Chugach Electric Association 10-K 24 Mar 16 2015 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Jun. 30, 2015
Document And Entity Information [Abstract]
Entity Registrant Name	CHUGACH ELECTRIC ASSOCIATION INC
Entity Filer Category	Non-accelerated Filer
Entity Central Index Key	878,004
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, 2015
Document Fiscal Year Focus	2,015
Current Fiscal Year End Date	--12-31
Entity Common Stock, Shares Outstanding	0
Entity Public Float		$ 0

Balance Sheets

Balance Sheets - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Utility Plant:
Electric plant in service	$ 1,128,474,292	$ 1,155,500,963
Construction work in progress	15,601,374	21,567,341
Total utility plant	1,144,075,666	1,177,068,304
Less accumulated depreciation	(469,199,226)	(497,601,371)
Net utility plant	674,876,440	679,466,933
Other property and investments, at cost:
Nonutility property	76,889	76,889
Investments in associated organizations	9,635,519	9,923,552
Special funds	763,913	666,967
Restricted cash equivalents	1,705,760	1,705,086
Total other property and investments	12,182,081	12,372,494
Current assets:
Cash and cash equivalents	15,626,919	16,364,962
Special deposits	74,416	79,390
Restricted cash equivalents	1,143,467	1,143,000
Accounts receivable, less provisions for doubtful accounts of $425,751 in 2015 and $346,749 in 2014	28,232,930	36,060,256
Materials and supplies	27,611,184	26,774,512
Fuel stock	7,063,541	9,652,073
Prepayments	1,466,301	2,178,723
Other current assets	225,079	242,682
Total current assets	81,443,837	92,495,598
Deferred charges, net	19,492,653	21,376,596
Total assets	787,995,011	805,711,621
Equities and margins:
Memberships	1,661,744	1,631,569
Patronage capital	167,447,781	164,135,053
Other	12,527,856	11,158,677
Total equities and margins	181,637,381	176,925,299
Long-term obligations, excluding current installments:
Bonds payable	426,666,665	448,083,332
National Bank for Cooperatives bond payable	22,241,852	24,941,165
Total long-term obligations	448,908,517	473,024,497
Current liabilities:
Current installments of long-term obligations	24,115,980	23,889,777
Commercial paper	20,000,000	21,000,000
Accounts payable	9,701,088	9,746,175
Consumer deposits	5,000,684	4,914,260
Fuel cost over-recovery	5,135,745	1,462,057
Accrued interest	5,915,580	6,191,608
Salaries, wages and benefits	7,259,806	7,547,316
Fuel	4,942,310	11,137,609
Other current liabilities	8,076,903	4,594,865
Total current liabilities	90,148,096	90,483,667
Other non-current liabilities:
Deferred compensation	763,913	666,967
Other liabilities, non-current	1,555,329	1,842,000
Deferred liabilities	1,802,389	1,858,455
Patronage capital payable	11,108,071	10,205,739
Cost of removal obligation	52,071,315	50,704,997
Total other non-current liabilities	67,301,017	65,278,158
Total liabilities, equities and margins	$ 787,995,011	$ 805,711,621

Balance Sheets (Parenthetical)

Balance Sheets (Parenthetical) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Accounts receivable, provision for doubtful accounts	$ 425,751	$ 346,749

Statements Of Operations

Statements Of Operations - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statements Of Operations [Abstract]
Operating revenues	$ 216,421,152	$ 281,318,513	$ 305,308,427
Operating expenses:
Fuel	66,534,877	126,038,350	136,610,262
Production	16,886,257	21,082,176	21,911,324
Purchased power	19,599,994	15,608,396	27,836,680
Transmission	6,287,558	6,138,658	6,624,836
Distribution	14,089,862	13,002,157	13,225,242
Consumer accounts	6,117,625	5,887,713	6,014,888
Administrative, general and other	23,623,299	25,036,248	23,131,149
Depreciation and amortization	35,652,086	40,179,181	43,384,116
Total operating expenses	188,791,558	252,972,879	278,738,497
Interest expense:
Long-term debt and other	22,194,290	23,264,041	24,691,582
Charged to construction	(379,845)	(463,335)	(1,310,110)
Interest expense, net	21,814,445	22,800,706	23,381,472
Net operating margins	5,815,149	5,544,928	3,188,458
Nonoperating margins:
Interest income	296,788	566,639	686,460
Allowance for funds used during construction	142,881	163,151	141,014
Gain of sale of asset	0	0	6,436,992
Capital credits, patronage dividends and other	248,034	240,827	91,119
Total nonoperating margins	687,703	970,617	7,355,585
Assignable margins	$ 6,502,852	$ 6,515,545	$ 10,544,043

Statements Of Changes In Equiti

Statements Of Changes In Equities And Margins - USD ($)	3 Months Ended				12 Months Ended
	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Balance		$ 176,925,299		$ 175,795,865	$ 176,925,299	$ 175,795,865	$ 166,764,373
Assignable margins	$ 3,411,797	6,046,730	$ 5,214,661	5,001,831	6,502,852	6,515,545	10,544,043
Retirement/net transfer of capital credits					(3,190,124)	(5,130,381)	(1,626,828)
Unclaimed capital credit retirements					1,298,410	(350,776)	(21,456)
Memberships and donations received					100,944	95,046	135,733
Balance	181,637,381		176,925,299		181,637,381	176,925,299	175,795,865
Memberships [Member]
Balance		1,631,569		1,600,058	1,631,569	1,600,058	1,559,344
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					30,175	31,511	40,714
Balance	1,661,744		1,631,569		1,661,744	1,631,569	1,600,058
Other Equities And Margins [Member]
Balance		11,158,677		11,445,918	11,158,677	11,445,918	11,372,355
Assignable margins					0	0	0
Retirement/net transfer of capital credits					0	0	0
Unclaimed capital credit retirements					1,298,410	(350,776)	(21,456)
Memberships and donations received					70,769	63,535	95,019
Balance	12,527,856		11,158,677		12,527,856	11,158,677	11,445,918
Patronage Capital [Member]
Balance		$ 164,135,053		$ 162,749,889	164,135,053	162,749,889	153,832,674
Assignable margins					6,502,852	6,515,545	10,544,043
Retirement/net transfer of capital credits					(3,190,124)	(5,130,381)	(1,626,828)
Unclaimed capital credit retirements					0	0	0
Memberships and donations received					0	0	0
Balance	$ 167,447,781		$ 164,135,053		$ 167,447,781	$ 164,135,053	$ 162,749,889

Statements Of Cash Flows

Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Assignable margins	$ 6,502,852	$ 6,515,545	$ 10,544,043
Adjustments to reconcile assignable margins to net cash provided by operating activities:
Depreciation and amortization	35,652,086	40,179,181	43,384,116
Amortization and depreciation cleared to operating expenses	4,390,385	5,777,628	5,912,254
Allowance for funds used during construction	(142,881)	(163,151)	(141,014)
Write off of inventory, deferred charges and projects	691,035	974,062	430,453
Gain on sale of Bernice Lake Power Plant	0	0	(6,436,992)
Other	(220,496)	56,250	240,836
(Increase) decrease in assets:
Accounts receivable, net	6,866,956	6,879,762	4,823,879
Materials and supplies	(1,070,896)	(1,197,127)	(907,942)
Fuel stock	2,588,532	3,377,775	(3,563,081)
Prepayments	712,422	(315,316)	293,455
Other assets	215,738	978,338	(1,827,291)
Deferred charges	(405,746)	(1,050,505)	(317,070)
Increase (decrease) in liabilities:
Accounts payable	(270,416)	(420,041)	1,775,412
Consumer deposits	86,424	62,702	571,657
Fuel cost over-recovery	3,673,688	(173,620)	(12,074,372)
Accrued interest	(276,028)	(321,252)	(294,347)
Salaries, wages and benefits	(287,510)	(385,047)	597,937
Fuel	(6,195,299)	(3,696,976)	(6,033,493)
Other current liabilities	(290,715)	1,653,424	1,134
Deferred liabilities	(123,695)	34,668	3,399
Net cash provided by operating activities	52,096,436	58,766,300	36,982,973
Cash flows from investing activities:
Return of capital from investment in associated organizations	352,420	351,162	424,484
Investment in restricted cash equivalents	(1,141)	(142)	0
Investment in marketable securities	0	(217,817)	(327,175)
Proceeds from the sale of marketable securities	0	10,522,620	0
Proceeds from capital grants	2,395,331	6,960,143	20,329,782
Extension and replacement of plant	(35,094,355)	(30,303,133)	(64,473,966)
Net cash used in investing activities	(32,347,745)	(12,687,167)	(44,046,875)
Cash flows from financing activities:
Proceeds from short-term obligations	23,000,000	22,000,000	45,500,000
Repayments of short-term obligations	(24,000,000)	(31,000,000)	(27,000,000)
Repayments of long-term obligations	(23,889,777)	(24,682,812)	(24,493,022)
Memberships and donations received	357,365	(255,730)	114,277
Retirement of patronage capital and estate payments	(182,352)	(4,114,541)	(156,565)
Net receipts on consumer advances for construction	4,228,030	3,991,749	3,398,906
Net cash used in financing activities	(20,486,734)	(34,061,334)	(2,636,404)
Net change in cash and cash equivalents	(738,043)	12,017,799	(9,700,306)
Cash and cash equivalents at beginning of period	16,364,962	4,347,163	14,047,469
Cash and cash equivalents at end of period	15,626,919	16,364,962	4,347,163
Supplemental disclosure of non-cash investing and financing activities:
Cost of removal obligation	1,366,318	3,565,605	2,511,077
Extension and replacement of plant included in accounts payable	2,582,947	2,382,117	3,817,788
Patronage capital retired and included in other current liabilities	2,105,440	2,572,670	2,512,753
Supplemental disclosure of cash flow information - interest expense paid, net of amounts capitalized	$ 21,891,308	$ 21,835,216	$ 21,839,391

Description Of Business

Description Of Business	12 Months Ended
	Dec. 31, 2015
Description Of Business [Abstract]
Description Of Business	(1) Description of Business Chugach Electric Association, Inc. (Chugach) is the largest electric utility in Alaska. Chugach is engaged in the generation, transmission and distribution of electricity to directly serve retail customers in the Anchorage and upper Kenai Peninsula areas. 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. We provided much of the power requirements of Matanuska Electric Association, Inc. (MEA) and Homer Electric Association, Inc. (HEA) through their contract expiration dates of April 30, 2015 , and December 31, 2013 , respectively. 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 . Chugach was organized as an Alaska electric cooperative in 1948 and operates on a not ‑for ‑profit basis and, accordingly, seeks only to generate revenues sufficient to pay operating and maintenance costs, the cost of purchased power, capital expenditures, depreciation, and principal and interest on all indebtedness and to provide for reserves. Chugach is subject to the regulatory authority of the Regulatory Commission of Alaska (RCA).

Significant Accounting Policies

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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 allowance for doubtful accounts, workers’ compensation, deferred charges and credits, unbilled revenue, the estimated useful life of utility plant and the cost of removal obligation. Actual results could differ from those estimates. b. Regulation The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 980, “Topic 980 - Regulated Operations.” FASB ASC 980 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates. Our regulated rates are established to recover all of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs and those rates are then collected from our retail and wholesale customers. The regulatory assets or liabilities are then reduced as the cost or credit is reflected in earnings and our rates, see Note (2j) – “ Deferred Charges and Credits.” c. Utility Plant and Depreciation Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. For property replaced or retired, the book value of the property, less salvage, is charged to accumulated depreciation. The removal cost is charged to cost of removal obligation. Renewals and betterments are capitalized, while maintenance and repairs are normally charged to expense as incurred. In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain asset groups are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset group may not be recoverable in rates. Recoverability of asset groups to be held and used is measured by a comparison of the carrying amount of an asset group to estimated undiscounted future cash flows expected to be generated by the asset group. If the carrying amount of an asset group exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset group exceeds the fair value of the asset. Depreciation and amortization rates have been applied on a straight ‑line basis and at December 31, 2015 are as follows: Annual Depreciation Rate Ranges Steam production plant 4.81% - 7.04% Hydroelectric production plant 1.06% - 3.00% Other production plant 3.98% - 10.15% Transmission plant 1.58% - 7.86% Distribution plant 2.17% - 9.63% General plant 1.57% - 20.00% Other 2.75% - 2.75% Southcentral Power Project (SPP) steam production plant 3.09% - 3.46% SPP other production plant 3.15% - 3.84% On November 1, 2010, the RCA approved revised depreciation rates effective November 1, 2010 in Docket U-09-097. Chugach’s depreciation rates include a provision for cost of removal. Chugach records a separate liability for the estimated obligation related to the cost of removal. On August 31, 2012, in Docket U-12-009, the RCA approved Southcentral Power Project (SPP) depreciation rates effective February 1, 2013, the date the SPP plant was placed in service. d. Capitalized Interest Allowance for funds used during construction (AFUDC) and interest charged to construction ‑ credit (IDC) are the estimated costs of the funds used during the period of construction from both equity and borrowed funds. AFUDC and IDC are applied to specific projects during construction. AFUDC and IDC calculations use the net cost of borrowed funds when used and is recovered through RCA approved rates as utility plant is depreciated. For all projects excluding SPP, Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 4.3% during 2015 and 2014 and 3.7% during 2013. For SPP, Chugach capitalized actual interest expense and related fees associated with its construction. e. Investments in Associated Organizations The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) requires as a condition of the extension of credit, that an equity ownership position be established by all borrowers. Chugach’s equity ownership in these organizations is less than one percent. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment. No impairment was recorded during 2015, 2014 and 2013. f. Fair Value of Financial Instruments FASB ASC 825, “Topic 825 – Financial Instruments,” requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments: Cash and cash equivalents – the carrying amount approximates fair value because of the short maturity of those instruments. Consumer deposits – the carrying amount approximates fair value because of the short refunding term. Long ‑term obligations – the fair value is estimated based on the quoted market price for same or similar issues (see note 11). Restricted cash – the carrying amount approximates fair value because of the short maturity of those instruments. The fair value of accounts receivable and payable, and other short-term monetary assets and liabilities approximate carrying value due to their short-term nature. g. Cash and Cash Equivalents / Restricted Cash Equivalents For purposes of the statement of cash flows, Chugach considers all highly liquid instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. Chugach has a concentration account with First National Bank Alaska (FNBA). There is no rate of return or fees on this account. The concentration account had an average balance of $6,218,015 and $6,300,149 during the years ended December 31, 2015 and 2014, respectively. Restricted cash equivalents include funds on deposit for future workers’ compensation claims and interim rates collected from customers and escrowed as required by the RCA. At December 31, 2015 and 2014, restricted cash equivalents included $2.8 million of funds on deposit for future workers’ compensation claims. At December 31, 2015 and 2014, there were no restricted cash equivalents representing interim rates collected from customers. h. Accounts Receivable Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers. Included in accounts receivable are invoiced amounts to Anchorage Municipal Light & Power (ML&P) for their proportionate share of current SPP costs, which amounted to $1.1 million and $0.9 million in 2015 and 2014, respectively. In addition, accounts receivable includes invoiced amounts for grants to support the construction of facilities to divert water and safely transmit electricity, which amounted to $0.2 million and $1.1 million in 2015 and 2014, respectively. i. Materials and Supplies Materials and supplies are stated at average cost. j. Deferred Charges and Credits In accordance with FASB ASC 980, Chugach’s financial statements reflect regulatory assets and liabilities. Continued accounting under FASB ASC 980 requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for ratemaking purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria. Chugach regulatory asset recoveries are embedded in base rates approved by the RCA. Specific costs incurred and recorded as Regulatory Assets, including the amortization period for recovery, are approved by the RCA either in standard Simplified Rate Filings (SRF), general rate case filings or specified independent requests. The rates approved related to the regulatory assets are matched to the amortization of actual expenses recognized. The regulatory assets are amortized and collected through rates over differing periods depending upon the period of benefit as established by the RCA. Deferred credits, primarily representing regulatory liabilities, are amortized to operating expense over the period required for ratemaking purposes. It also includes refundable contributions in aid of construction, which are credited to the associated cost of construction of property units. Refundable contributions in aid of construction are held in deferred credits pending their return or other disposition. If events or circumstances should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on Chugach’s financial position, results of operations or cash flows. k. Patronage Capital Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on Chugach’s statement of operations as assignable margins. These excess amounts (i.e. assignable margins) are considered capital furnished by the members, and are credited to their accounts and held by Chugach until such future time as they are retired and returned without interest at the discretion of the Board of Directors (Board). Retained assignable margins are designated on Chugach’s balance sheet as patronage capital. This patronage capital constitutes the principal equity of Chugach. The Board may also approve the return of capital to former members and estates who request early retirements at discounted rates under a discounted capital credits retirement plan authorized by the Board in September of 2002. l. Operating Revenues Revenues are recognized upon delivery of electricity. Operating revenues are based on billing rates authorized by the RCA, which are applied to customers’ usage of electricity. Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results. Chugach calculates unbilled revenue at the end of each month to ensure the recognition of a calendar year’s revenue. Chugach accrued $10,531,377 and $9,885,526 of unbilled retail revenue at December 31, 2015 and 2014, respectively. Wholesale revenue is recorded from metered locations on a calendar month basis, so no estimation is required. Chugach's tariffs include provisions for the recovery of gas costs according to gas supply contracts, as well as purchased power costs. m. Fuel and Purchased Power Cost Recovery Expenses associated with electric services include fuel used to generate electricity and power purchased from others. Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel and purchased power adjustment process, which is adjusted quarterly to reflect increases and decreases of such costs. We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates. The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under- or over-collection of fuel and purchase power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods. Fuel costs were over-recovered by $5,135,745 and by $1,462,057 in 2015 and 2014, respectively. Total fuel and purchased power costs in 2015, 2014, and 2013 were $86,134,871 , $141,646,746 , and $164,446,942 , respectively. n. Environmental Remediation Costs Chugach accrues for losses and establishes a liability associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. Estimates of future costs for environmental remediation obligations are not discounted to their present value. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset. o. Income Taxes Chugach is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code and for the years ended December 31, 2015, 2014 and 2013 was in compliance with that provision. In addition, as described in Note (15) – “Commitments and Contingencies,” Chugach collects sales tax and is assessed gross revenue and excise taxes which are presented on a net basis in accordance with FASB ASC 605-45-50, “Topic 605 - Revenue Recognition – Subtopic 45 - Principal Agent Considerations – Section 50 - Disclosure.” Chugach applies a more-likely-than-not recognition threshold for all tax uncertainties. FASB ASC 740, “Topic 740 – Income Taxes,” only allows the recognition of those tax benefits that have a greater than 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, 2013 through December 31, 2015 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2015. p. Consumer Deposits Consumer deposits are the amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 2015 and 2014, totaled $3.1 million and $2.9 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances for the years ended December 31, 2015 and 2014 totaled $1.9 million and $2.0 million, respectively. q. Grants Chugach has received federal and state grants to offset storm related expenditures and to support the construction of facilities to transport fuel, divert water and safely transmit electricity to its consumers. Grant proceeds used to construct or acquire equipment are offset against the carrying amount of the related assets while grant proceeds for storm related expenditures are offset against the actual expense incurred, which totaled $1.6 million and $4.8 million in 2015 and 2014, respectively. r. Fuel Stock Fuel Stock is the weighted average cost of fuel injected into Cook Inlet Natural Gas Storage Alaska (CINGSA), which began service in the second quarter of 2012. Chugach’s fuel balance in storage for the years ended December 31, 2015 and 2014 amounted to $7.1 million and $9.7 million, respectively. s. Corrections For the year ended December 31, 2 015, Chugach recorded the following correction for the year ended December 31, 2014: A correction representing the long-term versus current presentation of long-term obligations associated with bonds payable, previously reported as current installments of long-term obligations and now reported as long-term obligations, excluding current installments. The impact of this correction was an increase to long-term obligations, excluding current installments, and a decrease to current installments of long-term obligations of $1.0 million as of December 31, 2014 . For the year ended December 31, 2015, Chugach recorded the following correction for the years ended December 31, 2014 and 2013 : A correction representing the cash received from customers for the undergrounding ordinance, included in net receipts on consumer advances for construction, previously reported as other current liabilities. The impact of this correction was a decrease in cash provided by operating activities and cash used in financing activities of $3.2 million and $2.9 million for the years ended December 31, 2014 and 2013, respectively.

Accounting Pronouncements

Accounting Pronouncements	12 Months Ended
	Dec. 31, 2015
Accounting Pronouncements [Abstract]
Accounting Pronouncements	(3) Accounting Pronouncements Issued, not yet adopted: ASC Update 2014-09 “Revenue from Contracts with Customers (Topic 606)” In May of 2014, the FASB issued ASC Update 2014-09, “Revenue from Contracts with Customers (Topic 606).” ASC Update 2014-09 provides guidance for the recognition, measurement and disclosure of revenue related to the transfer of promised goods or services to customers. This update wa s effective for fiscal years beginning after December 15, 2016, for which early adoption wa s prohibited. However, in August of 2015, the FASB issued ASC Update 2014-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date,” deferring the effective date of ASC Update 2014-09 to fiscal years beginning after December 15, 2017, and permitting early adoption of this update, but only for annual reporting periods beginning after December 15, 2016, and interim reporting periods within that reporting period. The standard permits the use of either the retrospective or cumulative effect transition method. Chugach has not yet selected a transition method and is evaluating the effect on its results of operations, financial position, and cash flows . ASC Update 2015-03 “ Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ” In April of 2015, the FASB issued ASC Update 2015-03, “Interest – Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs.” ASC Update 2015 -03 revises the presentation guidance for debt issuance costs related to a recognized debt liability. The effect of this update is to present the debt issuance costs as a direct deduction to the liability on the balance sheet and retrospective application is required. This update does not change the recognition and measurement guidance for debt issuance costs. This update is effective for fiscal years beginning after December 15, 2015, and interim periods beginning after December 15, 2016, with early adoption permitted. Chugach will begin application of ASC 2015-03 with the annual report for the year ended December 3 1, 2016. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows. ASC Update 2015-15 “ Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements ” In September of 2015, the FASB issued ASC Update 2015-15, “Interest – Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” ASC Update 2015-15 amends guidance related to the presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements for SEC reporting. This update is effective for fiscal years beginning after December 15, 2015, and interim periods beginning after December 15, 2016, with early adoption permitted. Chugach will beg i n application of ASC 2015-15 with the annual report for the year ended December 31 , 2016. Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows. ASC Update 201 6 - 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 201 6 - 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, 201 8 , and interim periods beginning after December 15, 201 9, with early adoption not permitted with certain exceptions . Chugach will begin application of ASC 201 6 - 01 with the annual report for the year ended December 31, 201 8 . Adoption is not expected to have a material effect on its results of operations, financial position, and cash flows. ASC Update 201 6 - 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 201 6 , the FASB issued ASC Update 201 6 - 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, 201 8 , including the interim periods within those years , with early adoption permitted. Chugach will begin application of ASC 201 6 - 02 on January 1, 2019 . Chugach is evaluating the effect on its results of operations, financial position, and cash flo ws .

Fair Value Of Assets And Liabil

Fair Value Of Assets And Liabilities	12 Months Ended
	Dec. 31, 2015
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. Chu gach had no Level 2 or 3 assets or liabilities measured at fair value on a recurring basis. Fair value estimates are de pendent upon subjective assumptions and involve significant uncertainties resulting in variability in estimates with changes in assumptions.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2015
Regulatory Matters [Abstract]
Regulatory Matters	(5) Regulatory Matters MEA Interim Power Sales Agreement On August 12, 2014, MEA notified Chugach that their newly constructed power plant, the Eklutna Generation Station (EGS), would not be completed by January 1, 2015. On September 30, 2014, Chugach entered into an Interim Power Sales Agreement (Agreement) to provide MEA with all demand and energy requirements on a firm basis based on existing tariff rates for a minimum one quarter period beginning on January 1, 2015 , and ending on March 31, 2015 . Under the terms of the agreement, Chugach agreed to purchase from MEA the output of up to four units from their plant upon commercial operation through the term of the agreement. Chugach proposed to purchase the pooled energy and recover the costs from its members, including MEA, through Chugach’s fuel and purchased power adjustment process. MEA supplied and deliver ed all additional gas and attendant transportation necessary for Chugach to produce electric service to MEA arising as a result of the electric services to be provided by Chugach pursuant to the Agreement. On December 22, 2014, the RCA approved both the Agreement and Chugach’s proposal to recover costs incurred under the Agreement through its fuel and purchased power rate adjustment process. As part of the approval, the RCA required Chugach to provide monthly information on MEA gas deliveries to Chugach, system heat rates with and without EGS, and the number of EGS units made commercially available during each month of the contract. On January 30, 2015, MEA notified Chugach that it had four units available to pool with Chugach units to meet the combined system load of Chugach and MEA. These units were subsequently pooled with Chugach units. The term of the Agreement was subsequently extended to and expired on April 30, 2015 . 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 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. As a result, Chugach is receiving $40,000 per month from MEA for these services. The Dispatch Services Agreement remains 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. Chugach and MEA have discussed modification of the Dispatch Agreement . At this time, a final agreement has not been reached. June 2014 Test Year General Rate Case Chugach’s June 2014 test year rate case was submitted to the RCA on February 13, 2015. Chugach requested a system base rate increase of approximately $21.3 million, or 20% on total base rate revenues for rates effective in April 2015. The filing also included updates to firm and non-firm transmission wheeling rates and attendant ancillary services in support of third-party transactions on the Chugach transmission system. The primary driver of the rate changes wa s the reduction in fixed-cost contributions resulting from the March 31, 2015 expiration of the Interim Power Sales Agreement between Chugach and MEA. Chugach submitted proposed adjustments to its fuel and purchased power rates under a separate tariff advice letter to become effective at the same time which allows interim base rate increases to be synchronized with reductions in fuel costs resulting from system heat rate improvements and a greater share of hydroelectric generation used to meet the load requirements of the remaining customers on the system. In combination with Chugach’s fuel and purchased power rate adjustment filing for rates effective in April 2015, the effective increase to retail customer bills was approximately between two and five percent. The RCA issued Order U-15-081(1) on April 30, 2015, suspending the filing and granting Chugach’s request for interim and refundable rate increases effective May 1, 2015. A scheduling conference was held on May 27, 2015. On June 4, 2015, the RCA issued Order U-15-081(2), granting approval for intervention by HEA, MEA and GVEA. The RCA indicated that a final order in the case will be issued by May 8, 2016. Intervenor responsive testimony was filed by the Attorney General (AG) and MEA on October 28, 2015. The AG’s testimony focused on revenue requirement matters and MEA’s testimony focused on transmission cost allocation issues. Chugach’s responsive testimony was filed on December 15, 2015. In January of 2016, Chugach and the A ttorney G eneral (AG) for the State of Alaska entered into settlement discussions to resolve revenue requirement matters in the case, which resulted in settlement of all outstanding matters related to the determination of Chugach’s system revenue requirement for both the interim and permanent rate periods. As a result, Chugach agreed to reduce its revenue requirement by 0.5% (approximately $0.6 million). In addition, the stipulation provides for a permanent increase in Chugach’s system Times Interest Earned Ratio (TIER) from 1.30 to 1.35 , which represents an approximate margin increase of $1.0 million per year. The stipulation was filed with the RCA on January 21, 2016. The RCA has not issued a ruling on the settlement. If the settlement is accepted, Chugach will reduce its revenue requirement by $0.6 million and expects to issue refunds on demand and energy rates for bill s issued during the interim rate period. The adjudicatory hearing was held from January 25 through January 28, 2016, to address transmission-related matters identified by MEA. Because of the settlement, no revenue requirement matters were addressed during the hearing. A final order in the case is expected by May 8, 2016. Chugach expects to resume its participation in the SRF process at the conclusion of this case. SRF is an expedited process available to electric cooperatives in Alaska for routine updates to demand and energy rates. Fire Island Wind Project On October 10, 2011, the RCA issued an order approving Chugach’s request for assurance of cost recovery associated with a new power purchase agreement (PPA) between Chugach and Fire Island Wind, LLC (FIW), a special purpose entity wholly-owned by Cook Inlet Region, Inc. Associated with the approval of the PPA, Chugach submitted project status reports on March 31, 2012, June 29, 2012, October 31, 2012, and January 16, 2013. On January 30, 2014, Chugach submitted a status report regarding FIW integration and a cost reimbursement agreement related to possible impacts to an interconnected utility as a result of the project. On July 25, 2014, the RCA issued Order No. 4 approving Chugach’s request to file its next status update by September 30, 2014. Chugach filed a status report with the RCA on September 26, 2014. In the filing, Chugach informed the RCA that it had received notification from ML&P that they believe no further proceedings on this matter are necessary. ML&P indicated that fluctuations from the wind project are impacting system frequency but the attendant costs associated with quantifying the impacts likely exceed the attendant benefit. ML&P reserved the right to open this issue at a later time. In the filing, Chugach indicated that it will continue to evaluate the potential impact of the Fire Island Wind Project on the grid and requested that the RCA accept the status report on the integration and cost reimbursement issues and close the docket. The RCA issued an order in February of 2015 requiring ML&P to file a separate report addressing the nature and estimate of any adverse cost impacts attributable to FIW integration, as well as the estimated costs and equipment needed for measurement. ML&P submitted its compliance filing in April of 2015 addressing the type and range of costs ML&P might experience if it sought to isolate and identify the integration impacts of the FIW Project. In a subsequent order, the RCA acknowledged ML&P’s compliance filing and closed the docket. AIX Energy LLC: March 1, 2015, through February 29, 2016 On December 22, 2014, Chugach executed an agreement (AIX Agreement) with AIX Energy LLC (AIX) which allows for natural gas purchases by Chugach from AIX beginning March 1, 2015 , through February 29, 2016 . The AIX Agreement provides flexibility in both the purchase price and volumes, with specific prices and volumes to be determined by each transaction. However, the price of gas cannot exceed $6.24 per thousand cubic feet (Mcf) and the total volume of gas is capped at 300,000 Mcf, or a maximum total outlay of approximately $1.9 million. As the AIX Agreement is for a term less than one year, approval of the agreement by the RCA is not required; however, Chugach submitted a filing to the RCA seeking approval to recover purchases made under the agreement as a new cost element in its fuel and purchased power adjustment process. This agreement was subsequently approved by the RCA. AIX Energy LLC: 2016 through March 31, 2029 Chugach entered into a long-term gas contract with AIX, entitled, “Gas Sale and Purchase Agreement between AIX Energy LLC and Chugach” (AIX GSPA), that extends through March 31, 2024 , with an option to extend the term an additional 5 -year period through March 31, 2029 . Under the AIX GSPA , Chugach is permitted to purchase gas as either firm or interruptible, with the specific purchase price and quantity negotiated at the time of each transaction, subject to a maximum price and quantity in each contract year. There is no minimum purchase requirement contained in the AIX GSPA and the purchase price is determined through mutual agreement of Chugach and AIX, subject to a maximum price in each contract year. The AIX GSPA provides Chugach with additional diversity in its gas supply portfolio with the opportunity to purchase gas at prices below existing supplier prices. Th e AIX GSPA was filed with the RCA on November 25, 2015, and approved in a letter order issued on January 11, 2016. Second and Third Amendments to the Gas Sale and Purchase Agreement with Hilcorp Chugac h submitted the Second Amendment (Second Amendment) to the GSPA between Hilcorp Alaska, LLC and Chugach to the RCA on March 19, 2015. The Second Amendment was administrative in nature and established a more efficient payment procedure and updated notice provisions required under the GSPA. The Second Amendment was approved by the RCA on April 20, 2015. On July 23, 2015, Chugach filed the Third Amendment (Third Amendment) to the GSPA between Hilcorp Alaska, LLC and Chugach with the RCA. The Third Amendment extends the term of the existing GSPA for firm gas sales from March 31, 2019 to March 31, 2023 , and adjusts the volumes and gas price for purchases in 2019. The Third Amendment does not change the underlying terms and conditions of the GSPA as amended, or the pricing and gas quantities in 2015 through March 31, 2018. The Third Amendment reduces the gas price by 8.5 percent on April 1, 2018. A key provision of the Third Amendment is the option for additional gas volumes during the period of April 1, 2019, through March 31, 2023, on both an annual contract quantity and average daily contract quantity basis. These options provide Chugach with added flexibility in the overall management of its gas supply requirements. The annual volumetric basis option provides Chugach with the ability to augment its firm gas supply requirements from other independent suppliers. Chugach is permitted to increase the annual contract volumes of up to 1.1 billion cubic feet (Bcf) of gas beginning April 1, 2019, and up to 2.6 Bcf annually on April 1 thereafter, provided advanced notice is given to Hilcorp. This option allows Chugach to continue to obtain firm gas supplies from Hilcorp or alternatively from other gas suppliers if market conditions allow. The Third Amendment also provides Chugach with shorter-term options to purchase up to 2.0 million cubic feet (MMcf) per day of additional firm gas without impacting established annual contract quantities. This option allows Chugach to purchase additional volumes in response to short-term sales increases due to weather, bulk power maintenance activities, or other events on the Chugach system. The Third Amendment was approved by the RCA on September 8, 2015. 2013 General Rate Case To reflect revenue and cost changes resulting from the expiration of HEA’s wholesale contract, Chugach submitted its 2013 Test Year General Rate Case to the RCA on November 19, 2013, to increase system base rate revenues by $16.0 million, or approximately 12.5% on total retail, MEA, and Seward base rate revenues of $127.4 million. On January 2, 2014, the RCA approved the submitted rates on an interim and refundable basis. Retail rates were effective January 2, 2014, and wholesale rate changes were effective February 1, 2014, for purchases beginning January 1, 2014. The increase, net of both base rate increases and fuel savings, to Chugach retail end-users wa s approximately six percent. On April 18, 2014, Chugach submitted an update to its 2013 general rate case to reflect the final results contained in Chugach’s compliance filing in the 2012 general rate case that was submitted to the RCA on April 14, 2014. The update reflect ed final rate design changes contained in the 2012 rate case. On May 30, 2014, the RCA issued Order No. 3 approving Chugach’s motion and update to retail and wholesale base rates effective with the first billing cycle in June 2014. There was no impact to the system revenue requirement contained in the 2013 Test Year General Rate Case filing. Chugach and the parties to the docket entered into a stipulation resolving revenue requirement and cost of service matters contained in the case. The stipulation was filed with the RCA on October 16, 2014, and require d Chugach to issue refunds totaling $1.1 million (annualized) for service provided beginning January 2014, with an expected financial impact to Chugach of approximately $0.2 million on an annual basis. The stipulation contained a provision that Chugach be permitted to create a regulatory asset for approximately $0.9 million of storm-related costs and be permitted to recover $0.2 million per year over the next five years. On November 13, 2014, the RCA accepted the stipulation. On February 12, 2015, the RCA issued Order No. 9 of U-14-001 accepting the stipulation on revenue requirement matters and resolving the remaining issues in the docket. The RCA required Chugach to submit updated tariffs reflecting the results of the RCA order and the stipulations entered into the case, including a detailed refund plan, which Chugach submitted on March 13, 2015. The RCA issued Order U-14-001(11) on April 30, 2015, approving final rates for the January 1, 2014, through April 30, 2015, period, and approving Chugach’s refund plan resulting from settlements in the case. Chugach issued refunds to Seward, MEA and transmission wheeling customers in May of 2015, and to retail customers be tween June and July of 2015. On August 6, 2015, in compliance with Order U-14-001(11), Chugach notified the RCA that it had completed the disbursement of refunds to retail and wholesale customers. On August 25, 2015, the RCA issued Order U-14-001(12) closing the docket. Operation and Regulation of the Alaska Railbelt 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. The RCA held public meetings and workshops throughout the second quarter of 2015. 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 also wants to be granted authority for siting new generation and transmission and to regulate integrated resource planning of the Railbelt electrical system. Quarterly progress reports on this effort were required for the remainder of 2015. The development of common Railbelt operating and reliability standards and system-wide merit order economic dispatch of the Railbelt’s electrical generation units to bring the maximum benefit to ratepayers was also recommended. 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. Initial progress reports to develop an independent Railbelt electric transmission company were filed with the RCA on September 30, 2015. A second report on grid unification was filed with the RCA in December 2015. Progress reports associated with system-wide economic dispatch were filed with the RCA in January and early February 2016. 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. Chugach intends to finalize this review and evaluation in the first or second quarter of 2016. 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. Cook Inlet Natural Gas Alaska: Found Gas On January 30, 2015, CINGSA submitted a filing to the RCA providing notice that it had found 14.5 Bcf of gas as a result of directional drilling in the storage facility and now proposes to establish guidelines for commercial sales of at least 2 Bcf of this gas. Chugach submitted comments to the RCA regarding CINGSA’s proposed treatment of found gas. Chugach does not believe CINGSA’s proposal to retain revenues for the sale of found gas should be permitted in recognition of the risk-sharing agreements made by CINGSA and its storage customers that resulted in the development of the CINGSA storage facility. The RCA issued an order in March of 2015 suspending the filing for further investigation. CINGSA filed direct testimony in the case on April 13, 2015. Chugach and other intervenors 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 intervenors 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, errored, 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. ENSTAR Natural Gas ENSTAR Natural Gas Company (ENSTAR) submitted a general rate case to the RCA proposing a 20% system rate increase, and an approximate 100% increase to Chugach for gas transportation services. Chugach submitted responsive testimony in May 2015. ENSTAR submitted reply testimony on June 26, 2015. Chugach and other parties to the docket entered into mediation in mid-July and reached an agreement to settle in principal the outstanding issues in the case. As a result of the stipulation, the original proposed annual increase of $2.6 million to Chugach was settled at less than $0.5 million . The parties also agreed to several tariff changes that remove demand charge penalties for economy transactions. The hearing originally scheduled to begin in late August was vacated. The RCA accepted the stipulation. ENSTAR is required to file another general rate case in the second quarter of 2016. Beluga River Unit In July of 2015, ConocoPhillips Alaska, Inc. (COP) announced the marketing for sale of its North Cook Inlet Unit; its interest in the Beluga River Unit (BRU); and its interest in 5,700 acres of exploration prospects in the Cook Inlet region. In October of 2015, Chugach submitted a joint bid with the Municipality of Anchorage d/b/a Municipal Light & Power (ML&P) for acquisition of COP’s one -third working interest in the BRU. As discussed in “ Note 17 – Subsequent Events – Beluga River Unit ,” Chugach entered into an agreement entitled, “Purchase and Sale Agreement between ConocoPhillips Alaska, Inc. and Municipality of Anchorage d/b/a Municipal Light & Power and Chugach Electric Association, Inc.” (Purchase and Sale Agreement) on February 4, 2016 . The Purchase and Sale Agreement transfers COP’s interest in the BRU to Chugach and ML&P. The acquisition and attendant recovery of costs in electric rates is subject to the approval of the RCA. Chugach and ML&P expect to submit a joint petition to the RCA for approval of the Purchase and Sale Agreement in March of 2016. Chugach expects a two to six month process for RCA review of the Purchase and Sale Agreement. A separate filing detailing the specific rate recovery process is expected to be filed in the second quarter of 2016. Under the recovery structure that will be proposed by Chugach, costs associated with the BRU, including acquisition and on-going operations, maintenance and capital investment, will be recovered on a dollar-for-dollar basis through Chugach’s quarterly fuel adjustment process. Chugach recovers its fuel and purchased power costs as a direct pass-through from its retail and wholesale customers with minimal lag between cost incurrence and recovery.

Utility Plant

Utility Plant	12 Months Ended
	Dec. 31, 2015
Utility Plant [Abstract]
Utility Plant	(6) Utility Plant Major classes of utility plant as of December 31 are as follows: Electric plant in service: 2015 2014 Steam production plant $ 100,938,247 $ 161,454,274 Hydroelectric production plant 20,591,678 20,594,429 Other production plant 284,035,865 278,389,073 Transmission plant 277,490,606 261,173,934 Distribution plant 290,680,919 281,706,456 General plant 51,841,582 53,452,136 Unclassified electric plant in service 1 95,611,615 91,446,881 Intangible plant 1 5,455,371 5,455,371 Other 1 1,828,409 1,828,409 Total electric plant in service 1,128,474,292 1,155,500,963 Construction work in progress 15,601,374 21,567,341 Total electric plant in service and construction work in progress $ 1,144,075,666 $ 1,177,068,304 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.

Investments In Associated Organ

Investments In Associated Organizations	12 Months Ended
	Dec. 31, 2015
Investments In Associated Organizations [Abstract]
Investments In Associated Organizations	(7) Investments in Associated Organizations Investments in associated organizations include the following at December 31: 2015 2014 NRUCFC $ 6,095,980 $ 6,095,980 CoBank 3,475,664 3,763,697 NRUCFC Capital Term Certificates and other 63,875 63,875 Total investments in associated organizations $ 9,635,519 $ 9,923,552 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.

Deferred Charges And Credits

Deferred Charges And Credits	12 Months Ended
	Dec. 31, 2015
Deferred Charges And Credits [Abstract]
Deferred Charges And Credits	(8) Deferred Charges and Credits Deferred Charges Deferred charges, or regulatory assets, net of amortization, consisted of the following at December 31: 2015 2014 Debt issuance and reacquisition costs $ 2,928,378 $ 3,263,937 Refurbishment of transmission equipment 114,198 123,457 Feasibility studies 551,122 578,806 Beluga gas compression 508,866 1,017,733 Cooper Lake relicensing / projects 5,410,109 5,540,212 Fuel supply 939,768 898,849 Storm damage 841,595 971,071 Other regulatory deferred charges 1,257,809 1,464,784 Bond interest - market risk management 5,871,286 6,402,875 Environmental matters 1,069,522 1,114,872 Total deferred charges $ 19,492,653 $ 21,376,596 Deferred charges, or regulatory assets, not currently being recovered in rates charged to consumers, consisted of the following at December 31: 2015 2014 Studies and other $ 686,348 $ 387,253 Storm damage 0 971,071 Wind project 0 34,543 Total deferred charges $ 686,348 $ 1,392,867 The amount related to storm damage was approved by the RCA on February 21, 2015, see Note (5) – Regulatory Matters – 2013 General Rate Case.” We believe all regulatory assets not currently being recovered in rates charged to consumers are probable of recovery in the future based upon prior recovery of similar costs allowed by our regulator. The recovery of regulatory assets is approved by the RCA either in standard SRFs, general rate case filings or specified independent requests. In most cases, deferred charges are recovered over the life of the underlying asset. Deferred Credits Deferred credits, or regulatory liabilities, at December 31 consisted of the following: 2015 2014 Refundable consumer advances for construction $ 823,115 $ 787,824 Estimated initial installation costs for meters 105,274 98,964 Post retirement benefit obligation 874,000 874,000 Other 0 97,667 Total deferred costs $ 1,802,389 $ 1,858,455

Patronage Capital

Patronage Capital	12 Months Ended
	Dec. 31, 2015
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, 2015, Chugach had $167,447,781 of patronage capital (net of capital credits retired in 2015), which included $160,944,929 of patronage capital that had been assigned and $6,502,852 of patronage capital to be assigned to its members. At December 31, 2014, Chugach had $164,135,053 of patronage capital (net of capital credits retired in 2014), which included $157,619,508 of patronage capital that had been assigned and $6,515,545 of patronage capital to be assigned to its members. Approval of actual capital credit retirements is at the discretion of the Chugach Board. Chugach records a liability when the retirements are approved by the Board. In December of 2013, the Board resumed its capital credit retirement program. Chugach entered into an agreement with HEA to return all of its patronage capital within five years after expiration of its power sales agreement, which was December 31, 2013 . This patronage capital retirement was related to a settlement agreement associated with the 2005 Test Year General Rate Case (Docket U-06-134). The RCA accepted the parties’ settlement agreement on August 9, 2007. HEA’s patronage capital payable was $7.9 million at December 31, 2015 and 2014, respectively. In an agreement reached in May of 2014 with MEA, capital credits retired to MEA are classified as patronage capital payable on Chugach’s Balance Sheet . MEA’s patronage capital payable was $3.2 million and $2.3 million at December 31, 2015 and 2014, respectively. T he Second Amended and Restated Indenture of Trust (the Indenture) and the CoBank Amended and Restated Master Loan Agreement prohibit Chugach from making any distribution of patronage capital to Chugach’s customers if an event of default under the Indenture or debt agreements exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins. Capital credits retired, net of HEA’s allocations, were $3,190,124 , $5,130,381 , and $1,626,828 for the years ended December 31, 2015, 2014, and 2013, 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, 2015, 2014, and 2013 was $2,105,440 , $1,042,064 and $1,470,263 , respectively.

Other Equities

Other Equities	12 Months Ended
	Dec. 31, 2015
Other Equities [Abstract]
Other Equities	(10) Other Equities A summary of other equities at December 31 follows: 2015 2014 Nonoperating margins, prior to 1967 $ 23,625 $ 23,625 Donated capital 1,877,193 1,806,424 Unclaimed capital credit retirement 1 10,627,038 9,328,628 Total other equities $ 12,527,856 $ 11,158,677 1 Represents unclaimed capital credits that have met all requirements of Alaska Statute section 34.45.200 regarding Alaska’s unclaimed property law and has therefore reverted to Chugach.

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt [Abstract]
Debt	(11) Debt Long-term obligations at December 31 are as follows: 2015 2014 2011 CoBank bond, 2.77% variable rate bond maturing in 2022 , with interest payable monthly and principal due annually beginning in 2003 $ 24,941,165 $ 27,414,275 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 72,000,000 76,500,000 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 160,333,332 166,499,999 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 63,750,000 67,500,000 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 102,000,000 109,000,000 2012 Series A Bond of 4.78% , maturing in 2042 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023 50,000,000 50,000,000 Total long-term obligations $ 473,024,497 $ 496,914,274 Less current installments 24,115,980 23,889,777 Long-term obligations, excluding current installments $ 448,908,517 $ 473,024,497 C ovenants Chugach is required to comply with all covenants set forth in the Indenture that secures the 2011 Series A Bonds, the 2012 Series A Bonds and the 2011 CoBank bond. The CoBank bond is governed by the Amended and Restated Master Loan Agreement, which is now secured by the Indenture dated January 20, 2011. Chugach is also required to comply with the 2010 Credit Agreement, between Chugach and NRUCFC, KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank, ACB and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch as amended June 29, 2012, governing loans and extensions of credit associated with Chugach’s Commercial Paper Program, in an aggregate principal amount not exceeding $100.0 million at any one time outstanding. Chugach is also required to comply with other covenants set forth in the Revolving Line of Credit Agreement with NRUCFC. Security The Indenture, which became effective on January 20, 2011, imposes a lien on substantially all of Chugach’s assets to secure Chugach’s long-term debt obligations. Assets that are generally not subject to the lien of the Indenture include cash (other than cash deposited with the indenture trustee); instruments and securities; patents, trademarks, licenses and other intellectual property; vehicles and other movable equipment; inventory and consumable materials and supplies; office furniture, equipment and supplies; computer equipment and software; office leases; other leasehold interests for an original term of less than five years; contracts (other than power sales agreements with members having an original term exceeding three years, certain contracts specifically identified in the indenture, and other contracts relating to the ownership, operation or maintenance of generation, transmission or distribution facilities); non-assignable permits, licenses and other contract rights; timber and minerals separated from land; electricity, gas, steam, water and other products generated, produced or purchased; other property in which a security interest cannot legally be perfected by the filing of a Uniform Commercial Code financing statement, and certain parcels of real property specifically excepted from the lien of the Indenture. The lien of the Indenture may be subject to various permitted encumbrances that include matters existing on the date of the Indenture or the date on which property is later acquired; reservations in United States patents; non-delinquent or contested taxes, assessments and contractors’ liens; and various leases, rights-of-way, easements, covenants, conditions, restrictions, reservations, licenses and permits that do not materially impair Chugach’s use of the mortgaged property in the conduct of Chugach’s business. Rates The Indenture also requires Chugach, subject to any necessary regulatory approval, to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times total interest expense. If there occurs any material change in the circumstances contemplated at the time rates were most recently reviewed, the Indenture requires Chugach to seek appropriate adjustment to those rates so that they would generate revenues reasonably expected to yield margins for interest equal to at least 1.10 times interest charges, provided, however, upon review of rates based on a material change in circumstances, rates are required to be revised in order to comply and there are less than six calendar months remaining in the current fiscal year, Chugach can revise its rates so as to reasonably expect to meet the covenant for the next succeeding 12-month period after the date of any such revision. The CoBank Master Loan Agreement also required Chugach to establish and collect rates reasonably expected to yield margins for interest equal to at least 1.10 times interest expense. The Amended and Restated Master Loan Agreement with CoBank, which became effective on January 19, 2011 , did not change this requirement. The 2010 Credit Agreement governing the unsecured facility providing liquidity for Chugach’s Commercial Paper Program requires Chugach to maintain minimum margins for interest of at least 1.10 times interest charges for each fiscal year. Margins for interest generally consist of Chugach’s assignable margins plus total interest expense. Distributions to Members Under the Indenture and debt agreements, Chugach is prohibited from making any distribution of patronage capital to Chugach’s customers if an event of default under the Indenture or debt agreements exists. Otherwise, Chugach may make distributions to Chugach’s members in each year equal to the lesser of 5% of Chugach’s patronage capital or 50% of assignable margins for the prior fiscal year. This restriction does not apply if, after the distribution, Chugach’s aggregate equities and margins as of the end of the immediately preceding fiscal quarter are equal to at least 30% of Chugach’s total liabilities and equities and margins. Maturities of Long ‑term Obligations Long-term obligations at December 31, 2015, mature as follows: Year ending December 31 2011 Series A Bonds CoBank Bond 2012 Series A Bonds Total 2016 10,666,667 2,699,313 10,750,000 24,115,980 2017 10,666,667 2,945,954 10,750,000 24,362,621 2018 10,666,667 3,215,267 10,750,000 24,631,934 2019 10,666,667 3,509,142 10,750,000 24,925,809 2020 10,666,667 3,829,809 10,750,000 25,246,476 Thereafter 178,999,997 8,741,680 162,000,000 349,741,677 $ 232,333,332 $ 24,941,165 $ 215,750,000 $ 473,024,497 Lines of credit Chugach maintains a $50.0 million line of credit with NRUCFC. Chugach did not utilize this line of credit in 2015 or 2014, and therefore had no outstanding balance at December 31, 2015 and 2014. The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC. The borrowing rate was 2.90% at December 31, 2015 and 2014. The NRUCFC Revolving Line Of Credit Agreement requires that Chugach, for each 12 -month period, for a period of at least five consecutive days, pay down the entire outstanding principal balance. The NRUCFC line of credit expires October 12, 2017 , and is immediately available for unconditional borrowing. Commercial Paper On November 17, 2010 , Chugach entered into a $300.0 million Unsecured Credit Agreement, which is used to back Chugach’s Commercial Paper Program. The participating banks were NRUCFC, Bank of America, N.A., KeyBank National Association, JPMorgan Chase Bank, N.A., Bank of Montreal, CoBank, ACB, Goldman Sachs Bank USA, Bank of Taiwan, Los Angeles Branch and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch. Effective May 4, 2012 , Chugach reduced the commitment amount to $100.0 million and on June 29, 2012 , amended and extended the Credit Agreement to update the pricing and extend the term. The new pricing includes an all-in drawn spread of one month London Interbank Offered Rate (LIBOR) plus 107.5 basis points, along with a 17.5 basis points facility fee (based on an A- unsecured debt rating). The Amended Unsecured Credit Agreement now expires on November 17, 2016 . The participating banks include NRUCFC, KeyBank National Association, Bank of America, N.A., Bank of Montreal, CoBank and Chang Hwa Commercial Bank, Ltd., Los Angeles Branch. Our commercial paper can be repriced between one day and 270 days. Chugach is expected to continue to issue commercial paper in 2016, as needed, however, the requirement for short-term borrowing has decreased. Chugach had $20.0 million and $21.0 million of commercial paper outstanding at December 31, 2015 and 2014, respectively. The following table provides information regarding 2015 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 2015 $ 17.8 0.26 July 2015 $ 10.1 0.26 February 2015 $ 11.6 0.22 August 2015 $ 12.0 0.25 March 2015 $ 16.0 0.29 September 2015 $ 19.5 0.25 April 2015 $ 23.8 0.28 October 2015 $ 24.0 0.25 May 2015 $ 16.0 0.27 November 2015 $ 22.4 0.25 June 2015 $ 12.1 0.31 December 2015 $ 21.4 0.49 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 be ginning 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. The following table provides additional information regarding the 2011 Series A and 2012 Series A bonds at December 31, 2015: Maturing March 15, Average Life (Years) Interest Rate Issue Amount Carrying Value 2011 Series A, Tranche A 2031 10.0 4.20 % $ 90,000 $ 72,000 2011 Series A, Tranche B 2041 15.5 4.75 % 185,000 160,333 2012 Series A, Tranche A 2032 10.7 4.01 % 75,000 63,750 2012 Series A, Tranche B 2042 15.7 4.41 % 125,000 102,000 2012 Series A, Tranche C 2042 20.7 4.78 % 50,000 50,000 Total $ 525,000 $ 448,083 Chugach has a term loan facility with CoBank. Loans made under this facility are evidenced by the 2011 CoBank Note, which is governed by the Amended and Restated Master Loan Agreement dated January 19, 2011 , and secured by the Indenture. Fair Value of Debt Instruments The fair value of long-term debt has been determined using discounted future cash flows at borrowing rates currently available to Chugach. Level 1 measurement was used to determine the fair value of the 2011 and 2012 Series A Bonds. Level 2 measurements were used to determine all other long-term obligations. The estimated fair value (in thousands) of the long-term obligations included in the financial statements at December 31 is as follows: Carrying Value Fair Value Long-term obligations (including current installments) $ 473,024 $ 480,135

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2015
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, 2015, 2014 and 2013 of $6.7 million , $6.8 million and $6.8 million, respectively. The rate and number of employees in all significant pension plans did not materially change f or the years ended December 31, 2015, 2014 and 2013. The following table provides information regarding pension plans which Chugach considers individually significant: Alaska Electrical Pension Plan 3 NRECA Retirement Security Plan 3 Employer Identification Number 92-6005171 53-0116145 Plan Number 001 333 Year-end Date December 31 December 31 Expiration Date of CBA's June 30, 2017 N/A 2 Subject to Funding Improvement Plan No No 4 Surcharge Paid N/A N/A 4 2015 2014 2013 2015 2014 2013 Zone Status Green Green Green N/A 1 N/A 1 N/A 1 Required minimum contributions None None None N/A N/A N/A Contributions (in millions) $3.1 $3.3 $3.4 $3.5 $3.5 $3.4 Contributions > 5% of total plan contributions Yes Yes Yes No No No 1 A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006. 2 The CEO is the only participant in the NRECA RS Plan who is subject to an employment agreement, which is effective through July 17, 2016. 3 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 . 4 The provisions of the PPA do not apply to the RS Plan, therefore, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the RS Plan and may change as a result of plan experience. Health and Welfare Plans Health and welfare benefits for union employees are provided through the Alaska Electrical Health and Welfare Trust and the Alaska Hotel, Restaurant and Camp Employees Health and Welfare and Pension Trust Fund. Chugach participates in multi-employer plans that provide substantially all union workers with health care and other welfare benefits during their employment with Chugach. Chugach pays a defined amount per union employee pursuant to collective bargaining unit agreements. Amounts charged to benefit costs and contributed to the health and welfare plans for these benefits for the years ending December 31, 2015, 2014, and 2013 were $4.5 million , $4.5 million, and $4.1 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, 2015, 2014, and 2013 totaled $2.6 million , $2.9 million, and $2.9 million respectively. Money Purchase Pension Plan Chugach participates in a multi-employer defined contribution money purchase pension plan covering some employees who are covered by a collective bargaining agreement. Contributions to the Plan are made based on a percentage of each employee’s compensation. Contributions to the money purchase pension plan for the years ending December 31, 2015, 2014 and 2013 were $133.6 thousand, $149.2 thousand and $147.9 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, $17,500 and $17,500 in 2015, 2014 and 2013 respectively, and allowed catch-up contributions for those over 50 years of age of $6,000 in 2015 and $5,500 in 2014 and 2013. 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, 2015, 2014 and 2013 was $763,913 , $666,967 and $536,546 , 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.

Bradley Lake Hydroelectric Proj

Bradley Lake Hydroelectric Project	12 Months Ended
	Dec. 31, 2015
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 $21.6 million . Upon the default of a Bradley Lake participant, and subject to certain other conditions, AEA is entitled to increase each participant’s share of costs pro rata, to the extent necessary to compensate for the failure of another participant to pay its share, provided that no participant’s percentage share is increased by more than 25% . Upon default, Chugach could be faced with annual expenditures of approximatel y $5.7 million as a result of Chugach’s Bradley Lake take-or-pay obligations. Management believes that such expenditures, if any, would be recoverable through the fuel recovery process. The State of Alaska provided an initial grant for work on a project to divert water from Battle Creek into Bradley Lake. The project is being managed by the Alaska Energy Authority. Based on stream flow measurements from 1991 through 1993, diverting a portion of Battle Creek into Bradley Lake has the potential to increase annual energy output up to 40,000 megawatt-hours (MWh). Chugach would be entitled to 30.4% of the additional energy produced. The following represents information with respect to Bradley Lake at June 30, 201 5 (the most recent date for which information is available). Chugach's share of expenses was $5,663,304 in 201 5 , $5,228,907 in 201 4 , and $4,882,163 in 201 3 and is included in purchased power in the accompanying financial statements. (In thousands) Total Proportionate Share Plant in service $ 167,235 $ 50,839 Long-term debt 62,585 19,026 Interest expense 3,668 1,115 Chugach's share of a Bradley Lake transmission line financed internally is included in Intangible Electric Plant .

Eklutna Hydroelectric Project

Eklutna Hydroelectric Project	12 Months Ended
	Dec. 31, 2015
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 201 5 inclu de d $4,401,440 , net of accumulated depreciation of $2,203,659 , which represents Chugach’s share of the Eklutna Hydroelectric Project. In 201 4 , plant in service included $4,442,440 , net of accumulated depreciation of $2,017,032 . The facility is operated by Chugach and maintained jointly by Chugach and ML&P. Each participant contributes their proportionate share for operation, maintenance and capital improvement costs to the plant, as well as to the transmission line between Anchorage and the plant. Under net billing arrangements, Chugach then reimburses MEA for their share of the costs. Chugach’s share of expenses was $689,501 , $761,613 , and $730,122 in 201 5 , 201 4 , and 201 3 , 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.

Commitments And Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies [Abstract]
Commitments And Contingencies	(15) Commitments and Contingencies Contingencies Chugach is a participant in various legal actions, rate disputes, personnel matters and claims both for and against Chugach’s interests. Management believes the outcome of any such matters will not materially impact Chugach’s financial condition, results of operations or liquidity. Chugach establishes reserves when a particular contingency is probable and calculable. Chugach has not accrued for any contingency at December 31, 2015, as it does not consider any contingency to be probable nor calculable. Chugach faces contingencies that are reasonably possible to occur; however, they cannot currently be estimated. Concentrations Approximately 70% of our employees are members of the International Brotherhood of Electrical Workers (IBEW). Chugach has three Collective Bargaining Unit Agreements (CBA) with the IBEW. We also have an agreement with the Hotel Employees and Restaurant Employees (HERE). All three IBEW CBA’s have been renewed through June 30, 2017 . The HERE contract has been renewed through June 30, 2016 . Chugach was the principal supplier of power under wholesale power contracts with MEA and HEA, which expired April 30, 2015 , and December 31, 2013 , respectively. The MEA contract, including the fuel component, represented $26.2 million through its expiration, or 13% of 2015 sales revenue, and $70.7 million, or 26% of 2014 sales revenue. The MEA and HEA contracts, including the fuel component, represented $103.1 million, or 35% of 2013 sales revenue. All rates were established by the RCA. Fuel Supply Contracts Chugach has fuel supply contracts from various producers at market terms. A gas supply contract between Chugach and ConocoPhillips Alaska, Inc. and ConocoPhillips, Inc. (collectively “ConocoPhillips”), approved effective by the RCA on August 21, 2009 , began providing gas in 2010 and will terminate December 31, 2016 . The total amount of gas under the contract is currently estimated to be 60 Bcf. T he 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. The se contracts fill 100% of Chugach’s needs through March 31, 2023. All of the production is expected to come from Cook Inlet, Alaska. In 201 5, 86% of our power was generated from gas, with 30% generated at the Beluga Power Plant and 61% generated at SPP. In 201 4 and 201 3 , 87% of our power was generated from gas, with 57% and 47% , respectively, generated at Beluga, and 43% and 31% , respectively, generated at SPP. The terms of the ConocoPhillips and Hilcorp agreements require Chugach to handle the natural gas transportation over the connecting pipeline systems. We have gas transportation agreements with ENSTAR and Hilcorp. The following represents the cost of fuel purchased and or transported from various vendors as a percentage of total fuel costs for the years ended December 31: 2015 2014 2013 Hilcorp 30.3 % 50.4 % 46.4 % ConocoPhillips (COP) 58.7 % 43.6 % 42.8 % AIX Energy 4.7 % 0.0 % 0.0 % ENSTAR 3.3 % 2.0 % 2.1 % Harvest (Hilcorp) Pipeline 1.6 % 3.0 % 3.8 % Miscellaneous 1.4 % 1.0 % 4.9 % Patronage Capital Payable Pursuant to agreements reached with HEA and MEA, and discussed in Note (9) – “Patronage Capital,” patronage capital allocated or retired to HEA or MEA is classified as patronage capital payable on Chugach’s balance sheet . HEA’s patronage capital payable was $7.9 million at December 31, 201 5 and 201 4 . MEA’s patronage capital payable was $3.2 million and $2.3 million at December 31, 2015 and 2014, 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 $0.000732 , effective July 1, 2015. 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 re venue tax in lieu of state and local ad valorem, income and excise taxes on electricity sold in the retail market. The tax is accrued monthly and remitted annually . Production Taxes Production taxes on Chugach fuel purchases are paid directly to our gas producers and are recorded under “Fuel” in Chugach’s financial statements. Underground Compliance Charge In 2005, the Anchorage Municipal Assembly adopted an ordinance to require utilities to convert overhead distribution lines to underground. To comply with the ordinance, Chugach must expend two percent of a three -year average of gross retail revenue within the Municipality of Anchorage annually in moving existing distribution overhead lines underground. Consistent with Alaska Statutes regarding undergrounding programs, Chugach is permitted to amend its rates by adding a two percent charge to its retail members’ bills to recover the actual costs of the program. The rate amendments are not subject to RCA review or approval. Chugach’s liability was $5,184,551 and $2,761,921 for this charge at December 31, 201 5 and 201 4 , respectively. These funds are used to offset the costs of the undergrounding program. Environmental Matters Since January 1, 2007, transformer manufacturers have been required to meet the US Department of Energy (DOE) efficiency levels as defined by the Energy Act of 2005 (Energy Act) for all “Distribution Transformers.” As of January 1, 2016, the specific efficiency levels are increasing from the original “TP1” levels to the new “DOE-2016” levels. The Energy Act mandates specific types of low voltage dry-type transformers manufactured and sold in the USA to have efficiencies as defined by the 10 CFR Part 431 standard when loaded to 35% of maximum capacity. Chugach is in the process of evaluating our transformer specifications and will make modifications as necessary with our alliance transformer manufacturers to ensure DOE-2016 is met. 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 (CO 2 ) 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 CO 2 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. 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. Economy Energy Sales On October 5, 2012 , Chugach and GVEA finalized arrangements for Chugach to provide economy energy to GVEA until March of 2015 . Sales w ere made under the terms and conditions of Chugach’s economy energy sales tariff. The price to GVEA include d the cost of fuel, variable operations and maintenance expense, wheeling charges and a margin. Chugach ha d also entered into specific gas supply arrangements to make economy energy sales to GVEA. Sales revenue to GVEA amounted to $8.0 million in 2015 through the expiration of their contract, and $36.9 million in 2014. Cooper Lake Hydroelectric Project The Cooper Lake Hydroelectric Project received a 50 -year license from FERC in August of 2007. A condition of that license is a requirement to construct a Stetson Creek diversion structure, a pipeline to Cooper Lake, and a bypass structure to release warmer water from Cooper Lake into Cooper Creek. If the project was not feasible or if the cost estimate materially exceed ed the terms of the license, Chugach ha d the option to request a license amendment. At the time the project was being relicensed the estimated cost to complete the project was $12.0 million. Due to a change in FERC requirements, the completed project cost $22.2 million. As an alternative to requesting a license amendment from FERC, Chugach requested grants from the State of Alaska. Funding for this project include d $9.3 million in grants awarded . The Chugach Board authorized expenditures for the project November 15, 2012. The diversion project began construction in 2013 and w as put into service on July 25, 2015. It will operate through the duration of the license.

Gain On Sale Of Asset

Gain On Sale Of Asset	12 Months Ended
	Dec. 31, 2015
Gain On Sale Of Asset [Abstract]
Gain On Sale Of Asset	(16) Gain on Sale of Asset On July 12, 2011, Chugach sold the Bernice Lake Power Plant to AEEC and HEA. Chugach recognized the proceeds from this sale as a liability on its Balance Sheet and continued to dispatch the power plant until the expiration of its power sales agreement with HEA. In December of 2013, Chugach recognized the gain associated with this sale which amounted to $6.4 million .

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	(17) Subsequent Events Beluga River Unit On February 4, 2016 , Chugach entered into an agreement entitled, “Purchase and Sale Agreement between ConocoPhillips Alaska, Inc. and Municipality of Anchorage d/b/a Municipal Light & Power and Chugach Electric Association, Inc.” The Purchase and Sale Agreement transfers COP’s working interest in the BRU to Chugach and ML&P. The total purchase price is $152 million, with Chugach’s portion totaling $45.6 million . Under the joint bid arrangement, Chugach’s ownership of COP’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 COP’s 67% working interest in deep oil resources. The acquisition is subject to the approval of the RCA (see “ Note 5 – Regulatory Matters – 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, 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, or from 2016 to 2033 . 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 firm gas supply contracts with COP and Hilcorp, as discussed in “ Note 15 – Commitments and Contingencies – Fuel Supply Contracts ”. In addition to Chugach, COP has contractual gas sales obligations to ENSTAR through 2017 . These contracts are expected to be assumed by ML&P and Chugach on the basis of ownership share. In addition to these firm contracts, Chugach has gas supply agreements with Aurora Gas LLC through September 30, 2016 , AIX Energy LLC through March 31, 2024 (with an option to extend the term an additional 5 -year period through March 31, 2029 ), and 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 ). Collectively, these agreements provide added diversification and optionality for Chugach to minimize costs within its gas supply portfolio. 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. Currently, the BRU is jointly owned ( one -third) by COP, Hilcorp, and ML&P. If the transaction is approved, ML&P’s ownership of the BRU would increase to approximately 56.7% , Hilcorp’s ownership would remain unchanged at 33.3% , and Chugach’s ownership would be 10.0% .

Quarterly Results Of Operations

Quarterly Results Of Operations	12 Months Ended
	Dec. 31, 2015
Quarterly Results Of Operations [Abstract]
Quarterly Results Of Operations	(1 8 ) Quarterly Results of Operations (unaudited) 2015 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 Operating Revenue $ 50,640,703 $ 43,109,512 $ 47,697,820 $ 74,973,117 Operating Expense 42,182,178 39,667,546 43,490,558 63,451,276 Net Interest 5,415,131 5,428,774 5,381,167 5,589,373 Net Operating Margins 3,043,394 (1,986,808) (1,173,905) 5,932,468 Nonoperating Margins 368,403 79,028 126,010 114,262 Assignable Margins $ 3,411,797 $ (1,907,780) $ (1,047,895) $ 6,046,730 2014 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 Operating Revenue $ 69,272,422 $ 65,677,900 $ 70,269,305 $ 76,098,886 Operating Expense 58,795,411 61,712,934 66,997,011 65,467,523 Net Interest 5,673,940 5,622,892 5,661,316 5,842,558 Net Operating Margins 4,803,071 (1,657,926) (2,389,022) 4,788,805 Nonoperating Margins 411,590 96,181 249,820 213,026 Assignable Margins $ 5,214,661 $ (1,561,745) $ (2,139,202) $ 5,001,831

Significant Accounting Polici25

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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 allowance for doubtful accounts, workers’ compensation, deferred charges and credits, unbilled revenue, the estimated useful life of utility plant and the cost of removal obligation. Actual results could differ from those estimates.
Regulation	b. Regulation The accounting records of Chugach conform to the Uniform System of Accounts as prescribed by the Federal Energy Regulatory Commission (FERC). Chugach meets the criteria, and accordingly, follows the accounting and reporting requirements of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 980, “Topic 980 - Regulated Operations.” FASB ASC 980 provides for the recognition of regulatory assets and liabilities as allowed by regulators for costs or credits that are reflected in current rates or are considered probable of being included in future rates. Our regulated rates are established to recover all of our specific costs of providing electric service. In each rate filing, rates are set at levels to recover all of our specific allowable costs and those rates are then collected from our retail and wholesale customers. The regulatory assets or liabilities are then reduced as the cost or credit is reflected in earnings and our rates, see Note (2j) – “ Deferred Charges and Credits.”
Utility Plant And Depreciation	c. Utility Plant and Depreciation Additions to electric plant in service are recorded at original cost of contracted services, direct labor and materials, indirect overhead charges and capitalized interest. For property replaced or retired, the book value of the property, less salvage, is charged to accumulated depreciation. The removal cost is charged to cost of removal obligation. Renewals and betterments are capitalized, while maintenance and repairs are normally charged to expense as incurred. In accordance with FASB ASC 360, “Topic 360 – Property, Plant, and Equipment,” certain asset groups are reviewed for impairment whenever events or changes in circumstances indicate the carrying amount of an asset group may not be recoverable in rates. Recoverability of asset groups to be held and used is measured by a comparison of the carrying amount of an asset group to estimated undiscounted future cash flows expected to be generated by the asset group. If the carrying amount of an asset group exceeds its estimated future cash flows, an impairment charge is recognized by the amount by which the carrying amount of the asset group exceeds the fair value of the asset. Depreciation and amortization rates have been applied on a straight ‑line basis and at December 31, 2015 are as follows: Annual Depreciation Rate Ranges Steam production plant 4.81% - 7.04% Hydroelectric production plant 1.06% - 3.00% Other production plant 3.98% - 10.15% Transmission plant 1.58% - 7.86% Distribution plant 2.17% - 9.63% General plant 1.57% - 20.00% Other 2.75% - 2.75% Southcentral Power Project (SPP) steam production plant 3.09% - 3.46% SPP other production plant 3.15% - 3.84% On November 1, 2010, the RCA approved revised depreciation rates effective November 1, 2010 in Docket U-09-097. Chugach’s depreciation rates include a provision for cost of removal. Chugach records a separate liability for the estimated obligation related to the cost of removal. On August 31, 2012, in Docket U-12-009, the RCA approved Southcentral Power Project (SPP) depreciation rates effective February 1, 2013, the date the SPP plant was placed in service.
Capitalized Interest	d. Capitalized Interest Allowance for funds used during construction (AFUDC) and interest charged to construction ‑ credit (IDC) are the estimated costs of the funds used during the period of construction from both equity and borrowed funds. AFUDC and IDC are applied to specific projects during construction. AFUDC and IDC calculations use the net cost of borrowed funds when used and is recovered through RCA approved rates as utility plant is depreciated. For all projects excluding SPP, Chugach capitalized such funds at the weighted average rate (adjusted monthly) of 4.3% during 2015 and 2014 and 3.7% during 2013. For SPP, Chugach capitalized actual interest expense and related fees associated with its construction.
Investments In Associated Organizations	e. Investments in Associated Organizations The loan agreements with CoBank, ACB (CoBank) and National Rural Utilities Cooperative Finance Corporation (NRUCFC) requires as a condition of the extension of credit, that an equity ownership position be established by all borrowers. Chugach’s equity ownership in these organizations is less than one percent. These investments are non-marketable and accounted for at cost. Management evaluates these investments annually for impairment. No impairment was recorded during 2015, 2014 and 2013.
Fair Value Of Financial Instruments	f. Fair Value of Financial Instruments FASB ASC 825, “Topic 825 – Financial Instruments,” requires disclosure of the fair value of certain on and off balance sheet financial instruments for which it is practicable to estimate that value. The following methods are used to estimate the fair value of financial instruments: Cash and cash equivalents – the carrying amount approximates fair value because of the short maturity of those instruments. Consumer deposits – the carrying amount approximates fair value because of the short refunding term. Long ‑term obligations – the fair value is estimated based on the quoted market price for same or similar issues (see note 11). Restricted cash – the carrying amount approximates fair value because of the short maturity of those instruments. 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.
Cash And Cash Equivalents / Restricted Cash Equivalents	g. Cash and Cash Equivalents / Restricted Cash Equivalents For purposes of the statement of cash flows, Chugach considers all highly liquid instruments with a maturity of three months or less upon acquisition by Chugach to be cash equivalents. 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 $6,218,015 and $6,300,149 during the years ended December 31, 2015 and 2014, respectively. Restricted cash equivalents include funds on deposit for future workers’ compensation claims and interim rates collected from customers and escrowed as required by the RCA. At December 31, 2015 and 2014, restricted cash equivalents included $2.8 million of funds on deposit for future workers’ compensation claims. At December 31, 2015 and 2014, there were no restricted cash equivalents representing interim rates collected from customers.
Accounts Receivable	h. Accounts Receivable Trade accounts receivable are recorded at the invoiced amount. The allowance for doubtful accounts is management’s best estimate of the amount of probable credit losses in existing accounts receivable. Chugach determines the allowance based on its historical write-off experience and current economic conditions. Chugach reviews its allowance for doubtful accounts monthly. Past due balances over 90 days in a specified amount are reviewed individually for collectability. All other balances are reviewed in aggregate. Account balances are charged off against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. Chugach does not have any off–balance-sheet credit exposure related to its customers. Included in accounts receivable are invoiced amounts to Anchorage Municipal Light & Power (ML&P) for their proportionate share of current SPP costs, which amounted to $1.1 million and $0.9 million in 2015 and 2014, respectively. In addition, accounts receivable includes invoiced amounts for grants to support the construction of facilities to divert water and safely transmit electricity, which amounted to $0.2 million and $1.1 million in 2015 and 2014, respectively.
Materials And Supplies	i. Materials and Supplies Materials and supplies are stated at average cost.
Deferred Charges and Credits	j. Deferred Charges and Credits In accordance with FASB ASC 980, Chugach’s financial statements reflect regulatory assets and liabilities. Continued accounting under FASB ASC 980 requires that certain criteria be met. We capitalize all or part of costs that would otherwise be charged to expense if it is probable that future revenue in an amount at least equal to the capitalized cost will result from inclusion of that cost in allowable costs for ratemaking purposes and future revenue will be provided to permit recovery of the previously incurred cost. Management believes Chugach’s operations currently satisfy these criteria. Chugach regulatory asset recoveries are embedded in base rates approved by the RCA. Specific costs incurred and recorded as Regulatory Assets, including the amortization period for recovery, are approved by the RCA either in standard Simplified Rate Filings (SRF), general rate case filings or specified independent requests. The rates approved related to the regulatory assets are matched to the amortization of actual expenses recognized. The regulatory assets are amortized and collected through rates over differing periods depending upon the period of benefit as established by the RCA. Deferred credits, primarily representing regulatory liabilities, are amortized to operating expense over the period required for ratemaking purposes. It also includes refundable contributions in aid of construction, which are credited to the associated cost of construction of property units. Refundable contributions in aid of construction are held in deferred credits pending their return or other disposition. If events or circumstances should change so the criteria are not met, the write off of regulatory assets and liabilities could have a material effect on Chugach’s financial position, results of operations or cash flows.
Patronage Capital	k. Patronage Capital Revenues in excess of current period costs (net operating margins and nonoperating margins) in any year are designated on Chugach’s statement of 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.
Operating Revenues	l. Operating Revenues Revenues are recognized upon delivery of electricity. Operating revenues are based on billing rates authorized by the RCA, which are applied to customers’ usage of electricity. Chugach’s rates are established, in part, on test period sales levels that reflect actual operating results. Chugach calculates unbilled revenue at the end of each month to ensure the recognition of a calendar year’s revenue. Chugach accrued $10,531,377 and $9,885,526 of unbilled retail revenue at December 31, 2015 and 2014, respectively. Wholesale revenue is recorded from metered locations on a calendar month basis, so no estimation is required. Chugach's tariffs include provisions for the recovery of gas costs according to gas supply contracts, as well as purchased power costs.
Fuel And Purchased Power Cost Recovery	m. Fuel and Purchased Power Cost Recovery Expenses associated with electric services include fuel used to generate electricity and power purchased from others. Chugach is authorized by the RCA to recover fuel and purchased power costs through the fuel and purchased power adjustment process, which is adjusted quarterly to reflect increases and decreases of such costs. We recognize differences between projected recoverable fuel costs and amounts actually recovered through rates. The fuel cost under/over recovery on our Balance Sheet represents the net accumulation of any under- or over-collection of fuel and purchase power costs. Fuel cost under-recovery will appear as an asset on our Balance Sheet and will be collected from our members in subsequent periods. Conversely, fuel cost over-recovery will appear as a liability on our Balance Sheet and will be refunded to our members in subsequent periods. Fuel costs were over-recovered by $5,135,745 and by $1,462,057 in 2015 and 2014, respectively. Total fuel and purchased power costs in 2015, 2014, and 2013 were $86,134,871 , $141,646,746 , and $164,446,942 , respectively.
Environmental Remediation Costs	n. Environmental Remediation Costs Chugach accrues for losses and establishes a liability associated with environmental remediation obligations when such losses are probable and can be reasonably estimated. Such accruals are adjusted as further information develops or circumstances change. Estimates of future costs for environmental remediation obligations are not discounted to their present value. However, various remediation costs may be recoverable through rates and accounted for as a regulatory asset.
Income Taxes	o. Income Taxes Chugach is exempt from federal income taxes under the provisions of Section 501(c)(12) of the Internal Revenue Code and for the years ended December 31, 2015, 2014 and 2013 was in compliance with that provision. In addition, as described in Note (15) – “Commitments and Contingencies,” Chugach collects sales tax and is assessed gross revenue and excise taxes which are presented on a net basis in accordance with FASB ASC 605-45-50, “Topic 605 - Revenue Recognition – Subtopic 45 - Principal Agent Considerations – Section 50 - Disclosure.” Chugach applies a more-likely-than-not recognition threshold for all tax uncertainties. FASB ASC 740, “Topic 740 – Income Taxes,” only allows the recognition of those tax benefits that have a greater than 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, 2013 through December 31, 2015 for United States Federal Income Tax, the tax years which remain subject to examination by major tax jurisdictions as of December 31, 2015.
Consumer Deposits	p. Consumer Deposits Consumer deposits are the amounts certain customers are required to deposit to receive electric service. Consumer deposits for the years ended December 31, 2015 and 2014, totaled $3.1 million and $2.9 million, respectively. Consumer deposits also represent customer credit balances as a result of prepaid accounts. Credit balances for the years ended December 31, 2015 and 2014 totaled $1.9 million and $2.0 million, respectively.
Grants	q. Grants Chugach has received federal and state grants to offset storm related expenditures and to support the construction of facilities to transport fuel, divert water and safely transmit electricity to its consumers. Grant proceeds used to construct or acquire equipment are offset against the carrying amount of the related assets while grant proceeds for storm related expenditures are offset against the actual expense incurred, which totaled $1.6 million and $4.8 million in 2015 and 2014, respectively.
Fuel Stock	r. Fuel Stock Fuel Stock is the weighted average cost of fuel injected into Cook Inlet Natural Gas Storage Alaska (CINGSA), which began service in the second quarter of 2012. Chugach’s fuel balance in storage for the years ended December 31, 2015 and 2014 amounted to $7.1 million and $9.7 million, respectively.
Corrections	s. Corrections For the year ended December 31, 2 015, Chugach recorded the following correction for the year ended December 31, 2014: A correction representing the long-term versus current presentation of long-term obligations associated with bonds payable, previously reported as current installments of long-term obligations and now reported as long-term obligations, excluding current installments. The impact of this correction was an increase to long-term obligations, excluding current installments, and a decrease to current installments of long-term obligations of $1.0 million as of December 31, 2014 . For the year ended December 31, 2015, Chugach recorded the following correction for the years ended December 31, 2014 and 2013 : A correction representing the cash received from customers for the undergrounding ordinance, included in net receipts on consumer advances for construction, previously reported as other current liabilities. The impact of this correction was a decrease in cash provided by operating activities and cash used in financing activities of $3.2 million and $2.9 million for the years ended December 31, 2014 and 2013, respectively.

Significant Accounting Polici26

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Significant Accounting Policies [Abstract]
Schedule Of Depreciation And Amortization Rates	Steam production plant 4.81% - 7.04% Hydroelectric production plant 1.06% - 3.00% Other production plant 3.98% - 10.15% Transmission plant 1.58% - 7.86% Distribution plant 2.17% - 9.63% General plant 1.57% - 20.00% Other 2.75% - 2.75% Southcentral Power Project (SPP) steam production plant 3.09% - 3.46% SPP other production plant 3.15% - 3.84%

Utility Plant (Tables)

Utility Plant (Tables)	12 Months Ended
	Dec. 31, 2015
Utility Plant [Abstract]
Schedule Of Major Classes Of Utility Plant	Electric plant in service: 2015 2014 Steam production plant $ 100,938,247 $ 161,454,274 Hydroelectric production plant 20,591,678 20,594,429 Other production plant 284,035,865 278,389,073 Transmission plant 277,490,606 261,173,934 Distribution plant 290,680,919 281,706,456 General plant 51,841,582 53,452,136 Unclassified electric plant in service 1 95,611,615 91,446,881 Intangible plant 1 5,455,371 5,455,371 Other 1 1,828,409 1,828,409 Total electric plant in service 1,128,474,292 1,155,500,963 Construction work in progress 15,601,374 21,567,341 Total electric plant in service and construction work in progress $ 1,144,075,666 $ 1,177,068,304 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.

Investments In Associated Org28

Investments In Associated Organizations (Tables)	12 Months Ended
	Dec. 31, 2015
Investments In Associated Organizations [Abstract]
Schedule Of Investments In Associated Organizations	2015 2014 NRUCFC $ 6,095,980 $ 6,095,980 CoBank 3,475,664 3,763,697 NRUCFC Capital Term Certificates and other 63,875 63,875 Total investments in associated organizations $ 9,635,519 $ 9,923,552

Deferred Charges And Credits (T

Deferred Charges And Credits (Tables)	12 Months Ended
	Dec. 31, 2015
Regulatory Assets [Line Items]
Schedule Of Deferred Charges, Or Regulatory Assets	2015 2014 Debt issuance and reacquisition costs $ 2,928,378 $ 3,263,937 Refurbishment of transmission equipment 114,198 123,457 Feasibility studies 551,122 578,806 Beluga gas compression 508,866 1,017,733 Cooper Lake relicensing / projects 5,410,109 5,540,212 Fuel supply 939,768 898,849 Storm damage 841,595 971,071 Other regulatory deferred charges 1,257,809 1,464,784 Bond interest - market risk management 5,871,286 6,402,875 Environmental matters 1,069,522 1,114,872 Total deferred charges $ 19,492,653 $ 21,376,596
Schedule Of Deferred Credits, Or Regulatory Liabilities	2015 2014 Refundable consumer advances for construction $ 823,115 $ 787,824 Estimated initial installation costs for meters 105,274 98,964 Post retirement benefit obligation 874,000 874,000 Other 0 97,667 Total deferred costs $ 1,802,389 $ 1,858,455
Not Currently Being Recovered In Rates Charged to Consumers [Member]
Regulatory Assets [Line Items]
Schedule Of Deferred Charges, Or Regulatory Assets	2015 2014 Studies and other $ 686,348 $ 387,253 Storm damage 0 971,071 Wind project 0 34,543 Total deferred charges $ 686,348 $ 1,392,867

Other Equities (Tables)

Other Equities (Tables)	12 Months Ended
	Dec. 31, 2015
Other Equities [Abstract]
Schedule Of Other Equities	2015 2014 Nonoperating margins, prior to 1967 $ 23,625 $ 23,625 Donated capital 1,877,193 1,806,424 Unclaimed capital credit retirement 1 10,627,038 9,328,628 Total other equities $ 12,527,856 $ 11,158,677 1 Represents unclaimed capital credits that have met all requirements of Alaska Statute section 34.45.200 regarding Alaska’s unclaimed property law and has therefore reverted to Chugach.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt [Abstract]
Schedule Of Long-Term Obligations	Long-term obligations at December 31 are as follows: 2015 2014 2011 CoBank bond, 2.77% variable rate bond maturing in 2022 , with interest payable monthly and principal due annually beginning in 2003 $ 24,941,165 $ 27,414,275 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 72,000,000 76,500,000 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 160,333,332 166,499,999 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 63,750,000 67,500,000 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 102,000,000 109,000,000 2012 Series A Bond of 4.78% , maturing in 2042 , with interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023 50,000,000 50,000,000 Total long-term obligations $ 473,024,497 $ 496,914,274 Less current installments 24,115,980 23,889,777 Long-term obligations, excluding current installments $ 448,908,517 $ 473,024,497
Schedule Of Maturities Of Long-Term Obligations	Year ending December 31 2011 Series A Bonds CoBank Bond 2012 Series A Bonds Total 2016 10,666,667 2,699,313 10,750,000 24,115,980 2017 10,666,667 2,945,954 10,750,000 24,362,621 2018 10,666,667 3,215,267 10,750,000 24,631,934 2019 10,666,667 3,509,142 10,750,000 24,925,809 2020 10,666,667 3,829,809 10,750,000 25,246,476 Thereafter 178,999,997 8,741,680 162,000,000 349,741,677 $ 232,333,332 $ 24,941,165 $ 215,750,000 $ 473,024,497
Schedule Of Monthly Commercial Paper Balances Outstanding And Weighted Average Interest Rates	Month Average Balance Weighted Average Interest Rate Month Average Balance Weighted Average Interest Rate January 2015 $ 17.8 0.26 July 2015 $ 10.1 0.26 February 2015 $ 11.6 0.22 August 2015 $ 12.0 0.25 March 2015 $ 16.0 0.29 September 2015 $ 19.5 0.25 April 2015 $ 23.8 0.28 October 2015 $ 24.0 0.25 May 2015 $ 16.0 0.27 November 2015 $ 22.4 0.25 June 2015 $ 12.1 0.31 December 2015 $ 21.4 0.49
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 10.0 4.20 % $ 90,000 $ 72,000 2011 Series A, Tranche B 2041 15.5 4.75 % 185,000 160,333 2012 Series A, Tranche A 2032 10.7 4.01 % 75,000 63,750 2012 Series A, Tranche B 2042 15.7 4.41 % 125,000 102,000 2012 Series A, Tranche C 2042 20.7 4.78 % 50,000 50,000 Total $ 525,000 $ 448,083
Schedule Of Estimated Fair Value Of Long-Term Obligations	Carrying Value Fair Value Long-term obligations (including current installments) $ 473,024 $ 480,135

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Employee Benefit Plans [Abstract]
Schedule Of Information Regarding Individually Significant Pension Plans	Alaska Electrical Pension Plan 3 NRECA Retirement Security Plan 3 Employer Identification Number 92-6005171 53-0116145 Plan Number 001 333 Year-end Date December 31 December 31 Expiration Date of CBA's June 30, 2017 N/A 2 Subject to Funding Improvement Plan No No 4 Surcharge Paid N/A N/A 4 2015 2014 2013 2015 2014 2013 Zone Status Green Green Green N/A 1 N/A 1 N/A 1 Required minimum contributions None None None N/A N/A N/A Contributions (in millions) $3.1 $3.3 $3.4 $3.5 $3.5 $3.4 Contributions > 5% of total plan contributions Yes Yes Yes No No No 1 A “zone status” determination is not required, and therefore not determined under the Pension Protection Act (PPA) of 2006. 2 The CEO is the only participant in the NRECA RS Plan who is subject to an employment agreement, which is effective through July 17, 2016. 3 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 . 4 The provisions of the PPA do not apply to the RS Plan, therefore, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the RS Plan and may change as a result of plan experience.

Bradley Lake Hydroelectric Pr33

Bradley Lake Hydroelectric Project (Tables)	12 Months Ended
	Dec. 31, 2015
Bradley Lake Hydroelectric Project [Abstract]
Schedule Of Bradley Lake Information	(In thousands) Total Proportionate Share Plant in service $ 167,235 $ 50,839 Long-term debt 62,585 19,026 Interest expense 3,668 1,115

Commitments And Contingencies (

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies [Abstract]
Schedule Of Costs Of Fuel Purchased And Transported As A Percentage Of Total Fuel Costs	2015 2014 2013 Hilcorp 30.3 % 50.4 % 46.4 % ConocoPhillips (COP) 58.7 % 43.6 % 42.8 % AIX Energy 4.7 % 0.0 % 0.0 % ENSTAR 3.3 % 2.0 % 2.1 % Harvest (Hilcorp) Pipeline 1.6 % 3.0 % 3.8 % Miscellaneous 1.4 % 1.0 % 4.9 %

Quarterly Results Of Operatio35

Quarterly Results Of Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Results Of Operations [Abstract]
Schedule Of Quarterly Results Of Operations	2015 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 Operating Revenue $ 50,640,703 $ 43,109,512 $ 47,697,820 $ 74,973,117 Operating Expense 42,182,178 39,667,546 43,490,558 63,451,276 Net Interest 5,415,131 5,428,774 5,381,167 5,589,373 Net Operating Margins 3,043,394 (1,986,808) (1,173,905) 5,932,468 Nonoperating Margins 368,403 79,028 126,010 114,262 Assignable Margins $ 3,411,797 $ (1,907,780) $ (1,047,895) $ 6,046,730 2014 Quarter Ended Dec. 31 Sept. 30 June 30 March 31 Operating Revenue $ 69,272,422 $ 65,677,900 $ 70,269,305 $ 76,098,886 Operating Expense 58,795,411 61,712,934 66,997,011 65,467,523 Net Interest 5,673,940 5,622,892 5,661,316 5,842,558 Net Operating Margins 4,803,071 (1,657,926) (2,389,022) 4,788,805 Nonoperating Margins 411,590 96,181 249,820 213,026 Assignable Margins $ 5,214,661 $ (1,561,745) $ (2,139,202) $ 5,001,831

Description Of Business (Detail

Description Of Business (Details)	12 Months Ended
	Dec. 31, 2015mi
Electrification area	400
Matanuska Electric Association, Inc. [Member]
Power contracts expiration date	Apr. 30, 2015
Homer Electric Association, Inc. [Member]
Power contracts expiration date	Dec. 31, 2013
Golden Valley Electric Association, Inc. [Member]
Power contracts expiration date	Mar. 31, 2015

Significant Accounting Polici37

Significant Accounting Policies (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Significant Accounting Policies [Line Items]
Weighted average capital interest percentage	4.30%	4.30%	3.70%
Impairment on investments	$ 0	$ 0	$ 0
Minimum number of days past balances reviewed	90 days
Accounts receivable	$ 28,232,930	36,060,256
Fuel cost over-recovery	5,135,745	1,462,057
Fuel and purchased power costs	86,134,871	141,646,746	164,446,942
Consumer deposits	3,100,000	2,900,000
Customer credits	1,900,000	2,000,000
Grant proceeds included in public utilities property, plant and equipment carrying amount	1,600,000	4,800,000
Fuel stock	7,063,541	9,652,073
Increase to long-term obligations, excluding current installments		1,000,000
Decrease to current installments of long-term obligations		(1,000,000)
Cash provided by operating activities	52,096,436	58,766,300	36,982,973
Cash used in financing activities	(20,486,734)	(34,061,334)	(2,636,404)
ML&P For Fuel and South Central Power Project Costs [Member]
Significant Accounting Policies [Line Items]
Accounts receivable	1,100,000	900,000
Alaska Energy Authority For Grant [Member]
Significant Accounting Policies [Line Items]
Accounts receivable	200,000	1,100,000
Concentration Account [Member]
Significant Accounting Policies [Line Items]
Average balance of cash account	6,218,015	6,300,149
Future Workers Compensation Claims [Member]
Significant Accounting Policies [Line Items]
Restricted cash equivalents	2,800,000	2,800,000
Interim Rates Collected From Customers [Member]
Significant Accounting Policies [Line Items]
Restricted cash equivalents	0	0
Unbilled Retail Revenues [Member]
Significant Accounting Policies [Line Items]
Accounts receivable	$ 10,531,377	9,885,526
Maximum [Member] | CoBank, ACB (CoBank) And National Rural Utilities Cooperative Finance Corporation (NRUCFC) [Member]
Significant Accounting Policies [Line Items]
Cost ownership percentage	1.00%
Restatement Adjustment [Member]
Significant Accounting Policies [Line Items]
Cash provided by operating activities		(3,200,000)	(2,900,000)
Cash used in financing activities		$ 3,200,000	$ 2,900,000

Significant Accounting Polici38

Significant Accounting Policies (Schedule Of Depreciation And Amortization Rates) (Details)	12 Months Ended
	Dec. 31, 2015
Minimum [Member] | Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	4.81%
Minimum [Member] | Hydroelectric Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	1.06%
Minimum [Member] | Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.98%
Minimum [Member] | Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	1.58%
Minimum [Member] | Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.17%
Minimum [Member] | General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	1.57%
Minimum [Member] | Other Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.75%
Minimum [Member] | Southcentral Power Project (SPP) Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.09%
Minimum [Member] | SPP Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.15%
Maximum [Member] | Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	7.04%
Maximum [Member] | Hydroelectric Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.00%
Maximum [Member] | Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	10.15%
Maximum [Member] | Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	7.86%
Maximum [Member] | Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	9.63%
Maximum [Member] | General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	20.00%
Maximum [Member] | Other Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	2.75%
Maximum [Member] | Southcentral Power Project (SPP) Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.46%
Maximum [Member] | SPP Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Depreciation and amortization rates	3.84%

Fair Value Of Assets And Liab39

Fair Value Of Assets And Liabilities (Details)	Dec. 31, 2015USD ($)
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value, assets	$ 0
Fair value, liabilities	0
Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value, assets	0
Fair value, liabilities	$ 0

Regulatory Matters (Details)

Regulatory Matters (Details)

Dec. 04, 2015MMcf

Mar. 23, 2015USD ($)

Feb. 13, 2015USD ($)

Jan. 30, 2015itemMMcf

Dec. 22, 2014USD ($)$ / McfeMcf

Oct. 16, 2014USD ($)

Jan. 01, 2014

Nov. 19, 2013USD ($)

Jan. 31, 2016USD ($)

Jul. 31, 2015a

Apr. 30, 2015

Dec. 31, 2015USD ($)MMcf

Sep. 30, 2015USD ($)

Jun. 30, 2015USD ($)

Mar. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Sep. 30, 2014USD ($)

Jun. 30, 2014USD ($)

Mar. 31, 2014USD ($)

Dec. 31, 2015USD ($)MMcf

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Apr. 01, 2020MMcf

Apr. 01, 2019MMcf

Apr. 01, 2018

Feb. 04, 2016

Other Commitments [Line Items]

Proposed increase (decrease) in base rate revenues

$ 21,300,000

$ 16,000,000

Proposed percentage increase (decrease) in base rate revenues

20.00%

12.50%

Times interest earned ratio

1.30

Base rate revenue for proposed rate increase (decrease)

$ 127,400,000

Refunds for service

$ 1,100,000

Assignable margins

(200,000)

$ 3,411,797

$ (1,907,780)

$ (1,047,895)

$ 6,046,730

$ 5,214,661

$ (1,561,745)

$ (2,139,202)

$ 5,001,831

$ 6,502,852

$ 6,515,545

$ 10,544,043

Regulatory asset

19,492,653

21,376,596

19,492,653

21,376,596

Storm Damage [Member]

Other Commitments [Line Items]

Regulatory asset

900,000

$ 841,595

$ 971,071

$ 841,595

$ 971,071

Amortization of regulatory asset per year

$ 200,000

Number of years to recover storm costs

5 years

Matanuska Electric Association, Inc. [Member]

Other Commitments [Line Items]

Commencement date of Interim Power Sales Agreement

Jan. 1, 2015

Expiration date of Interim Power Sales Agreement

Mar. 31, 2015

Number of units available to pool with Chugach units to meet combined system load | item

4

Extension date of Interim Power Sales Agreement

Apr. 30, 2015

Term of dispatch services

1 year

Dispatch services revenue per month

$ 40,000

Expiration date of dispatch services

Mar. 31, 2016

Retail Customers [Member]

Other Commitments [Line Items]

Approved percentage increase (decrease) in base rate revenues

6.00%

ConocoPhillips (COP) [Member]

Other Commitments [Line Items]

Acres of exploration prospects | a

5,700

Subsequent Event [Member]

Other Commitments [Line Items]

Approved percentage increase (decrease) in base rate revenues

(0.50%)

Approved increase (decrease) in base rate revenues

$ (600,000)

Times interest earned ratio

1.35

Times interest earned ratio margin increase per year

$ 1,000,000

Minimum [Member]

Other Commitments [Line Items]

Approved percentage increase (decrease) in base rate revenues

2.00%

Maximum [Member]

Other Commitments [Line Items]

Approved percentage increase (decrease) in base rate revenues

5.00%

AIX Energy, LLC [Member]

Other Commitments [Line Items]

Commencement date of Gas Sale and Purchase Agreement

Mar. 1, 2015

Expiration date of Gas Sale and Purchase Agreement

Feb. 29, 2016

Extension date of Gas Sale and Purchase Agreement

Mar. 31, 2024

Optional number of years of contract extension

5 years

Optional extension date of Gas Sale and Purchase Agreement

Mar. 31, 2029

Minimum purchase requirement | MMcf

0

AIX Energy, LLC [Member] | Maximum [Member]

Other Commitments [Line Items]

Price of natural gas purchases | $ / Mcfe

6.24

Total volume of natural gas purchases | Mcf

300,000

Maximum total outlay of natural gas purchases

$ 1,900,000

Hilcorp Alaska, LLC [Member]

Other Commitments [Line Items]

Expiration date of Gas Sale and Purchase Agreement

Mar. 31, 2023

Total volume of natural gas purchases | MMcf

49,000

49,000

Addtional volume of gas purchases per day | MMcf

2

Hilcorp Alaska, LLC [Member] | Forecast [Member]

Other Commitments [Line Items]

Percentage reduction in gas price

(8.50%)

Increase in contract volume of gas | MMcf

1,100

Increase in contract volume of gas annually | MMcf

2,600

CINGSA [Member]

Other Commitments [Line Items]

Total volume of natural gas found | MMcf

14,500

Approved volume of natural gas for commercial sale | MMcf

2,000

Percentage of proceeds allocated

13.00%

Term of notice preceding gas sales

30 days

CINGSA [Member] | Minimum [Member]

Other Commitments [Line Items]

Proposed volume of natural gas for commercial sale | MMcf

2,000

FSS [Member]

Other Commitments [Line Items]

Percentage of proceeds allocated

87.00%

ENSTAR [Member]

Other Commitments [Line Items]

Proposed increase (decrease) in base rate revenues

$ 2,600,000

Proposed percentage increase (decrease) in base rate revenues

20.00%

Approved increase (decrease) in base rate revenues

$ 500,000

Proposed percentage increase for gas transportation services

100.00%

Beluga River Unit [Member]

Other Commitments [Line Items]

Working interest ownership percentage

10.00%

10.00%

Date of Purchase and Sale Agreement

Feb. 4, 2016

Beluga River Unit [Member] | ConocoPhillips (COP) [Member]

Other Commitments [Line Items]

Working interest ownership percentage

33.30%

33.30%

Beluga River Unit [Member] | Subsequent Event [Member]

Other Commitments [Line Items]

Working interest ownership percentage

30.00%

Beluga River Unit [Member] | Minimum [Member]

Other Commitments [Line Items]

Expected term for RCA review

2 months

Beluga River Unit [Member] | Maximum [Member]

Other Commitments [Line Items]

Expected term for RCA review

6 months

Utility Plant (Details)

Utility Plant (Details) - USD ($)		Dec. 31, 2015	Dec. 31, 2014
Public Utility, Property, Plant and Equipment [Line Items]
Total electric plant in service		$ 1,128,474,292	$ 1,155,500,963
Construction work in progress		15,601,374	21,567,341
Total utility plant		1,144,075,666	1,177,068,304
Steam Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing		100,938,247	161,454,274
Hydroelectric Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing		20,591,678	20,594,429
Other Production Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Generation and processing		284,035,865	278,389,073
Transmission Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Transmission		277,490,606	261,173,934
Distribution Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Distribution		290,680,919	281,706,456
General Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment		51,841,582	53,452,136
Unclassified Electric Plant In Service [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Other property, plant and equipment	[1]	95,611,615	91,446,881
Intangible Plant [Member]
Public Utility, Property, Plant and Equipment [Line Items]
Transmission	[1]	5,455,371	5,455,371
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.

Investments In Associated Org42

Investments In Associated Organizations (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	$ 9,635,519	$ 9,923,552
NRUCFC [Member]
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	6,095,980	6,095,980
CoBank [Member]
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	3,475,664	3,763,697
NRUCFC Capital Term Certificates And Other [Member]
Schedule of Cost-method Investments [Line Items]
Total investments in associated organizations	$ 63,875	$ 63,875

Deferred Charges And Credits (S

Deferred Charges And Credits (Schedule Of Deferred Charges, Or Regulatory Assets) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Oct. 16, 2014
Regulatory Assets [Line Items]
Total deferred charges	$ 19,492,653	$ 21,376,596
Debt Issuance And Reacquisition Costs [Member]
Regulatory Assets [Line Items]
Total deferred charges	2,928,378	3,263,937
Refurbishment Of Transmission Equipment [Member]
Regulatory Assets [Line Items]
Total deferred charges	114,198	123,457
Feasibility Studies [Member]
Regulatory Assets [Line Items]
Total deferred charges	551,122	578,806
Beluga Gas Compression [Member]
Regulatory Assets [Line Items]
Total deferred charges	508,866	1,017,733
Cooper Lake Relicensing / Projects [Member]
Regulatory Assets [Line Items]
Total deferred charges	5,410,109	5,540,212
Fuel Supply [Member]
Regulatory Assets [Line Items]
Total deferred charges	939,768	898,849
Storm Damage [Member]
Regulatory Assets [Line Items]
Total deferred charges	841,595	971,071	$ 900,000
Other [Member]
Regulatory Assets [Line Items]
Total deferred charges	1,257,809	1,464,784
Bond Interest - Market Risk Management [Member]
Regulatory Assets [Line Items]
Total deferred charges	5,871,286	6,402,875
Environmental Matters [Member]
Regulatory Assets [Line Items]
Total deferred charges	$ 1,069,522	$ 1,114,872

Deferred Charges And Credits 44

Deferred Charges And Credits (Schedule Of Deferred Charges, Or Regulatory Assets, Not Currently Being Recovered In Rates Charged To Consumers) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014	Oct. 16, 2014
Regulatory Assets [Line Items]
Total deferred charges	$ 19,492,653	$ 21,376,596
Storm Damage [Member]
Regulatory Assets [Line Items]
Total deferred charges	841,595	971,071	$ 900,000
Not Currently Being Recovered In Rates Charged to Consumers [Member]
Regulatory Assets [Line Items]
Total deferred charges	686,348	1,392,867
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Studies And Other [Member]
Regulatory Assets [Line Items]
Total deferred charges	686,348	387,253
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Storm Damage [Member]
Regulatory Assets [Line Items]
Total deferred charges	0	971,071
Not Currently Being Recovered In Rates Charged to Consumers [Member] | Wind Project [Member]
Regulatory Assets [Line Items]
Total deferred charges	$ 0	$ 34,543

Deferred Charges And Credits 45

Deferred Charges And Credits (Schedule Of Deferred Credits, Or Regulatory Liabilities) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Total deferred costs	$ 1,802,389	$ 1,858,455
Refundable Consumer Advances For Construction [Member]
Regulatory Liabilities [Line Items]
Total deferred costs	823,115	787,824
Estimated Initial Installation Costs For Meters [Member]
Regulatory Liabilities [Line Items]
Total deferred costs	105,274	98,964
Post Retirement Benefit Obligation [Member]
Regulatory Liabilities [Line Items]
Total deferred costs	874,000	874,000
Other [Member]
Regulatory Liabilities [Line Items]
Total deferred costs	$ 0	$ 97,667

Patronage Capital (Details)

Patronage Capital (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Patronage capital	$ 167,447,781	$ 164,135,053
Patronage capital assigned	160,944,929	157,619,508
Patronage capital to be assigned to members	6,502,852	6,515,545
Patronage capital payable	11,108,071	10,205,739
Retirement of capital credits	3,190,124	5,130,381	$ 1,626,828
Excluding Homer Electric Association Retirement [Member]
Retirement of capital credits	3,190,124	5,130,381	1,626,828
Excluding Matanuska Electric Association And Homer Electric Association Patronage Capital [Member]
Liability of capital credits	$ 2,105,440	1,042,064	$ 1,470,263
Assignable Margins [Member]
Secured debt covenant restriction during period	50.00%
Homer Electric Association, Inc. [Member]
Return of patronage capital term after expiration date of Power Sales Agreement	5 years
Expiration date of power sales agreement	Dec. 31, 2013
Patronage capital payable	$ 7,900,000	7,900,000
Matanuska Electric Association, Inc. [Member]
Expiration date of power sales agreement	Apr. 30, 2015
Patronage capital payable	$ 3,200,000	$ 2,300,000
Minimum [Member] | Aggregate Equities And Margins To Total Liabilities And Equities And Margins [Member]
Secured debt covenant restriction during period	30.00%
Patronage Capital [Member]
Secured debt covenant restriction at period end	5.00%

Other Equities (Schedule Of Oth

Other Equities (Schedule Of Other Equities) (Details) - USD ($)		Dec. 31, 2015	Dec. 31, 2014
Total other equities		$ 12,527,856	$ 11,158,677
Nonoperating Margins, Prior To 1967 [Member]
Total other equities		23,625	23,625
Donated Capital [Member]
Total other equities		1,877,193	1,806,424
Unclaimed Capital Credit Retirement [Member]
Total other equities	[1]	$ 10,627,038	$ 9,328,628
[1]	Represents unclaimed capital credits that have met all requirements of Alaska Statute section 34.45.200 regarding Alaska's unclaimed property law and has therefore reverted to Chugach.

Debt (Narrative) (Details)

Debt (Narrative) (Details)	Jun. 29, 2012	Dec. 31, 2015USD ($)item	Dec. 31, 2014USD ($)	Jan. 11, 2012USD ($)	Jan. 21, 2011USD ($)	Nov. 17, 2010USD ($)
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Line of credit, maximum borrowing capacity		$ 50,000,000
Line of credit facility, outstanding amount		$ 0	$ 0
Line of credit, borrowing rate description		The borrowing rate is calculated using the total rate per annum and may be fixed by NRUCFC.
Line of credit, borrowing rate		2.90%	2.90%
Period of time the line of credit needs to be paid down for five consecutive days		12 months
Number of consecutive days debt needs to be paid down to $0 during a twelve month period		5 days
Line of credit, expiration date		Oct. 12, 2017
Commercial paper		$ 20,000,000	$ 21,000,000
Minimum [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Commercial paper repricing term		1 day
Maximum [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Commercial paper repricing term		270 days
Amended Unsecured Credit Agreement [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Yield margins for interest multiplier to total interest expense | item		1.10
Line of credit, borrowing rate description		one month London Interbank Offered Rate (LIBOR) plus 107.5 basis points, along with a 17.5 basis points facility fee (based on an A- unsecured debt rating).
Line of credit, expiration date		Nov. 17, 2016
Line of credit facility, first amendment date		May 4, 2012
Line of credit facility, second amendment date		Jun. 29, 2012
Commercial paper, basis points facility fee on variable rate	0.175%
Amended Unsecured Credit Agreement [Member] | LIBOR [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Commercial paper, basis points on variable rate	1.075%
Amended Unsecured Credit Agreement [Member] | Maximum [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Line of credit, maximum borrowing capacity		$ 100,000,000
Second Amended And Restated Indenture Of Trust [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Yield margins for interest multiplier to total interest expense | item		1.10
CoBank Master Loan Agreement [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Yield margins for interest multiplier to total interest expense | item		1.10
Line of credit facility, first amendment date		Jan. 19, 2011
Initial Unsecured Credit Agreement [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Line of credit, maximum borrowing capacity						$ 300,000,000
Line of credit, initiation date		Nov. 17, 2010
2011 Series A Bonds [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Bonds issuance date		Jan. 21, 2011
Bonds issuance amount					$ 275,000,000
Bonds commencement payment date		Sep. 15, 2011
2012 Series A Bonds [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Bonds issuance date		Jan. 11, 2012
Bonds issuance amount				$ 250,000,000
Bonds commencement payment date		Sep. 15, 2012
2012 Series A Bond Of 4.41% Maturing 2042 [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Bonds issuance amount		$ 125,000,000
Bonds maturity date		Mar. 15, 2042
Assignable Margins [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Secured debt covenant restriction during period		50.00%
Aggregate Equities And Margins To Total Liabilities And Equities And Margins [Member] | Minimum [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Secured debt covenant restriction during period		30.00%
Patronage Capital [Member]
Schedule Of Long Term And Short Term Debt Instruments [Line Items]
Secured debt covenant restriction at period end		5.00%

Debt (Schedule Of Long-Term Obl

Debt (Schedule Of Long-Term Obligations) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total long-term obligations	$ 473,024,497	$ 496,914,274
Less current installments	24,115,980	23,889,777
Long-term obligations, excluding current installments	448,908,517	473,024,497
CoBank Bond Variable Rate Maturing In 2022 [Member]
Debt Instrument [Line Items]
Total long-term obligations	$ 24,941,165	$ 27,414,275
Variable interest rate	2.77%	2.77%
Maturity year	2,022
Frequency of payment	interest payable monthly and principal due annually beginning in 2003
2011 Series A Bond Of 4.20% Maturing 2031 [Member]
Debt Instrument [Line Items]
Total long-term obligations	$ 72,000,000	$ 76,500,000
Bonds interest rate	4.20%	4.20%
Maturity year	2,031
Frequency of payment	interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012
2011 Series A Bond Of 4.75% Maturing 2041 [Member]
Debt Instrument [Line Items]
Total long-term obligations	$ 160,333,332	$ 166,499,999
Bonds interest rate	4.75%	4.75%
Maturity year	2,041
Frequency of payment	interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2012
2012 Series A Bond Of 4.01% Maturing 2032 [Member]
Debt Instrument [Line Items]
Total long-term obligations	$ 63,750,000	$ 67,500,000
Bonds interest rate	4.01%	4.01%
Maturity year	2,032
Frequency of payment	interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2013
2012 Series A Bond Of 4.41% Maturing 2042 [Member]
Debt Instrument [Line Items]
Total long-term obligations	$ 102,000,000	$ 109,000,000
Bonds interest rate	4.41%	4.41%
Maturity year	2,042
Frequency of payment	interest payable semi-annually March 15 and September 15 and principal due annually between 2013 and 2020 and between 2032 and 2042
2012 Series A Bond Of 4.78% Maturing 2042 [Member]
Debt Instrument [Line Items]
Total long-term obligations	$ 50,000,000	$ 50,000,000
Bonds interest rate	4.78%	4.78%
Maturity year	2,042
Frequency of payment	interest payable semi-annually March 15 and September 15 and principal due annually beginning in 2023

Debt (Schedule Of Maturities Of

Debt (Schedule Of Maturities Of Long-Term Obligations) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
2,016	$ 24,115,980
2,017	24,362,621
2,018	24,631,934
2,019	24,925,809
2,020	25,246,476
Thereafter	349,741,677
Total long-term obligations	473,024,497	$ 496,914,274
2011 Series A Bonds [Member]
Debt Instrument [Line Items]
2,016	10,666,667
2,017	10,666,667
2,018	10,666,667
2,019	10,666,667
2,020	10,666,667
Thereafter	178,999,997
Total long-term obligations	232,333,332
CoBank Bond Variable Rate Maturing In 2022 [Member]
Debt Instrument [Line Items]
2,016	2,699,313
2,017	2,945,954
2,018	3,215,267
2,019	3,509,142
2,020	3,829,809
Thereafter	8,741,680
Total long-term obligations	24,941,165	$ 27,414,275
2012 Series A Bonds [Member]
Debt Instrument [Line Items]
2,016	10,750,000
2,017	10,750,000
2,018	10,750,000
2,019	10,750,000
2,020	10,750,000
Thereafter	162,000,000
Total long-term obligations	$ 215,750,000

Debt (Schedule Of Monthly Avera

Debt (Schedule Of Monthly Average Commercial Paper Balances And Weighted Average Interest Rates) (Details) - Commercial Paper [Member] - USD ($) $ in Millions	1 Months Ended
	Dec. 31, 2015	Nov. 30, 2015	Oct. 31, 2015	Sep. 30, 2015	Aug. 31, 2015	Jul. 31, 2015	Jun. 30, 2015	May. 31, 2015	Apr. 30, 2015	Mar. 31, 2015	Feb. 28, 2015	Jan. 31, 2015
Short-term Debt [Line Items]
Average Balance	$ 21.4	$ 22.4	$ 24	$ 19.5	$ 12	$ 10.1	$ 12.1	$ 16	$ 23.8	$ 16	$ 11.6	$ 17.8
Weighted Average Interest Rate	0.49%	0.25%	0.25%	0.25%	0.25%	0.26%	0.31%	0.27%	0.28%	0.29%	0.22%	0.26%

Debt (Schedule Of Additional In

Debt (Schedule Of Additional Information Regarding Series A Bonds) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Carrying Value	$ 473,024,497	$ 496,914,274
2011 Series A Bond Of 4.20% Maturing 2031 [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2031
Average Life (Years)	10 years
Interest Rate	4.20%	4.20%
Issue Amount	$ 90,000,000
Carrying Value	$ 72,000,000	$ 76,500,000
2011 Series A Bond Of 4.75% Maturing 2041 [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2041
Average Life (Years)	15 years 6 months
Interest Rate	4.75%	4.75%
Issue Amount	$ 185,000,000
Carrying Value	$ 160,333,332	$ 166,499,999
2012 Series A Bond Of 4.01% Maturing 2032 [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2032
Average Life (Years)	10 years 8 months 12 days
Interest Rate	4.01%	4.01%
Issue Amount	$ 75,000,000
Carrying Value	$ 63,750,000	$ 67,500,000
2012 Series A Bond Of 4.41% Maturing 2042 [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2042
Average Life (Years)	15 years 8 months 12 days
Interest Rate	4.41%	4.41%
Issue Amount	$ 125,000,000
Carrying Value	$ 102,000,000	$ 109,000,000
2012 Series A Bond Of 4.78% Maturing 2042 [Member]
Debt Instrument [Line Items]
Maturing	Mar. 15, 2042
Average Life (Years)	20 years 8 months 12 days
Interest Rate	4.78%	4.78%
Issue Amount	$ 50,000,000
Carrying Value	50,000,000	$ 50,000,000
2011 And 2012 Series A Bonds [Member]
Debt Instrument [Line Items]
Issue Amount	525,000,000
Carrying Value	$ 448,083,000

Debt (Schedule Of Estimated Fai

Debt (Schedule Of Estimated Fair Value Of Long-Term Obligations) (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations, including current installments	$ 473,024,497	$ 496,914,274
Carrying Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations, including current installments	473,024,000
Fair Value [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term obligations, including current installments	$ 480,135,000

Employee Benefit Plans (Narrati

Employee Benefit Plans (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Deferred compensation	$ 763,913	$ 666,967	$ 536,546
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
Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	$ 6,700,000	6,800,000	6,800,000
Union Health and Welfare Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	4,500,000	4,500,000	4,100,000
Non-Union Health And Welfare Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	2,600,000	2,900,000	2,900,000
Money Purchase Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to benefit plan	$ 133,600	$ 149,200	$ 147,900

Employee Benefit Plans (Schedul

Employee Benefit Plans (Schedule Of Information Regarding Individually Significant Pension Plans) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Alaska Electrical Pension Plan [Member]
Multiemployer Plans [Line Items]
Employer Identification Number	[1]	926,005,171
Plan Number	[1]	1
Year-end Date	[1]	December 31
Expiration Date of CBA's	[1]	Jun. 30, 2017
Subject to Funding Improvement Plan	[1]	No
Surcharge Paid	[1]	NA
Zone Status	[1]	Green
Required minimum contributions	[1]	None
Contributions (in millions)	[1]	$ 3.1	$ 3.3	$ 3.4
Contributions > 5% of total plan contributions	[1]	Yes
NRECA Retirement Security Plan [Member]
Multiemployer Plans [Line Items]
Employer Identification Number	[1]	530,116,145
Plan Number	[1]	333
Year-end Date	[1]	December 31
Subject to Funding Improvement Plan	[1],[2]	No
Surcharge Paid	[1],[2]	NA
Zone Status	[1],[3]	NA
Required minimum contributions	[1]	N/A
Contributions (in millions)	[1]	$ 3.5	$ 3.5	$ 3.4
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.

Bradley Lake Hydroelectric Pr56

Bradley Lake Hydroelectric Project (Narrative) (Details)	12 Months Ended
	Dec. 31, 2015USD ($)MWhMW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Long-term Contract for Purchase of Electric Power [Line Items]
Bonds payable	$ 426,666,665	$ 448,083,332
Purchased power	$ 19,599,994	15,608,396	$ 27,836,680
Bradley Lake Hydroelectric Project [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Percentage share of power purchased	30.40%
Amount of committed purchased power | MW	27.4
Threshold percentage for increasing plant costs	25.00%
Estimated entitled additional energy output percentage	30.40%
Purchased power	$ 5,663,304	$ 5,228,907	$ 4,882,163
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	21,600,000
Possible annual expenditures upon default	$ 5,700,000
Maximum [Member] | Bradley Lake Hydroelectric Project [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Estimated increase in annual energy output | MWh	40,000

Bradley Lake Hydroelectric Pr57

Bradley Lake Hydroelectric Project (Schedule Of Bradley Lake Information) (Details) - USD ($)	3 Months Ended								6 Months Ended	12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Long-term Contract for Purchase of Electric Power [Line Items]
Plant in service	$ 1,128,474,292				$ 1,155,500,963					$ 1,128,474,292	$ 1,155,500,963
Long-term debt	473,024,497				496,914,274					473,024,497	496,914,274
Interest expense	$ 5,415,131	$ 5,428,774	$ 5,381,167	$ 5,589,373	$ 5,673,940	$ 5,622,892	$ 5,661,316	$ 5,842,558		$ 21,814,445	$ 22,800,706	$ 23,381,472
Bradley Lake Hydroelectric Project [Member] | Alaska Energy Authority [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Plant in service			167,235,000						$ 167,235,000
Long-term debt			62,585,000						62,585,000
Interest expense									3,668,000
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			50,839,000						50,839,000
Long-term debt			$ 19,026,000						19,026,000
Interest expense									$ 1,115,000

Eklutna Hydroelectric Project (

Eklutna Hydroelectric Project (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Jointly Owned Utility Plant Interests [Line Items]
Net utility plant	$ 674,876,440				$ 679,466,933				$ 674,876,440	$ 679,466,933
Net utility plant	674,876,440				679,466,933				674,876,440	679,466,933
Less accumulated depreciation	(469,199,226)				(497,601,371)				(469,199,226)	(497,601,371)
Accumulated depreciation	469,199,226				497,601,371				469,199,226	497,601,371
Total operating expenses	$ 42,182,178	$ 39,667,546	$ 43,490,558	$ 63,451,276	58,795,411	$ 61,712,934	$ 66,997,011	$ 65,467,523	$ 188,791,558	252,972,879	$ 278,738,497
Eklutna Hydroelectric Project [Member]
Jointly Owned Utility Plant Interests [Line Items]
Percentage ownership	30.00%								30.00%
Net utility plant	$ 4,401,440				4,442,440				$ 4,401,440	4,442,440
Net utility plant	4,401,440				4,442,440				4,401,440	4,442,440
Less accumulated depreciation	(2,203,659)				(2,017,032)				(2,203,659)	(2,017,032)
Accumulated depreciation	$ 2,203,659				$ 2,017,032				2,203,659	2,017,032
Total operating expenses									$ 689,501	$ 761,613	$ 730,122
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%

Commitments And Contingencies59

Commitments And Contingencies (Narrative) (Details) MMcf in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2015USD ($)MMcf	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)$ / kWhcontractitemMMcf	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 22, 2014Mcf
Other Commitments [Line Items]
Contingency accruals	$ 0								$ 0
Operating revenues	50,640,703	$ 43,109,512	$ 47,697,820	$ 74,973,117	$ 69,272,422	$ 65,677,900	$ 70,269,305	$ 76,098,886	$ 216,421,152	$ 281,318,513	$ 305,308,427
Percentage of met natural gas needs									100.00%
Percentage of power generated from gas									86.00%	87.00%	87.00%
Patronage capital payable	11,108,071				10,205,739				$ 11,108,071	$ 10,205,739
Regulatory initial cost charge per KWH | $ / kWh									0.000626
Regulatory current cost charge per KWH | $ / kWh									0.000732
Percentage of three year average of gross retail revenue to be spent on underground lines									2.00%
Average of gross revenue to determine expenditure for underground lines									3 years
Percentage of retail bill collected to move existing overhead lines underground									2.00%
Other current liabilities	8,076,903				4,594,865				$ 8,076,903	$ 4,594,865
Beluga Power Plant [Member]
Other Commitments [Line Items]
Percentage of power generated from gas									30.00%	57.00%	47.00%
Southcentral Power Project Plant [Member]
Other Commitments [Line Items]
Percentage of power generated from gas									61.00%	43.00%	31.00%
Cooper Lake Hydroelectric Project [Member]
Other Commitments [Line Items]
Duration of license agreement with FERC									50 years
Estimated cost to complete project at time of relicense									$ 12,000,000
Completed project cost									22,200,000
Grants awarded from state	9,300,000								$ 9,300,000
Matanuska Electric Association, Inc. [Member]
Other Commitments [Line Items]
Power contracts expiration date									Apr. 30, 2015
Operating revenues									$ 26,200,000	$ 70,700,000
Patronage capital payable	3,200,000				2,300,000				$ 3,200,000	2,300,000
Homer Electric Association, Inc. [Member]
Other Commitments [Line Items]
Power contracts expiration date									Dec. 31, 2013
Patronage capital payable	$ 7,900,000				7,900,000				$ 7,900,000	7,900,000
Homer Electric Association, Inc. And Matanuska Electric Association, Inc. [Member]
Other Commitments [Line Items]
Operating revenues											$ 103,100,000
ConocoPhillips (COP) [Member]
Other Commitments [Line Items]
Commencement date of long term contract for purchase of gas supply									Aug. 21, 2009
Expiration date of long term contract for purchase of gas supply									Dec. 31, 2016
Estimated amount of gas under contract | MMcf	60								60
Hilcorp Alaska, LLC [Member]
Other Commitments [Line Items]
Commencement date of long term contract for purchase of gas supply									Apr. 1, 2011
Expiration date of long term contract for purchase of gas supply									Mar. 31, 2023
Estimated amount of gas under contract | MMcf	49								49
Number of contract extensions | contract									2
GVEA Economy Energy Sales [Member]
Other Commitments [Line Items]
Operating revenues									$ 8,000,000	$ 36,900,000
Commencement date of long term contract for economy energy sales									Oct. 5, 2012
Expiration date of long term contract for economy energy sales									Mar. 31, 2015
Sales Revenue [Member] | Matanuska Electric Association, Inc. [Member]
Other Commitments [Line Items]
Customer percentage of sales revenue									13.00%	26.00%
Sales Revenue [Member] | Homer Electric Association, Inc. And Matanuska Electric Association, Inc. [Member]
Other Commitments [Line Items]
Customer percentage of sales revenue											35.00%
Moving Overhead Lines Underground [Member]
Other Commitments [Line Items]
Other current liabilities	$ 5,184,551				$ 2,761,921				$ 5,184,551	$ 2,761,921
Maximum [Member] | AIX Energy, LLC [Member]
Other Commitments [Line Items]
Estimated amount of gas under contract | Mcf												300,000
International Brotherhood of Electrical Workers [Member]
Other Commitments [Line Items]
Percentage of employees belonging to unions	70.00%								70.00%
Number of collective bargaining agreements | item									3
Expiration date of collective bargaining agreements									Jun. 30, 2017
Hotel Employees and Restaurant Employees [Member]
Other Commitments [Line Items]
Number of collective bargaining agreements | item									1
Expiration date of collective bargaining agreements									Jun. 30, 2016

Commitments And Contingencies60

Commitments And Contingencies (Schedule Of Cost Of Fuel Purchased And Transported As A Percentage Of Total Fuel Costs) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Hilcorp Alaska, LLC [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	30.30%	50.40%	46.40%
ConocoPhillips (COP) [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	58.70%	43.60%	42.80%
AIX Energy, LLC [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	4.70%	0.00%	0.00%
ENSTAR [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	3.30%	2.00%	2.10%
Harvest (Hilcorp) Pipeline [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	1.60%	3.00%	3.80%
Miscellaneous [Member]
Other Commitments [Line Items]
Cost of fuel purchased and transported as a percentage of total fuel costs	1.40%	1.00%	4.90%

Gain On Sale Of Asset (Details)

Gain On Sale Of Asset (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Gain On Sale Of Asset [Abstract]
Gain of sale of asset	$ 0	$ 0	$ 6,436,992

Subsequent Events (Details)

Subsequent Events (Details) $ in Millions	Feb. 04, 2016USD ($)a	Dec. 31, 2015USD ($)mi
Subsequent Event [Line Items]
Percentage of generation requirements met from natural gas		80.00%
Percentage of generation requirements met from hydroelectric		16.00%
Percentage of generation requirements met from wind		4.00%
Aurora Gas LLC [Member]
Subsequent Event [Line Items]
Expiration date of Gas Sale and Purchase Agreement		Sep. 30, 2016
AIX Energy, LLC [Member]
Subsequent Event [Line Items]
Expiration date of Gas Sale and Purchase Agreement		Feb. 29, 2016
Extension date of Gas Sale and Purchase Agreement		Mar. 31, 2024
Optional number of years of contract extension		5 years
Optional extension date of Gas Sale and Purchase Agreement		Mar. 31, 2029
Cook Inlet Energy LLC [Member]
Subsequent Event [Line Items]
Expiration date of Gas Sale and Purchase Agreement		Mar. 31, 2018
Optional number of years of contract extension		5 years
Optional extension date of Gas Sale and Purchase Agreement		Mar. 31, 2023
Beluga River Unit [Member]
Subsequent Event [Line Items]
Date of Purchase and Sale Agreement		Feb. 4, 2016
Working interest ownership percentage		10.00%
Period of on-going met gas generation requirements		18 years
Commencement year of on-going met gas generation requirements		2,016
Expiration year of on-going met gas generation requirements		2,033
Percentage of gas requirements provided		15.00%
Number of miles from Anchorage | mi		35
Minimum [Member] | Beluga River Unit [Member]
Subsequent Event [Line Items]
Effective annual cost savings		$ (2)
Maximum [Member] | Beluga River Unit [Member]
Subsequent Event [Line Items]
Effective annual cost savings		$ (3)
ConocoPhillips (COP) [Member] | ENSTAR [Member]
Subsequent Event [Line Items]
Expiration year of Gas Sale and Purchase Agreement		2,017
ConocoPhillips (COP) [Member] | Beluga River Unit [Member]
Subsequent Event [Line Items]
Working interest ownership percentage		33.30%
Municipal Light & Power [Member] | Beluga River Unit [Member]
Subsequent Event [Line Items]
Working interest ownership percentage		56.70%
Hilcorp Alaska, LLC [Member] | Beluga River Unit [Member]
Subsequent Event [Line Items]
Working interest ownership percentage		33.30%
Subsequent Event [Member] | Beluga River Unit [Member]
Subsequent Event [Line Items]
Working interest ownership percentage	30.00%
Total purchase price	$ 45.6
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
Subsequent Event [Member] | ConocoPhillips (COP) [Member] | Deep Oil Resources [Member]
Subsequent Event [Line Items]
Working interest ownership percentage	67.00%
Subsequent Event [Member] | Municipal Light & Power And Chugach [Member] | Beluga River Unit [Member]
Subsequent Event [Line Items]
Total purchase price	$ 152
Subsequent Event [Member] | Municipal Light & Power [Member] | Beluga River Unit [Member]
Subsequent Event [Line Items]
Working interest ownership percentage	70.00%

Quarterly Results Of Operatio63

Quarterly Results Of Operations (Details) - USD ($)	Oct. 16, 2014	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Results Of Operations [Abstract]
Operating revenues		$ 50,640,703	$ 43,109,512	$ 47,697,820	$ 74,973,117	$ 69,272,422	$ 65,677,900	$ 70,269,305	$ 76,098,886	$ 216,421,152	$ 281,318,513	$ 305,308,427
Operating expenses		42,182,178	39,667,546	43,490,558	63,451,276	58,795,411	61,712,934	66,997,011	65,467,523	188,791,558	252,972,879	278,738,497
Net interest		5,415,131	5,428,774	5,381,167	5,589,373	5,673,940	5,622,892	5,661,316	5,842,558	21,814,445	22,800,706	23,381,472
Net operating margins		3,043,394	(1,986,808)	(1,173,905)	5,932,468	4,803,071	(1,657,926)	(2,389,022)	4,788,805	5,815,149	5,544,928	3,188,458
Nonoperating margins		368,403	79,028	126,010	114,262	411,590	96,181	249,820	213,026	687,703	970,617	7,355,585
Assignable margins	$ (200,000)	$ 3,411,797	$ (1,907,780)	$ (1,047,895)	$ 6,046,730	$ 5,214,661	$ (1,561,745)	$ (2,139,202)	$ 5,001,831	$ 6,502,852	$ 6,515,545	$ 10,544,043