Tri-State Generation & Transmission Association 10-K 14 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
Entity Registrant Name	Tri-State Generation & Transmission Association, Inc.
Entity Central Index Key	1,637,880
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Public Float		$ 0
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2,015
Entity Common Stock, Shares Outstanding	0

Consolidated Statements of Fina

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Electric Plant
In service	$ 5,486,518	$ 5,193,236
Construction work in progress	216,279	206,097
Total electric plant	5,702,797	5,399,333
Less allowances for depreciation and amortization	(2,240,732)	(2,129,173)
Net electric plant	3,462,065	3,270,160
Other plant	227,957	210,694
Accumulated depreciation and depletion	(73,471)	(58,117)
Net other plant	154,486	152,577
Total property, plant and equipment	3,616,551	3,422,737
Other assets and investments
Investment in other associations	123,686	117,976
Investments in and advances to coal mines	16,221	15,016
Restricted cash and investments	1,000	39,376
Intangible assets	25,634	32,958
Other noncurrent assets	12,139	12,531
Total other assets and investments	178,680	217,857
Current assets
Cash and cash equivalents	144,587	92,468
Restricted cash and investments	9,530	9,784
Deposits and advances	21,673	22,224
Accounts receivable—Members	106,216	105,723
Other accounts receivable	14,270	25,693
Coal inventory	59,277	40,673
Materials and supplies	85,501	80,069
Total current assets	441,054	376,634
Deferred charges
Regulatory assets	415,081	426,043
Prepayment—NRECA Retirement and Security Plan	49,146	54,665
Other	122,535	156,200
Total deferred charges	586,762	636,908
Total assets	4,823,047	4,654,136
Capitalization
Patronage capital equity	952,082	908,669
Accumulated other comprehensive income (loss)	589	(828)
Noncontrolling interest	108,757	109,302
Total equity	1,061,428	1,017,143
Long-term debt	3,273,538	3,145,246
Total capitalization	4,334,966	4,162,389
Current liabilities
Member advances	9,403	14,576
Accounts payable	96,098	103,177
Accrued expenses	30,045	30,005
Accrued interest	34,332	32,517
Accrued property taxes	27,395	26,010
Current maturities of long‑term debt	91,419	92,802
Total current liabilities	288,692	299,087
Deferred credits and other liabilities
Regulatory liabilities	45,000	45,000
Deferred income tax liability	28,629	17,230
Intangible liabilities	6,221	9,424
Asset retirement obligation	55,215	53,754
Other	57,423	59,121
Total deferred credits and other liabilities	192,488	184,529
Accumulated postretirement benefit and postemployment obligations	6,901	8,131
Total equity and liabilities	$ 4,823,047	$ 4,654,136

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenues
Member electric sales	$ 1,125,699	$ 1,101,471	$ 1,091,103
Non-member electric sales	120,234	197,497	172,102
Other	89,515	96,123	77,958
Total revenues	1,335,448	1,395,091	1,341,163
Operating expenses
Purchased power	305,045	327,445	322,059
Fuel	231,537	293,033	287,647
Production	235,398	229,933	209,816
Transmission	153,443	145,396	138,684
General and administrative	24,708	28,591	24,325
Depreciation and amortization	152,718	128,712	121,818
Coal mining	36,130	40,849	29,889
Other	18,500	19,255	18,337
Operating expenses	1,157,479	1,213,214	1,152,575
Operating margins	177,969	181,877	188,588
Other income
Interest Income	4,355	11,076	17,288
Capital credits from cooperatives	9,189	8,684	10,922
Other income	3,981	3,573	3,344
Total other income	17,525	23,333	31,554
Interest expense, net of amounts capitalized	142,570	142,357	149,463
Income taxes	0	0	0
Net margins including noncontrolling interest	52,924	62,853	70,679
Net loss attributable to noncontrolling interest	489	1,383	2,233
Net margins attributable to the Association	$ 53,413	$ 64,236	$ 72,912

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Statements of Comprehensive Income
Net margins including noncontrolling interest	$ 52,924	$ 62,853	$ 70,679
Other comprehensive income (loss):
Unrealized loss on securities available for sale	(125)		278
Unrecognized actuarial loss on postretirement benefit obligation	1,528	(4,194)
Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net income	14	31	(358)
Other comprehensive income (loss)	1,417	(4,163)	(80)
Comprehensive income including noncontrolling interest	54,341	58,690	70,599
Net comprehensive loss attributable to noncontrolling interest	489	1,383	2,233
Comprehensive income attributable to the Association	$ 54,830	$ 60,073	$ 72,832

Consolidated Statement of Equit

Consolidated Statement of Equity - USD ($) $ in Thousands	Patronage capital	Accumulated other comprehensive income (loss)	Noncontrolling interest	Total
Equity at beginning of period at Dec. 31, 2012	$ 802,467	$ 3,415	$ 113,027
Change in Equity
Net margins attributable to the Association	72,912			$ 72,912
Retirement of patronage capital	(10,000)
Unrealized loss on securities available for sale		278
Reclassification adjustment for actuarial (gain)/loss on postretirement benefit obligation included in net income		(358)
Net loss attributable to noncontrolling interest			(2,233)	(2,233)
Equity distribution to noncontrolling interest			(54)
Equity at end of period at Dec. 31, 2013	865,379	3,335	110,740	979,454
Change in Equity
Net margins attributable to the Association	64,236			64,236
Retirement of patronage capital	(20,946)
Unrecognized actuarial loss on postretirement benefit obligation		(4,194)
Reclassification adjustment for actuarial (gain)/loss on postretirement benefit obligation included in net income		31
Net loss attributable to noncontrolling interest			(1,383)	(1,383)
Equity distribution to noncontrolling interest			(55)
Equity at end of period at Dec. 31, 2014	908,669	(828)	109,302	1,017,143
Change in Equity
Net margins attributable to the Association	53,413			53,413
Retirement of patronage capital	(10,000)
Unrealized loss on securities available for sale		(125)
Unrecognized actuarial loss on postretirement benefit obligation		1,528
Reclassification adjustment for actuarial (gain)/loss on postretirement benefit obligation included in net income		14
Net loss attributable to noncontrolling interest			(489)	(489)
Equity distribution to noncontrolling interest			(56)
Equity at end of period at Dec. 31, 2015	$ 952,082	$ 589	$ 108,757	$ 1,061,428

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities
Net margins including noncontrolling interest	$ 52,924	$ 62,853	$ 70,679
Adjustments to reconcile net margins to net cash used in operating activities:
Depreciation and amortization	152,718	126,693	118,776
Amortization of intangible asset	7,324	7,324	7,324
Amortization of NRECA Retirement and Security Plan prepayment	5,520	5,519	5,457
Amortization of debt issuance costs	1,870	1,356	897
Capital credit allocations from cooperatives and income from coal mines over refund distributions	(7,179)	(6,465)	(7,053)
Prepayment—NRECA Retirement and Security Plan			(71,160)
Recognition of deferred revenue		(20,000)
Change in restricted cash and investments	29,113		(390)
Changes in operating assets and liabilities:
Accounts receivable	10,936	(6,460)	7,000
Coal inventory	(18,604)	3,057	17,524
Materials and supplies	(5,432)	(4,593)	(4,119)
Accounts payable and accrued expenses	(12,188)	(5,923)	13,090
Accrued interest	1,814	7,909	(1,061)
Accrued property taxes	1,385	2,507	(189)
Other deferred credits - BNSF settlement	(29,381)
Other	21,324	13,076	(5,089)
Net cash provided by operating activities	212,144	186,853	151,686
Investing activities
Purchases of plant	(290,428)	(221,613)	(212,703)
Changes in deferred charges	9,031	(8,263)	(1,849)
Proceeds from other investments	321	15,270	1,578
Net cash used in investing activities	(281,076)	(214,606)	(212,974)
Financing activities
Member advances	(7,041)	2,227	(2,129)
Payments of long-term debt	(113,063)	(1,739,835)	(196,490)
Proceeds from issuance of debt	240,183	1,674,977	258,873
Debt refinancing transaction costs		(184,073)
Decrease in advance payments to RUS		137,727	130,257
Retirement of patronage capital	(8,286)	(20,582)	(10,711)
Proceeds from investment in securities pledged as collateral	8,931	8,723	8,410
Change in restricted cash and investments	327	48,000	(15,357)
Net cash provided by (used in) financing activities	121,051	(72,836)	172,853
Net decrease in cash and cash equivalents	52,119	(100,589)	111,565
Cash and cash equivalents - beginning	92,468	193,057	81,492
Cash and cash equivalents - end	144,587	92,468	193,057
Supplemental cash flow information:
Cash paid for interest	154,657	152,344	166,828
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	2,173	$ (4,691)	$ 5,276
Renewal of transmission right of way easements	$ 27,447

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES B ASIS OF CONSOLIDATION: Our consolidated financial statements include the accounts of the Association, our wholly ‑owned and majority ‑owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 11—Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. All significant intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) as applied to regulated enterprises. JOINTLY OWNED FACILITIES: We own undivided interests in three jointly owned generation facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common. These projects include the Craig Station Units 1 and 2 (operated by us (“Yampa Project”)), the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)) and the San Juan Project (operated by Public Service Company of New Mexico). Each participant in these agreements receives a portion of the total output of the generation facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and operating expenses is included in our consolidated financial statements. VARIABLE INTEREST ENTITIES: We evaluate our arrangements and relationships with other entities, including our investments in other associations and investments in coal mines, in accordance with the accounting standard related to consolidation of variable interest entities. This guidance requires us to identify variable interests (contractual, ownership or other financial interests) in other entities and whether any of those entities in which we have a variable interest in, meets the criteria of a variable interest entity. An entity is considered to be a variable interest entity when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. In making this assessment, we consider the potential that our arrangements and relationships with other entities provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of an entity, the ability to directly or indirectly make decisions about the entity’s activities and other factors. If an entity that we have a variable interest in meets the criteria of a variable interest entity, we must determine whether we are the primary beneficiary of that entity. The primary beneficiary is the entity that has the power to direct any of the activities of the variable interest entity that most significantly impact the variable interest entity’s economic performance, and the obligation to absorb losses or the right to receive benefits from the variable interest entity that could be potentially significant to the variable interest entity. If we are determined to be the primary beneficiary of (has controlling financial interest in) a variable interest entity, then we would be required to consolidate that entity. In certain situations, it may be determined that power is shared among multiple unrelated parties such that no one party has the power to direct the activities of a variable interest entity that most significantly impact the variable interest entity’s economic performance (decisions about those activities require the consent of each of the parties sharing power). In accordance with the accounting guidance prescribed by consolidation of variable interest entities, if the determination is made that power is shared among multiple unrelated parties, then no party is the primary beneficiary. See Note 11—Variable Interest Entities. ACCOUNTING FOR RATE REGULATION: We are subject to the accounting requirements related to regulated operations. In accordance with these accounting requirements, some revenues and expenses have been deferred at the discretion of our Board, which has budgetary and rate ‑setting authority, if it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs we expect to recover from our Members based on rates approved by our Board in accordance with our rate policy. Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to our Members based on rates approved by our Board in accordance with our rate policy. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses concurrent with their recovery in rates. Regulatory assets and liabilities are as follows (thousands): 2015 2014 Regulatory assets Deferred income tax expense (1) $ $ Deferred prepaid lease expense- Craig 3 Lease (2) Deferred prepaid lease expense- Springerville 3 Lease (3) Goodwill – J.M. Shafer (4) Goodwill – Colowyo Coal (5) Deferred debt prepayment transaction costs (6) Other — Regulatory liabilities Deferred revenues (7) Net regulatory asset $ $ (1) A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. (2) Deferral of loss on acquisition related to the Craig Generating Station (“Craig Station”) Unit 3 prepaid lease expense upon acquisitions of equity interests in 2002 and 2006. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $6.5 million annually through the remaining original life of the lease ending in 2018 and recovered from our Members in rates. (3) Deferral of loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $2.3 million annually through the 47 -year period ending in 2056 and recovered from our Members in rates. (4) Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP (“TCP”) in December 2011. Goodwill is being amortized to depreciation and amortization expense in the amount of $2.8 million annually through the 25 -year period ending in 2036 and recovered from our Members in rates. (5) Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation and amortization expense through the 44 -year period ending in 2056 and recovered from our Members in rates. (6) Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation and amortization expense in the amount of $8.6 million annually over the 21.4 -year average life of the new debt issued and recovered from our Members in rates. (7) Represents deferral of the recognition of $10 million of non-member electric sales revenue received in 2008 and $35 million of non-member electric sales revenue in 2011. These deferred non-member electric sales revenues will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods. SEGMENT REPORTING: We are organized for the purpose of supplying wholesale power to our Members and do so through the utilization of a portfolio of resources, including generating facilities, long ‑term purchase contracts and forward, short ‑term and spot market energy purchases. In support of our coal generating resources, we have direct ownership and investments in coal mines. Our Board serves as our chief operating decision maker who manages and reviews our operating results and allocates resources as one operating segment. Therefore, we have one reportable segment for financial reporting purposes. BUSINESS COMBINATIONS: We account for business acquisitions by applying the accounting standard related to business combinations. In accordance with this method, the identifiable assets acquired, the liabilities assumed and any noncontrolling interests in the acquired entities are required to be recognized at their acquisition date fair values. We typically engage an independent valuation firm to determine the acquisition date fair values of most of the acquired assets and assumed liabilities. The excess of total consideration transferred over the net assets acquired is recognized as goodwill. Acquisition ‑related costs such as legal fees, accounting services fees and valuation fees, are expensed as incurred. We are required to consolidate these acquired entities. If an acquisition does not result in acquiring a business, the transaction is accounted for as an acquisition of assets. This method requires measurement and recognition of the acquired net assets based upon the amount of cash transferred and the amount paid for acquisition ‑related costs. There is no goodwill recognized in an acquisition of assets. USE OF ESTIMATES: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. ELECTRIC PLANT AND DEPRECIATION: Electric plant is stated at cost. The cost of internally constructed assets includes payroll, overhead costs and interest charged during construction. Interest rates charged during construction of 4.4 , 4.7 and 4.8 percent were used for 2015 , 2014 and 2013 , respectively. The amount of interest capitalized during construction was $13.5 , $ 15.0 and $ 13.0 million during 2015 , 2014 and 2013 , respectively. At the time that units of electric plant are retired, original cost and cost of removal, net of the salvage value, are charged to the allowance for depreciation. Replacements of electric plant that involve less than a designated unit value are charged to maintenance expense when incurred. Electric plant is depreciated based upon estimated depreciation rates and useful lives that are periodically re ‑evaluated. COAL RESERVES AND DEPLETION: Coal reserves are recorded at cost. Depletion of coal reserves is computed using the units ‑of ‑production method utilizing only proven and probable reserves. LEASES: The accounting for lease transactions in conformity with GAAP requires management to make various assumptions, including the discount rate, the fair market value of the leased assets and the estimated useful life, in order to determine whether a lease should be classified as operating or capital. We are the lessor under power sales arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey the right to use our power generating equipment for a stated period of time. The lease revenues from these arrangements are included in other operating revenue on the consolidated statements of operations. We are the lessee under power purchase arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey to us the right to use power generating equipment for a stated period of time. These are included in other operating expenses on the consolidated statements of operations. See Note 8—Leases. INVESTMENTS IN OTHER ASSOCIATIONS: Investments in other associations includes investments in the patronage capital of other cooperatives (accounted for using the cost method) and other required investments in the organizations. Under this method, our investment in a cooperative increases when a cooperative allocates patronage capital credits to us and it decreases when we receive a cash retirement of the allocated capital credits from the cooperative. A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative. Investments in other associations are as follows (thousands): 2015 2014 Basin Electric Power Cooperative $ $ National Rural Utilities Cooperative Finance Corporation CoBank, ACB Western Fuels Association, Inc. Other Investments in other associations $ $ INVESTMENTS IN AND ADVANCES TO COAL MINES: We have direct ownership and investments in coal mines to support our coal generating resources. We, and certain participants in the Yampa Project, are members of Trapper Mining, Inc. (“Trapper Mining”), which is organized as a cooperative and is the owner and operator of the Trapper Mine near Craig, Colorado. Our investment in Trapper Mining is recorded using the equity method. In addition, we have ownership in Western Fuels Association, Inc. (“WFA”), which is the owner of Western Fuels ‑Wyoming, Inc. (“WFW”), the owner and operator of the Dry Fork Mine near Gillette, Wyoming. We, through our ownership in WFA, advance funds to the Dry Fork Mine. Investments in and advances to coal mines are as follows (thousands): 2015 2014 Investment in Trapper Mine $ $ Advances to Dry Fork Mine Investments in and advances to coal mines $ $ CASH AND CASH EQUIVALENTS: We consider highly liquid investments with an original maturity of three months or less to be cash equivalents. RESTRICTED CASH AND INVESTMENTS: Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds is for the payment of debt within one year and funds restricted by contract that are expected to be settled within one year. These funds are therefore classified as current on the statements of financial position. The other funds are for the payment of debt beyond one year and funds restricted by contract or other legal reasons that are expected to be settled beyond one year. These funds are classified as noncurrent and are included in other assets and investments on the statements of financial position. We have investments in U.S. Treasury Notes pledged as collateral in connection with the in ‑substance defeasance for the principal outstanding and future interest payments on the Coal Contract Receivable Collateralized Bonds (“Colowyo Bonds”). The balances in these investments are described as investments in securities pledged as collateral in the table below. As of December 31, 2015 , the entire $8.7 million balance of the defeasance investment is for Colowyo Bond debt payments due within one year and is, therefore, a current asset on the consolidated statements of financial position. The Colowyo Bonds mature in November 2016. We received $29.4 million in 2009 from BNSF Railway Company (“BNSF”) as a reduction of prior coal delivery shipping charges as the result of the decision of the Surface Transportation Board (“STB”). However, BNSF appealed the decision and the funds were subject to refund in the event BNSF was ultimately successful in its appeal. These funds were designated by our Board to be held as restricted cash. In May 2015, BNSF, WFA and Basin filed a joint petition at the STB informing the STB that the parties had entered into a rail transportation agreement settling all matters at issue. In June 2015, the STB granted the joint petition, which resolved the uncertainties related to the outcome of this matter and the $29.4 million of cash related to the BNSF settlement was no longer designated as restricted. Restricted cash and investments are as follows (thousands): 2015 2014 Investments in securities pledged as collateral $ $ Funds restricted by contract Restricted cash and investments - current BNSF settlement — Funds restricted by contract Investments in securities pledged as collateral — Restricted cash and investments - noncurrent Total restricted cash and investments $ $ MARKETABLE SECURITIES: We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are classified as available ‑for ‑sale securities. At December 31, 2015 , the cost and estimated fair value of the investments based upon their active market value (Level 1 inputs) were $1.0 and $1.2 million, respectively, with a net unrealized gain balance of $129,000 . At December 31, 2014 , the cost and estimated fair value of the investments were $1.1 and $1.4 million, respectively, with a net unrealized gain balance of $254,000 . The estimated fair value of the investments is included in other noncurrent assets on the consolidated statements of financial position. The unrealized gains at December 31, 2015 and 2014 are reported as a component of accumulated other comprehensive income as of those dates. Changes in the net unrealized gains or losses are reported as a component of comprehensive income. We hold U.S. Treasury Notes to maturity in connection with the December 2011 defeasance of the Colowyo Bonds and these are included in restricted cash and investments on the statements of financial position. Since they will be held to maturity, the notes are carried at amortized cost. As of December 31, 2015 , the defeasance investment of $8.7 million consisted of a principal amount of $7.4 million, an unamortized premium of $113,000 and cash of $1.1 million. As of December 31, 2014 , the defeasance investment of $18.2 million consisted of a principal amount of $16.4 million, an unamortized premium of $371,000 and cash of $1.4 million. INVENTORIES: Coal inventories at our owned generating stations are stated at LIFO (last ‑in, first ‑out) cost and were $42.2 and $22.2 million at December 31, 2015 and 2014 , respectively. The remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost. In 2014, we realized lower coal fuel expense of $596,000 as a result of a LIFO inventory liquidation at our generating stations. OTHER DEFERRED CHARGES: We make expenditures for preliminary surveys and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the preliminary survey and investigation expenditures will be reclassified to electric plant—construction work in progress. If the work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating expense account or the expense could be deferred as a regulatory asset to be recovered from our Members in rates subject to approval by our Board, which has budgetary and rate-setting authority. As of December 31, 2015 , preliminary surveys and investigations was primarily comprised of expenditures for the Holcomb Station Project of $86.7 million (see Note 12—Commitments and Contingencies—Legal). In December 2015, $28.5 million of preliminary survey charges related to the Eastern Plains Transmission Project was capitalized as part of the Burlington-Wray 230kV transmission line project and is included in electric plant-construction work in progress on the consolidated statements of financial position. We make advance payments to the operating agents of jointly owned facilities. See Note 3—Property, Plant and Equipment—Jointly Owned Facilities. Other deferred charges are as follows (thousands): 2015 2014 Preliminary surveys and investigations $ $ Advances to operating agents of jointly owned facilities Other Total other deferred charges $ $ DEBT ISSUANCE COSTS: We adopted Accounting Standards Update (“ASU”) 2015-03, Interest — Imputation of Interest (Subtopic 835-30) and ASU 2015-15, Interest – Imputation of Interest (Subtopic 835-30) Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. Accordingly, we accounted for debt issuance costs as a direct deduction of the associated long-term debt carrying amount consistent with the accounting for debt discounts and premiums. Deferred debt issuance costs are amortized to interest expense using an effective interest method over the life of the respective debt. The adoption of these amendments resulted in $21.2 million and $22.3 million of debt issuance costs being presented as a direct deduction from long-term debt as of December 31, 2015 and 2014. The $22.3 million of debt issuance costs as of December 31, 2014 were retrospectively adjusted as a change in accounting principle and were previously reported in other deferred charges . ASSET RETIREMENT OBLIGATIONS: We account for current obligations associated with the future retirement of tangible long ‑lived assets in accordance with the accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations associated with the retirement of long ‑lived assets be recognized at fair value at the time the liability is incurred and capitalized as part of the related long ‑lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense and the capitalized cost of the long ‑lived asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. In the absence of quoted market prices, we determine fair value by using present value techniques in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk ‑free rate including a market risk premium. Upon settlement of an asset retirement obligation, we will apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability. These liabilities are included in asset retirement obligations. Coal mines: We have asset retirement obligations for the final reclamation costs and post ‑reclamation monitoring related to the Colowyo Mine, the New Horizon Mine, and the Fort Union Mine. Fossil steam generation: We, including our undivided interest in jointly owned facilities, have asset retirement obligations related to equipment, dams, ponds, wells and underground storage tanks at the fossil steam generating stations. Transmission: We have an asset retirement obligation to remove a certain transmission line and related substation assets resulting from an agreement to relocate the line. Aggregate carrying amounts of asset retirement obligations are as follows (thousands): 2015 2014 Asset retirement obligation at beginning of year $ $ Liabilities incurred Liabilities settled Accretion expense Change in cash flow estimate Asset retirement obligation at end of year $ $ We also have asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations attached to transmission and other easements that are considered by us to be operated in perpetuity and therefore the measurement of the obligation is not possible. A liability will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates as is needed to employ a present value technique to estimate far value. MEMBERSHIPS: There are 44 $5 memberships outstanding at December 31, 2015 and 2014 . PATRONAGE CAPITAL: Our net margins are treated as advances of capital by our Members and are allocated to our Members on the basis of their electricity purchases from us. Net losses, should they occur, are not allocated to Members, but are offset by future margins. Margins not distributed to Members constitute patronage capital. Patronage capital is held for the account of our Members and is distributed through patronage capital retirements when our Board deems it appropriate to do so, subject to debt instrument restrictions. ELECTRIC SALES REVENUE: Revenue from electric energy deliveries is recognized when delivered. ACCOUNTS RECEIVABLE—MEMBERS AND OTHER: Receivables are primarily related to electric sales to Members and electric sales and other transactions with electric utilities. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period determined to be uncollectible. OTHER OPERATING REVENUE: Other operating revenue consists primarily of wheeling revenue, lease revenue, coal sales and revenue from supplying steam and water to a paper manufacturer located adjacent to the Escalante Generating Station. Wheeling revenue is received when we charge other energy companies for transmitting electricity over our transmission lines. The lease revenue is primarily from certain power sales arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey to others the right to use power generating equipment for a stated period of time. Coal sales revenue results from the sale of a portion of the coal from the Colowyo Mine per a contract ending in 2017 to other joint owners in the Yampa Project (the “Yampa Participants”). The associated Colowyo Mine expenses are included in coal mining, depreciation and amortization and interest expense on the consolidated statements of operations. INCOME TAXES: We are a non ‑exempt cooperative subject to federal and state taxation and, as a cooperative, are allowed a tax exclusion for margins allocated as patronage capital. The liability method of accounting for income taxes is utilized, whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. INTERCHANGE POWER: We occasionally engage in interchanges, or non ‑cash swapping, of energy. Based on the assumption that all energy interchanged will eventually be received or delivered in ‑kind, interchanged energy is generally valued at the average cost of fuel to generate power. Additionally, portions of the energy interchanged are valued per contract with the utility involved in the interchange. When we are in a net energy advance position, the advanced energy balance is recorded as an asset. If we owe energy, the net energy balance owed to others is recorded as a liability. The net activity for the year is included in purchased power expense. The interchange liability balance of $1.6 and $1.5 million at December 31, 2015 and 2014 , respectively, is included in accounts payable. The net interchange activity recorded in purchased power expense was $108,630 , $(452,500) and $2.6 million in 2015 , 2014 and 2013 , respectively. EVALUATION OF SUBSEQUENT EVENTS: We evaluated subsequent events through March 14, 2016, which is the date when the financial statements were issued. NEW ACCOUNTING PRONOUNCEMENTS: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . In July 2015, FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date . ASU 2014-09 replaces current revenue guidance, which was based on a risks and rewards model, with a transfer of control model. The core principle under the new transfer of control model states that revenue should be recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve the core principle, this amendment requires the following steps: (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This amendment also requires additional quantitative and qualitative disclosures sufficient enough to enable users of financial information to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, this amendment is effective for the fiscal year beginning January 1, 2018 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes footnote disclosures). Reporting entities have the option to adopt the standard as early as the original January 1, 2017 effective date of this amendment. We are currently evaluating the impact of this amendment on our financial position and results of operations. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements Going Concern (Subtopic 205-40); Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendment in this ASU requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern, which is currently performed by the external auditors. Management will be required to perform this assessment for both interim and annual reporting periods and must make certain disclosures if it concludes that substantial doubt exists. Substantial doubt about an entity’s ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meets its obligations as they become due within one year after the date that that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). The amendment is effective for annual periods, and interim periods within those annual periods, beginning on or after December 15, 2016. We are currently evaluating the impact of this amendment on our financial position and results of operations. The adoption of this update is not expected to have a material impact on the financial position or results of operations. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810), Amendments to the Consolidation Analysis . The amendments in this ASU affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Specifically, ASU 2015-02: (1) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (2) eliminates the presumption that a general partner should consolidate a limited partnership, and (3) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. The amendment is effective for the fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. A reporting entity may apply the amendments in this ASU using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. A reporting entity also may apply the amendments retrospectively. We adopted this update in 2015 and it did not have a material impact on our financial position or results of operations. In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740); Balance Sheet Classification of Deferred Taxes. The amendments in this ASU simplify the presentation of deferred income taxes. Deferred tax assets

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2015
PROPERTY, PLANT AND EQUIPMENT
PROPERTY, PLANT AND EQUIPMENT	NOTE 3—PROPERTY, PLANT AND EQUIPMENT Our property, plant and equipment consist of electric plant and other plant. Both of these are discussed below and are included on the consolidated statements of financial position. ELECTRIC PLANT: Our investment in electric plant and the related annual rates of depreciation or amortization calculated using the straight ‑line method are as follows (thousands): Annual Depreciation Rate 2015 2014 Generation plant % to % $ $ Transmission plant % to % General plant % to % Other % to % Electric plant in service (at cost) Construction work in progress Less allowances for depreciation and amortization Electric plant $ $ At December 31, 2015 , we had $82.8 million of commitments to complete construction projects, of which approximately $63.6 , $14.3 and $4.9 million are expected to be incurred in 2016, 2017 and 2018, respectively. JOINTLY OWNED FACILITIES: Our share in each jointly owned facility is as follows as of December 31, 2015 (these electric plant in service, accumulated depreciation and construction work in progress amounts are included in the electric plant table above) (thousands): Electric Construction Tri-State Plant in Accumulated Work In Share Service Depreciation Progress Yampa Project - Craig Station Units 1 and 2 % $ $ $ MBPP - Laramie River Station % San Juan Project – San Juan Unit 3 % Total $ $ $ OTHER PLANT: Other plant consists of mine assets (discussed below) and non ‑utility assets (which consist of piping and equipment specifically related to providing steam and water from the Escalante Generating Station to a third party for the use in the production of paper). We own 100 percent of Western Fuels ‑Colorado (“WFC”), a limited liability company organized for the purpose of acquiring coal reserves and supplying coal to us, which is the owner and operator of the New Horizon Mine near Nucla, Colorado. WFC also owns Colowyo Coal, which is the owner and operator of the Colowyo Mine, a large surface coal mine near Craig, Colorado. We also own a 50 percent undivided ownership in the land and the rights to mine the property known as Fort Union Mine. Our share of the coal provided from these mines is primarily used by us for generation at our generating facilities. The expenses related to this coal used by us are included in fuel expense on the consolidated statements of operations. Other plant assets are as follows (thousands): 2015 2014 Colowyo Mine assets $ $ New Horizon Mine assets Fort Union Mine assets Accumulated depreciation and depletion Net mine assets Non-utility assets Accumulated depreciation Net non-utility assets Net other plant $ $

INTANGIBLES

INTANGIBLES	12 Months Ended
	Dec. 31, 2015
INTANGIBLES
INTANGIBLES	NOTE 4—INTANGIBLES INTANGIBLE ASSETS: The December 2011 acquisition of TCP resulted in recording an intangible asset in the amount of $55.5 million relating to a contractual obligation that TCP has to a third party under a purchase power agreement (the “PPA”). The $55.5 million intangible asset represents the amount that the PPA contract terms were above market value at the acquisition date and is being amortized on a straight ‑line basis over the remaining life of the PPA through June 30, 2019. The straight ‑line method is consistent with the terms of the PPA as this contract is for a fixed amount of capacity at a fixed capacity rate that stays constant over the term of the contract. The amortization of the PPA intangible asset is accounted for as a reduction of the revenue generated by the PPA and is included in other operating revenue. The amortization was $7.3 million in each of the years 2015 , 2014 and 2013 and will be recognized over each of the next four years as follows (thousands): 2016 $ 2017 2018 2019 $ INTANGIBLE LIABILITIES: The December 2011 acquisition of Colowyo Coal resulted in recording an intangible liability of $18.0 million relating to a contractual obligation that Colowyo Coal has to sell coal to the Yampa Participants through 2017. The $18.0 million intangible liability represents the amount that the coal sale contract terms were below market at the acquisition date and is being amortized based upon the contracted tonnage with the Yampa Participants over the remaining life of the coal contract ending December 31, 2017. The intangible liability balance of $6.2 and $9.4 million as of December 31, 2015 and 2014 , respectively, is included in intangible liabilities. The amortization of the Colowyo Coal intangible liability is accounted for as an increase in other operating revenue. An amortization benefit of $3.2 , $3.2 and $2.5 million was recognized in 2015 , 2014 and 2013 , respectively, and the recognition of the benefit over the next two years is estimated to be as follows (thousands): 2016 $ 2017 $

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2015
LONG-TERM DEBT
LONG-TERM DEBT	NOTE 5 – LONG-TERM DEBT The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement except for two unsecured notes in the aggregate amount of $55.9 million as of December 31, 2015. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. The Colowyo Bonds are secured by funds deposited with the trustee as part of the in-substance defeasance and an unconditional guarantee by us. All long-term debt contains certain restrictive financial covenants, including a DSR requirement and ECR requirement. Long-term debt consists of the following (thousands): 2015 2014 Mortgage notes payable 3.66% to 8.08% CFC, 5.96% average for 2015, due through 2028 $ $ 2.63% to 6.17% CoBank, ACB, 4.35% average for 2015, due through 2042 First Mortgage Bonds, Series 2014E-1, 3.70% due 2024 First Mortgage Bonds, Series 2014E-2, 4.70% due 2044 First Mortgage Bonds, Series 2010A, 6.00% due 2040 First Mortgage Obligation, Series 2014B, Tranche 1, 3.90%, due through 2033 First Mortgage Obligation Series 2014B, Tranche 2, 4.30%, due through 2039 First Mortgage Obligation Series 2014B, Tranche 3, 4.45%, due through 2045 First Mortgage Obligation, Series 2009C, Tranche 1, 6.00%, due through 2019 First Mortgage Obligation, Series 2009C, Tranche 2, 6.31%, due through 2021 Variable rate CFC, as determined by CFC, 2.90% average for 2015, due through 2026 Variable rate CFC, LIBOR-based term loan, 1.48% average for 2015, due through 2049 Variable rate CoBank, ACB, LIBOR-based term loan, 1.74% average for 2015, due through 2044 Variable rate, Revolving Credit Agreement, LIBOR-based revolving credit, 1.25% average for 2015, due through 2019 Pollution control revenue bonds City of Gallup, NM, 5.00%, Series 2005, due through 2017 Moffat County, CO Variable Rate Demand Series 2009, 0.06% average for 2015, due 2036 Springerville certificates Series A, 6.04%, due through 2018 Series B, 7.14%, due through 2033 Colowyo Coal Colowyo Bonds, 10.19%, due through 2016 Other Total debt $ $ Less debt issuance costs Less debt discounts Plus debt premiums Total debt adjusted for discounts, premiums and debt issuance costs $ $ Less current maturities Long-term debt $ $ On October 30, 2014, we issued the First Mortgage Bonds, Series 2014 E-1 and E-2 (“Series 2014 Bonds”) in an aggregate amount of $500 million. In connection with the Series 2014 Bonds, we entered into a registration rights agreement. On July 30, 2015, we commenced an offer to exchange the $500 million aggregate principal amount of the Series 2014 Bonds. The exchange offer satisfied our obligations under the registration rights agreement. The exchange offer did not represent a new financing transaction and there were no proceeds to us when the exchange offer was completed in September 2015. We have a secured revolving credit facility with Bank of America, N.A.(“Bank of America”) and CoBank, ACB as Joint Lead Arrangers in the amount of $750 million (“Revolving Credit Agreement”). We had outstanding borrowings of $271 million and $50 million at December 31, 2015 and December 31, 2014, respectively. There is a 364-day, direct pay letter of credit issued under the Revolving Credit Agreement and provided by Bank of America, N.A. for the $46.8 million Moffat County, CO, Variable Rate Demand Pollution Control Revenue Refunding Bonds, Series 2009. In November 2015, the letter of credit from Bank of America was extended for an additional 364 days to mature in January 2017. As of December 31, 2015, the availability under the Revolving Credit Agreement was $431 million. Annual maturities of total debt adjusted for debt issuance costs, discounts and premiums at December 31, 2015 are as follows (thousands): 2016 $ 2017 2018 2019 (1) 2020 Thereafter $ (1) Annual maturities in 2019 include $271 million of outstanding borrowings under the Revolving Credit Agreement.

FAIR VALUE

FAIR VALUE	12 Months Ended
	Dec. 31, 2015
FAIR VALUE
FAIR VALUE	NOTE 6—FAIR VALUE Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market, or in the most advantageous market when no principal market exists. The fair value measurements accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows: Level 1 inputs utilize observable market data in active markets for identical assets or liabilities. Level 2 inputs consist of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 inputs consist of unobservable market data which is typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Marketable Securities We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are classified as available-for-sale and are measured at fair value on a recurring basis. The estimated fair value of the investments is included in other noncurrent assets on our consolidated statements of financial position. The unrealized gains are reported as a component of accumulated other comprehensive income. Changes in the net unrealized gains or losses are reported as a component of comprehensive income. The carrying amounts and fair values of our marketable securities are as follows (thousands): As of December 31, 2015 As of December 31, 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Marketable securities $ $ $ $ The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The unrealized gains at December 31, 2015 and December 31, 2014 are reported as a component of accumulated other comprehensive income as of those dates. Changes in the net unrealized gains or losses are reported as a component of comprehensive income. Debt The fair values of debt were estimated using discounted cash flow analyses based on our current incremental borrowing rates for similar types of borrowing arrangements. These valuation assumptions utilize observable inputs based on market data obtained from independent sources and are therefore considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market corroborated inputs). The carrying amounts and fair values of our debt are as follows (thousands): 2015 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Total debt $ $ $ $

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2015
INCOME TAXES
INCOME TAXES	NOTE 7 – INCOME TAXES We had no income tax expense or benefit in 2015 , 2014 and 2013 . The liability method of accounting for income taxes is utilized, whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. Under the liability method, deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and for income tax purposes. Components of our net deferred tax liability are as follows (thousands): 2015 2014 Deferred tax assets Safe harbor lease receivables $ $ Net operating loss carryforwards Alternative minimum tax credit carryforwards Deferred revenues Colowyo Coal- coal contract intangible liability Other Deferred tax liabilities Basis differences- property, plant and equipment Capital credits from other associations Deferred debt prepayment transaction costs Other — Net deferred tax liability $ $ The $11.4 million increase in the net deferred tax liability from $17.2 million at December 31, 2014 to $28.6 million at December 31, 2015 is not recognized as a tax expense in 2015 due to our regulatory accounting treatment of deferred taxes. Instead, the tax expense is deferred and reflected as an increase in the regulatory asset established for deferred income tax expense. The accounting for regulatory assets is discussed further in Note 2—Accounting for Rate Regulation. The regulatory asset account for deferred income tax expense has a balance of $28.6 million and $17.2 million at December 31, 2015 and 2014 , respectively. The reconciliation between the statutory federal income tax rate and the effective tax rate is as follows: 2015 2014 2013 Federal income tax expense at statutory rate % % % State income tax expense, net of federal benefit Patronage exclusion Asset retirement obligations Postretirement medical actuarial gains and losses Various book tax differences Regulatory treatment of deferred taxes Effective tax rate % % % We had a taxable loss of $54.0 million for 2015 . At December 31, 2015 , we have a federal net operating loss carryforward of $406.4 million which, if not utilized, will expire between 2030 and 2035 . The future reversal of existing temporary differences will more ‑likely ‑than ‑not enable the realization of the net operating loss carryforward. We have $3.8 million of alternative minimum tax credit carryforwards at December 31, 2015 to offset future regular taxes payable and the credit carryforwards have no expiration date. The authoritative guidance for income taxes addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. We may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than 50 percent likelihood of being realized upon ultimate settlement. We file a U.S. federal consolidated income tax return and income tax returns in state jurisdictions where required. The statute of limitations remains open for federal and state returns for the years 2012 forward. We do not have any liabilities recorded for uncertain tax positions.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2015
LEASES
LEASES	NOTE 8—LEASES LESSOR—GAS TOLLING ARRANGEMENTS: We are the lessor under certain power sales arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey the right to use power generating equipment for a stated period of time. These arrangements include sales contracts to a third party out of our J.M. Shafer, Knutson and Limon Generating Stations. Under the first of these contracts, the third party directs the use of 122 megawatts of the 272 ‑megawatt net generating capability of the J.M. Shafer Generating Station through June 30, 2019 under a tolling arrangement whereby the third party provides its own natural gas for generation of electricity. Under the other contracts, the third party directs the use of both of the two Knutson Generating Station units and one of the two Limon Generating Station units over the terms of the contracts under tolling arrangements whereby the third party provides its own natural gas for generation of electricity. The Limon contract was suspended for a four ‑year period beginning May 2009 through April 2013 and the Knutson contract was suspended for a three ‑year period beginning May 2010 through April 2013 to allow us to utilize the output of the turbines. Both turbine contracts resumed with the third party under the original tolling arrangements on May 1, 2013 and are in effect through April 30, 2016. We also had a similar tolling arrangement with a third party through September 30, 2014 involving one of the four 40 ‑megawatt units at our Pyramid Generating Station. The revenues from these operating leases of $30.1 , $30.6 and $25.8 million for 2015 , 2014 and 2013 , respectively, are accounted for as lease revenue and are reflected in other operating revenue on the consolidated statements of operations. The generating units used in these gas tolling arrangements have a total cost and accumulated depreciation of $223 and $106 million, respectively, as of December 31, 2015 , and of $232 and $108 million, respectively, as of December 31, 2014 . The minimum future lease revenues under these gas tolling arrangements at December 31, 2015 are as follows (thousands): 2016 $ 2017 2018 2019 $ LESSEE—GAS TOLLING ARRANGEMENT: We are the lessee under a power purchase arrangement that is required to be accounted for as an operating lease since the arrangement is in substance a lease because it conveys to us the right to use power generating equipment for a stated period of time. Under this agreement, we direct the use of 70 megawatts at the Brush Generating Station for a 10 ‑year term ending December 31, 2019 and provide our own natural gas for generation of electricity. The expense for the Brush operating lease of $5.3 million for each of the years 2015 , 2014 and 2013 is included in other operating expenses on the consolidated statements of operations. Our operating lease commitments for this gas tolling arrangement at December 31, 2015 are as follows (thousands): 2016 $ 2017 2018 2019 $

RELATED PARTIES

RELATED PARTIES	12 Months Ended
	Dec. 31, 2015
RELATED PARTIES
RELATED PARTIES	NOTE 9—RELATED PARTIES TRAPPER MINING, INC.: We, and certain participants in the Yampa Project, own Trapper Mining. Organized as a cooperative, Trapper Mining supplied 26 , 35 and 24 percent of the coal for the Yampa Project in 2015 , 2014 and 2013 , respectively. Our 26.57 percent share of coal purchases from Trapper Mining was $17.7 , $30.6 and $16.9 million in 2015 , 2014 and 2013 , respectively. Our membership interest in Trapper Mining of $14.1 and $13.7 million at December 31, 2015 and 2014 , respectively, is included in investments in and advances to coal mines on the consolidated statements of financial position. Our share of Trapper Mining capital credit al locations of $531,000 for 2015, and $532,000 in each of the years 2014 and 2013 is included in capital credits from cooperatives on the consolidated statements of operations.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2015
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS	NOTE 10—EMPLOYEE BENEFIT PLANS DEFINED BENEFIT PLAN: Substantially all of our 1,561 employees participate in the National Rural Electric Cooperative Association Retirement Security Plan (“RS Plan”) except for the 216 employees of Colowyo Coal. The RS Plan is a defined benefit pension plan qualified under Section 401(a) and tax ‑exempt under Section 501(a) of the Internal Revenue Code. It is considered a multiemployer plan under the accounting standards for compensation ‑retirement benefits. The plan sponsor’s Employer Identification Number is 53 ‑0116145 and the Plan Number is 333. A unique characteristic of a multiemployer plan compared to a single employer plan is that all plan assets are available to pay benefits to any plan participant. Separate asset accounts are not maintained for participating employers. This means that assets contributed by one employer may be used to provide benefits to employees of other participating employers. Our contributions to the RS Plan in each of the years 2015 , 2014 and 2013 represented less than 5 percent of the total contributions made each year to the plan by all participating employers. We made contributions to the RS Plan of $22.9 , $21.5 and $92.6 million in 2015 , 2014 and 2013 , respectively. Contributions in 2013 were significantly higher than those in 2015 and 2014 due to our election to exercise the prepayment option offered to participating employers in 2013. In December 2012, the National Rural Electric Cooperative Association approved an option to allow participating cooperatives in the RS Plan to make a contribution prepayment and reduce future required contributions. The prepayment amount is a cooperative’s share, as of January 1, 2013, of future contributions required to fund the RS Plan’s unfunded value of benefits earned to date using RS Plan actuarial valuation assumptions. The prepayment amount is equal to approximately 2.5 times a cooperative’s annual RS Plan required contribution as of January 1, 2013. After making the prepayment, the annual contribution was reduced by approximately 25 percent, retroactive to January 1, 2013. The reduced annual contribution is expected to continue for approximately 15 years. However, changes in interest rates, asset returns and other plan experience different from expected, plan assumption changes and other factors may have an impact on future contributions and the 15-year period. In May 2013, we elected to make a contribution prepayment of $71.2 million to the RS Plan. This contribution prepayment was determined to be a long ‑term prepayment and therefore recorded in deferred charges and amortized beginning January 1, 2013 over the 13 ‑year period calculated by subtracting the average age of our workforce from our normal retirement age under the RS Plan. Our contributions to the RS Plan include contributions for substantially all of the 361 bargaining unit employees that are made in accordance with collective bargaining agreements. In the RS Plan, a “zone status” determination is not required, and therefore not determined, under the Pension Protection Act (“Act”) of 2006. In addition, the accumulated benefit obligations and plan assets are not determined or allocated separately by individual empl oyer. In total, the RS Plan was over 80 percent funded at January 1, 2015, and over 80 percent funded at January 1, 2014, based on the Act funding target and the Act actuarial value of assets on those dates. Because the provisions of the Act do not apply to the RS Plan, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the plan and may change as a result of plan experience. DEFINED CONTRIBUTION PLAN: We have a qualified savings plan for eligible employees who may make pre ‑tax and after ‑tax contributions totaling up to 100 percent of their eligible earnings subject to certain limitations under federal law. We make no contributions for the 361 bargaining unit employees. For all of the eligible non ‑bargaining unit employees, other than the 216 employees of Colowyo Coal, we contribute 1 percent of an employee’s eligible earnings. For the employees of Colowyo Coal, we contribute 7 percent of an employee’s eligible earnings and also match an employee’s contributions up to 5 percent. We made contributions to the plan of $3.0 , $2.9 and $3.0 million in 2015 , 2014 and 2013 , respectively. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS: We sponsor three medical plans for all non ‑bargaining unit employees. Two of the plans provide postretirement medical benefits to full ‑time non ‑bargaining unit employees and retirees who receive benefits under those plans, who have attained age 55 , and who elect to participate. All three of these non ‑bargaining unit medical plans offer postemployment medical benefits to employees on long ‑term disability. The plans were unfunded at December 31, 2015 , are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost ‑sharing features such as deductibles. The postretirement medical benefit plans were amended as of December 31, 2015. The plan amendment eliminated coverage for all members after the age of 65 . This did not impact the valuation as post-65 retiree contributions were sufficient to cover expected claim costs for that group, so there was no implicit subsidy to value. The postretirement medical benefit plan was amended to include three different plan options for members prior to the age of 65 . This reduced the liability by approximately 11.5 percent and is reflected as a prior service cost in the amount of ($896,214) as of December 31, 2015. The postretirement medical benefit and postemployment medical benefit obligations are determined annually by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on the consolidated statements of financial position as follows (thousands): 2015 2014 Postretirement medical benefit obligation at beginning of year $ $ Service cost Interest cost Plan amendments - prior service cost — Benefit payments (net of contributions by participants) Actuarial (gain) loss Postretirement medical benefit obligation at end of year $ $ Postemployment medical benefit obligation at end of year Total postretirement and postemployment medical obligations at end of year $ $ In accordance with the accounting standard related to postretirement benefits other than pensions, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other comprehensive income on the consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess amount is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the postretirement medical benefit obligation. The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligation are included in accumulated other comprehensive income as follows (thousands): 2015 2014 Actuarial gain included in accumulated other comprehensive income at beginning of year $ $ Reclassification adjustment included in income Plan amendments - prior service cost — Actuarial gain (loss) per actuarial study Actuarial gain (loss) included in accumulated other comprehensive income at end of year $ $ The assumptions used in the 2015 actuarial study performed for our postretirement medical benefit obligation were as follows: Weighted-average discount rate % Initial health care cost trend (2015) % Ultimate health care cost trend % Year that the rate reached the ultimate health care cost trend rate Expected return on plan assets (unfunded) N/A Average remaining service lives of active plan participants (years) Changes in the assumed health care cost trend rates would impact the accumulated postretirement medical benefit obligation and the net periodic postretirement medical benefit expense as follows (thousands): 1% Increase 1% Decrease Accumulated postretirement medical benefit obligation $ $ Net periodic postretirement medical benefit expense $ $ The following are the expected future benefits to be paid related to the postretirement medical benefit obligation (thousands): 2016 $ 2017 2018 2019 2020 2021 and thereafter $

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2015
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES	NOTE 11 – VARIABLE INTEREST ENTITIES The following is a description of our financial interests in variable interest entities that we consider significant. This includes an entity for which we are determined to be the primary beneficiary and therefore consolidate and also entities for which we are not the primary beneficiary and therefore do not consolidate. Consolidated Variable Interest Entity Springerville Partnership: We own a 51 percent equity interest, including the 1 percent general partner equity interest, in the Springerville Partnership, which is the 100 percent owner of Springerville Unit 3 Holding LLC (“Owner Lessor”) of the Springerville Unit 3. We, as general partner, have the full, exclusive and complete right, power and discretion to operate, manage and control the affairs of the Springerville Partnership and take certain actions necessary to maintain the Springerville Partnership in good standing without the consent of the limited partners. Additionally, the Owner Lessor has historically not demonstrated an ability to finance its activities without additional financial support. The financial support is provided by our remittance of lease payments in order to permit the Owner Lessor, the holder of the Springerville Unit 3 assets, to pay the debt obligations and equity returns of the Springerville Partnership. We have the primary risk (expense) exposure in operating the Springerville Unit 3 assets and are responsible for 100 percent of the operation, maintenance and capital expenditures of Springerville Unit 3 and the decisions related to those expenditures including budgeting, financing and dispatch of power. Based on all these facts, it was determined that we are the primary beneficiary of the Owner Lessor. Therefore, the Springerville Partnership and Owner Lessor have been consolidated by us. Our consolidated statements of financial position include the Springerville Partnership’s net electric plant of $853.3 and $874.4 million at December 31, 2015 and 2014 , respectively, the long-term debt of $511.0 and $548.1 million at December 31, 2015 and 2014 , respectively, accrued interest associated with the long-term debt of $14.3 million and $15.2 million at December 31, 2015 and 2014 , respectively, and the 49 percent noncontrolling equity interest in the Springerville Partnership of $108.8 and $109.3 million at December 31, 2015 and 2014 , respectively. Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization expense of $21.0 million for 2015 and 2014. Our consolidated statements of operations also include interest expense of $32.3 million, $34.1 million and $35.9 million for 2015, 2014, and 2013 . The net losses attributable to the 49 percent noncontrolling equity interest in the Springerville Partnership are reflected on our consolidated statements of operations. The revenue associated with the Springerville Partnership lease has been eliminated in consolidation. Income, losses and cash flows of the Springerville Partnership are allocated to the general and limited partners based on their equity ownership percentages. Unconsolidated Variable Interest Entities Western Fuels Association : WFA is a non-profit membership corporation organized for the purpose of acquiring and supplying fuel resources to its members, which includes us. WFA supplies fuel to MBPP for the use of the Laramie River Station through its ownership in WFW. We also receive coal supplies directly from WFA for the Escalante Generating Station in New Mexico and spot coal for the Springerville Unit 3 in Arizona. The pricing structure of the coal supply agreements with WFA is designed to recover the mine operating costs of the mine supplying the coal and therefore the coal sales agreements provide the financial support for the mine operations. There isn’t sufficient equity at risk for WFA to finance its activities without additional financial support. Therefore, WFA is considered a variable interest entity in which we have a variable interest. The power to direct the activities that most significantly impact WFA’s economic performance (acquiring and supplying fuel resources) is held by the members who are represented on the WFA board of directors whose actions require joint approval. There is shared power with a related party (Basin), which results in power and the ability to receive benefits from the significant activities of WFA. Due to Basin’s participating interest of 42.27 percent interest in MBPP and ownership of the Dry Fork Station, Basin is the party most closely associated to WFA. We are not the primary beneficiary of WFA and the entity is not consolidated. Our investment in WFA, accounted for using the cost method, was $2.3 million for both December 31, 2015 and 2014 , respectively, and is included in investments in other associations. Western Fuels – Wyoming : WFW, the owner and operator of the Dry Fork Mine in Gillette, WY, was organized for the purpose of acquiring and supplying coal, through long-term coal supply agreements, to be used in the production of electric energy at the Laramie River Station (owned by the participants of MBPP) and at the Dry Fork Station (owned by Basin). WFA owns 100 percent of the class AA shares and 75 percent of the class BB shares of WFW, while the participants of MBPP (of which we have a 24.13 percent undivided interest) own the remaining 25 percent of class BB shares of WFW. The pricing structure of the coal supply agreements is designed to recover the costs of production of the Dry Fork Mine and therefore the coal supply agreements provide the financial support for the operation of the Dry Fork Mine. There isn’t sufficient equity at risk at WFW for it to finance its activities without additional financial support. Therefore, WFW is considered a variable interest entity in which we have a variable interest. The power to direct the activities that most significantly impact WFW’s economic performance (which includes operations, maintenance and reclamation activities) is shared with the equity interest holders since each member has representation on the WFW board of directors whose actions require joint approval. Therefore, we are not the primary beneficiary of WFW and the entity is not consolidated. Trapper Mining, Inc. : Trapper Mining is a cooperative organized for the purpose of mining, selling and delivering coal from the Trapper Mine to the Craig Station Units 1 and 2 through long-term coal supply agreements. Trapper Mining is jointly owned by some of the participants of the Yampa Project. We have a 26.57 percent cooperative member interest in Trapper Mining. The pricing structure of the coal supply agreements is designed to recover the costs of production of the Trapper Mine and therefore the coal supply agreements provide the financial support for the operation of the Trapper Mine. There isn’t sufficient equity at risk for Trapper Mining to finance its activities without additional financial support. Therefore, Trapper Mining is considered a variable interest entity in which we have a variable interest. The power to direct the activities that most significantly impact Trapper Mining’s economic performance (which includes operations, maintenance and reclamation activities) is shared with the cooperative members since each member has representation on the Trapper Mining board of directors whose actions require joint approval. Therefore, we are not the primary beneficiary of Trapper Mining and the entity is not consolidated. We record our investment in Trapper Mining using the equity method. Our membership interest in Trapper Mining was $14.1 million at December 31, 2015 and $13.7 million at December 31, 2014 .

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2015
COMMITMENTS AND CONTINGENCIES
LEGAL	NOTE 12—COMMITMENTS AND CONTINGENCIES SALES: We have delivery obligations under resource-contingent power sales contracts with Public Service Company of Colorado totaling 125 megawatts in the summer season and 175 megawatts in the winter season. These contracts expire in 2016 and 2017. We also have a resource-contingent firm power sales contract of 100 megawatts to Salt River Project Agricultural Improvement and Power District through August 31, 2036. COAL PURCHASE REQUIREMENTS: We are committed to purchase coal for our generating plants under long ‑term contracts that expire between 2017 and 2034. These contracts require us to purchase a minimum quantity of coal at prices that are subject to escalation clauses that reflect cost increases incurred by the suppliers and market conditions. The projection of contractually committed purchases is based upon estimated future prices. At December 31, 2015 , the annual minimum coal purchases under these contracts are as follows (thousands): 2016 $ 2017 2018 2019 2020 Thereafter $ ELECTRIC POWER PURCHASE AGREEMENTS: Our principal long ‑term electric power purchase contracts are with Western Area Power Administration (“WAPA”) and Basin. WAPA, one of four power marketing administrations of the U.S. Department of Energy, markets and supplies cost ‑based hydroelectric power and related services primarily to cooperatives and municipal electric systems located in 15 states in the central and western United States. WAPA markets and transmits the power to us under three contracts, one relating to WAPA’s Loveland Area Project (terminates September 30, 2024), and two contracts relating to WAPA’s Salt Lake City Area Integrated Projects (terminate September 30, 2024). We have entered into a new contract with WAPA relating to the Loveland Area Project which commences upon termination of the above referenced contract terminating September 30, 2024, and will run through September 2054. Our purchases of hydroelectric ‑based electric power from WAPA are made at cost ‑based rates under long ‑standing federal law under which WAPA sells power to cooperatives and municipal electric systems and certain other preference customers. We utilize a portion of our electric purchases from Basin to supply power to our Nebraska members, which are primarily located east of the electrical grid separation and are generally isolated from our generating facilities that are located west of the separation. We have a contract with Basin for a term ending December 31, 2050, to supply the electrical requirements of its Nebraska members in excess of power supplied by WAPA. We also purchase 225 MWs from Basin for use west of the electrical separation under a contract for a term ending December 31, 2050. Costs under the above electric power purchase agreements for the years ended December 31 were as follows (thousands): 2015 2014 2013 WAPA $ $ $ Basin ENVIRONMENTAL: Our electric generation facilities are subject to various operating permits and must operate within guidelines imposed by numerous environmental regulations. We believe these facilities are currently in compliance with such regulatory and operating permit requirements. LEGAL: On October 19, 2012, we gave notice, as required by New Mexico law, to the New Mexico Public Regulation Commission (“NMPRC”) of our new A ‑37 wholesale rate which was scheduled to become effective on January 1, 2013. The rate would have increased revenue collected from all 44 of our Members by approximately 4.9 percent, with revenues from our 12 New Mexico Members increasing by approximately 6.7 percent. In November 2012, three of our Members located in New Mexico filed protests of our rates with the NMPRC. On December 20, 2012, the NMPRC suspended the rate filing in New Mexico and appointed a hearing examiner to conduct a hearing and establish reasonable rate schedules pursuant to New Mexico law. On June 25, 2013, we filed to withdraw the A ‑37 rate. On July 3, 2013, the NMPRC denied the filing to withdraw and ordered the A ‑37 rate filing to be consolidated with the A ‑38 rate filing described below. On September 10, 2013, we gave notice, as required by New Mexico law, to the NMPRC of our new A ‑38 wholesale rate which was scheduled to become effective on January 1, 2014. The A ‑38 rate modified the rate design but did not increase the general revenue requirement. On December 11, 2013, the NMPRC suspended the A ‑38 rate filing and assigned the consolidated A ‑37 and A ‑38 rate filings to a hearing examiner. In August 2014, we and the New Mexico Members executed a preliminary mediation agreement providing for a temporary rate rider through no later than December 31, 2015 (unless terminated earlier as provided in the preliminary mediation agreement) and a suspension of the procedural schedule related to the rate protest to allow the parties time to proceed with more extensive discussions on a global settlement. We filed notice of the temporary rate rider with the NMPRC and it became effective on October 2, 2014. The temporary rate rider was applied in conjunction with the 2012 wholesale rate to recover additional revenue from the New Mexico Members in an annualized amount of $7 million per year, which was prorated beginning October 2 for 2014. In 2015 and 2014 , the overall revenue impact of the New Mexico Members paying a lower rate was approximately $10.7 million and $16.4 million, respectively. On October 9, 2015, we gave notice, as required by New Mexico law, to the NMPRC of our 2016 wholesale rate, or the A ‑39 rate. No New Mexico Member filed a protest with the NMPRC of the A ‑39 rate and thus the A ‑39 rate became effective on January 1, 2016 without NMPRC review or approval. On December 9, 2015, we and the New Mexico Members filed a joint motion with the NMPRC seeking continuation of the suspension of the procedural schedule related to the rate protests to allow the parties additional time to proceed with further negotiations towards a global settlement. On January 7, 2016, the NMPRC ordered that the procedural schedule related to the rate protests remains suspended until further order of the NMPRC. As part of the global settlement, the parties seek to address the issue of our rate regulation in New Mexico, payment of capital credits, and whether we have the right to collect the amounts uncollected from our New Mexico Members as a result of the suspension of prior rate filings. We cannot predict the outcome of this matter or if a global settlement will be reached, although we do not believe this proceeding is likely to have a material adverse effect on our financial condition or our future results of operations or cash flows. On March 4, 2013, three of our Colorado Members and several of their large industrial customers filed a complaint at the Colorado Public Utilities Commission (“COPUC”) alleging that our A ‑37 rate design was unjust and unreasonable. On April 4, 2013, we filed a motion to dismiss the complaint arguing lack of jurisdiction by the COPUC over our wholesale rates. The COPUC assigned the matter to an Administrative Law Judge (“ALJ”). The ALJ bifurcated the case into deciding first, whether the COPUC had the jurisdiction to hear such a case against us, who has been historically regulated by its membership through its Board, and secondly to hear the facts in the case depending on jurisdiction. The ALJ conducted a hearing in July 2013 and ruled on September 11, 2013 denying our motion to dismiss. In October 2013, we appealed the ALJ’s decision to the full commission and on December 18, 2013, the commission granted in part and denied in part our motion contesting the ALJ’s decision and remanded the case to the ALJ to hold a hearing on limited issues. In November 2014, we and the three Colorado Members executed a preliminary agreement providing for a temporary optional rate effective December 1, 2014 and to continue through no later than December 31, 2015, available to all non ‑New Mexico Members and a suspension of the procedural schedule related to the complaint. The ALJ entered a decision on November 28, 2014 holding this matter in abeyance until December 31, 2015 to give the parties time to work toward a global settlement and permanent rate. On December 28, 2015, we and the three Colorado Members filed a joint motion with the COPUC to withdraw the complaint and dismiss the proceeding. On January 19, 2016, the ALJ granted our joint motion to withdraw the complaint, dismiss the proceeding with prejudice and close the proceeding . The ALJ’s order has become effective by operation of law. The Purchase Option and Development Agreement was executed on July 26, 2007 between us and Sunflower Electric Power Corporation (“Sunflower”) and other Sunflower parties. The agreement calls for us to make option payments totaling $55 million to Sunflower and/or the other Sunflower parties in exchange for the development rights to develop a new coal ‑fired generating unit or units at Sunflower’s existing single ‑unit Holcomb Station in western Kansas. Upon execution, $25 million was paid. In 2008, $5 million was paid and the remainder will be paid on the purchase date. The purchase date will be designated by us, Sunflower and the other parties to the Purchase Option and Development Agreement after we exercise our option to acquire the development rights. The purchase date cannot currently be estimated due to legal uncertainties surrounding the status of the necessary air permits. The original air permit application was denied by the Kansas Department of Health and Environment (“KDHE”) in October 2007 and we and Sunflower appealed the denial to the Kansas courts. Subsequent to the denial of the air permit, Sunflower entered into an agreement with the governor of Kansas that could result in the KDHE issuing a permit for one new coal ‑fired generating unit at Holcomb Station of 895 megawatts. As a result of the agreement, Sunflower and we withdrew the appeal of the denial of the original air permit application. The KDHE issued the new permit on December 16, 2010. The Sierra Club filed an appeal of the new permit with the Kansas Court of Appeals on January 14, 2011 and the case was immediately transferred to the Kansas Supreme Court. The Kansas Supreme Court remanded the permit to the KDHE to consider a limited issue. The KDHE issued an addendum to the permit on May 30, 2014. The Sierra Club filed an appeal with the Kansas Court of Appeals on June 27, 2014. On November 3, 2014, the Kansas Supreme Court granted a pending motion to transfer the case from the Court of Appeals and KDHE subsequently filed the record on appeal. The Kansas Supreme Court heard oral argument on the appeal on January 28, 2016. Excluding the cost of land and water rights, the cost of developing the units incurred by us as of December 31, 2015 is $86.7 million, which is included in other deferred charges on the consolidated sta tements of financial position. We are unable to project the ultimate outcome of this matter or when the air permit application process may conclude. In June 2011, a wildfire in New Mexico, known as the Las Conchas Fire, burned for five days in northern New Mexico, primarily on national forest service land in the Santa Fe National Forest. Six plaintiff groups, comprised of property owners in the area of the Las Conchas Fire, filed separate lawsuits against our Member, Jemez Mountains Electric Cooperative, Inc. (“JMEC”) in the Thirteenth District Court, Sandoval County in the State of New Mexico. Plaintiffs alleged that the fire ignited when a tree growing outside the right of way fell onto a distribution line owned by JMEC as a result of high winds. On January 7, 2014, the district court allowed all parties and related parties to amend their complaints to include the addition of us as a party defendant. The allegations in each case were similar. Plaintiffs alleged that we owed them independent duties to inspect and maintain the right ‑of ‑way for JMEC’s distribution line and that we are also jointly liable for any negligence by JMEC under joint venture and alter ego theories. On June 16, 2014, we filed multiple motions for summary judgment including for plaintiffs’ claims related to nuisance, trespass, negligence per se, independent duty, joint venture and alter ego. On December 29, 2014, we received a demand letter from the U.S. Department of Justice for costs incurred as a result of the fire, also alleging the joint venture theory. JMEC has settled with the subrogated insurers, executing and funding the deal on December 30, 2014 and on February 7, 2015, the district court dismissed the subrogated insurers’ claims against us with prejudice. Settlement demands were received from plaintiffs Jemez Pueblo and Pueblo de Cochiti claiming damages in the amount of approximately $34.4 million and $23.9 million, respectively, focusing mainly on damages arising from flooding subsequent to the fire. On March 9, 2015, the district court granted our motions for summary judgment related to nuisance, trespass, negligence per se, and alter ego, but denied our motions related to independent duty and joint venture. On March 17, 2015, we filed an application for interlocutory appeal with the New Mexico Court of Appeals related to the district court’s denial of our motions for summary judgment for plaintiffs’ claims related to independent duty and joint venture. The New Mexico Court of Appeals denied our application for interlocutory appeal on May 27, 2015. A jury trial commenced on September 28, 2015. On October 28, 2015, the jury affirmed our position that we and JMEC did not operate as a joint venture or joint enterprise. The jury did find we owed the plaintiffs an independent duty and allocated comparative negligence with JMEC 75 percent negligent, us 20 percent negligent, and the United States Forest Service 5 percent negligent. On November 11, 2015, we filed a request with the district court to certify for interlocutory appeal certain issues regarding our duty under a negligence claim, which was denied by the district court in January 2016. Three or four separate trials will occur in the second half of 2016 and first quarter of 2017 to determine the amount of damages . We maintain $100 million in liability insurance coverage for this matter. Although we cannot predict the outcome of these matters at this point in time, we do not expect them to have a material adverse effect on our financial condition or our future results of operations or cash flows. In May 2013, near the Village of Pecos, New Mexico, a wildfire known as the Tres Lagunas Fire was ignited and subsequently destroyed timber on thousands of acres and burned for approximately three weeks. On March 25, 2014, a lawsuit was filed by David Old d/b/a Old Wood, The Viveash Ranch, and River Bend Ranch, LLC, against our Member, Mora-San Miguel Electric Cooperative, Inc. (“MSMEC”), in the First Judicial District Court for the County of Santa Fe, New Mexico. In the complaint, plaintiffs allege that the Tres Lagunas Fire resulted from wind blowing a portion of a dead standing tree into an electric distribution power line owned and operated by MSMEC. On November 6, 2015, plaintiffs filed a motion to amend their complaint and include the addition of us as a defendant. The district court approved the motion to amend on November 20, 2015 and plaintiffs’ first amended complaint was filed. Plaintiffs assert claims of negligence, violations of New Mexico’s Unfair Practices Act (“NMUPA”), and strict liability. On December 21, 2015, we filed a motion to dismiss the NMUPA and strict liability claims and, additionally, filed our answer and 12-person jury demand. In 2014, we renewed our coverage and now maintain $200 million in liability insurance coverage for this matter. Although we cannot predict the outcome of this matter at this point in time, we do not expect it to have a material adverse effect on our financial condition or our future results of operations or cash flows.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2015
QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERLY FINANCIAL DATA (UNAUDITED)	QUARTERLY FINANCIAL DATA (UNAUDITED)

SUMMARY OF SIGNIFICANT ACCOUN19

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF CONSOLIDATION:	B ASIS OF CONSOLIDATION: Our consolidated financial statements include the accounts of the Association, our wholly ‑owned and majority ‑owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 11—Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. All significant intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) as applied to regulated enterprises.
JOINTLY OWNED FACILITIES:	JOINTLY OWNED FACILITIES: We own undivided interests in three jointly owned generation facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common. These projects include the Craig Station Units 1 and 2 (operated by us (“Yampa Project”)), the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)) and the San Juan Project (operated by Public Service Company of New Mexico). Each participant in these agreements receives a portion of the total output of the generation facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and operating expenses is included in our consolidated financial statements.
VARIABLE INTEREST ENTITIES:	VARIABLE INTEREST ENTITIES: We evaluate our arrangements and relationships with other entities, including our investments in other associations and investments in coal mines, in accordance with the accounting standard related to consolidation of variable interest entities. This guidance requires us to identify variable interests (contractual, ownership or other financial interests) in other entities and whether any of those entities in which we have a variable interest in, meets the criteria of a variable interest entity. An entity is considered to be a variable interest entity when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. In making this assessment, we consider the potential that our arrangements and relationships with other entities provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of an entity, the ability to directly or indirectly make decisions about the entity’s activities and other factors. If an entity that we have a variable interest in meets the criteria of a variable interest entity, we must determine whether we are the primary beneficiary of that entity. The primary beneficiary is the entity that has the power to direct any of the activities of the variable interest entity that most significantly impact the variable interest entity’s economic performance, and the obligation to absorb losses or the right to receive benefits from the variable interest entity that could be potentially significant to the variable interest entity. If we are determined to be the primary beneficiary of (has controlling financial interest in) a variable interest entity, then we would be required to consolidate that entity. In certain situations, it may be determined that power is shared among multiple unrelated parties such that no one party has the power to direct the activities of a variable interest entity that most significantly impact the variable interest entity’s economic performance (decisions about those activities require the consent of each of the parties sharing power). In accordance with the accounting guidance prescribed by consolidation of variable interest entities, if the determination is made that power is shared among multiple unrelated parties, then no party is the primary beneficiary. See Note 11—Variable Interest Entities.
ACCOUNTING FOR RATE REGULATION:	ACCOUNTING FOR RATE REGULATION: We are subject to the accounting requirements related to regulated operations. In accordance with these accounting requirements, some revenues and expenses have been deferred at the discretion of our Board, which has budgetary and rate ‑setting authority, if it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs we expect to recover from our Members based on rates approved by our Board in accordance with our rate policy. Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to our Members based on rates approved by our Board in accordance with our rate policy. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses concurrent with their recovery in rates.
SEGMENT REPORTING:	SEGMENT REPORTING: We are organized for the purpose of supplying wholesale power to our Members and do so through the utilization of a portfolio of resources, including generating facilities, long ‑term purchase contracts and forward, short ‑term and spot market energy purchases. In support of our coal generating resources, we have direct ownership and investments in coal mines. Our Board serves as our chief operating decision maker who manages and reviews our operating results and allocates resources as one operating segment. Therefore, we have one reportable segment for financial reporting purposes.
BUSINESS COMBINATIONS:	BUSINESS COMBINATIONS: We account for business acquisitions by applying the accounting standard related to business combinations. In accordance with this method, the identifiable assets acquired, the liabilities assumed and any noncontrolling interests in the acquired entities are required to be recognized at their acquisition date fair values. We typically engage an independent valuation firm to determine the acquisition date fair values of most of the acquired assets and assumed liabilities. The excess of total consideration transferred over the net assets acquired is recognized as goodwill. Acquisition ‑related costs such as legal fees, accounting services fees and valuation fees, are expensed as incurred. We are required to consolidate these acquired entities. If an acquisition does not result in acquiring a business, the transaction is accounted for as an acquisition of assets. This method requires measurement and recognition of the acquired net assets based upon the amount of cash transferred and the amount paid for acquisition ‑related costs. There is no goodwill recognized in an acquisition of assets.
USE OF ESTIMATES:	USE OF ESTIMATES: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.
ELECTRIC PLANT AND DEPRECIATION:	ELECTRIC PLANT AND DEPRECIATION: Electric plant is stated at cost. The cost of internally constructed assets includes payroll, overhead costs and interest charged during construction. Interest rates charged during construction of 4.4 , 4.7 and 4.8 percent were used for 2015 , 2014 and 2013 , respectively. The amount of interest capitalized during construction was $13.5 , $ 15.0 and $ 13.0 million during 2015 , 2014 and 2013 , respectively. At the time that units of electric plant are retired, original cost and cost of removal, net of the salvage value, are charged to the allowance for depreciation. Replacements of electric plant that involve less than a designated unit value are charged to maintenance expense when incurred. Electric plant is depreciated based upon estimated depreciation rates and useful lives that are periodically re ‑evaluated.
COAL RESERVES AND DEPLETION:	COAL RESERVES AND DEPLETION: Coal reserves are recorded at cost. Depletion of coal reserves is computed using the units ‑of ‑production method utilizing only proven and probable reserves.
LEASES:	LEASES: The accounting for lease transactions in conformity with GAAP requires management to make various assumptions, including the discount rate, the fair market value of the leased assets and the estimated useful life, in order to determine whether a lease should be classified as operating or capital. We are the lessor under power sales arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey the right to use our power generating equipment for a stated period of time. The lease revenues from these arrangements are included in other operating revenue on the consolidated statements of operations. We are the lessee under power purchase arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey to us the right to use power generating equipment for a stated period of time. These are included in other operating expenses on the consolidated statements of operations. See Note 8—Leases.
INVESTMENTS IN OTHER ASSOCIATIONS:	INVESTMENTS IN OTHER ASSOCIATIONS: Investments in other associations includes investments in the patronage capital of other cooperatives (accounted for using the cost method) and other required investments in the organizations. Under this method, our investment in a cooperative increases when a cooperative allocates patronage capital credits to us and it decreases when we receive a cash retirement of the allocated capital credits from the cooperative. A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative.
INVESTMENTS IN AND ADVANCES TO COAL MINES:	INVESTMENTS IN AND ADVANCES TO COAL MINES: We have direct ownership and investments in coal mines to support our coal generating resources. We, and certain participants in the Yampa Project, are members of Trapper Mining, Inc. (“Trapper Mining”), which is organized as a cooperative and is the owner and operator of the Trapper Mine near Craig, Colorado. Our investment in Trapper Mining is recorded using the equity method. In addition, we have ownership in Western Fuels Association, Inc. (“WFA”), which is the owner of Western Fuels ‑Wyoming, Inc. (“WFW”), the owner and operator of the Dry Fork Mine near Gillette, Wyoming. We, through our ownership in WFA, advance funds to the Dry Fork Mine.
CASH AND CASH EQUIVALENTS:	CASH AND CASH EQUIVALENTS: We consider highly liquid investments with an original maturity of three months or less to be cash equivalents.
RESTRICTED CASH AND INVESTMENTS:	RESTRICTED CASH AND INVESTMENTS: Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds is for the payment of debt within one year and funds restricted by contract that are expected to be settled within one year. These funds are therefore classified as current on the statements of financial position. The other funds are for the payment of debt beyond one year and funds restricted by contract or other legal reasons that are expected to be settled beyond one year. These funds are classified as noncurrent and are included in other assets and investments on the statements of financial position. We have investments in U.S. Treasury Notes pledged as collateral in connection with the in ‑substance defeasance for the principal outstanding and future interest payments on the Coal Contract Receivable Collateralized Bonds (“Colowyo Bonds”). The balances in these investments are described as investments in securities pledged as collateral in the table below. As of December 31, 2015 , the entire $8.7 million balance of the defeasance investment is for Colowyo Bond debt payments due within one year and is, therefore, a current asset on the consolidated statements of financial position. The Colowyo Bonds mature in November 2016. We received $29.4 million in 2009 from BNSF Railway Company (“BNSF”) as a reduction of prior coal delivery shipping charges as the result of the decision of the Surface Transportation Board (“STB”). However, BNSF appealed the decision and the funds were subject to refund in the event BNSF was ultimately successful in its appeal. These funds were designated by our Board to be held as restricted cash. In May 2015, BNSF, WFA and Basin filed a joint petition at the STB informing the STB that the parties had entered into a rail transportation agreement settling all matters at issue. In June 2015, the STB granted the joint petition, which resolved the uncertainties related to the outcome of this matter and the $29.4 million of cash related to the BNSF settlement was no longer designated as restricted.
MARKETABLE SECURITIES:	MARKETABLE SECURITIES: We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are classified as available ‑for ‑sale securities. At December 31, 2015 , the cost and estimated fair value of the investments based upon their active market value (Level 1 inputs) were $1.0 and $1.2 million, respectively, with a net unrealized gain balance of $129,000 . At December 31, 2014 , the cost and estimated fair value of the investments were $1.1 and $1.4 million, respectively, with a net unrealized gain balance of $254,000 . The estimated fair value of the investments is included in other noncurrent assets on the consolidated statements of financial position. The unrealized gains at December 31, 2015 and 2014 are reported as a component of accumulated other comprehensive income as of those dates. Changes in the net unrealized gains or losses are reported as a component of comprehensive income. We hold U.S. Treasury Notes to maturity in connection with the December 2011 defeasance of the Colowyo Bonds and these are included in restricted cash and investments on the statements of financial position. Since they will be held to maturity, the notes are carried at amortized cost. As of December 31, 2015 , the defeasance investment of $8.7 million consisted of a principal amount of $7.4 million, an unamortized premium of $113,000 and cash of $1.1 million. As of December 31, 2014 , the defeasance investment of $18.2 million consisted of a principal amount of $16.4 million, an unamortized premium of $371,000 and cash of $1.4 million.
INVENTORIES:	INVENTORIES: Coal inventories at our owned generating stations are stated at LIFO (last ‑in, first ‑out) cost and were $42.2 and $22.2 million at December 31, 2015 and 2014 , respectively. The remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost. In 2014, we realized lower coal fuel expense of $596,000 as a result of a LIFO inventory liquidation at our generating stations.
OTHER DEFERRED CHARGES:	OTHER DEFERRED CHARGES: We make expenditures for preliminary surveys and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the preliminary survey and investigation expenditures will be reclassified to electric plant—construction work in progress. If the work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating expense account or the expense could be deferred as a regulatory asset to be recovered from our Members in rates subject to approval by our Board, which has budgetary and rate-setting authority. As of December 31, 2015 , preliminary surveys and investigations was primarily comprised of expenditures for the Holcomb Station Project of $86.7 million (see Note 12—Commitments and Contingencies—Legal). In December 2015, $28.5 million of preliminary survey charges related to the Eastern Plains Transmission Project was capitalized as part of the Burlington-Wray 230kV transmission line project and is included in electric plant-construction work in progress on the consolidated statements of financial position. We make advance payments to the operating agents of jointly owned facilities. See Note 3—Property, Plant and Equipment—Jointly Owned Facilities.
DEBT ISSUANCE COSTS:	DEBT ISSUANCE COSTS: We adopted Accounting Standards Update (“ASU”) 2015-03, Interest — Imputation of Interest (Subtopic 835-30) and ASU 2015-15, Interest – Imputation of Interest (Subtopic 835-30) Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. Accordingly, we accounted for debt issuance costs as a direct deduction of the associated long-term debt carrying amount consistent with the accounting for debt discounts and premiums. Deferred debt issuance costs are amortized to interest expense using an effective interest method over the life of the respective debt. The adoption of these amendments resulted in $21.2 million and $22.3 million of debt issuance costs being presented as a direct deduction from long-term debt as of December 31, 2015 and 2014. The $22.3 million of debt issuance costs as of December 31, 2014 were retrospectively adjusted as a change in accounting principle and were previously reported in other deferred charges .
ASSET RETIREMENT OBLIGATIONS:	ASSET RETIREMENT OBLIGATIONS: We account for current obligations associated with the future retirement of tangible long ‑lived assets in accordance with the accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations associated with the retirement of long ‑lived assets be recognized at fair value at the time the liability is incurred and capitalized as part of the related long ‑lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense and the capitalized cost of the long ‑lived asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. In the absence of quoted market prices, we determine fair value by using present value techniques in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk ‑free rate including a market risk premium. Upon settlement of an asset retirement obligation, we will apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability. These liabilities are included in asset retirement obligations. Coal mines: We have asset retirement obligations for the final reclamation costs and post ‑reclamation monitoring related to the Colowyo Mine, the New Horizon Mine, and the Fort Union Mine. Fossil steam generation: We, including our undivided interest in jointly owned facilities, have asset retirement obligations related to equipment, dams, ponds, wells and underground storage tanks at the fossil steam generating stations. Transmission: We have an asset retirement obligation to remove a certain transmission line and related substation assets resulting from an agreement to relocate the line. Aggregate carrying amounts of asset retirement obligations are as follows (thousands): 2015 2014 Asset retirement obligation at beginning of year $ $ Liabilities incurred Liabilities settled Accretion expense Change in cash flow estimate Asset retirement obligation at end of year $ $ We also have asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations attached to transmission and other easements that are considered by us to be operated in perpetuity and therefore the measurement of the obligation is not possible. A liability will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates as is needed to employ a present value technique to estimate far value.
MEMBERSHIPS AND PATRONAGE CAPITAL:	MEMBERSHIPS: There are 44 $5 memberships outstanding at December 31, 2015 and 2014 . PATRONAGE CAPITAL: Our net margins are treated as advances of capital by our Members and are allocated to our Members on the basis of their electricity purchases from us. Net losses, should they occur, are not allocated to Members, but are offset by future margins. Margins not distributed to Members constitute patronage capital. Patronage capital is held for the account of our Members and is distributed through patronage capital retirements when our Board deems it appropriate to do so, subject to debt instrument restrictions.
ELECTRIC SALES REVENUE:	ELECTRIC SALES REVENUE: Revenue from electric energy deliveries is recognized when delivered.
ACCOUNTS RECEIVABLE—MEMBERS AND OTHER:	ACCOUNTS RECEIVABLE—MEMBERS AND OTHER: Receivables are primarily related to electric sales to Members and electric sales and other transactions with electric utilities. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period determined to be uncollectible.
OTHER OPERATING REVENUE:	OTHER OPERATING REVENUE: Other operating revenue consists primarily of wheeling revenue, lease revenue, coal sales and revenue from supplying steam and water to a paper manufacturer located adjacent to the Escalante Generating Station. Wheeling revenue is received when we charge other energy companies for transmitting electricity over our transmission lines. The lease revenue is primarily from certain power sales arrangements that are required to be accounted for as operating leases since the arrangements are in substance leases because they convey to others the right to use power generating equipment for a stated period of time. Coal sales revenue results from the sale of a portion of the coal from the Colowyo Mine per a contract ending in 2017 to other joint owners in the Yampa Project (the “Yampa Participants”). The associated Colowyo Mine expenses are included in coal mining, depreciation and amortization and interest expense on the consolidated statements of operations.
INCOME TAXES:	INCOME TAXES: We are a non ‑exempt cooperative subject to federal and state taxation and, as a cooperative, are allowed a tax exclusion for margins allocated as patronage capital. The liability method of accounting for income taxes is utilized, whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues.
INTERCHANGE POWER:	INTERCHANGE POWER: We occasionally engage in interchanges, or non ‑cash swapping, of energy. Based on the assumption that all energy interchanged will eventually be received or delivered in ‑kind, interchanged energy is generally valued at the average cost of fuel to generate power. Additionally, portions of the energy interchanged are valued per contract with the utility involved in the interchange. When we are in a net energy advance position, the advanced energy balance is recorded as an asset. If we owe energy, the net energy balance owed to others is recorded as a liability. The net activity for the year is included in purchased power expense. The interchange liability balance of $1.6 and $1.5 million at December 31, 2015 and 2014 , respectively, is included in accounts payable. The net interchange activity recorded in purchased power expense was $108,630 , $(452,500) and $2.6 million in 2015 , 2014 and 2013 , respectively.
EVALUATION OF SUBSEQUENT EVENTS:	EVALUATION OF SUBSEQUENT EVENTS: We evaluated subsequent events through March 14, 2016, which is the date when the financial statements were issued.
NEW ACCOUNTING PRONOUNCEMENTS:	NEW ACCOUNTING PRONOUNCEMENTS: In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . In July 2015, FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date . ASU 2014-09 replaces current revenue guidance, which was based on a risks and rewards model, with a transfer of control model. The core principle under the new transfer of control model states that revenue should be recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve the core principle, this amendment requires the following steps: (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This amendment also requires additional quantitative and qualitative disclosures sufficient enough to enable users of financial information to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, this amendment is effective for the fiscal year beginning January 1, 2018 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes footnote disclosures). Reporting entities have the option to adopt the standard as early as the original January 1, 2017 effective date of this amendment. We are currently evaluating the impact of this amendment on our financial position and results of operations. In August 2014, the FASB issued ASU 2014-15, Presentation of Financial Statements Going Concern (Subtopic 205-40); Disclosures of Uncertainties about an Entity’s Ability to Continue as a Going Concern. The amendment in this ASU requires management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern, which is currently performed by the external auditors. Management will be required to perform this assessment for both interim and annual reporting periods and must make certain disclosures if it concludes that substantial doubt exists. Substantial doubt about an entity’s ability to continue as a going concern exists when relevant conditions and events, considered in the aggregate, indicate that it is probable that the entity will be unable to meets its obligations as they become due within one year after the date that that the financial statements are issued (or within one year after the date that the financial statements are available to be issued when applicable). The amendment is effective for annual periods, and interim periods within those annual periods, beginning on or after December 15, 2016. We are currently evaluating the impact of this amendment on our financial position and results of operations. The adoption of this update is not expected to have a material impact on the financial position or results of operations. In February 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810), Amendments to the Consolidation Analysis . The amendments in this ASU affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Specifically, ASU 2015-02: (1) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (2) eliminates the presumption that a general partner should consolidate a limited partnership, and (3) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. The amendment is effective for the fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. A reporting entity may apply the amendments in this ASU using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. A reporting entity also may apply the amendments retrospectively. We adopted this update in 2015 and it did not have a material impact on our financial position or results of operations. In November 2015, the FASB issued ASU 2015-17, Income Taxes (Topic 740); Balance Sheet Classification of Deferred Taxes. The amendments in this ASU simplify the presentation of deferred income taxes. Deferred tax assets and liabilities must all be classified as noncurrent. This amendment is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2016. We adopted this update in 2015 and it did not have a material impact on our financial position or results of operations. In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities . The amendments in this ASU require that equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) be measured at fair value, with subsequent changes in fair value recognized in net income. An entity may choose to measure equity investments that do not have readily determinable fair value at cost minus impairment. The pronouncement impacts financial liabilities under the fair value option and the presentation and disclosure requirements for financial instruments. Also, an entity should present separately in other comprehensive income the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk if the entity has elected to measure the liability at fair value in accordance with the fair value option for financial instruments. The amendments are effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early application by public business entities to financial statements of fiscal years or interim periods that have not yet been issued or, by all other entities, that have not yet been made available for issuance are permitted as of the beginning of the fiscal year of adoption. An entity should apply the amendments by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. The amendments related to equity securities without readily determinable fair values (including disclosure requirements) should be applied prospectively to equity investments that exist as of the date of adoption of the update. We are currently evaluating the impact of this amendment on our financial position and results of operations. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842). This amendment requires a lessee to recognize substantially all leases (whether operating or finance leases) on the balance sheet as a right-of-use asset and an associated lease liability. Short-term leases of 12 months or less are excluded from this amendment. A right-of-use asset represents a lessee’s right to use (control the use of) the underlying asset for the lease term. A lease liability represents a lessee’s liability to make lease payments. The right-of-use asset and the lease liability are initially measured at the present value of the lease payments over the lease term. For finance leases, the lessee subsequently recognizes interest expense and amortization of the right-of-use asset, similar to accounting for capital leases under current GAAP. For operating leases, the lessee subsequently recognizes straight-line lease expense over the life of the lease. Lessor accounting remains substantially the same as that applied under current GAAP. ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early adoption is permitted. The guidance is to be applied using a modified retrospective transition method with the option to elect a package of practical expedients. We are currently evaluating the impact of this amendment on our financial position and results of operations.

SUMMARY OF SIGNIFICANT ACCOUN20

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2015
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Schedule of regulatory assets and liabilities	Regulatory assets and liabilities are as follows (thousands): 2015 2014 Regulatory assets Deferred income tax expense (1) $ $ Deferred prepaid lease expense- Craig 3 Lease (2) Deferred prepaid lease expense- Springerville 3 Lease (3) Goodwill – J.M. Shafer (4) Goodwill – Colowyo Coal (5) Deferred debt prepayment transaction costs (6) Other — Regulatory liabilities Deferred revenues (7) Net regulatory asset $ $ (1) A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. (2) Deferral of loss on acquisition related to the Craig Generating Station (“Craig Station”) Unit 3 prepaid lease expense upon acquisitions of equity interests in 2002 and 2006. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $6.5 million annually through the remaining original life of the lease ending in 2018 and recovered from our Members in rates. (3) Deferral of loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $2.3 million annually through the 47 -year period ending in 2056 and recovered from our Members in rates. (4) Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP (“TCP”) in December 2011. Goodwill is being amortized to depreciation and amortization expense in the amount of $2.8 million annually through the 25 -year period ending in 2036 and recovered from our Members in rates. (5) Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation and amortization expense through the 44 -year period ending in 2056 and recovered from our Members in rates. (6) Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation and amortization expense in the amount of $8.6 million annually over the 21.4 -year average life of the new debt issued and recovered from our Members in rates. (7) Represents deferral of the recognition of $10 million of non-member electric sales revenue received in 2008 and $35 million of non-member electric sales revenue in 2011. These deferred non-member electric sales revenues will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods.
Schedule of investments in other associations	Investments in other associations are as follows (thousands): 2015 2014 Basin Electric Power Cooperative $ $ National Rural Utilities Cooperative Finance Corporation CoBank, ACB Western Fuels Association, Inc. Other Investments in other associations $ $
Schedule of investments in and advances to coal mines	Investments in and advances to coal mines are as follows (thousands): 2015 2014 Investment in Trapper Mine $ $ Advances to Dry Fork Mine Investments in and advances to coal mines $ $
Schedule of restricted cash and investments	Restricted cash and investments are as follows (thousands): 2015 2014 Investments in securities pledged as collateral $ $ Funds restricted by contract Restricted cash and investments - current BNSF settlement — Funds restricted by contract Investments in securities pledged as collateral — Restricted cash and investments - noncurrent Total restricted cash and investments $ $
Schedule of other deferred charges	Other deferred charges are as follows (thousands): 2015 2014 Preliminary surveys and investigations $ $ Advances to operating agents of jointly owned facilities Other Total other deferred charges $ $
Schedule of change in aggregate carrying amount of asset retirement obligations	Aggregate carrying amounts of asset retirement obligations are as follows (thousands): 2015 2014 Asset retirement obligation at beginning of year $ $ Liabilities incurred Liabilities settled Accretion expense Change in cash flow estimate Asset retirement obligation at end of year $ $

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2015
PROPERTY, PLANT AND EQUIPMENT
Schedule of jointly owned facilities	JOINTLY OWNED FACILITIES: Our share in each jointly owned facility is as follows as of December 31, 2015 (these electric plant in service, accumulated depreciation and construction work in progress amounts are included in the electric plant table above) (thousands): Electric Construction Tri-State Plant in Accumulated Work In Share Service Depreciation Progress Yampa Project - Craig Station Units 1 and 2 % $ $ $ MBPP - Laramie River Station % San Juan Project – San Juan Unit 3 % Total $ $ $
Schedule of other plant assets (excluding utility assets)	Other plant assets are as follows (thousands): 2015 2014 Colowyo Mine assets $ $ New Horizon Mine assets Fort Union Mine assets Accumulated depreciation and depletion Net mine assets Non-utility assets Accumulated depreciation Net non-utility assets Net other plant $ $
Electric Plant
PROPERTY, PLANT AND EQUIPMENT
Schedule of investment in plant	ELECTRIC PLANT: Our investment in electric plant and the related annual rates of depreciation or amortization calculated using the straight ‑line method are as follows (thousands): Annual Depreciation Rate 2015 2014 Generation plant % to % $ $ Transmission plant % to % General plant % to % Other % to % Electric plant in service (at cost) Construction work in progress Less allowances for depreciation and amortization Electric plant $ $

INTANGIBLES (Tables)

INTANGIBLES (Tables)	12 Months Ended
	Dec. 31, 2015
INTANGIBLES
Schedule of amortization of intangible assets	The amortization was $7.3 million in each of the years 2015 , 2014 and 2013 and will be recognized over each of the next four years as follows (thousands): 2016 $ 2017 2018 2019 $
Schedule of future amortization of below market intangibles	An amortization benefit of $3.2 , $3.2 and $2.5 million was recognized in 2015 , 2014 and 2013 , respectively, and the recognition of the benefit over the next two years is estimated to be as follows (thousands): 2016 $ 2017 $

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2015
LONG-TERM DEBT
Schedule of long-term debt	Long-term debt consists of the following (thousands): 2015 2014 Mortgage notes payable 3.66% to 8.08% CFC, 5.96% average for 2015, due through 2028 $ $ 2.63% to 6.17% CoBank, ACB, 4.35% average for 2015, due through 2042 First Mortgage Bonds, Series 2014E-1, 3.70% due 2024 First Mortgage Bonds, Series 2014E-2, 4.70% due 2044 First Mortgage Bonds, Series 2010A, 6.00% due 2040 First Mortgage Obligation, Series 2014B, Tranche 1, 3.90%, due through 2033 First Mortgage Obligation Series 2014B, Tranche 2, 4.30%, due through 2039 First Mortgage Obligation Series 2014B, Tranche 3, 4.45%, due through 2045 First Mortgage Obligation, Series 2009C, Tranche 1, 6.00%, due through 2019 First Mortgage Obligation, Series 2009C, Tranche 2, 6.31%, due through 2021 Variable rate CFC, as determined by CFC, 2.90% average for 2015, due through 2026 Variable rate CFC, LIBOR-based term loan, 1.48% average for 2015, due through 2049 Variable rate CoBank, ACB, LIBOR-based term loan, 1.74% average for 2015, due through 2044 Variable rate, Revolving Credit Agreement, LIBOR-based revolving credit, 1.25% average for 2015, due through 2019 Pollution control revenue bonds City of Gallup, NM, 5.00%, Series 2005, due through 2017 Moffat County, CO Variable Rate Demand Series 2009, 0.06% average for 2015, due 2036 Springerville certificates Series A, 6.04%, due through 2018 Series B, 7.14%, due through 2033 Colowyo Coal Colowyo Bonds, 10.19%, due through 2016 Other Total debt $ $ Less debt issuance costs Less debt discounts Plus debt premiums Total debt adjusted for discounts, premiums and debt issuance costs $ $ Less current maturities Long-term debt $ $
Schedule of annual maturities of long-term debt	2016 $ 2017 2018 2019 (1) 2020 Thereafter $ (1) Annual maturities in 2019 include $271 million of outstanding borrowings under the Revolving Credit Agreement.

FAIR VALUE (Tables)

FAIR VALUE (Tables)	12 Months Ended
	Dec. 31, 2015
Marketable securities
FAIR VALUE
Schedule of carrying amounts and fair values of assets and liabilities	The carrying amounts and fair values of our marketable securities are as follows (thousands): As of December 31, 2015 As of December 31, 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Marketable securities $ $ $ $
Long-term debt
FAIR VALUE
Schedule of carrying amounts and fair values of assets and liabilities	The carrying amounts and fair values of our debt are as follows (thousands): 2015 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Total debt $ $ $ $

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2015
INCOME TAXES
Schedule of components of net deferred tax liability	Components of our net deferred tax liability are as follows (thousands): 2015 2014 Deferred tax assets Safe harbor lease receivables $ $ Net operating loss carryforwards Alternative minimum tax credit carryforwards Deferred revenues Colowyo Coal- coal contract intangible liability Other Deferred tax liabilities Basis differences- property, plant and equipment Capital credits from other associations Deferred debt prepayment transaction costs Other — Net deferred tax liability $ $
Schedule of reconciliation of statutory federal income tax rate and effective tax rate	2015 2014 2013 Federal income tax expense at statutory rate % % % State income tax expense, net of federal benefit Patronage exclusion Asset retirement obligations Postretirement medical actuarial gains and losses Various book tax differences Regulatory treatment of deferred taxes Effective tax rate % % %

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2015
LEASES
Schedule of minimum future lease revenues	The minimum future lease revenues under these gas tolling arrangements at December 31, 2015 are as follows (thousands): 2016 $ 2017 2018 2019 $
Schedule of operating lease commitments	Our operating lease commitments for this gas tolling arrangement at December 31, 2015 are as follows (thousands): 2016 $ 2017 2018 2019 $

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2015
EMPLOYEE BENEFIT PLANS
Schedule of the postretirement medical benefit and postemployment medical benefit obligations	The postretirement medical benefit and postemployment medical benefit obligations are determined annually by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on the consolidated statements of financial position as follows (thousands): 2015 2014 Postretirement medical benefit obligation at beginning of year $ $ Service cost Interest cost Plan amendments - prior service cost — Benefit payments (net of contributions by participants) Actuarial (gain) loss Postretirement medical benefit obligation at end of year $ $ Postemployment medical benefit obligation at end of year Total postretirement and postemployment medical obligations at end of year $ $
Schedule of the net unrecognized actuarial gains and losses related to the postretirement medical benefit obligation that are included in accumulated other comprehensive income	The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligation are included in accumulated other comprehensive income as follows (thousands): 2015 2014 Actuarial gain included in accumulated other comprehensive income at beginning of year $ $ Reclassification adjustment included in income Plan amendments - prior service cost — Actuarial gain (loss) per actuarial study Actuarial gain (loss) included in accumulated other comprehensive income at end of year $ $
Schedule of the assumptions used in the 2015 actuarial study performed for our postretirement medical benefit obligation	The assumptions used in the 2015 actuarial study performed for our postretirement medical benefit obligation were as follows: Weighted-average discount rate % Initial health care cost trend (2015) % Ultimate health care cost trend % Year that the rate reached the ultimate health care cost trend rate Expected return on plan assets (unfunded) N/A Average remaining service lives of active plan participants (years)
Schedule of changes in the assumed health care cost trend rates and their impact on the accumulated postretirement medical benefit obligation and the net periodic postretirement medical benefit expense	Changes in the assumed health care cost trend rates would impact the accumulated postretirement medical benefit obligation and the net periodic postretirement medical benefit expense as follows (thousands): 1% Increase 1% Decrease Accumulated postretirement medical benefit obligation $ $ Net periodic postretirement medical benefit expense $ $
Schedule of the expected future benefits to be paid related to the postretirement medical benefit obligation	The following are the expected future benefits to be paid related to the postretirement medical benefit obligation (thousands): 2016 $ 2017 2018 2019 2020 2021 and thereafter $

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2015
COMMITMENTS AND CONTINGENCIES
Schedule of costs for purchased power under long-term contracts	Costs under the above electric power purchase agreements for the years ended December 31 were as follows (thousands): 2015 2014 2013 WAPA $ $ $ Basin
Coal
COMMITMENTS AND CONTINGENCIES
Schedule of future minimum commitments	At December 31, 2015 , the annual minimum coal purchases under these contracts are as follows (thousands): 2016 $ 2017 2018 2019 2020 Thereafter $

QUARTERLY FINANCIAL DATA (UNA29

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2015
QUARTERLY FINANCIAL DATA (UNAUDITED)
Schedule of Quarterly Financial Information	First Second Third Fourth Statement of Operations Data (thousands): Quarter Quarter Quarter Quarter Total 2015 Operating revenues $ $ $ $ $ Operating margins Net margins attributable to the Association 2014 Operating revenues $ $ $ $ $ Operating margins Net margins attributable to the Association

ORGANIZATION - Electric Sales (

ORGANIZATION - Electric Sales (Details) MWh in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2015USD ($)MWhcustomer	Dec. 31, 2014USD ($)MWhcustomer	Dec. 31, 2013USD ($)MWh
Electricity sales
Total megawatt-hours sold | MWh	17.8	18.7	18.6
Total electric sales | $	$ 1.2	$ 1.3	$ 1.3
Energy resources, percentage supplied by generation	63.00%	63.00%	64.00%
Members
Electricity sales
Number of Members | customer	44	44
Total Megawatt-Hours | Customer Concentration | Members
Electricity sales
Percentage of benchmark	89.00%	85.00%	86.00%
Electric sales provided by generation | Customer Concentration | Members
Electricity sales
Percentage of benchmark	90.00%	85.00%	86.00%

ORGANIZATION - Long Term Contra

ORGANIZATION - Long Term Contracts (Details) - customer	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Members
Member contracts
Number of Members	44	44
Minimum percent of purchase and receive obligation (as a percent)	95.00%
Long-term Supply Contracts | Members
Member contracts
Notice of termination, period	2 years
Maximum percent of transmission or generation providable by member	5.00%
Number of Members exercising Election option	16
Contracts expiring in 2050
Member contracts
Number of Members	42
Contracts expiring in 2040
Member contracts
Number of Members	2

ORGANIZATION - Customer (Detail

ORGANIZATION - Customer (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)employeecustomeragreement	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Electricity sales
Member electric sales	$ 1,125,699	$ 1,101,471	$ 1,091,103
Number of employees | employee	1,561
Total Revenues | Customer Concentration | United Power, Inc.
Electricity sales
Number of members exceeding 10% of revenues | customer	1
Member electric sales	$ 147,100
Percentage of benchmark	11.00%
Member Revenues | Customer Concentration | United Power, Inc.
Electricity sales
Number of members exceeding 10% of revenues | customer	1
Member electric sales	$ 147,100
Percentage of benchmark	13.10%
Workforce Subject to Collective Bargaining Arrangements | Unionized Employees Concentration Risk
Electricity sales
Number of employees | employee	361
Workforce Subject to Collective Bargaining Arrangements Expiring within One Year | Unionized Employees Concentration Risk
Electricity sales
Number of collective bargaining agreements expiring within one year | agreement	0

SUMMARY OF SIGNIFICANT ACCOUN33

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Regulatory Assets and Liabilities (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)facility	Dec. 31, 2014USD ($)
Regulatory assets and liabilities
Number of jointly owned facilities | facility	3
Regulatory assets and liabilities
Regulatory assets	$ 415,081	$ 426,043
Regulatory liabilities	45,000	45,000
Net regulatory asset	370,081	381,043
Deferred revenue
Regulatory assets and liabilities
Regulatory liabilities	45,000	45,000
Deferred revenue received in 2008
Regulatory assets and liabilities
Regulatory liabilities	10,000
Deferred revenue received in 2011
Regulatory assets and liabilities
Regulatory liabilities	35,000
Craig 3 Lease
Regulatory assets and liabilities
Annual amortization expense	6,500
Deferred income tax expense
Regulatory assets and liabilities
Regulatory assets	28,629	17,230
Deferred prepaid lease expense | Craig 3 Lease
Regulatory assets and liabilities
Regulatory assets	16,183	22,656
Deferred prepaid lease expense | Springerville 3 Lease
Regulatory assets and liabilities
Regulatory assets	92,878	95,168
Annual amortization expense	$ 2,300
Remaining amortization period	47 years
Goodwill | TCP
Regulatory assets and liabilities
Regulatory assets	$ 60,541	63,390
Annual amortization expense	$ 2,800
Remaining amortization period	25 years
Goodwill | Colowyo Coal
Regulatory assets and liabilities
Regulatory assets	$ 41,327	43,526
Remaining amortization period	44 years
Deferred debt prepayment transaction costs
Regulatory assets and liabilities
Regulatory assets	$ 175,444	$ 184,073
Annual amortization expense	$ 8,600
Remaining amortization period	21 years 4 months 24 days
Other
Regulatory assets and liabilities
Regulatory assets	$ 79

SUMMARY OF SIGNIFICANT ACCOUN34

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Segments and Business Combinations (Details)	12 Months Ended
	Dec. 31, 2015USD ($)segment
SEGMENT REPORTING:
Number of operating segments	1
Number of reportable segments	1
BUSINESS COMBINATIONS:
Goodwill recognized for asset acquisitions | $	$ 0

SUMMARY OF SIGNIFICANT ACCOUN35

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Electric Plant and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
ELECTRIC PLANT AND DEPRECIATION:
Interest rates charged during construction (as a percent)	4.40%	4.70%	4.80%
Interest capitalized during construction	$ 13.5	$ 15	$ 13

SUMMARY OF SIGNIFICANT ACCOUN36

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Investments in Other Associations (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Investments in other associations
Investment in other associations (in dollars)	$ 123,686	$ 117,976
Basin Electric Power Cooperative
Investments in other associations
Investment in other associations (in dollars)	84,875	80,250
National Rural Utilities Cooperative Finance Corporation [Member]
Investments in other associations
Investment in other associations (in dollars)	26,808	26,695
CoBank, ACB
Investments in other associations
Investment in other associations (in dollars)	6,212	5,518
Western Fuels Association
Investments in other associations
Investment in other associations (in dollars)	2,275	2,338
Other
Investments in other associations
Investment in other associations (in dollars)	$ 3,516	$ 3,175

SUMMARY OF SIGNIFICANT ACCOUN37

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Investments in and Advances to Coal Mines (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Investments in and advances to coal mines
Investments in and advances to coal mines	$ 16,221	$ 15,016
Trapper Mining
Investments in and advances to coal mines
Investment in coal mine	14,072	13,650
Dry Fork Mine
Investments in and advances to coal mines
Advances	$ 2,149	$ 1,366

SUMMARY OF SIGNIFICANT ACCOUN38

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Restricted Cash and Investments (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014	Dec. 31, 2009
Restricted cash and investments
Restricted cash and investments - current		$ 9,530		$ 9,784
Restricted cash and investments - noncurrent		1,000		39,376
Restricted cash and investments		10,530		49,160
Restricted cash released due to settlement		29,113	$ (390)
Securities pledged as collateral
Restricted cash and investments
Restricted cash and investments - current		8,671		9,192
Restricted cash and investments - noncurrent				8,995
Funds restricted by contract
Restricted cash and investments
Restricted cash and investments - current		859		592
Restricted cash and investments - noncurrent		1,000		1,000
BNSF settlement
Restricted cash and investments
Restricted cash and investments - noncurrent				$ 29,381
Restricted cash and investments					$ 29,400
Restricted cash released due to settlement	$ 29,400
Colowyo Bonds | US Treasury Notes | Securities pledged as collateral
Restricted cash and investments
Investments in securities pledged as collateral		$ 8,700

SUMMARY OF SIGNIFICANT ACCOUN39

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Marketable Securities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Director and Executive Deferred Compensation Plans
Marketable securities
Available-for-sale securities, amortized cost	$ 1,000	$ 1,100
Available-for-sale securities, fair value	1,200	1,400
Net unrealized gain	129	254
Securities pledged as collateral | Colowyo Bonds | US Treasury Notes
Marketable securities
Investments in securities pledged as collateral carried at amortized cost	8,700	18,200
Defeasance investment, principal	7,400	16,400
Unamortized premium	113	371
Restricted cash	$ 1,100	$ 1,400

SUMMARY OF SIGNIFICANT ACCOUN40

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
INVENTORIES:
Coal inventory	$ 59,277	$ 40,673
Owned Generating Stations
INVENTORIES:
Coal inventory	$ 42,200	22,200
LIFO inventory liquidation		$ 596

SUMMARY OF SIGNIFICANT ACCOUN41

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Deferred Charges (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Other deferred charges
Preliminary surveys and investigations	$ 107,146	$ 131,693
Advances to operating agents of jointly owned facilities	11,537	20,567
Other	3,852	3,940
Total other deferred charges	122,535	$ 156,200
Holcomb Station Project
Other deferred charges
Preliminary surveys and investigations	86,700
Eastern Plains Transmission Project
Other deferred charges
Preliminary surveys and investigations	$ 28,500

SUMMARY OF SIGNIFICANT ACCOUN42

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Debt Issuance Costs (Details) - ASU 2015-03 and 2015-15 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Long-term debt
Debt Issuance Costs
Implementation effect of adoption	$ (21.2)
Retrospective adjustments due to change in accounting principle		$ (22.3)
Other deferred charges
Debt Issuance Costs
Implementation effect of adoption	$ 21.2
Retrospective adjustments due to change in accounting principle		$ 22.3

SUMMARY OF SIGNIFICANT ACCOUN43

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Aggregate carrying amounts of asset retirement obligations
Asset retirement obligation at beginning of year	$ 53,754	$ 52,585
Liabilities incurred	1,802	1,366
Liabilities settled	(3,028)	(5,729)
Accretion expense	3,324	2,250
Change in cash flow estimate	(637)	3,282
Asset retirement obligation at end of year	$ 55,215	$ 53,754

SUMMARY OF SIGNIFICANT ACCOUN44

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Memberships (Details) - Members $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)customer	Dec. 31, 2014USD ($)customer
Memberships
Number of Members | customer	44	44
Membership fee per member | $	$ 5	$ 5

SUMMARY OF SIGNIFICANT ACCOUN45

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Interchange Power (Details) - Interchange Power - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Purchased Power Expense
INTERCHANGE POWER:
Net interchange activity, expense (income)	$ 108,630
Accounts Payable
INTERCHANGE POWER:
Interchange liability	$ 1,600,000	$ 1,500,000
Accounts Payable | Purchased Power Expense
INTERCHANGE POWER:
Net interchange activity, expense (income)		$ (452,500)	$ 2,600,000

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Electric Plant (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Electric Plant
Electric plant in service (at cost)	$ 5,486,518	$ 5,193,236
Construction work in progress	216,279	206,097
Less allowances for depreciation and amortization	(2,240,732)	(2,129,173)
Net electric plant	3,462,065	3,270,160
Electric Plant
Electric Plant
Generation plant	3,498,248	3,379,305
Transmission plant	1,294,151	1,161,462
General plant	430,842	392,963
Other plant	263,277	259,506
Electric plant in service (at cost)	5,486,518	5,193,236
Construction work in progress	216,279	206,097
Less allowances for depreciation and amortization	(2,240,732)	(2,129,173)
Net electric plant	$ 3,462,065	$ 3,270,160
Generation plant | Minimum
Electric Plant
Annual Depreciation Rate (as a percent)	0.44%
Generation plant | Maximum
Electric Plant
Annual Depreciation Rate (as a percent)	3.16%
Transmission plant | Minimum
Electric Plant
Annual Depreciation Rate (as a percent)	2.00%
Transmission plant | Maximum
Electric Plant
Annual Depreciation Rate (as a percent)	2.88%
General plant | Minimum
Electric Plant
Annual Depreciation Rate (as a percent)	3.00%
General plant | Maximum
Electric Plant
Annual Depreciation Rate (as a percent)	33.33%
Other Plant | Minimum
Electric Plant
Annual Depreciation Rate (as a percent)	2.80%
Other Plant | Maximum
Electric Plant
Annual Depreciation Rate (as a percent)	5.60%

PROPERTY, PLANT AND EQUIPMENT47

PROPERTY, PLANT AND EQUIPMENT - Construction Commitments (Details) - Electric Plant - Construction Commitments $ in Millions	Dec. 31, 2015USD ($)
Construction commitments
Total obligation	$ 82.8
Future commitments
2,016	63.6
2,017	14.3
2,018	$ 4.9

PROPERTY, PLANT AND EQUIPMENT48

PROPERTY, PLANT AND EQUIPMENT - Jointly Owned Facilities (Details) $ in Thousands	Dec. 31, 2015USD ($)
Jointly owned facilities
Electric plant in service	$ 817,974
Accumulated depreciation	579,219
Construction work in progress	$ 37,871
Yampa
Jointly owned facilities
Tri-State share (as a percent)	24.00%
Electric plant in service	$ 345,937
Accumulated depreciation	229,464
Construction work in progress	$ 23,518
MBPP
Jointly owned facilities
Tri-State share (as a percent)	24.13%
Electric plant in service	$ 389,283
Accumulated depreciation	288,386
Construction work in progress	$ 13,791
San Juan Project
Jointly owned facilities
Tri-State share (as a percent)	8.20%
Electric plant in service	$ 82,754
Accumulated depreciation	61,369
Construction work in progress	$ 562

PROPERTY, PLANT AND EQUIPMENT49

PROPERTY, PLANT AND EQUIPMENT - Other Plant (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Other Plant Assets
Other plant assets	$ 227,957	$ 210,694
Accumulated depreciation and depletion	(73,471)	(58,117)
Net other plant	$ 154,486	152,577
Western Fuels Colorado (“WFC”)
Other Plant Assets
Ownership interest held by parent (as a percent)	100.00%
Fort Union Mine
Other Plant Assets
Ownership interest in land and rights to the mine (as a percent)	50.00%
Mine assets
Other Plant Assets
Accumulated depreciation and depletion	$ (67,601)	(52,580)
Net other plant	148,087	146,788
Mine assets | Colowyo Mine
Other Plant Assets
Other plant assets	166,157	152,549
Mine assets | New Horizon Mine
Other Plant Assets
Other plant assets	48,373	44,812
Mine assets | Fort Union Mine
Other Plant Assets
Other plant assets	1,158	2,007
Non-utility assets
Other Plant Assets
Other plant assets	12,269	11,326
Accumulated depreciation and depletion	(5,870)	(5,537)
Net other plant	$ 6,399	$ 5,789

INTANGIBLES - Intangible Assets

INTANGIBLES - Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2011
INTANGIBLE ASSETS:
Amortization of intangible asset	$ 7,324	$ 7,324	$ 7,324
Future amortization of intangible assets
Intangible assets, net	25,634	32,958
Purchase Power Agreement
INTANGIBLE ASSETS:
Amortization of intangible asset	$ 7,300	$ 7,300	$ 7,300
Intangible asset, remaining life (in years)	4 years
Future amortization of intangible assets
2,016	$ 7,324
2,017	7,324
2,018	7,324
2,019	3,662
Intangible assets, net	$ 25,634
TCP | Purchase Power Agreement
INTANGIBLE ASSETS:
Intangible asset				$ 55,500

INTANGIBLES - Intangible Liabil

INTANGIBLES - Intangible Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2011
Intangible Liabilities
Amortization benefit	$ 3,200	$ 3,200	$ 2,500
Remaining amortization period	2 years
Intangible liabilities, future amortization
2,016	$ 3,125
2,017	3,096
Intangible liability, total	$ 6,221	9,424
Colowyo Coal
Intangible Liabilities
Intangible liability				$ 18,000
Intangible liabilities, future amortization
Intangible liability, total		$ 9,400

LONG-TERM DEBT - Components (De

LONG-TERM DEBT - Components (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)instrument	Dec. 31, 2014USD ($)
Unsecured debt
Number of unsecured debt instruments | instrument	2
Unsecured notes	$ 55,900
Long-term debt, components
Total debt	3,371,679	$ 3,242,470
Less debt issuance costs	(21,201)	(22,254)
Less debt discounts	(8,739)	(8,894)
Plus debt premiums	23,218	26,726
Total debt adjusted for discounts, premiums and debt issuance costs	3,364,957	3,238,048
Less current maturities	(91,419)	(92,802)
Long-term debt	3,273,538	3,145,246
3.66% to 8.08% CFC, due through 2028
Long-term debt, components
Total debt	$ 86,979	92,977
Interest rate terms
Stated interest rate, minimum (as a percent)	3.66%
Stated interest rate, maximum (as a percent)	8.08%
Average interest rate (as a percent)	5.96%
2.63% to 6.17% CoBank, ACB, due through 2042
Long-term debt, components
Total debt	$ 278,086	287,798
Interest rate terms
Stated interest rate, minimum (as a percent)	2.63%
Stated interest rate, maximum (as a percent)	6.17%
Average interest rate (as a percent)	4.35%
First Mortgage Bonds, Series 2014E-1, 3.70% due 2024
Long-term debt, components
Total debt	$ 250,000	250,000
Interest rate terms
Stated interest rate (as a percent)	3.70%
First Mortgage Bonds, Series 2014E-2, 4.70% due 2044
Long-term debt, components
Total debt	$ 250,000	250,000
Interest rate terms
Stated interest rate (as a percent)	4.70%
First Mortgage Bonds, Series 2010A, 6.00% due 2040
Long-term debt, components
Total debt	$ 500,000	500,000
Interest rate terms
Stated interest rate (as a percent)	6.00%
First Mortgage Obligation, Series 2014B, Tranche 1, 3.90%, due through 2033
Long-term debt, components
Total debt	$ 180,000	180,000
Interest rate terms
Stated interest rate (as a percent)	3.90%
First Mortgage Obligation Series 2014B, Tranche 2, 4.30%, due through 2039
Long-term debt, components
Total debt	$ 20,000	20,000
Interest rate terms
Stated interest rate (as a percent)	4.30%
First Mortgage Obligation Series 2014B, Tranche 3, 4.45%, due through 2045
Long-term debt, components
Total debt	$ 550,000	550,000
Interest rate terms
Stated interest rate (as a percent)	4.45%
First Mortgage Obligation, Series 2009C, Tranche 1, 6.00%, due through 2019
Long-term debt, components
Total debt	$ 108,571	135,714
Interest rate terms
Stated interest rate (as a percent)	6.00%
First Mortgage Obligation, Series 2009C, Tranche 2, 6.31%, due through 2021
Long-term debt, components
Total debt	$ 110,000	110,000
Interest rate terms
Stated interest rate (as a percent)	6.31%
Variable rate CFC, as determined by CFC, 2.90% average for 2015, due through 2026
Long-term debt, components
Total debt	$ 644	687
Interest rate terms
Average interest rate (as a percent)	2.90%
Variable rate CFC, LIBOR-based term loan, 1.48% average for 2015, due through 2049
Long-term debt, components
Total debt	$ 102,220	102,220
Variable rate CFC, LIBOR-based term loan, 1.48% average for 2015, due through 2049 | LIBOR
Interest rate terms
Average interest rate (as a percent)	1.48%
Variable rate CoBank, ACB, LIBOR-based term loan, 1.74% average for 2015, due through 2044
Long-term debt, components
Total debt	$ 102,220	102,220
Variable rate CoBank, ACB, LIBOR-based term loan, 1.74% average for 2015, due through 2044 | LIBOR
Interest rate terms
Average interest rate (as a percent)	1.74%
Revolving Credit Agreement
Long-term debt, components
Total debt	$ 271,000	50,000
Revolving Credit Agreement | LIBOR
Interest rate terms
Average interest rate (as a percent)	1.25%
Pollution control revenue bonds, City of Gallup, NM, 5.00%, Series 2005, due through 2017
Long-term debt, components
Total debt	$ 10,815	15,840
Interest rate terms
Stated interest rate (as a percent)	5.00%
Pollution control revenue bonds, Moffat County, CO Variable Rate Demand Series 2009, due 2036
Long-term debt, components
Total debt	$ 46,800	46,800
Interest rate terms
Average interest rate (as a percent)	0.06%
Springerville certificates, Series A, 6.04%, due through 2018
Long-term debt, components
Total debt	$ 89,968	124,779
Interest rate terms
Stated interest rate (as a percent)	6.04%
Springerville certificates, Series B, 7.14%, due through 2033
Long-term debt, components
Total debt	$ 405,000	405,000
Interest rate terms
Stated interest rate (as a percent)	7.14%
Colowyo Bonds
Long-term debt, components
Total debt	$ 7,693	15,899
Interest rate terms
Stated interest rate (as a percent)	10.19%
Other
Long-term debt, components
Total debt	$ 1,683	$ 2,536

LONG-TERM DEBT - Other Informat

LONG-TERM DEBT - Other Information (Details) - USD ($)	1 Months Ended
	Nov. 30, 2015	Sep. 30, 2015	Dec. 31, 2015	Jul. 30, 2015	Dec. 31, 2014	Oct. 30, 2014
Debt
Outstanding borrowings			$ 3,371,679,000		$ 3,242,470,000
Series 2014 Bonds
Debt
Face amount of debt issued						$ 500,000,000
Series 2014 Bonds | Registration Rights Agreement
Debt
Face amount of debt exchanged				$ 500,000,000
Proceeds from Exchange of Long-term Debt		$ 0
Pollution control revenue bonds, Moffat County, CO Variable Rate Demand Series 2009, due 2036
Debt
Outstanding borrowings			46,800,000		46,800,000
Revolving Credit Agreement
Debt
Maximum borrowing capacity			750,000,000
Outstanding borrowings			271,000,000		$ 50,000,000
Available borrowing capacity			$ 431,000,000
Revolving Credit Agreement | Pollution control revenue bonds, Moffat County, CO Variable Rate Demand Series 2009, due 2036 | Bank of America
Debt
Letter of credit, period	364 days

LONG-TERM DEBT - Annual Maturit

LONG-TERM DEBT - Annual Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Annual maturities of total debt adjusted for debt issuance costs, discounts and premiums
2,016	$ 91,419
2,017	108,037
2,018	78,322
2,019	368,776
2,020	84,834
Thereafter	2,633,569
Total debt adjusted for discounts, premiums and debt issuance costs	3,364,957	$ 3,238,048
Revolving Credit Agreement
Annual maturities of total debt adjusted for debt issuance costs, discounts and premiums
2,019	$ 271,000

FAIR VALUE (Details)

FAIR VALUE (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Carrying Amount
Fair value:
Long-term debt	$ 3,371,679	$ 3,242,470
Carrying Amount | Recurring | Level 1
Fair value:
Marketable securities	1,022	1,095
Estimated Fair Value | Level 2
Fair value:
Long-term debt	3,616,946	3,716,513
Estimated Fair Value | Recurring | Level 1
Fair value:
Marketable securities	$ 1,151	$ 1,349

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
INCOME TAXES
Income tax expense or benefit	$ 0	$ 0	$ 0

INCOME TAXES - Net Deferred Tax

INCOME TAXES - Net Deferred Tax Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets
Safe harbor lease receivables	$ 35,945	$ 38,218
Net operating loss carryforwards	152,936	131,935
Alternative minimum tax credit carryforwards	3,834	3,834
Deferred Tax Assets, Deferred Income	16,933	16,933
Colowyo Coal- coal contract intangible liability	2,341	3,547
Other	35,332	46,856
Deferred tax assets, total	247,321	241,323
Deferred tax liabilities
Basis differences- property, plant and equipment	160,494	152,497
Capital credits from other associations	38,663	36,790
Deferred debt prepayment transaction costs	66,020	69,266
Other	10,773
Deferred tax liabilities, total	275,950	258,553
Net deferred tax liability	(28,629)	(17,230)
Deferred tax treatment of regulatory assets
Regulatory assets	415,081	426,043
Deferred income tax expense
Deferred tax treatment of regulatory assets
Increase in net deferred tax liability not recognized as expense	11,400
Regulatory assets	$ 28,629	$ 17,230

INCOME TAXES - Effective Tax Ra

INCOME TAXES - Effective Tax Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation between the statutory federal income tax rate and the effective tax rate
Federal income tax expense at statutory rate	35.00%	35.00%	35.00%
State income tax expense, net of federal benefit	2.63%	2.63%	2.63%
Patronage exclusion	(37.63%)	(37.63%)	(37.63%)
Asset retirement obligations	(0.58%)	1.40%	(6.74%)
Postretirement medical actuarial gains and losses	(1.09%)	2.44%	0.18%
Various book tax differences	2.84%	4.52%	8.93%
Regulatory treatment of deferred taxes	(1.17%)	(8.36%)	(2.37%)
Effective tax rate	0.00%	0.00%	0.00%

INCOME TAXES - Operating Loss a

INCOME TAXES - Operating Loss and Tax Credit Carryforwards (Details) - USD ($) $ in Thousands	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
Carryforwards
Net margins attributable to the Association	$ (21,299)	$ 48,302	$ 6,284	$ 20,126	$ (4,099)	$ 40,451	$ 3,373	$ 24,511	$ 53,413	$ 64,236	$ 72,912
Federal
Carryforwards
Net operating loss carryforwards	406,400								406,400
Alternative Minimum Tax Credit Carryforwards
Carryforwards
Tax credit carryforwards	$ 3,800								$ 3,800

LEASES - Lessor (Details)

LEASES - Lessor (Details) $ in Thousands	9 Months Ended	12 Months Ended			36 Months Ended	48 Months Ended
	Sep. 30, 2014facilityMW	Dec. 31, 2015USD ($)facilityMW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Apr. 30, 2013	Apr. 30, 2013
Operating leases - LESSOR
Generating units, accumulated depreciation | $		$ 2,240,732	$ 2,129,173
Gas tolling arrangement
Operating leases - LESSOR
Lease revenues | $		30,100	30,600	$ 25,800
Generation plant | $		223,000	232,000
Generating units, accumulated depreciation | $		$ 106,000	$ 108,000
Gas tolling arrangement | J. M. Shafer Generating Station
Operating leases - LESSOR
Megawatt usage | MW		272
Gas tolling arrangement | J. M. Shafer Generating Station | Third Party
Operating leases - LESSOR
Megawatt usage | MW		122
Gas tolling arrangement | Knutson Generating Station
Operating leases - LESSOR
Contract suspension (in years)					3 years
Gas tolling arrangement | Knutson Generating Station | Third Party
Operating leases - LESSOR
Number of generating station units		2
Gas tolling arrangement | Limon Generating Station
Operating leases - LESSOR
Number of generating station units		2
Contract suspension (in years)						4 years
Gas tolling arrangement | Limon Generating Station | Third Party
Operating leases - LESSOR
Number of generating station units		1
Gas tolling arrangement | Pyramid Generating Station
Operating leases - LESSOR
Megawatt usage | MW	40
Number of generating station units	4
Gas tolling arrangement | Pyramid Generating Station | Third Party
Operating leases - LESSOR
Number of generating station units	1

LEASES - Lessor - Minimum Lease

LEASES - Lessor - Minimum Lease Payments Receivable (Details) - Gas tolling arrangement $ in Thousands	Dec. 31, 2015USD ($)
Minimum future lease revenues
2,016	$ 18,745
2,017	11,734
2,018	11,734
2,019	5,867
Total minimum future lease revenues	$ 48,080

LEASES - Lessee (Details)

LEASES - Lessee (Details) - Gas tolling arrangement - Brush Generating Station $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)MW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Operating leases - LESSEE
Megawatt usage | MW	70
Term of agreement	10 years
Rent expense	$ 5,300	$ 5,300	$ 5,300
Operating lease commitments
2,016	5,519
2,017	5,678
2,018	5,855
2,019	6,031
Total operating lease commitments	$ 23,083

RELATED PARTIES (Details)

RELATED PARTIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
RELATED PARTIES
Capital credits from cooperatives	$ 9,189	$ 8,684	$ 10,922
Trapper Mining
RELATED PARTIES
Tri-State share (as a percent)	26.57%	26.57%	26.57%
Investment in coal mine	$ 14,100	$ 13,700
Capital credits from cooperatives	531	532	$ 532
Trapper Mining | Coal
RELATED PARTIES
Purchases	$ 17,700	$ 30,600	$ 16,900
Trapper Mining | Coal | Yampa
RELATED PARTIES
Percent of purchases supplied by related party	26.00%	35.00%	24.00%

EMPLOYEE BENEFIT PLANS - Define

EMPLOYEE BENEFIT PLANS - Defined Benefit and Defined Contribution Plans (Details)	Jan. 01, 2015	Jan. 01, 2014	Jan. 01, 2013	May. 31, 2013USD ($)	Dec. 31, 2015USD ($)employee	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
DEFINED BENEFIT PLAN
Number of employees | employee					1,561
DEFINED CONTRIBUTION PLAN
Employee contribution, maximum percentage of eligible earnings					100.00%
Contributions made					$ 3,000,000	$ 2,900,000	$ 3,000,000
Collective bargaining agreements and their bargaining unit employees
DEFINED BENEFIT PLAN
Number of employees | employee					361
DEFINED CONTRIBUTION PLAN
Contributions made					$ 0
Non-bargaining unit employees, other than the 216 employees of Colowyo Coal
DEFINED CONTRIBUTION PLAN
Employer contribution, maximum percentage of eligible earnings					1.00%
Non-bargaining unit employees, only the 216 employees of Colowyo Coal
DEFINED CONTRIBUTION PLAN
Employer contribution, maximum percentage of eligible earnings					7.00%
Maximum | Non-bargaining unit employees, only the 216 employees of Colowyo Coal
DEFINED CONTRIBUTION PLAN
Employer matching contribution, maximum percentage of employee contributions					5.00%
RS Plan
DEFINED BENEFIT PLAN
Our contributions represent more than (true) or less than (false) 5 percent of total contributions					false	false	false
Contributions made each year					$ 22,900,000	$ 21,500,000	$ 92,600,000
Plan funded status	At least 80 percent	At least 80 percent
RS Plan Contribution Prepayment Option
DEFINED BENEFIT PLAN
Prepayment amount, multiple of annual required contribution (as a percent)			2.50%
Reduction in the annual contribution (as a percent)			25.00%
Reduced annual contribution period					15 years
Contribution prepayment				$ 71,200,000
Amortization period of prepayment			13 years
Colowyo Coal
DEFINED BENEFIT PLAN
Number of employees | employee					216

EMPLOYEE BENEFIT PLANS - Postre

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other Than Pensions, Plans, Amendments and Obligations (Details)	12 Months Ended
	Dec. 31, 2015USD ($)planOption	Dec. 31, 2014USD ($)
Postretirement medical benefit and postemployment medical benefit obligations
Threshold percentage, unrecognized amount of actuarial gains and losses as a percentage of projected benefit obligation	10.00%
Medical Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3
Postretirement medical benefit and postemployment medical benefit obligations
Postretirement medical benefit obligation at beginning of year	$ 8,131,000
Postretirement and/or postemployment medical benefit obligation at end of year	$ 6,901,000	$ 8,131,000
Postretirement Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	2
Attained age	55 years
Prior service cost due to amendment	$ (896,000)
Postretirement medical benefit and postemployment medical benefit obligations
Postretirement medical benefit obligation at beginning of year	7,713,000	2,957,000
Service cost	593,000	582,000
Interest cost	270,000	256,000
Plan amendments - prior service cost	(896,000)
Benefit payments (net of contributions by participants)	(325,000)	(276,000)
Actuarial (gain) loss	(632,000)	4,194,000
Postretirement and/or postemployment medical benefit obligation at end of year	$ 6,723,000	7,713,000
Postemployment Medical Benefit Plans Amendment
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Elimination of coverage, age cut-off	65 years
Number of plan options | Option	3
Age to qualify for plan options	65 years
Percentage reduction in liability	11.50%
Prior service cost due to amendment	$ (896,214)
Postretirement medical benefit and postemployment medical benefit obligations
Plan amendments - prior service cost	$ (896,214)
Postemployment Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3
Postretirement medical benefit and postemployment medical benefit obligations
Postretirement medical benefit obligation at beginning of year	$ 418,000
Postretirement and/or postemployment medical benefit obligation at end of year	$ 178,000	$ 418,000

EMPLOYEE BENEFIT PLANS - Post66

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other Than Pensions, Actuarial Gains and Losses, and Assumptions (Details) - Postretirement Medical Benefit Plans - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Net unrecognized actuarial gains and losses related to the postretirement medical benefit obligation are included in accumulated other comprehensive income
Actuarial gain included in accumulated other comprehensive income at beginning of year	$ (1,082)	$ 3,081
Reclassification adjustment included in income	14	31
Plan amendments - prior service cost	896
Actuarial gain (loss) per actuarial study	632	(4,194)
Actuarial gain (loss) included in accumulated other comprehensive income at end of year	$ 460	$ (1,082)
Assumptions used
Weighted-average discount rate	3.90%
Initial health care cost trend (2015)	8.00%
Ultimate health care cost trend	4.50%
Year that the rate reached the ultimate health care cost trend rate	2,025
Average remaining service lives of active plan participants (years)	12 years 1 month 2 days
Impact of changes in the assumed health care cost trend rates upon the accumulated postretirement medical benefit obligation and the net periodic postretirement medical benefit expense
1% increase, Accumulated postretirement medical benefit obligation	$ 709
1% decrease, Accumulated postretirement medical benefit obligation	(620)
1% increase, Net periodic postretirement medical benefit expense	131
1% decrease, Net periodic postretirement medical benefit expense	$ (109)

EMPLOYEE BENEFIT PLANS - Expect

EMPLOYEE BENEFIT PLANS - Expected Future Benefits (Details) - Postretirement Medical Benefit Plans $ in Thousands	Dec. 31, 2015USD ($)
Expected future benefits to be paid related to the postretirement medical benefit obligation
2,016	$ 362
2,017	433
2,018	473
2,019	535
2,020	561
2021 and thereafter	2,600
Total	$ 4,964

VARIABLE INTEREST ENTITIES - Co

VARIABLE INTEREST ENTITIES - Consolidated Entities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Consolidated Variable Interest Entities
Noncontrolling interest included in consolidated statements of financial position (in dollars)	$ 108,757	$ 109,302
Depreciation and amortization (in dollars)	152,718	128,712	$ 121,818
Interest expense (in dollars)	$ 142,570	142,357	149,463
Springerville Partnership | Primary Beneficiary
Consolidated Variable Interest Entities
Equity interest (as a percent)	51.00%
General partner interest (as a percent)	1.00%
Ownership interest held by noncontrolling interest (as a percent)	49.00%
Noncontrolling interest included in consolidated statements of financial position (in dollars)	$ 108,800	109,300
Depreciation and amortization (in dollars)	21,000	21,000
Interest expense (in dollars)	32,300	34,100	$ 35,900
Springerville Partnership | Primary Beneficiary | Electric Plant
Consolidated Variable Interest Entities
Assets of variable interest entity included in consolidated statements of financial position (in dollars)	853,300	874,400
Springerville Partnership | Primary Beneficiary | Long-term debt
Consolidated Variable Interest Entities
Liabilities of variable interest entity included in consolidated statements of financial position (in dollars)	511,000	548,100
Springerville Partnership | Primary Beneficiary | Accrued interest included in long-term debt
Consolidated Variable Interest Entities
Liabilities of variable interest entity included in consolidated statements of financial position (in dollars)	$ 14,300	$ 15,200
Springerville Partnership | Primary Beneficiary | Springerville 3 Lease
Consolidated Variable Interest Entities
Percentage of financial and other support provided	100.00%
Springerville Partnership | Springerville Unit 3 Holding LLC
Consolidated Variable Interest Entities
Ownership interest held by parent (as a percent)	100.00%

VARIABLE INTEREST ENTITIES - Un

VARIABLE INTEREST ENTITIES - Unconsolidated Entities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Unconsolidated Variable Interest Entities
Investment in other associations (in dollars)	$ 123,686	$ 117,976
Western Fuels Association
Unconsolidated Variable Interest Entities
Investment in other associations (in dollars)	2,275	2,338
WFW | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments in other associations
Unconsolidated Variable Interest Entities
Investment in other associations (in dollars)	2,300	2,300
Trapper Mining
Unconsolidated Variable Interest Entities
Investment in coal mine	14,072	13,650
Trapper Mining | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments in other associations
Unconsolidated Variable Interest Entities
Investment in coal mine	$ 14,100	$ 13,700
Western Fuels Association | WFW | Class AA shares
Unconsolidated Variable Interest Entities
Ownership interest held by parent (as a percent)	100.00%
Western Fuels Association | WFW | Class BB Shares
Unconsolidated Variable Interest Entities
Ownership interest held by parent (as a percent)	75.00%
MBPP
Unconsolidated Variable Interest Entities
Tri-State share (as a percent)	24.13%
MBPP | Unconsolidated Variable Interest Entity - not primary beneficiary
Unconsolidated Variable Interest Entities
Tri-State share (as a percent)	24.13%
MBPP | Basin Electric Power Cooperative
Unconsolidated Variable Interest Entities
Participating interest (as a percent)	42.27%
MBPP | WFW | Class BB Shares
Unconsolidated Variable Interest Entities
Ownership interest held by noncontrolling interest (as a percent)	25.00%
Yampa
Unconsolidated Variable Interest Entities
Tri-State share (as a percent)	24.00%
Yampa | Trapper Mining | Unconsolidated Variable Interest Entity - not primary beneficiary
Unconsolidated Variable Interest Entities
Tri-State share (as a percent)	26.57%

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Sales Commitments (Details)	12 Months Ended
	Dec. 31, 2015MW
Public Service Company of Colorado | Supply Contracts
Sales commitments
Megawatts, summer season	125
Megawatts, winter season	175
Salt River Project Agricultural Improvement and Power District | Long-term Supply Contracts
Sales commitments
Megawatts	100

COMMITMENTS AND CONTINGENCIES71

COMMITMENTS AND CONTINGENCIES - Coal Purchase Requirements (Details) - Coal $ in Thousands	Dec. 31, 2015USD ($)
Annual minimum coal purchases under contracts
2,016	$ 102,535
2,017	105,457
2,018	103,389
2,019	104,686
2,020	82,612
Thereafter	63,396
Total obligation	$ 562,075

COMMITMENTS AND CONTINGENCIES72

COMMITMENTS AND CONTINGENCIES - Electric Power Purchase Agreements (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)statejurisdictioncontractMW	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Electric Power Purchase Agreements
Number of power marketing administrations of the U.S. Department of Energy | jurisdiction	4
WAPA
Electric Power Purchase Agreements
Number of contracts	3
Costs under the above electric power purchase agreements | $	$ 89,986	$ 91,639	$ 91,038
Basin Electric Power Cooperative
Electric Power Purchase Agreements
Megawatts purchased | MW	225
Costs under the above electric power purchase agreements | $	$ 127,500	$ 132,649	$ 136,223
Loveland Area Project | WAPA
Electric Power Purchase Agreements
Number of contracts	1
Salt Lake City Area Integrated Projects | WAPA
Electric Power Purchase Agreements
Number of contracts	2
WAPA
Electric Power Purchase Agreements
Number of power marketing administrations of the U.S. Department of Energy | jurisdiction	1
Number of states in which entity operates | state	15

COMMITMENTS AND CONTINGENCIES73

COMMITMENTS AND CONTINGENCIES - New Mexico Regulatory (Details) - Members $ in Millions	Oct. 02, 2014USD ($)	Oct. 19, 2012customer	Nov. 30, 2012customer	Dec. 31, 2015customer	Dec. 31, 2015USD ($)customer	Dec. 31, 2014USD ($)customer
Rate setting
Number of Members					44	44
New Mexico Public Regulation Commission ("NMPRC") | A-37 Wholesale Rate
Rate setting
Number of Members		44
Revenue increase, % of revenue collected		4.90%
New Mexico Public Regulation Commission ("NMPRC") | A-37 Wholesale Rate | NEW MEXICO
Rate setting
Number of Members		12
Revenue increase, % of revenue collected		6.70%
Number of protests filed			3
New Mexico Public Regulation Commission ("NMPRC") | A-37 and A-38 Temporary Rate Rider | NEW MEXICO
Rate setting
Additional annualized revenue to be recovered under agreement | $	$ 7
Rate change, impact of lower rate | $					$ 10.7	$ 16.4
New Mexico Public Regulation Commission ("NMPRC") | A-39 Wholesale Rate | NEW MEXICO
Rate setting
Number of protests filed				0

COMMITMENTS AND CONTINGENCIES74

COMMITMENTS AND CONTINGENCIES - Colorado Regulatory (Details) - Members - customer	Dec. 08, 2015	Mar. 04, 2013	Nov. 30, 2014	Dec. 31, 2015	Dec. 31, 2014
Rate setting
Number of Members				44	44
COLORADO | A-37 Wholesale Rate | Colorado Public Utilities Commission ("COPUC")
Rate setting
Number of complaints filed		3
Number of Members filing joint motion to withdraw the complaint and dismiss the proceeding	3
COLORADO | Temporary Optional Rate Agreement
Rate setting
Number of Members			3

COMMITMENTS AND CONTINGENCIES75

COMMITMENTS AND CONTINGENCIES - Purchase Option and Development Agreement (Details) $ in Thousands	Dec. 16, 2010facilityMW	Jul. 26, 2007USD ($)	Dec. 31, 2008USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Purchase Option and Development Agreement
Preliminary surveys and investigations				$ 107,146	$ 131,693
Holcomb Station Project
Purchase Option and Development Agreement
Preliminary surveys and investigations				86,700
Holcomb Station Project | Other Deferred Charges | Purchase Option and Development Agreement
Purchase Option and Development Agreement
Preliminary surveys and investigations				$ 86,700
Holcomb Station Project | Sunflower and other Sunflower parties | Purchase Option and Development Agreement
Purchase Option and Development Agreement
Total amount of option payments		$ 55,000
Option payments made for development rights		$ 25,000	$ 5,000
Number of new coal-fired generating units if permit issued | facility	1
Generating unit capacity (in megawatts) | MW	895

COMMITMENTS AND CONTINGENCIES76

COMMITMENTS AND CONTINGENCIES - Las Conchas Fire (Details) - Damages from fire	Oct. 28, 2015USD ($)	Jun. 10, 2013USD ($)	Jun. 30, 2011plaintiff	Dec. 31, 2015USD ($)
Litigation information
Number of plaintiff groups | plaintiff			6
Pending litigation
Litigation information
Liability insurance coverage				$ 100,000,000
Pending litigation | JMEC
Litigation information
Percentage negligent	$ 75
Pending litigation | Tri-State
Litigation information
Percentage negligent	20
Pending litigation | United States Forest Service
Litigation information
Percentage negligent	$ 5
Jemez Pueblo
Litigation information
Damages sought		$ 34,400,000
Pueblo de Cochiti
Litigation information
Damages sought		$ 23,900,000

COMMITMENTS AND CONTINGENCIES77

COMMITMENTS AND CONTINGENCIES - Tres Lagunas Fire (Details) - Pending litigation - Damages from fire - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Litigation information
Liability insurance coverage	$ 100
Mora San Miguel Electric Cooperative versus Old Wood, The Viveash Ranch and River Bend Ranch
Litigation information
Liability insurance coverage		$ 200

QUARTERLY FINANCIAL DATA (UNA78

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ in Thousands	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
QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating revenues	$ 313,042	$ 388,102	$ 305,913	$ 328,391	$ 322,126	$ 396,479	$ 327,288	$ 349,198	$ 1,335,448	$ 1,395,091	$ 1,341,163
Operating margin	8,623	81,412	38,550	49,384	24,524	69,603	34,098	53,652	177,969	181,877	188,588
Net margins attributable to the Association	$ (21,299)	$ 48,302	$ 6,284	$ 20,126	$ (4,099)	$ 40,451	$ 3,373	$ 24,511	$ 53,413	$ 64,236	$ 72,912