879
Total regulatory assets		1,164,581		485,448
Other deferred charges:
NRECA pension plan prepayment		7,925,050		0
Post retirement benefit obligation		59,100		200,900
Total other deferred charges		7,984,150		200,900
Total deferred charges	$	9,148,731	$	686,348

66

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

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 Liabilities

Deferred liabilities, at December 31 consisted of the following:

	2016		2015
Refundable consumer advances for construction	$	328,360	$	823,115
Estimated initial installation costs for meters		118,854		105,274
Post retirement benefit obligation		732,200		874,000
Total deferred liabilities	$	1,179,414	$	1,802,389

(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, 2016, Chugach had$169,996,436 of patronage capital (net of capital credits retired in 2016), which included $164,182,580of patronage capital that had been assigned and $5,813,856 of patronage capital to be assigned to its members. At December 31, 2015, Chugach had $167,447,781of patronage capital (net of capital credits retired in 2015), which included $160,944,929of patronage capital that had been assigned and $6,502,852 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. 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, 2016 and 2015, 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 $4.1 million and $3.2 million at December 31, 2016 and 2015, respectively.

67

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

The Second Amended and Restated Indenture of Trust (Indenture) and the CoBank Second 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% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins. Capital credits retired, net of HEA’s allocations, were $3,265,201,  $3,190,124, and $5,130,381 for the years ended December 31, 2016, 2015, and 2014, respectively. With the exception of MEA’s and HEA’s patronage capital payable, the outstanding liability for capital credits authorized but not paid at December 31, 2016,  2015, and 2014 was $2,014,080,  $2,105,440 and$1,042,064, respectively.

(10)  Other Equities

A summary of other equities at December 31 follows:

	2016		2015
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		2,001,450		1,877,193
Unclaimed capital credit retirement1		11,803,000		10,627,038
Total other equities	$	13,828,075	$	12,527,856

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

68

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

(11)  Debt

Long-term obligations at December 31 are as follows:	2016		2015
2011 CoBank Note, 2.78% variable rate at redemption, with interest payable monthly and principal due annually beginning in 2003	$	0	$	24,941,165
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		67,500,000		72,000,000
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		154,166,665		160,333,332
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		60,000,000		63,750,000
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		95,000,000		102,000,000
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
2016 CoBank Note, 2.58% fixed rate note maturing in 2031, with interest and principal due quarterly beginning in 2016		43,776,000		0
Total long-term obligations	$	470,442,665	$	473,024,497
Less current installments		24,836,667		24,115,980
Less unamortized debt issuance costs		2,715,745		2,680,897
Long-term obligations, excluding current installments	$	442,890,253	$	446,227,620

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 2016 CoBank Note.The CoBank Note is governed by the Second Amended and Restated Master Loan Agreement, which is secured by the Indenture dated January 20, 2011.

69

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Chugach is also required to comply with the 2016 Credit Agreement, between Chugach and NRUCFC, KeyBank National Association, Bank of America, N.A., CoBank, and ACB dated June 13, 2016, governing loans and extensions of credit associated with Chugach’s commercial paper program, in an aggregate principal amount not exceeding $150.0 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.

70

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

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 Second Amended and Restated Master Loan Agreement with CoBank, which became effective on June 30, 2016, did not change this requirement.

The 2016 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% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins.

Maturities of Long‑term Obligations

Long-term obligations at December 31, 2016, mature as follows:

Year ending December 31		2011 Series A Bonds		2016 CoBank Note		2012 Series A Bonds		Total
2017	$	10,666,667	$	3,420,000	$	10,750,000	$	24,836,667
2018		10,666,667		3,192,000		10,750,000		24,608,667
2019		10,666,667		3,192,000		10,750,000		24,608,667
2020		10,666,667		3,420,000		10,750,000		24,836,667
2021		10,666,667		3,648,000		3,750,000		18,064,667
Thereafter		168,333,330		26,904,000		158,250,000		353,487,330
	$	221,666,665	$	43,776,000	$	205,000,000	$	470,442,665

Lines of credit

Chugach maintains a $50.0 million line of credit with NRUCFC. Chugach did not utilize this line of credit in 2016 or 2015, and therefore had no outstanding balance at December 31, 2016 and 2015.  The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. The borrowing rate was2.90% at December 31, 2016 and 2015.

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.

71

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

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. This pricing included 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 was set to expire on November 17, 2016.  

On June 13, 2016, Chugach entered into a $150.0 million senior unsecured credit facility, the Credit Agreement, which is used to back Chugach’s commercial paper program. The new pricing includes an all-in drawn spread of one month LIBOR plus 90.0 basis points, along with a 10.0 basis points facility fee (based on an A/A2/A unsecured debt rating). The new Credit Agreement will expire on June 13, 2021. The participating banks include NRUCFC, KeyBank National Association, Bank of America, N.A., and CoBank, ACB.

Our commercial paper can be repriced between one day and 270 days. Chugach is expected to continue to issue commercial paper in 2017, as needed.

Chugach had $68.2 million and $20.0 million of commercial paper outstanding at December 31, 2016 and 2015, respectively.

The following table provides information regarding 2016 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 2016	$	16.1	0.61	July 2016	$	47.3	0.66
February 2016	$	16.9	0.60	August 2016	$	54.2	0.63
March 2016	$	30.5	0.60	September 2016	$	60.0	0.65
April 2016	$	55.1	0.60	October 2016	$	63.5	0.65
May 2016	$	78.2	0.60	November 2016	$	60.8	0.65
June 2016	$	76.0	0.62	December 2016	$	63.7	0.86

72

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Financing

On January 21, 2011, Chugach issued $275.0 million of First Mortgage Bonds, 2011 Series A, in two tranches, Tranche A and Tranche B, for the purpose of refinancing the 2001 and 2002 Series A Bonds in 2011 and 2012, and for general corporate purposes. Interest is paid semi-annually on March 15 and September 15 commencing on September 15, 2011. Principal on the 2011 Series A Bonds is paid in equal annual installments beginning March 15, 2012.On January 11, 2012, Chugach issued $250.0 million of First Mortgage Bonds, 2012 Series A, in three tranches, Tranche A, Tranche B and Tranche C, for the purpose of repaying outstanding commercial paper used to finance SPP construction and for general corporate purposes. Interest is paid semi-annually March 15 and September 15 commencing on September 15, 2012. The 2012 Series A Bonds,  Tranche A and Tranche C, pay principal in equal installments on an annual basis beginning March 15, 2013, and 2023, respectively. The 2012 Series A Bonds,  Tranche B, pay principal beginning March 15, 2013,through 2020, and on March 15, 2032,through2042.  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.

Chugach had a term loan facility with CoBank,  evidenced by the 2011 CoBank Note, which was governed by the Amended and Restated Master Loan Agreement dated January 19, 2011, and secured by the Indenture. On July 13, 2016, Chugach used commercial paper to pay off the $22.2 million balance and therefore had no outstanding balance at December 31, 2016. Chugach had $24.9 million outstanding on this facility at December 31, 2015.

On June 30, 2016, Chugach entered into another term loan facility with CoBank, evidenced by the 2016 CoBank Note, which is governed by the Second Amended and Restated Master Loan Agreement dated June 30, 2016, and secured by the Indenture. Chugach had $43.8 million outstanding on this facility at December 31, 2016.

The following table provides additional information regarding the 2011 Series A and 2012 Series A bonds and the 2016 CoBank Note at December 31, 2016 (dollars in thousands):

	Maturing March 15,	Average Life (Years)	Interest Rate		Issue Amount		Carrying Value
2011 Series A, Tranche A	2031	7.2	4.20	%	$	90,000	$	67,500
2011 Series A, Tranche B	2041	12.2	4.75	%		185,000		154,167
2012 Series A, Tranche A	2032	7.7	4.01	%		75,000		60,000
2012 Series A, Tranche B	2042	14.8	4.41	%		125,000		95,000
2012 Series A, Tranche C	2042	15.7	4.78	%		50,000		50,000
2016 CoBank Note	2031	6.2	2.58	%		45,600		43,776
Total					$	570,600	$	470,443

73

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

(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, 2016, 2015 and 2014 of $6.7million,  $6.7 million and $6.8 million, respectively. The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2016, 2015 and 2014.

In December 2012,acommittee of the NRECA Board of Directors approved an option to allow participating cooperatives in the Retirement Security (RS) Plan (a defined benefit multiemployer pension plan) to make a prepayment and reduce future required contributions. The prepayment amount is a cooperative’s share, as of January 1, 2013, of future contributions required to fund the RS Plan’s unfunded value of benefits earned to date using Plan actuarial valuation assumptions. The prepayment amount will typically equal approximately 2.5 times a cooperative’s annual RS Plan required contribution as of January 1, 2013. After making the prepayment, for most cooperatives the billing rate is reduced by approximately 25%, retroactive to January 1, 2013. The 25% differential in billing rates is expected to continue for approximately 15 years. However changes in interest rates, asset returns and other plan experience different from that expected, plan assumption changes, and other factors may have an impact on the differential in billing rates and the 15 year period.

On December 29, 2106, Chugach made a prepayment of $7.9 million to the NRECA RS Plan. See Note 2n – “Deferred Charges and Liabilities.”

74

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

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
	2016	2015	2014	2016	2015	2014
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)	$3.2	$3.1	$3.3	$3.5	$3.5	$3.5
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 participant in the NRECA RS Plan who is subject to an employment agreement, which is effective through April 30, 2020.

3The Alaska Electrical Pension Plan financial statements are publicly available. The NRECA RS Plan financial statements are 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, 2016, 2015, and 2014 were$4.5 million,  $4.5 million, and $4.5 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, 2016, 2015, and 2014 totaled $2.8 million,  $2.6 million, and $2.9 million respectively.

75

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

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, 2016, 2015 and 2014 were $132.3 thousand, $133.6 thousand and $149.2 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 $18,000 in 2016 and 2015 and $17,500 in 2014, and allowed catch-up contributions for those over 50 years of age of $6,000 in 2016 and 2015 and $5,500 in 2014. 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, 2016, and 2015was $907,836 and$763,913, 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.

76

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

(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% 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$19.0million.  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%. Upon default, Chugach could be faced with annual expenditures of approximately  $6.0millionas 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% of the additional energy produced.

The following represents information with respect to Bradley Lake at June 30, 2016 (the most recent date for which information is available). Chugach's share of expenses was $5,662,522in 2016,  $5,663,304 in 2015, and $5,228,907 in 2014 and is included in purchased power in the accompanying financial statements.

(In thousands)	Total		Proportionate Share
Plant in service	$	163,531	$	49,713
Long-term debt		53,495		16,262
Interest expense		3,177		966

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

77

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

(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%), MEA (17%) and ML&P (53%).

Plant in service in 2016 included$4,229,167, net of accumulated depreciation of $2,442,175,  which represents Chugach’s share of the Eklutna Hydroelectric Project. In 2015, plant in service included $4,401,440, net of accumulated depreciation of $2,203,659. 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 $532,678,  $689,501, and $761,613in 2016, 2015, and 2014, 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)  Beluga River Unit

On February 4, 2016, Chugach entered into an agreement entitled, “Purchase and Sale Agreement between ConocoPhillips Alaska, Inc. and Municipality of Anchorage d/b/a Municipal Light & Power and Chugach Electric Association, Inc.” The Purchase and Sale Agreement transfers CPAI’s working interest in the BRU to Chugach and ML&P. The total purchase price was $148.0 million, with Chugach’s portion totaling $44.4 million. Chugach’s interest in the BRU is to reduce the cost of electric service to its retail and wholesale members by securing an additional long-term supply of natural gas to meet on-going generation requirements. The acquisition complements existing gas supplies and is expected to provide greater fuel diversity.

Under the joint bid arrangement, Chugach’s ownership of CPAI’s working interest is 30% and ML&P’s ownership is 70%. The ownership shares include the attendant rights and privileges of all gas and oil resources, including 15,500 lease acres (8,200 in Unit / Participating Area and 7,300 held by Unit), Sterling and Beluga producing zones, and CPAI’s 67% working interest in deep oil resources. On April 21, 2016, the acquisition was approved by the RCA (see “Note 5 – Regulatory Matters – Beluga River Unit”) and the transaction closed on April 22, 2016.

Chugach had a firm gas supply contract with CPAI as previously discussed in “Note 16 – Commitments and Contingencies – Fuel Supply Contracts”. In addition to Chugach, CPAI had contractual gas sales obligations to ENSTAR through 2017. These contracts were assumed by ML&P and Chugach on the basis of ownership share.

78

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

The BRU is located on the western side of Cook Inlet, approximately 35 miles from Anchorage, and is an established natural gas field that was originally discovered in 1962. The BRU was jointly owned (one-third) by CPAI, Hilcorp, and ML&P. Following the acquisition, ML&P’s ownership of the BRU increased to approximately 56.7%, Hilcorp’s ownership remained unchanged at 33.3%, and Chugach’s ownership is 10.0%.

Chugach’s interest in the BRU is insignificant to the BRU as a whole and compared to Chugach’s operations prior to the acquisition. As such, Chugach has not provided supplemental pro forma financial information. Since the BRU activities are limited to the extraction of natural gas, Chugach is following the guidance provided in ASC 932-810-45-1 (Extractive Activities-Oil and Gas – Consolidation – Other Presentation Matters) and will record its pro rata share of the assets, liabilities, revenues and expenses of the BRU.

Chugach recorded the acquisition at fair value on the acquisition date. The fair value estimate used the discounted cash flow method assuming an estimated useful life of 18 years with 27 Bcf of proven developed producing reserves and using Chugach’s BRU financing rate as the credit adjusted risk free rate. The table below outlines the acquisition allocation recorded at December 31, 2016.

	Amount
Utility Plant:
Proved Developed Reserves	$	33,693,922
Proved Undeveloped Reserves		10,710,000
Asset Retirement Obligation		3,523,409
Utility plant		47,927,331
Cost of removal obligation		(3,523,409)
Cash Consideration	$	44,403,922

Acquisition costs are recorded as deferred charges on Chugach’s balance sheet because Chugach believes it is probable the RCA will allow them to be collected through rates, and totaled $1.5 million at December 31, 2016. Chugach has requested that these costs be amortized based on units of production of the BRU and recognized as depreciation and amortization on Chugach’s statement of operations.

Each of the BRU participants has a right to take their interest of the gas produced. Parties that take less than their interest of the field’s output may either accept a cash settlement for their underlift or take their underlifted gas in future years. As part of the BRU acquisition, Chugach acquired 30% of CPAI’s underlift, which was 69,099 Mcf at acquisition and was in an overlift position of 84 Mcf at December 31, 2016. Chugach has opted to take any cumulative underlift in gas in the future and will record the gas as fuel expense on the statement of operations when received.

The revenue generated by Chugach’s interest in the BRU operations is primarily associated with the gas sold to ENSTAR, pursuant to the aforementioned contract due to expire December 31, 2017. Chugach recognized revenue from the BRU in the amount of $2.8 million through December 31, 2016.

79

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Chugach records depreciation, depletion and amortization on BRU assets based on units of production. As of December 31, 2016, Chugach lifted 1.9 Bcf resulting in approximately 25.1 Bcf remaining in Chugach’s proven developed reserves. Prior to the acquisition, CPAI was the contracted operator of the BRU. Following the acquisition, Hilcorp temporarily assumed operations under an agreement similar to that previously held by CPAI. A final operator agreement is expected during the second quarter of 2017. In addition to the operator fees to Hilcorp, other BRU expenses include royalty expense and interest on long-term debt. All expenses other than depreciation, depletion and amortization and interest on long-term debt are included as fuel expense on Chugach’s statement of operations. Chugach has applied and qualified for a small producer tax credit, provided by the State of Alaska, resulting in an estimate of no liability for production taxes. The revenue in excess of expenses less the allowed TIER from BRU operations is adjusted through Chugach’s fuel and purchased power adjustment process.

(16)  Commitments and Contingencies

Contingencies

Chugach is a participant in various legal actions, rate disputes, personnel matters and claims both for and against Chugach’s interests. Management believes the outcome of any such matters will not materially impact Chugach’s financial condition, results of operations or liquidity. Chugach establishes reserves when a particular contingency is probable and calculable. Chugach has not accrued for any contingency at December 31, 2016, as it does not consider any contingency to be probable nor calculable. Chugach faces contingencies that are reasonably possible to occur; however, they cannot currently be estimated.

Concentrations

Approximately 70% of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW. We also have an agreement with the Hotel Employees and Restaurant Employees (HERE). All three IBEW CBA’s have been renewed through June 30, 2021. The HERE contract was renewed through June 30, 2021. We believe our relationship with our employees is good.

80

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Fuel Supply Contracts

Chugach has fuel supply contracts from various producers at market terms. A gas supply contract between Chugach and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively “ConocoPhillips”), approved effective by the RCA on August 21, 2009, began providing gas in 2010 and expired December 31, 2016. The total amount of gas under the contract was 62 Bcf.This contract was assumed by Chugach and ML&P as part of the BRU acquisition, on the basis of ownership share. As such, Chugach pays ML&P for 70% of gas purchased under this contract. Chugach entered into a gas contract with Hilcorp effective January 1, 2015, to provide gas through March 31, 2018. On September 15, 2014, the RCA approved an amendment to the Hilcorp gas purchase agreement extending gas delivery and subsequently filling 100 percent of Chugach’s needs through March 31, 2019. On September 8, 2015, the RCA approved another amendment to the Hilcorp gas purchase agreement extending the term of the agreement, thus filling up to 100 percent of Chugach’s needs through March 31, 2023.  The total amount of gas under this contract is estimated to be 60 Bcf. All of the production is expected to come from Cook Inlet, Alaska. The terms of the ML&P (previously under ConocoPhillips) and Hilcorp agreements require Chugach to manage the natural gas transportation over the connecting pipeline systems. Chugach has gas transportation agreements with ENSTAR Natural Gas Company (ENSTAR) and Hilcorp.

The RCA approved a 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 began providing gas April 1, 2011, and will expire March 31, 2023. The total amount of gas under contract is currently estimated up to49 Bcf. These contracts fill 100% of Chugach’s needs through March 31, 2023. All of the production is expected to come from Cook Inlet, Alaska.

In 2016, 77% of our power was generated from gas, with 9% generated at the Beluga Power Plant and 88%generated at SPP. In 2015,  86% of our power was generated from gas, with 30% generated at Beluga and61% generated at SPP.

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 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:

	2016		2015		2014
Hilcorp	56.9	%	30.3	%	50.4	%
ConocoPhillips (COP)	32.0	%	58.7	%	43.6	%
AIX Energy	0.7	%	4.7	%	0.0	%
ENSTAR	4.7	%	3.3	%	2.0	%
Harvest (Hilcorp) Pipeline	3.2	%	1.6	%	3.0	%
Miscellaneous	2.5	%	1.4	%	1.0	%

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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

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, 2016 and 2015.MEA’s patronage capital payable was $4.1 million and $3.2 million at December 31, 2016 and 2015, respectively.

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 $0.000675, effective July 1, 2016. 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 collectedmonthly 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 $2,507,482and $5,184,551 for this charge at December 31, 2016 and 2015, respectively, and is included in other current liabilities. These funds are used to offset the costs of the undergrounding program.

82

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

Environmental Matters

Since January 1, 2007, transformer manufacturers have been required to meet the US Department of Energy (DOE) efficiency levels as defined by the Energy Act of 2005 (Energy Act) for all “Distribution Transformers.” As of January 1, 2016, the specific efficiency levels are increasing from the original “TP1” levels to the new “DOE-2016” levels. All new transformers are DOE-2016 compliant. At this time a small increase in capital costs is anticipated along with a reduction in energy losses.

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 August 3, 2015, the EPA released the final 111(d) regulation language aimed at reducing emissions of carbon dioxide (CO₂) from existing power plants that provide electricity for utility customers. In the final 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. The EPA initially applied the final rule to 47 of the contiguous states. At this time, Alaska, Hawaii, Vermont, Washington D.C. and two U.S. territories are not bound by the regulation. Alaska may be required to comply at some future date. On February 9, 2016 the U.S. Supreme Court issued a stay on the proposed EPA 111(d) regulations until the DC Circuit decides the case, or until the disposition of a petition to the Supreme Court on the issue. On September 27, 2016, the US Court of Appeals for the District of Columbia Circuit heard oral arguments challenging the legality of the Clean Power Plan. The court is expected to issue a decision in the near future. The EPA 111(d) regulation, in its current form, is not expected to have a material effect on Chugach’s 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 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.

83

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2016 and 2015

(17)  Subsequent Events

On March 17, 2017, Chugach issued $40,000,000 of First Mortgage Bonds, 2017 Series A, due March 15, 2037 for general corporate purposes. The 2017 Series A Bonds will mature on March 15, 2037, and will bear interest at 3.43%. Interest will be paid each March 15 and September 15, commencing on September 15, 2017. The 2017 Series A Bonds will pay principal in equal installments on an annual basis beginning March 15, 2018, resulting in an average life of approximately 10.0 years. The bonds are secured, ranking equally with all other long-term obligations, by a first lien on substantially all of Chugach’s assets, pursuant to the Sixth Supplemental Indenture to the Second Amended and Restated Indenture of Trust, which initially became effective on January 20, 2011, as previously amended and supplemented.

(18)  Quarterly Results of Operations (unaudited)

2016 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	57,741,954	$	45,132,973	$	44,622,517	$	50,250,135
Operating Expense		47,000,307		40,308,301		41,472,710		42,359,071
Net Interest		5,341,242		5,427,440		5,247,404		5,385,211
Net Operating Margins		5,400,405		(602,768)		(2,097,597)		2,505,853
Nonoperating Margins		231,683		125,332		127,871		123,077
Assignable Margins	$	5,632,088	$	(477,436)	$	(1,969,726)	$	2,628,930

2015 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	50,640,703	$	43,109,512	$	47,697,820	$	74,973,117
Operating Expense		42,182,178		39,667,546		43,490,558		63,451,276
Net Interest		5,415,131		5,428,774		5,381,167		5,589,373
Net Operating Margins		3,043,394		(1,986,808)		(1,173,905)		5,932,468
Nonoperating Margins		368,403		79,028		126,010		114,262
Assignable Margins	$	3,411,797	$	(1,907,780)	$	(1,047,895)	$	6,046,730

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Item 9 –Changes in and Disagreements with

Accountants on Accounting and Financial Disclosure

None

Item 9A – Controls and Procedures

Changes in Internal Control Over Financial Reporting

In connection with the acquisition of the BRU on April 22, 2016, Chugach has evaluated and implemented additional internal 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.

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 are 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, 2016, using the criteria set forth in “Internal Control Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) (2013 framework). Based on this assessment, management believes that, as of December 31, 2016, Chugach maintained effective internal controls over financial reporting.

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Item 9B – Other Information

None.

PART III

Item 10 – Directors, Executive Officers and Corporate Governance

Chugach operates under the direction of a Board of Directors (Board) that is elected at large by our membership. Day-to-day business and affairs are administered by the CEO. Our seven-member Board sets policy and provides direction to the CEO. Each statutory officer must be a member of the Board, but these officers do not participate in the day-to-day management of Chugach. No member of the Board is an employee of Chugach nor does any member of the Board have a material relationship with Chugach. 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 the Nominating Committee. The Nominating 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 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. 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.

Janet Reiser, 61, Chair, was elected to the Board in 2008, and re-elected in 2011 and 2014. She currently serves on the Governance, Operations, and Audit and Finance 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.

Susan Reeves, 68, 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 and 2016. She currently serves as the Chair of the Governance Committee and as the Vice Chair of the Operations Committee. She is a National Rural Electric Cooperative Association Credentialed Cooperative Director. Her term expires in May of 2020.

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Bettina Chastain,  52,  Secretary, is an executive, business owner and engineer who has spent her career providing technical and management consulting services to the oil and gas and energy sectors in Alaska, nationally and internationally.  She has been a very active member of th community serving on several non-profit boards for many years. She was elected to the Board in May of 2015. She currently serves as the Chair of the Operations Committee and as the Vice Chair of the Audit and FinanceCommittee. Her term expires in May of 2019.

Sisi Cooper, 36, Treasurer, is a project engineer with Doyon Anvil, 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 is a NRECA Credentialed Cooperative Director.  She was elected to the Board in 2012 and re-elected in 2015. She currently serves as the Chair of the Audit and Finance Committee and as a member of the Governance Committee. Her term expires in May of 2019.

Harry T. Crawford, Jr., 64, 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 as a member of the Operations Committee and as a member of the Audit and Finance Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2017.

Jim Henderson, 70,  Director,  is a principal with New American Financial Group in the financial services industry. He specializes in asset-based finance products, reorganization and refinancing of distressed companies, and accounting and disposition of capital assets. His primary emphasis is transportation, industrial machinery and aviation operations, assets and industry development. He has over 35 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 a member of the Audit and Finance Committee and as a member of the Governance Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director. His term expires in May of 2018.

Stuart Parks, 53, Director, is a Vice President with NANA WorleyParsons. He has been with NANA WorleyParsons and its related companies since 1990. During the last ten years, he has been responsible for leadership and management, business development, strategy development, contract management, market analysis, customer relations and program/project management. Prior to his appointment to the Board Mr. Parks served on Chugach’s Renewable Energy Committee. He was appointed to the Board on January 26, 2017. He currently serves as a member of the Operations and Governance Committees. His term expires in May of 2017.

Identification of Executive Officers

Lee D. Thibert,  61,was appointed Chief Executive Officer effective July 17, 2016. Prior to that appointment, Mr. Thibert served as Sr. Vice President, Strategic Development and Regulatory Affairs since July 1, 2013, Sr. Vice President, Strategic Planning and Corporate Affairs since June 11, 2008, Sr. Vice President, Power Deliveryfrom 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.

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Sherri Highers, 48, was appointed Chief Financial Officer and Vice President, Finance and Administration effective July 23, 2013.Prior to this appointment, Ms. Highers served as Manager, Budget and Financial Reporting since December 1, 2005,  Senior Financial Analyst since October 18, 2002, Financial Analyst since October 18, 1999, and Accountant since April 6, 1998.

Paul R. Risse,  62, was appointed Sr. Vice President, Production & Engineering on January 1, 2017. Prior to that appointment, he served as Sr. Vice President, Power Supply since 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.

Brian J. Hickey,  59, was appointed Sr. Vice President, System Operations on January 1, 2017.  Prior to that appointment he served as Executive Manager, Grid Development since June 5, 2012. Prior to that appointment he was a Sr. Project Manager for NANA WorleyParsons and Electric Power Systems, where he managed power plant and hydrocarbons projects in Alaska’s Railbelt and on Alaska’s North Slope since March 2008. Prior to that, he served Chugach for twenty years in various senior management roles including System Operations Supervisor, Manager of Substation Operations, Manager of Power Control, Director of Technical Services and lastly Vice President, Power Delivery. Mr. Hickey is a registered Professional Electrical Engineer, registered project management professional, holds a Bachelor of Science in Electrical Engineering, masters certificate in project management and a master’s degree in global finance.

Tyler E. Andrews, 51, was appointed Vice President, Member and Employee Services on September 9, 2013. Prior to that appointment he served as Vice President, Human Resources since March 17, 2008. Mr. Andrews has over 20 years of experience in Human Resources and Labor Relations. Since June of 2008, Mr. Andrews has also served as an appointed board member of the State of Alaska’s labor relations agency. Prior to his employment with Chugach, Mr. Andrews served as the Sr. Manager of Labor Relations for Alaska Communications Systems. Prior to that, he served more than 10 years with the State of Alaska in a wide range of Human Resources and Labor Relations functions including Human Resources Manager and Chief Spokesperson on numerous collective bargaining teams.

Code of Ethics

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

88

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 Nominating 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 2016 Audit and Finance Committee include Chair Sisi Cooper, Vice Chair Bettina Chastain and Directors Jim Henderson, Harry Crawford, and Janet Reiser.

The disclosure required by Rule 10A-3(d) of the Exchange Act regarding exemption from the listing standards for audit committees is not applicable to the Chugach Audit and Finance Committee.

89

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.

Compensation Committee Interlocks and Insider Participation

Chugach does not have a compensation committee. The compensation of the CEO is determined by the Board and no other individual, whether presently or previously employed by Chugach, was a party to the deliberations undergone by the Board in determining the CEO’s compensation.

Former CEO Brad Evans was 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 - was allocated a percentage of a total bonus amount to a maximum of $50,000. In 2016, 2015 and 2014, upon review of the performance of the CEO, Mr. Evans received bonuses of $45,000, $98,000 and $95,000, respectively.

CEO Lee Thibert is eligible for annual performance payments calculated as a percentage of his base salary based on individual and company-wide performance objectives determined by the Board associated with organizational vision and planning, leadership and management, Board relations/communications, electric system operations, organizational effectiveness, member/community relations, financial management and performance, employee relations, and project specific objectives.

The median employee was determined as of December 31, 2016, and the total annual compensation of Chugach’s median employee was $140,831. The current CEO’s total compensation in 2016 was 3.55 times the total compensation of Chugach’s median employee.

Chugach does not have shareholders and no vote has been put before the membership to approve the CEO’s compensation or the compensation of any other named executive. 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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Compensation Committee Report

Chugach does not have a compensation committee. The Board has reviewed and discussed the disclosures included in the Compensation Discussion and Analysis with management and has recommended the disclosures be included in Chugach’s Annual Report on Form 10-K.

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 2016 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
Lee D. Thibert,	2016	$	293,138	$	29,590	$	171,215	$	6,687	$	500,630
Chief Executive Officer	2015	$	247,266	$	27,000	$	148,951	$	18,888	$	442,105
	2014	$	232,252	$	15,000	$	126,569	$	10,648	$	384,469
Sherri L. Highers,	2016	$	176,405	$	18,422	$	75,726	$	932	$	271,485
Chief Financial Officer	2015	$	175,692	$	12,500	$	66,509	$	25,165	$	279,866
	2014	$	154,275	$	7,000	$	37,000	$	4,214	$	202,489
Paul R. Risse	2016	$	211,885	$	17,517	$	126,256	$	4,731	$	360,389
Sr. Vice President,	2015	$	215,447	$	16,000	$	114,127	$	12,595	$	358,169
Production & Engineering	2014	$	202,298	$	15,000	$	96,615	$	11,748	$	325,661
Tyler E. Andrews,	2016	$	178,824	$	15,353	$	41,669	$	8,353	$	244,199
Vice President, Member and	2015	$	181,744	$	14,500	$	37,243	$	34,169	$	267,656
Employee Services	2014	$	171,088	$	8,000	$	28,300	$	4,785	$	212,173
Bradley W. Evans,	2016	$	222,090	$	45,000	$	42,424	$	298,786	$	608,300
Former	2015	$	336,057	$	98,000	$	167,171	$	7,808	$	609,036
Chief Executive Officer	2014	$	314,284	$	95,000	$	132,305	$	7,193	$	548,782
William J. Bernier,	2016	$	179,427	$	10,517	$	56,433	$	9,061	$	255,438
Former Vice President,	2015	$	184,740	$	10,500	$	54,284	$	12,899	$	262,423
Power Delivery	2014	$	166,913	$	1,000	$	50,174	$	8,682	$	226,769

1Includes costs for life insurance premiums, tax withholdings on bonuses, payment for unused vacation days, severance 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% 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% 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 $265,000, 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 two 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, 2016, 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
Lee D. Thibert, Chief Executive Officer	Retirement Security	28.33	$	2,100,441	$	0
Sherri L. Highers, Chief Financial Officer	Retirement Security	17.08	$	377,874	$	0
Paul R. Risse, Sr. VP, Production & Engineering	Retirement Security	20.92	$	1,388,650	$	0
Tyler E. Andrews, VP, Member and Employee Services	Retirement Security	7.75	$	281,554	$	0
William J. Bernier, Former VP, Power Delivery	Retirement Security	7.42	$	333,852	$	0
Bradley W. Evans, Former Chief Executive Officer	Retirement Security	15.83	$	0	$	845,299
	Pension Restoration	15.83	$	0	$	290,513

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 PGGC rate (1.25% for 2016 and 1.00% for 2015), 30-year Treasury rate (3.03% for 2016 and 3.04% for 2015) and the Pension Protection Act (PPA) three-segment yield rates (1.76%, 4.15%, and 5.13% for 2016 and 1.40%, 3.88%, and 4.96% for 2015) and the required IRS mortality table for lump sum payments (1994 Guaranteed Annuity Rate (GAR), projected to 2002, blended 50%/50% for unisex mortality in combination with the 30-year Treasury rates and Retirement Plan (RP) 2000 PPA at 2016 and 2015, respectively, combined unisex 50%/50% mortality in combination with the PPA rates). The lump sum is then discounted at 4.03% interest only (no mortality is assumed) from assumed retirement date back to December 31, 2016, and 4.22% interest only (no mortality is assumed) from assumed retirement date back to December 31, 2015, to determine the present value for the appropriate year.

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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
Lee D. Thibert	$	2,600	$	0	$	12	$	0	$	2,612
Chief Executive Officer
Tyler E. Andrews,	$	12,462	$	0	$	3,939	$	0	$	84,799
Vice President, Member and
Employee Services
Bradley W. Evans,	$	18,000	$	0	$	765	$	0	$	162,312
Former Chief Executive Officer

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. Thibert is terminated by Chugach without cause, he will receive a lump sum payment equal to 100% of his annual base salary payable and the full cost of health and welfare coverage for a period not in excess of twelve 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
Lee D. Thibert,	$	435,905
Chief Executive Officer
Sherri L. Highers,	$	126,708
Chief Financial Officer
Paul R. Risse,	$	278,917
Sr. Vice President, Production & Engineering
Tyler E. Andrews,	$	93,207
Vice President, Member and Employee Services

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, 2016, to each of our current and former Board members:

Director Compensation Table

Name	Fees Paid In Cash
Janet Reiser, Chair and Director	$	23,800
Susan Reeves, Vice-Chair and Director	$	16,250
Bettina Chastain, Secretary and Director	$	17,500
Sisi Cooper, Treasurer and Director	$	23,400
Harry Crawford, Jr., Director	$	18,000
Jim Henderson, Director	$	18,450
Stuart Parks, Director	$	0
Bruce Dougherty, Former Director	$	17,300

Two Board members were re-elected at Chugach’s annual membership meeting held on May 19, 2016. Susan Reeves and Bruce Dougherty were elected to four year terms. Bruce Dougherty resigned from the Board effective December 14, 2016, due to a move out of state. The Board appointed Stuart Parks on January 26, 2017, to fill the vacancy left as a result of Bruce Dougherty’s resignation.

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, 2016.

Fees and Services

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

	2016		2015
Audit and audit-related services:
Audit and quarterly reviews	$	270,341	$	169,840
Audit-related services		42,608		36,555
Non-audit services:
Tax consulting and return preparation		12,568		10,200
Other services		0		0
Total	$	325,517	$	216,595

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, 2016 and 2015 were approved by the Audit and Finance Committee.

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PART IV

Item 15 – Exhibits, Financial Statement Schedules

	Page
Financial Statements
Included in Part II of this Report
Report of Independent Registered Public Accounting Firm	41
Balance Sheets, December 31, 2016 and 2015	42-43
Statements of Operations
Years ended December 31, 2016, 2015 and 2014	44
Statements of Changes in Equities and Margins
Years ended December 31, 2016, 2015 and 2014	45
Statements of Cash Flows
Years ended December 31, 2016, 2015 and 2014	46
Notes to Financial Statements	47-84

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 19, 2016, 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.
4.30	Fifth Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated June 30, 2016. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2016, 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.

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10.7	Power Purchase Agreement by and between Fire Island Wind, LLC and the Registrant dated as of June 21, 2011.Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
10.15.1	Amended and Restated Alaska Intertie Agreement Among Alaska Energy Authority, Municipality of Anchorage d/b/a Municipal Light and Power, the Registrant, Golden Valley Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc. dated November 18, 2011. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2011, SEC File No. 033-42125.
10.17	Memorandum of Understanding Regarding Intertie Upgrades among Alaska Energy Authority, the Registrant, Golden Valley Electric Association, Inc., Homer Electric Association, Inc., Matanuska Electric Association, Inc., Municipality of Anchorage d/b/a Municipal Light and Power, and the City of Seward d/b/a Seward Electric System dated March 21, 1990. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.18	Amendment No. 1 to the Alaska Intertie Agreement-Insurance and Liability dated March 28, 1991. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
10.19	Intertie Grant Agreement between the Registrant, Golden Valley Electric Association, Inc., Fairbanks Municipal Utility System, Anchorage Municipal Light and Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Matanuska Electric Association, Inc. and Homer Electric Association, Inc.), City of Seward, the State of Alaska, Department of Administration and Alaska Industrial Development and Export Authority dated August 17, 1993. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1993, SEC File No. 033-42125.
	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.

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10.23	Grant Administration Agreement by and among the Registrant, Alaska Industrial Development and Export Authority, Golden Valley Electric Association, Inc., Fairbanks Municipal Utilities System, Anchorage Municipal Light & Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Homer Electric Association, Inc. and Matanuska Electric Association, Inc.) and City of Seward dated August 30, 1994. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
10.24	Bradley Lake Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated December 8, 1987. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.24.1	Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.
10.25	Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated December 8, 1987. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
	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.

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10.27	Amendment to Agreement for Sale of Transmission Capability by and among the Registrant, Homer Electric Association, Inc., Alaska Electric Generation and Transmission Cooperative, Inc., Golden Valley Electric Association, Inc. and the Municipality of Anchorage d/b/a Municipal Light and Power dated March 7, 1989. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.28	Bradley Lake Hydroelectric Agreement for the Dispatch of Electric Power and for Related Services between the Registrant and the Alaska Energy Authority dated February 19, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1991, SEC File No. 033-42125.
10.29	Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated September 29, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.
10.29.1	Assignment of Agreement for Bradley Lake Resource Scheduling by and among the Registrant, Homer Electric Association, Inc. and the Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.
10.30	Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated December 2, 1983. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.30.1	Addendum No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated August 8, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.30.2	Amendment No. 1 to Interconnection Agreement between the Registrant and Municipality of Anchorage Municipal Light and Power dated November 28, 1984. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated September 19, 1991, SEC File No. 33-42125.
10.31	Gas Transportation Agreement by and among the Registrant, Alaska Pipeline Company and ENSTAR Natural Gas Company dated December 7, 1992. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1992, SEC File No. 033-42125.

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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.
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.
10.45.11	Second Amended and Restated Master Loan Agreement between the Registrant and CoBank, ACB, dated June 30, 2016. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2016, SEC File No. 033-42125.
10.45.12	Supplement to the Second Amended and Restated Master Loan Agreement between the Registrant and CoBank, ACB, dated June 30, 2016. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2016, SEC File No. 033-42125.

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10.45.13	Form of 2016 CoBank Note. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2016, 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.
10.47.4	First Amendment to Revolving Line of Credit Agreement between the Registrant and National Rural Utilities Cooperative Finance Corporation (NRUCFC) dated effective October 7, 2016. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated October 7, 2016, 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.
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.

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10.59	Agreement Covering Terms and Conditions of Employment for Office and Engineering Personnel between the Registrant and the International Brotherhood of Electrical Workers Local 1547 dated effective September 13, 2007. 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.
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.

106

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.
10.67	Engineering, Procurement and Construction Contract between the Registrant and SNC-Lavalin Constructors, Inc. dated effective June 18, 2010.Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2015, SEC File No. 033-42125.
10.68	Transportation Agreement between the Registrant and Beluga Pipeline Company dated effective October 1, 2010.Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125.
10.69	Transportation Agreement For Interruptible Transportation Of Natural Gas between the Registrant and Kenai Nikiski Pipeline dated effective October 1, 2010. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2010, SEC File No. 033-42125.
10.73	Special Contract for Natural Gas Transportation Service between the Registrant and ENSTAR Natural Gas Company effective November 1, 2012.Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2012, SEC File No. 033-42125.
10.74	Firm Transportation Service Agreement between the Registrant and ENSTAR Natural Gas Company effective August 1, 2012.Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2012, SEC File No. 033-42125.
10.75	Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska LLC effective September 10, 2013. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated September 10, 2013, SEC File No. 033-42125.
10.75.1	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.

107

10.75.2	Second Amendment to the Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska, LLC effective May 4, 2015. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2015, SEC File No. 033-42125.
10.75.3	Third Amendment to the Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska, LLC effective September 8, 2015. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2015, 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.
10.77.1	Memorandum of Understanding Regarding 2015 Interim Power Sales Agreement and Eklutna Generation Station agreements between the Registrant and Matanuska Electric Association, Inc. effective March 31, 2015. Previously filed as an exhibit to the Registrant’s Current Report on Form 8-K dated March 31, 2015, SEC File No. 033-42125.
10.78	Employment Agreement between the Registrant and Lee D. Thibert dated effective May 1, 2016. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2016, SEC File No. 033-42125.
10.79	Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation (NRUCFC), Bank of America, N.A., KeyBank National Association, and CoBank, ACB, dated June 13, 2016. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2016, SEC File No. 033-42125.
10.80	Employment Agreement between the Registrant and Bradley W. Evans dated effective July 18, 2016. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2016, 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.

108

31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

109

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 24, 2017.  

	CHUGACH ELECTRIC ASSOCIATION, INC.
By:	/s/ Lee D. Thibert
	Lee D. Thibert
	Chief Executive Officer
Date:	March 24, 2017

110

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 22, 2017, by the following persons on behalf of the registrant and in the capacities indicated:

/s/ Lee D. Thibert
Lee D. Thibert	Chief Executive Officer
	(Principal Executive Officer)
/s/ Sherri L. Highers
Sherri L. Highers	Chief Financial Officer
	(Principal Financial Officer)
	(Principal Accounting Officer)
/s/ Paul R. Risse
Paul R. Risse	Sr. Vice President, Production & Engineering
/s/ Brian J. Hickey
Brian J. Hickey	Sr. Vice President, System Operations
/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/ Bettina Chastain
Bettina Chastain	Director & Secretary of the Board

111

/s/ Harry T. Crawford, Jr.
Harry T. Crawford, Jr.	Director
/s/ Jim Henderson
Jim Henderson	Director
/s/ Stuart Parks
Stuart Parks	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 2015 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.

112

EX-31.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)

I, Lee D. Thibert, certify that:

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

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

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

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

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

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

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

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

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

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

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

Date: March 24, 2017	By:	/s/ Lee D. Thibert
		Lee D. Thibert
		Chief Executive Officer
		Principal Executive Officer

EX-31.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002)

I, SherriL.  Highers, certify that:

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

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

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

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

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

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

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

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

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing equivalent functions):

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

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

Date: March 24, 2017	By:	/s/ Sherri L. Highers
		Sherri L. Highers
		Chief Financial Officer
		Principal Financial Officer

EX-32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER

Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the annual report on Form 10-K of Chugach Electric Association, Inc. (the "Company") for the year ended December 31, 2016, as filed with the Securities and Exchange Commission (the "Report"), I, Lee D. Thibert, Chief Executive Officer and Principal Executive Officer of the Company, hereby certify as the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

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

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

Date: March 24, 2017	By:	/s/ Lee D. Thibert
		Lee D Thibert
		Chief Executive Officer
		Principal Executive Officer

EX-32.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER

Certification Pursuant to 18 U.S.C. Section 1350 (Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the annual report on Form 10-K of Chugach Electric Association, Inc. (the "Company") for the year ended December 31, 2016, as filed with the Securities and Exchange Commission (the "Report"), I, SherriL.  Highers, Chief Financial Officer and Principal Financial Officer of the Company, hereby certify as the date hereof, solely for purposes of Title 18, Chapter 63, Section 1350 of the United States Code, that to the best of my knowledge:

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

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

Date: March 24, 2017	By:	/s/ Sherri L. Highers
		Sherri L. Highers
		Chief Financial Officer
		Principal Financial Officer

XML

Document And Entity Information	12 Months Ended
	Dec. 31, 2016 USD ($) shares
Document And Entity Information [Abstract]
Entity Registrant Name	CHUGACH ELECTRIC ASSOCIATION INC
Entity Filer Category	Non-accelerated Filer
Entity Central Index Key	0000878004
Entity Voluntary Filers	Yes
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	No
Amendment Flag	false
Document Type	10-K
Document Fiscal Period Focus	FY
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2016
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding | shares	0
Entity Public Float | $	$ 0

XML

Consolidated Balance Sheets - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Utility plant:
Electric plant in service	$ 1,192,513,869	$ 1,128,474,292
Construction work in progress	18,455,940	15,601,374
Total utility plant	1,210,969,809	1,144,075,666
Less accumulated depreciation	(496,098,131)	(469,199,226)
Net utility plant	714,871,678	674,876,440
Other property and investments, at cost:
Nonutility property	76,889	76,889
Investments in associated organizations	9,349,311	9,635,519
Special funds	907,836	763,913
Restricted cash equivalents	810,559	1,705,760
Investments - other	3,061,434	0
Total other property and investments	14,206,029	12,182,081
Current assets:
Cash and cash equivalents	4,672,935	15,626,919
Special deposits	75,942	74,416
Restricted cash equivalents	899,723	1,143,467
Marketable securities	7,375,381	0
Accounts receivable, less provisions for doubtfule accounts of $484,352 in 2016 and $425,751 in 2015	33,000,919	28,232,930
Materials and supplies	27,889,167	27,611,184
Fuel stock	6,321,676	7,063,541
Prepayments	1,407,026	1,466,301
Other current assets	294,697	225,079
Total current assets	81,937,466	81,443,837
Other non-current assets:
Deferred charges, net	25,140,957	16,811,756
Total other non-current assets	25,140,957	16,811,756
Total assets	836,156,130	785,314,114
Equities and margins:
Memberships	1,691,014	1,661,744
Patronage capital	169,996,436	167,447,781
Other	13,828,075	12,527,856
Total equities and margins	185,515,525	181,637,381
Long-term obligations, excluding current installments:
Bonds payable	405,249,998	426,666,665
Notes payable	40,356,000	22,241,852
Less unamortized debt issuance costs	(2,715,745)	(2,680,897)
Total long-term obligations	442,890,253	446,227,620
Current liabilities:
Current installments of long-term obligations	24,836,667	24,115,980
Commercial paper	68,200,000	20,000,000
Accounts payable	9,618,630	9,701,088
Consumer deposits	5,207,585	5,000,684
Fuel cost over-recovery	3,824,722	5,135,745
Accrued interest	5,873,368	5,915,580
Salaries, wages and benefits	7,315,898	7,259,806
Fuel	6,284,338	4,942,310
Other current liabilities	3,234,586	8,076,903
Total current liabilities	134,395,794	90,148,096
Other non-current liabilities:
Deferred compensation	907,836	763,913
Other liabilities, non-current	655,277	1,555,329
Deferred liabilities	1,179,414	1,802,389
Patronage capital payable	12,008,499	11,108,071
Cost of removal obligation/asset retirement obligation	58,603,532	52,071,315
Total other non-current liabilities	73,354,558	67,301,017
Total liabilities, equities and margins	$ 836,156,130	$ 785,314,114

XML

Consolidated Balance Sheets (Parenthetical) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Consolidated Balance Sheets [Abstract]
Accounts receivable, provision for doubtful accounts	$ 484,352	$ 425,751

XML

Consolidated Statements Of Operations - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Consolidated Statements Of Operations [Abstract]
Operating revenues	$ 197,747,579	$ 216,421,152	$ 281,318,513
Operating expenses:
Fuel	54,778,582	66,534,877	126,038,350
Production	15,809,168	16,886,257	21,082,176
Purchased power	15,774,733	19,599,994	15,608,396
Transmission	5,590,737	6,287,558	6,138,658
Distribution	13,991,997	14,089,862	13,002,157
Consumer accounts	6,073,710	6,117,625	5,887,713
Administrative, general and other	22,888,048	23,623,299	25,036,248
Depreciation and amortization	36,233,414	35,652,086	40,179,181
Total operating expenses	171,140,389	188,791,558	252,972,879
Interest expense:
Long-term debt and other	21,856,095	22,194,290	23,264,041
Charged to construction	(454,798)	(379,845)	(463,335)
Interest expense, net	21,401,297	21,814,445	22,800,706
Net operating margins	5,205,893	5,815,149	5,544,928
Nonoperating margins:
Interest income	425,173	296,788	566,639
Allowance for funds used during construction	188,111	142,881	163,151
Capital credits, patronage dividends and other	(5,321)	248,034	240,827
Total nonoperating margins	607,963	687,703	970,617
Assignable margins	$ 5,813,856	$ 6,502,852	$ 6,515,545

XML

Consolidated Statements Of Changes In Equities And Margins - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Balance		$ 181,637,381		$ 176,925,299	$ 181,637,381	$ 176,925,299	$ 175,795,865
Assignable margins	$ 5,632,088	2,628,930	$ 3,411,797	6,046,730	5,813,856	6,502,852	6,515,545
Retirement/net transfer of capital credits					(3,265,201)	(3,190,124)	(5,130,381)
Unclaimed capital credit retirements					1,175,962	1,298,410	(350,776)
Memberships and donations received					153,527	100,944	95,046
Balance	185,515,525		181,637,381		185,515,525	181,637,381	176,925,299
Memberships [Member]
Balance		1,661,744		1,631,569	1,661,744	1,631,569	1,600,058
Assignable margins					0	0	0
Retirement/net transfer of capital credits					0	0	0
Unclaimed capital credit retirements					0	0	0
Memberships and donations received					29,270	30,175	31,511
Balance	1,691,014		1,661,744		1,691,014	1,661,744	1,631,569
Other Equities And Margins [Member]
Balance		12,527,856		11,158,677	12,527,856	11,158,677	11,445,918
Assignable margins					0	0	0
Retirement/net transfer of capital credits					0	0	0
Unclaimed capital credit retirements					1,175,962	1,298,410	(350,776)
Memberships and donations received					124,257	70,769	63,535
Balance	13,828,075		12,527,856		13,828,075	12,527,856	11,158,677
Patronage Capital [Member]
Balance		$ 167,447,781		$ 164,135,053	167,447,781	164,135,053	162,749,889
Assignable margins					5,813,856	6,502,852	6,515,545
Retirement/net transfer of capital credits					(3,265,201)	(3,190,124)	(5,130,381)
Unclaimed capital credit retirements					0	0	0
Memberships and donations received					0	0	0
Balance	$ 169,996,436		$ 167,447,781		$ 169,996,436	$ 167,447,781	$ 164,135,053

XML

Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities:
Assignable margins	$ 5,813,856	$ 6,502,852	$ 6,515,545
Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation and amortization	36,233,414	35,652,086	40,179,181
Amortization and depreciation cleared to operating expenses	4,988,068	4,390,385	5,777,628
Allowance for funds used during construction	(188,111)	(142,881)	(163,151)
Write off of inventory, deferred charges and projects	997,301	691,035	974,062
Other	248,482	(220,496)	56,250
(Increase) decrease in assets:
Accounts receivable, net	(4,926,631)	6,866,956	6,879,762
Materials and supplies	(850,493)	(1,070,896)	(1,197,127)
Fuel stock	741,865	2,588,532	3,377,775
Prepayments	59,275	712,422	(315,316)
Other assets	(71,144)	215,738	978,338
Deferred charges	(10,374,429)	(405,746)	(1,050,505)
Increase (decrease) in liabilities:
Accounts payable	750,538	(270,416)	(420,041)
Consumer deposits	206,901	86,424	62,702
Fuel cost over-recovery	(1,311,023)	3,673,688	(173,620)
Accrued interest	(42,212)	(276,028)	(321,252)
Salaries, wages and benefits	56,092	(287,510)	(385,047)
Fuel	1,342,028	(6,195,299)	(3,696,976)
Other current liabilities	(1,051,220)	(290,715)	1,653,424
Deferred liabilities	(128,221)	(123,695)	34,668
Net cash provided by operating activities	32,494,336	52,096,436	58,766,300
Cash flows from investing activities:
Return of capital from investment in associated organizations	319,233	352,420	351,162
Investment in restricted cash equivalents	(1,398)	(1,141)	(142)
Investment in marketable securitiesand investments-other	(10,580,000)	0	(217,817)
Investment in Beluga River Unit	(44,403,922)	0	0
Proceeds from restricted cash equivalents	1,140,343	0	0
Proceeds from the sale of marketable securities	0	0	10,522,620
Proceeds from capital grants	1,021,929	2,395,331	6,960,143
Extension and replacement of plant	(36,984,892)	(35,094,355)	(30,303,133)
Net cash used in investing activities	(89,488,707)	(32,347,745)	(12,687,167)
Cash flows from financing activities:
Payments for debt issue costs	(277,155)	0	0
Net increase (decrease) in short-term obligations	48,200,000	(1,000,000)	(9,000,000)
Proceeds from long-term obligations	45,600,000	0	0
Repayments of long-term obligations	(48,181,832)	(23,889,777)	(24,682,812)
Memberships and donations received	1,329,489	357,365	(255,730)
Retirement of patronage capital and estate payments	(4,378,853)	(182,352)	(4,114,541)
Net receipts on consumer advances for construction	3,748,738	4,228,030	3,991,749
Net cash provided by (used in) financing activities	46,040,387	(20,486,734)	(34,061,334)
Net change in cash and cash equivalents	(10,953,984)	(738,043)	12,017,799
Cash and cash equivalents at beginning of period	15,626,919	16,364,962	4,347,163
Cash and cash equivalents at end of period	4,672,935	15,626,919	16,364,962
Supplemental disclosure of non-cash investing and financing activities:
Cost of removal obligation	3,008,808	1,366,318	3,565,605
Asset retirement obligation assumed upon BRU acquisition	3,523,409	0	0
Extension and replacement of plant included in accounts payable	1,915,033	2,582,947	2,382,117
Patronage capital retired and included in other current liabilities	0	2,105,440	2,572,670
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized	$ 20,220,317	$ 21,891,308	$ 21,835,216

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Description Of Business

12 Months Ended

Dec. 31, 2016

Description Of Business [Abstract]

Description Of Business

(1)    Description of Business

Chugach Electric Association, Inc. (Chugach) is one of the largest electric utilities in Alaska. Chugach is engaged in the generation, transmission and distribution of electricity in the Anchorage and upper Kenai Peninsula areas. Chugach is on an interconnected regional electrical system referred to as the Alaska 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’s retail and wholesale members are the consumers of the electricity sold. Chugach supplies much of the power requirements to the City of Seward (Seward), as a wholesale customer. Chugach also served Matanuska Electric Association, Inc. (MEA) through their contract expiration onApril 30, 2015.  Through March 31, 2015, we sold economy (non-firm) energy to Golden Valley Electric Association, Inc. (GVEA), which used that energy to serve its own load. Periodically, Chugach sells available generation, in excess of its own needs, to MEA, GVEA and Anchorage Municipal Light & Power (ML&P).

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 authority of the Regulatory Commission of Alaska (RCA).

The consolidated financial statements include the activity of Chugach and the activity of the Beluga River Unit (BRU). Chugach accounts for its share of BRU activity using proportional consolidation (see Note 15 – “Beluga River Unit”). Intercompany activity has been eliminated for presentation of the consolidated financial statements.

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Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Significant Accounting Policies [Abstract]

Significant Accounting Policies

(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 the allowance for doubtful accounts, workers’ compensation liability, deferred charges and liabilities, unbilled revenue, estimated useful life of utility plant, cost of removal and asset retirement obligation (ARO), purchase price allocation for BRU, and remaining proved BRU reserves. 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 (2n) – “Deferred Charges and Liabilities.”

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, 2016 are as follows:

Annual Depreciation Rate Ranges

Steam production plant	3.15%	-	3.84%
Hydroelectric production plant	1.06%	-	3.00%
Other production plant	3.15%		8.85%
Transmission plant	1.58%	-	7.86%
Distribution plant	2.16%	-	9.63%
General plant	1.57%	-	20.00%
Other	2.75%	-	2.75%

On November 1, 2010, the RCA approved revised depreciation rates effective November 1, 2010 in Docket U-09-097. Chugach’s depreciation rates include a provision for cost of removal. 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 Southcentral Power Project (SPP) depreciation rates effective February 1, 2013, the date the SPP plant was placed in service.

Chugach records Depreciation, Depletion and Amortization (DD&A) expense on the BRU assets based on units of production using the following formula: ten percent of the total production from the BRU as provided by the operator divided by ten percent of the estimated remaining proved reserves (in thousand cubic feet (Mcf)) in the field multiplied by Chugach’s total assets in the BRU.

d. Full Cost Method

Pursuant to Accounting Standards Codification (ASC) 932-360-25, “Extractive Activities-Oil and Gas – Property, Plant and Equipment – Recognition,” Chugach has elected the Full Cost method, rather than the Successful Efforts method, to account for exploration and development costs of gas reserves. This is the first time Chugach has invested in oil or gas activities, so there is no prior policy of using the Successful Efforts method.

e. Asset Retirement Obligation (ARO)

Chugach calculated and recorded an Asset Retirement Obligation associated with the BRU. Chugach uses its BRU financing rate as its credit adjusted risk free rate and the expected cash flow approach to calculate the fair value of the ARO liability. The ARO asset is depreciated using the DD&A formula previously discussed. The ARO liability is accreted using the interest method of allocation.

f. 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 one percent. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment. No impairment was recorded during 2016, 2015 and 2014.

g. Investments – Other

Investments –other consists of certificates of deposit with an original maturity of 18 months.

h. 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 $5,897,767and $6,218,015 during the years ended December 31, 2016 and 2015, respectively.

Restricted cash equivalents include funds on deposit for future workers’ compensation claims. At December 31, 2016 and 2015, restricted cash equivalents included $0.8 million and $1.7 million, respectively, of funds on deposit for future workers’ compensation claims.

i. Marketable Securities

In September 2016, Chugach resumed its mutual fund investment portfolio. The investments are classified as trading securities, reported at fair value with gains and losses in earnings, and include bond funds.

	Twelve months ended December 31, 2016
Net gains and losses recognized during the period on trading securities	$	(143,185)
Less: Net gains and losses recognized during the period on trading securities sold during the period		0
Unrealized gains and losses recognized during the reporting period on trading securities still held at the reporting date	$	(143,185)

j. 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 Anchorage Municipal Light & Power (ML&P) for their proportionate share of current SPP costs, which amounted to $1.4 million and $1.1 million in 2016 and 2015, respectively. In addition, accounts receivable includes invoiced amounts for grants to support investigating means of mitigating the impact of renewable generation variability on the grid as well as the construction of facilities to divert water and safely transmit electricity, which amounted to $0.0 million and $0.2 million in 2016 and 2015, respectively. At December 31, 2016, accounts receivable also included $0.7 million from BRU operations primarily associated with gas sales to ENSTAR.

k. Materials and Supplies

Materials and supplies are stated at average cost.

l. 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, 2016 and 2015 amounted to $6.3 million and $7.1 million, respectively.

m. Fuel and Purchased Power Cost Recovery

Expenses associated with electric services include fuel purchased from others and produced from Chugach’s interest in the BRU, both of which are used to generate electricity, as well as 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 purchased power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods.

n. Deferred Charges and Liabilities

Included in deferred charges and liabilities on Chugach’s financial statements are regulatory assets and liabilities recorded in accordance with FASB ASC 980.  See Note 8 – Deferred Charges and Liabilities. Continued accounting under FASB ASC 980 requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for ratemaking purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria.

Chugach’s 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 liabilities include 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.

On December 29, 2016, Chugach made a prepayment of $7.9 million to the National Rural Electric Cooperative Association (NRECA) Retirement and Security (RS) Plan, which is included in deferred charges. Chugach recorded the long term prepayment in deferred charges and is amortizing the deferred charge to administrative, general and other expense, over 11 years, which represents the difference between the normal retirement age of 62 and the average age of Chugach’s employees in the RS Plan.

o. 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.

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, 2016 and 2015, totaled $3.3 million and $3.1 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances totaled $1.9 million for the years ended December 31, 2016 and 2015.

q. 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.

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

Marketable securities – the carrying amount approximates fair value as changes in the market value are recorded monthly and gains or losses are reported in earnings (see note 2i and note 4).

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

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

The fair value of accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature.

r. Operating Revenues

Revenues are recognized upon delivery of electricity. Operating revenues are based on billing rates authorized by the RCA, which are applied to customers’ usage of electricity. Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results. Chugach calculates unbilled revenue at the end of each month to ensure the recognition of a calendar year’s revenue. Chugach accrued $10,940,274 and $10,531,377 of unbilled retail revenue at December 31, 2016 and 2015, respectively, which is included in accounts receivable on the balance sheet. 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.

s. 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 Chugach capitalized such funds at the weighted average rate of 4.3% during 2016, 2015 and 2014.

t. 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.

u. 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, 2016, 2015 and 2014 was in compliance with that provision. In addition, as described in Note (16) – “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 fifty percent likelihood of being sustained upon examination by the taxing authorities. Chugach’s management reviewed Chugach’s tax positions and determined there were no outstanding or retroactive tax positions that were not highly certain of being sustained upon examination by the taxing authorities.

Management has concluded that there are no significant uncertain tax positions requiring recognition in its financial statements for all periods presented. Chugach’s evaluation was performed for the tax periods ended December 31, 2014 through December 31, 2016 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2016.

v. Grants

Chugach has received federal and state grants to offset storm related expenditures and to support investigating means of mitigating the impact of renewable generation variability on the grid as well as 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, both of which totaled $0.6 million and $1.6 million in 2016 and 2015, respectively.

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Accounting Pronouncements

12 Months Ended

Dec. 31, 2016

Accounting Pronouncements [Abstract]

Accounting Pronouncements

(3)Accounting Pronouncements

Issued and adopted:

ASC Update 2015-03 “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs”

In April of 2015, the FASB issued ASC Update 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASC Update 2015-03 revised the presentation guidance for debt issuance costs related to a recognized debt liability. The effect of this update was to present the debt issuance costs as a direct deduction to the liability on the balance sheet and was adopted by retrospective application. This update did not change the recognition and measurement guidance for debt issuance costs. This update was effective for fiscal years beginning after December 15, 2015, and interim periods beginning after December 15, 2016, with early adoption permitted. Chugach began application of ASC 2015-03 with the fiscal year beginning January 1, 2016. Adoption did not have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2015-15 “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements”

In September of 2015, the FASB issued ASC Update 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” ASC Update 2015-15 amended guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements for SEC reporting. This update was effective for fiscal years beginning after December 15, 2015, and interim periods beginning after December 15, 2016, with early adoption permitted. Chugach began application of ASC 2015-15 with the fiscal year beginning January 1, 2016. Adoption did not have a material effect on its results of operations, financial position, and cash flows.

Adoption of this guidance was applied retrospectively and reduced deferred charges and long-term debt by the unamortized debt issuance costs of $2.7 million at December 31, 2016, and December 31, 2015.

Issued, not yet adopted:

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

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 was effective for fiscal years beginning after December 15, 2016, for which early adoption was prohibited. However, in August of 2015, the FASB issued ASC Update 2014-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” deferring the effective date of ASC Update 2014-09 to fiscal years beginning after December 15, 2017, and permitting early adoption of this update, but only for annual reporting periods beginning after December 15, 2016, and interim reporting periods within that reporting period. The standard permits the use of either the retrospective or cumulative effect transition method. While Chugach has not yet selected a transition method, we currently expect to use the cumulative effect method. Our transition method, and the expected materiality of the impact of adopting this standard on our operations, financial position, and cash flows, will be determined after we further evaluate the impact of this update.

We have evaluated our energy sales contracts, including retail, wholesale, and economy energy, and do not believe there will be a material impact to our recognition of revenue from energy sales. Energy sales are billed monthly per regulator approved tariffs based on the energy consumed by the customer. Total revenue derived from energy sales during 2016 was approximately 99% of our total operating revenue.

The American Institute of Certified Public Accountants (AICPA) Power and Utilities Revenue Recognition Task Force is currently assessing the impact of this update on contributions in aid of construction (CIAC). CIAC represents the funds collected from customers and third parties and recorded as a reduction to the total cost of property, plant and equipment, per industry standard practice. If it is determined that CIAC is within the scope of this update, it could have a material impact on the amount of revenue we recognize.

ASC Update 2016-01  “Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities”

In January of 2016, the FASB issued ASC Update 2016-01, “Financial Instruments – Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” ASC Update 2016-01 amends guidance related to certain aspects of the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2018, and interim periods beginning after December 15, 2019, with early adoption not permitted with certain exceptions. Chugach will begin application of ASC 2016-01 with the annual report for the year ended December 31, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2016-02  “Leases (Topic 842): Section A – Leases: Amendments to the FASB Accounting Standards Codification; Section B – Conforming Amendments Related to Leases: Amendments to the FASB Accounting Standards Codification; Section C – Background Information and Basis for Conclusions”

In February of 2016, the FASB issued ASC Update 2016-02, “Leases (Topic 842): Section A – Leases: Amendments to the FASB Accounting Standards Codification; Section B – Conforming Amendments Related to Leases: Amendments to the FASB Accounting Standards Codification; Section C – Background Information and Basis for Conclusions.” ASC Update 2016-02 amends guidance related to the recognition, measurement, presentation and disclosure of leases for lessors and lessees. This update is effective for fiscal years beginning after December 15, 2018,  including the interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2016-02on January 1, 2019.  Chugach expects this update to increase the recorded amounts of assets and liabilities and we are evaluating the significance of the increase. We are also evaluating the impact of this update to our results of operations, financial position, and cash flows.

ASC Update 2016-11 “Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Update 2014-09 and 2014-06 Pursuant to Staff Announcements at the March 3, 2016, EITF Meeting (SEC Update)”

In May 2016, the FASB issued ASC Update 2016-11, “Revenue Recognition (Topic 605) and Derivatives and Hedging (Topic 815): Rescission of SEC Guidance Because of Accounting Standards Update 2014-09 and 2014-06 Pursuant to Staff Announcements at the March 3, 2016, EITF Meeting (SEC Update).” ASC 2016-11 rescinds and supersedes SEC guidance previously governing revenue and expense recognition for freight services in process, accounting for shipping and handling fees and costs, consideration given by a vendor to a customer, and gas-balancing arrangements. This update affects the guidance in ASC Update 2014-09 and 2014-06 and follows the same effective date and transition requirements. While Chugach has not yet selected a transition method, we currently expect to use the cumulative effect method. Our transition method, and the expected materiality of the impact of adopting this standard on our operations, financial position, and cash flows, will be determined after we further evaluate the impact of this update.

ASC Update 2016-13 “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments”

In June 2016, the FASB issued ASC Update 2016-13, “Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” ASC Update 2016-13 revised the criteria for the measurement, recognition, and reporting of credit losses on financial instruments to be recognized when expected. This update is effective for fiscal years beginning after December 15, 2019, including the interim periods within those years, with early adoption permitted for fiscal years beginning after December 15, 2018, including interim periods within those years. Chugach will begin application of ASC 2016-13 on January 1, 2020. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2016-15 “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force)”

In August 2016, the FASB issued ASC Update 2016-15, “Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). ASC Update 2016-15 clarifies how certain cash payments and cash proceeds should be classified on the statement of cash flows to limit the diversity in practice. This update is effective fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2016-15 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

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Fair Value Of Assets And Liabilities

12 Months Ended

Dec. 31, 2016

Fair Value Of Assets And Liabilities [Abstract]

Fair Value Of Assets And Liabilities

(4)    Fair Value of Assets and Liabilities

Fair Value Hierarchy

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

Level 1 – Valuation is based upon quoted prices for identical instruments traded in active exchange markets, such as the New York Stock Exchange. Level 1 also includes 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’s marketable securities classified as trading securities are outlined in the table below. Chugach had no other assets or liabilities measured at fair value on a recurring basis at December 31, 2016. At December 31, 2015, Chugach had no Level 1 or Level 2 assets or liabilities measured at fair value on a recurring basis.

	December 31, 2016		Level 1
Bond funds/Certificates of Deposit	$	10,436,815	$	10,436,815

Fair Value of Financial Instruments

Fair value estimates are dependent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions. The fair value of cash and cash equivalents, accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature. The fair value of investments – other approximate their carrying value due to the recency of their acquisition.

The estimated fair values (in thousands) of long-term obligations included in the financial statements at December 31, 2016, are as follows:

	Measurement	Carrying Value		Fair Value
2011 Series A Bonds	Level 2	$	221,667	$	231,057
2012 Series A Bonds	Level 2		205,000		209,242
2016 CoBank Note	Level 2		43,776		40,921
Long-term obligations (including current installments)		$	470,443	$	481,220

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Regulatory Matters

12 Months Ended

Dec. 31, 2016

Regulatory Matters [Abstract]

Regulatory Matters

(5)    Regulatory Matters

Amended Eklutna Generation Station 2015 Dispatch Services Agreement

On February 13, 2015, Chugach submitted the Amended Eklutna Generation Station 2015 Dispatch Services Agreement (Dispatch Services Agreement) to the RCA for dispatch services to be provided by Chugach to MEA for a one-year period. Under the Dispatch Services 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.

On March 23, 2015, the RCA approved the Dispatch Agreement, conditioned on the requirements that: 1) MEA and Chugach notify the RCA at least one month prior to forming separate Load Balancing Authorities and include in any such notification details on the tie points and any written agreements contemplated by the utilities; and, 2) Chugach file an update to its tariff to reflect any extension of the Dispatch Services Agreement one week from the receipt of such a request from MEA. The Dispatch Services Agreement was in effect through March 31, 2016.

In December of 2015, MEA notified Chugach that it would not be extending the Dispatch Services Agreement for the dispatch of electric service. Subsequently, Chugach and MEA entered into an agreement entitled, “Gas Dispatch Agreement” in which Chugach provides gas scheduling and dispatch services to MEA. The term of the agreement is April 1, 2016, through March 31, 2017. On April 18, 2016, Chugach requested RCA approval of the special contract. The RCA issued a letter order on June 8, 2016, approving the filing. This agreement was extended through March 31, 2018, in a letter agreement dated July 29, 2016, with a provision to extend the agreement through March 31, 2019, to be exercised on or before August 1, 2017.

June 2014 Test Year General Rate Case

Chugach’s June 2014 test year rate case was submitted to the RCA on February 13, 2015. Chugach requested a system base rate increase of approximately $21.3 million, or 20% on total base rate revenues for rates effective in April 2015. The filing also included 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 was the reduction in fixed-cost contributions resulting from the expiration of the Interim Power Sales Agreement between Chugach and MEA. In addition, Chugach submitted proposed adjustments to its fuel and purchased power rates under a separate tariff advice letter to become effective at the same time. This 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. Collectively, the effective increase to retail customer bills was approximately between two and five percent.

The RCA issued Order U-15-081(1) on April 30, 2015, suspending the filing and granting Chugach’s request for interim and refundable rate increases effective May 1, 2015. A scheduling conference was held on May 27, 2015. On June 4, 2015, the RCA issued Order U-15-081(2), granting approval for intervention by HEA, MEA and GVEA. The RCA indicated that a final order in the case will be issued by May 8, 2016. Intervenor responsive testimony was filed by the Attorney General (AG) and MEA on October 28, 2015. The AG’s testimony focused on revenue requirement matters and MEA’s testimony focused on transmission cost allocation issues. Chugach’s responsive testimony was filed on December 15, 2015.

In January of 2016, Chugach and the Attorney General (AG) for the State of Alaska entered into settlement discussions to resolve revenue requirement matters in the case, which resulted in settlement of all outstanding matters related to the determination of Chugach’s system revenue requirement for both the interim and permanent rate periods. As a result, Chugach agreed to reduce its revenue requirement by 0.5% (approximately $0.6 million). In addition, the stipulation provides for a permanent increase in Chugach’s system Times Interest Earned Ratio (TIER) from 1.30 to 1.35, which represents an approximate margin increase of $1.0 million per year.

The stipulation was filed with the RCA on January 21, 2016. On May 2, 2016, the RCA issued Order U-15-081(8) accepting the stipulation between Chugach and the AG. On May 20, 2016, Chugach submitted updated revenue requirement, cost of service and tariffs reflecting the results of the stipulation, with proposed final rates effective July 5, 2016. On June 17, 2016, the RCA issued Order U-15-081(10) approving final permanent rates effective for Chugach retail customers and the City of Seward (Seward). Refunds totaling $0.75 million were issued to Chugach retail customers in August 2016. The refund applied to purchases from May 2015 through July 2016. Chugach issued a refund to Seward totaling approximately $28,000 on July 8, 2016.

On June 27, 2016, the RCA issued Order U-15-081(11) resolving the outstanding issues related to transmission and ancillary services. The RCA ruled in Chugach’s favor, affirming continued use of a postage stamp rate methodology for wheeling transactions on the Chugach system and denied MEA’s request for a separate rate for wheeling transactions based on MEA’s claim that it only used a small portion of Chugach’s transmission system. The order was consistent with previous orders on transmission and ancillary services that were issued by the RCA in Chugach’s 2012 and 2013 General Rate Case filings. On July 15, 2016, Chugach submitted updated tariff sheets and supporting exhibits for the calculation of transmission and ancillary service rates. On August 23, 2016, the RCA approved final rates contained in Chugach’s July 15, 2016, compliance filing.

On September 15, 2016, Chugach notified the RCA that it completed the issuance of refunds resulting from settlement of the rate case. A final order closing the docket was issued on October 6, 2016.

Simplified Rate Filing

On June 30, 2016, the Chugach Board of Directors voted to re-enter the SRF process for adjustments to base demand and energy rates for Chugach retail customers and wholesale customer, Seward. SRF is an expedited base rate adjustment process available to electric cooperatives in the State of Alaska. On July 1, 2016, Chugach requested approval to implement the SRF process for energy and demand rate changes, and requested approval for a 4.2% system demand and energy rate increase, or approximately $4.8 million on an annual basis. On a total retail customer bill basis, which includes fuel and purchased power costs, the impact was approximately 2.5%. Chugach requested the proposed rate increase become effective August 15, 2016. Chugach plans to adjust rates through the SRF process on a quarterly basis going forward.

On August 12, 2016, the RCA issued a letter order approving Chugach’s entry into the SRF process for quarterly adjustments to the demand and energy rates of Chugach retail customers and Seward. The RCA also approved Chugach’s request to increase demand and energy rates by 4.2%, effective August 15, 2016.

On August 29, 2016, Chugach submitted its June 2016 test year SRF to the RCA with no changes to the demand and energy rates of Chugach retail and Seward. In the filing, Chugach requested approval to adopt the SRF process for quarterly rate adjustments for non-firm transmission wheeling and ancillary services, and approval to reduce these rates between 9.5% and 14.4% based on the current SRF. The RCA issued an order on October 13, 2016, denying Chugach’s request on the basis that the underlying premise of the SRF does not apply to rates for third-party use of Chugach’s transmission system. Revenues from these transactions do not impact Chugach margin levels, but instead are used to reduce fuel and purchased power costs that are recovered by Chugach retail and Seward. As a result, rate changes to third party transmission and ancillary services will be prospectively made through general rate case filings. This has no impact on Chugach’s continued use of SRF for quarterly demand and energy rate adjustments to Chugach retail customers and Seward.

Chugach submitted its June 2016 and September 2016 test year SRFs with the RCA on August 29, 2016 and December 1, 2016, respectively, as informational filings with no changes to the demand and energy rates of Chugach retail and Seward.

Operation and Regulation of the Alaska Railbelt Electric and Transmission System

The 2014 Alaska Legislature directed the RCA to provide a recommendation on whether creating an independent system operator or similar structure in the Railbelt area is the best option for effective and efficient electrical transmission. 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 June 30, 2015, the RCA issued its report which recommended an independent transmission company, certificated and regulated as a public utility, be created to operate the transmission system reliably and transparently and to plan and execute major maintenance, transmission system upgrades, and new transmission projects necessary for the reliable delivery of electric power to Railbelt customers. The RCA opened Docket I-15-001 to gather information on power pooling and/or centralized transmission system planning and operation among the Railbelt electric utilities, including economic dispatch of the Railbelt’s electrical generation units.Initial progress reports were filed with the RCA on September 30, 2015. With the support of the RCA, Chugach and several other Railbelt utilities are evaluating possible transmission business model opportunities and associated economic dispatch models that Chugach believes may lead to more optimal Railbelt-wide system operations.

On February 1, 2016, Chugach and the Municipality of Anchorage d/b/a Municipal Light and Power (ML&P) filed a joint report regarding the development of a power pooling and joint dispatch arrangement between the utilities. The filing summarized several of the projected qualitative and quantitative benefits of such an arrangement. Chugach and ML&P filed subsequent joint reports regarding their progress toward joint dispatch and power pooling arrangements on May 2, 2016, and August 10, 2016. On October 31, 2016, Chugach, ML&P, and MEA filed a joint report informing the RCA that they were negotiating a power pooling and joint dispatch agreement.

On January 27, 2017, Chugach, ML&P, and MEA entered into an Amended and Restated Power Pooling and Joint Dispatch Agreement (Agreement) which provides for economic dispatch resulting from coordinated scheduling of generation and transmission assets, including scheduling, dispatch, and settlement transactions at the bulk power level of electric services. The Agreement was submitted to the RCA as an informational filing on January 30, 2017 under Docket I-15-001. The Agreement provides a contractual framework for coordinated scheduling, dispatch, and settlement transactions for the purchase, sale, or exchange of energy, capacity, reserves, and transmission ancillary services on an efficient and economic basis among the signatories to the Agreement.

The Agreement provides for a one-year development period to develop and agree upon specific, detailed generation and transmission dispatch procedures, fuel supply dispatch procedures, and a settlement process. Upon finalization of dispatch procedures and the settlement process in 2018, Chugach, ML&P and MEA will submit the Agreement to the RCA for approval. The total cost reductions resulting from the pool are estimated to be up to $16 million per year after the development period for all participants combined.

Cook Inlet Natural Gas Alaska:  Found Gas

On January 30, 2015, CINGSA submitted a filing to the RCA providing notice that it had found 14.5 Bcf of gas as a result of directional drilling in the storage facility and now proposes to establish guidelines for commercial sales of at least 2 Bcf of this gas. Chugach submitted comments to the RCA regarding CINGSA’s proposed treatment of found gas. Chugach does not believe CINGSA’s proposal to retain revenues for the sale of found gas should be permitted in recognition of the risk-sharing agreements made by CINGSA and its storage customers that resulted in the development of the CINGSA storage facility.

The RCA issued an order in March of 2015 suspending the filing for further investigation. CINGSA filed direct testimony in the case on April 13, 2015. Chugach and other interveners in the case submitted responsive testimony on June 5, 2015. CINGSA submitted its reply testimony on June 29, 2015. The evidentiary hearing was held in September of 2015.

The RCA issued a final order in the case on December 4, 2015, ruling significantly in favor of the interveners in the case. The RCA granted approval for CINGSA to sell 2 Bcf with 87% of the proceeds allocated to CINGSA’s Firm Storage Service (FSS) customers and 13 percent to CINGSA. The RCA also required CINGSA to file a reservoir engineering study by June 30, 2016, and required CINGSA to file notice of all gas sales within 30 days of any sales, including the transaction price, purchaser, quantities, and the terms and conditions of the sale. The RCA also required that all proceeds to the FSS customers be treated as a reduction in fuel costs that are paid by CINGSA’s customers.

On January 4, 2016, CINGSA filed an appeal in Superior Court to Order U-15-016(14), stating the RCA violated CINGSA’s right to due process of law, erred, and/or acted unreasonably, unfairly, arbitrarily, capriciously, or contrary to applicable law. CINGSA believes additional proceeds resulting from the sale of found native gas should remain with CINGSA. Chugach filed an entry of appearance in the case on January 14, 2016. CINGSA filed its brief on June 6, 2016. Chugach filed its reply brief on October 31, 2016. Oral argument was held on March 6, 2017.

Beluga River Unit

In July of 2015, ConocoPhillips Alaska, Inc. (CPAI) announced the marketing for sale of its North Cook Inlet Unit; its interest in the Beluga River Unit (BRU); and its interest in 5,700 acres of exploration prospects in the Cook Inlet region. In October of 2015, Chugach submitted a joint bid with ML&P for acquisition of CPAI’s one-third working interest in the BRU.

Chugach entered into an agreement entitled, “Purchase and Sale Agreement between ConocoPhillips Alaska, Inc. and Municipality of Anchorage d/b/a Municipal Light & Power and Chugach Electric Association, Inc.” (Purchase and Sale Agreement) on February 4, 2016. The Purchase and Sale Agreement transfers CPAI’s interest in the BRU to Chugach and ML&P. The acquisition and attendant recovery of costs in electric rates was subject to RCA approval.

On March 11, 2016, Chugach and ML&P submitted a joint request to the RCA for approval of the acquisition of CPAI’s interest in the BRU and the attendant recovery of the acquisition costs in electric rates. Chugach and ML&P requested expedited consideration, asking the RCA to issue a bench ruling by April 21, 2016. The request for expedited consideration was made to provide additional certainty regarding Chugach’s eligibility for a State of Alaska production tax credit.

The RCA opened docket U-15-081 and established an expedited procedural schedule for the case. The RCA held a hearing from April 18 through April 20, 2016, and issued a bench ruling on April 20, 2016, approving the joint request for approval of the Purchase and Sale Agreement. A written order affirming the bench ruling was issued on April 21, 2016.

Separate filings detailing the specific rate recovery process were filed in the second quarter of 2016. The RCA approved the initial gas transfer price of $5.88 per Mcf. Under the recovery structure proposed by Chugach, costs associated with the BRU, including acquisition and on-going operations, maintenance and capital investment, will be recovered on a dollar-for-dollar basis through Chugach’s quarterly fuel adjustment process. Chugach recovers its fuel and purchased power costs as a direct pass-through from its retail and wholesale customers with minimal lag between cost incurrence and recovery.

On June 29, 2016, Chugach filed a petition with the RCA for approval to create a regulatory asset for the deferral of expenses (financial/economic, engineering and legal services) associated with Chugach’s acquisition of the BRU, which was $1.5 million at December 31, 2016, and is included in deferred charges on Chugach’s balance sheet. See Note 8 – Deferred Charges and Liabilities.  Chugach also requested approval to recover the deferred costs in the gas transfer price.

On September 14, 2016, the RCA issued an order combining the BRU cost recovery process and the request to create a regulatory asset into a single docket. The RCA established a procedural schedule and indicated that a final order in the case would be issued by November 17, 2017.

Depreciation Study Update

In compliance with a previous order from the RCA (U-12-009(8)), Chugach submitted a 2015 Depreciation Study Update to the RCA, requesting approval of the depreciation rates resulting from the study for use in Chugach’s financial record keeping and for establishing electric rates. If approved, adoption of the updated depreciation rates would result in a $5.9 million reduction in annual depreciation expense. On a demand and energy rate basis, the impact is a 4.7% reduction to retail customers and a 4.6% reduction to Seward. The reductions on a total customer bill basis, which includes fuel and purchased power costs, are 3.2% and 1.9%, respectively. Chugach requested that the updated depreciation rates be implemented on July 1, 2017, for both accounting and ratemaking purposes.

On October 11, 2016, the RCA issued Order U-16-081(1) to address the depreciation study update. The RCA indicated that a final order in the proceeding would be issued by March 29, 2017.

Beluga Parts Filing

On November 18, 2016, Chugach submitted a petition to the RCA for approval to create a regulatory asset that would allow Chugach to amortize and recover in rates the value of certain plant needed to support power production equipment located at Beluga Power Plant.

Specifically, Chugach requested RCA approval to recover approximately $11.4 million in equipment that supports Beluga generation units. Chugach requested that it be permitted to amortize the value of this plant over a period of 30 months for plant associated with Units 1 and 2 (approximately $0.3 million), and 108 months for all other parts (approximately $11.1 million). The amortization periods are consistent with the proposed depreciation rates for the Beluga units contained in Chugach’s depreciation study that was submitted to the RCA on September 30, 2016.

Furie Agreement

On March 16, 2017, Chugach submitted a request to the RCA for approval of the agreement entitled, “Firm and Interruptible Gas Sale and Purchase Agreement between Furie Operating Alaska, LLC and Chugach Electric Association, Inc.” (Furie Agreement) dated March 3, 2017. As part of the filing, Chugach also requested RCA approval to recover both firm and interruptible purchases under the agreement and all attendant transportation and storage costs through its quarterly fuel and purchased power cost adjustment process.

The Furie Agreement provides Chugach with both firm and non-firm gas supplies over a 16-year period, with firm purchases beginning on April 1, 2023, and ending on March 31, 2033, and interruptible gas purchases available to Chugach immediately upon RCA approval and ending on March 31, 2033. With respect to firm purchases beginning on April 1, 2023, and ending on March 31, 2033, the Furie Agreement provides an Annual Gas Commitment by Furie to sell and Chugach to purchase approximately 1.8 Bcf of gas each year, which represents approximately 20% to 25% of Chugach’s projected gas requirements during this period. The Furie Agreement also provides Chugach with additional purchase options, with on a firm and interruptible basis. The initial price for firm gas is $7.16 per Mcf beginning April 1, 2023 and escalates annually, rising to $7.98 per Mcf on April 1, 2032, the last year of the contract.

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Utility Plant

12 Months Ended

Dec. 31, 2016

Utility Plant [Abstract]

Utility Plant

(6)Utility Plant

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

Electric plant in service:	2016		2015
Steam production plant	$	101,116,277	$	100,938,247
Hydroelectric production plant		33,659,129		20,591,678
Other production plant		287,404,484		284,035,865
Transmission plant		282,040,969		277,490,606
Distribution plant		294,641,485		290,680,919
General plant		54,982,432		51,841,582
Unclassified electric plant in service1		83,457,981		95,611,615
Intangible plant1		5,455,371		5,455,371
Beluga River Natural Gas Field (BRU Asset & ARO)		47,927,331		0
Other1		1,828,409		1,828,409
Total electric plant in service		1,192,513,869		1,128,474,292
Construction work in progress		18,455,940		15,601,374
Total electric plant in service and construction work in progress	$	1,210,969,809	$	1,144,075,666

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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Investments In Associated Organizations

12 Months Ended

Dec. 31, 2016

Investments In Associated Organizations [Abstract]

Investments In Associated Organizations

(7)    Investments in Associated Organizations

Investments in associated organizations include the following at December 31:

	2016		2015
NRUCFC	$	6,095,980	$	6,095,980
CoBank		3,188,490		3,475,664
NRUCFC Capital Term Certificates and other		64,841		63,875
Total investments in associated organizations	$	9,349,311	$	9,635,519

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

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Deferred Charges And Liabilities

12 Months Ended

Dec. 31, 2016

Deferred Charges And Liabilities [Abstract]

Deferred Charges And Liabilities

(8)    Deferred Charges and Liabilities

Deferred Charges

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

	2016		2015
Regulatory assets:
Debt issuance and reacquisition costs	$	492,850	$	247,481
Refurbishment of transmission equipment		104,939		114,198
Feasibility studies		1,387,285		551,122
Beluga gas compression		0		508,866
Cooper Lake relicensing / projects		5,280,006		5,410,109
Fuel supply		2,005,052		939,768
Storm damage		647,381		841,595
Other regulatory deferred charges		849,933		1,056,909
Bond interest - market risk management		5,365,190		5,871,286
Environmental matters		1,024,171		1,069,522
Total regulatory assets		17,156,807		16,610,856
Other deferred charges:
NRECA pension plan prepayment		7,925,050		0
Post retirement benefit obligation		59,100		200,900
Total other deferred charges		7,984,150		200,900
Total deferred charges	$	25,140,957	$	16,811,756

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

	2016		2015
Regulatory assets:
Multi-stage Energy Storage	$	1,117,860	$	124,569
Regulatory studies and other		46,721		360,879
Total regulatory assets		1,164,581		485,448
Other deferred charges:
NRECA pension plan prepayment		7,925,050		0
Post retirement benefit obligation		59,100		200,900
Total other deferred charges		7,984,150		200,900
Total deferred charges	$	9,148,731	$	686,348

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 Liabilities

Deferred liabilities, at December 31 consisted of the following:

	2016		2015
Refundable consumer advances for construction	$	328,360	$	823,115
Estimated initial installation costs for meters		118,854		105,274
Post retirement benefit obligation		732,200		874,000
Total deferred liabilities	$	1,179,414	$	1,802,389

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Patronage Capital

12 Months Ended

Dec. 31, 2016

Patronage Capital [Abstract]

Patronage Capital

(9)    Patronage Capital

Chugach has a Board-approved capital credit retirement policy, which is contained in Chugach’s Financial Forecast. This establishes, in general, a plan to return the capital credits of wholesale and retail customers based on the members’ proportionate contribution to Chugach’s assignable margins. At December 31, 2016, Chugach had$169,996,436 of patronage capital (net of capital credits retired in 2016), which included $164,182,580of patronage capital that had been assigned and $5,813,856 of patronage capital to be assigned to its members. At December 31, 2015, Chugach had $167,447,781of patronage capital (net of capital credits retired in 2015), which included $160,944,929of patronage capital that had been assigned and $6,502,852 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. 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, 2016 and 2015, 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 $4.1 million and $3.2 million at December 31, 2016 and 2015, respectively.

The Second Amended and Restated Indenture of Trust (Indenture) and the CoBank Second 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% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins. Capital credits retired, net of HEA’s allocations, were $3,265,201,  $3,190,124, and $5,130,381 for the years ended December 31, 2016, 2015, and 2014, respectively. With the exception of MEA’s and HEA’s patronage capital payable, the outstanding liability for capital credits authorized but not paid at December 31, 2016,  2015, and 2014 was $2,014,080,  $2,105,440 and$1,042,064, respectively.

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Other Equities

12 Months Ended

Dec. 31, 2016

Other Equities [Abstract]

Other Equities

(10)  Other Equities

A summary of other equities at December 31 follows:

	2016		2015
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		2,001,450		1,877,193
Unclaimed capital credit retirement1		11,803,000		10,627,038
Total other equities	$	13,828,075	$	12,527,856

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

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Debt

12 Months Ended

Dec. 31, 2016

Debt [Abstract]

Debt

(11)  Debt

Long-term obligations at December 31 are as follows:	2016		2015
2011 CoBank Note, 2.78% variable rate at redemption, with interest payable monthly and principal due annually beginning in 2003	$	0	$	24,941,165
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		67,500,000		72,000,000
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		154,166,665		160,333,332
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		60,000,000		63,750,000
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		95,000,000		102,000,000
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
2016 CoBank Note, 2.58% fixed rate note maturing in 2031, with interest and principal due quarterly beginning in 2016		43,776,000		0
Total long-term obligations	$	470,442,665	$	473,024,497
Less current installments		24,836,667		24,115,980
Less unamortized debt issuance costs		2,715,745		2,680,897
Long-term obligations, excluding current installments	$	442,890,253	$	446,227,620

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 2016 CoBank Note.The CoBank Note is governed by the Second Amended and Restated Master Loan Agreement, which is secured by the Indenture dated January 20, 2011.

Chugach is also required to comply with the 2016 Credit Agreement, between Chugach and NRUCFC, KeyBank National Association, Bank of America, N.A., CoBank, and ACB dated June 13, 2016, governing loans and extensions of credit associated with Chugach’s commercial paper program, in an aggregate principal amount not exceeding $150.0 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.

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 Second Amended and Restated Master Loan Agreement with CoBank, which became effective on June 30, 2016, did not change this requirement.

The 2016 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% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins.

Maturities of Long‑term Obligations

Long-term obligations at December 31, 2016, mature as follows:

Year ending December 31		2011 Series A Bonds		2016 CoBank Note		2012 Series A Bonds		Total
2017	$	10,666,667	$	3,420,000	$	10,750,000	$	24,836,667
2018		10,666,667		3,192,000		10,750,000		24,608,667
2019		10,666,667		3,192,000		10,750,000		24,608,667
2020		10,666,667		3,420,000		10,750,000		24,836,667
2021		10,666,667		3,648,000		3,750,000		18,064,667
Thereafter		168,333,330		26,904,000		158,250,000		353,487,330
	$	221,666,665	$	43,776,000	$	205,000,000	$	470,442,665

Lines of credit

Chugach maintains a $50.0 million line of credit with NRUCFC. Chugach did not utilize this line of credit in 2016 or 2015, and therefore had no outstanding balance at December 31, 2016 and 2015.  The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. The borrowing rate was2.90% at December 31, 2016 and 2015.

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.

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. This pricing included 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 was set to expire on November 17, 2016.  

On June 13, 2016, Chugach entered into a $150.0 million senior unsecured credit facility, the Credit Agreement, which is used to back Chugach’s commercial paper program. The new pricing includes an all-in drawn spread of one month LIBOR plus 90.0 basis points, along with a 10.0 basis points facility fee (based on an A/A2/A unsecured debt rating). The new Credit Agreement will expire on June 13, 2021. The participating banks include NRUCFC, KeyBank National Association, Bank of America, N.A., and CoBank, ACB.

Our commercial paper can be repriced between one day and 270 days. Chugach is expected to continue to issue commercial paper in 2017, as needed.

Chugach had $68.2 million and $20.0 million of commercial paper outstanding at December 31, 2016 and 2015, respectively.

The following table provides information regarding 2016 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 2016	$	16.1	0.61	July 2016	$	47.3	0.66
February 2016	$	16.9	0.60	August 2016	$	54.2	0.63
March 2016	$	30.5	0.60	September 2016	$	60.0	0.65
April 2016	$	55.1	0.60	October 2016	$	63.5	0.65
May 2016	$	78.2	0.60	November 2016	$	60.8	0.65
June 2016	$	76.0	0.62	December 2016	$	63.7	0.86

Financing

On January 21, 2011, Chugach issued $275.0 million of First Mortgage Bonds, 2011 Series A, in two tranches, Tranche A and Tranche B, for the purpose of refinancing the 2001 and 2002 Series A Bonds in 2011 and 2012, and for general corporate purposes. Interest is paid semi-annually on March 15 and September 15 commencing on September 15, 2011. Principal on the 2011 Series A Bonds is paid in equal annual installments beginning March 15, 2012.On January 11, 2012, Chugach issued $250.0 million of First Mortgage Bonds, 2012 Series A, in three tranches, Tranche A, Tranche B and Tranche C, for the purpose of repaying outstanding commercial paper used to finance SPP construction and for general corporate purposes. Interest is paid semi-annually March 15 and September 15 commencing on September 15, 2012. The 2012 Series A Bonds,  Tranche A and Tranche C, pay principal in equal installments on an annual basis beginning March 15, 2013, and 2023, respectively. The 2012 Series A Bonds,  Tranche B, pay principal beginning March 15, 2013,through 2020, and on March 15, 2032,through2042.  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.

Chugach had a term loan facility with CoBank,  evidenced by the 2011 CoBank Note, which was governed by the Amended and Restated Master Loan Agreement dated January 19, 2011,  and secured by the Indenture. On July 13, 2016, Chugach used commercial paper to pay off the $22.2 million balance and therefore had no outstanding balance at December 31, 2016. Chugach had $24.9 million outstanding on this facility at December 31, 2015.

On June 30, 2016, Chugach entered into another term loan facility with CoBank, evidenced by the 2016 CoBank Note, which is governed by the Second Amended and Restated Master Loan Agreement dated June 30, 2016, and secured by the Indenture. Chugach had $43.8 million outstanding on this facility at December 31, 2016.

The following table provides additional information regarding the 2011 Series A and 2012 Series A bonds and the 2016 CoBank Note at December 31, 2016 (dollars in thousands):

	Maturing March 15,	Average Life (Years)	Interest Rate		Issue Amount		Carrying Value
2011 Series A, Tranche A	2031	7.2	4.20	%	$	90,000	$	67,500
2011 Series A, Tranche B	2041	12.2	4.75	%		185,000		154,167
2012 Series A, Tranche A	2032	7.7	4.01	%		75,000		60,000
2012 Series A, Tranche B	2042	14.8	4.41	%		125,000		95,000
2012 Series A, Tranche C	2042	15.7	4.78	%		50,000		50,000
2016 CoBank Note	2031	6.2	2.58	%		45,600		43,776
Total					$	570,600	$	470,443

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2016

Employee Benefit Plans [Abstract]

Employee Benefit Plans

(12)  Employee Benefit Plans

Pension Plans

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

Pension benefits for non-union employees are provided by the National Rural Electric Cooperative Association (NRECA) Retirement and Security Plan (RS Plan). The RS Plan is a defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the Internal Revenue Code. Under ASC 960, “Topic 960 – Plan Accounting – Defined Benefit Pension Plans,” the 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, 2016, 2015 and 2014 of $6.7million,  $6.7 million and $6.8 million, respectively. The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2016, 2015 and 2014.

In December 2012, a committee of the NRECA Board of Directors approved an option to allow participating cooperatives in the Retirement Security (RS) Plan (a defined benefit multiemployer pension plan) to make a prepayment and reduce future required contributions. The prepayment amount is a cooperative’s share, as of January 1, 2013, of future contributions required to fund the RS Plan’s unfunded value of benefits earned to date using Plan actuarial valuation assumptions. The prepayment amount will typically equal approximately 2.5 times a cooperative’s annual RS Plan required contribution as of January 1, 2013. After making the prepayment, for most cooperatives the billing rate is reduced by approximately 25%, retroactive to January 1, 2013. The 25% differential in billing rates is expected to continue for approximately 15 years. However changes in interest rates, asset returns and other plan experience different from that expected, plan assumption changes, and other factors may have an impact on the differential in billing rates and the 15 year period.

On December 29, 2106, Chugach made a prepayment of $7.9 million to the NRECA RS Plan. See Note 2n – “Deferred Charges and Liabilities.”

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
	2016	2015	2014	2016	2015	2014
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)	$3.2	$3.1	$3.3	$3.5	$3.5	$3.5
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 participant in the NRECA RS Plan who is subject to an employment agreement, which is effective through April 30, 2020.

3The Alaska Electrical Pension Plan financial statements are publicly available. The NRECA RS Plan financial statements are 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, 2016, 2015, and 2014 were$4.5 million,  $4.5 million, and $4.5 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, 2016, 2015, and 2014 totaled $2.8 million,  $2.6 million, and $2.9 million respectively.

Money Purchase Pension Plan

Chugach participates in a multi-employer defined contribution money purchase pension plan covering some employees who are covered by a collective bargaining agreement. Contributions to the Plan are made based on a percentage of each employee’s compensation. Contributions to the money purchase pension plan for the years ending December 31, 2016, 2015 and 2014 were $132.3 thousand, $133.6 thousand and $149.2 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 $18,000 in 2016 and 2015 and $17,500 in 2014, and allowed catch-up contributions for those over 50 years of age of $6,000in 2016 and 2015 and $5,500 in 2014. 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, 2016, and 2015was $907,836 and$763,913, 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.

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Bradley Lake Hydroelectric Project

12 Months Ended

Dec. 31, 2016

Bradley Lake Hydroelectric Project [Abstract]

Bradley Lake Hydroelectric Project

(13)  Bradley Lake Hydroelectric Project

Chugach is a participant in the Bradley Lake Hydroelectric Project (Bradley Lake). Bradley Lake was built and financed by the Alaska Energy Authority (AEA) through State of Alaska grants and $166.0 million of revenue bonds. Chugach and other participating utilities have entered into take‑or‑pay power sales agreements under which shares of the project capacity have been purchased and the participants have agreed to pay a like percentage of annual costs of the project (including ownership, operation and maintenance costs, debt service costs and amounts required to maintain established reserves). Under these take‑or‑pay power sales agreements, the participants have agreed to pay all project costs from the date of commercial operation even if no energy is produced. Chugach has a 30.4% 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$19.0million.  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%. Upon default, Chugach could be faced with annual expenditures of approximately  $6.0millionas 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% of the additional energy produced.

The following represents information with respect to Bradley Lake at June 30, 2016 (the most recent date for which information is available). Chugach's share of expenses was $5,662,522in 2016,  $5,663,304 in 2015, and $5,228,907 in 2014 and is included in purchased power in the accompanying financial statements.

(In thousands)	Total		Proportionate Share
Plant in service	$	163,531	$	49,713
Long-term debt		53,495		16,262
Interest expense		3,177		966

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

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Eklutna Hydroelectric Project

12 Months Ended

Dec. 31, 2016

Eklutna Hydroelectric Project [Abstract]

Eklutna Hydroelectric Project

(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%), MEA (17%) and ML&P (53%).

Plant in service in 2016 included$4,229,167, net of accumulated depreciation of $2,442,175,  which represents Chugach’s share of the Eklutna Hydroelectric Project. In 2015, plant in service included $4,401,440, net of accumulated depreciation of $2,203,659. 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 $532,678,  $689,501, and $761,613in 2016, 2015, and 2014, 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.

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Beluga River Unit

12 Months Ended

Dec. 31, 2016

Beluga River Unit [Abstract]

Beluga River Unit

(15)  Beluga River Unit

On February 4, 2016, Chugach entered into an agreement entitled, “Purchase and Sale Agreement between ConocoPhillips Alaska, Inc. and Municipality of Anchorage d/b/a Municipal Light & Power and Chugach Electric Association, Inc.” The Purchase and Sale Agreement transfers CPAI’s working interest in the BRU to Chugach and ML&P. The total purchase price was $148.0 million, with Chugach’s portion totaling $44.4 million. Chugach’s interest in the BRU is to reduce the cost of electric service to its retail and wholesale members by securing an additional long-term supply of natural gas to meet on-going generation requirements. The acquisition complements existing gas supplies and is expected to provide greater fuel diversity.

Under the joint bid arrangement, Chugach’s ownership of CPAI’s working interest is 30% and ML&P’s ownership is 70%. The ownership shares include the attendant rights and privileges of all gas and oil resources, including 15,500 lease acres (8,200 in Unit / Participating Area and 7,300 held by Unit), Sterling and Beluga producing zones, and CPAI’s 67% working interest in deep oil resources. On April 21, 2016, the acquisition was approved by the RCA (see “Note 5 – Regulatory Matters – Beluga River Unit”) and the transaction closed on April 22, 2016.

Chugach had a firm gas supply contract with CPAI as previously discussed in “Note 16 – Commitments and Contingencies – Fuel Supply Contracts”. In addition to Chugach, CPAI had contractual gas sales obligations to ENSTAR through 2017. These contracts were assumed by ML&P and Chugach on the basis of ownership share.

The BRU is located on the western side of Cook Inlet, approximately 35 miles from Anchorage, and is an established natural gas field that was originally discovered in 1962. The BRU was jointly owned (one-third) by CPAI, Hilcorp, and ML&P. Following the acquisition, ML&P’s ownership of the BRU increased to approximately 56.7%, Hilcorp’s ownership remained unchanged at 33.3%, and Chugach’s ownership is 10.0%.

Chugach’s interest in the BRU is insignificant to the BRU as a whole and compared to Chugach’s operations prior to the acquisition. As such, Chugach has not provided supplemental pro forma financial information. Since the BRU activities are limited to the extraction of natural gas, Chugach is following the guidance provided in ASC 932-810-45-1 (Extractive Activities-Oil and Gas – Consolidation – Other Presentation Matters) and will record its pro rata share of the assets, liabilities, revenues and expenses of the BRU.

Chugach recorded the acquisition at fair value on the acquisition date. The fair value estimate used the discounted cash flow method assuming an estimated useful life of 18 years with 27 Bcf of proven developed producing reserves and using Chugach’s BRU financing rate as the credit adjusted risk free rate. The table below outlines the acquisition allocation recorded at December 31, 2016.

	Amount
Utility Plant:
Proved Developed Reserves	$	33,693,922
Proved Undeveloped Reserves		10,710,000
Asset Retirement Obligation		3,523,409
Utility plant		47,927,331
Cost of removal obligation		(3,523,409)
Cash Consideration	$	44,403,922

Acquisition costs are recorded as deferred charges on Chugach’s balance sheet because Chugach believes it is probable the RCA will allow them to be collected through rates, and totaled $1.5 million at December 31, 2016. Chugach has requested that these costs be amortized based on units of production of the BRU and recognized as depreciation and amortization on Chugach’s statement of operations.

Each of the BRU participants has a right to take their interest of the gas produced. Parties that take less than their interest of the field’s output may either accept a cash settlement for their underlift or take their underlifted gas in future years. As part of the BRU acquisition, Chugach acquired 30% of CPAI’s underlift, which was 69,099 Mcf at acquisition and was in an overlift position of 84 Mcf at December 31, 2016. Chugach has opted to take any cumulative underlift in gas in the future and will record the gas as fuel expense on the statement of operations when received.

The revenue generated by Chugach’s interest in the BRU operations is primarily associated with the gas sold to ENSTAR, pursuant to the aforementioned contract due to expire December 31, 2017. Chugach recognized revenue from the BRU in the amount of $2.8 million through December 31, 2016.

Chugach records depreciation, depletion and amortization on BRU assets based on units of production. As of December 31, 2016, Chugach lifted 1.9 Bcf resulting in approximately 25.1 Bcf remaining in Chugach’s proven developed reserves. Prior to the acquisition, CPAI was the contracted operator of the BRU. Following the acquisition, Hilcorp temporarily assumed operations under an agreement similar to that previously held by CPAI. A final operator agreement is expected during the second quarter of 2017. In addition to the operator fees to Hilcorp, other BRU expenses include royalty expense and interest on long-term debt. All expenses other than depreciation, depletion and amortization and interest on long-term debt are included as fuel expense on Chugach’s statement of operations. Chugach has applied and qualified for a small producer tax credit, provided by the State of Alaska, resulting in an estimate of no liability for production taxes. The revenue in excess of expenses less the allowed TIER from BRU operations is adjusted through Chugach’s fuel and purchased power adjustment process.

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Commitments And Contingencies

12 Months Ended

Dec. 31, 2016

Commitments And Contingencies [Abstract]

Commitments And Contingencies

(16)  Commitments and Contingencies

Contingencies

Chugach is a participant in various legal actions, rate disputes, personnel matters and claims both for and against Chugach’s interests. Management believes the outcome of any such matters will not materially impact Chugach’s financial condition, results of operations or liquidity. Chugach establishes reserves when a particular contingency is probable and calculable. Chugach has not accrued for any contingency at December 31, 2016, as it does not consider any contingency to be probable nor calculable. Chugach faces contingencies that are reasonably possible to occur; however, they cannot currently be estimated.

Concentrations

Approximately 70% of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW. We also have an agreement with the Hotel Employees and Restaurant Employees (HERE). All three IBEW CBA’s have been renewed through June 30, 2021. The HERE contract was renewed through June 30, 2021. We believe our relationship with our employees is good.

Fuel Supply Contracts

Chugach has fuel supply contracts from various producers at market terms. A gas supply contract between Chugach and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively “ConocoPhillips”), approved effective by the RCA on August 21, 2009, began providing gas in 2010 and expired December 31, 2016. The total amount of gas under the contract was 62 Bcf.This contract was assumed by Chugach and ML&P as part of the BRU acquisition, on the basis of ownership share. As such, Chugach pays ML&P for 70% of gas purchased under this contract. Chugach entered into a gas contract with Hilcorp effective January 1, 2015, to provide gas through March 31, 2018. On September 15, 2014, the RCA approved an amendment to the Hilcorp gas purchase agreement extending gas delivery and subsequently filling 100 percent of Chugach’s needs through March 31, 2019. On September 8, 2015, the RCA approved another amendment to the Hilcorp gas purchase agreement extending the term of the agreement, thus filling up to 100 percent of Chugach’s needs through March 31, 2023.  The total amount of gas under this contract is estimated to be 60 Bcf. All of the production is expected to come from Cook Inlet, Alaska. The terms of the ML&P (previously under ConocoPhillips) and Hilcorp agreements require Chugach to manage the natural gas transportation over the connecting pipeline systems. Chugach has gas transportation agreements with ENSTAR Natural Gas Company (ENSTAR) and Hilcorp.

The RCA approved a 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 began providing gas April 1, 2011, and will expire March 31, 2023. The total amount of gas under contract is currently estimated up to49 Bcf. These contracts fill 100% of Chugach’s needs through March 31, 2023. All of the production is expected to come from Cook Inlet, Alaska.

In 2016, 77% of our power was generated from gas, with 9% generated at the Beluga Power Plant and 88%generated at SPP. In 2015,  86% of our power was generated from gas, with 30% generated at Beluga and61% generated at SPP.

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 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:

	2016		2015		2014
Hilcorp	56.9	%	30.3	%	50.4	%
ConocoPhillips (COP)	32.0	%	58.7	%	43.6	%
AIX Energy	0.7	%	4.7	%	0.0	%
ENSTAR	4.7	%	3.3	%	2.0	%
Harvest (Hilcorp) Pipeline	3.2	%	1.6	%	3.0	%
Miscellaneous	2.5	%	1.4	%	1.0	%

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, 2016 and 2015.MEA’s patronage capital payable was $4.1 million and $3.2 million at December 31, 2016 and 2015, respectively.

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 $0.000675, effective July 1, 2016. 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 collectedmonthly 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 $2,507,482and $5,184,551 for this charge at December 31, 2016 and 2015, respectively, and is included in other current liabilities. These funds are used to offset the costs of the undergrounding program.

Environmental Matters

Since January 1, 2007, transformer manufacturers have been required to meet the US Department of Energy (DOE) efficiency levels as defined by the Energy Act of 2005 (Energy Act) for all “Distribution Transformers.” As of January 1, 2016, the specific efficiency levels are increasing from the original “TP1” levels to the new “DOE-2016” levels. All new transformers are DOE-2016 compliant. At this time a small increase in capital costs is anticipated along with a reduction in energy losses.

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 August 3, 2015, the EPA released the final 111(d) regulation language aimed at reducing emissions of carbon dioxide (CO₂) from existing power plants that provide electricity for utility customers. In the final 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. The EPA initially applied the final rule to 47 of the contiguous states. At this time, Alaska, Hawaii, Vermont, Washington D.C. and two U.S. territories are not bound by the regulation. Alaska may be required to comply at some future date. On February 9, 2016 the U.S. Supreme Court issued a stay on the proposed EPA 111(d) regulations until the DC Circuit decides the case, or until the disposition of a petition to the Supreme Court on the issue. On September 27, 2016, the US Court of Appeals for the District of Columbia Circuit heard oral arguments challenging the legality of the Clean Power Plan. The court is expected to issue a decision in the near future. The EPA 111(d) regulation, in its current form, is not expected to have a material effect on Chugach’s 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 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.

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Subsequent Events

12 Months Ended

Dec. 31, 2016

Subsequent Events [Abstract]

Subsequent Events

(17)  Subsequent Events

On March 17, 2017, Chugach issued $40,000,000 of First Mortgage Bonds, 2017 Series A, due March 15, 2037 for general corporate purposes. The 2017 Series A Bonds will mature on March 15, 2037, and will bear interest at 3.43%. Interest will be paid each March 15 and September 15, commencing on September 15, 2017. The 2017 Series A Bonds will pay principal in equal installments on an annual basis beginning March 15, 2018, resulting in an average life of approximately 10.0 years. The bonds are secured, ranking equally with all other long-term obligations, by a first lien on substantially all of Chugach’s assets, pursuant to the Sixth Supplemental Indenture to the Second Amended and Restated Indenture of Trust, which initially became effective on January 20, 2011, as previously amended and supplemented.

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Quarterly Results Of Operations

12 Months Ended

Dec. 31, 2016

Quarterly Results Of Operations [Abstract]

Quarterly Results Of Operations

(18)  Quarterly Results of Operations (unaudited)

2016 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	57,741,954	$	45,132,973	$	44,622,517	$	50,250,135
Operating Expense		47,000,307		40,308,301		41,472,710		42,359,071
Net Interest		5,341,242		5,427,440		5,247,404		5,385,211
Net Operating Margins		5,400,405		(602,768)		(2,097,597)		2,505,853
Nonoperating Margins		231,683		125,332		127,871		123,077
Assignable Margins	$	5,632,088	$	(477,436)	$	(1,969,726)	$	2,628,930

2015 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	50,640,703	$	43,109,512	$	47,697,820	$	74,973,117
Operating Expense		42,182,178		39,667,546		43,490,558		63,451,276
Net Interest		5,415,131		5,428,774		5,381,167		5,589,373
Net Operating Margins		3,043,394		(1,986,808)		(1,173,905)		5,932,468
Nonoperating Margins		368,403		79,028		126,010		114,262
Assignable Margins	$	3,411,797	$	(1,907,780)	$	(1,047,895)	$	6,046,730

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Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2016

Significant Accounting Policies [Abstract]

Management Estimates

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 the allowance for doubtful accounts, workers’ compensation liability, deferred charges and liabilities, unbilled revenue, estimated useful life of utility plant, cost of removal and asset retirement obligation (ARO), purchase price allocation for BRU, and remaining proved BRU reserves. Actual results could differ from those estimates.

Regulation

b. Regulation

The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 980, “Topic 980 - Regulated Operations.” FASB ASC 980 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates. Our regulated rates are established to recover all of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs and those rates are then collected from our retail and wholesale customers. The regulatory assets or liabilities are then reduced as the cost or credit is reflected in earnings and our rates, see Note (2n) – “Deferred Charges and Liabilities.”

Utility Plant And Depreciation

c. Utility Plant and Depreciation

Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. For property replaced or retired, the book value of the property, 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, 2016 are as follows:

Annual Depreciation Rate Ranges

Steam production plant	3.15%	-	3.84%
Hydroelectric production plant	1.06%	-	3.00%
Other production plant	3.15%		8.85%
Transmission plant	1.58%	-	7.86%
Distribution plant	2.16%	-	9.63%
General plant	1.57%	-	20.00%
Other	2.75%	-	2.75%

On November 1, 2010, the RCA approved revised depreciation rates effective November 1, 2010 in Docket U-09-097. Chugach’s depreciation rates include a provision for cost of removal. 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 Southcentral Power Project (SPP) depreciation rates effective February 1, 2013, the date the SPP plant was placed in service.

Chugach records Depreciation, Depletion and Amortization (DD&A) expense on the BRU assets based on units of production using the following formula: ten percent of the total production from the BRU as provided by the operator divided by ten percent of the estimated remaining proved reserves (in thousand cubic feet (Mcf)) in the field multiplied by Chugach’s total assets in the BRU.

Full Cost Method

d. Full Cost Method

Pursuant to Accounting Standards Codification (ASC) 932-360-25, “Extractive Activities-Oil and Gas – Property, Plant and Equipment – Recognition,” Chugach has elected the Full Cost method, rather than the Successful Efforts method, to account for exploration and development costs of gas reserves. This is the first time Chugach has invested in oil or gas activities, so there is no prior policy of using the Successful Efforts method.

Asset Retirement Obligation (ARO)

e. Asset Retirement Obligation (ARO)

Chugach calculated and recorded an Asset Retirement Obligation associated with the BRU. Chugach uses its BRU financing rate as its credit adjusted risk free rate and the expected cash flow approach to calculate the fair value of the ARO liability. The ARO asset is depreciated using the DD&A formula previously discussed. The ARO liability is accreted using the interest method of allocation.

Investments In Associated Organizations

f. 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 one percent. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment. No impairment was recorded during 2016, 2015 and 2014.

Investments - Other

g. Investments – Other

Investments –other consists of certificates of deposit with an original maturity of 18 months.

Cash And Cash Equivalents / Restricted Cash Equivalents

h. 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 $5,897,767and $6,218,015 during the years ended December 31, 2016 and 2015, respectively.

Restricted cash equivalents include funds on deposit for future workers’ compensation claims. At December 31, 2016 and 2015, restricted cash equivalents included $0.8 million and $1.7 million, respectively, of funds on deposit for future workers’ compensation claims.

Marketable Securities

i. Marketable Securities

In September 2016, Chugach resumed its mutual fund investment portfolio. The investments are classified as trading securities, reported at fair value with gains and losses in earnings, and include bond funds.

	Twelve months ended December 31, 2016
Net gains and losses recognized during the period on trading securities	$	(143,185)
Less: Net gains and losses recognized during the period on trading securities sold during the period		0
Unrealized gains and losses recognized during the reporting period on trading securities still held at the reporting date	$	(143,185)

Accounts Receivable

j. 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 Anchorage Municipal Light & Power (ML&P) for their proportionate share of current SPP costs, which amounted to $1.4 million and $1.1 million in 2016 and 2015, respectively. In addition, accounts receivable includes invoiced amounts for grants to support investigating means of mitigating the impact of renewable generation variability on the grid as well as the construction of facilities to divert water and safely transmit electricity, which amounted to $0.0 million and $0.2 million in 2016 and 2015, respectively. At December 31, 2016, accounts receivable also included $0.7 million from BRU operations primarily associated with gas sales to ENSTAR.

Materials And Supplies

k. Materials and Supplies

Materials and supplies are stated at average cost.

Fuel Stock

l. 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, 2016 and 2015 amounted to $6.3 million and $7.1 million, respectively.

Fuel And Purchased Power Cost Recovery

m. Fuel and Purchased Power Cost Recovery

Expenses associated with electric services include fuel purchased from others and produced from Chugach’s interest in the BRU, both of which are used to generate electricity, as well as 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 purchased power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods.

Deferred Charges and Liabilities

n. Deferred Charges and Liabilities

Included in deferred charges and liabilities on Chugach’s financial statements are regulatory assets and liabilities recorded in accordance with FASB ASC 980.  See Note 8 – Deferred Charges and Liabilities. Continued accounting under FASB ASC 980 requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for ratemaking purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria.

Chugach’s 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 liabilities include 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.

On December 29, 2016, Chugach made a prepayment of $7.9 million to the National Rural Electric Cooperative Association (NRECA) Retirement and Security (RS) Plan, which is included in deferred charges. Chugach recorded the long term prepayment in deferred charges and is amortizing the deferred charge to administrative, general and other expense, over 11 years, which represents the difference between the normal retirement age of 62 and the average age of Chugach’s employees in the RS Plan.

Patronage Capital

o. 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.

Consumer Deposits

p. Consumer Deposits

Consumer deposits are the amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 2016 and 2015, totaled $3.3 million and $3.1 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances totaled $1.9 million for the years ended December 31, 2016 and 2015.

Fair Value Of Financial Instruments

q. 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.

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

Marketable securities – the carrying amount approximates fair value as changes in the market value are recorded monthly and gains or losses are reported in earnings (see note 2i and note 4).

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

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

The fair value of accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature.

Operating Revenues

r. Operating Revenues

Revenues are recognized upon delivery of electricity. Operating revenues are based on billing rates authorized by the RCA, which are applied to customers’ usage of electricity. Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results. Chugach calculates unbilled revenue at the end of each month to ensure the recognition of a calendar year’s revenue. Chugach accrued $10,940,274 and $10,531,377 of unbilled retail revenue at December 31, 2016 and 2015, respectively, which is included in accounts receivable on the balance sheet. 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.

Capitalized Interest

s. 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 Chugach capitalized such funds at the weighted average rate of 4.3% during 2016, 2015 and 2014.

Environmental Remediation Costs

t. Environmental Remediation Costs

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

Income Taxes

u. 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, 2016, 2015 and 2014 was in compliance with that provision. In addition, as described in Note (16) – “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 fifty percent likelihood of being sustained upon examination by the taxing authorities. Chugach’s management reviewed Chugach’s tax positions and determined there were no outstanding or retroactive tax positions that were not highly certain of being sustained upon examination by the taxing authorities.

Management has concluded that there are no significant uncertain tax positions requiring recognition in its financial statements for all periods presented. Chugach’s evaluation was performed for the tax periods ended December 31, 2014 through December 31, 2016 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2016.

Grants

v. Grants

Chugach has received federal and state grants to offset storm related expenditures and to support investigating means of mitigating the impact of renewable generation variability on the grid as well as 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, both of which totaled $0.6 million and $1.6 million in 2016 and 2015, respectively.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

Significant Accounting Policies [Abstract]

Schedule Of Depreciation And Amortization Rates

Steam production plant	3.15%	-	3.84%
Hydroelectric production plant	1.06%	-	3.00%
Other production plant	3.15%		8.85%
Transmission plant	1.58%	-	7.86%
Distribution plant	2.16%	-	9.63%
General plant	1.57%	-	20.00%
Other	2.75%	-	2.75%

Schedule Of Gains And Losses On Trading Securities

	Twelve months ended December 31, 2016
Net gains and losses recognized during the period on trading securities	$	(143,185)
Less: Net gains and losses recognized during the period on trading securities sold during the period		0
Unrealized gains and losses recognized during the reporting period on trading securities still held at the reporting date	$	(143,185)

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Fair Value Of Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value Of Assets And Liabilities [Abstract]

Schedule Of Marketable Securities

	December 31, 2016		Level 1
Bond funds/Certificates of Deposit	$	10,436,815	$	10,436,815

Schedule Of Estimated Fair Value Of Long-Term Obligations Included In Financial Statements

	Measurement	Carrying Value		Fair Value
2011 Series A Bonds	Level 2	$	221,667	$	231,057
2012 Series A Bonds	Level 2		205,000		209,242
2016 CoBank Note	Level 2		43,776		40,921
Long-term obligations (including current installments)		$	470,443	$	481,220

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Utility Plant (Tables)

12 Months Ended

Dec. 31, 2016

Utility Plant [Abstract]

Schedule Of Major Classes Of Utility Plant

Electric plant in service:	2016		2015
Steam production plant	$	101,116,277	$	100,938,247
Hydroelectric production plant		33,659,129		20,591,678
Other production plant		287,404,484		284,035,865
Transmission plant		282,040,969		277,490,606
Distribution plant		294,641,485		290,680,919
General plant		54,982,432		51,841,582
Unclassified electric plant in service1		83,457,981		95,611,615
Intangible plant1		5,455,371		5,455,371
Beluga River Natural Gas Field (BRU Asset & ARO)		47,927,331		0
Other1		1,828,409		1,828,409
Total electric plant in service		1,192,513,869		1,128,474,292
Construction work in progress		18,455,940		15,601,374
Total electric plant in service and construction work in progress	$	1,210,969,809	$	1,144,075,666

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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Investments In Associated Organizations (Tables)

12 Months Ended

Dec. 31, 2016

Investments In Associated Organizations [Abstract]

Schedule Of Investments In Associated Organizations

	2016		2015
NRUCFC	$	6,095,980	$	6,095,980
CoBank		3,188,490		3,475,664
NRUCFC Capital Term Certificates and other		64,841		63,875
Total investments in associated organizations	$	9,349,311	$	9,635,519

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Deferred Charges And Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Regulatory Assets [Line Items]

Schedule Of Deferred Charges, Or Regulatory Assets

	2016		2015
Regulatory assets:
Debt issuance and reacquisition costs	$	492,850	$	247,481
Refurbishment of transmission equipment		104,939		114,198
Feasibility studies		1,387,285		551,122
Beluga gas compression		0		508,866
Cooper Lake relicensing / projects		5,280,006		5,410,109
Fuel supply		2,005,052		939,768
Storm damage		647,381		841,595
Other regulatory deferred charges		849,933		1,056,909
Bond interest - market risk management		5,365,190		5,871,286
Environmental matters		1,024,171		1,069,522
Total regulatory assets		17,156,807		16,610,856
Other deferred charges:
NRECA pension plan prepayment		7,925,050		0
Post retirement benefit obligation		59,100		200,900
Total other deferred charges		7,984,150		200,900
Total deferred charges	$	25,140,957	$	16,811,756

Schedule Of Deferred Credits, Or Regulatory Liabilities

	2016		2015
Refundable consumer advances for construction	$	328,360	$	823,115
Estimated initial installation costs for meters		118,854		105,274
Post retirement benefit obligation		732,200		874,000
Total deferred liabilities	$	1,179,414	$	1,802,389

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

Regulatory Assets [Line Items]

Schedule Of Deferred Charges, Or Regulatory Assets

	2016		2015
Regulatory assets:
Multi-stage Energy Storage	$	1,117,860	$	124,569
Regulatory studies and other		46,721		360,879
Total regulatory assets		1,164,581		485,448
Other deferred charges:
NRECA pension plan prepayment		7,925,050		0
Post retirement benefit obligation		59,100		200,900
Total other deferred charges		7,984,150		200,900
Total deferred charges	$	9,148,731	$	686,348

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Other Equities (Tables)

12 Months Ended

Dec. 31, 2016

Other Equities [Abstract]

Schedule Of Other Equities

	2016		2015
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		2,001,450		1,877,193
Unclaimed capital credit retirement1		11,803,000		10,627,038
Total other equities	$	13,828,075	$	12,527,856

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

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Debt (Tables)

12 Months Ended

Dec. 31, 2016

Debt [Abstract]

Schedule Of Debt Issuance Costs Associated With Long-Term Obligations

Long-term obligations at December 31 are as follows:	2016		2015
2011 CoBank Note, 2.78% variable rate at redemption, with interest payable monthly and principal due annually beginning in 2003	$	0	$	24,941,165
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		67,500,000		72,000,000
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		154,166,665		160,333,332
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		60,000,000		63,750,000
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		95,000,000		102,000,000
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
2016 CoBank Note, 2.58% fixed rate note maturing in 2031, with interest and principal due quarterly beginning in 2016		43,776,000		0
Total long-term obligations	$	470,442,665	$	473,024,497
Less current installments		24,836,667		24,115,980
Less unamortized debt issuance costs		2,715,745		2,680,897
Long-term obligations, excluding current installments	$	442,890,253	$	446,227,620

Schedule Of Maturities Of Long-Term Obligations

Year ending December 31		2011 Series A Bonds		2016 CoBank Note		2012 Series A Bonds		Total
2017	$	10,666,667	$	3,420,000	$	10,750,000	$	24,836,667
2018		10,666,667		3,192,000		10,750,000		24,608,667
2019		10,666,667		3,192,000		10,750,000		24,608,667
2020		10,666,667		3,420,000		10,750,000		24,836,667
2021		10,666,667		3,648,000		3,750,000		18,064,667
Thereafter		168,333,330		26,904,000		158,250,000		353,487,330
	$	221,666,665	$	43,776,000	$	205,000,000	$	470,442,665

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

Month	Average Balance		Weighted Average Interest Rate	Month	Average Balance		Weighted Average Interest Rate
January 2016	$	16.1	0.61	July 2016	$	47.3	0.66
February 2016	$	16.9	0.60	August 2016	$	54.2	0.63
March 2016	$	30.5	0.60	September 2016	$	60.0	0.65
April 2016	$	55.1	0.60	October 2016	$	63.5	0.65
May 2016	$	78.2	0.60	November 2016	$	60.8	0.65
June 2016	$	76.0	0.62	December 2016	$	63.7	0.86

Schedule Of Additional Information Regarding Series A Bonds

	Maturing March 15,	Average Life (Years)	Interest Rate		Issue Amount		Carrying Value
2011 Series A, Tranche A	2031	7.2	4.20	%	$	90,000	$	67,500
2011 Series A, Tranche B	2041	12.2	4.75	%		185,000		154,167
2012 Series A, Tranche A	2032	7.7	4.01	%		75,000		60,000
2012 Series A, Tranche B	2042	14.8	4.41	%		125,000		95,000
2012 Series A, Tranche C	2042	15.7	4.78	%		50,000		50,000
2016 CoBank Note	2031	6.2	2.58	%		45,600		43,776
Total					$	570,600	$	470,443

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2016

Employee Benefit Plans [Abstract]

Schedule Of Information Regarding Individually Significant Pension Plans

	Alaska Electrical Pension Plan3			NRECA Retirement Security Plan3
Employer Identification Number	92-6005171			53-0116145
Plan Number	001			333
Year-end Date	December 31			December 31
Expiration Date of CBA's	June 30, 2017			N/A2
Subject to Funding Improvement Plan	No			No4
Surcharge Paid	N/A			N/A4
	2016	2015	2014	2016	2015	2014
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)	$3.2	$3.1	$3.3	$3.5	$3.5	$3.5
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 participant in the NRECA RS Plan who is subject to an employment agreement, which is effective through April 30, 2020.

3The Alaska Electrical Pension Plan financial statements are publicly available. The NRECA RS Plan financial statements are 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.

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Bradley Lake Hydroelectric Project (Tables)

12 Months Ended

Dec. 31, 2016

Bradley Lake Hydroelectric Project [Abstract]

Schedule Of Bradley Lake Information

(In thousands)	Total		Proportionate Share
Plant in service	$	163,531	$	49,713
Long-term debt		53,495		16,262
Interest expense		3,177		966

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Beluga River Unit (Tables)

12 Months Ended

Dec. 31, 2016

Beluga River Unit [Abstract]

Schedule Of Acquisition Allocation

	Amount
Utility Plant:
Proved Developed Reserves	$	33,693,922
Proved Undeveloped Reserves		10,710,000
Asset Retirement Obligation		3,523,409
Utility plant		47,927,331
Cost of removal obligation		(3,523,409)
Cash Consideration	$	44,403,922

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Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Commitments And Contingencies [Abstract]

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

	2016		2015		2014
Hilcorp	56.9	%	30.3	%	50.4	%
ConocoPhillips (COP)	32.0	%	58.7	%	43.6	%
AIX Energy	0.7	%	4.7	%	0.0	%
ENSTAR	4.7	%	3.3	%	2.0	%
Harvest (Hilcorp) Pipeline	3.2	%	1.6	%	3.0	%
Miscellaneous	2.5	%	1.4	%	1.0	%

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Quarterly Results Of Operations (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Results Of Operations [Abstract]

Schedule Of Quarterly Results Of Operations

2016 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	57,741,954	$	45,132,973	$	44,622,517	$	50,250,135
Operating Expense		47,000,307		40,308,301		41,472,710		42,359,071
Net Interest		5,341,242		5,427,440		5,247,404		5,385,211
Net Operating Margins		5,400,405		(602,768)		(2,097,597)		2,505,853
Nonoperating Margins		231,683		125,332		127,871		123,077
Assignable Margins	$	5,632,088	$	(477,436)	$	(1,969,726)	$	2,628,930

2015 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	50,640,703	$	43,109,512	$	47,697,820	$	74,973,117
Operating Expense		42,182,178		39,667,546		43,490,558		63,451,276
Net Interest		5,415,131		5,428,774		5,381,167		5,589,373
Net Operating Margins		3,043,394		(1,986,808)		(1,173,905)		5,932,468
Nonoperating Margins		368,403		79,028		126,010		114,262
Assignable Margins	$	3,411,797	$	(1,907,780)	$	(1,047,895)	$	6,046,730

XML

Description Of Business (Details)	12 Months Ended
	Dec. 31, 2016 mi
Description Of Business [Line Items]
Electrification area	400
Matanuska Electric Association, Inc. [Member]
Description Of Business [Line Items]
Long-term Contract for Purchase of Electric Power, Date of Contract Extension	Apr. 30, 2015
Golden Valley Electric Association, Inc. [Member]
Description Of Business [Line Items]
Power contracts expiration date	Mar. 31, 2015

XML

Significant Accounting Policies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Significant Accounting Policies [Line Items]
Weighted average capital interest percentage	4.30%	4.30%	4.30%
Impairment on investments	$ 0	$ 0	$ 0
Investment maturity period	18 months
Minimum number of days past balances reviewed	90 days
Accounts receivable	$ 33,000,919	28,232,930
Fuel stock	6,321,676	7,063,541
Fuel cost over-recovery	3,824,722	5,135,745
Consumer deposits	3,300,000	3,100,000
Customer credits	1,900,000	1,900,000
Grant proceeds included in public utilities property, plant and equipment carrying amount	600,000	1,600,000
Cash provided by operating activities	32,494,336	52,096,436	58,766,300
Cash used in financing activities	46,040,387	(20,486,734)	$ (34,061,334)
NRECA Retirement Security Plan [Member]
Significant Accounting Policies [Line Items]
Multiemployer plan, Prepayment amount	$ 7,900,000
Multiemployer plan, Prepayment amortization period	11 years
ML&P For Fuel And South Central Power Project Costs [Member]
Significant Accounting Policies [Line Items]
Accounts receivable	$ 1,400,000	1,100,000
Alaska Energy Authority For Grant [Member]
Significant Accounting Policies [Line Items]
Accounts receivable	0	200,000
BRU Operations For Gas Sales [Member]
Significant Accounting Policies [Line Items]
Accounts receivable	700,000
Unbilled Retail Revenues [Member]
Significant Accounting Policies [Line Items]
Accounts receivable	10,940,274	10,531,377
Concentration Account [Member]
Significant Accounting Policies [Line Items]
Average balance of cash account	5,897,767	6,218,015
Funds On Deposit [Member]
Significant Accounting Policies [Line Items]
Restricted cash equivalents	$ 800,000	$ 1,700,000
Maximum [Member] | CoBank, ACB (CoBank) And National Rural Utilities Cooperative Finance Corporation (NRUCFC) [Member]
Significant Accounting Policies [Line Items]
Cost ownership percentage	1.00%

XML

Significant Accounting Policies (Schedule Of Depreciation And Amortization Rates) (Details)	12 Months Ended
	Dec. 31, 2016
Minimum [Member] | Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.15%
Minimum [Member] | Hydroelectric Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	1.06%
Minimum [Member] | Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.15%
Minimum [Member] | Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	1.58%
Minimum [Member] | Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.16%
Minimum [Member] | General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	1.57%
Minimum [Member] | Other Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.75%
Maximum [Member] | Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.84%
Maximum [Member] | Hydroelectric Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.00%
Maximum [Member] | Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	8.85%
Maximum [Member] | Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	7.86%
Maximum [Member] | Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	9.63%
Maximum [Member] | General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	20.00%
Maximum [Member] | Other Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.75%

XML

Significant Accounting Policies (Schedule Of Gains And Losses On Trading Securities) (Details)	12 Months Ended
	Dec. 31, 2016 USD ($)
Significant Accounting Policies [Abstract]
Net gains and losses recognized during the period on trading securities	$ (143,185)
Less: Net gains and losses recognized during the period on trading securities sold during the period	0
Unrealized gains and losses recognized during the reporting period on trading securities still held at the reporting date	$ (143,185)

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Accounting Pronouncements (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Concentration Risk [Line Items]
Less unnamortized debt issuance costs	$ 2,715,745	$ 2,680,897
Product Concentration Risk [Member] | Sales Revenue, Product Line [Member]
Concentration Risk [Line Items]
Energy percentage of revenue	99.00%

XML

Fair Value Of Assets And Liabilities (Schedule Of Marketable Securities) (Details)	Dec. 31, 2016 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Bond funds/Certificates of Deposit	$ 10,436,815
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Bond funds/Certificates of Deposit	$ 10,436,815

XML

Fair Value Of Assets And Liabilities (Schedule Of Estimated Fair Value Of Long-Term Obligations Included In Financial Statements) (Details) $ in Thousands	Dec. 31, 2016 USD ($)
Carrying Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	$ 470,443
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	481,220
2011 Series A Bonds [Member] | Level 2 [Member] | Carrying Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	221,667
2011 Series A Bonds [Member] | Level 2 [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	231,057
2012 Series A Bonds [Member] | Level 2 [Member] | Carrying Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	205,000
2012 Series A Bonds [Member] | Level 2 [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	209,242
2016 CoBank Note [Member] | Level 2 [Member] | Carrying Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	43,776
2016 CoBank Note [Member] | Level 2 [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	$ 40,921

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Regulatory Matters (Details) Mcf in Millions										1 Months Ended					12 Months Ended
	Mar. 16, 2017 $ / Mcfe Mcf	Nov. 18, 2016 USD ($)	Aug. 29, 2016	Aug. 12, 2016	Jul. 08, 2016 USD ($)	Jul. 01, 2016 USD ($)	Dec. 04, 2015 MMcf	Feb. 13, 2015 USD ($)	Jan. 30, 2015 MMcf	Jan. 31, 2017 USD ($)	Aug. 31, 2016 USD ($)	Jan. 31, 2016 USD ($)	Jul. 31, 2015 a	Apr. 30, 2015	Dec. 31, 2016 USD ($) $ / Mcfe MMcf
Other Commitments [Line Items]
Proposed percentage increase (decrease) in rates						4.20%		20.00%
Proposed increase (decrease) in rates						$ 4,800,000		$ 21,300,000							$ (5,900,000)
Approved percentage increase (decrease) in rates				4.20%								(0.50%)
Approved increase (decrease) in rates												$ (600,000)
Times interest earned ratio												1.35			1.30
Times interest earned ratio margin increase per year												$ 1,000,000
Beluga Power Plant [Member]
Other Commitments [Line Items]
Recovery requested		$ 11,400,000
Beluga Power Plant, Unit 1 [Member] | Beluga Power Plant [Member]
Other Commitments [Line Items]
Recovery requested		$ 300,000
Amortization period of regulatory asset		30 months
Beluga Power Plant, Unit 2 [Member] | Beluga Power Plant [Member]
Other Commitments [Line Items]
Recovery requested		$ 11,100,000
Amortization period of regulatory asset		108 months
Matanuska Electric Association, Inc. [Member]
Other Commitments [Line Items]
Power contracts extension date															Apr. 30, 2015
City Of Seward [Member]
Other Commitments [Line Items]
Proposed percentage increase (decrease) in rates															(4.60%)
Refunds issued					$ 28,000
City Of Seward [Member] | Total Customer Bill Basis [Member]
Other Commitments [Line Items]
Proposed percentage increase (decrease) in rates															(1.90%)
Retail Customers [Member]
Other Commitments [Line Items]
Proposed percentage increase (decrease) in rates						2.50%									(4.70%)
Refunds issued											$ 750,000
Retail Customers [Member] | Total Customer Bill Basis [Member]
Other Commitments [Line Items]
Proposed percentage increase (decrease) in rates															(3.20%)
ConocoPhillips (COP) [Member]
Other Commitments [Line Items]
Acres of exploration prospects | a													5,700
Minimum [Member]
Other Commitments [Line Items]
Approved percentage increase (decrease) in rates														2.00%
Minimum [Member] | Transmission Wheeling And Ancillary Services [Member]
Other Commitments [Line Items]
Proposed percentage increase (decrease) in rates			9.50%
Maximum [Member]
Other Commitments [Line Items]
Approved percentage increase (decrease) in rates														5.00%
Maximum [Member] | Transmission Wheeling And Ancillary Services [Member]
Other Commitments [Line Items]
Proposed percentage increase (decrease) in rates			14.40%
Subsequent Event [Member]
Other Commitments [Line Items]
Term to finalize agreementerm to finalize agreement										1 year
Estimated cost reductions										$ 16,000,000
CINGSA [Member]
Other Commitments [Line Items]
Total volume of natural gas found | MMcf									14,500
Approved volume of natural gas for commercial sale | MMcf							2,000
Percentage of proceeds allocated							13.00%
Term of notice preceding gas sales															30 days
CINGSA [Member] | Minimum [Member]
Other Commitments [Line Items]
Proposed volume of natural gas for commercial sale | MMcf															2,000
FSS [Member]
Other Commitments [Line Items]
Percentage of proceeds allocated							87.00%
Furie Operating Alaska, LLC [Member] | Subsequent Event [Member]
Other Commitments [Line Items]
Minimum purchase requirement | Mcf	1.8
Term of purchase commitment	16 years
Furie Operating Alaska, LLC [Member] | Subsequent Event [Member] | Firm Purchases [Member]
Other Commitments [Line Items]
Commencement date of natural gas purchases	Apr. 01, 2023
Expiration date of natural gas purchases	Mar. 31, 2033
Furie Operating Alaska, LLC [Member] | Subsequent Event [Member] | Interruptible Gas Purchases [Member]
Other Commitments [Line Items]
Expiration date of natural gas purchases	Mar. 31, 2033
Furie Operating Alaska, LLC [Member] | Subsequent Event [Member] | Minimum [Member]
Other Commitments [Line Items]
Price of natural gas purchases | $ / Mcfe	7.16
Percentage of projected natural gas requirements	20.00%
Furie Operating Alaska, LLC [Member] | Subsequent Event [Member] | Maximum [Member]
Other Commitments [Line Items]
Price of natural gas purchases | $ / Mcfe	7.98
Percentage of projected natural gas requirements	25.00%
Beluga River Unit [Member]
Other Commitments [Line Items]
Date of Purchase and Sale Agreement															Feb. 04, 2016
Initial gas transfer price | $ / Mcfe															5.88
Deferred cost of acquisition															$ 1,500,000

XML

Utility Plant (Details) - USD ($)		Dec. 31, 2016	Dec. 31, 2015
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment		$ 1,192,513,869	$ 1,128,474,292
Electric plant in service		1,192,513,869	1,128,474,292
Construction work in progress		18,455,940	15,601,374
Total utility plant		1,210,969,809	1,144,075,666
Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing		101,116,277	100,938,247
Hydroelectric Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing		33,659,129	20,591,678
Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing		287,404,484	284,035,865
Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Transmission		282,040,969	277,490,606
Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution		294,641,485	290,680,919
General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment		54,982,432	51,841,582
Electric plant in service		54,982,432	51,841,582
Unclassified Electric Plant In Service [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment	[1]	83,457,981	95,611,615
Electric plant in service	[1]	83,457,981	95,611,615
Intangible Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	[1]	5,455,371	5,455,371
Beluga River Unit [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment		47,927,331	0
Electric plant in service		47,927,331	0
Other [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other- land	[1]	$ 1,828,409	$ 1,828,409

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

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Investments In Associated Organizations (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	$ 9,349,311	$ 9,635,519
NRUCFC [Member]
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	6,095,980	6,095,980
CoBank [Member]
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	3,188,490	3,475,664
NRUCFC Capital Term Certificates And Other [Member]
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	$ 64,841	$ 63,875

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Deferred Charges And Liabilities (Schedule Of Deferred Charges, Or Regulatory Assets) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Total deferred charges	$ 25,140,957	$ 16,811,756
Total deferred charges	25,140,957	16,811,756
Debt Issuance And Reacquisition Costs [Member]
Regulatory Assets [Line Items]
Total deferred charges	492,850	247,481
Refurbishment Of Transmission Equipment [Member]
Regulatory Assets [Line Items]
Total deferred charges	104,939	114,198
Feasibility Studies [Member]
Regulatory Assets [Line Items]
Total deferred charges	1,387,285	551,122
Beluga Gas Compression [Member]
Regulatory Assets [Line Items]
Total deferred charges	0	508,866
Cooper Lake Relicensing / Projects [Member]
Regulatory Assets [Line Items]
Total deferred charges	5,280,006	5,410,109
Fuel Supply [Member]
Regulatory Assets [Line Items]
Total deferred charges	2,005,052	939,768
Storm Damage [Member]
Regulatory Assets [Line Items]
Total deferred charges	647,381	841,595
Other Regulatory Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	849,933	1,056,909
Bond Interest - Market Risk Management [Member]
Regulatory Assets [Line Items]
Total deferred charges	5,365,190	5,871,286
Environmental Matters [Member]
Regulatory Assets [Line Items]
Total deferred charges	1,024,171	1,069,522
Regulatory Assets Excluding Other Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	17,156,807	16,610,856
NRECA Retirement Security Plan [Member]
Regulatory Assets [Line Items]
Total deferred charges	7,925,050	0
Post Retirement Benefit Obligation [Member]
Regulatory Assets [Line Items]
Total deferred charges	59,100	200,900
Other Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	$ 7,984,150	$ 200,900

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Deferred Charges And Liabilities (Schedule Of Deferred Charges, Or Regulatory Assets, Not Currently Being Recovered In Rates Charged To Consumers) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets [Line Items]
Total deferred charges	$ 25,140,957	$ 16,811,756
Total deferred charges	25,140,957	16,811,756
Regulatory Assets Excluding Other Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	17,156,807	16,610,856
NRECA Retirement Security Plan [Member]
Regulatory Assets [Line Items]
Total deferred charges	7,925,050	0
Post Retirement Benefit Obligation [Member]
Regulatory Assets [Line Items]
Total deferred charges	59,100	200,900
Other Regulatory Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	849,933	1,056,909
Not Currently Being Recovered In Rates Charged to Consumers [Member]
Regulatory Assets [Line Items]
Total deferred charges	9,148,731	686,348
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Multi-Stage Energy Storage [Member]
Regulatory Assets [Line Items]
Total deferred charges	1,117,860	124,569
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Regulatory Studies And Other [Member]
Regulatory Assets [Line Items]
Total deferred charges	46,721	360,879
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Regulatory Assets Excluding Other Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	1,164,581	485,448
Not Currently Being Recovered In Rates Charged to Consumers [Member] | NRECA Retirement Security Plan [Member]
Regulatory Assets [Line Items]
Total deferred charges	7,925,050	0
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Post Retirement Benefit Obligation [Member]
Regulatory Assets [Line Items]
Total deferred charges	59,100	200,900
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Other Regulatory Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	$ 7,984,150	$ 200,900

XML

Deferred Charges And Liabilities (Schedule Of Deferred Credits, Or Regulatory Liabilities) (Details) - USD ($)	Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Total deferred liabilities	$ 1,179,414	$ 1,802,389
Refundable Consumer Advances For Construction [Member]
Regulatory Liabilities [Line Items]
Total deferred liabilities	328,360	823,115
Estimated Initial Installation Costs For Meters [Member]
Regulatory Liabilities [Line Items]
Total deferred liabilities	118,854	105,274
Post Retirement Benefit Obligation [Member]
Regulatory Liabilities [Line Items]
Total deferred liabilities	$ 732,200	$ 874,000

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Patronage Capital (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Patronage Capital [Line Items]
Patronage capital	$ 169,996,436	$ 167,447,781
Patronage capital assigned	164,182,580	160,944,929
Patronage capital to be assigned to members	5,813,856	6,502,852
Patronage capital payable	12,008,499	11,108,071
Retirement of capital credits	3,265,201	3,190,124	$ 5,130,381
Excluding Homer Electric Association Retirement [Member]
Patronage Capital [Line Items]
Retirement of capital credits	3,265,201	3,190,124	5,130,381
Excluding Matanuska Electric Association And Homer Electric Association Patronage Capital [Member]
Patronage Capital [Line Items]
Liability of capital credits	$ 2,014,080	2,105,440	$ 1,042,064
Assignable Margins [Member]
Patronage Capital [Line Items]
Secured debt covenant restriction during period	50.00%
Homer Electric Association, Inc. [Member]
Patronage Capital [Line Items]
Return of patronage capital term after expiration date of Power Sales Agreement	5 years
Expiration date of power sales agreement	Dec. 31, 2013
Patronage capital payable	$ 7,900,000	7,900,000
Matanuska Electric Association, Inc. [Member]
Patronage Capital [Line Items]
Patronage capital payable	$ 4,100,000	$ 3,200,000
Minimum [Member] | Aggregate Equities And Margins To Total Liabilities And Equities And Margins [Member]
Patronage Capital [Line Items]
Secured debt covenant restriction during period	30.00%
Patronage Capital [Member]
Patronage Capital [Line Items]
Secured debt covenant restriction at period end	5.00%

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Other Equities (Schedule Of Other Equities) (Details) - USD ($)		Dec. 31, 2016	Dec. 31, 2015
Schedule Of Other Equities [Line Items]
Total other equities		$ 13,828,075	$ 12,527,856
Nonoperating Margins, Prior To 1967 [Member]
Schedule Of Other Equities [Line Items]
Total other equities		23,625	23,625
Donated Capital [Member]
Schedule Of Other Equities [Line Items]
Total other equities		2,001,450	1,877,193
Unclaimed Capital Credit Retirement [Member]
Schedule Of Other Equities [Line Items]
Total other equities	[1]	$ 11,803,000	$ 10,627,038

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

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Debt (Narrative) (Details)		12 Months Ended
	Jun. 29, 2012	Dec. 31, 2016 USD ($) item	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Jan. 11, 2012 USD ($)	Jan. 21, 2011 USD ($)	Nov. 17, 2010 USD ($)
Debt Instrument [Line Items]
Commercial paper		$ 68,200,000	$ 20,000,000
Long-term Obligations		470,442,665	473,024,497
Repayments of long-term debt		$ 48,181,832	23,889,777	$ 24,682,812
Patronage Capital [Member]
Debt Instrument [Line Items]
Secured debt covenant restriction at period end		5.00%
Indenture [Member] | Minimum [Member] | Power Sales Agreements With Members [Member]
Debt Instrument [Line Items]
Assets excluded from lien, term of contract		3 years
Indenture [Member] | Maximum [Member]
Debt Instrument [Line Items]
Assets excluded from lien, term of contract		5 years
Term Loan Facility [Member]
Debt Instrument [Line Items]
Bonds issuance amount		$ 570,600,000
Commercial Paper [Member] | Minimum [Member]
Debt Instrument [Line Items]
Commercial paper repricing term		1 day
Commercial Paper [Member] | Maximum [Member]
Debt Instrument [Line Items]
Commercial paper repricing term		270 days
Revolving Line Of Credit [Member]
Debt Instrument [Line Items]
Line of credit, maximum borrowing capacity		$ 50,000,000
Line of credit, outstanding balance		$ 0	$ 0
Line of credit, borrowing rate description		The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC.
Line of credit, borrowing rate		2.90%	2.90%
Period of time the line of credit needs to be paid down for five consecutive days		12 months
Number of consecutive days debt needs to be paid down to $0 during a twelve month period		5 days
Line of credit, expiration date		Oct. 12, 2017
Amended And Unsecured Credit Agreement [Member] | Unsecured Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum borrowing capacity		$ 100,000,000
Yield margins for interest multiplier to total interest expense | item		1.10
Line of credit, borrowing rate description		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).
Line of credit, expiration date		Nov. 17, 2016
Line of credit facility, first amendment date		May 04, 2012
Line of credit facility, second amendment date		Jun. 29, 2012
Facility fee	0.175%
Amended And Unsecured Credit Agreement [Member] | Unsecured Credit Facility [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Variable rate	1.075%
Amended And Unsecured Credit Agreement [Member] | Unsecured Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of credit, maximum borrowing capacity		$ 150,000,000
Amended And Unsecured Credit Agreement [Member] | Unsecured Credit Facility [Member] | Commercial Paper [Member]
Debt Instrument [Line Items]
Line of credit, maximum borrowing capacity							$ 300,000,000
Line of credit, commencement date		Nov. 17, 2010
Credit Agreement [Member] | Unsecured Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit, maximum borrowing capacity		$ 150,000,000
Line of credit, borrowing rate description		one month LIBOR plus 90.0 basis points, along with a 10.0 basis points facility fee (based on an A/A2/A unsecured debt rating).
Line of credit, commencement date		Jun. 13, 2016
Line of credit, expiration date		Jun. 13, 2021
Facility fee		0.10%
Credit Agreement [Member] | Unsecured Credit Facility [Member] | LIBOR [Member]
Debt Instrument [Line Items]
Variable rate		0.90%
2011 CoBank Note [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Long-term Obligations		$ 0	$ 24,941,165
Repayments of long-term debt		22,200,000
2016 CoBank Note [Member]
Debt Instrument [Line Items]
Bonds issuance amount		$ 45,600,000
Bonds maturity date		Mar. 15, 2031
Long-term Obligations		$ 43,776,000	$ 0
2011 Series A Bonds [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Bonds issuance amount						$ 275,000,000
Bonds commencement payment date		Sep. 15, 2011
Note commencement date		Jan. 21, 2011
2012 Series A Bonds [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Bonds issuance amount					$ 250,000,000
Bonds commencement payment date		Sep. 15, 2012
Note commencement date		Jan. 11, 2012
CoBank Master Loan Agreement [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Yield margins for interest multiplier to total interest expense | item		1.10
Line of credit facility, first amendment date		Jun. 30, 2016
Second Amended and Restated Master Loan Agreement [Member] | Indenture [Member]
Debt Instrument [Line Items]
Yield margins for interest multiplier to total interest expense | item		1.10
Assignable Margins [Member]
Debt Instrument [Line Items]
Secured debt covenant restriction during period		50.00%
Aggregate Equities And Margins To Total Liabilities And Equities And Margins [Member] | Minimum [Member]
Debt Instrument [Line Items]
Secured debt covenant restriction during period		30.00%

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Debt (Schedule Of Debt Issuance Costs Associated With Long-Term Obligations) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Obligations	$ 470,442,665	$ 473,024,497
Less current installments	24,836,667	24,115,980
Less unnamortized debt issuance costs	2,715,745	2,680,897
Total long-term obligations, excluding current installments	442,890,253	446,227,620
2011 CoBank Note [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 0	$ 24,941,165
Variable interest rate	2.78%	2.78%
Maturity year	2003
2011 Series A Bond Of 4.20% Maturing 2031 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 67,500,000	$ 72,000,000
Interest rate	4.20%	4.20%
Maturity year	2031
2011 Series A Bond Of 4.75% Maturing 2041 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 154,166,665	$ 160,333,332
Interest rate	4.75%	4.75%
Maturity year	2041
2012 Series A Bond Of 4.01% Maturing 2032 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 60,000,000	$ 63,750,000
Interest rate	4.01%	4.01%
Maturity year	2032
2012 Series A Bond Of 4.41% Maturing 2042 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 95,000,000	$ 102,000,000
Interest rate	4.41%	4.41%
Maturity year	2042
2012 Series A Bond Of 4.78% Maturing 2042 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 50,000,000	$ 50,000,000
Interest rate	4.78%	4.78%
Maturity year	2042
2016 CoBank Note [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 43,776,000	$ 0
Interest rate	2.58%	2.58%
Maturity year	2031

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Debt (Schedule Of Maturities Of Long-Term Obligations) (Details)	Dec. 31, 2016 USD ($)
Debt Instrument [Line Items]
2017	$ 24,836,667
2018	24,608,667
2019	24,608,667
2020	24,836,667
2021	18,064,667
Thereafter	353,487,330
Total long-term obligations	470,442,665
2011 Series A Bonds [Member]
Debt Instrument [Line Items]
2017	10,666,667
2018	10,666,667
2019	10,666,667
2020	10,666,667
2021	10,666,667
Thereafter	168,333,330
Total long-term obligations	221,666,665
2011 CoBank Note [Member]
Debt Instrument [Line Items]
2017	3,420,000
2018	3,192,000
2019	3,192,000
2020	3,420,000
2021	3,648,000
Thereafter	26,904,000
Total long-term obligations	43,776,000
2012 Series A Bonds [Member]
Debt Instrument [Line Items]
2017	10,750,000
2018	10,750,000
2019	10,750,000
2020	10,750,000
2021	3,750,000
Thereafter	158,250,000
Total long-term obligations	$ 205,000,000

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Debt (Schedule Of Average Commercial Paper Balances Outstanding And Weighted Average Interest Rates) (Details) - Commercial Paper [Member] - USD ($) $ in Millions	1 Months Ended
	Dec. 31, 2016	Nov. 30, 2016	Oct. 31, 2016	Sep. 30, 2016	Aug. 31, 2016	Jul. 31, 2016	Jun. 30, 2016	May 31, 2016	Apr. 30, 2016	Mar. 31, 2016	Feb. 29, 2016	Jan. 31, 2016
Short-term Debt [Line Items]
Average Balance	$ 63.7	$ 60.8	$ 63.5	$ 60.0	$ 54.2	$ 47.3	$ 76.0	$ 78.2	$ 55.1	$ 30.5	$ 16.9	$ 16.1
Weighted Average Interest Rate	0.86%	0.65%	0.65%	0.65%	0.63%	0.66%	0.62%	0.60%	0.60%	0.60%	0.60%	0.61%

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Debt (Schedule Of Additional Information Regarding Series A Bonds) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Carrying Value	$ 470,442,665
Term Loan Facility [Member]
Debt Instrument [Line Items]
Issue Amount	570,600,000
Carrying Value	$ 470,443,000
2011 Series A Bond Of 4.20% Maturing 2031 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2031
Average Life (Years)	7 years 2 months 12 days
Interest Rate	4.20%	4.20%
Issue Amount	$ 90,000,000
Carrying Value	$ 67,500,000
2011 Series A Bond Of 4.75% Maturing 2041 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2041
Average Life (Years)	12 years 2 months 12 days
Interest Rate	4.75%	4.75%
Issue Amount	$ 185,000,000
Carrying Value	$ 154,167,000
2012 Series A Bond Of 4.01% Maturing 2032 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2032
Average Life (Years)	7 years 8 months 12 days
Interest Rate	4.01%	4.01%
Issue Amount	$ 75,000,000
Carrying Value	$ 60,000,000
2012 Series A Bond Of 4.41% Maturing 2042 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2042
Average Life (Years)	14 years 9 months 18 days
Interest Rate	4.41%	4.41%
Issue Amount	$ 125,000,000
Carrying Value	$ 95,000,000
2012 Series A Bond Of 4.78% Maturing 2042 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2042
Average Life (Years)	15 years 8 months 12 days
Interest Rate	4.78%	4.78%
Issue Amount	$ 50,000,000
Carrying Value	$ 50,000,000
2016 CoBank Note [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2031
Average Life (Years)	6 years 2 months 12 days
Interest Rate	2.58%	2.58%
Issue Amount	$ 45,600,000
Carrying Value	$ 43,776,000

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Employee Benefit Plans (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Deferred compensation	$ 907,836	$ 763,913
Number of days of severance pay per year of service	14 days
Maximum number of days of severance pay	182 days
Number of years of service	13 years
NRECA Retirement Security Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Prepayment multiplier	2.50%
Prepayment, effect on billing rate	25.00%
Period of billing rate reduction related to prepayment	15 years
Prepayment amount	$ 7,900,000
Prepayment amortization period	11 years
Multiemployer Plans, Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	$ 6,700,000	6,700,000	$ 6,800,000
Union Health and Welfare Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	4,500,000	4,500,000	4,500,000
Non-Union Health And Welfare Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	2,800,000	2,600,000	2,900,000
Money Purchase Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	$ 132,300	$ 133,600	$ 149,200

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Employee Benefit Plans (Schedule Of Information Regarding Individually Significant Pension Plans) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Alaska Electrical Pension Plan [Member]
Multiemployer Plans [Line Items]
Employer Identification Number	[1]	926005171
Plan Number	[1]	001
Year-end Date	[1]	December 31
Expiration Date of CBA's	[1]	Jun. 30, 2017
Subject to Funding Improvement Plan	[1]	No
Surcharge Paid	[1]	NA
Zone Status	[1]	Green
Required minimum contributions	[1]	None
Contributions (in millions)	[1]	$ 3.2	$ 3.1	$ 3.3
Contributions > 5% of total plan contributions	[1]	Yes
NRECA Retirement Security Plan [Member]
Multiemployer Plans [Line Items]
Employer Identification Number	[1]	530116145
Plan Number	[1]	333
Year-end Date	[1]	December 31
Subject to Funding Improvement Plan	[1],[2]	No
Surcharge Paid	[1],[2]	NA
Zone Status	[1],[3]	NA
Required minimum contributions	[1]	N/A
Contributions (in millions)	[1]	$ 3.5	$ 3.5	$ 3.5
Contributions > 5% of total plan contributions	[1]	No

[1] The Alaska Electrical Pension Plan financial statements are publicly available. The NRECA RS Plan financial statements are available on Chugach's website at www.chugachelectric.com.

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

[3] A "zone status" determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006.

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Bradley Lake Hydroelectric Project (Narrative) (Details)	12 Months Ended
	Dec. 31, 2016 USD ($) MWh MW	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 15,774,733	$ 19,599,994	$ 15,608,396
Bradley Lake Hydroelectric Project [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Percentage share of power purchased	30.40%
Amount of committed purchased power | MW	27.4
Threshold percentage for increasing plant costs	25.00%
Estimated entitled additional energy output percentage	30.40%
Purchased power	$ 5,662,522	$ 5,663,304	$ 5,228,907
Revenue Bonds [Member] | Alaska Energy Authority [Member] | Bradley Lake Hydroelectric Project [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Bonds issuance amount	166,000,000
Portion of outstanding debt	19,000,000
Possible annual expenditures upon default	$ 6,000,000
Maximum [Member] | Bradley Lake Hydroelectric Project [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Estimated increase in annual energy output | MWh	40,000

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Bradley Lake Hydroelectric Project (Schedule Of Bradley Lake Information) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
Long-term Contract for Purchase of Electric Power [Line Items]
Plant in service	$ 1,210,969,809				$ 1,144,075,666				$ 1,210,969,809		$ 1,144,075,666
Note outstanding balance	470,442,665								470,442,665
Interest expense	$ 5,341,242	$ 5,427,440	$ 5,247,404	$ 5,385,211	$ 5,415,131	$ 5,428,774	$ 5,381,167	$ 5,589,373	$ 21,401,297		$ 21,814,445	$ 22,800,706
Bradley Lake Hydroelectric Project [Member] | Alaska Energy Authority [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Plant in service			163,531,000							$ 163,531,000
Note outstanding balance			53,495,000							53,495,000
Interest expense										3,177,000
Bradley Lake Hydroelectric Project [Member] | Alaska Energy Authority [Member] | Proportionate Share [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Plant in service			49,713,000							49,713,000
Note outstanding balance			$ 16,262,000							16,262,000
Interest expense										$ 966,000

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Eklutna Hydroelectric Project (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Jointly Owned Utility Plant Interests [Line Items]
Net utility plant	$ 714,871,678				$ 674,876,440				$ 714,871,678	$ 674,876,440
Accumulated depreciation	496,098,131				469,199,226				496,098,131	469,199,226
Total operating expenses	$ 47,000,307	$ 40,308,301	$ 41,472,710	$ 42,359,071	42,182,178	$ 39,667,546	$ 43,490,558	$ 63,451,276	$ 171,140,389	188,791,558	$ 252,972,879
Eklutna Hydroelectric Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage ownership	30.00%								30.00%
Net utility plant	$ 4,229,167				4,401,440				$ 4,229,167	4,401,440
Accumulated depreciation	$ 2,442,175				$ 2,203,659				2,442,175	2,203,659
Total operating expenses									$ 532,678	$ 689,501	$ 761,613
Matanuska Electric Association, Inc. [Member] | Eklutna Hydroelectric Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage ownership	17.00%								17.00%
Municipal Light & Power [Member] | Eklutna Hydroelectric Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage ownership	53.00%								53.00%

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Beluga River Unit (Narrative) (Details)		3 Months Ended								12 Months Ended
	Feb. 04, 2016 USD ($) a Mcf	Dec. 31, 2016 USD ($) Mcf	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($) mi Mcf	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Revenue		$ 57,741,954	$ 45,132,973	$ 44,622,517	$ 50,250,135	$ 50,640,703	$ 43,109,512	$ 47,697,820	$ 74,973,117	$ 197,747,579	$ 216,421,152	$ 281,318,513
Beluga River Unit [Member]
Business Acquisition [Line Items]
Date of Purchase and Sale Agreement										Feb. 04, 2016
Total purchase price	$ 148,000,000
Cash consideration		$ 44,403,922								$ 44,403,922
Working interest ownership percentage	30.00%	10.00%								10.00%
Number of lease acres | a	15,500
Number of lease acres in Unit / Participating Area | a	8,200
Number of lease acres held by Unit | a	7,300
Number of miles from Anchorage | mi										35
Acquisition costs		$ 1,500,000								$ 1,500,000
Amount of gas acquired | Mcf	69,099	84								84
Revenue										$ 2,800,000
Lifted amount of gas in proven developed reserves | Mcf		1,900,000								1,900,000
Remaining amount of gas in proven developed reserves | Mcf		25,100,000								25,100,000
Estimated useful life										18 years
Proved developed producing reserves | Mcf		27,000,000								27,000,000
Municipal Light & Power [Member] | Beluga River Unit [Member]
Business Acquisition [Line Items]
Working interest ownership percentage	70.00%	56.70%								56.70%
ConocoPhillips (COP) [Member] | Beluga River Unit [Member]
Business Acquisition [Line Items]
Working interest ownership percentage		33.30%								33.30%
ConocoPhillips (COP) [Member] | Deep Oil Resources [Member]
Business Acquisition [Line Items]
Working interest ownership percentage	67.00%
Hilcorp Alaska, LLC [Member] | Beluga River Unit [Member]
Business Acquisition [Line Items]
Working interest ownership percentage		33.30%								33.30%
ENSTAR [Member] | ConocoPhillips (COP) [Member]
Business Acquisition [Line Items]
Expiration year of Gas Sale and Purchase Agreement										2017

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Beluga River Unit (Schedule Of Acquisition Allocation) (Details) - Beluga River Unit [Member]	Dec. 31, 2016 USD ($)
Business Acquisition [Line Items]
Proved Developed Reserves	$ 33,693,922
Proved Undeveloped Reserves	10,710,000
Asset Retirement Obligation	3,523,409
Utility plant	47,927,331
Cost of removal obligation	(3,523,409)
Cash Consideration	$ 44,403,922

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Commitments And Contingencies (Narrative) (Details) MMcf in Thousands, Mcf in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016 USD ($) Mcf MMcf	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jun. 30, 2015 USD ($)	Mar. 31, 2015 USD ($)	Dec. 31, 2016 USD ($) $ / kWh contract item Mcf MMcf	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)	Feb. 04, 2016
Other Commitments [Line Items]
Contingency accruals	$ 0								$ 0
Operating revenues	57,741,954	$ 45,132,973	$ 44,622,517	$ 50,250,135	$ 50,640,703	$ 43,109,512	$ 47,697,820	$ 74,973,117	$ 197,747,579	$ 216,421,152	$ 281,318,513
Percentage of power generated from gas									77.00%	86.00%
Patronage capital payable	12,008,499				11,108,071				$ 12,008,499	$ 11,108,071
Regulatory initial cost charge per KWH | $ / kWh									0.000626
Regulatory current cost charge per KWH | $ / kWh									0.000675
Percentage of three year average of gross retail revenue to be spent on underground lines									2.00%
Average of gross revenue to determine expenditure for underground lines									3 years
Percentage of retail bill collected to move existing overhead lines underground									2.00%
Other current liabilities	3,234,586				8,076,903				$ 3,234,586	$ 8,076,903
Beluga Power Plant [Member]
Other Commitments [Line Items]
Percentage of power generated from gas									9.00%	30.00%
Southcentral Power Project Plant [Member]
Other Commitments [Line Items]
Percentage of power generated from gas									88.00%	61.00%
Matanuska Electric Association, Inc. [Member]
Other Commitments [Line Items]
Patronage capital payable	4,100,000				3,200,000				$ 4,100,000	$ 3,200,000
Homer Electric Association, Inc. [Member]
Other Commitments [Line Items]
Power contracts expiration date									Dec. 31, 2013
Patronage capital payable	$ 7,900,000				7,900,000				$ 7,900,000	7,900,000
ConocoPhillips (COP) [Member]
Other Commitments [Line Items]
Commencement date of long term contract for purchase of gas supply									Aug. 21, 2009
Expiration date of long term contract for purchase of gas supply									Dec. 31, 2016
Estimated amount of gas under contract | MMcf	62								62
Percentage of met natural gas needs									70.00%
Hilcorp Alaska, LLC [Member]
Other Commitments [Line Items]
Commencement date of long term contract for purchase of gas supply									Jan. 01, 2015
Expiration date of long term contract for purchase of gas supply									Mar. 31, 2018
Hilcorp Alaska, LLC, Purchase Commitment Amendment 1 [Member]
Other Commitments [Line Items]
Commencement date of long term contract for purchase of gas supply									Sep. 15, 2014
Expiration date of long term contract for purchase of gas supply									Mar. 31, 2019
Percentage of met natural gas needs									100.00%
Hilcorp Alaska, LLC, Purchase Commitment Amendment 2 [Member]
Other Commitments [Line Items]
Commencement date of long term contract for purchase of gas supply									Sep. 08, 2015
Expiration date of long term contract for purchase of gas supply									Mar. 31, 2023
Estimated amount of gas under contract | Mcf	60.0								60.0
Percentage of met natural gas needs									100.00%
Marathon Alaska Production, LLC [Member]
Other Commitments [Line Items]
Commencement date of long term contract for purchase of gas supply									Apr. 01, 2011
Expiration date of long term contract for purchase of gas supply									Mar. 31, 2023
Estimated amount of gas under contract | MMcf	49								49
Number of contract extensions | contract									2
Percentage of met natural gas needs									100.00%
Moving Overhead Lines Underground [Member]
Other Commitments [Line Items]
Other current liabilities	$ 2,507,482				$ 5,184,551				$ 2,507,482	$ 5,184,551
Beluga River Unit [Member]
Other Commitments [Line Items]
Operating revenues									$ 2,800,000
Estimated amount of gas under contract | Mcf	25.1								25.1
Working interest ownership percentage	10.00%								10.00%			30.00%
Beluga River Unit [Member] | Municipal Light & Power [Member]
Other Commitments [Line Items]
Working interest ownership percentage	56.70%								56.70%			70.00%
International Brotherhood of Electrical Workers [Member]
Other Commitments [Line Items]
Percentage of employees belonging to unions	70.00%								70.00%
Number of collective bargaining agreements | item									3
Expiration date of collective bargaining agreements									Jun. 30, 2021
Hotel Employees and Restaurant Employees [Member]
Other Commitments [Line Items]
Number of collective bargaining agreements | item									1
Expiration date of collective bargaining agreements									Jun. 30, 2021

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Commitments And Contingencies (Schedule Of Cost Of Fuel Purchased And Transported As A Percentage Of Total Fuel Costs) (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Hilcorp Alaska, LLC [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	56.90%	30.30%	50.40%
ConocoPhillips (COP) [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	32.00%	58.70%	43.60%
AIX Energy, LLC [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	0.70%	4.70%	0.00%
ENSTAR [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	4.70%	3.30%	2.00%
Harvest (Hilcorp) Pipeline [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	3.20%	1.60%	3.00%
Miscellaneous [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	2.50%	1.40%	1.00%

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Subsequent Events (Details) - Subsequent Event [Member] - 2017 Series A Bonds, 3.43%, Maturing March 15, 2037 [Member]	Mar. 17, 2017 USD ($)
Subsequent Event [Line Items]
Bonds issuance amount	$ 40,000,000
Bonds maturity date	Mar. 15, 2037
Interest Rate	3.43%
Average Life (Years)	10 years

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Quarterly Results Of Operations (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Results Of Operations [Abstract]
Operating revenues	$ 57,741,954	$ 45,132,973	$ 44,622,517	$ 50,250,135	$ 50,640,703	$ 43,109,512	$ 47,697,820	$ 74,973,117	$ 197,747,579	$ 216,421,152	$ 281,318,513
Operating expenses	47,000,307	40,308,301	41,472,710	42,359,071	42,182,178	39,667,546	43,490,558	63,451,276	171,140,389	188,791,558	252,972,879
Net interest	5,341,242	5,427,440	5,247,404	5,385,211	5,415,131	5,428,774	5,381,167	5,589,373	21,401,297	21,814,445	22,800,706
Net operating margins	5,400,405	(602,768)	(2,097,597)	2,505,853	3,043,394	(1,986,808)	(1,173,905)	5,932,468	5,205,893	5,815,149	5,544,928
Nonoperating margins	231,683	125,332	127,871	123,077	368,403	79,028	126,010	114,262	607,963	687,703	970,617
Assignable margins	$ 5,632,088	$ (477,436)	$ (1,969,726)	$ 2,628,930	$ 3,411,797	$ (1,907,780)	$ (1,047,895)	$ 6,046,730	$ 5,813,856	$ 6,502,852	$ 6,515,545