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, 2017

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

(Note:  The registrant is a voluntary filer and not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934.  Although not subject to these filing requirements, the registrant has filed all reports that would have been required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months had the registrant been subject to such requirements.)

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	☐
		Emerging growth 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.

2017 Form 10-K Annual Report

Table of Contents

PART I			Page
	Item 1.	Business	2
	Item 1A.	Risk Factors	7
	Item 1B.	Unresolved Staff Comments	13
	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	83
	Item 9A.	Controls and Procedures	83
	Item 9B.	Other Information	84
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	84
	Item 11.	Executive Compensation	88
	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	96
PART IV
	Item 15.	Exhibits, Financial Statement Schedules	97
		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 an 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 $0.000899 per kWh of retail electricity sold. The RCC is assessed to fund the

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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 291 employees as of March 12, 2018. 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 a CBA with the Hotel Employees and Restaurant Employees (HERE). All of the CBA’s have been renewed through June 30, 2021. The three IBEW CBAs provide for wage and pension contribution increases in all years and include health and welfare premium cost sharing provisions. The HERE CBA 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, 2017, we had one wholesale customer, 67,992 retail members, and 84,106service 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.  Periodically, we sell available generation, in excess of our own needs, to Matanuska Electric Association, Inc. (MEA), Homer Electric Association, Inc. (HEA), Golden Valley Electric Association, Inc. (GVEA) and Anchorage Municipal Light & Power (ML&P).

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, Changes in Equities and Margins, and Cash Flows 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 2017, 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 2017,  81% of Chugach’s power, including purchased power, was generated from gas. Of that gas-fired generation, 81% took place at SPP and 14% took place at Beluga. 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 1,724miles 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, 2017, we sold 1.2 billion kWh of electrical power.

Customer Revenue from Sales

Economy energy/other includes sales to GVEA, MEA, HEA 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, 2017,  we had 67,992 members receiving power from 84,106services, 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, 2017, 2016 and 2015 is discussed in “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations – Year ended December 31, 2017, compared to the year ended December 31, 2016, and the year ended December 31, 2016, compared to the year ended December 31, 2015 – Revenues.”

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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 $5.9 million, $4.9 million, and $30.9 million in revenues for the years ended December 31, 2017, 2016 and 2015, respectively.

Seward

We currently provide nearly all the power needs of the City of Seward. Sales to Seward represented approximately 5%, 5%, and 4% of Chugach’s total energy sales for the years ended December 31, 2017, 2016, and 2015, 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 automatic five-year extensions 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.

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.

We made non-firm, economy energy sales to GVEA, HEA, MEA, and ML&P on an as needed basis.Total non-firm sales were 48,526 MWh, 25,000 MWh, and 105,815 MWh for 2017, 2016, and 2015, respectively.

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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 Chugach’s 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.

Chugach expects to continue to recover changes in its 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 minimum margins for interest of at least 1.10 times interest charges for each fiscal year.

For the years ended December 31, 2017, 2016 and 2015, our Margins for Interest/Interest (MFI/I) was 1.27, 1.27, and 1.29, respectively. For the same periods, our TIER was 1.28, 1.27, and 1.30, respectively.

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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)	2018	2019	2020	2021	2022
Retail	1,081,499	1,070,110	1,058,950	1,061,598	1,064,252
Wholesale	57,676	57,099	56,529	56,670	56,811
Total	1,139,175	1,127,209	1,115,479	1,118,268	1,121,063

Energy sales are expected to slightly decline due to slow economic growth and progress in energy efficiency and conservation from 2018 to 2020, and then slightly rebound in 2021 and 2022. These projections are based on assumptions that management believes to be reasonable as of the date the projections were made. The occurrence of a significant change in any of the assumptions could affect a change in the projected sales forecast.

Item 1A – Risk Factors

Chugach’s consolidated financial results will be impacted by weather, the economy of our service territory, fuel availability and prices, and the decisions of regulatory agencies. Our creditworthiness will be affected by national and international monetary trends, general market conditions and the expectations of the investment community, all of which are largely beyond our control. In addition, the following statements highlight risk factors that, 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 March 17, 2017, Chugach issued $40,000,000 of First Mortgage Bonds, 2017 Series A, due March 15, 2037. The bonds were issued for general corporate purposes. The 2017 Series A Bonds will mature on March 15, 2037, and bear interest at 3.43%. Interest will be paid each

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March 15 and September 15, commencing on September 15, 2017. The 2017 Series A Bonds require principal payments 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.

Chugach is expected to continue to issue commercial paper in 2018, 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. The cost of raising money in the debt capital markets could increase while the availability of funds from those markets could diminish as a result of volatile global financial markets and economic conditions.

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" (Watch Evolving), respectively. Fitch’s Watch Evolving is driven by Chugach’s planned purchase, subject to voter and regulatory approval, of ML&P, see “Item 7 – Management's Discussion and Analysisof Financial Condition and Results of Operations – Potential ML&P Acquisition.” 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.

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,  a 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 multi-employer 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

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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 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 11 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 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 2017, 81% of our power was generated from natural gas. Our primary sources of natural gas in 2017 were Hilcorp, Chugach’s 10% share of the Beluga River Unit, and Furie Operating Alaska, LLC. 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) and AIX Energy, LLC, which provide a structure to purchase supplemental gas, adding diversity in Chugach’s sources of natural gas to meet system load requirements.

On May 1, 2017, the RCA approved the Furie Agreement.   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 March 31, 2033, and interruptible gas purchases available to Chugach immediately 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 

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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, on a firm and interruptible basis.  The initial price for firm gas is $7.16 per thousand cubic feet (Mcf) beginning April 1, 2023 and escalates annually rising to $7.98 per Mcf on April 1, 2032, the last year of the contract.

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 beginning in 2016. 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 developed and in production by Furie and another considered for development by BlueCrest Energy, Inc. Furie has constructed an offshore gas production platform and has achieved commercial 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.

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 1.6 Bcf in 2017. Chugach is entitled to withdraw gas at a rate of up to 31 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

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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 under-recovered $4.9 million at December 31, 2017, and had over-recovered $3.8 million at December 31, 2016. 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 is a participant in the Simplified Rate Filing (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, with filings made either on a quarterly or semi-annual basis. Chugach is a participant on a quarterly filing schedule basis. See “Item 8-Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Simplified Rate Filings.”

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. While awaiting the court decision, an Executive Order promoting energy independence and economic growth was issued on March 28, 2017, by the President instructing the EPA to review the Clean Power Plan. The EPA is directed to review the Clean Power Plan rule and either revise or withdraw the proposed rule. On October 10, 2017, the EPA initiated a Proposed Repeal of the

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Clean Power Plan.  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 increased 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 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 power 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

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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 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.

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

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Item 2 – Properties

General

As of December 31, 2017, 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 Eklutna Generation Station (EGS). We also purchased power from FIW.

The Beluga, IGT and SPP facilities are fueled by natural gas. We own our offices and headquarters, located adjacent to IGT and SPP in Anchorage. We also lease warehouse space for some generation, transmission and distribution inventory (including a small amount of office space).

Generation Assets

We own the land and improvements comprising our generating facilities at Beluga, IGT and SPP.  Our principal generation assets are in two plants, Beluga and SPP. With SPP in operation, the Beluga units are used for peaking, and 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 are inspected annually with combustion and hot gas path parts replaced according to their condition or as recommended by the manufacturer. 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 2017. The gas turbine generators of Units 11, 12, and 13 receive two internal combustion system inspections each and one full package inspection annually. In 2017, Unit 13 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 and later installed in Unit 11 when it began to show evidence of bearing failure, per the OEM recommendation.  Unit 10 steam turbine received a scheduled inspection consistent with OEM specifications. All three steam-generating boilers were internally inspected as well as hydrotested in accordance with OEM recommendations.

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The Cooper Lake Hydroelectric Project is partially located on federal lands. Chugach owns, operates and maintains the Cooper Lake project subject to a 50-year license granted to us by FERC in August of 2007. As part of the relicensing process, a Relicensing Settlement Agreement (RSA) was 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; designed to replace colder water flowing into the Cooper Creek drainage from Stetson Creek with warmer Cooper Lake water. This project included a Stetson Creek Diversion (Dam), Pipeline (Conveyance System) and Cooper Lake Outlet Works. 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 August of 2016 and 2017.

The Eklutna Hydroelectric Project is located on federal land subject to a United States Bureau of Land Management right-of-way grant issued in October of 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 2017, percentages of contribution and other historical information for all Chugach generation units.

Facility	Commercial Operation Date	Nomenclature	Rating (MW)(1)		Run Hours (2017)		Percent of Total Run Hours	Percent of Time Available
Beluga Power Plant (2)
1	1968	GE Frame 5	19.6		231.8		0.53	86.2
2	1968	GE Frame 5	19.6		256.6		0.59	89.3
3	1973	GE Frame 7	64.8		594.0		1.36	73.6
5	1975	GE Frame 7	68.7		3,337.5		7.66	94.3
6	1976	GE 11DM-EV	79.2		855.7		1.96	91.3
7	1978	GE 11DM-EV	80.1		1,348.2		3.09	91.6
			332.0
Cooper Lake Hydroelectric Project
1	1960	BBC MV 230/10	9.6		875.0		2.01	96.7
2	1960	BBC MV 230/10	9.6		2,854.0		6.55	96.7
			19.2
IGT Power Plant (7)
1	1964	GE Frame 5	14.1		9.5		0.02	91.5
2	1965	GE Frame 5	14.1		8.7		0.02	100.0
			28.2
Southcentral Power Project
10	2013	Mitsubishi SC1F-29.5 (6)	40.2	(5)	8,144.5		18.69	93.0
11	2013	GE LM6000 PF	33.3	(5)	8,359.9		19.19	96.4
12	2013	GE LM6000 PF	33.3	(5)	8,310.2		19.07	94.9
13	2013	GE LM6000 PF	33.3	(5)	8,387.5		19.26	95.7
			140.1
Eklutna Hydroelectric Project
1	1955	Newport News	5.8	(3)	N/A	(4)		42.6
2	1955	Oerlikon custom	5.9	(3)	N/A	(4)		94.7
			11.7
System Total			531.2		43,573.1		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, 2017, our transmission and distribution assets included 43 substations and 434 miles of transmission lines, which included Chugach’s share of the Eklutna transmission line, 896 miles of overhead distribution lines and 828 miles of underground distribution line. We own the land on which 25 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 (North - South Runway) are authorized by the State Department of Transportation and Public Facilities, Ted Stevens Anchorage International Airport; the East Terminal Site (Six Mile) is under rights from Joint Base Elmendorf-Richardson; the West Terminal Site is authorized by 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 authorized by the State; the Portage Substation has a permit from the Alaska Railroad Corporation (ARRC); the Summit Lake Substation is on land recently conveyed to the Kenai Peninsula Borough (permit pending) and a permit 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 authorized 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 the FERC License. Most of Chugach’s transmission, sub-transmission and distribution lines are either on public lands under rights from federal, state, municipal, borough agencies, 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 1991) or when the revenue bond principal is repaid, whichever is longer. The agreement may be renewed for successive 40-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 $16.3 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 Battle Creek Diversion Project (Project) is a project to increase water available for generation by constructing a diversion on the West Fork of Upper Battle Creek to divert flows to Bradley Lake, increasing annual energy output by an estimated 37,000 MWh. The Bradley Lake Project Management Committee (BPMC) approved the project October 13, 2017, as amended December 1,

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2017, and December 6, 2017.  The Project cost is estimated at $47.0 million and the BMPC approved financing in this amount on December 6, 2017.  The project is estimated to begin in the Spring of 2018 with an estimated completion date of 2020.  Not all Bradley Lake purchasers are participating in the development and resulting benefits of the Project at this time, although they have preserved their ability to participate in the Project at a later date.  Chugach would be entitled to 39.38% of the additional energy produced if no additional participants elect to join.

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 BRU by jointly purchasing, in partnership with ML&P, ConocoPhillips’ 1/3 Working Interest Ownership of the BRU.  In 2017 Chugach received 1.4 Bcf from the BRU field at the field’s delivery meter as a WIO. Of that gas volume received Chugach allocated gas deliveries of 875 MMcf to the ConocoPhillips-ENSTAR contract (average price of $7.57 per Mcf) and retained 506 MMcf for Chugach native use in thermal generation, which had a weighted average transfer price of $4.64 per Mcf.

Fuel Supply

In 2017, 81% of our power was generated from natural gas. Total gas purchased and produced in 2017 was approximately 9.3 Bcf. All of the production came from Cook Inlet, Alaska. The contract with Hilcorp provided 89%, Furie provided 5%, Chugach’s 10% share of the Beluga River Unit gas field provided 5%, and the balance from minor purchases from AIX and CIE. Of the 9.3 Bcf of gas purchased and produced, 0.9Bcf 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 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. The gas contract with Furie currently provides Chugach with additional purchase options, on a firm and interruptible basis, and will provide both firm and non-firm gas supplies beginning on April 1, 2023 and ending March 31, 2033. 

Hilcorp

Chugach entered into a contract with Hilcorp to provide gas beginning January 1, 2015, and through multiple amendments, now extends through March 31, 2023. The total amount of gas under contract is currently estimated to be 60 Bcf. Pricing for the 2017 term of the Hilcorp contract was set at $7.73 per Mcf.

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

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part of the filing, Chugach 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 March 31, 2033, and interruptible gas purchases available to Chugach immediately 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, 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 Furie Agreement.

On May 1, 2017, the RCA approved the Furie Agreement. The RCA also approved recovery of costs associated with the Furie Agreement through its fuel and purchased power cost adjustment process.

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.

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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 beginning June 6, 2016, and expiring March 31, 2017. This agreement capped the price of gas at $5.75 per Mcf and the total volume at 500,000 Mcf. The ML&P agreement provided Chugach the ability to further diversify its gas supply portfolio, with no minimum purchase requirements.

Natural Gas Transportation Contracts

The terms of the 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

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).

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.

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 increased from the original “TP1” levels to the new “DOE-2016” levels.

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All new transformers are DOE-2016 compliant. 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 District of Columbia (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 D.C. Circuit decides the case, or until the disposition of a petition to the Supreme Court on the issue. On September 27, 2016, the U.S. Court of Appeals for the D.C. Circuit heard oral arguments challenging the legality of the Clean Power Plan. While awaiting the court decision, an Executive Order promoting energy independence and economic growth was issued March 28, 2017, by the President instructing the EPA to review the Clean Power Plan. The EPA is directed to review the Clean Power Plan rule and either revise or withdraw the proposed rule. On October 10, 2017, the EPA initiated a Proposed Repeal of the Clean Power Plan. 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	2017		2016		2015		2014		2013
Electric plant, net:
In service	$	689,595,912	$	696,415,738	$	659,275,066	$	657,899,592	$	670,476,634
Construction work in progress		17,952,573		18,455,940		15,601,374		21,567,341		28,674,163
Electric plant, net		707,548,485		714,871,678		674,876,440		679,466,933		699,150,797
Other assets		129,970,259		121,284,452		110,437,674		126,244,688		139,033,241
Total assets	$	837,518,744	$	836,156,130	$	785,314,114	$	805,711,621	$	838,184,038
Capitalization:
Long-term debt		456,327,846		442,890,253		446,227,620		473,024,497		496,914,274
Equities and margins		189,301,294		185,515,525		181,637,381		176,925,299		175,795,865
Total capitalization	$	645,629,140	$	628,405,778	$	627,865,001	$	649,949,796	$	672,710,139
Equity Ratio1		29.3%		29.5%		28.9%		27.2%		26.1%
Operations Data
Operating revenues	$	224,688,669	$	197,747,579	$	216,421,152	$	281,318,513	$	305,308,427
Operating expenses		197,217,684		171,140,389		188,791,558		252,972,879		278,738,497
Interest expense		22,366,034		21,856,095		22,194,290		23,264,041		24,691,582
Capitalized interest		(164,898)		(454,798)		(379,845)		(463,335)		(1,310,110)
Net operating margins		5,269,849		5,205,893		5,815,149		5,544,928		3,188,458
Nonoperating margins		778,875		607,963		687,703		970,617		7,355,585
Assignable margins	$	6,048,724	$	5,813,856	$	6,502,852	$	6,515,545	$	10,544,043
Margins for Interest Ratio2		1.27		1.27		1.29		1.28		1.43

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, 2017, 2016 and 2015 was $21,424,095, $21,168,967 and $21,811,573, 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 (currently 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, 2017, compared to the year ended December 31, 2016, and the year ended December 31, 2016 compared to the year ended December 31, 2015 – Expenses.”  We achieved TIERs for the past five years as follows:

1	24
Year	TIER
2017	1.28
2016	1.27
2015	1.30
2014	1.29
2013	1.43

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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. In general, 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.

In 2017, Chugach submitted quarterly SRF filings which resulted in a 3.0% decrease to system demand and energy rates effective July 1, 2017, and an increase of 1.9% for rates effective November 1, 2017.

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.

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.

Fuel and Purchased Power Rates.Chugach recovers fuel and purchased power costs directly from 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 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 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. Chugach recognizes differences between projected recoverable fuel and purchased power costs and amounts actually recovered through rates. The fuel cost under/over recovery on the balance sheet represents 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 the balance sheet and will be refunded to members in subsequent periods.

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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, our regulator 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 operations than they would on a non-regulated company. As reflected in the financial statements, see “Item 8 -Financial Statements and Supplementary Data – Note 2o – 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.

Year ended December31, 2017, compared to the year ended December 31, 2016, and the year ended December 31, 2016, compared to the year ended December 31, 2015

Margins

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

	2017		2016		2015
Net Operating Margins	$	5,269,849	$	5,205,893	$	5,815,149
Nonoperating Margins	$	778,875	$	607,963	$	687,703
Assignable Margins	$	6,048,724	$	5,813,856	$	6,502,852

Net operating margins did not materially change in 2017 from 2016. 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.

Nonoperating margins include interest income, Allowance for Funds Used During Construction (AFUDC), capital credits and patronage capital allocations and other. The increase in nonoperating margins in 2017 from 2016 was primarily due to increased interest and dividendsassociated with marketable securities. 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.

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Revenues

Operating revenues include sales of electric energy to retail, wholesale and economy energy customers and other miscellaneous revenues. In 2017, operating revenues were $27.0 million, or 13.7% higher than 2016. The increase was primarily due to higher fuel and purchased power expense recovered in revenue and higher economy energy sales and wheeling.

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.

Retail revenue increased $17.3 million, or 9.6%, in 2017 from 2016 primarily due to increased fuel and purchased power costs recovered in revenue.  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.

Wholesale revenue increased $0.9 million, or 18.0% in 2017 from 2016, due to increased fuel and purchased power costs recovered in revenue.  Wholesale revenue decreased $26.0 million, or 84.1%, in 2016 from 2015, primarily due to the expiration of MEA’s wholesale contract on April 30, 2015.

Economy revenue increased $3.0 million due to increased sales to GVEA, MEA, and HEA.  Economy revenue decreased $6.9 million, or 84.1%, in 2016 from 2015 due primarily to the expiration of GVEA’s contract at the end of the first quarter of 2015.

Miscellaneous revenue increased $5.8 million or 54.7% in 2017 from 2016 and $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 GVEA, in 2017 and 2016, and from MEA, in 2017, also contributed to the increase.

Based on the results of fixed and variable cost recovery established in Chugach’s rate filings, wholesale sales to Seward contributed approximately $1.4 million for the year ended December 31, 2017 and $1.3 million for the years ended December 31, 2016 and 2015. Wholesale sales to MEA contributed approximately $26.2 million, for the year ended December 31, 2015.

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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, 2017, and 2016.

	Base Rate Sales Revenue							Fuel and Purchased Power Revenue							Total Revenue
		2017		2016		% Variance			2017		2016		% Variance			2017		2016		% Variance
Retail
Residential		$	66.0	$	64.8	1.9	%		$	34.6	$	26.7	29.6	%		$	100.6	$	91.5	9.9	%
Small Commercial		$	11.5	$	11.6	(0.9	%)		$	8.1	$	6.4	26.6	%		$	19.6	$	18.0	8.9	%
Large Commercial		$	43.4	$	43.7	(0.7	%)		$	32.7	$	25.8	26.7	%		$	76.1	$	69.5	9.5	%
Lighting		$	1.6	$	1.6	0.0	%		$	0.2	$	0.2	0.0	%		$	1.8	$	1.8	0.0	%
Total Retail		$	122.5	$	121.7	0.7	%		$	75.6	$	59.1	27.9	%		$	198.1	$	180.8	9.6	%
Wholesale
SES		$	2.1	$	2.2	(4.5	%)		$	3.8	$	2.8	35.7	%		$	5.9	$	5.0	18.0	%
Total Wholesale		$	2.1	$	2.2	(4.5	%)		$	3.8	$	2.8	35.7	%		$	5.9	$	5.0	18.0	%
Economy		$	0.7	$	0.5	40.0	%		$	3.6	$	0.8	350.0	%		$	4.3	$	1.3	230.8	%
Miscellaneous		$	2.1	$	2.2	(4.5	%)		$	14.3	$	8.4	70.2	%		$	16.4	$	10.6	54.7	%
Total Revenue		$	127.4	$	126.6	0.6	%		$	97.3	$	71.1	36.8	%		$	224.7	$	197.7	13.7	%

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, 2016, and 2015.

	Base Rate Sales Revenue							Fuel and Purchased Power Revenue							Total Revenue
		2016		2015		% Variance			2016		2105		% 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	%)

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

	2017	2017		2016	2016		2015	2015
	Sales (MWh)	Revenue		Sales (MWh)	Revenue		Sales (MWh)	Revenue
Retail	1,105,173	$	198,079,331	1,113,020	$	180,838,811	1,133,427	$	170,147,462
Wholesale:
MEA	0		0	0		0	275,362		26,177,627
Seward	59,803		5,883,121	59,063		4,938,175	61,347		4,770,129
Total Wholesale	59,803		5,883,121	59,063		4,938,175	336,709		30,947,756
Economy energy	48,526		4,351,050	25,000		1,340,750	105,815		8,150,983
Other	N/A		16,375,167	N/A		10,629,843	N/A		7,174,951
Total	1,213,502	$	224,688,669	1,197,083	$	197,747,579	1,575,951	$	216,421,152

Chugach provided economy energy sales to GVEA through March of 2015 under contract, and continues to provide economy energy on an as needed basis to GVEA, HEA, MEA, and ML&P. Sales are made under the terms and conditions of Chugach’s economy energy sales tariff approved by the RCA. The price includes the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin.

In 2017, 2016, and 2015, economy sales constituted approximately 2%, 1%, and 4%, respectively, of our sales revenues. Economy energy revenue decreased in 2016 from 2015 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 December 31 were as follows:

	2017		2016		2015
Fuel	$	78,552,672	$	54,778,582	$	66,534,877
Power production		18,006,490		15,809,168		16,886,257
Purchased power		17,301,067		15,774,733		19,599,994
Transmission		6,129,871		5,590,737		6,287,558
Distribution		13,991,088		13,991,997		14,089,862
Consumer accounts		5,968,736		6,073,710		6,117,625
Administrative, general and other		23,256,983		22,888,048		23,623,299
Depreciation		34,010,777		36,233,414		35,652,086
Total operating expenses	$	197,217,684	$	171,140,389	$	188,791,558

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Fuel

Chugach recognizes actual fuel expense as incurred. Fuel expense increased $23.8 million, or 43.4% in 2017 from 2016.  The increase was primarily due to an increase in the amount of natural gas used as well as an increase in the average effective delivered price.  In 2017, Chugach used 9,042,071 Mcf of fuel at an average effective delivered price of $7.91 per Mcf compared to 8,546,043 Mcf at an average effective price of $5.63 per Mcf in 2016.  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 2015, Chugach used 13,058,423 Mcf at an average effective price of $4.69 per Mcf.

Power Production

Power production expense increased $2.2 million, or 13.9%, in 2017 from 2016, primarily due toincreased operating and maintenance costs at SPP, as well as increased generation maintenance expense at Beluga Power Plant associated with the amortization of production equipment parts, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Beluga Parts Filing.”Power production expense decreased $1.1 million, or 6.4%, in 2016 from 2015, primarily due to a decrease in the maintenance for 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.

Purchased Power

Purchased power expense increased $1.5 million, or 9.7%, in 2017 from 2016, primarily due to an increase in purchases from ML&P and Bradley Lake, which was somewhat offset by a decrease in purchases from Fire Island Wind and a lower average effective price.  In 2017, Chugach purchased 231,749 MWh of energy at an average effective price of 6.16 cents per kWh compared to 182,651 MWh at an average effective price of 7.17 cents per kWh.  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 somewhat offset by a higher average effective price. In 2015, Chugach purchased 295,925 MWh of energy at an average effective of 5.68 cents per kWh.  

Transmission

Transmission expense increased $0.5 million or 9.6%, in 2017 from 2016, primarily due to increased labor expense associated with control & communication systems and line maintenance, as well ashigher vegetation control expense. 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.

Other Expenses

Distribution, consumer accounts, administrative, general and other expenses did not materially change in 2017 from 2016 or in 2016 from 2015.

30

Depreciation

Depreciation and amortization expense decreased $2.2 million or 6.1%, in 2017 from 2016, primarily due to the implementation of lower depreciation rates effective July 1, 2017. Depreciation and amortization expense did not materially change in 2016 from 2015.

Interest

Interest on long-term debt and other increased $0.5 million, or 2.3%, in 2017 from 2016, primarily due to additional interest expense associated with the issuance of the 2017 Series A Bonds. Interest on long-term debt and other did not materially change in 2016 from 2015.

Interest charged to construction decreased $0.3 million, or 63.7%, primarily due to a lower average CWIP balance. Interest charged to construction did not materially change in 2016 from 2015.

Non-Operating Margins

Non-operating margins increased $0.2 million or 28.1% in 2017 from 2016, primarily due to higher interest and dividends associated with marketable securities. Non-operating margins decreased $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.

Patronage Capital (Equity)

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

	2017		2016		2015
Patronage capital at beginning of year	$	169,996,436	$	167,447,781	$	164,135,053
Retirement/net transfer of capital credits		(3,116,273)		(3,265,201)		(3,190,124)
Assignable margins		6,048,724		5,813,856		6,502,852
Patronage capital at end of year		172,928,887		169,996,436		167,447,781
Other equity1		16,372,407		15,519,089		14,189,600
Total equity at end of year	$	189,301,294	$	185,515,525	$	181,637,381
1 Other equity includes memberships and donated capital on capital credit retirements.

We credit to our members all amounts received from them for the furnishing of electricity in excess of our operating costs, expenses and provision for reasonable reserves. These excess amounts (i.e., assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by us until such future time as they are retired and returned without interest. Approval of distributions of these amounts to members, also known as capital credits, is at the discretion of our Board. We currently have a practice of retiring patronage capital on a first-in, first-out basis for retail customers, but we are currently evaluating other methodologies. 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.

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Capital credits retirements authorized by our Board, less early retirements, were $2,631,928 and $3,001,426 for the years ended December 31, 2017, and 2016, 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 long-term debt and equities and margins.

Changes in Financial Condition

Assets

Total assets did not materially change in 2017 from 2016. Decreases in net utility plant, investments – other, and materials and supplies were offset by increases in marketable securities, fuel cost-under-recovery, accounts receivable, prepayments, and deferred charges. Net utility plant decreased $7.3 million, or 1.0%, in 2017 from 2016 primarily due to depreciation expense in excess of extension and replacement of plant. Investments – other decreased $3.1 million, or 100%, in 2017 from 2016 due to the reclassification of marketable CDs to marketable securities in 2017. Materials and supplies decreased $12.6 million, or 45.2%, in 2017 from 2016 primarily due to the reclassification of production equipment parts for the Beluga Power Plant to a regulatory asset under deferred charges. Marketable securities increased $4.0 million, or 54.9%, in 2017 from 2016 primarily due to the reclassification from investments – other, as well as the unrealized gain on the investment portfolio. Fuel cost under-recovery increased $4.9 million, or 100%, in 2017 from 2016 due to the under-collection of the prior quarter’s fuel and purchased power costs. Accounts receivable increased $2.7 million, or 8.1%, in 2017 from 2016 primarily due to higher retail revenue. Prepayments increased $3.5 million in 2017 from 2016 primarily due to a capital projectassociated with the Bradley Lake Hydroelectric Project. Deferred charges increased $7.6 million, or 30.3%, in 2017 from 2016 primarily due to the aforementioned reclassification of production equipment parts for the Beluga Power Plant, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Beluga Parts Filing.”

Liabilities and Equity

Total liabilities, equities and margins did not materially change in 2017 from 2016. Decreases in commercial paper, accounts payable, fuel cost over-recovery, and patronage capital payable were offset by increases in total equities and margins, long-term obligations, fuel, and other liabilities. Commercial paper decreased $18.2 million, or 26.7%, in 2017 from 2016 primarily due to the issuance of the 2017 Series A Bonds. Accounts payable decreased $2.2 million, or 22.9%, in 2017 from 2016 primarily due to the timing of cash payments. Fuel cost over-recovery decreased $3.8 million, or 100%, in 2017 from 2016 due to refunding of the prior quarter’s over-collection of fuel and purchased power costs. Patronage capital payable decreased $3.2 million, or 26.7%, in 2017 from 2016 primarily due to the payment and reclassification to current of a portion of HEA’s patronage capital payable. Total equities and margins increased $3.8 million, or 2.0%, in 2017 from 2016 primarily due to the margins generated in 2017. Long-term obligations, including the current portion, increased $15.2 million, or 3.3% primarily due to the issuance of the 2017 Series A Bonds. Fuel increased $3.6 million, or 57.8%, in 2017 from 2016 as a result of more fuel purchased and at a higher price in December 2017 compared to December 2016. Other liabilities increased $3.8

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million, or 118.9%, primarily due to the reclassification of the current portion of HEA’s patronage capital payable and an increase in the underground ordinance liability.

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 2017.

Contractual Obligations and Commercial Commitments

The following table presents Chugach’s contractual and commercial commitments as of December 31, 2017:

Contractual cash obligations – Payments Due By Period

(In thousands)	Total		2018		2019-2020		2021-2022		Thereafter
Long-term debt, including current portion	$	485,606	$	26,609	$	53,445	$	40,357	$	365,195
Long-term interest expense		228,940		19,780		36,287		32,672		140,201
Commercial Paper1		50,000		50,000		0		0		0
Bradley Lake2		18,477		3,692		7,602		7,183		0
Fuel and fuel transportation expense3		632,324		75,569		128,964		133,002		294,789
BRU4		19,380		2,367		2,617		2,617		11,779
Capital Credit Retirements5		10,798		2,000		8,798		0		0
Total	$	1,445,525	$	180,017	$	237,713	$	215,831	$	811,964
1 At December 31, 2017, Chugach's Commercial Paper Program was backed by a $150.0 million Unsecured Credit Agreement, which funds operating and capital requirements. At December 31, 2017, there was $50.0 million of commercial paper outstanding, therefore, the available borrowing capacity under the Commercial Paper Program was $100.0 million and could be used for future operational and capital funding requirements.
2 Estimated annual debt service requirements
3 Estimated committed fuel and fuel transportation expense
4 Estimate of operating and maintenance costs only and does not include capital improvements at this time.
5 Capital credit retirement commitments

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 $5.6 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 Hilcorp, Furie, and the BRU, 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 2017 with $5.5 million of cash and cash equivalents, up from $4.7 million at December 31, 2016, and down from $15.6 million at December 31, 2015. 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.

	2017		2016		2015
Total cash provided by (used in):
Operating activities	$	30,291,152	$	32,494,336	$	52,096,436
Investing activities		(29,561,928)		(89,488,707)		(32,347,745)
Financing activities		83,472		46,040,387		(20,486,734)
Increase (decrease) in cash and cash equivalents	$	812,696	$	(10,953,984)	$	(738,043)

Cash provided by operating activities was $30.3 million in 2017 compared to $32.5 million in 2016 and $52.1 million in 2015. The decrease in cash provided by operating activities in 2017 from 2016 was primarily due to the change in our fuel recovery position caused by the under-collection of fuel and purchased power costs recovered through the fuel and purchased power adjustment process in 2017. Prepayments associated with Bradley Lake contributed to this decrease, which was somewhat offset by less cash used for deferred charges as a result of the NRECA pension prepayment in 2016. The decrease in cash provided by operating activities in 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.

Cash used in investing activities was $29.6 million in 2017 compared to $89.5 million in 2016 and $32.3 million in 2015. The change in cash used in investing activities in 2017 from 2016 and in 2016 from 2015 was primarily due to the impact of Chugach’s investment in the BRU and our investment activity with marketable securities in 2016.

Cash provided by financing activities was $0.1 million in 2017 compared to $46.0 million in 2016 and cash used of $20.5 million in 2015. The change in 2017 from 2016 was primarily due to the issuance of the 2017 Series A Bonds which were used, in part, to pay down commercial paper.  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 in 2016, and the retirement of capital credits in 2017 and 2016.

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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, 2017, there was no outstanding balance on our NRUCFC line of credit and $50.0 million of outstanding commercial paper under the Commercial Paper Program. Thus, at December 31, 2017, our available borrowing capacity under our line of credit was $50.0 million and our available commercial paper capacity was $100.0 million. The NRUCFC line of credit was renewed effective September 29, 2017, and expires September 29, 2022.

Chugach maintains a $150.0 million Credit Agreement, which is used to back Chugach’s commercial paper program and is due to 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, 2017, Chugach had $40.4 million outstanding with CoBank.

Under the Indenture, additional obligations may be sold by Chugach upon the basis of bondable additions and the retirement or defeasance of, or principal payments on previously outstanding obligations. The beginning balance of bondable additions on January 20, 2011, was $322.2 million, which would support the issuance of additional debt of approximately $293.0 million. On March 15, 2011, Chugach used $5.5 million of bondable additions to pay financing costs associated with the 2011 Series A Bond transaction. On January 11, 2012, Chugach used $275.0 million of bondable additions when it issued $250.0 million of 2012 Series A Bonds. The balance of bondable additions after the January 11, 2012, transaction was $38.2 million. On October 9, 2015, Chugach certified bondable additions of $261.9 million bringing the balance of bondable additions to $300.1 million.On February 6, 2018, Chugach certified bondable additions of $56.3 million bringing the balance of bondable additions to $356.4 million, which would support the issuance of approximately $324.0 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. On March 17, 2017, Chugach used $40.0 million of principal payments to issue the 2017 Series A Bonds.  Total principal payment capacity as of March 15, 2018 is $63.6 million.

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.

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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, 2017, are set forth below:

Year Ending December 31	Principal Maturities
2018		26,608,667
2019		26,608,667
2020		26,836,667
2021		20,064,667
2022		20,292,667
Thereafter		365,194,663
	$	485,605,998

During 2017, we spent approximately $28.9million 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 2018 through 2022 as contained in the CIP, which was approved by the Board on November 29, 2017:

Year	Estimated Expenditures
2018	$41.9 million
2019	$58.5 million
2020	$19.7 million
2021	$22.4 million
2022	$22.9 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.

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.

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Potential ML&P Acquisition

In December 2017, the Mayor of Anchorage, Alaska, announced plans to place a proposition on the April 3, 2018 municipal ballot allowing the voters to authorize the sale of ML&P to Chugach. If approved by Anchorage voters, terms will be finalized and will require approval by the Chugach Board of Directors, the Anchorage Assembly and the RCA.

Railbelt Grid Unification

Chugach remains 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 appropriating $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 were required. With the support of the RCA, Chugach and several other Alaska’s Railbelt utilities began evaluating possible transmission business model opportunities and associated economic dispatch models that Chugach believes may lead to more optimal system wide operations.

In June 2016, the RCA opened a docket to “evaluate the reliability and security standards and practices of Alaska Electric Utilities.” In 2017, Chugach and several other Alaska Railbelt utilities entered into a contract with GDS Associates, Inc. (GDS).  GDS’s scope is to facilitate discussion among all six Alaska Railbelt utilities and various stakeholders with an end goal of submitting to the RCA a Railbelt Reliability Council (RRC), including a governance structure, that will be responsible for adoption and enforcement of uniform reliability standards and integrated transmission resource planning. GDS presented to the RCA during a technical conference in January 2018 and will present an update in a second technical conference in March 2018. Chugach and the other utilities plan to provide GDS’s final recommendation of the RRC to the RCA in May 2018. 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.

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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 and another considered for development by BlueCrest Energy, Inc. Furie has constructed an offshore gas production platform and has begun 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.

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 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 this firm contract, 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.

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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, 2017.

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 operations than they would on a non-regulated company. As reflected in the financial statements, see “Item 8 - Financial Statements and Supplementary Data – Note 2o – 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

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materially impact the amounts of such regulatory assets and liabilities and could adversely impact Chugach’s financial statements.

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.”

Item 7A – Quantitative and Qualitative Disclosures About Market Risk

Chugach is exposed to a variety of risks, including changes in interest rates. 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, 2017, our short- and long- term debt was comprised of our 2011, 2012, and 2017 Series A Bonds, CoBank note and outstanding commercial paper.

The interest rates of Chugach’s 2011, 2012, and 2017 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, 2017.

	Maturing	Interest Rate		Carrying Value		Fair Value
2011 Series A, Tranche A	2031	4.20	%	$	63,000	$	64,543
2011 Series A, Tranche B	2041	4.75	%		148,000		162,804
2012 Series A, Tranche A	2032	4.01	%		56,250		57,072
2012 Series A, Tranche B	2042	4.41	%		88,000		93,940
2012 Series A, Tranche C	2042	4.78	%		50,000		55,472
2017 Series A, Tranche A	2037	3.43	%		40,000		38,925
2016 CoBank Note	2031	2.58	%		40,356		38,440
Total				$	485,606	$	511,196

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, 2017, we had $50.0 million of commercial paper outstanding, which is currently our only debt subject to variable interest rates. Based on this balance a 100 basis-point rise in interest rates would increase our interest expense by approximately $0.5 million, and a 100 basis point decline in interest rates would decrease our interest expenses by approximately $0.5 million.

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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.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Chugach Electric Association, Inc. and subsidiary (the Company) as of December 31, 2017 and 2016, 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, 2017, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the years in the three‑year period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Basis for Opinion

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 are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the relevant ethical requirements relating to our audits.

We conducted our audits in accordance with the standards of the PCAOB 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 consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ KPMG LLP

We have served as the Company’s auditor since 1983.

Anchorage, Alaska
March 20, 2018

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Chugach Electric Association, Inc.

Consolidated Balance Sheets

December 31, 2017 and 2016

Assets	December 31, 2017		December 31, 2016
Utility plant:
Electric plant in service	$	1,205,092,224	$	1,192,513,869
Construction work in progress		17,952,573		18,455,940
Total utility plant		1,223,044,797		1,210,969,809
Less accumulated depreciation		(515,496,312)		(496,098,131)
Net utility plant		707,548,485		714,871,678
Other property and investments, at cost:
Nonutility property		76,889		76,889
Investments in associated organizations		8,980,410		9,349,311
Special funds		1,466,010		907,836
Restricted cash equivalents		1,028,758		810,559
Investments - other		0		3,061,434
Total other property and investments		11,552,067		14,206,029
Current assets:
Cash and cash equivalents		5,485,631		4,672,935
Special deposits		54,300		75,942
Restricted cash equivalents		687,370		899,723
Marketable securities		11,420,900		7,375,381
Fuel cost under-recovery		4,921,794		0
Accounts receivable, less provisions for doubtful accounts
of $555,336 in 2017 and $484,352 in 2016		35,680,680		33,000,919
Materials and supplies		15,291,095		27,889,167
Fuel stock		6,901,994		6,321,676
Prepayments		4,953,170		1,407,026
Other current assets		257,193		294,697
Total current assets		85,654,127		81,937,466
Other non-current assets:
Deferred charges, net		32,764,065		25,140,957
Total other non-current assets		32,764,065		25,140,957
Total assets	$	837,518,744	$	836,156,130

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Chugach Electric Association, Inc.

Consolidated Balance Sheets (continued)

December 31, 2017 and 2016

Liabilities, Equities and Margins	December 31, 2017		December 31, 2016
Equities and margins:
Memberships	$	1,719,154	$	1,691,014
Patronage capital		172,928,887		169,996,436
Other		14,653,253		13,828,075
Total equities and margins		189,301,294		185,515,525
Long-term obligations, excluding current installments:
Bonds payable		421,833,331		405,249,998
Notes payable		37,164,000		40,356,000
Less unamortized debt issuance costs		(2,669,485)		(2,715,745)
Total long-term obligations		456,327,846		442,890,253
Current liabilities:
Current installments of long-term obligations		26,608,667		24,836,667
Commercial paper		50,000,000		68,200,000
Accounts payable		7,420,279		9,618,630
Consumer deposits		5,335,896		5,207,585
Fuel cost over-recovery		0		3,824,722
Accrued interest		5,991,619		5,873,368
Salaries, wages and benefits		7,017,131		7,315,898
Fuel		9,913,781		6,284,338
Other current liabilities		7,079,821		3,234,586
Total current liabilities		119,367,194		134,395,794
Other non-current liabilities:
Deferred compensation		1,229,294		907,836
Other liabilities, non-current		531,630		655,277
Deferred liabilities		1,249,390		1,179,414
Patronage capital payable		8,798,077		12,008,499
Cost of removal obligation / asset retirement obligation		60,714,019		58,603,532
Total other non-current liabilities		72,522,410		73,354,558
Total liabilities, equities and margins	$	837,518,744	$	836,156,130

See accompanying notes to financial statements.

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Chugach Electric Association, Inc.

Consolidated Statements of Operations

Years Ended December 31, 2017, 2016 and 2015

	2017		2016		2015
Operating revenues	$	224,688,669	$	197,747,579	$	216,421,152
Operating expenses:
Fuel		78,552,672		54,778,582		66,534,877
Production		18,006,490		15,809,168		16,886,257
Purchased power		17,301,067		15,774,733		19,599,994
Transmission		6,129,871		5,590,737		6,287,558
Distribution		13,991,088		13,991,997		14,089,862
Consumer accounts		5,968,736		6,073,710		6,117,625
Administrative, general and other		23,256,983		22,888,048		23,623,299
Depreciation and amortization		34,010,777		36,233,414		35,652,086
Total operating expenses	$	197,217,684	$	171,140,389	$	188,791,558
Interest expense:
Long-term debt and other		22,366,034		21,856,095		22,194,290
Charged to construction		(164,898)		(454,798)		(379,845)
Interest expense, net	$	22,201,136	$	21,401,297	$	21,814,445
Net operating margins	$	5,269,849	$	5,205,893	$	5,815,149
Nonoperating margins:
Interest income		644,663		425,173		296,788
Allowance for funds used during construction		69,157		188,111		142,881
Capital credits, patronage dividends and other		65,055		(5,321)		248,034
Total nonoperating margins	$	778,875	$	607,963	$	687,703
Assignable margins	$	6,048,724	$	5,813,856	$	6,502,852

See accompanying notes to financial statements.

44

Chugach Electric Association, Inc.

Consolidated Statements of Changes in Equities and Margins

Years Ended December 31, 2017, 2016 and 2015

f
	Memberships		Other Equities and Margins		Patronage Capital		Total
Balance, January 1, 2015	$	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
Assignable margins		0		0		6,048,724		6,048,724
Retirement/net transfer of capital credits		0		0		(3,116,273)		(3,116,273)
Unclaimed capital credit retirements		0		612,752		0		612,752
Memberships and donations received		28,140		212,426		0		240,566
Balance, December 31, 2017	$	1,719,154	$	14,653,253	$	172,928,887	$	189,301,294

See accompanying notes to financial statements.

45

Chugach Electric Association, Inc.

Consolidated Statements of Cash Flows

Years Ended December 31, 2017, 2016 and 2015

	2017		2016		2015
Cash flows from operating activities:
Assignable margins	$	6,048,724	$	5,813,856	$	6,502,852
Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation and amortization		34,010,777		36,233,414		35,652,086
Amortization and depreciation cleared to operating expenses		4,791,978		4,988,068		4,390,385
Allowance for funds used during construction		(69,157)		(188,111)		(142,881)
Write off of inventory, deferred charges and projects		413,690		997,301		691,035
Other		27,986		248,482		(220,496)
(Increase) decrease in assets:
Accounts receivable, net		(2,858,099)		(4,926,631)		6,866,956
Fuel cost under-recovery		(4,921,794)		0		0
Materials and supplies		896,455		(850,493)		(1,070,896)
Fuel stock		(580,318)		741,865		2,588,532
Prepayments		(3,546,144)		59,275		712,422
Other assets		59,146		(71,144)		215,738
Deferred charges		(201,775)		(10,374,429)		(405,746)
Increase (decrease) in liabilities:
Accounts payable		(1,469,106)		750,538		(270,416)
Consumer deposits		128,311		206,901		86,424
Fuel cost over-recovery		(3,824,722)		(1,311,023)		3,673,688
Accrued interest		118,251		(42,212)		(276,028)
Salaries, wages and benefits		(298,767)		56,092		(287,510)
Fuel		3,629,443		1,342,028		(6,195,299)
Other current liabilities		(2,045,800)		(1,051,220)		(290,715)
Deferred liabilities		(17,927)		(128,221)		(123,695)
Net cash provided by operating activities		30,291,152		32,494,336		52,096,436
Cash flows from investing activities:
Return of capital from investment in associated organizations		370,010		319,233		352,420
Investment in restricted cash equivalents		(5,846)		(1,398)		(1,141)
Investment in special funds		(236,716)		0		0
Investment in marketable securities and investments-other		(924,903)		(10,580,000)		0
Investment in Beluga River Unit		0		(44,403,922)		0
Proceeds from restricted cash equivalents		0		1,140,343		0
Proceeds from capital grants		115,453		1,021,929		2,395,331
Extension and replacement of plant		(28,879,926)		(36,984,892)		(35,094,355)
Net cash used in investing activities		(29,561,928)		(89,488,707)		(32,347,745)
Cash flows from financing activities:
Payments for debt issue costs		(206,871)		(277,155)		0
Net increase (decrease) in short-term obligations		(18,200,000)		48,200,000		(1,000,000)
Proceeds from long-term obligations		40,000,000		45,600,000		0
Repayments of long-term obligations		(24,836,667)		(48,181,832)		(23,889,777)
Memberships and donations received		853,318		1,329,489		357,365
Retirement of patronage capital and estate payments		(2,258,047)		(4,378,853)		(182,352)
Net receipts on consumer advances for construction		4,731,739		3,748,738		4,228,030
Net cash provided by (used in) financing activities		83,472		46,040,387		(20,486,734)
Net change in cash and cash equivalents		812,696		(10,953,984)		(738,043)
Cash and cash equivalents at beginning of period	$	4,672,935		15,626,919		16,364,962
Cash and cash equivalents at end of period	$	5,485,631	$	4,672,935	$	15,626,919
Supplemental disclosure of non-cash investing and financing activities:
Cost of removal obligation	$	2,110,487	$	3,008,808	$	1,366,318
Asset retirement obligation assumed upon BRU acquisition	$	0	$	3,523,409	$	0
Extension and replacement of plant included in accounts payable	$	1,185,788	$	1,915,033	$	2,582,947
Patronage capital retired/net transferred and included in other current liabilities	$	2,057,036	$	0	$	2,105,440
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized	$	20,911,535	$	20,220,317	$	21,891,308

See accompanying notes to financial statements.

46

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

(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, Homer Electric Association, Inc. (HEA), 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), and remaining proved BRU reserves. Actual results could differ from those estimates.

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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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 (2o) – “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, removal cost, less salvage, is charged to accumulated depreciation.  Renewals and betterments are capitalized, while maintenance and repairs are normally charged to expense as incurred.

In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain 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, 2017 are as follows:

Annual Depreciation Rate Ranges

	Six months ending June 30, 2017			Six months ending December 31, 2017
Steam production plant	3.15%	-	3.84%	3.03%	-	3.26%
Hydroelectric production plant	1.06%	-	3.00%	0.88%	-	2.71%
Other production plant	3.15%	-	8.85%	2.18%	-	3.46%
Transmission plant	1.58%	-	7.86%	1.01%	-	10.50%
Distribution plant	2.16%	-	9.63%	1.40%	-	10.00%
General plant	1.57%	-	20.00%	1.95%	-	33.33%
Other	2.75%	-	2.75%	2.75%	-	2.75%

48

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

On March 23, 2017, the RCA approved revised depreciation rates effective July 1, 2017 in Docket U-16-081(2). 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.

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 FASB 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.

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 2017, 2016 or 2015.

g. Investments – Other

Investments – other consists of certificates of deposit with a maturity greater than 12 months.  Total investments – other were$3.1 million as of December 31, 2016. 

h. Special Funds

Special funds includes deposits associated with the deferred compensation plan and an investment associated with the BRU ARO. The BRU ARO investment was established pursuant to an agreement with the State of Alaska and was $0.2 million as of December 31, 2017.

49

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

i. Cash and Cash Equivalents / Restricted Cash Equivalents

For purposes of the statement of cash flows, Chugach considers all highly liquid instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. Chugach has a concentration account with First National Bank Alaska (FNBA). There is no rate of return or fees on this account. The concentration account had an average balance of $6,454,809and $5,897,767 during the years ended December 31, 2017 and 2016, respectively.

Restricted cash equivalents include funds on deposit for future workers’ compensation claims.  Total current and long term restricted cash equivalents were $1.7million at December 31, 2017 and 2016.

j. Marketable Securities

Chugach’s marketable securities consist of bond mutual funds, corporate bonds, and certificates of deposit with a maturity less than 12 months, classified as trading securities, reported at fair value with gains and losses in earnings. Net gains on marketable securities are included in nonoperating margins – capital credits, patronage dividends and other, and are summarized as follows:

	Twelve months ended December 31, 2017
Net gains and losses recognized during the period on trading securities	$	59,182
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	$	59,182

k. Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers. Included in accounts receivable are invoiced amounts to ML&P for their proportionate share of current Southcentral Power Project (SPP) costs, which amounted to $1.3million and $1.4 million in 2017 and 2016, respectively. At December 31, 2017 and 2016, accounts receivable also included $1.1million and $0.7 million, respectively, from BRU operations primarily associated with gas sales to ENSTAR.

l. Materials and Supplies

Materials and supplies are stated at average cost.

50

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

m. Fuel Stock

Fuel Stock is the weighted average cost of fuel injected into Cook Inlet Natural Gas Storage Alaska (CINGSA). Chugach’s fuel balance in storage for the years ended December 31, 2017 and 2016 amounted to $6.9  million and $6.3 million, respectively.

n. 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.

o. 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 liabilities 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,

51

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

which represents the difference between the normal retirement age of 62 and the average age of Chugach’s employees in the RS Plan. The balance of the prepayment in deferred charges at December 31, 2017 and 2016 was $7.2 million and $7.9 million, respectively.  

p. 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.

q. Consumer Deposits

Consumer deposits include amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 2017 and 2016, totaled $3.7million and $3.3 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances totaled $1.6 million and $1.9 million for the years ended December 31, 2017 and 2016.

r. 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 2j 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, 2017 and 2016

s. 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 $10,674,543and $10,940,274 of unbilled retail revenue at December 31, 2017 and 2016, 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.

t. 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 4.1%during 2017 and 4.3% during 2016 and 2015.  

u. 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.

v. 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, 2017, 2016 and 2015 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, 2017 and 2016

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, 2015 through December 31, 2017 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2017.

w. 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.  Chugach received no grants in 2017 and$0.6 million in 2016.

(3)Accounting Pronouncements

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. Chugach adopted the standard on January 1, 2018 using the modified retrospective transition method with an immaterial cumulative effect adjustment as of the January 1, 2018 adoption date.

We have evaluated our energy sales contracts, including retail, wholesale, and economy energy, and do not believe there will be an impact to the timing or pattern of revenue recognition from our 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 2017 was approximately 99% of our total operating revenue.

The adoption of Topic 606 also includes additional disclosure requirements beginning in the first quarter of 2018, including expanded disclosures around the amount, timing, nature and uncertainty of revenues from contracts with customers. We  are finalizing the required disclosures.

54

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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, 2019. 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 2016-02 on 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 2016-13 “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.

55

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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 for 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.

ASC Update 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)”

In November 2016, the FASB issued ASC Update 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” ASC Update 2016-18 clarifies how to classify and present changes in restricted cash or cash equivalents that occur when there are transfers between cash, cash equivalents, and restricted cash or restricted cash equivalents and when there are direct cash receipts into or payments made from restricted cash or restricted cash equivalents on the statement of cash flows to limit the diversity in practice. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2016-18 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business”

In January 2017, the FASB issued ASC Update 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.” ASC Update 2017-01 clarifies the definition of a business by providing a screen to determine when a set of assets and activities acquired or disposed of constitute a business, as well as a framework for evaluating whether all elements of a business are present in the set. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted only when the transaction has not been reported in financial statements. Chugach will begin application of ASC 2017-01 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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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

ASC Update 2017-07 “Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”

In March 2017, the FASB issued ASC Update 2017-07, “Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” ASC Update 2017-07 amends current guidance on the presentation and disclosure of other compensation costs in the income statement. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted only for financial statements that have not been issued. Chugach will begin application of ASC 2017-07 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842”

In January 2018, the FASB issued ASC Update 2018-01, “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842.” ASC Update 2018-01 amends current guidance to provide an optional transition practical expedient allowing entities to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. 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 2018-01 on January 1, 2019. Chugach is evaluating the impact of the Lease update as well as existing land easements to determine if we will elect to use the practical expedient for transition as well as the effect on our results of operations, financial position, and cash flows.

57

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

(4)    Fair Value of Assets and Liabilities

Fair Value Hierarchy

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

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

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

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

The table below presents the balance of Chugach’s marketable securities measured at fair value on a recurring basis at December 31, 2017 and 2016. Chugach’s bond mutual funds, corporate bonds, and marketable certificates of deposit are measured using quoted prices in active markets. Chugach had no other assets or liabilities measured at fair value on a recurring basis at December 31, 2017 or 2016.  

December 31, 2017	Total		Level 1		Level 2		Level 3
Bond mutual funds	$	8,109,242	$	8,109,242	$	0	$	0
Corporate bonds	$	248,335	$	248,335	$	0	$	0
Certificates of deposit	$	3,063,323	$	3,063,323	$	0	$	0
December 31, 2016	Total		Level 1		Level 2		Level 3
Bond mutual funds	$	7,375,381	$	7,375,381	$	0	$	0
Certificates of deposit	$	3,061,434	$	3,061,434	$	0	$	0

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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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 estimated fair values (in thousands) of long-term obligations included in the financial statements at December 31, 2017,  are as follows:

	Carrying Value		Fair Value Level 2
Long-term obligations (including current installments)	$	485,606	$	511,196

(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 was 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. Chugach and MEA signed an agreement to extend the gas dispatch agreement through March 31, 2018, and later signed an amendment to extend the agreement through March 31, 2019. A letter order was issued by the RCA on September 22, 2017, approving the amendment to the agreement to extend gas dispatch services as filed in Tariff Advice No. 442-8.

59

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

Simplified Rate Filing

Chugach is a participant in the Simplified Rate Filing (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, with filings made either on a quarterly or semi-annual basis. Chugach is a participant on a quarterly filing schedule basis. Chugach submitted quarterly SRF filings which resulted in a 3.0% decrease to system demand and energy rates effective July 1, 2017, and an increase of 1.9% for rates effective November 1, 2017. The SRF based on the September 2017 test year resulted in a 0.4 % increase to system demand and energy rates effective February 1, 2018.

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 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, 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 Furie Agreement.

On May 1, 2017, the RCA approved the Furie Agreement. The RCA also approved recovery of costs associated with the Furie Agreement through its fuel and purchased power cost adjustment process.

Beluga River Unit Gas Transfer Price

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. Docket U-16-062 / U-16-074 was established to address the creation of a regulatory asset for the

60

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

recovery of costs associated with Chugach’s acquisition of a portion of ConocoPhillips Alaska, Inc.’s interest in the BRU and to determine the methodology to establish permanent rates for the gas transfer price (GTP) associated with Chugach’s ownership interest in the BRU. On September 7, 2017, the RCA issued U-16-062(7) / U-16-074(7) accepting a stipulation between Chugach and the Office of the Attorney General Regulatory Affairs and Public Advocacy Section and vacating the procedural hearing. On October 7, 2017, Chugach submitted the BRU GTP calculations to the RCA as part of a compliance filing to the settlement. On October 26, 2017, the RCA issued a final order accepting Chugach’s compliance filing and closing the docket.

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 the 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. 

The RCA opened Docket Number U-16-092 to review the petition. The RCA approved the petition May 17, 2017 closing docket U-16-092(2).

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. The filing was submitted to the RCA on September 30, 2016. Chugach proposed changes to depreciation rates that would result in a $5.9 million reduction in annual depreciation expense. On a demand and energy rate basis, the impact was 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, were3.2% and 1.9%, respectively. Chugach requested that the updated depreciation rates be implemented on July 1, 2017, for both accounting and ratemaking purposes.

On March 23, 2017, the RCA issued Order U-16-081(2) approving Chugach’s proposed changes to its depreciation rates. The depreciation rates were approved as filed. The RCA required Chugach to file a new depreciation study by July 1, 2022, based on plant activity as of December 31, 2021.

61

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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 proposed 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 did 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.

On August 17, 2017, the Superior Court issued its order affirming the decisions by the RCA that it has authority in this case, that the RCA’s decision was not arbitrary, and that the RCA’s basis for assignment was reasonable.  The RCA’s assignment allocation remains unchanged.  There is no impact on Chugach’s margin levels as a result of a sale of found gas and any funds Chugach receives will be returned to members as a reduction to fuel expense.  It is not known if or when CINGSA will sell any of the found gas.

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,

62

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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.

63

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

(6)Utility Plant

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

Electric plant in service:	2017		2016
Steam production plant	$	101,116,277	$	101,116,277
Hydroelectric production plant		33,659,129		33,659,129
Other production plant		287,765,474		287,404,484
Transmission plant		296,018,078		282,040,969
Distribution plant		315,862,812		294,641,485
General plant		55,164,994		54,982,432
Unclassified electric plant in service1		60,294,349		83,457,981
Intangible plant1		5,455,371		5,455,371
Beluga River Natural Gas Field (BRU Asset & ARO)		47,927,331		47,927,331
Other1		1,828,409		1,828,409
Total electric plant in service		1,205,092,224		1,192,513,869
Construction work in progress		17,952,573		18,455,940
Total electric plant in service and construction work in progress	$	1,223,044,797	$	1,210,969,809

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:

	2017		2016
NRUCFC Capital Term Certificates	$	6,095,980	$	6,095,980
CoBank		2,819,307		3,188,490
Other		65,123		64,841
Total investments in associated organizations	$	8,980,410	$	9,349,311

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.

64

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

(8)    Deferred Charges and Liabilities

Deferred Charges

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

	2017		2016
Regulatory assets:
Debt issuance and reacquisition costs	$	386,892	$	492,850
Refurbishment of transmission equipment		95,679		104,939
Feasibility studies		237,425		1,387,285
Cooper Lake relicensing / projects		5,149,903		5,280,006
Fuel supply		1,801,970		2,005,052
Storm damage		453,166		647,381
Other regulatory deferred charges		815,722		849,933
Bond interest - market risk management		4,884,587		5,365,190
Environmental matters		978,820		1,024,171
Beluga parts and materials		10,696,210		0
Total regulatory assets		25,500,374		17,156,807
Other deferred charges:
NRECA pension plan prepayment		7,204,591		7,925,050
Post retirement benefit obligation		59,100		59,100
Total other deferred charges		7,263,691		7,984,150
Total deferred charges	$	32,764,065	$	25,140,957

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

	2017		2016
Regulatory assets:
Multi-stage Energy Storage	$	0	$	1,117,860
Regulatory studies and other		201,775		46,721
Total regulatory assets		201,775		1,164,581
Other deferred charges:
NRECA pension plan prepayment		0		7,925,050
Post retirement benefit obligation		59,100		59,100
Total other deferred charges		59,100		7,984,150
Total deferred charges	$	260,875	$	9,148,731

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.

65

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

Deferred Liabilities

Deferred liabilities, at December 31 consisted of the following:

	2017		2016
Refundable consumer advances for construction	$	416,263	$	328,360
Estimated initial installation costs for meters		100,927		118,854
Post retirement benefit obligation		732,200		732,200
Total deferred liabilities	$	1,249,390	$	1,179,414

(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, 2017, Chugach had $172,928,887 of patronage capital (net of capital credits retired in 2017), which included $166,880,163 of patronage capital that had been assigned and $6,048,724of patronage capital to be assigned to its members. At December 31, 2016, Chugach had $169,996,436of patronage capital (net of capital credits retired in 2016), which included $164,182,580 of patronage capital that had been assigned and $5,813,856 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.

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. We finalized a new agreement with HEA in September 2017 which spread their retirement payments between 2017 and 2020 in increments of $2.0 million annually. As a result,$2.0 million of HEA’s patronage capital was retired and paid in 2017, and $2.0 million of HEA’s patronage capital was reclassified to a current payable under other current liabilities leaving $3.9 million in long-term patronage capital payable at December 31, 2017.  HEA’s patronage capital payable was $7.9 million at December 31, 2016.

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 $4.9million and $4.1 million at December 31, 2017 and 2016, 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 long-term debt and equities and margins. Capital credit retirements

66

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

authorized by our Board, less early retirements, were $2,631,928,  $3,001,426,  and $3,007,772 for the years ended December 31, 2017, 2016, and 2015, 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, 2017,  2016, and 2015 was $57,036,  $2,014,080, and$2,105,440, respectively.

(10)  Other Equities

A summary of other equities at December 31 follows:

	2017		2016
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		2,213,876		2,001,450
Unclaimed capital credit retirement1		12,415,752		11,803,000
Total other equities	$	14,653,253	$	13,828,075

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

67

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

(11)  Debt

Long-term obligations at December 31 are as follows:	2017		2016
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		63,000,000		67,500,000
2011 Series A Bond of 4.75%, maturing in 2041, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012		147,999,998		154,166,665
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		56,250,000		60,000,000
2012 Series A Bond of 4.41%, maturing in 2042, with interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042		88,000,000		95,000,000
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
2017 Series A Bond of 3.43%, maturing in 2037, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2018		40,000,000		0
2016 CoBank Note, 2.58% fixed rate note maturing in 2031, with interest and principal due quarterly beginning in 2016		40,356,000		43,776,000
Total long-term obligations	$	485,605,998	$	470,442,665
Less current installments		26,608,667		24,836,667
Less unamortized debt issuance costs		2,669,485		2,715,745
Long-term obligations, excluding current installments	$	456,327,846	$	442,890,253

Covenants

Chugach is required to comply with all covenants set forth in the Indenture that secures the 2011, 2012, and 2017 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.

68

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

Chugach is also required to comply with the 2016 Credit Agreement, between Chugach and NRUCFC, KeyBank National Association, Bank of America, N.A., and CoBank, 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.

69

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

The Second Amended and Restated Master Loan Agreement with CoBank, which became effective on 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 interest expense.

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 long-term debt and equities and margins.

Maturities of Long‑term Obligations

Long-term obligations at December 31, 2017, mature as follows:

Year ending December 31		2011 Series A Bonds		2012 Series A Bonds		2016 CoBank Note		2017 Series A Bonds		Total
2018	$	10,666,667	$	10,750,000	$	3,192,000	$	2,000,000	$	26,608,667
2019		10,666,667		10,750,000		3,192,000		2,000,000		26,608,667
2020		10,666,667		10,750,000		3,420,000		2,000,000		26,836,667
2021		10,666,667		3,750,000		3,648,000		2,000,000		20,064,667
2022		10,666,667		3,750,000		3,876,000		2,000,000		20,292,667
Thereafter		157,666,663		154,500,000		23,028,000		30,000,000		365,194,663
	$	210,999,998	$	194,250,000	$	40,356,000	$	40,000,000	$	485,605,998

Lines of credit

Chugach maintains a $50.0 million line of credit with NRUCFC. Chugach did not utilize this line of credit in 2017 or 2016, and therefore had no outstanding balance at December 31, 2017 and 2016. The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. The borrowing rate was 3.00% at December 31, 2017, and 2.90% at December 31, 2016.

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 was renewed effective September 29, 2017, and expires September 29, 2022.  This line of credit is immediately available for unconditional borrowing.

70

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

Commercial Paper

On June 13, 2016, Chugach entered into a $150.0 million senior unsecured credit facility (Credit Agreement), which is used to back Chugach’s commercial paper program. The 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 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 2018, as needed.

Chugach had $50.0 million and $68.2 million of commercial paper outstanding at December 31, 2017 and 2016, respectively.

The following table provides information regarding 2017  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	$	65.0	0.94	%	July	$	41.1	1.40	%
February	$	63.0	0.92	%	August	$	41.5	1.40	%
March	$	60.9	1.04	%	September	$	45.7	1.40	%
April	$	44.4	1.14	%	October	$	48.4	1.39	%
May	$	42.4	1.14	%	November	$	46.0	1.39	%
June	$	40.2	1.29	%	December	$	48.7	1.67	%

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, through 2042. 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.

71

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

On June 30, 2016, Chugach entered into a 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 $40.4 million and $43.8 million outstanding on this facility at December 31, 2017, and 2016, respectively.

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. 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.

The following table provides additional information regarding the 2011 Series A , 2012 Series A, and 2017 SeriesA  bonds and the 2016 CoBank Note at December 31, 2017 (dollars in thousands):

	Maturing March 15,	Average Life (Years)	Interest Rate		Issue Amount		Carrying Value
2011 Series A, Tranche A	2031	6.7	4.20	%	$	90,000	$	63,000
2011 Series A, Tranche B	2041	11.7	4.75	%		185,000		148,000
2012 Series A, Tranche A	2032	7.2	4.01	%		75,000		56,250
2012 Series A, Tranche B	2042	15.0	4.41	%		125,000		88,000
2012 Series A, Tranche C	2042	14.7	4.78	%		50,000		50,000
2017 Series A, Tranche A	2037	10.2	3.43	%		40,000		40,000
2016 CoBank Note	2031	5.7	2.58	%		45,600		40,356
Total					$	610,600	$	485,606

72

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

(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, 2017, 2016 and 2015 of $5.9million, $6.7 million and $6.7 million, respectively. The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2017, 2016 and 2015.

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 multi-employer 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 of the year in which the amount is paid to the RS Plan. The 25% differential in billing rates is expected to continue for approximately 15 years from January 1, 2013. However unexpected changes in interest rates, asset returns and other plan experience, plan assumption changes, and other factors may have an impact on the differential in billing rates and the 15-year period.

On December 29, 2016, Chugach made a prepayment of $7.9 million to the NRECA RS Plan. See Note 2o – “Deferred Charges and Liabilities.”

73

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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, 2021			N/A2
Subject to Funding Improvement Plan	No			No4
Surcharge Paid	N/A			N/A4
	2017	2016	2015	2017	2016	2015
Zone Status	Green	Green	Green	N/A1	N/A1	N/A1
Required minimum contributions	None	None	None	N/A	N/A	N/A
Contributions (in millions)	$3.3	$3.2	$3.1	$2.6	$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, 2017, 2016, and 2015 were $4.8million, $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, 2017, 2016, and 2015 totaled $2.8million, $2.8 million, and $2.6 million, respectively.

74

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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, 2017, 2016 and 2015 were $141.8thousand, $132.3 thousand and $133.6 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 2017, 2016, and 2015, and allowed catch-up contributions for those over 50 years of age of $6,000 in 2017, 2016, and 2015. 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, 2017, and 2016 was $1,229,294 and$907,836, 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.

75

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

(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 $16.3 million. Upon the default of a Bradley Lake participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs pro rata, to the extent necessary to compensate for the failure of another participant to pay its share, provided that no participant’s percentage share is increased by more than 25%. 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. Management believes that such expenditures, if any, would be recoverable through the fuel recovery process.

The Battle Creek Diversion Project (Project) is a project to increase water available for generation by constructing a diversion on the West Fork of Upper Battle Creek to divert flows to Bradley Lake, increasing annual energy output by an estimated 37,000 MWh. The Bradley Lake Project Management Committee (BPMC) approved the project October 13, 2017, as amended December 1, 2017, and December 6, 2017.  The Project cost is estimated at $47.0 million and the BMPC approved financing in this amount on December 6, 2017.  The project is estimated to begin in the Spring of 2018 with an estimated completion date of 2020.  Not all Bradley Lake purchasers are participating in the development and resulting benefits of the Project at this time, although they have preserved their ability to participate in the Project at a later date.  Chugach would be entitled to 39.38% of the additional energy produced if no additional participants elect to join. 

The following represents information with respect to Bradley Lake at June 30, 2017 (the most recent date for which information is available). Chugach's share of expenses was $6,452,898 in 2017, $5,662,522 in 2016, and $5,663,304 in 2015 and is included in purchased power in the accompanying financial statements.

(In thousands)	Total		Proportionate Share
Plant in service	$	162,907	$	49,524
Long-term debt		43,940		13,358
Interest expense		2,652		806

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

76

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

(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 2017 included $3,967,933, net of accumulated depreciation of $2,591,717, which represents Chugach’s share of the Eklutna Hydroelectric Project. In 2016, plant in service included $4,229,167, net of accumulated depreciation of $2,442,175. 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. When MEA was an all-requirements wholesale customer, under net billing arrangements, Chugach reimbursed MEA for their share of the costs. Chugach’s share of expenses was $403,511,  $532,678, and $689,501 in 2017, 2016, and 2015, 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. (CPAI) 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 and the transaction closed on April 22, 2016.

Additionally, CPAI had contractual gas sales obligations to ENSTAR through 2017. This contract was assumed by ML&P and Chugach on the basis of ownership share.

77

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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%.

The BRU acquisition costs were recorded as deferred charges on Chugach’s balance sheet and totaled $1.5 million at December 31, 2016. Chugach 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.Chugach also requested approval to recover the deferred costs in the gas transfer price.  The RCA issued an order combining the BRU cost recovery process and the request to create a regulatory asset into a single docket.  On October 26, 2017, the RCA issued a final order accepting Chugach’s filing and closing the docket, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Beluga River Unit Gas Transfer Price.”

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 8Mcf and 84 Mcf at December 31, 2017 and 2016, respectively. 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, which expired December 31, 2017. Chugach recognized revenue from the BRU in the amount of $6.6 million and $2.8 million through December 31, 2017 and 2016, respectively.

Chugach records depreciation, depletion and amortization on BRU assets based on units of production. During 2017, Chugach lifted 1.4 Bcf resulting in a cumulative lift since purchase of 3.1 Bcf of the approximate 25.1 Bcf in Chugach’s proven developed reserves. Chugach, and other owners, ML&P and Hilcorp, are operating under an existing Joint Operating Agreement.  Hilcorp is the operator for BRU.  The owners are considering updating the existing Joint Operating Agreement to better match the new owners’ interests. 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.

78

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

(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, 2017, 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 aCBA with the Hotel Employees and Restaurant Employees (HERE). All three IBEW CBA’s and the HERE CBA have been renewed through June 30, 2021.  

Fuel Supply Contracts

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 Hilcorp agreement 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 to 49 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 2017, 81% of our power was generated from gas, with 14% generated at the Beluga Power Plant and 81% generated at SPP. In 2016, 77% of our power was generated from gas, with 9% generated at Beluga and 88% generated at SPP.

79

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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:

	2017		2016		2015
Hilcorp	88.4	%	56.9	%	30.3	%
Furie	5.3	%	0.0	%	0.0	%
ConocoPhillips (COP)	0.0	%	32.0	%	58.7	%
AIX Energy	0.1	%	0.7	%	4.7	%
ENSTAR	3.4	%	4.7	%	3.3	%
Harvest (Hilcorp) Pipeline	2.1	%	3.2	%	1.6	%
Miscellaneous	0.7	%	2.5	%	1.4	%

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. The Board of Directors approved a capital credit retirement on September 27, 2017. MEA received a retirement of $0.8 million, increasing their payable to $4.9 million at December 31, 2017. We also finalized a new agreement with HEA in September 2017, which spread their retirement payments between 2017 and 2020 in increments of $2.0 million annually. As a result,$2.0 million of HEA’s patronage capital was retired and paid in 2017, and $2.0 million of HEA’s patronage capital was reclassified to a current payable under other current liabilities leaving $3.9 million in long term patronage capital payable at December 31, 2017. At December 31, 2016, patronage capital payable to HEA and MEA was $7.9 million and $4.1 million, 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 $0.000899, effective July 1, 2017. 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.

80

Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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.

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 $4,206,223 and$2,507,482for this charge at December 31, 2017 and 2016, 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 increased 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. While awaiting the court decision, an Executive Order promoting energy independence and economic growth was issued March 28, 2017, by the President instructing the EPA to review the Clean Power Plan. The EPA is directed to review the Clean Power Plan rule and either revise or withdraw the proposed rule. On October 10, 2017, the EPA initiated a Proposed Repeal of the Clean Power Plan. 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

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Chugach Electric Association, Inc.

Notes to Consolidated Financial Statements

December 31, 2017 and 2016

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.

(17)  Quarterly Results of Operations (unaudited)

2017 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	62,934,930	$	49,405,607	$	51,554,650	$	60,793,482
Operating Expense		52,778,100		44,850,594		48,365,752		51,223,238
Net Interest		5,575,665		5,569,961		5,535,031		5,520,479
Net Operating Margins		4,581,165		(1,014,948)		(2,346,133)		4,049,765
Nonoperating Margins		157,569		207,513		201,916		211,877
Assignable Margins	$	4,738,734	$	(807,435)	$	(2,144,217)	$	4,261,642

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

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Item 9 –Changes in and Disagreements with

Accountants on Accounting and Financial Disclosure

None

Item 9A – Controls and Procedures

Evaluation of Controls and Procedures

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

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, 2017, 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, 2017, Chugach maintained effective internal controls over financial reporting.

Changes in Internal Control over Financial Reporting

There have been no changes in the Company’s internal control over financial reporting through the date of this report or during the quarter ended December 31, 2017, that materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Independent Registered Accountant’s Internal Control Attestation

This annual report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to applicable law.

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.

Bettina Chastain,  53,  Chair, is a private consultant at Arktis, LLC.  She has spent her career as an executive, business owner and engineer, 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 the community serving on several non-profit boards for many years. She was elected to the Board in May of 2015. She currently serves as a member of the Operations Committee and as a member of the Audit and FinanceCommittee.  She is a National Rural Electric Cooperative Association Credentialed Cooperative Director and has earned her Board Leadership Certificate. Her term expires in May of 2019.

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Susan Reeves, 69, 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 Audit and Finance Committee and as a member of the Operations Committee. She is a National Rural Electric Cooperative Association Credentialed Cooperative Director. Her term expires in May of 2020.

Jim Henderson, 71,  Secretary,  is a principal with New American Financial Group in the financial services industry. He specializes in asset-based finance products, reorganization and refinancing of distressed companies, and accounting and disposition of capital assets. His primary emphasis is transportation, industrial machinery and aviation operations, assets and industry development. He has over 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 and has earned his Board Leadership Certificate and Director Gold Credential. His term expires in May of 2018.

Sisi Cooper, 37, Treasurer, is a Process Risk Management Group Manager at Applied Engineering Solutions.She specializes in process safety and risk management, energy-sector project management, and process/facility engineering and design.  Ms. Cooper is a former project engineer with Doyon Anvil, LLC and former small business owner of North Ridge Home Inspections, LLC where she was the principal inspector. 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.  She is a National Rural Electric Cooperative Association Credentialed Cooperative Director and has earned her Board Leadership Certificate. Her term expires in May of 2019.

Harry T. Crawford, Jr., 65, 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 and 2017. He currently serves as a member of the Operations Committee and as a member of the Governance Committee. He is a National Rural Electric Cooperative Association Credentialed Cooperative Director and has earned his Board Leadership Certificate. His term expires in May of 2020.

Stuart Parks, 54, 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 in January 2017 and re-elected in May 2017.  He currently serves as the Chair of the Operations Committee. His term expires in May of 2021.

Rachel Morse,  46, Director,  is a partner with Blue Skies Solutions, LLC.  She has been a partner with Blue Skies Solutions, LLC since the business’s inception in 2003. Ms. Morse was Assistant Vice Chancellor for Alumni Relations at the University of Alaska Anchorage (UAA). She has also served as Development Director for the Rural Alaska Community Action Program, Inc., and Executive Director at the Bird Treatment and Learning Center. She has been a Chugach member for more than 17 years and served on the Nominating Committee from 2015-2017. She was appointed to the Board in December 2017. Her term expires in May of 2018.

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Identification of Executive Officers

Lee D. Thibert,  62,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.

Sherri Highers, 49, 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,  63, 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.  Mr. Risse is a registered professional engineer, and holds a Bachelor of Science degree in Electrical Engineering and a Masters of Business Administration (MBA).

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, 52, 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.

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Arthur W. Miller, 54, was appointed Vice President, Regulatory and External Affairs on January 2, 2018. Prior to becoming Vice President, he served as Executive Manager, Regulatory and External Affairs since July 18, 2016. Prior to this appointment, Mr. Miller held the Director, Regulatory Affairs and Pricing position since August 2009. He has served as a manager of the Regulatory Affairs and Pricing department since January 1996 and worked as a Senior Rate Analyst from June 1993 after being hired as a Rate Analyst in June 1990. 

Code of Ethics

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

Nominating Committee

Chugach has not made any material changes to the procedures by which our membership may recommend nominees to our Board. The Board appoints a Nominating Committee each year. The Nominating Committee consists of members selected from different sections of the service area of Chugach. No member of the Board may serve on the 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. All of our current Board members were nominated by the Nominating Committee.

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.

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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 2017 Audit and Finance Committee include Chair Sisi Cooper, Vice Chair Susan Reeves and Directors Jim Henderson and Bettina Chastain.

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.

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.

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CEO Lee Thibert must maintain an overall parameter performance scoreto be eligible for a performance-based payment. Annual performance payments are calculated as a percentage of his base salary,ranging from 0% to 30%, based on individual and company-wide performance objectives determined by the Board.  Various objectives include 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. In 2017, upon review of the performance of the CEO, Mr. Thibert received an award of $57,600.

Grants of Plan-Based Awards

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards
Name	Grant Date	Threshold		Target		Maximum
Lee D. Thibert	3/22/2017	$	0	$	57,600	$	96,000
Chief Executive Officer

The median employee was determined as of December 31, 2017, and the total annual compensation, excluding change in pension value, of Chugach’s median employee was $141,617. The current CEO’s total compensation, excluding change in pension value, in 2017 was 3.56times 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 awards for all other named executive officers are set annually by the CEO within annual budget guidelines approved by the Board.

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.

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Cash Compensation

The following table sets forth all remuneration paid by us for the last three fiscal years to each of our executive officers, each of whose total cash and cash equivalent compensation exceeded $100,000 for 2017:

Summary Compensation Table

Name	Year	Salary		Cash Award		Change in Pension Value and Nonqualified Deferred Compensation		All Other Compensation 1		Total
Lee D. Thibert,	2017	$	321,954	$	57,600	$	233,706	$	7,575	$	620,835
Chief Executive Officer	2016	$	293,138	$	29,590	$	171,215	$	6,687	$	500,630
	2015	$	247,266	$	27,000	$	148,951	$	18,888	$	442,105
Sherri L. Highers,	2017	$	185,221	$	29,240	$	98,311	$	1,813	$	314,585
Chief Financial Officer	2016	$	176,405	$	18,422	$	75,726	$	932	$	271,485
	2015	$	175,692	$	12,500	$	66,509	$	25,165	$	279,866
Paul R. Risse	2017	$	216,669	$	34,401	$	61,258	$	5,031	$	317,359
Sr. Vice President,	2016	$	211,885	$	17,517	$	126,256	$	4,731	$	360,389
Production & Engineering	2015	$	215,447	$	16,000	$	114,127	$	12,595	$	358,169
Tyler E. Andrews,	2017	$	183,002	$	29,240	$	48,273	$	28,764	$	289,279
Vice President, Member and	2016	$	178,824	$	15,353	$	41,669	$	8,353	$	244,199
Employee Services	2015	$	181,744	$	14,500	$	37,243	$	34,169	$	267,656
Brian J. Hickey,	2017	$	219,226	$	34,401	$	70,566	$	3,350	$	327,543
Sr. Vice President,	2016	$	208,460	$	7,424	$	54,913	$	3,029	$	273,826
System Operations	2015	$	205,024	$	4,000	$	49,591	$	5,177	$	263,792

1Includes costs for life insurance premiums, tax withholdings on awards, 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 multi-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, 2017, 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 1
Lee D. Thibert, Chief Executive Officer	Retirement Security	0.17	$	2,201,756	$	21,102
Sherri L. Highers, Chief Financial Officer	Retirement Security	18.08	$	653,641	$	0
Paul R. Risse, Sr. VP, Production & Engineering	Retirement Security	0.92	$	61,258	$	1,497,116
Tyler E. Andrews, VP, Member and Employee Services	Retirement Security	8.75	$	370,844	$	0
Brian J. Hickey, VP, System Operations	Retirement Security	23.83	$	1,164,139	$	0

1Payments issued as a result of quasi-retirements

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 PBGC rate (1.25% for 2017 and 1.25% for 2016),  30-year Treasury rate (2.86% for 2017 and 3.03% for 2016) and the PPA three-segment yield rates (1.79, 3.80%, and 4.71% for 2017 and 1.76, 4.15%, and 5.13% for 2016) and the required IRS mortality table for lump sum payments (1994 GAR, projected to 2002, blended 50%/50% for unisex mortality in combination with the 30-year Treasury rates and RP 2000 PPA at 2017 and 2016, respectively, combined unisex 50%/50% mortality in combination with the PPA rates).The lump sum is then discounted at 3.56% interest only (no mortality is assumed) from assumed retirement date back to December 31, 2017, and 4.03% interest only (no mortality is assumed) from assumed retirement date back to December 31, 2016, 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	$	18,000	$	0	$	1,108	$	0	$	21,720
Chief Executive Officer
Tyler E. Andrews,	$	18,000	$	0	$	14,464	$	0	$	117,263
Vice President, Member and
Employee Services
Paul Risse	$	18,000	$	0	$	1,106	$	0	$	19,106
Sr. Vice President,
Production & Engineering

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Potential Termination Payments

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

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 1
Lee D. Thibert,	$	453,816
Chief Executive Officer
Sherri L. Highers,	$	136,307
Chief Financial Officer
Paul R. Risse,	$	284,726
Sr. Vice President, Production & Engineering
Brian J. Hickey,	$	133,039
Sr. Vice President, System Operations
Tyler E. Andrews,	$	103,248
Vice President, Member and Employee Services

1Estimated severance payment is calculated as of the last business day of 2017.

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Director Compensation

Directors are compensated for their services at the rate of $300 per Board meeting and $200 per other meeting at which they are representing Chugach in an official capacity within the State of Alaska, and $350 per day when attending meetings or training outside of the State, including a fee for each day of travel, plus reimbursement of reasonable out of pocket expenses, up to a maximum of 70 meetings per year for a director and 85 meetings per year for the Chair. The Chair of the Board receives an additional $50 per day for each day of each meeting if the Chair performs the duties of Chair at the meeting.

The following table sets forth the dollar amounts of all fees paid in cash by us for the fiscal year ending December 31, 2017, to each of our current and former Board members:

Director Compensation Table

Name	Fees Paid In Cash
Bettina Chastain, Chair and Director	$	17,400
Susan Reeves, Vice-Chair and Director	$	14,900
Jim Henderson, Secretary and Director	$	17,400
Sisi Cooper, Treasurer and Director	$	15,800
Harry Crawford, Jr., Director	$	17,450
Stuart Parks, Director	$	16,600
Rachel Morse, Director	$	0
Janet Reiser, Former Chair and Director	$	24,850
Total	$	124,400

Two Board members were re-elected at Chugach’s annual membership meeting held on May 18, 2017. Stuart Parks was elected to a four year term and Harry Crawford was elected to a three year term. Janet Reiser resigned from the Board effective December 31, 2017, due to her acceptance of a position as the Executive Director at Alaska Energy Authority. The Board appointed Rachel Morse on December 26, 2017, to fill the vacancy left as a result of Janet Reiser’s resignation.

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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

The Chugach Board has a written “Prohibited Conduct and Conflict of Interest” policy and procedures for review and approval of related-party transactions. If a related-party transaction subject to review involves directly or indirectly:

· The CEO or a member of the Board (or an immediate family member or domestic partner), the remaining Board members will conduct the review.

· An employee (or an immediate family member or domestic partner), the CEO will conduct the review and shall determine whether it is necessary to inform the Board.

Among other factors, the nature of the transaction and whether the transaction or relationship impairs the ability of the employee or director to serve the best interests of Chugach are evaluated during the review.

There are no relationships or transactions to which Chugach is a party, or intended to be a party, subject to disclosure under Item 404(a) of Regulation S-K.

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, 2017.

Fees and Services

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

	2017		2016
Audit and audit-related services:
Audit and quarterly reviews	$	274,094	$	270,341
Audit-related services		34,013		42,608
Non-audit services:
Tax consulting and return preparation		10,700		12,568
Other services		0		0
Total	$	318,807	$	325,517

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, 2017 and 2016 were pre-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, 2017 and 2016	42-43
Statements of Operations
Years ended December 31, 2017, 2016 and 2015	44
Statements of Changes in Equities and Margins
Years ended December 31, 2017, 2016 and 2015	45
Statements of Cash Flows
Years ended December 31, 2017, 2016 and 2015	46
Notes to Financial Statements	47-82

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.
4.31	Sixth Supplemental Indenture to the Second Amended and Restated Indenture of Trust between the Registrant and U.S. Bank National Association dated March 17, 2017
4.32	Bond Purchase Agreement between the Registrant and the 2017 Series A Bond Purchasers dated March 17, 2017
4.33	Form of 2017 Series A Bond (Tranche A) due March 15, 2037
10.2P	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.  (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.3P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).

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10.4.2	2006 Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective February 27, 2007. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2007, SEC File No. 033-42125.
10.4.3	Amendment No. 2 to the 2006 Agreement for the Sale and Purchase of Electric Power and Energy between the Registrant and the City of Seward dated effective March 1, 2012. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2012, SEC File No. 033-42125.
10.7	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.
10.17P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
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.
10.19P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).

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10.20P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.22	Amendment No. 1 to the 1993 Alaska Intertie Project Participants Agreement dated December 10, 1999. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
10.23	Grant Administration Agreement by and among the Registrant, Alaska Industrial Development and Export Authority, Golden Valley Electric Association, Inc., Fairbanks Municipal Utilities System, Anchorage Municipal Light & Power, Alaska Electric Generation and Transmission Cooperative, Inc. (on behalf of Homer Electric Association, Inc. and Matanuska Electric Association, Inc.) and City of Seward dated August 30, 1994. Previously filed as an exhibit to the Registrant’s Registration Statement on Form S-1 dated March 22, 2001, SEC File No. 333-57400.
10.24P	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.(Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.24.1	Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Sale and Purchase of Electric Power by and among the Registrant, the Alaska Power Authority, Golden Valley Electric Association, Inc., the Municipality of Anchorage, the City of Seward, the Alaska Electric Generation and Transmission Cooperative, Inc., Homer Electric Association, Inc. and Matanuska Electric Association Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.

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10.25P	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.(Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.25.1	Partial Assignment of Bradley Lake Hydroelectric Project Agreement for the Wheeling of Electric Power and for Related Services by and among the Registrant, Homer Electric Association, Inc., Golden Valley Electric Association, Inc., Matanuska Electric Association, Inc., the Municipality of Anchorage, Inc. d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System and Alaska Electric Generation and Transmission Cooperative, Inc. dated June 30, 2003. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2003, SEC File No. 033-42125.
10.26P	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.(Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.27P	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.(Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.28P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.29P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).

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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.
10.30P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.30.1P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.30.2P	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.(Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.31P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.32P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.33	Eklutna Hydroelectric Project Closing Documents dated October 2, 1997. Previously reported as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 1997, SEC File No. 033-42125.
10.35	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.

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10.36P	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. (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
10.37P	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.  (Filed on paper – hyperlink is not required pursuant to Rule 105 of Regulation S-T).
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.
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.

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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.
10.47.5	Line of Credit Agreement between the Registrant and the National Rural Utilities Cooperative Finance Corporation (NRUCFC) dated September 29, 2017
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.
10.58.3	Letter of Agreement By and Between the Registrant and the Hotel Employees and Restaurant Employees Union Local 878 dated effective July 1, 2017
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.

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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.
10.59.3	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, 2017
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.
10.60.4	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, 2017
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.

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10.61.1	Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 for Outside Plant Personnel dated effective July 1, 2010. Previously filed as an exhibit to the Registrant’s Annual Report on Form 10-K dated December 31, 2009, SEC File No. 033-42125.
10.61.2	Letter of Agreement By and Between the Registrant and the International Brotherhood of Electrical Workers Local 1547 Representing Outside Plant Bargaining Unit dated effective July 1, 2013. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated March 31, 2013, SEC File No. 033-42125.
10.61.3	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, 2017
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.
10.68	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.

107

10.75.1	First Amendment to the Gas Sale and Purchase Agreement between the Registrant and Hilcorp Alaska, LLC effective September 15, 2014. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated September 30, 2014, SEC File No. 033-42125.
10.75.2	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.
10.81	Firm and Interruptible Gas Sale and Purchase Agreement (GSA) between theRegistrant and Furie Operating Alaska, LLC dated effective May 1, 2017.

108

14	Code of Ethics for Senior Financial Officers of the Registrant dated effective June 16, 2004. Previously filed as an exhibit to the Registrant’s Quarterly Report on Form 10-Q dated June 30, 2004, SEC File No. 033-42125.
31.1	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS	XBRL Instance Document
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

PFiled on Paper

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 20, 2018.  

CHUGACH ELECTRIC ASSOCIATION, INC.
By:	/s/ Lee D. Thibert
	Lee D. Thibert
	Chief Executive Officer
Date:	March 20, 2018

110

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 19, 2018, 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/ Arthur W. Miller
Arthur W. Miller	Vice President, Regulatory and External Affairs
/s/ Bettina Chastain
Bettina Chastain	Director & Chair of the Board
Susan Reeves	Director & Vice Chair of the Board
/s/ Sisi Cooper
Sisi Cooper	Director & Treasurer of the Board
/s/ Jim Henderson
Jim Henderson	Director & Secretary of the Board

111

/s/ Harry T. Crawford, Jr.
Harry T. Crawford, Jr.	Director
/s/ Stuart Parks
Stuart Parks	Director
/s/ Rachel Morse
Rachel Morse	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

No annual report or proxy materials have been sent to security holders and no such report or proxy materials are to be furnished to security holders subsequent to the filing of this Annual Report on Form 10-K.

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 20, 2018	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 20, 2018	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, 2017, 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 20, 2018	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, 2017, 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 20, 2018	By:	/s/ Sherri L. Highers
		Sherri L. Highers
		Chief Financial Officer
		Principal Financial Officer

XML

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Jun. 30, 2017
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, 2017
Document Fiscal Year Focus	2017
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding	0
Entity Public Float		$ 0

XML

Consolidated Balance Sheets - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Utility plant:
Electric plant in service	$ 1,205,092,224	$ 1,192,513,869
Construction work in progress	17,952,573	18,455,940
Total utility plant	1,223,044,797	1,210,969,809
Less accumulated depreciation	(515,496,312)	(496,098,131)
Net utility plant	707,548,485	714,871,678
Other property and investments, at cost:
Nonutility property	76,889	76,889
Investments in associated organizations	8,980,410	9,349,311
Special funds	1,466,010	907,836
Restricted cash equivalents	1,028,758	810,559
Investments - other	0	3,061,434
Total other property and investments	11,552,067	14,206,029
Current assets:
Cash and cash equivalents	5,485,631	4,672,935
Special deposits	54,300	75,942
Restricted cash equivalents	687,370	899,723
Marketable securities	11,420,900	7,375,381
Fuel cost under-recovery	4,921,794	0
Accounts receivable, less provisions for doubtful accounts of $555,336 in 2017 and $484,352 in 2016	35,680,680	33,000,919
Materials and supplies	15,291,095	27,889,167
Fuel stock	6,901,994	6,321,676
Prepayments	4,953,170	1,407,026
Other current assets	257,193	294,697
Total current assets	85,654,127	81,937,466
Other non-current assets:
Deferred charges, net	32,764,065	25,140,957
Total other non-current assets	32,764,065	25,140,957
Total assets	837,518,744	836,156,130
Equities and margins:
Memberships	1,719,154	1,691,014
Patronage capital	172,928,887	169,996,436
Other	14,653,253	13,828,075
Total equities and margins	189,301,294	185,515,525
Long-term obligations, excluding current installments:
Bonds payable	421,833,331	405,249,998
Notes payable	37,164,000	40,356,000
Less unamortized debt issuance costs	(2,669,485)	(2,715,745)
Total long-term obligations	456,327,846	442,890,253
Current liabilities:
Current installments of long-term obligations	26,608,667	24,836,667
Commercial paper	50,000,000	68,200,000
Accounts payable	7,420,279	9,618,630
Consumer deposits	5,335,896	5,207,585
Fuel cost over-recovery	0	3,824,722
Accrued interest	5,991,619	5,873,368
Salaries, wages and benefits	7,017,131	7,315,898
Fuel	9,913,781	6,284,338
Other current liabilities	7,079,821	3,234,586
Total current liabilities	119,367,194	134,395,794
Other non-current liabilities:
Deferred compensation	1,229,294	907,836
Other liabilities, non-current	531,630	655,277
Deferred liabilities	1,249,390	1,179,414
Patronage capital payable	8,798,077	12,008,499
Cost of removal obligation / asset retirement obligation	60,714,019	58,603,532
Total other non-current liabilities	72,522,410	73,354,558
Total liabilities, equities and margins	$ 837,518,744	$ 836,156,130

XML

Consolidated Balance Sheets (Parenthetical) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Consolidated Balance Sheets [Abstract]
Accounts receivable, provision for doubtful accounts	$ 555,336	$ 484,352

XML

Consolidated Statements Of Operations - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Consolidated Statements Of Operations [Abstract]
Operating revenues	$ 224,688,669	$ 197,747,579	$ 216,421,152
Operating expenses:
Fuel	78,552,672	54,778,582	66,534,877
Production	18,006,490	15,809,168	16,886,257
Purchased power	17,301,067	15,774,733	19,599,994
Transmission	6,129,871	5,590,737	6,287,558
Distribution	13,991,088	13,991,997	14,089,862
Consumer accounts	5,968,736	6,073,710	6,117,625
Administrative, general and other	23,256,983	22,888,048	23,623,299
Depreciation and amortization	34,010,777	36,233,414	35,652,086
Total operating expenses	197,217,684	171,140,389	188,791,558
Interest expense:
Long-term debt and other	22,366,034	21,856,095	22,194,290
Charged to construction	(164,898)	(454,798)	(379,845)
Interest expense, net	22,201,136	21,401,297	21,814,445
Net operating margins	5,269,849	5,205,893	5,815,149
Nonoperating margins:
Interest income	644,663	425,173	296,788
Allowance for funds used during construction	69,157	188,111	142,881
Capital credits, patronage dividends and other	65,055	(5,321)	248,034
Total nonoperating margins	778,875	607,963	687,703
Assignable margins	$ 6,048,724	$ 5,813,856	$ 6,502,852

XML

Consolidated Statements Of Changes In Equities And Margins - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Balance		$ 185,515,525		$ 181,637,381	$ 185,515,525	$ 181,637,381	$ 176,925,299
Assignable margins	$ 4,738,734	4,261,642	$ 5,632,088	2,628,930	6,048,724	5,813,856	6,502,852
Retirement/net transfer of capital credits					(3,116,273)	(3,265,201)	(3,190,124)
Unclaimed capital credit retirements					612,752	1,175,962	1,298,410
Memberships and donations received					240,566	153,527	100,944
Balance	189,301,294		185,515,525		189,301,294	185,515,525	181,637,381
Memberships [Member]
Balance		1,691,014		1,661,744	1,691,014	1,661,744	1,631,569
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					28,140	29,270	30,175
Balance	1,719,154		1,691,014		1,719,154	1,691,014	1,661,744
Other Equities And Margins [Member]
Balance		13,828,075		12,527,856	13,828,075	12,527,856	11,158,677
Assignable margins					0	0	0
Retirement/net transfer of capital credits					0	0	0
Unclaimed capital credit retirements					612,752	1,175,962	1,298,410
Memberships and donations received					212,426	124,257	70,769
Balance	14,653,253		13,828,075		14,653,253	13,828,075	12,527,856
Patronage Capital [Member]
Balance		$ 169,996,436		$ 167,447,781	169,996,436	167,447,781	164,135,053
Assignable margins					6,048,724	5,813,856	6,502,852
Retirement/net transfer of capital credits					(3,116,273)	(3,265,201)	(3,190,124)
Unclaimed capital credit retirements					0	0	0
Memberships and donations received					0	0	0
Balance	$ 172,928,887		$ 169,996,436		$ 172,928,887	$ 169,996,436	$ 167,447,781

XML

Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities:
Assignable margins	$ 6,048,724	$ 5,813,856	$ 6,502,852
Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation and amortization	34,010,777	36,233,414	35,652,086
Amortization and depreciation cleared to operating expenses	4,791,978	4,988,068	4,390,385
Allowance for funds used during construction	(69,157)	(188,111)	(142,881)
Write off of inventory, deferred charges and projects	413,690	997,301	691,035
Other	27,986	248,482	(220,496)
(Increase) decrease in assets:
Accounts receivable, net	(2,858,099)	(4,926,631)	6,866,956
Fuel cost under-recovery	(4,921,794)	0	0
Materials and supplies	896,455	(850,493)	(1,070,896)
Fuel stock	(580,318)	741,865	2,588,532
Prepayments	(3,546,144)	59,275	712,422
Other assets	59,146	(71,144)	215,738
Deferred charges	(201,775)	(10,374,429)	(405,746)
Increase (decrease) in liabilities:
Accounts payable	(1,469,106)	750,538	(270,416)
Consumer deposits	128,311	206,901	86,424
Fuel cost over-recovery	(3,824,722)	(1,311,023)	3,673,688
Accrued interest	118,251	(42,212)	(276,028)
Salaries, wages and benefits	(298,767)	56,092	(287,510)
Fuel	3,629,443	1,342,028	(6,195,299)
Other current liabilities	(2,045,800)	(1,051,220)	(290,715)
Deferred liabilities	(17,927)	(128,221)	(123,695)
Net cash provided by operating activities	30,291,152	32,494,336	52,096,436
Cash flows from investing activities:
Return of capital from investment in associated organizations	370,010	319,233	352,420
Investment in restricted cash equivalents	(5,846)	(1,398)	(1,141)
Investment in special funds	(236,716)	0	0
Investment in marketable securitiesand investments-other	(924,903)	(10,580,000)	0
Investment in Beluga River Unit	0	(44,403,922)	0
Proceeds from restricted cash equivalents	0	1,140,343	0
Proceeds from capital grants	115,453	1,021,929	2,395,331
Extension and replacement of plant	(28,879,926)	(36,984,892)	(35,094,355)
Net cash used in investing activities	(29,561,928)	(89,488,707)	(32,347,745)
Cash flows from financing activities:
Payments for debt issue costs	(206,871)	(277,155)	0
Net increase (decrease) in short-term obligations	(18,200,000)	48,200,000	(1,000,000)
Proceeds from long-term obligations	40,000,000	45,600,000	0
Repayments of long-term obligations	(24,836,667)	(48,181,832)	(23,889,777)
Memberships and donations received	853,318	1,329,489	357,365
Retirement of patronage capital and estate payments	(2,258,047)	(4,378,853)	(182,352)
Net receipts on consumer advances for construction	4,731,739	3,748,738	4,228,030
Net cash provided by (used in) financing activities	83,472	46,040,387	(20,486,734)
Net change in cash and cash equivalents	812,696	(10,953,984)	(738,043)
Cash and cash equivalents at beginning of period	4,672,935	15,626,919	16,364,962
Cash and cash equivalents at end of period	5,485,631	4,672,935	15,626,919
Supplemental disclosure of non-cash investing and financing activities:
Cost of removal obligation	2,110,487	3,008,808	1,366,318
Asset retirement obligation assumed upon BRU acquisition	0	3,523,409	0
Extension and replacement of plant included in accounts payable	1,185,788	1,915,033	2,582,947
Patronage capital retired/net transferred and included in other current liabilities	2,057,036	0	2,105,440
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized	$ 20,911,535	$ 20,220,317	$ 21,891,308

XML

Description Of Business

12 Months Ended

Dec. 31, 2017

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, Homer Electric Association, Inc. (HEA), 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.

XML

Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

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), 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 (2o) – “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, removal cost, less salvage, is charged to accumulated depreciation.  Renewals and betterments are capitalized, while maintenance and repairs are normally charged to expense as incurred.

In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain 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, 2017 are as follows:

Annual Depreciation Rate Ranges

	Six months ending June 30, 2017			Six months ending December 31, 2017
Steam production plant	3.15%	-	3.84%	3.03%	-	3.26%
Hydroelectric production plant	1.06%	-	3.00%	0.88%	-	2.71%
Other production plant	3.15%	-	8.85%	2.18%	-	3.46%
Transmission plant	1.58%	-	7.86%	1.01%	-	10.50%
Distribution plant	2.16%	-	9.63%	1.40%	-	10.00%
General plant	1.57%	-	20.00%	1.95%	-	33.33%
Other	2.75%	-	2.75%	2.75%	-	2.75%

On March 23, 2017, the RCA approved revised depreciation rates effective July 1, 2017 in Docket U-16-081(2). 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.

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 FASB 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.

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 2017, 2016 or 2015.

g. Investments – Other

Investments – other consists of certificates of deposit with a maturity greater than 12 months.  Total investments – other were$3.1million as of December 31, 2016. 

h. Special Funds

Special funds includes deposits associated with the deferred compensation plan and an investment associated with the BRU ARO. The BRU ARO investment was established pursuant to an agreement with the State of Alaska and was $0.2million as of December 31, 2017.

i. Cash and Cash Equivalents / Restricted Cash Equivalents

For purposes of the statement of cash flows, Chugach considers all highly liquid instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. Chugach has a concentration account with First National Bank Alaska (FNBA). There is no rate of return or fees on this account. The concentration account had an average balance of $6,454,809and $5,897,767 during the years ended December 31, 2017 and 2016, respectively.

Restricted cash equivalents include funds on deposit for future workers’ compensation claims.  Total current and long term restricted cash equivalents were $1.7million at December 31, 2017 and 2016.

j. Marketable Securities

Chugach’s marketable securities consist of bond mutual funds, corporate bonds, and certificates of deposit with a maturity less than 12 months, classified as trading securities, reported at fair value with gains and losses in earnings. Net gains on marketable securities are included in nonoperating margins – capital credits, patronage dividends and other, and are summarized as follows:

	Twelve months ended December 31, 2017
Net gains and losses recognized during the period on trading securities	$	59,182
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	$	59,182

k. Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers. Included in accounts receivable are invoiced amounts to ML&P for their proportionate share of current Southcentral Power Project (SPP) costs, which amounted to $1.3million and $1.4 million in 2017 and 2016, respectively. At December 31, 2017 and 2016, accounts receivable also included $1.1million and $0.7 million, respectively, from BRU operations primarily associated with gas sales to ENSTAR.

l. Materials and Supplies

Materials and supplies are stated at average cost.

m. Fuel Stock

Fuel Stock is the weighted average cost of fuel injected into Cook Inlet Natural Gas Storage Alaska (CINGSA). Chugach’s fuel balance in storage for the years ended December 31, 2017 and 2016 amounted to $6.9  million and $6.3million, respectively.

n. 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.

o. 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 liabilities 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. The balance of the prepayment in deferred charges at December 31, 2017 and 2016 was $7.2million and $7.9million, respectively.  

p. 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.

q. Consumer Deposits

Consumer deposits include amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 2017 and 2016, totaled $3.7million and $3.3 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances totaled $1.6 million and $1.9 million for the years ended December 31, 2017 and 2016.

r. 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 2j 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.

s. 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 $10,674,543and $10,940,274 of unbilled retail revenue at December 31, 2017 and 2016, 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.

t. 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 4.1%during 2017 and 4.3% during 2016 and 2015.  

u. 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.

v. 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, 2017, 2016 and 2015 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, 2015 through December 31, 2017 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2017.

w. 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.  Chugach received no grants in 2017 and$0.6 million in 2016.

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Accounting Pronouncements

12 Months Ended

Dec. 31, 2017

Accounting Pronouncements [Abstract]

Accounting Pronouncements

(3)Accounting Pronouncements

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. Chugach adopted the standard on January 1, 2018 using the modified retrospective transition method with an immaterial cumulative effect adjustment as of the January 1, 2018 adoption date.

We have evaluated our energy sales contracts, including retail, wholesale, and economy energy, and do not believe there will be an impact to the timing or pattern of revenue recognition from our 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 2017 was approximately 99% of our total operating revenue.

The adoption of Topic 606 also includes additional disclosure requirements beginning in the first quarter of 2018, including expanded disclosures around the amount, timing, nature and uncertainty of revenues from contracts with customers. We  are finalizing the required disclosures.

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, 2019. 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 2016-02 on 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 2016-13 “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 for 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.

ASC Update 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)”

In November 2016, the FASB issued ASC Update 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” ASC Update 2016-18 clarifies how to classify and present changes in restricted cash or cash equivalents that occur when there are transfers between cash, cash equivalents, and restricted cash or restricted cash equivalents and when there are direct cash receipts into or payments made from restricted cash or restricted cash equivalents on the statement of cash flows to limit the diversity in practice. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted. Chugach will begin application of ASC 2016-18 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2017-01 “Business Combinations (Topic 805): Clarifying the Definition of a Business”

In January 2017, the FASB issued ASC Update 2017-01, “Business Combinations (Topic 805): Clarifying the Definition of a Business.” ASC Update 2017-01 clarifies the definition of a business by providing a screen to determine when a set of assets and activities acquired or disposed of constitute a business, as well as a framework for evaluating whether all elements of a business are present in the set. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted only when the transaction has not been reported in financial statements. Chugach will begin application of ASC 2017-01 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2017-07 “Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”

In March 2017, the FASB issued ASC Update 2017-07, “Compensation – Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost.” ASC Update 2017-07 amends current guidance on the presentation and disclosure of other compensation costs in the income statement. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those years, with early adoption permitted only for financial statements that have not been issued. Chugach will begin application of ASC 2017-07 on January 1, 2018. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows.

ASC Update 2018-01 “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842”

In January 2018, the FASB issued ASC Update 2018-01, “Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842.” ASC Update 2018-01 amends current guidance to provide an optional transition practical expedient allowing entities to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under the current leases guidance in Topic 840. 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 2018-01 on January 1, 2019. Chugach is evaluating the impact of the Lease update as well as existing land easements to determine if we will elect to use the practical expedient for transition as well as the effect on our results of operations, financial position, and cash flows.

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Fair Value Of Assets And Liabilities

12 Months Ended

Dec. 31, 2017

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.

The table below presents the balance of Chugach’s marketable securities measured at fair value on a recurring basis at December 31, 2017 and 2016. Chugach’s bond mutual funds, corporate bonds, and marketable certificates of deposit are measured using quoted prices in active markets. Chugach had no other assets or liabilities measured at fair value on a recurring basis at December 31, 2017 or 2016.  

December 31, 2017	Total		Level 1		Level 2		Level 3
Bond mutual funds	$	8,109,242	$	8,109,242	$	0	$	0
Corporate bonds	$	248,335	$	248,335	$	0	$	0
Certificates of deposit	$	3,063,323	$	3,063,323	$	0	$	0
December 31, 2016	Total		Level 1		Level 2		Level 3
Bond mutual funds	$	7,375,381	$	7,375,381	$	0	$	0
Certificates of deposit	$	3,061,434	$	3,061,434	$	0	$	0

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 estimated fair values (in thousands) of long-term obligations included in the financial statements at December 31, 2017,  are as follows:

	Carrying Value		Fair Value Level 2
Long-term obligations (including current installments)	$	485,606	$	511,196

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Regulatory Matters

12 Months Ended

Dec. 31, 2017

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 was 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. Chugach and MEA signed an agreement to extend the gas dispatch agreement through March 31, 2018, and later signed an amendment to extend the agreement through March 31, 2019. A letter order was issued by the RCA on September 22, 2017, approving the amendment to the agreement to extend gas dispatch services as filed in Tariff Advice No. 442-8.

Simplified Rate Filing

Chugach is a participant in the Simplified Rate Filing (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, with filings made either on a quarterly or semi-annual basis. Chugach is a participant on a quarterly filing schedule basis. Chugach submitted quarterly SRF filings which resulted in a 3.0% decrease to system demand and energy rates effective July 1, 2017, and an increase of 1.9% for rates effective November 1, 2017. The SRF based on the September 2017 test year resulted in a 0.4% increase to system demand and energy rates effective February 1, 2018.

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 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 1.8Bcf 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, 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 $7.98per Mcf on April 1, 2032, the last year of the Furie Agreement.

On May 1, 2017, the RCA approved the Furie Agreement. The RCA also approved recovery of costs associated with the Furie Agreement through its fuel and purchased power cost adjustment process.

Beluga River Unit Gas Transfer Price

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. Docket U-16-062 / U-16-074 was established to address the creation of a regulatory asset for the recovery of costs associated with Chugach’s acquisition of a portion of ConocoPhillips Alaska, Inc.’s interest in the BRU and to determine the methodology to establish permanent rates for the gas transfer price (GTP) associated with Chugach’s ownership interest in the BRU. On September 7, 2017, the RCA issued U-16-062(7) / U-16-074(7) accepting a stipulation between Chugach and the Office of the Attorney General Regulatory Affairs and Public Advocacy Section and vacating the procedural hearing. On October 7, 2017, Chugach submitted the BRU GTP calculations to the RCA as part of a compliance filing to the settlement. On October 26, 2017, the RCA issued a final order accepting Chugach’s compliance filing and closing the docket.

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 the 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. 

The RCA opened Docket Number U-16-092 to review the petition. The RCA approved the petition May 17, 2017 closing docket U-16-092(2).

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. The filing was submitted to the RCA on September 30, 2016. Chugach proposed changes to depreciation rates that would result in a $5.9 million reduction in annual depreciation expense. On a demand and energy rate basis, the impact was 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, were3.2% and 1.9%, respectively. Chugach requested that the updated depreciation rates be implemented on July 1, 2017, for both accounting and ratemaking purposes.

On March 23, 2017, the RCA issued Order U-16-081(2) approving Chugach’s proposed changes to its depreciation rates. The depreciation rates were approved as filed. The RCA required Chugach to file a new depreciation study by July 1, 2022, based on plant activity as of December 31, 2021.

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 proposed 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 did 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.

On August 17, 2017, the Superior Court issued its order affirming the decisions by the RCA that it has authority in this case, that the RCA’s decision was not arbitrary, and that the RCA’s basis for assignment was reasonable.  The RCA’s assignment allocation remains unchanged.  There is no impact on Chugach’s margin levels as a result of a sale of found gas and any funds Chugach receives will be returned to members as a reduction to fuel expense.  It is not known if or when CINGSA will sell any of the found gas.

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.

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Utility Plant

12 Months Ended

Dec. 31, 2017

Utility Plant [Abstract]

Utility Plant

(6)Utility Plant

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

Electric plant in service:	2017		2016
Steam production plant	$	101,116,277	$	101,116,277
Hydroelectric production plant		33,659,129		33,659,129
Other production plant		287,765,474		287,404,484
Transmission plant		296,018,078		282,040,969
Distribution plant		315,862,812		294,641,485
General plant		55,164,994		54,982,432
Unclassified electric plant in service1		60,294,349		83,457,981
Intangible plant1		5,455,371		5,455,371
Beluga River Natural Gas Field (BRU Asset & ARO)		47,927,331		47,927,331
Other1		1,828,409		1,828,409
Total electric plant in service		1,205,092,224		1,192,513,869
Construction work in progress		17,952,573		18,455,940
Total electric plant in service and construction work in progress	$	1,223,044,797	$	1,210,969,809

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, 2017

Investments In Associated Organizations [Abstract]

Investments In Associated Organizations

(7)    Investments in Associated Organizations

Investments in associated organizations include the following at December 31:

	2017		2016
NRUCFC Capital Term Certificates	$	6,095,980	$	6,095,980
CoBank		2,819,307		3,188,490
Other		65,123		64,841
Total investments in associated organizations	$	8,980,410	$	9,349,311

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, 2017

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:

	2017		2016
Regulatory assets:
Debt issuance and reacquisition costs	$	386,892	$	492,850
Refurbishment of transmission equipment		95,679		104,939
Feasibility studies		237,425		1,387,285
Cooper Lake relicensing / projects		5,149,903		5,280,006
Fuel supply		1,801,970		2,005,052
Storm damage		453,166		647,381
Other regulatory deferred charges		815,722		849,933
Bond interest - market risk management		4,884,587		5,365,190
Environmental matters		978,820		1,024,171
Beluga parts and materials		10,696,210		0
Total regulatory assets		25,500,374		17,156,807
Other deferred charges:
NRECA pension plan prepayment		7,204,591		7,925,050
Post retirement benefit obligation		59,100		59,100
Total other deferred charges		7,263,691		7,984,150
Total deferred charges	$	32,764,065	$	25,140,957

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

	2017		2016
Regulatory assets:
Multi-stage Energy Storage	$	0	$	1,117,860
Regulatory studies and other		201,775		46,721
Total regulatory assets		201,775		1,164,581
Other deferred charges:
NRECA pension plan prepayment		0		7,925,050
Post retirement benefit obligation		59,100		59,100
Total other deferred charges		59,100		7,984,150
Total deferred charges	$	260,875	$	9,148,731

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:

	2017		2016
Refundable consumer advances for construction	$	416,263	$	328,360
Estimated initial installation costs for meters		100,927		118,854
Post retirement benefit obligation		732,200		732,200
Total deferred liabilities	$	1,249,390	$	1,179,414

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Patronage Capital

12 Months Ended

Dec. 31, 2017

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, 2017, Chugach had $172,928,887 of patronage capital (net of capital credits retired in 2017), which included $166,880,163 of patronage capital that had been assigned and $6,048,724of patronage capital to be assigned to its members. At December 31, 2016, Chugach had $169,996,436of patronage capital (net of capital credits retired in 2016), which included $164,182,580 of patronage capital that had been assigned and $5,813,856 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.

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. We finalized a new agreement with HEA in September 2017 which spread their retirement payments between 2017 and 2020 in increments of $2.0 million annually. As a result,$2.0 million of HEA’s patronage capital was retired and paid in 2017, and $2.0 million of HEA’s patronage capital was reclassified to a current payable under other current liabilities leaving $3.9million in long-term patronage capital payable at December 31, 2017.  HEA’s patronage capital payable was $7.9 million at December 31, 2016.

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 $4.9million and $4.1 million at December 31, 2017 and 2016, 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 long-term debt and equities and margins. Capital credit retirements authorized by our Board, less early retirements, were $2,631,928,  $3,001,426,  and $3,007,772 for the years ended December 31, 2017, 2016, and 2015, 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, 2017,  2016, and 2015 was $57,036,  $2,014,080, and$2,105,440, respectively.

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Other Equities

12 Months Ended

Dec. 31, 2017

Other Equities [Abstract]

Other Equities

(10)  Other Equities

A summary of other equities at December 31 follows:

	2017		2016
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		2,213,876		2,001,450
Unclaimed capital credit retirement1		12,415,752		11,803,000
Total other equities	$	14,653,253	$	13,828,075

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

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Debt

12 Months Ended

Dec. 31, 2017

Debt [Abstract]

Debt

(11)  Debt

Long-term obligations at December 31 are as follows:	2017		2016
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		63,000,000		67,500,000
2011 Series A Bond of 4.75%, maturing in 2041, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012		147,999,998		154,166,665
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		56,250,000		60,000,000
2012 Series A Bond of 4.41%, maturing in 2042, with interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042		88,000,000		95,000,000
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
2017 Series A Bond of 3.43%, maturing in 2037, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2018		40,000,000		0
2016 CoBank Note, 2.58% fixed rate note maturing in 2031, with interest and principal due quarterly beginning in 2016		40,356,000		43,776,000
Total long-term obligations	$	485,605,998	$	470,442,665
Less current installments		26,608,667		24,836,667
Less unamortized debt issuance costs		2,669,485		2,715,745
Long-term obligations, excluding current installments	$	456,327,846	$	442,890,253

Covenants

Chugach is required to comply with all covenants set forth in the Indenture that secures the 2011, 2012, and 2017 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., and CoBank, 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 Second Amended and Restated Master Loan Agreement with CoBank, which became effective on 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 interest expense.

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 long-term debt and equities and margins.

Maturities of Long‑term Obligations

Long-term obligations at December 31, 2017, mature as follows:

Year ending December 31		2011 Series A Bonds		2012 Series A Bonds		2016 CoBank Note		2017 Series A Bonds		Total
2018	$	10,666,667	$	10,750,000	$	3,192,000	$	2,000,000	$	26,608,667
2019		10,666,667		10,750,000		3,192,000		2,000,000		26,608,667
2020		10,666,667		10,750,000		3,420,000		2,000,000		26,836,667
2021		10,666,667		3,750,000		3,648,000		2,000,000		20,064,667
2022		10,666,667		3,750,000		3,876,000		2,000,000		20,292,667
Thereafter		157,666,663		154,500,000		23,028,000		30,000,000		365,194,663
	$	210,999,998	$	194,250,000	$	40,356,000	$	40,000,000	$	485,605,998

Lines of credit

Chugach maintains a $50.0 million line of credit with NRUCFC. Chugach did not utilize this line of credit in 2017 or 2016, and therefore had no outstanding balance at December 31, 2017 and 2016. The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. The borrowing rate was 3.00% at December 31, 2017, and 2.90% at December 31, 2016.

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 was renewed effective September 29, 2017, and expires September 29, 2022.  This line of credit is immediately available for unconditional borrowing.

Commercial Paper

On June 13, 2016, Chugach entered into a $150.0 million senior unsecured credit facility (Credit Agreement), which is used to back Chugach’s commercial paper program. The 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 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 2018, as needed.

Chugach had $50.0 million and $68.2 million of commercial paper outstanding at December 31, 2017 and 2016, respectively.

The following table provides information regarding 2017  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	$	65.0	0.94	%	July	$	41.1	1.40	%
February	$	63.0	0.92	%	August	$	41.5	1.40	%
March	$	60.9	1.04	%	September	$	45.7	1.40	%
April	$	44.4	1.14	%	October	$	48.4	1.39	%
May	$	42.4	1.14	%	November	$	46.0	1.39	%
June	$	40.2	1.29	%	December	$	48.7	1.67	%

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, through 2042. The bonds and all other long-term debt obligations are secured by a lien on substantially all of Chugach’s assets, pursuant to the Indenture, which became effective on January 20, 2011.

On June 30, 2016, Chugach entered into a 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 $40.4 million and $43.8 million outstanding on this facility at December 31, 2017, and 2016, respectively.

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. 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.

The following table provides additional information regarding the 2011 Series A , 2012 Series A, and 2017 SeriesA  bonds and the 2016 CoBank Note at December 31, 2017 (dollars in thousands):

	Maturing March 15,	Average Life (Years)	Interest Rate		Issue Amount		Carrying Value
2011 Series A, Tranche A	2031	6.7	4.20	%	$	90,000	$	63,000
2011 Series A, Tranche B	2041	11.7	4.75	%		185,000		148,000
2012 Series A, Tranche A	2032	7.2	4.01	%		75,000		56,250
2012 Series A, Tranche B	2042	15.0	4.41	%		125,000		88,000
2012 Series A, Tranche C	2042	14.7	4.78	%		50,000		50,000
2017 Series A, Tranche A	2037	10.2	3.43	%		40,000		40,000
2016 CoBank Note	2031	5.7	2.58	%		45,600		40,356
Total					$	610,600	$	485,606

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2017

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, 2017, 2016 and 2015 of $5.9million, $6.7 million and $6.7 million, respectively. The rate and number of employees in all significant pension plans did not materially change for the years ended December 31, 2017, 2016 and 2015.

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 multi-employer 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 of the year in which the amount is paid to the RS Plan. The 25% differential in billing rates is expected to continue for approximately 15 years from January 1, 2013. However unexpected changes in interest rates, asset returns and other plan experience, plan assumption changes, and other factors may have an impact on the differential in billing rates and the 15-year period.

On December 29, 2016, Chugach made a prepayment of $7.9 million to the NRECA RS Plan. See Note 2o – “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, 2021			N/A2
Subject to Funding Improvement Plan	No			No4
Surcharge Paid	N/A			N/A4
	2017	2016	2015	2017	2016	2015
Zone Status	Green	Green	Green	N/A1	N/A1	N/A1
Required minimum contributions	None	None	None	N/A	N/A	N/A
Contributions (in millions)	$3.3	$3.2	$3.1	$2.6	$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, 2017, 2016, and 2015 were $4.8million, $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, 2017, 2016, and 2015 totaled $2.8million, $2.8 million, and $2.6 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, 2017, 2016 and 2015 were $141.8thousand, $132.3 thousand and $133.6 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 2017, 2016, and 2015, and allowed catch-up contributions for those over 50 years of age of $6,000 in 2017, 2016, and 2015. 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, 2017, and 2016 was $1,229,294 and$907,836, 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, 2017

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 $16.3 million. Upon the default of a Bradley Lake participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs pro rata, to the extent necessary to compensate for the failure of another participant to pay its share, provided that no participant’s percentage share is increased by more than 25%. 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. Management believes that such expenditures, if any, would be recoverable through the fuel recovery process.

The Battle Creek Diversion Project (Project) is a project to increase water available for generation by constructing a diversion on the West Fork of Upper Battle Creek to divert flows to Bradley Lake, increasing annual energy output by an estimated 37,000 MWh. The Bradley Lake Project Management Committee (BPMC) approved the project October 13, 2017, as amended December 1, 2017, and December 6, 2017.  The Project cost is estimated at $47.0 million and the BMPC approved financing in this amount on December 6, 2017.  The project is estimated to begin in the Spring of 2018 with an estimated completion date of 2020.  Not all Bradley Lake purchasers are participating in the development and resulting benefits of the Project at this time, although they have preserved their ability to participate in the Project at a later date.  Chugach would be entitled to 39.38% of the additional energy produced if no additional participants elect to join. 

The following represents information with respect to Bradley Lake at June 30, 2017 (the most recent date for which information is available). Chugach's share of expenses was $6,452,898 in 2017, $5,662,522 in 2016, and $5,663,304 in 2015 and is included in purchased power in the accompanying financial statements.

(In thousands)	Total		Proportionate Share
Plant in service	$	162,907	$	49,524
Long-term debt		43,940		13,358
Interest expense		2,652		806

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, 2017

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 2017 included $3,967,933, net of accumulated depreciation of $2,591,717, which represents Chugach’s share of the Eklutna Hydroelectric Project. In 2016, plant in service included $4,229,167, net of accumulated depreciation of $2,442,175. 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. When MEA was an all-requirements wholesale customer, under net billing arrangements, Chugach reimbursed MEA for their share of the costs. Chugach’s share of expenses was $403,511,  $532,678, and $689,501 in 2017, 2016, and 2015, 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, 2017

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. (CPAI) 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 and the transaction closed on April 22, 2016.

Additionally, CPAI had contractual gas sales obligations to ENSTAR through 2017. This contract was 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%.

The BRU acquisition costs were recorded as deferred charges on Chugach’s balance sheet and totaled $1.5 million at December 31, 2016. Chugach 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. Chugach also requested approval to recover the deferred costs in the gas transfer price.  The RCA issued an order combining the BRU cost recovery process and the request to create a regulatory asset into a single docket.  On October 26, 2017, the RCA issued a final order accepting Chugach’s filing and closing the docket, see “Item 8 – Financial Statements and Supplementary Data – Note 5 – Regulatory Matters – Beluga River Unit Gas Transfer Price.”

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 8 Mcf and 84 Mcf at December 31, 2017 and 2016, respectively. 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, which expired December 31, 2017. Chugach recognized revenue from the BRU in the amount of $6.6 million and $2.8 million through December 31, 2017 and 2016, respectively.

Chugach records depreciation, depletion and amortization on BRU assets based on units of production. During 2017, Chugach lifted 1.4 Bcf resulting in a cumulative lift since purchase of 3.1 Bcf of the approximate 25.1 Bcf in Chugach’s proven developed reserves. Chugach, and other owners, ML&P and Hilcorp, are operating under an existing Joint Operating Agreement.  Hilcorp is the operator for BRU.  The owners are considering updating the existing Joint Operating Agreement to better match the new owners’ interests. 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, 2017

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, 2017, 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 aCBA with the Hotel Employees and Restaurant Employees (HERE). All three IBEW CBA’s and the HERE CBA have been renewed through June 30, 2021.  

Fuel Supply Contracts

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 Hilcorp agreement 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 to 49 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 2017, 81% of our power was generated from gas, with 14% generated at the Beluga Power Plant and 81% generated at SPP. In 2016, 77% of our power was generated from gas, with 9% generated at Beluga and 88% generated at SPP.

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:

	2017		2016		2015
Hilcorp	88.4	%	56.9	%	30.3	%
Furie	5.3	%	0.0	%	0.0	%
ConocoPhillips (COP)	0.0	%	32.0	%	58.7	%
AIX Energy	0.1	%	0.7	%	4.7	%
ENSTAR	3.4	%	4.7	%	3.3	%
Harvest (Hilcorp) Pipeline	2.1	%	3.2	%	1.6	%
Miscellaneous	0.7	%	2.5	%	1.4	%

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. The Board of Directors approved a capital credit retirement on September 27, 2017. MEA received a retirement of $0.8 million, increasing their payable to $4.9 million at December 31, 2017. We also finalized a new agreement with HEA in September 2017, which spread their retirement payments between 2017 and 2020 in increments of $2.0 million annually. As a result,$2.0 million of HEA’s patronage capital was retired and paid in 2017, and$2.0 million of HEA’s patronage capital was reclassified to a current payable under other current liabilities leaving $3.9 million in long term patronage capital payable at December 31, 2017. At December 31, 2016, patronage capital payable to HEA and MEA was $7.9 million and $4.1 million, 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 $0.000899, effective July 1, 2017. 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.

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$4,206,223 and$2,507,482for this charge at December 31, 2017 and 2016, 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 increased 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. While awaiting the court decision, an Executive Order promoting energy independence and economic growth was issued March 28, 2017, by the President instructing the EPA to review the Clean Power Plan. The EPA is directed to review the Clean Power Plan rule and either revise or withdraw the proposed rule. On October 10, 2017, the EPA initiated a Proposed Repeal of the Clean Power Plan. 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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Quarterly Results Of Operations

12 Months Ended

Dec. 31, 2017

Quarterly Results Of Operations [Abstract]

Quarterly Results Of Operations

(17)  Quarterly Results of Operations (unaudited)

2017 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	62,934,930	$	49,405,607	$	51,554,650	$	60,793,482
Operating Expense		52,778,100		44,850,594		48,365,752		51,223,238
Net Interest		5,575,665		5,569,961		5,535,031		5,520,479
Net Operating Margins		4,581,165		(1,014,948)		(2,346,133)		4,049,765
Nonoperating Margins		157,569		207,513		201,916		211,877
Assignable Margins	$	4,738,734	$	(807,435)	$	(2,144,217)	$	4,261,642

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

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Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2017

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), 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 (2o) – “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, removal cost, less salvage, is charged to accumulated depreciation.  Renewals and betterments are capitalized, while maintenance and repairs are normally charged to expense as incurred.

In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain 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, 2017 are as follows:

Annual Depreciation Rate Ranges

	Six months ending June 30, 2017			Six months ending December 31, 2017
Steam production plant	3.15%	-	3.84%	3.03%	-	3.26%
Hydroelectric production plant	1.06%	-	3.00%	0.88%	-	2.71%
Other production plant	3.15%	-	8.85%	2.18%	-	3.46%
Transmission plant	1.58%	-	7.86%	1.01%	-	10.50%
Distribution plant	2.16%	-	9.63%	1.40%	-	10.00%
General plant	1.57%	-	20.00%	1.95%	-	33.33%
Other	2.75%	-	2.75%	2.75%	-	2.75%

On March 23, 2017, the RCA approved revised depreciation rates effective July 1, 2017 in Docket U-16-081(2). 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.

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 FASB 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.

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 2017, 2016 or 2015.

Investments - Other

g. Investments – Other

Investments – other consists of certificates of deposit with a maturity greater than 12 months.  Total investments – other were$3.1million as of December 31, 2016. 

Special Funds

h. Special Funds

Special funds includes deposits associated with the deferred compensation plan and an investment associated with the BRU ARO. The BRU ARO investment was established pursuant to an agreement with the State of Alaska and was $0.2million as of December 31, 2017.

Cash And Cash Equivalents / Restricted Cash Equivalents

i. Cash and Cash Equivalents / Restricted Cash Equivalents

For purposes of the statement of cash flows, Chugach considers all highly liquid instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. Chugach has a concentration account with First National Bank Alaska (FNBA). There is no rate of return or fees on this account. The concentration account had an average balance of $6,454,809and $5,897,767 during the years ended December 31, 2017 and 2016, respectively.

Restricted cash equivalents include funds on deposit for future workers’ compensation claims.  Total current and long term restricted cash equivalents were $1.7million at December 31, 2017 and 2016.

Marketable Securities

j. Marketable Securities

Chugach’s marketable securities consist of bond mutual funds, corporate bonds, and certificates of deposit with a maturity less than 12 months, classified as trading securities, reported at fair value with gains and losses in earnings. Net gains on marketable securities are included in nonoperating margins – capital credits, patronage dividends and other, and are summarized as follows:

	Twelve months ended December 31, 2017
Net gains and losses recognized during the period on trading securities	$	59,182
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	$	59,182

Accounts Receivable

k. Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers. Included in accounts receivable are invoiced amounts to ML&P for their proportionate share of current Southcentral Power Project (SPP) costs, which amounted to $1.3million and $1.4 million in 2017 and 2016, respectively. At December 31, 2017 and 2016, accounts receivable also included $1.1million and $0.7 million, respectively, from BRU operations primarily associated with gas sales to ENSTAR.

Materials And Supplies

l. Materials and Supplies

Materials and supplies are stated at average cost.

Fuel Stock

m. Fuel Stock

Fuel Stock is the weighted average cost of fuel injected into Cook Inlet Natural Gas Storage Alaska (CINGSA). Chugach’s fuel balance in storage for the years ended December 31, 2017 and 2016 amounted to $6.9  million and $6.3million, respectively.

Fuel And Purchased Power Cost Recovery

n. 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

o. 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 liabilities 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. The balance of the prepayment in deferred charges at December 31, 2017 and 2016 was $7.2million and $7.9million, respectively.  

Patronage Capital

p. 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

q. Consumer Deposits

Consumer deposits include amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 2017 and 2016, totaled $3.7million and $3.3 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances totaled $1.6 million and $1.9 million for the years ended December 31, 2017 and 2016.

Fair Value Of Financial Instruments

r. 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 2j 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

s. 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 $10,674,543and $10,940,274 of unbilled retail revenue at December 31, 2017 and 2016, 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

t. 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 4.1%during 2017 and 4.3% during 2016 and 2015.  

Environmental Remediation Costs

u. 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

v. 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, 2017, 2016 and 2015 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, 2015 through December 31, 2017 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2017.

Grants

w. 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.  Chugach received no grants in 2017 and$0.6 million in 2016.

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Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2017

Significant Accounting Policies [Abstract]

Schedule Of Depreciation And Amortization Rates

	Six months ending June 30, 2017			Six months ending December 31, 2017
Steam production plant	3.15%	-	3.84%	3.03%	-	3.26%
Hydroelectric production plant	1.06%	-	3.00%	0.88%	-	2.71%
Other production plant	3.15%	-	8.85%	2.18%	-	3.46%
Transmission plant	1.58%	-	7.86%	1.01%	-	10.50%
Distribution plant	2.16%	-	9.63%	1.40%	-	10.00%
General plant	1.57%	-	20.00%	1.95%	-	33.33%
Other	2.75%	-	2.75%	2.75%	-	2.75%

Schedule Of Gains And Losses On Trading Securities

	Twelve months ended December 31, 2017
Net gains and losses recognized during the period on trading securities	$	59,182
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	$	59,182

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Fair Value Of Assets And Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value Of Assets And Liabilities [Abstract]

Schedule Of Marketable Securities

December 31, 2017	Total		Level 1		Level 2		Level 3
Bond mutual funds	$	8,109,242	$	8,109,242	$	0	$	0
Corporate bonds	$	248,335	$	248,335	$	0	$	0
Certificates of deposit	$	3,063,323	$	3,063,323	$	0	$	0
December 31, 2016	Total		Level 1		Level 2		Level 3
Bond mutual funds	$	7,375,381	$	7,375,381	$	0	$	0
Certificates of deposit	$	3,061,434	$	3,061,434	$	0	$	0

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

	Carrying Value		Fair Value Level 2
Long-term obligations (including current installments)	$	485,606	$	511,196

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Utility Plant (Tables)

12 Months Ended

Dec. 31, 2017

Utility Plant [Abstract]

Schedule Of Major Classes Of Utility Plant

Electric plant in service:	2017		2016
Steam production plant	$	101,116,277	$	101,116,277
Hydroelectric production plant		33,659,129		33,659,129
Other production plant		287,765,474		287,404,484
Transmission plant		296,018,078		282,040,969
Distribution plant		315,862,812		294,641,485
General plant		55,164,994		54,982,432
Unclassified electric plant in service1		60,294,349		83,457,981
Intangible plant1		5,455,371		5,455,371
Beluga River Natural Gas Field (BRU Asset & ARO)		47,927,331		47,927,331
Other1		1,828,409		1,828,409
Total electric plant in service		1,205,092,224		1,192,513,869
Construction work in progress		17,952,573		18,455,940
Total electric plant in service and construction work in progress	$	1,223,044,797	$	1,210,969,809

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, 2017

Investments In Associated Organizations [Abstract]

Schedule Of Investments In Associated Organizations

	2017		2016
NRUCFC Capital Term Certificates	$	6,095,980	$	6,095,980
CoBank		2,819,307		3,188,490
Other		65,123		64,841
Total investments in associated organizations	$	8,980,410	$	9,349,311

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Deferred Charges And Liabilities (Tables)

12 Months Ended

Dec. 31, 2017

Regulatory Assets [Line Items]

Schedule Of Deferred Charges, Or Regulatory Assets

	2017		2016
Regulatory assets:
Debt issuance and reacquisition costs	$	386,892	$	492,850
Refurbishment of transmission equipment		95,679		104,939
Feasibility studies		237,425		1,387,285
Cooper Lake relicensing / projects		5,149,903		5,280,006
Fuel supply		1,801,970		2,005,052
Storm damage		453,166		647,381
Other regulatory deferred charges		815,722		849,933
Bond interest - market risk management		4,884,587		5,365,190
Environmental matters		978,820		1,024,171
Beluga parts and materials		10,696,210		0
Total regulatory assets		25,500,374		17,156,807
Other deferred charges:
NRECA pension plan prepayment		7,204,591		7,925,050
Post retirement benefit obligation		59,100		59,100
Total other deferred charges		7,263,691		7,984,150
Total deferred charges	$	32,764,065	$	25,140,957

Schedule Of Deferred Credits, Or Regulatory Liabilities

	2017		2016
Refundable consumer advances for construction	$	416,263	$	328,360
Estimated initial installation costs for meters		100,927		118,854
Post retirement benefit obligation		732,200		732,200
Total deferred liabilities	$	1,249,390	$	1,179,414

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

Regulatory Assets [Line Items]

Schedule Of Deferred Charges, Or Regulatory Assets

	2017		2016
Regulatory assets:
Multi-stage Energy Storage	$	0	$	1,117,860
Regulatory studies and other		201,775		46,721
Total regulatory assets		201,775		1,164,581
Other deferred charges:
NRECA pension plan prepayment		0		7,925,050
Post retirement benefit obligation		59,100		59,100
Total other deferred charges		59,100		7,984,150
Total deferred charges	$	260,875	$	9,148,731

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Other Equities (Tables)

12 Months Ended

Dec. 31, 2017

Other Equities [Abstract]

Schedule Of Other Equities

	2017		2016
Nonoperating margins, prior to 1967	$	23,625	$	23,625
Donated capital		2,213,876		2,001,450
Unclaimed capital credit retirement1		12,415,752		11,803,000
Total other equities	$	14,653,253	$	13,828,075

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

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Debt (Tables)

12 Months Ended

Dec. 31, 2017

Debt [Abstract]

Schedule Of Debt Issuance Costs Associated With Long-Term Obligations

Long-term obligations at December 31 are as follows:	2017		2016
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		63,000,000		67,500,000
2011 Series A Bond of 4.75%, maturing in 2041, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012		147,999,998		154,166,665
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		56,250,000		60,000,000
2012 Series A Bond of 4.41%, maturing in 2042, with interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042		88,000,000		95,000,000
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
2017 Series A Bond of 3.43%, maturing in 2037, with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2018		40,000,000		0
2016 CoBank Note, 2.58% fixed rate note maturing in 2031, with interest and principal due quarterly beginning in 2016		40,356,000		43,776,000
Total long-term obligations	$	485,605,998	$	470,442,665
Less current installments		26,608,667		24,836,667
Less unamortized debt issuance costs		2,669,485		2,715,745
Long-term obligations, excluding current installments	$	456,327,846	$	442,890,253

Schedule Of Maturities Of Long-Term Obligations

Year ending December 31		2011 Series A Bonds		2012 Series A Bonds		2016 CoBank Note		2017 Series A Bonds		Total
2018	$	10,666,667	$	10,750,000	$	3,192,000	$	2,000,000	$	26,608,667
2019		10,666,667		10,750,000		3,192,000		2,000,000		26,608,667
2020		10,666,667		10,750,000		3,420,000		2,000,000		26,836,667
2021		10,666,667		3,750,000		3,648,000		2,000,000		20,064,667
2022		10,666,667		3,750,000		3,876,000		2,000,000		20,292,667
Thereafter		157,666,663		154,500,000		23,028,000		30,000,000		365,194,663
	$	210,999,998	$	194,250,000	$	40,356,000	$	40,000,000	$	485,605,998

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	$	65.0	0.94	%	July	$	41.1	1.40	%
February	$	63.0	0.92	%	August	$	41.5	1.40	%
March	$	60.9	1.04	%	September	$	45.7	1.40	%
April	$	44.4	1.14	%	October	$	48.4	1.39	%
May	$	42.4	1.14	%	November	$	46.0	1.39	%
June	$	40.2	1.29	%	December	$	48.7	1.67	%

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	6.7	4.20	%	$	90,000	$	63,000
2011 Series A, Tranche B	2041	11.7	4.75	%		185,000		148,000
2012 Series A, Tranche A	2032	7.2	4.01	%		75,000		56,250
2012 Series A, Tranche B	2042	15.0	4.41	%		125,000		88,000
2012 Series A, Tranche C	2042	14.7	4.78	%		50,000		50,000
2017 Series A, Tranche A	2037	10.2	3.43	%		40,000		40,000
2016 CoBank Note	2031	5.7	2.58	%		45,600		40,356
Total					$	610,600	$	485,606

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2017

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, 2021			N/A2
Subject to Funding Improvement Plan	No			No4
Surcharge Paid	N/A			N/A4
	2017	2016	2015	2017	2016	2015
Zone Status	Green	Green	Green	N/A1	N/A1	N/A1
Required minimum contributions	None	None	None	N/A	N/A	N/A
Contributions (in millions)	$3.3	$3.2	$3.1	$2.6	$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, 2017

Bradley Lake Hydroelectric Project [Abstract]

Schedule Of Bradley Lake Information

(In thousands)	Total		Proportionate Share
Plant in service	$	162,907	$	49,524
Long-term debt		43,940		13,358
Interest expense		2,652		806

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Commitments And Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments And Contingencies [Abstract]

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

	2017		2016		2015
Hilcorp	88.4	%	56.9	%	30.3	%
Furie	5.3	%	0.0	%	0.0	%
ConocoPhillips (COP)	0.0	%	32.0	%	58.7	%
AIX Energy	0.1	%	0.7	%	4.7	%
ENSTAR	3.4	%	4.7	%	3.3	%
Harvest (Hilcorp) Pipeline	2.1	%	3.2	%	1.6	%
Miscellaneous	0.7	%	2.5	%	1.4	%

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Quarterly Results Of Operations (Tables)

12 Months Ended

Dec. 31, 2017

Quarterly Results Of Operations [Abstract]

Schedule Of Quarterly Results Of Operations

2017 Quarter Ended

	Dec. 31		Sept. 30		June 30		March 31
Operating Revenue	$	62,934,930	$	49,405,607	$	51,554,650	$	60,793,482
Operating Expense		52,778,100		44,850,594		48,365,752		51,223,238
Net Interest		5,575,665		5,569,961		5,535,031		5,520,479
Net Operating Margins		4,581,165		(1,014,948)		(2,346,133)		4,049,765
Nonoperating Margins		157,569		207,513		201,916		211,877
Assignable Margins	$	4,738,734	$	(807,435)	$	(2,144,217)	$	4,261,642

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

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Description Of Business (Details)	12 Months Ended
	Dec. 31, 2017 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

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Significant Accounting Policies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Significant Accounting Policies [Line Items]
Numerator percentage of total production	10.00%
Denominator percentage of estimated remaining proved reserves	10.00%
Impairment on investments	$ 0	$ 0	$ 0
Minimum number of days past balances reviewed	90 days
Other investments		3,100,000
Special funds	$ 1,466,010	907,836
Accounts receivable	35,680,680	33,000,919
Fuel stock	6,901,994	6,321,676
Multiemployer plan, Prepayment amount	7,200,000	7,900,000
Consumer deposits	3,700,000	3,300,000
Customer credits	$ 1,600,000	$ 1,900,000
Weighted average capital interest percentage	4.10%	4.30%	4.30%
Grant proceeds included in public utilities property, plant and equipment carrying amount	$ 0	$ 600,000
ALASKA
Significant Accounting Policies [Line Items]
Special funds	$ 200,000
NRECA Retirement 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	$ 1,300,000	1,400,000
BRU Operations For Gas Sales [Member]
Significant Accounting Policies [Line Items]
Accounts receivable	1,100,000	700,000
Unbilled Retail Revenues [Member]
Significant Accounting Policies [Line Items]
Accounts receivable	10,674,543	10,940,274
Concentration Account [Member]
Significant Accounting Policies [Line Items]
Average balance of cash account	6,454,809	$ 5,897,767
Funds On Deposit [Member]
Significant Accounting Policies [Line Items]
Restricted cash equivalents	$ 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%

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Significant Accounting Policies (Schedule Of Depreciation And Amortization Rates) (Details)	6 Months Ended
	Dec. 31, 2017	Jun. 30, 2017
Minimum [Member] | Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.03%	3.15%
Minimum [Member] | Hydroelectric Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	0.88%	1.06%
Minimum [Member] | Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.18%	3.15%
Minimum [Member] | Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	1.01%	1.58%
Minimum [Member] | Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	1.40%	2.16%
Minimum [Member] | General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	1.95%	1.57%
Minimum [Member] | Other Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.75%	2.75%
Maximum [Member] | Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.26%	3.84%
Maximum [Member] | Hydroelectric Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.71%	3.00%
Maximum [Member] | Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.46%	8.85%
Maximum [Member] | Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	10.50%	7.86%
Maximum [Member] | Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	10.00%	9.63%
Maximum [Member] | General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	33.33%	20.00%
Maximum [Member] | Other Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.75%	2.75%

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Significant Accounting Policies (Schedule Of Gains And Losses On Trading Securities) (Details)	12 Months Ended
	Dec. 31, 2017 USD ($)
Significant Accounting Policies [Abstract]
Net gains and losses recognized during the period on trading securities	$ 59,182
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	$ 59,182

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Accounting Pronouncements (Details)	12 Months Ended
	Dec. 31, 2017
Product Concentration Risk [Member] | Sales Revenue, Product Line [Member]
Concentration Risk [Line Items]
Energy percentage of revenue	99.00%

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Fair Value Of Assets And Liabilities (Schedule Of Marketable Securities) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Bond Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 8,109,242	$ 7,375,381
Corporate Bonds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	248,335
Certificates of Deposit [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,063,323	3,061,434
Level 1 [Member] | Bond Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	8,109,242	7,375,381
Level 1 [Member] | Corporate Bonds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	248,335
Level 1 [Member] | Certificates of Deposit [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	3,063,323	3,061,434
Level 2 [Member] | Bond Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Level 2 [Member] | Corporate Bonds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0
Level 2 [Member] | Certificates of Deposit [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Level 3 [Member] | Bond Mutual Funds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0	0
Level 3 [Member] | Corporate Bonds [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	0
Level 3 [Member] | Certificates of Deposit [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$ 0	$ 0

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Fair Value Of Assets And Liabilities (Schedule Of Estimated Fair Value Of Long-Term Obligations Included In Financial Statements) (Details) $ in Thousands	Dec. 31, 2017 USD ($)
Carrying Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	$ 485,606
Level 2 [Member] | Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations (including current installments)	$ 511,196

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Regulatory Matters (Details) Mcf in Millions, $ in Millions					1 Months Ended		3 Months Ended	4 Months Ended	12 Months Ended
	Mar. 16, 2017	Nov. 18, 2016 USD ($)	Dec. 04, 2015 Mcf	Jan. 30, 2015 Mcf	Feb. 28, 2018	Jan. 31, 2017	Jan. 31, 2018	Oct. 31, 2017	Dec. 31, 2017 USD ($) $ / Mcfe Mcf
Other Commitments [Line Items]
Proposed increase (decrease) in rates									$ (5.9)
Approved percentage increase (decrease) in rates							1.90%	(3.00%)
Term to finalize agreementerm to finalize agreement						1 year
Beluga Power Plant [Member]
Other Commitments [Line Items]
Recovery requested		$ 11.4
Beluga Power Plant, Unit 1 [Member] | Beluga Power Plant [Member]
Other Commitments [Line Items]
Recovery requested		$ 0.3
Amortization period of regulatory asset		30 months
Beluga Power Plant, Unit 2 [Member] | Beluga Power Plant [Member]
Other Commitments [Line Items]
Recovery requested		$ 11.1
Amortization period of regulatory asset		108 months
City Of Seward [Member]
Other Commitments [Line Items]
Proposed percentage increase (decrease) in rates									(4.60%)
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									(4.70%)
Retail Customers [Member] | Total Customer Bill Basis [Member]
Other Commitments [Line Items]
Proposed percentage increase (decrease) in rates									(3.20%)
Subsequent Event [Member]
Other Commitments [Line Items]
Approved percentage increase (decrease) in rates					0.40%
Hilcorp Alaska, LLC [Member]
Other Commitments [Line Items]
Expiration date of long term contract for purchase of gas supply									Mar. 31, 2018
CINGSA [Member]
Other Commitments [Line Items]
Total volume of natural gas found | Mcf				14.5
Approved volume of natural gas for commercial sale | Mcf			2.0
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 | Mcf									2.0
FSS [Member]
Other Commitments [Line Items]
Percentage of proceeds allocated			87.00%
Furie Operating Alaska, LLC [Member]
Other Commitments [Line Items]
Term of purchase commitment	16 years
Approximate annual volume | Mcf									1.8
Furie Operating Alaska, LLC [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] | Minimum [Member]
Other Commitments [Line Items]
Price of natural gas purchases | $ / Mcfe									7.16
Percentage of met natural gas needs									20.00%
Furie Operating Alaska, LLC [Member] | Maximum [Member]
Other Commitments [Line Items]
Price of natural gas purchases | $ / Mcfe									7.98
Percentage of met natural gas needs									25.00%
Eklutna Generation Station [Member]
Other Commitments [Line Items]
Expiration date of natural gas purchases									Mar. 31, 2016
Gas Dispatch Agreement [Member]
Other Commitments [Line Items]
Commencement date of natural gas purchases									Apr. 01, 2016
Expiration date of natural gas purchases									Mar. 31, 2017
Beluga River Unit [Member]
Other Commitments [Line Items]
Deferred cost of acquisition									$ 1.5

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Utility Plant (Details) - USD ($)		Dec. 31, 2017	Dec. 31, 2016
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment		$ 1,205,092,224	$ 1,192,513,869
Electric plant in service		1,205,092,224	1,192,513,869
Construction work in progress		17,952,573	18,455,940
Total utility plant		1,223,044,797	1,210,969,809
Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing		101,116,277	101,116,277
Hydroelectric Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing		33,659,129	33,659,129
Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing		287,765,474	287,404,484
Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Transmission		296,018,078	282,040,969
Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution		315,862,812	294,641,485
General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment		55,164,994	54,982,432
Electric plant in service		55,164,994	54,982,432
Unclassified Electric Plant In Service [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment	[1]	60,294,349	83,457,981
Electric plant in service	[1]	60,294,349	83,457,981
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	47,927,331
Electric plant in service		47,927,331	47,927,331
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, 2017	Dec. 31, 2016
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	$ 8,980,410	$ 9,349,311
NRUCFC Capital Term Certificates [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	2,819,307	3,188,490
Other [Member]
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	$ 65,123	$ 64,841

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Deferred Charges And Liabilities (Schedule Of Deferred Charges, Or Regulatory Assets) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Regulatory Assets [Line Items]
Total deferred charges	$ 32,764,065	$ 25,140,957
Debt Issuance And Reacquisition Costs [Member]
Regulatory Assets [Line Items]
Total regulatory assets	386,892	492,850
Refurbishment Of Transmission Equipment [Member]
Regulatory Assets [Line Items]
Total regulatory assets	95,679	104,939
Feasibility Studies [Member]
Regulatory Assets [Line Items]
Total regulatory assets	237,425	1,387,285
Cooper Lake Relicensing / Projects [Member]
Regulatory Assets [Line Items]
Total regulatory assets	5,149,903	5,280,006
Fuel Supply [Member]
Regulatory Assets [Line Items]
Total regulatory assets	1,801,970	2,005,052
Storm Damage [Member]
Regulatory Assets [Line Items]
Total regulatory assets	453,166	647,381
Other Regulatory Deferred Charges [Member]
Regulatory Assets [Line Items]
Total regulatory assets	815,722	849,933
Bond Interest - Market Risk Management [Member]
Regulatory Assets [Line Items]
Total regulatory assets	4,884,587	5,365,190
Environmental Matters [Member]
Regulatory Assets [Line Items]
Total regulatory assets	978,820	1,024,171
Beluga Parts And Materials [Member]
Regulatory Assets [Line Items]
Total regulatory assets	10,696,210	0
Regulatory Assets Excluding Other Deferred Charges [Member]
Regulatory Assets [Line Items]
Total regulatory assets	25,500,374	17,156,807
NRECA Retirement Plan [Member]
Regulatory Assets [Line Items]
Total deferred charges	7,204,591	7,925,050
Post Retirement Benefit Obligation [Member]
Regulatory Assets [Line Items]
Total deferred charges	59,100	59,100
Other Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	$ 7,263,691	$ 7,984,150

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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, 2017	Dec. 31, 2016
Regulatory Assets [Line Items]
Total deferred charges	$ 32,764,065	$ 25,140,957
Regulatory Assets Excluding Other Deferred Charges [Member]
Regulatory Assets [Line Items]
Total regulatory assets	25,500,374	17,156,807
NRECA Retirement Plan [Member]
Regulatory Assets [Line Items]
Total deferred charges	7,204,591	7,925,050
Post Retirement Benefit Obligation [Member]
Regulatory Assets [Line Items]
Total deferred charges	59,100	59,100
Other Regulatory Deferred Charges [Member]
Regulatory Assets [Line Items]
Total regulatory assets	815,722	849,933
Not Currently Being Recovered In Rates Charged to Consumers [Member]
Regulatory Assets [Line Items]
Total deferred charges	260,875	9,148,731
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Multi-Stage Energy Storage [Member]
Regulatory Assets [Line Items]
Total regulatory assets	0	1,117,860
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Regulatory Studies And Other [Member]
Regulatory Assets [Line Items]
Total regulatory assets	201,775	46,721
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Regulatory Assets Excluding Other Deferred Charges [Member]
Regulatory Assets [Line Items]
Total regulatory assets	201,775	1,164,581
Not Currently Being Recovered In Rates Charged to Consumers [Member] | NRECA Retirement Plan [Member]
Regulatory Assets [Line Items]
Total deferred charges	0	7,925,050
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Post Retirement Benefit Obligation [Member]
Regulatory Assets [Line Items]
Total deferred charges	59,100	59,100
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Other Regulatory Deferred Charges [Member]
Regulatory Assets [Line Items]
Total deferred charges	$ 59,100	$ 7,984,150

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Deferred Charges And Liabilities (Schedule Of Deferred Credits, Or Regulatory Liabilities) (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Total deferred liabilities	$ 1,249,390	$ 1,179,414
Refundable Consumer Advances For Construction [Member]
Regulatory Liabilities [Line Items]
Total deferred liabilities	416,263	328,360
Estimated Initial Installation Costs For Meters [Member]
Regulatory Liabilities [Line Items]
Total deferred liabilities	100,927	118,854
Post Retirement Benefit Obligation [Member]
Regulatory Liabilities [Line Items]
Total deferred liabilities	$ 732,200	$ 732,200

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Patronage Capital (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Patronage Capital [Line Items]
Patronage capital	$ 172,928,887	$ 169,996,436
Patronage capital assigned	166,880,163	164,182,580
Patronage capital to be assigned to members	6,048,724	5,813,856
Patronage capital payable, noncurrent	8,798,077	12,008,499
Retirement of capital credits	3,116,273	3,265,201	$ 3,190,124
Excluding Homer Electric Association Retirement [Member]
Patronage Capital [Line Items]
Retirement of capital credits	2,631,928	3,001,426	3,007,772
Excluding Matanuska Electric Association And Homer Electric Association Patronage Capital [Member]
Patronage Capital [Line Items]
Patronage capital payable, current	$ 57,036	2,014,080	$ 2,105,440
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, annual retirements	$ 2,000,000
Payments to retire patronage capital	2,000,000
Patronage capital payable, noncurrent	3,900,000	7,900,000
Patronage capital payable, current	2,000,000
Matanuska Electric Association, Inc. [Member]
Patronage Capital [Line Items]
Payments to retire patronage capital	800,000
Patronage capital payable, noncurrent	$ 4,900,000	$ 4,100,000
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, 2017	Dec. 31, 2016
Schedule Of Other Equities [Line Items]
Total other equities		$ 14,653,253	$ 13,828,075
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		2,213,876	2,001,450
Unclaimed Capital Credit Retirement [Member]
Schedule Of Other Equities [Line Items]
Total other equities	[1]	$ 12,415,752	$ 11,803,000

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

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Debt (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017 USD ($) item	Dec. 31, 2016 USD ($)	Jan. 11, 2012 USD ($)	Jan. 21, 2011 USD ($)
Debt Instrument [Line Items]
Commercial paper	$ 50,000,000	$ 68,200,000
Balance outstanding	$ 485,605,998	470,442,665
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	$ 610,600,000
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	3.00%	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
Amended And Unsecured Credit Agreement [Member] | Unsecured Credit Facility [Member]
Debt Instrument [Line Items]
Yield margins for interest multiplier to total interest expense | item	1.10
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
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 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
2016 CoBank Note [Member]
Debt Instrument [Line Items]
Bonds issuance amount	$ 45,600,000
Maturity date	Mar. 15, 2031
Interest rate	2.58%	2.58%
Average Life (Years)	5 years 8 months 12 days
Balance outstanding	$ 40,356,000	$ 43,776,000
2017 Series A Bonds [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Bonds issuance amount	$ 40,000,000
Maturity date	Mar. 15, 2037
Interest rate	3.43%
Average Life (Years)	10 years 2 months 12 days
Balance outstanding	$ 40,000,000	$ 0
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, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term Obligations	$ 485,605,998	$ 470,442,665
Less current installments	26,608,667	24,836,667
Less unamortized debt issuance costs	2,669,485	2,715,745
Long-term obligations, excluding current installments	456,327,846	442,890,253
2011 Series A Bond Of 4.20% Maturing 2031 [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 63,000,000	$ 67,500,000
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	$ 147,999,998	$ 154,166,665
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	$ 56,250,000	$ 60,000,000
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	$ 88,000,000	$ 95,000,000
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
2017 Series A Bonds [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 40,000,000	$ 0
Interest rate	3.43%
Maturity year	2037
2016 CoBank Note [Member]
Debt Instrument [Line Items]
Long-term Obligations	$ 40,356,000	$ 43,776,000
Interest rate	2.58%	2.58%
Maturity year	2031

XML

Debt (Schedule Of Maturities Of Long-Term Obligations) (Details)	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
2018	$ 26,608,667
2019	26,608,667
2020	26,836,667
2021	20,064,667
2022	20,292,667
Thereafter	365,194,663
Total long-term obligations	485,605,998
2011 Series A Bonds [Member]
Debt Instrument [Line Items]
2018	10,666,667
2019	10,666,667
2020	10,666,667
2021	10,666,667
2022	10,666,667
Thereafter	157,666,663
Total long-term obligations	210,999,998
2012 Series A Bonds [Member]
Debt Instrument [Line Items]
2018	10,750,000
2019	10,750,000
2020	10,750,000
2021	3,750,000
2022	3,750,000
Thereafter	154,500,000
Total long-term obligations	194,250,000
2016 CoBank Note [Member]
Debt Instrument [Line Items]
2018	3,192,000
2019	3,192,000
2020	3,420,000
2021	3,648,000
2022	3,876,000
Thereafter	23,028,000
Total long-term obligations	40,356,000
2017 Series A Bonds [Member]
Debt Instrument [Line Items]
2018	2,000,000
2019	2,000,000
2020	2,000,000
2021	2,000,000
2022	2,000,000
Thereafter	30,000,000
Total long-term obligations	$ 40,000,000

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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, 2017	Nov. 30, 2017	Oct. 31, 2017	Sep. 30, 2017	Aug. 31, 2017	Jul. 31, 2017	Jun. 30, 2017	May 31, 2017	Apr. 30, 2017	Mar. 31, 2017	Feb. 28, 2017	Jan. 31, 2017
Short-term Debt [Line Items]
Average Balance	$ 48.7	$ 46.0	$ 48.4	$ 45.7	$ 41.5	$ 41.1	$ 40.2	$ 42.4	$ 44.4	$ 60.9	$ 63.0	$ 65.0
Weighted Average Interest Rate	1.67%	1.39%	1.39%	1.40%	1.40%	1.40%	1.29%	1.14%	1.14%	1.04%	0.92%	0.94%

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Debt (Schedule Of Additional Information Regarding Series A Bonds) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Carrying Value	$ 485,605,998
Term Loan Facility [Member]
Debt Instrument [Line Items]
Issue Amount	610,600,000
Carrying Value	$ 485,606,000
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)	6 years 8 months 12 days
Interest Rate	4.20%	4.20%
Issue Amount	$ 90,000,000
Carrying Value	$ 63,000,000
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)	11 years 8 months 12 days
Interest Rate	4.75%	4.75%
Issue Amount	$ 185,000,000
Carrying Value	$ 148,000,000
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 2 months 12 days
Interest Rate	4.01%	4.01%
Issue Amount	$ 75,000,000
Carrying Value	$ 56,250,000
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)	15 years
Interest Rate	4.41%	4.41%
Issue Amount	$ 125,000,000
Carrying Value	$ 88,000,000
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)	14 years 8 months 12 days
Interest Rate	4.78%	4.78%
Issue Amount	$ 50,000,000
Carrying Value	50,000,000
2017 Series A Bonds [Member]
Debt Instrument [Line Items]
Carrying Value	$ 40,000,000
2017 Series A Bonds [Member] | Term Loan Facility [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2037
Average Life (Years)	10 years 2 months 12 days
Interest Rate	3.43%
Issue Amount	$ 40,000,000
Carrying Value	$ 40,000,000
2016 CoBank Note [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2031
Average Life (Years)	5 years 8 months 12 days
Interest Rate	2.58%	2.58%
Issue Amount	$ 45,600,000
Carrying Value	$ 40,356,000

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Employee Benefit Plans (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Prepayment amount	$ 7,200,000	$ 7,900,000
Deferred compensation	$ 1,229,294	907,836
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 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	$ 5,900,000	6,700,000	$ 6,700,000
Union Health and Welfare Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	4,800,000	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	2,800,000	2,600,000
Money Purchase Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	$ 141,800	$ 132,300	$ 133,600

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Employee Benefit Plans (Schedule Of Information Regarding Individually Significant Pension Plans) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
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, 2021
Subject to Funding Improvement Plan	[1]	No
Surcharge Paid	[1]	NA
Zone Status	[1]	Green
Required minimum contributions	[1]	None
Contributions (in millions)	[1]	$ 3.3	$ 3.2	$ 3.1
Contributions > 5% of total plan contributions	[1]	Yes
NRECA Retirement 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]	$ 2.6	$ 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, 2017 USD ($) MWh MW	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Long-term Contract for Purchase of Electric Power [Line Items]
Purchased power	$ 17,301,067	$ 15,774,733	$ 19,599,994
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 increase in annual energy output | MWh	37,000
Estimated project cost	$ 47,000,000
Estimated entitled additional energy output percentage	39.38%
Purchased power	$ 6,452,898	$ 5,662,522	$ 5,663,304
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	16,300,000
Possible annual expenditures upon default	$ 6,000,000

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Bradley Lake Hydroelectric Project (Schedule Of Bradley Lake Information) (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Long-term Contract for Purchase of Electric Power [Line Items]
Plant in service	$ 1,223,044,797				$ 1,210,969,809				$ 1,223,044,797		$ 1,210,969,809
Long-term debt	485,605,998								485,605,998
Interest expense	$ 5,575,665	$ 5,569,961	$ 5,535,031	$ 5,520,479	$ 5,341,242	$ 5,427,440	$ 5,247,404	$ 5,385,211	$ 22,201,136		$ 21,401,297	$ 21,814,445
Bradley Lake Hydroelectric Project [Member] | Alaska Energy Authority [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Plant in service			162,907,000							$ 162,907,000
Long-term debt			43,940,000							43,940,000
Interest expense										2,652,000
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			49,524,000							49,524,000
Long-term debt			$ 13,358,000							13,358,000
Interest expense										$ 806,000

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Eklutna Hydroelectric Project (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Jointly Owned Utility Plant Interests [Line Items]
Net utility plant	$ 707,548,485				$ 714,871,678				$ 707,548,485	$ 714,871,678
Accumulated depreciation	515,496,312				496,098,131				515,496,312	496,098,131
Total operating expenses	$ 52,778,100	$ 44,850,594	$ 48,365,752	$ 51,223,238	47,000,307	$ 40,308,301	$ 41,472,710	$ 42,359,071	$ 197,217,684	171,140,389	$ 188,791,558
Eklutna Hydroelectric Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage ownership	30.00%								30.00%
Net utility plant	$ 3,967,933				4,229,167				$ 3,967,933	4,229,167
Accumulated depreciation	$ 2,591,717				$ 2,442,175				2,591,717	2,442,175
Total operating expenses									$ 403,511	$ 532,678	$ 689,501
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 ($) a Mcf	Dec. 31, 2017 USD ($) Mcf	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2016 USD ($) Mcf	Sep. 30, 2016 USD ($)	Jun. 30, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2017 USD ($) mi Mcf	Dec. 31, 2016 USD ($) Mcf	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Revenue		$ 62,934,930	$ 49,405,607	$ 51,554,650	$ 60,793,482	$ 57,741,954	$ 45,132,973	$ 44,622,517	$ 50,250,135	$ 224,688,669	$ 197,747,579	$ 216,421,152
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	$ 44,400,000
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	8				84				8	84
Revenue										$ 6,600,000	$ 2,800,000
Lifted amount of gas during the period | Mcf										1,400,000
Lifted amount of gas in proven developed reserves | Mcf		3,100,000								3,100,000
Remaining amount of gas in proven developed reserves | Mcf		25,100,000								25,100,000
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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Commitments And Contingencies (Narrative) (Details) Mcf in Millions	12 Months Ended
	Dec. 31, 2017 USD ($) $ / kWh contract item Mcf	Dec. 31, 2016 USD ($)
Other Commitments [Line Items]
Contingency accruals	$ 0
Percentage of power generated from gas	81.00%	77.00%
Patronage capital payable, noncurrent	$ 8,798,077	$ 12,008,499
Other current liabilities	$ 7,079,821	$ 3,234,586
Regulatory initial cost charge per KWH | $ / kWh	0.000626
Regulatory current cost charge per KWH | $ / kWh	0.000899
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%
Beluga Power Plant [Member]
Other Commitments [Line Items]
Percentage of power generated from gas	14.00%	9.00%
Southcentral Power Project Plant [Member]
Other Commitments [Line Items]
Percentage of power generated from gas	81.00%	88.00%
Homer Electric Association, Inc. [Member]
Other Commitments [Line Items]
Power contracts expiration date	Dec. 31, 2013
Patronage capital, annual retirements	$ 2,000,000
Payments to retire patronage capital	2,000,000
Patronage capital payable, noncurrent	3,900,000	$ 7,900,000
Patronage capital payable, current	2,000,000
Matanuska Electric Association, Inc. [Member]
Other Commitments [Line Items]
Payments to retire patronage capital	800,000
Patronage capital payable, noncurrent	$ 4,900,000	4,100,000
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
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 | Mcf	49
Percentage Of Met Natural Gas Needs	100.00%
Number of contract extensions | contract	2
Moving Overhead Lines Underground [Member]
Other Commitments [Line Items]
Other current liabilities	$ 4,206,223	$ 2,507,482
International Brotherhood of Electrical Workers [Member]
Other Commitments [Line Items]
Percentage of employees belonging to unions	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

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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, 2017	Dec. 31, 2016	Dec. 31, 2015
Hilcorp Alaska, LLC [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	0.10%	0.70%	4.70%
Furie Operating Alaska, LLC [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	5.30%	0.00%	0.00%
ConocoPhillips (COP) [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	88.40%	56.90%	30.30%
AIX Energy, LLC [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	0.00%	32.00%	58.70%
ENSTAR [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	3.40%	4.70%	3.30%
Harvest (Hilcorp) Pipeline [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	2.10%	3.20%	1.60%
Miscellaneous [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	0.70%	2.50%	1.40%

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Quarterly Results Of Operations (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Results Of Operations [Abstract]
Operating revenues	$ 62,934,930	$ 49,405,607	$ 51,554,650	$ 60,793,482	$ 57,741,954	$ 45,132,973	$ 44,622,517	$ 50,250,135	$ 224,688,669	$ 197,747,579	$ 216,421,152
Operating expenses	52,778,100	44,850,594	48,365,752	51,223,238	47,000,307	40,308,301	41,472,710	42,359,071	197,217,684	171,140,389	188,791,558
Net interest	5,575,665	5,569,961	5,535,031	5,520,479	5,341,242	5,427,440	5,247,404	5,385,211	22,201,136	21,401,297	21,814,445
Net operating margins	4,581,165	(1,014,948)	(2,346,133)	4,049,765	5,400,405	(602,768)	(2,097,597)	2,505,853	5,269,849	5,205,893	5,815,149
Nonoperating margins	157,569	207,513	201,916	211,877	231,683	125,332	127,871	123,077	778,875	607,963	687,703
Assignable margins	$ 4,738,734	$ (807,435)	$ (2,144,217)	$ 4,261,642	$ 5,632,088	$ (477,436)	$ (1,969,726)	$ 2,628,930	$ 6,048,724	$ 5,813,856	$ 6,502,852