Tri-State Generation & Transmission Association 10-K 10 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2016	Jun. 30, 2016
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, 2016
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	2,016
Entity Common Stock, Shares Outstanding	0

Consolidated Statements of Fina

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Electric Plant
In service	$ 5,682,613	$ 5,486,518
Construction work in progress	212,081	216,279
Total electric plant	5,894,694	5,702,797
Less allowances for depreciation and amortization	(2,361,555)	(2,240,732)
Net electric plant	3,533,139	3,462,065
Other plant	234,457	227,957
Less allowances for depreciation, amortization, and depletion	(89,809)	(73,471)
Net other plant	144,648	154,486
Total property, plant and equipment	3,677,787	3,616,551
Other assets and investments
Investment in other associations	139,350	123,686
Investments in and advances to coal mines	18,176	16,221
Restricted cash and investments	1,000	1,000
Intangible assets	18,310	25,634
Other noncurrent assets	11,542	12,139
Total other assets and investments	188,378	178,680
Current assets
Cash and cash equivalents	165,893	144,587
Restricted cash and investments	997	9,530
Deposits and advances	25,141	21,673
Accounts receivable—Members	97,925	106,216
Other accounts receivable	24,837	14,270
Coal inventory	63,945	59,277
Materials and supplies	87,768	85,501
Total current assets	466,506	441,054
Deferred charges
Regulatory assets	395,615	415,081
Prepayment—NRECA Retirement Security Plan	43,627	49,146
Other	139,378	122,535
Total deferred charges	578,620	586,762
Total assets	4,911,291	4,823,047
Capitalization
Patronage capital equity	961,364	952,082
Accumulated other comprehensive income (loss)	(286)	589
Noncontrolling interest	109,147	108,757
Total equity	1,070,225	1,061,428
Long-term debt	3,139,705	3,273,538
Total capitalization	4,209,930	4,334,966
Current liabilities
Member advances	11,363	9,403
Accounts payable	105,511	96,098
Short-term borrowing	119,901
Accrued expenses	32,719	30,045
Accrued interest	34,166	34,332
Accrued property taxes	27,584	27,395
Current maturities of long-term debt	107,903	91,419
Total current liabilities	439,147	288,692
Deferred credits and other liabilities
Regulatory liabilities	95,512	45,000
Deferred income tax liability	30,517	28,629
Intangible liabilities	3,263	6,221
Asset retirement obligations	58,583	55,215
Other	66,164	57,423
Total deferred credits and other liabilities	254,039	192,488
Accumulated postretirement benefit and postemployment obligations	8,175	6,901
Total equity and liabilities	$ 4,911,291	$ 4,823,047

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues
Member electric sales	$ 1,134,781	$ 1,125,699	$ 1,101,471
Non-member electric sales	132,208	120,234	197,497
Other	86,989	89,515	96,123
Total revenues	1,353,978	1,335,448	1,395,091
Operating expenses
Purchased power	341,289	305,045	327,445
Fuel	235,645	231,537	293,033
Production	218,008	235,398	229,933
Transmission	156,713	153,443	145,396
General and administrative	26,320	24,708	28,591
Depreciation, amortization, and depletion	173,969	152,718	128,712
Coal mining	36,929	36,130	40,849
Other	18,099	18,500	19,255
Operating expenses	1,206,972	1,157,479	1,213,214
Operating margins	147,006	177,969	181,877
Other income
Interest Income	4,368	4,355	11,076
Capital credits from cooperatives	20,349	9,189	8,684
Other income	3,934	3,981	3,573
Total other income	28,651	17,525	23,333
Interest expense, net of amounts capitalized	144,877	142,570	142,357
Income taxes	(1,417)	0	0
Net margins including noncontrolling interest	32,197	52,924	62,853
Net (income) loss attributable to noncontrolling interest	(449)	489	1,383
Net margins attributable to the Association	$ 31,748	$ 53,413	$ 64,236

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Consolidated Statements of Comprehensive Income
Net margins including noncontrolling interest	$ 32,197	$ 52,924	$ 62,853
Other comprehensive income (loss):
Unrealized loss on securities available for sale	(13)	(125)
Unrecognized actuarial gain (loss) on postretirement benefit obligation	(821)	1,528	(4,194)
Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net income	(41)	14	31
Other comprehensive income (loss)	(875)	1,417	(4,163)
Comprehensive income including noncontrolling interest	31,322	54,341	58,690
Net comprehensive (income) loss attributable to noncontrolling interest	(449)	489	1,383
Comprehensive income attributable to the Association	$ 30,873	$ 54,830	$ 60,073

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, 2013	$ 865,379	$ 3,335	$ 110,740
Change in Equity
Net margins attributable to the Association	64,236			$ 64,236
Retirement of patronage capital	(20,946)
Unrecognized actuarial gain (loss) on postretirement benefit obligation		(4,194)
Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net income		31
Net income (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 gain (loss) on postretirement benefit obligation		1,528
Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net income		14
Net income (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
Change in Equity
Net margins attributable to the Association	31,748			31,748
Retirement of patronage capital	(22,466)
Unrealized loss on securities available for sale		(13)
Unrecognized actuarial gain (loss) on postretirement benefit obligation		(821)
Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net income		(41)
Net income (loss) attributable to noncontrolling interest			449	449
Equity distribution to noncontrolling interest			(59)
Equity at end of period at Dec. 31, 2016	$ 961,364	$ (286)	$ 109,147	$ 1,070,225

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating activities
Net margins including noncontrolling interest	$ 32,197	$ 52,924	$ 62,853
Adjustments to reconcile net margins to net cash used in operating activities:
Depreciation, amortization and depletion	173,969	152,718	126,693
Amortization of intangible asset	7,324	7,324	7,324
Amortization of NRECA Retirement Security Plan prepayment	5,372	5,520	5,519
Amortization of debt issuance costs	1,931	1,870	1,356
Deferred membership withdrawal income	47,572
Capital credit allocations from cooperatives and income from coal mines over refund distributions	(17,933)	(7,179)	(6,465)
Recognition of deferred revenue	(9,200)		(20,000)
Change in restricted cash and investments	(137)	29,113
Changes in operating assets and liabilities:
Accounts receivable	(2,417)	10,936	(6,460)
Coal inventory	(4,668)	(18,604)	3,057
Materials and supplies	(2,267)	(5,432)	(4,593)
Accounts payable and accrued expenses	3,676	(12,188)	(5,923)
Accrued interest	(166)	1,814	7,909
Accrued property taxes	189	1,385	2,507
Other deferred credits - TEP transmission refund	15,521
Other deferred credits - BNSF settlement		(29,381)
Other	(175)	21,324	13,076
Net cash provided by operating activities	250,788	212,144	186,853
Investing activities
Purchases of plant	(219,771)	(290,428)	(221,613)
Changes in deferred charges	(298)	9,031	(8,263)
Proceeds from other investments	313	321	15,270
Net cash used in investing activities	(219,756)	(281,076)	(214,606)
Financing activities
Changes in Member advances	(887)	(7,041)	2,227
Payments of long-term debt	(423,957)	(113,063)	(1,739,835)
Proceeds from issuance of debt	307,000	240,183	1,674,977
Debt refinancing transaction costs			(184,073)
Increase in short-term borrowings, net	119,901
Decrease in advance payments to RUS			137,727
Retirement of patronage capital	(19,486)	(8,286)	(20,582)
Proceeds from investment in securities pledged as collateral	7,426	8,931	8,723
Other	277	327	48,000
Net cash provided by (used in) financing activities	(9,726)	121,051	(72,836)
Net increase in cash and cash equivalents	21,306	52,119	(100,589)
Cash and cash equivalents - beginning	144,587	92,468	193,057
Cash and cash equivalents - end	165,893	144,587	92,468
Supplemental cash flow information:
Cash paid for interest	158,978	154,657	152,344
Cash paid for income taxes	1,100
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$ (1,354)	2,173	$ (4,691)
Renewal of transmission right of way easements		$ 27,447

ORGANIZATION

ORGANIZATION	12 Months Ended
	Dec. 31, 2016
ORGANIZATION
ORGANIZATION	NOTE 1 – ORGANIZATION Tri‑State Generation and Transmission Association, Inc. (“the Association”) is a taxable wholesale electric power generation and transmission cooperative organized for the purpose of providing electricity to our member distribution systems (“Members”), that serve large portions of Colorado, Nebraska, New Mexico and Wyoming. We also sell a portion of our electric power to other utilities in our regions pursuant to long‑term contracts and short-term sale arrangements. In 2016, 2015 and 2014, total megawatt‑hours sold were 18.4, 17.8 and 18.7 million, respectively, of which 86, 89 and 85 percent, respectively, were sold to Members. Total revenue from electric sales was $1.3, $1.2, and $1.3 billion for 2016, 2015 and 2014, of which 90 percent in 2016 and 2015 and 85 percent in 2014 was from Member sales. Energy resources were provided by our generation and purchased power, of which 59 percent in 2016 and 63 percent in 2015 and 2014 were from our generation. We have entered into substantially similar contracts with each Member extending through 2050 for 42 Members (which constitute approximately 96 percent of our revenue from Member sales for 2016) and extending through 2040 for the remaining Member (Delta-Montrose Electric Association). These contracts are subject to automatic extension thereafter until either party provides at least a two years’ notice of its intent to terminate. Each contract obligates us to sell and deliver to the Member and obligates the Member to purchase and receive at least 95 percent of its electric power requirements from us. Each Member may elect to provide up to 5 percent of its requirements from distributed or renewable generation owned or controlled by the Member. As of December 31, 2016, 18 Members have enrolled in this program with capacity totaling approximately 113 megawatts. Revenue from one Member, United Power, Inc., was $159.4 million, or 14.0 percent, of our Member revenue and 11.8 percent of our operating revenues in 2016. No other Member exceeded 10 percent of our Member revenue or our operating revenues in 2016. Power is provided to Members at rates determined by the Board of Directors (“Board”). Rates are designed to recover all costs and provide margins to increase Members’ equity and to meet certain financial covenants, including a debt service ratio (“DSR”) requirement and equity to capitalization ratio (“ECR”) requirement. We supply wholesale power to our Members through the utilization of a portfolio of resources, including generating and transmission facilities, long‑term purchase contracts and short‑term energy purchases. Our generating facilities also include undivided ownership interests in jointly owned generating facilities. See Note 3—Property, Plant and Equipment. In support of our coal generating facilities, we have direct ownership and investment in coal mines. We, including our subsidiaries, employ 1,585 people, of which 335 are subject to collective bargaining agreements. None of these agreements expire within one year.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2016
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS 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 12—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 Yampa Project (operated by us), 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. See Note 3 – Property, Plant and Equipment. 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 and transmission facilities, long‑term purchase contracts and short‑term 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. IMPAIRMENT EVALUATION: Long-lived assets (property, plant and equipment, intangible assets and investments) that are held and used are evaluated for impairment whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. An impairment loss is recognized when estimated undiscounted cash flows expected to result from the use of the asset plus net proceeds expected from disposition of the asset (if any) are less than the carrying value of the asset. When an impairment loss is recognized, the carrying amount of the asset is reduced to its estimated fair value based on quoted market prices or other valuation techniques. There were no impairments of long-lived assets recognized for 2016, 2015 and 2014, respectively. 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 12—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 as expenses and regulatory liabilities as operating revenues, other income, or a reduction in expense concurrent with their recovery in rates. Regulatory assets and liabilities are as follows (dollars in thousands): 2016 2015 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 — Total regulatory assets Regulatory liabilities Interest rate swaps (7) — Deferred revenues (8) Membership withdrawal (9) — Total regulatory liabilities 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, amortization and depletion expense in the amount of $6.5 million annually through the remaining original life of the lease ending in June 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, amortization and depletion 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, amortization and depletion 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, amortization and depletion expense in the amount of $1.0 million annually 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, amortization and depletion 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 unrealized gain related to the change in fair value of forward starting interest rate swaps that were entered into in order to hedge interest rates on anticipated future borrowings. Upon settlement of these interest rate swaps, the realized gain or loss will be amortized to interest expense over the term of the associated long-term debt borrowing. See Note 5 – Long-Term Debt and Note 7 – Fair Value. (8) 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 received in 2011. $9.2 million of this deferred revenue was recognized in non-member electric sales revenue in 2016. As part of our Board approving the new A–40 rate schedule, which was implemented on January 1, 2017, the Board approved the income recognition in 2017 of $10.0 million of previously deferred 2008 non-member electric sales revenue and $20.0 million of previously deferred 2011 non-member electric sales revenue. The remaining deferred non-member electric sales revenue will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods. (9) Represents deferral of the recognition of other income of $47.6 million recorded in connection with the June 30, 2016 withdrawal of Kit Carson Electric Cooperative, Inc. (“KCEC”) from membership in us pursuant to the Membership Withdrawal Agreement (“Withdrawal Agreement”). The Withdrawal Agreement provided for the termination of the wholesale electric service contract between us and KCEC that extended through 2040 and the withdrawal of KCEC from membership in us. As part of the Withdrawal Agreement, we received $37 million net cash, which consisted of $49.5 million as an early termination fee for withdrawing from membership in us offset by $12.5 million for the retirement of KCEC’s patronage capital. This resulted in $47.6 million in other income, which was deferred by our Board. As part of our Board approving the new A–40 rate schedule, which was implemented on January 1, 2017, the Board approved the income recognition in 2017 of $10.0 million of deferred membership withdrawal income. The remaining deferred membership withdrawal income will be refunded to Members through reduced rates when recognized in other income in future periods. 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 4.7, 4.4 and 4.7 percent were used for 2016, 2015 and 2014, respectively. The amount of interest capitalized during construction was $13.8, $13.5 and $15.0 million during 2016, 2015 and 2014, 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 our consolidated statements of operations. 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. It is included in other operating expenses on our consolidated statements of operations. See Note 9—Leases. INVESTMENTS IN OTHER ASSOCIATIONS: Investments in other associations include 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 (dollars in thousands): 2016 2015 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 an owner of Western Fuels‑Wyoming, Inc. (“WFW”), the owner and operator of the Dry Fork Mine near Gillette, Wyoming. Dry Fork Mine provides coal to MBPP, which is the operator of Laramie River Generating Station. We, through our undivided interest in the jointly owned facility MBPP, advance funds to the Dry Fork Mine. Investments in and advances to coal mines are as follows (dollars in thousands): 2016 2015 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. The fair value of cash equivalents approximates their carrying values due to their short-term maturity. 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 our consolidated statements of financial position. The other funds are for 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 our consolidated statements of financial position. We had 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”). As of December 31, 2015, an $8.7 million defeasance investment remained related to the Colowyo Bond debt payments due in 2016 (the Colowyo Bonds matured in November 2016) and was classified as a current asset on our consolidated statements of financial position. As of December 31, 2016, there is no remaining defeasance investment. 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, 2016, the cost and estimated fair value of the investments based upon their active market value (Level 1 inputs) were $1.0 and $1.1 million, respectively, with a net unrealized gain balance of $0.1 million. At December 31, 2015, the cost and estimated fair value of the investments were $1.0 and $1.2 million, respectively, with a net unrealized gain balance of $0.1 million. The estimated fair value of the investments is included in other noncurrent assets on our consolidated statements of financial position. The unrealized gains at December 31, 2016 and 2015 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 held U.S. Treasury Notes to maturity in connection with the December 2011 defeasance of the Colowyo Bonds and these were included in restricted cash and investments on our statements of financial position. Since they were held to maturity, the notes were 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 $0.2 million and cash of $1.1 million. This defeasance investment was for the remaining Colowyo Bond debt payments due in 2016 (the Colowyo Bonds matured in November 2016). As of December 31, 2016, there is no remaining defeasance investment. INVENTORIES: Coal inventories at our owned generating stations are stated at LIFO (last‑in, first‑out) cost and were $46.0 and $42.2 million as of December 31, 2016 and 2015, respectively. The remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost. 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. Included in other deferred charges were preliminary surveys and investigations of $111.6 million and $107.1 million as of December 31, 2016 and 2015, respectively. These amounts were primarily comprised of expenditures for the expansion of Holcomb Generating Station of $91.3 million and $86.7 million as of December 31, 2016 and 2015, respectively. See Note 13—Commitments and Contingencies—Legal. We make advance payments to the operating agents of jointly owned facilities to fund our share of costs expected to be incurred under each project including MBPP – Laramie River Station, Yampa Project – Craig Station Units 1 and 2, San Juan Project – San Juan Unit 3. We also make advance payments to the operating agent of Springerville Unit 3. Included in other deferred charges were advance payments of $11.9 million and $11.5 million as of December 31, 2016 and 2015, respectively. See Note 3—Property, Plant and Equipment—Jointly Owned Facilities. During 2016, we entered into forward starting interest rate swaps to hedge a portion of our future long-term debt interest rate exposure. The unrealized gain on these interest rate swaps, as of December 31, 2016, was deferred in accordance with the accounting requirements related to regulated operations. See Note 2 – Accounting for Rate Regulation. Other deferred charges are as follows (dollars in thousands): 2016 2015 Preliminary surveys and investigations $ $ Advances to operating agents of jointly owned facilities Interest rate swaps — Other Total other deferred charges $ $ DEBT ISSUANCE COSTS: We account 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. 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. 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 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 (dollars in thousands): 2016 2015 Asset retirement obligation at beginning of period $ $ Liabilities incurred Liabilities settled Accretion expense Change in cash flow estimate Asset retirement obligation at end of period $ $ 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 fair value. OTHER DEFERRED CREDITS AND OTHER LIABILITIES: We received $15.5 million in 2016 from Tucson Electric Power Company (“TEP”) as ordered by the United States Federal Energy Regulatory Commission (“FERC”). In 2015, TEP filed various non-conforming point-to-point transmission services agreements with FERC, including transmission services agreements between TEP and us. FERC ordered TEP to make a time value refund to us with regard to these transmission services agreements. TEP appealed the FERC order and stated that the funds were subject to refund in the event TEP was ultimately successful in its appeal. Due to uncertainties regarding the ultimate outcome of this matter, we did not recognize benefit of the receipt of the total $15.5 million as of December 31, 2016. The funds are therefore recorded in other deferred credits. On January 12, 2017, we entered into a settlement agreement with TEP and TEP moved to dismiss the appeal with prejudice. We returned $7.75 million to TEP and will recognize $7.75 million that we retained as a reduction in transmission expense on our statement of operations during the first quarter of 2017. During 2015, we renewed transmission right of way easements on tribal nation lands where certain of our electric transmission lines are located. $34.5 million will be paid by us for these easements from 2017 through the individual easement terms ending between 2036 and 2040. The present value for the easement payments were $20.6 and $21.4 million as of December 31, 2016 and 2015, respectively, which is recorded as other deferred credits and other liabilities. We have received deposits from various parties and those that may still be required to be returned are a liability and these are reflected in customer deposits. We have received upfront payments from others for the use of optical fiber and these are reflected in unearned revenue until recognized over the life of the agreement. The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands): 2016 2015 Transmission easements $ $ TEP transmission refund — Customer deposits Unearned revenue Other Total other deferred credits and other liabilities $ $ MEMBERSHIPS: There are 43 and 44 $5 memberships outstanding at December 31, 2016 and 2015, respectively. PATRONAGE CAPITAL: Our net margins are treated as advances of capital from 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, transmission and 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. Transmission revenue is from our membership in the Southwest Power Pool, a regional transmission organization, which we joined on January 1, 2016. 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. See Note 9 – Leases. 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, amortization, and depletion and interest expense on our consolidated statements of operations. INCOME TAXES: We are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes. Accordingly 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 $1.9 and $1.6 million at December 31, 2016 and 2015, respectively, is included in accounts payable. The net interchange activity recorded in purchased power expense was $0.3 million, $0.1 million and $(0.5) million in 2016, 2015 and 2014, respectively. EVALUATION OF SUBSEQUENT EVENTS: We evaluated subsequent events through March 10, 2017, which is the date when the financial statements were issued. NEW ACCOUNTING PRONOUNCEMENTS: In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606), as amended by subsequent ASUs issued in 2015 and 2016. The core principle under the new revenue standard requires 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, the following steps are required: (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the trans

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2016
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 our 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 (dollars in thousands): Annual Depreciation Rate 2016 2015 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, 2016, we had $56.5 million of commitments to complete construction projects, of which approximately $51.9, $4.2 and $0.4 million are expected to be incurred in 2017, 2018 and 2019, respectively. On September 1, 2016, we announced that the owners of Craig Station Unit 1 reached an agreement with the Colorado Department of Public Health and Environment, U.S. Environmental Protection Agency, WildEarth Guardians and the National Parks Conservation Association to revise the Colorado Visibility and Regional Haze State Implementation Plan (“SIP”). Under the proposed revision to the SIP, the owners of Craig Station Unit 1 intend to retire Craig Station Unit 1 by December 31, 2025. The retirement date was previously estimated to be December 31, 2051. We are the operator of Craig Station and own 24 percent of Craig Station Unit 1. Craig Station Unit 2 and Unit 3 will continue to operate. Our share of Craig Station Unit 1 is 102 megawatts with a net book value of $28.9 million as of December 31, 2016. The shortened life increased depreciation expense in the amount of $0.8 million for the period September 1, 2016 through December 31, 2016 and will increase future annual depreciation expense by $2.3 million. As part of the above mentioned agreement on proposed revisions to the SIP, we intend to retire the Nucla Generating Station by December 31, 2022. The retirement date was previously estimated to be December 31, 2049. We are the operator and sole owner of Nucla Generating Station with a net book value of $62.6 million as of December 31, 2016. The shortened life increased depreciation expense in the amount of $2.8 million for the period September 1, 2016 through December 31, 2016 and will increase future annual depreciation expense by $8.4 million. The shortened life also increased the asset retirement obligation in the amount of $2.9 million as of December 31, 2016. Effective January 1, 2017, we adopted depreciation rates that reflect rates determined in a depreciation rate study completed in January 2017 for our transmission plant and most of our general plant. We expect that the new rates will result in a reduction in 2017 depreciation expense of approximately $21.0 million. It is also anticipated that a depreciation rate study will be performed and completed during 2017 for most of our generation plant and that these rates will be adopted prospectively in 2017 from the date the study is completed. We do not currently know what the impact of this study will be on our 2017 depreciation expense. JOINTLY OWNED FACILITIES : Our share in each jointly owned facility is as follows as of December 31, 2016 (these electric plant in service, accumulated depreciation and construction work in progress amounts are included in the electric plant table above) (dollars in 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 Elk Ridge Mining and Reclamation, LLC (“Elk Ridge”), 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. Elk Ridge 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 our consolidated statements of operations. Other plant assets are as follows (dollars in thousands): 2016 2015 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 $ $ The New Horizon Mine, which supplies coal to Nucla Generating Station, will cease coal production with the retirement of Nucla Generating Station. Reclamation efforts at the New Horizon Mine will continue.

INTANGIBLES

INTANGIBLES	12 Months Ended
	Dec. 31, 2016
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 represented 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 2016, 2015 and 2014 and will be recognized over each of the next three years as follows (dollars in thousands): 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 represented 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 $3.3 and $6.2 million as of December 31, 2016 and 2015, 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 $2.9, $3.2 and $3.2 million was recognized in 2016, 2015 and 2014, respectively, and the remaining benefit over the next year is estimated to be $3.3 million.

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2016
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 three unsecured notes in the aggregate amount of $49.6 million as of December 31, 2016. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. All long-term debt contains certain restrictive financial covenants, including a DSR requirement and ECR requirement. Long-term debt consists of the following (dollars in thousands): 2016 2015 Mortgage notes payable 3.66% to 8.08% CFC, due through 2028 $ $ 2.63% to 6.17% CoBank, ACB, due through 2042 First Mortgage Bonds, Series 2016A, 4.25% due 2046 — 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, due through 2026 Variable rate CFC, LIBOR-based term loan, due through 2049 Variable rate CoBank, ACB, LIBOR-based term loan, due through 2044 Variable rate, Revolving Credit Agreement, LIBOR-based revolving credit, matures 2019 — Pollution control revenue bonds City of Gallup, NM, 5.00%, Series 2005, due through 2017 Moffat County, CO Variable Rate Demand Series 2009, 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 $ $ 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 no outstanding borrowings at December 31, 2016 and $271 million at December 31, 2015. There is a 364-day, direct pay letter of credit issued under the Revolving Credit Agreement and provided by Bank of America for the $46.8 million Moffat County, CO pollution control revenue bonds. In December 2016, the letter of credit from Bank of America was extended for an additional 364 days to mature in January 2018. As of December 31, 2016, we have $582.4 million in total aggregate availability (including $380.1 million under the commercial paper back-up sublimit) under the Revolving Credit Agreement. 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. On May 23, 2016, we issued our First Mortgage Bonds, Series 2016A (“Series 2016A Bonds”) in an unregistered offering pursuant to Rule 144A under the Securities Act of 1933 with an aggregate principal amount of $250 million. The Series 2016A Bonds mature on June 1, 2046 and bear interest at a rate of 4.25 percent per annum. We utilized the proceeds from the Series 2016A Bonds primarily to repay outstanding indebtedness under the Revolving Credit Agreement. In connection with the Series 2016A Bonds, we entered into an exchange and registration rights agreement pursuant to which we agreed to file a registration statement relating to an exchange offer for our Series 2016A Bonds. On June 27, 2016, we commenced an offer to exchange all of the unregistered $250 million aggregate principal amount of the Series 2016A Bonds for $250 million aggregate principal amount of registered Series 2016A Bonds. We completed the exchange offer in July 2016 which satisfied our obligations under the exchange and 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. Annual maturities of total debt adjusted for debt issuance costs, discounts and premiums at December 31, 2016 are as follows (dollars in thousands): 2017 $ 2018 2019 2020 2021 Thereafter $ We are exposed to certain risks in the normal course of operations in providing a reliable and affordable source of wholesale electricity to our Members. These risks include interest rate risk, which represents the risk of increased operating expenses and higher rates due to increases in interest rates related to anticipated future long-term borrowings. To manage this exposure, we have entered into forward starting interest rate swaps to hedge a portion of our future long-term debt interest rate exposure. We anticipate settling these swaps in conjunction with the issuance of future long-term debt. See Note 2 – Accounting for Rate Regulation and Note 7 – Fair Value. The terms of the interest rate swap contracts are as follows (dollars in thousands): Notional Fixed Benchmark Interest Effective Maturity Amount Rate (1) Rate (2) Date Date Interest rate swap - April 2016 $ % 30 year - LIBOR April 2019 April 2049 Interest rate swap - June 2016 30 year - LIBOR June 2019 June 2049 $ (1) We will pay. (2) We will receive.

SHORT-TERM BORROWINGS

SHORT-TERM BORROWINGS	12 Months Ended
	Dec. 31, 2016
SHORT-TERM BORROWINGS
SHORT-TERM BORROWINGS	NOTE 6 – SHORT-TERM BORROWINGS We established a commercial paper program in May 2016 under which we issue unsecured commercial paper in aggregate amounts not exceeding the commercial paper back-up sublimit under our Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our Revolving Credit Agreement. The commercial paper issuances are used to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances vary, but may not exceed 397 days from the date of issue. The commercial paper notes are classified as current and are included in current liabilities as short-term borrowings on our consolidated statements of financial position. Commercial paper consisted of the following (dollars in thousands): 2016 2015 Commercial paper outstanding, net of discounts $ $ — Weighted average interest rate % N/A At December 31, 2016, $380.1 million of the commercial paper back-up sublimit remained available under the Revolving Credit Agreement. See Note 5 – Long-term Debt.

FAIR VALUE

FAIR VALUE	12 Months Ended
	Dec. 31, 2016
FAIR VALUE
FAIR VALUE	NOTE 7 – 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 are based upon quoted prices for identical instruments traded in active (exchange-traded) markets. Valuations are obtained from readily available pricing sources for market transactions (observable market data) involving identical assets or liabilities. Level 2 inputs are based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques (such as option pricing models and discounted cash flow models) for which all significant assumptions are observable in the market. 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 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 are reported as a component of accumulated other comprehensive income. The amortized cost and fair values of our marketable securities are as follows (dollars in thousands): 2016 2015 Amortized Estimated Amortized Estimated Cost Fair Value Cost Fair Value Marketable securities $ $ $ $ Cash Equivalents We invest portions of our cash and cash equivalents in commercial paper, money market funds, and other highly liquid investments. The fair value of these investments approximates our cost basis in the investments. In aggregate, the fair value was $49.1 million and $75.1 million as of December 31, 2016 and 2015, respectively. 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 principal amounts and fair values of our debt are as follows (dollars in thousands): 2016 2015 Principal Estimated Principal Estimated Amount Fair Value Amount Fair Value Total debt $ $ $ $ Interest Rate Swaps We entered into forward starting interest rate swaps in 2016 to hedge a portion of our future long-term debt interest rate expense. See Note 5 – Long-Term Debt. These interest rate swaps are derivative instruments in accordance with ASC 815, Derivatives and Hedging, and are recorded at fair value on a recurring basis. The estimated fair value of these interest rate swaps utilizes 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) and are included in other deferred charges on our consolidated statements of financial position. At December 31, 2016, the fair value of our interest rate swaps was an unrealized gain of $12.1 million, which was deferred in accordance with our regulatory accounting. See Note 2 – Summary of Significant Accounting Policies.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2016
INCOME TAXES
INCOME TAXES	NOTE 8 – INCOME TAXES We had an income tax benefit of $1.4 million in 2016 and no income tax expense or benefit in 2015 and 2014. The income tax benefit of $1.4 million is due to the alternative minimum tax credit refund in lieu of bonus depreciation of $1.9 million, offset by the current alternative minimum tax expense of $0.5 million. 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 (dollars in thousands): 2016 2015 Deferred tax assets Safe harbor lease receivables $ $ Net operating loss carryforwards Alternative minimum tax credit carryforwards Deferred revenues and membership withdrawal 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 $1.9 million increase in the net deferred tax liability from $28.6 million at December 31, 2015 to $30.5 million at December 31, 2016 is not recognized as a tax expense in 2016 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 $30.5 million and $28.6 million at December 31, 2016 and 2015, respectively. The reconciliation between the statutory federal income tax rate and the effective tax rate is as follows: 2016 2015 2014 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 taxable income of $20.4 million for 2016. At December 31, 2016, we have a federal net operating loss carryforward of $378.1 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 $1.9 million of alternative minimum tax credit carryforwards at December 31, 2016 that 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 2013 forward. We do not have any liabilities recorded for uncertain tax positions.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2016
LEASES
LEASES	NOTE 9 – 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 directed the use of both of the two Knutson Generating Station units and one of the two Limon Generating Station units through April 30, 2016 under tolling arrangements whereby the third party provided its own natural gas for generation of electricity. The revenues from these operating leases of $17.5, $30.1 and $30.6 million for 2016, 2015 and 2014, respectively, are accounted for as lease revenue and are reflected in other operating revenue on our consolidated statements of operations. The generating units used in these gas tolling arrangements have a total cost and accumulated depreciation of $114 and $63 million, respectively, as of December 31, 2016, and of $223 and $106 million, respectively, as of December 31, 2015. The minimum future lease revenues under these gas tolling arrangements at December 31, 2016 are as follows (dollars in thousands): 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 2016, 2015 and 2014 is included in other operating expenses on our consolidated statements of operations. Our operating lease commitments for this gas tolling arrangement at December 31, 2016 are as follows (dollars in thousands): 2017 $ 2018 2019 $

RELATED PARTIES

RELATED PARTIES	12 Months Ended
	Dec. 31, 2016
RELATED PARTIES
RELATED PARTIES	NOTE 10 – RELATED PARTIES TRAPPER MINING, INC.: We, and certain participants in the Yampa Project, own Trapper Mining. Organized as a cooperative, Trapper Mining supplied 26 percent in 2016 and 2015 and 35 percent in 2014 of the coal for the Yampa Project. Our 26.57 percent share of coal purchases from Trapper Mining was $16.9, $17.7 and $30.6 million in 2016, 2015 and 2014, respectively. Our membership interest in Trapper Mining of $14.5 and $14.1 million at December 31, 2016 and 2015, respectively, is included in investments in and advances to coal mines on our consolidated statements of financial position. Our share of Trapper Mining capital credit allocations of $0.5 million for 2016, 2015 and 2014, respectively, is included in capital credits from cooperatives on our consolidated statements of operations.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2016
EMPLOYEE BENEFIT PLANS
EMPLOYEE BENEFIT PLANS	NOTE 11 – EMPLOYEE BENEFIT PLANS DEFINED BENEFIT PLAN: Substantially all of our 1,585 employees participate in the National Rural Electric Cooperative Association Retirement Security Plan (“RS Plan”) except for the 223 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 2016, 2015 and 2014 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 $24.8, $22.9 and $21.5 million in 2016, 2015 and 2014, respectively. 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 335 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 employer. In total, the RS Plan was over 80 percent funded at January 1, 2016, and over 80 percent funded at January 1, 2015, 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 335 bargaining unit employees. For all of the eligible non‑bargaining unit employees, other than the 223 employees of Colowyo Coal, we contribute 1 percent of an employee’s eligible earnings. For the bargaining unit employees of New Horizon Mine, we match 1 percent of employee’s contributions. 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 million for 2016 and 2015 and $2.9 million for 2014. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS: We sponsor three medical plans for all non‑bargaining unit employees under the age of 65. 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, 2016, 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 and postemployment medical benefit obligations are determined annually by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): 2016 2015 Postretirement medical benefit obligation at beginning of year $ $ Service cost Interest cost Plan amendments - prior service credit — 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 $ $ The postretirement medical benefit plans were amended as of December 31, 2015. 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 $(0.9) million as of December 31, 2015. This prior service cost was recorded in accumulated other comprehensive income and is being amortized to expense in the amount of $0.1 million annually over the average remaining service lives of the active plan participants at the date of the plan amendment. 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 our 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 (dollars in thousands): 2016 2015 Amounts included in accumulated other comprehensive income at beginning of year $ $ Amortization of actuarial loss into income Plan amendments - prior service credit — Amortization of prior service credit into income — Actuarial gain (loss) Amounts included in accumulated other comprehensive income at end of year $ $ The assumptions used in the 2016 actuarial study performed for our postretirement medical benefit obligation were as follows: Weighted-average discount rate % Initial health care cost trend (2016) % 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 (dollars in 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 during the next 10 years (dollars in thousands): 2017 $ 2018 2019 2020 2021 2022 through 2026 $

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2016
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES	NOTE 12 – 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 $832.3 million and $853.3 million at December 31, 2016 and 2015, respectively, the long-term debt of $472.1 million and $511.0 million at December 31, 2016 and 2015, respectively, accrued interest associated with the long-term debt of $13.4 million and $14.3 million at December 31, 2016 and 2015, respectively, and the 49 percent noncontrolling equity interest in the Springerville Partnership of $109.1 million and $108.8 million at December 31, 2016 and 2015, respectively. Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization expense of $21.0 million for 2016, 2015 and 2014, respectively. Our consolidated statements of operations also include interest expense of $30.4, $32.3 and $34.1 million for 2016, 2015 and 2014, respectively. The net income or loss attributable to the 49 percent noncontrolling equity interest in the Springerville Partnership is 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. Therefore, since there is shared power over the significant activities of 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 $2.2 million and $2.3 million for December 31, 2016 and 2015, respectively, and is included in investments in other associations. Western Fuels – Wyoming : WFW, the owner and operator of the Dry Fork Mine in Gillette, Wyoming, 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’s 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 $14.5 million at December 31, 2016 and $14.1 million at December 31, 2015 and is recorded within investments in and advances to coal mines.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2016
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES	NOTE 13 – COMMITMENTS AND CONTINGENCIES SALES: We have delivery obligations under resource-contingent power sales contracts with Public Service Company of Colorado totaling 100 megawatts. This contract expires in March 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, 2016, the annual minimum coal purchases under these contracts are as follows (dollars in thousands): 2017 $ 2018 2019 2020 2021 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 part of the 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). In 2015, we entered into an additional 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 purchases from Basin to supply power to our Nebraska Members, which are primarily located in the Eastern Interconnection and are generally isolated from our generating facilities that are located in the Western Interconnection. 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 in the Western Interconnection 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 (dollars in thousands): 2016 2015 2014 WAPA $ $ $ Basin ENVIRONMENTAL: As with most electric utilities, we are subject to extensive federal, state and local environmental requirements that regulate, among other things, air emissions, water discharges and use and the management of hazardous and solid wastes. Compliance with these requirements requires significant expenditures for the installation, maintenance and operation of pollution control equipment, monitoring systems and other equipment or facilities. Our operations are subject to environmental laws and regulations that are complex, change frequently and have become more stringent and numerous over time. Federal, state, and local standards and procedures that regulate environmental impact of our operations are subject to change. Consequently, there is no assurance that environmental regulations applicable to our facilities will not become materially more stringent, or that we will always be able to obtain all required operating permits. More stringent standards may require us to modify the design or operation of existing facilities or purchase emission allowances. An inability to comply with environmental standards could result in reduced operating levels or the complete shutdown of our facilities that are not in compliance. We cannot predict at this time whether any additional legislation or rules will be enacted which will affect our operations, and if such laws or rules are enacted, what the cost to us might be in the future because of such actions or the effect it could have on our financial condition, results of operations and cash flow. From time to time, we are alleged to be in violation or in default under orders, statutes, rules, regulations, permits or compliance plans relating to the environment. Additionally, we may need to deal with notices of violation, enforcement proceedings or challenges to construction or operating permits. In addition, we may be involved in legal proceedings arising in the ordinary course of business. However, we believe our 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 A‑37 wholesale rate which was scheduled to become effective on January 1, 2013. The rate would have increased revenue collected from all of our Members. 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 26, 2013, we filed to withdraw our 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 A‑38 wholesale rate which was scheduled to become effective on January 1, 2014. Four Members filed protests with the NMPRC challenging the A-38 rate. 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 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 our 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 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 6, 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. 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 Generating 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 Generating 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, 2016 is $91.3 million, which is included in other deferred charges on our consolidated statements of financial position. We are unable to project the ultimate outcome of this matter or when the air permit application process may conclude. On February 17, 2016, we filed a Petition for Declaratory Order with FERC seeking a declaratory order from FERC finding that the fixed cost recovery mechanism in our revised Board policy is consistent with the provisions of Public Utility Regulatory Policies Act of 1978 and the implementing regulations of FERC. The revised Board policy provides for recovery of the unrecovered fixed costs directly from a Member as a result of that Member purchasing power from a “qualifying facility” in an amount that causes it to exceed the 5 percent limitation on that Member’s self-supply of power pursuant to its wholesale electric service contract, rather than allocating the costs among all of our Members. The fixed cost recovery is calculated based on the difference between our wholesale rate to our Members and our avoided costs. Various individuals and entities filed comments and four entities filed motions to intervene, including our Member, Delta-Montrose Electric Association. On June 16, 2016, FERC denied our Petition for Declaratory Order related to the fixed cost recovery mechanism in our revised Board policy. On July 18, 2016, we filed a Request for Rehearing with FERC regarding FERC’s June 16 order. In addition, five other generation and transmission cooperatives filed a Request for Rehearing with FERC. We cannot predict the outcome of our July 18 request for rehearing filed with FERC. In June 2011, a wildfire in New Mexico, known as the Las Conchas Fire, burned for five weeks in northern New Mexico, primarily on national forest service land in the Santa Fe National Forest. Six plaintiff groups, composed 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 JMEC’s 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. After JMEC settled with one plaintiff group, the remaining cases were Elizabeth Ora Cox, et al., v. Jemez Mountains Electric Cooperative, Inc., et al.; Norman Armijo, et al., v. Jemez Mountains Electric Cooperative, Inc., et al.; Esequiel Espinoza, et al. v. Allstate Property & Casualty, et al.; Jemez Pueblo v. Jemez Mountains Electric Cooperative, Inc., et al.; and Pueblo de Cochiti., et al. v. Jemez Mountains Electric Cooperative, Inc., et al. 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 were also jointly liable for any negligence by JMEC under joint venture and joint enterprise theories. A jury trial commenced on September 28, 2015 on the liability aspect of this matter. 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. We maintain $100 million in liability insurance coverage for this matter. We anticipate appealing the determination of our liability for this matter. If we do not prevail on appeal, we expect our allocation of damages to be covered by our liability insurance. Although we cannot predict the outcome of this matter 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 alleged 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 us as a defendant. The district court approved the motion to amend on November 10, 2015 and plaintiffs filed their first amended complaint. Plaintiffs asserted claims of negligence, violations of New Mexico 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. On February 18, 2016, Tres Lagunas Homeowners Association filed a lawsuit against MSMEC and us in the First Judicial District Court for the County of Santa Fe, New Mexico. In the complaint, the plaintiffs asserted claims of negligence and strict liability against us. On March 18, 2016, we filed a motion to dismiss the strict liability claim and, additionally, filed our answer. In January 2017 and February 2017, all plaintiffs in both lawsuits executed releases that expressly released all claims against us and MSMEC and resulted in a dismissal of both lawsuits with prejudice.

QUARTERLY FINANCIAL DATA (UNAUD

QUARTERLY FINANCIAL DATA (UNAUDITED)	12 Months Ended
	Dec. 31, 2016
QUARTERLY FINANCIAL DATA (UNAUDITED)
QUARTERLY FINANCIAL DATA (UNAUDITED)	NOTE 14 – QUARTERLY FINANCIAL DATA (UNAUDITED) Unaudited operating results by quarter for 2016 and 2015 are presented below. In the opinion of management, all adjustments (consisting of normal recurring accruals) necessary for the fair statement of our results of operations for such periods have been included (dollars in thousands): First Second Third Fourth Statement of Operations Data Quarter Quarter Quarter Quarter Total 2016 Operating revenues $ $ $ $ $ Operating margins Net margins attributable to the Association 2015 Operating revenues $ $ $ $ $ Operating margins Net margins attributable to the Association Our business is influenced by seasonal weather conditions, changes in rates and other factors. In the fourth quarter of 2016, operating revenues were $10.4 million higher than the comparable period in 2015 primarily due to the income recognition of $9.2 million of previously deferred 2011 non-member electric sales revenue. Operating expenses increased $7.6 million during the fourth quarter of 2016 compared to the same period in 2015 primarily due to a $16.7 million increase in purchased power expense and a $4.5 million increase in depreciation, amortization and depletion expense partially offset by a $13.9 million decrease in fuel expense. The increase in purchased power expense was due to an increase in MWhs purchased resulting from an increase in renewable energy purchases and a 3.5 percent increase in the average cost per MWh. The increase in depreciation, amortization, and depletion expense was due to a $3.6 million increase related to the shortened lives at the Nucla Generating Station and Craig Station Unit 1. The decrease in fuel expense was primarily due to reduced coal consumption as a result of a decrease in generation. Capital credits from cooperatives increased $11.4 million during the fourth quarter of 2016 compared to the same period in 2015 primarily due to a patronage allocation from Basin of $14.4 million. The increases in operating revenues of $10.4 million and capital credits from cooperatives of $11.4 million were partially offset by the increase in operating expenses of $7.6 million. This resulted in an increase in net margins attributable to us of $15.2 million to $(6.1) million for the fourth quarter of 2016 compared to $(21.3) million for the comparable period in 2015. In the third quarter of 2016, operating margins were $29.2 million lower than the comparable period in 2015 primarily due to a $25.9 million increase in operating expenses. The increase in operating expenses was primarily due to an increase in purchased power expense resulting from power purchase agreements that began in 2016. Depreciation expense also increased due to additions of equipment throughout our transmission system and at our generating stations. In addition, depreciation expense increased (beginning September 1, 2016) as a result of shortening the life of the Craig Station Unit 1 (a monthly increase of $0.2 million) and Nucla Generating Station (a monthly increase of $0.7 million).

SUMMARY OF SIGNIFICANT ACCOUN21

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2016
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
BASIS OF CONSOLIDATION:	BASIS 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 12—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 Yampa Project (operated by us), 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. See Note 3 – Property, Plant and Equipment.
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 and transmission facilities, long‑term purchase contracts and short‑term 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.
IMPAIRMENT EVALUATION:	IMPAIRMENT EVALUATION: Long-lived assets (property, plant and equipment, intangible assets and investments) that are held and used are evaluated for impairment whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. An impairment loss is recognized when estimated undiscounted cash flows expected to result from the use of the asset plus net proceeds expected from disposition of the asset (if any) are less than the carrying value of the asset. When an impairment loss is recognized, the carrying amount of the asset is reduced to its estimated fair value based on quoted market prices or other valuation techniques. There were no impairments of long-lived assets recognized for 2016, 2015 and 2014, respectively.
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 12—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 as expenses and regulatory liabilities as operating revenues, other income, or a reduction in expense concurrent with their recovery in rates. Regulatory assets and liabilities are as follows (dollars in thousands): 2016 2015 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 — Total regulatory assets Regulatory liabilities Interest rate swaps (7) — Deferred revenues (8) Membership withdrawal (9) — Total regulatory liabilities 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, amortization and depletion expense in the amount of $6.5 million annually through the remaining original life of the lease ending in June 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, amortization and depletion 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, amortization and depletion 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, amortization and depletion expense in the amount of $1.0 million annually 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, amortization and depletion 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 unrealized gain related to the change in fair value of forward starting interest rate swaps that were entered into in order to hedge interest rates on anticipated future borrowings. Upon settlement of these interest rate swaps, the realized gain or loss will be amortized to interest expense over the term of the associated long-term debt borrowing. See Note 5 – Long-Term Debt and Note 7 – Fair Value. (8) 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 received in 2011. $9.2 million of this deferred revenue was recognized in non-member electric sales revenue in 2016. As part of our Board approving the new A–40 rate schedule, which was implemented on January 1, 2017, the Board approved the income recognition in 2017 of $10.0 million of previously deferred 2008 non-member electric sales revenue and $20.0 million of previously deferred 2011 non-member electric sales revenue. The remaining deferred non-member electric sales revenue will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods. (9) Represents deferral of the recognition of other income of $47.6 million recorded in connection with the June 30, 2016 withdrawal of Kit Carson Electric Cooperative, Inc. (“KCEC”) from membership in us pursuant to the Membership Withdrawal Agreement (“Withdrawal Agreement”). The Withdrawal Agreement provided for the termination of the wholesale electric service contract between us and KCEC that extended through 2040 and the withdrawal of KCEC from membership in us. As part of the Withdrawal Agreement, we received $37 million net cash, which consisted of $49.5 million as an early termination fee for withdrawing from membership in us offset by $12.5 million for the retirement of KCEC’s patronage capital. This resulted in $47.6 million in other income, which was deferred by our Board. As part of our Board approving the new A–40 rate schedule, which was implemented on January 1, 2017, the Board approved the income recognition in 2017 of $10.0 million of deferred membership withdrawal income. The remaining deferred membership withdrawal income will be refunded to Members through reduced rates when recognized in other income in future periods.
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 4.7, 4.4 and 4.7 percent were used for 2016, 2015 and 2014, respectively. The amount of interest capitalized during construction was $13.8, $13.5 and $15.0 million during 2016, 2015 and 2014, 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 our consolidated statements of operations. 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. It is included in other operating expenses on our consolidated statements of operations. See Note 9—Leases.
INVESTMENTS IN OTHER ASSOCIATIONS:	INVESTMENTS IN OTHER ASSOCIATIONS: Investments in other associations include 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 (dollars in thousands): 2016 2015 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:	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 an owner of Western Fuels‑Wyoming, Inc. (“WFW”), the owner and operator of the Dry Fork Mine near Gillette, Wyoming. Dry Fork Mine provides coal to MBPP, which is the operator of Laramie River Generating Station. We, through our undivided interest in the jointly owned facility MBPP, advance funds to the Dry Fork Mine. Investments in and advances to coal mines are as follows (dollars in thousands): 2016 2015 Investment in Trapper Mine $ $ Advances to Dry Fork Mine Investments in and advances to coal mines $ $
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. The fair value of cash equivalents approximates their carrying values due to their short-term maturity.
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 our consolidated statements of financial position. The other funds are for 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 our consolidated statements of financial position. We had 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”). As of December 31, 2015, an $8.7 million defeasance investment remained related to the Colowyo Bond debt payments due in 2016 (the Colowyo Bonds matured in November 2016) and was classified as a current asset on our consolidated statements of financial position. As of December 31, 2016, there is no remaining defeasance investment.
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, 2016, the cost and estimated fair value of the investments based upon their active market value (Level 1 inputs) were $1.0 and $1.1 million, respectively, with a net unrealized gain balance of $0.1 million. At December 31, 2015, the cost and estimated fair value of the investments were $1.0 and $1.2 million, respectively, with a net unrealized gain balance of $0.1 million. The estimated fair value of the investments is included in other noncurrent assets on our consolidated statements of financial position. The unrealized gains at December 31, 2016 and 2015 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 held U.S. Treasury Notes to maturity in connection with the December 2011 defeasance of the Colowyo Bonds and these were included in restricted cash and investments on our statements of financial position. Since they were held to maturity, the notes were 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 $0.2 million and cash of $1.1 million. This defeasance investment was for the remaining Colowyo Bond debt payments due in 2016 (the Colowyo Bonds matured in November 2016). As of December 31, 2016, there is no remaining defeasance investment.
INVENTORIES:	INVENTORIES: Coal inventories at our owned generating stations are stated at LIFO (last‑in, first‑out) cost and were $46.0 and $42.2 million as of December 31, 2016 and 2015, respectively. The remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost.
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. Included in other deferred charges were preliminary surveys and investigations of $111.6 million and $107.1 million as of December 31, 2016 and 2015, respectively. These amounts were primarily comprised of expenditures for the expansion of Holcomb Generating Station of $91.3 million and $86.7 million as of December 31, 2016 and 2015, respectively. See Note 13—Commitments and Contingencies—Legal. We make advance payments to the operating agents of jointly owned facilities to fund our share of costs expected to be incurred under each project including MBPP – Laramie River Station, Yampa Project – Craig Station Units 1 and 2, San Juan Project – San Juan Unit 3. We also make advance payments to the operating agent of Springerville Unit 3. Included in other deferred charges were advance payments of $11.9 million and $11.5 million as of December 31, 2016 and 2015, respectively. See Note 3—Property, Plant and Equipment—Jointly Owned Facilities. During 2016, we entered into forward starting interest rate swaps to hedge a portion of our future long-term debt interest rate exposure. The unrealized gain on these interest rate swaps, as of December 31, 2016, was deferred in accordance with the accounting requirements related to regulated operations. See Note 2 – Accounting for Rate Regulation. Other deferred charges are as follows (dollars in thousands): 2016 2015 Preliminary surveys and investigations $ $ Advances to operating agents of jointly owned facilities Interest rate swaps — Other Total other deferred charges $ $
DEBT ISSUANCE COSTS:	DEBT ISSUANCE COSTS: We account 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.
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. 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 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 (dollars in thousands): 2016 2015 Asset retirement obligation at beginning of period $ $ Liabilities incurred Liabilities settled Accretion expense Change in cash flow estimate Asset retirement obligation at end of period $ $ 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 fair value.
OTHER DEFERRED CREDITS AND OTHER LIABILITIES:	OTHER DEFERRED CREDITS AND OTHER LIABILITIES: We received $15.5 million in 2016 from Tucson Electric Power Company (“TEP”) as ordered by the United States Federal Energy Regulatory Commission (“FERC”). In 2015, TEP filed various non-conforming point-to-point transmission services agreements with FERC, including transmission services agreements between TEP and us. FERC ordered TEP to make a time value refund to us with regard to these transmission services agreements. TEP appealed the FERC order and stated that the funds were subject to refund in the event TEP was ultimately successful in its appeal. Due to uncertainties regarding the ultimate outcome of this matter, we did not recognize benefit of the receipt of the total $15.5 million as of December 31, 2016. The funds are therefore recorded in other deferred credits. On January 12, 2017, we entered into a settlement agreement with TEP and TEP moved to dismiss the appeal with prejudice. We returned $7.75 million to TEP and will recognize $7.75 million that we retained as a reduction in transmission expense on our statement of operations during the first quarter of 2017. During 2015, we renewed transmission right of way easements on tribal nation lands where certain of our electric transmission lines are located. $34.5 million will be paid by us for these easements from 2017 through the individual easement terms ending between 2036 and 2040. The present value for the easement payments were $20.6 and $21.4 million as of December 31, 2016 and 2015, respectively, which is recorded as other deferred credits and other liabilities. We have received deposits from various parties and those that may still be required to be returned are a liability and these are reflected in customer deposits. We have received upfront payments from others for the use of optical fiber and these are reflected in unearned revenue until recognized over the life of the agreement. The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands): 2016 2015 Transmission easements $ $ TEP transmission refund — Customer deposits Unearned revenue Other Total other deferred credits and other liabilities $ $
MEMBERSHIPS AND PATRONAGE CAPITAL:	MEMBERSHIPS: There are 43 and 44 $5 memberships outstanding at December 31, 2016 and 2015, respectively. PATRONAGE CAPITAL: Our net margins are treated as advances of capital from 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 AND OTHER OPERATING REVENUE:	ELECTRIC SALES REVENUE: Revenue from electric energy deliveries is recognized when delivered. OTHER OPERATING REVENUE: Other operating revenue consists primarily of wheeling, transmission and 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. Transmission revenue is from our membership in the Southwest Power Pool, a regional transmission organization, which we joined on January 1, 2016. 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. See Note 9 – Leases. 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, amortization, and depletion and interest expense on our consolidated statements of operations.
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.
INCOME TAXES:	INCOME TAXES: We are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes. Accordingly 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 $1.9 and $1.6 million at December 31, 2016 and 2015, respectively, is included in accounts payable. The net interchange activity recorded in purchased power expense was $0.3 million, $0.1 million and $(0.5) million in 2016, 2015 and 2014, respectively.
EVALUATION OF SUBSEQUENT EVENTS:	EVALUATION OF SUBSEQUENT EVENTS: We evaluated subsequent events through March 10, 2017, which is the date when the financial statements were issued.
NEW ACCOUNTING PRONOUNCEMENTS:	NEW ACCOUNTING PRONOUNCEMENTS: In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, Revenue from Contracts with Customers (Topic 606), as amended by subsequent ASUs issued in 2015 and 2016. The core principle under the new revenue standard requires 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, the following steps are required: (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 enhanced quantitative and qualitative disclosures 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). We are currently evaluating the impact of Topic 606, including the transition method, on our financial position and results of operations. We have evaluated our wholesale electric service contracts with our 43 Members and do not believe there will be a material impact to our recognition of revenue from the sale of electricity to our Members. Our Members are billed on a monthly basis per an energy rate and demand rate(s) for energy consumed during the period. Member rates for energy and demand are set by our Board annually, consistent with adequate electrical reliability and sound fiscal policy. Under the new standard, revenue is recognized upon the satisfaction of an entity’s performance obligations, which occurs when control of a good or service transfers to the customer. The standard includes a practical expedient that allows an entity to recognize revenue in the amount at which the entity has a right to invoice if that amount corresponds directly with the value to the customer of the entity’s performance to date. We transfer control of the electricity over time and the Member simultaneously receives and consumes the benefits of the electricity. The amount we invoice Members on a monthly basis corresponds directly with the value to the Member of our performance. Total revenue from Member electric sales was $1.1 billion for 2016, which was 84 percent of our operating revenue. We are currently evaluating the impact of the new standard on our remaining operating revenue. The American Institute of Certified Public Accountants (“AICPA”) Power and Utilities Revenue Recognition Task Force is working with the FASB to address specific industry issues, including the applicability of Topic 606 to contributions in aid of construction (“CIAC”), and if it is within scope, whether the recognition of such revenue should occur upon receipt or be deferred. In order to be fair and economical to all our Members, we may require a Member to provide CIAC to make an investment in property, plant and equipment. In accordance with standard industry practice, we have accounted for receipt of CIAC as a reduction in the total cost basis of property, plant and equipment such that only the net cost to us is included in property, plant and equipment on our statements of financial position. This net amount (after contribution) is also the amount subject to ratemaking. If it is determined that CIAC is within the scope of Topic 606, and offsetting regulatory treatments is permitted, it could have a material impact 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 ending after December 15,2016, and interim periods within those annual periods beginning after December 15, 2016. We adopted this update in 2016 and it did not have an 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 . This amendment requires an entity to measure investments in equity securities, except those that result in consolidation or are accounted for under the equity method of accounting, at fair value with changes in fair value recognized in net income. For equity investments that do not have readily determinable fair value and don’t qualify for the existing practical expedient in ASC 820, Fair Value Measurements , to estimate fair value using the net asset value per share of the investment, the guidance provides a new measurement alternative. Entities may choose to measure those investments at cost, less any impairment, plus or minus changes resulting from observable price changes in orderly transactions for the identical or similar investment of the same issuer. This amendment also affects financial liabilities using 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 2016-02, Leases (Topic 842). This amendment requires a lessee to reco gnize 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. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230) – Classification of Certain Cash Receipts and Payments . This amendment provides specific guidance on certain cash flow presentation and classification issues in order to reduce diversity in practice on the statement of cash flows. The issues that primarily relate to us are the classification of proceeds from the settlement of insurance claims and distributions received from equity method investees. This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The guidance is applied using a full retrospective transition method. We are currently evaluating the impact that this amendment will have on our statement of cash flows. In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) – Restricted Cash . This amendment requires the statement of cash flows to explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Amounts described as restricted cash and restricted cash equivalents will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. This amendment is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted. The guidance is applied using a full retrospective transition method. We are currently evaluating the impact that this amendment will have on our statement of cash flows.

SUMMARY OF SIGNIFICANT ACCOUN22

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2016
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Schedule of regulatory assets and liabilities	Regulatory assets and liabilities are as follows (dollars in thousands): 2016 2015 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 — Total regulatory assets Regulatory liabilities Interest rate swaps (7) — Deferred revenues (8) Membership withdrawal (9) — Total regulatory liabilities 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, amortization and depletion expense in the amount of $6.5 million annually through the remaining original life of the lease ending in June 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, amortization and depletion 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, amortization and depletion 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, amortization and depletion expense in the amount of $1.0 million annually 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, amortization and depletion 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 unrealized gain related to the change in fair value of forward starting interest rate swaps that were entered into in order to hedge interest rates on anticipated future borrowings. Upon settlement of these interest rate swaps, the realized gain or loss will be amortized to interest expense over the term of the associated long-term debt borrowing. See Note 5 – Long-Term Debt and Note 7 – Fair Value. (8) 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 received in 2011. $9.2 million of this deferred revenue was recognized in non-member electric sales revenue in 2016. As part of our Board approving the new A–40 rate schedule, which was implemented on January 1, 2017, the Board approved the income recognition in 2017 of $10.0 million of previously deferred 2008 non-member electric sales revenue and $20.0 million of previously deferred 2011 non-member electric sales revenue. The remaining deferred non-member electric sales revenue will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods. (9) Represents deferral of the recognition of other income of $47.6 million recorded in connection with the June 30, 2016 withdrawal of Kit Carson Electric Cooperative, Inc. (“KCEC”) from membership in us pursuant to the Membership Withdrawal Agreement (“Withdrawal Agreement”). The Withdrawal Agreement provided for the termination of the wholesale electric service contract between us and KCEC that extended through 2040 and the withdrawal of KCEC from membership in us. As part of the Withdrawal Agreement, we received $37 million net cash, which consisted of $49.5 million as an early termination fee for withdrawing from membership in us offset by $12.5 million for the retirement of KCEC’s patronage capital. This resulted in $47.6 million in other income, which was deferred by our Board. As part of our Board approving the new A–40 rate schedule, which was implemented on January 1, 2017, the Board approved the income recognition in 2017 of $10.0 million of deferred membership withdrawal income. The remaining deferred membership withdrawal income will be refunded to Members through reduced rates when recognized in other income in future periods.
Schedule of investments in other associations	Investments in other associations are as follows (dollars in thousands): 2016 2015 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 (dollars in thousands): 2016 2015 Investment in Trapper Mine $ $ Advances to Dry Fork Mine Investments in and advances to coal mines $ $
Schedule of other deferred charges	Other deferred charges are as follows (dollars in thousands): 2016 2015 Preliminary surveys and investigations $ $ Advances to operating agents of jointly owned facilities Interest rate swaps — 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 (dollars in thousands): 2016 2015 Asset retirement obligation at beginning of period $ $ Liabilities incurred Liabilities settled Accretion expense Change in cash flow estimate Asset retirement obligation at end of period $ $
Schedule of other deferred credits and other liabilities	The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands): 2016 2015 Transmission easements $ $ TEP transmission refund — Customer deposits Unearned revenue Other Total other deferred credits and other liabilities $ $

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 (these electric plant in service, accumulated depreciation and construction work in progress amounts are included in the electric plant table above) (dollars in 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 (dollars in thousands): 2016 2015 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 (dollars in thousands): Annual Depreciation Rate 2016 2015 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, 2016
INTANGIBLES
Schedule of amortization of intangible assets	The amortization was $7.3 million in each of the years 2016, 2015 and 2014 and will be recognized over each of the next three years as follows (dollars in thousands): 2017 $ 2018 2019 $

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2016
LONG-TERM DEBT.
Schedule of long-term debt	Long-term debt consists of the following (dollars in thousands): 2016 2015 Mortgage notes payable 3.66% to 8.08% CFC, due through 2028 $ $ 2.63% to 6.17% CoBank, ACB, due through 2042 First Mortgage Bonds, Series 2016A, 4.25% due 2046 — 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, due through 2026 Variable rate CFC, LIBOR-based term loan, due through 2049 Variable rate CoBank, ACB, LIBOR-based term loan, due through 2044 Variable rate, Revolving Credit Agreement, LIBOR-based revolving credit, matures 2019 — Pollution control revenue bonds City of Gallup, NM, 5.00%, Series 2005, due through 2017 Moffat County, CO Variable Rate Demand Series 2009, 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	Annual maturities of total debt adjusted for debt issuance costs, discounts and premiums at December 31, 2016 are as follows (dollars in thousands): 2017 $ 2018 2019 2020 2021 Thereafter $
Schedule of interest rate swap contracts	The terms of the interest rate swap contracts are as follows (dollars in thousands): Notional Fixed Benchmark Interest Effective Maturity Amount Rate (1) Rate (2) Date Date Interest rate swap - April 2016 $ % 30 year - LIBOR April 2019 April 2049 Interest rate swap - June 2016 30 year - LIBOR June 2019 June 2049 $ (1) We will pay. We will receive.

SHORT-TERM BORROWINGS (Tables)

SHORT-TERM BORROWINGS (Tables)	12 Months Ended
	Dec. 31, 2016
SHORT-TERM BORROWINGS
Schedule of commercial paper	Commercial paper consisted of the following (dollars in thousands): 2016 2015 Commercial paper outstanding, net of discounts $ $ — Weighted average interest rate % N/A

FAIR VALUE (Tables)

FAIR VALUE (Tables)	12 Months Ended
	Dec. 31, 2016
Marketable securities
FAIR VALUE
Schedule of carrying amounts and fair values of assets and liabilities	The amortized cost and fair values of our marketable securities are as follows (dollars in thousands): 2016 2015 Amortized Estimated Amortized Estimated Cost Fair Value Cost Fair Value Marketable securities $ $ $ $
Long-term debt
FAIR VALUE
Schedule of carrying amounts and fair values of assets and liabilities	The principal amounts and fair values of our debt are as follows (dollars in thousands): 2016 2015 Principal Estimated Principal Estimated Amount Fair Value Amount Fair Value Total debt $ $ $ $

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2016
INCOME TAXES
Schedule of components of net deferred tax liability	Components of our net deferred tax liability are as follows (dollars in thousands): 2016 2015 Deferred tax assets Safe harbor lease receivables $ $ Net operating loss carryforwards Alternative minimum tax credit carryforwards Deferred revenues and membership withdrawal 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	2016 2015 2014 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, 2016
LEASES
Schedule of minimum future lease revenues	The minimum future lease revenues under these gas tolling arrangements at December 31, 2016 are as follows (dollars in thousands): 2017 $ 2018 2019 $
Schedule of operating lease commitments	Our operating lease commitments for this gas tolling arrangement at December 31, 2016 are as follows (dollars in thousands): 2017 $ 2018 2019 $

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2016
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 our consolidated statements of financial position as follows (dollars in thousands): 2016 2015 Postretirement medical benefit obligation at beginning of year $ $ Service cost Interest cost Plan amendments - prior service credit — 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 (dollars in thousands): 2016 2015 Amounts included in accumulated other comprehensive income at beginning of year $ $ Amortization of actuarial loss into income Plan amendments - prior service credit — Amortization of prior service credit into income — Actuarial gain (loss) Amounts included in accumulated other comprehensive income at end of year $ $
Schedule of the assumptions used in the 2016 actuarial study performed for our postretirement medical benefit obligation	The assumptions used in the 2016 actuarial study performed for our postretirement medical benefit obligation were as follows: Weighted-average discount rate % Initial health care cost trend (2016) % 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 (dollars in 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 during the next 10 years (dollars in thousands): 2017 $ 2018 2019 2020 2021 2022 through 2026 $

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2016
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 (dollars in thousands): 2016 2015 2014 WAPA $ $ $ Basin
Coal
COMMITMENTS AND CONTINGENCIES
Schedule of future minimum commitments	At December 31, 2016, the annual minimum coal purchases under these contracts are as follows (dollars in thousands): 2017 $ 2018 2019 2020 2021 Thereafter $

QUARTERLY FINANCIAL DATA (UNA32

QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables)	12 Months Ended
	Dec. 31, 2016
QUARTERLY FINANCIAL DATA (UNAUDITED)
Schedule of Quarterly Financial Information	First Second Third Fourth Statement of Operations Data Quarter Quarter Quarter Quarter Total 2016 Operating revenues $ $ $ $ $ Operating margins Net margins attributable to the Association 2015 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, 2016USD ($)MWhcustomer	Dec. 31, 2015USD ($)MWhcustomer	Dec. 31, 2014USD ($)MWh
Electricity sales
Total megawatt-hours sold | MWh	18.4	17.8	18.7
Total electric sales	$ 1.3	$ 1.2	$ 1.3
Energy resources, percentage supplied by generation	59.00%	63.00%	63.00%
Members
Electricity sales
Number of Members | customer	43	44
Total electric sales	$ 1.1
Total Megawatt-Hours | Customer Concentration | Members
Electricity sales
Percentage of benchmark	86.00%	89.00%	85.00%
Electric sales provided by generation | Customer Concentration | Members
Electricity sales
Percentage of benchmark	90.00%	90.00%	85.00%

ORGANIZATION - Long Term Contra

ORGANIZATION - Long Term Contracts (Details) - Members - customer	6 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015
Member contracts
Number of Members		43	44
Minimum percent of purchase and receive obligation (as a percent)		95.00%
Long-term Supply Contracts
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		18
Contracts expiring in 2050
Member contracts
Number of Members	42
Percentage of revenue		96.00%

ORGANIZATION - Customer (Detail

ORGANIZATION - Customer (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)employeecustomeragreement	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Electricity sales
Member electric sales	$ 1,134,781	$ 1,125,699	$ 1,101,471
Number of employees | employee	1,585
Total Revenues | Customer Concentration | United Power, Inc.
Electricity sales
Number of members exceeding 10% of revenues | customer	1
Member electric sales	$ 159,400
Percentage of benchmark	11.80%
Member Revenues | Customer Concentration | United Power, Inc.
Electricity sales
Number of members exceeding 10% of revenues | customer	1
Member electric sales	$ 159,400
Percentage of benchmark	14.00%
Workforce Subject to Collective Bargaining Arrangements | Unionized Employees Concentration Risk
Electricity sales
Number of employees | employee	335
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 ACCOUN36

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Segments and Business Combinations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
SEGMENT REPORTING:
Number of operating segments | segment	1
Number of reportable segments | segment	1
BUSINESS COMBINATIONS:
Goodwill recognized for asset acquisitions | $	$ 0
Impairments of long-lived assets | $	$ 0	$ 0	$ 0

SUMMARY OF SIGNIFICANT ACCOUN37

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Regulatory Assets and Liabilities (Details) $ in Thousands	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)facility	Dec. 31, 2015USD ($)
Regulatory assets and liabilities
Number of jointly owned facilities | facility		3
Regulatory assets and liabilities
Regulatory assets		$ 395,615	$ 415,081
Regulatory liabilities		95,512	45,000
Net regulatory asset		300,103	370,081
Deferred revenue
Regulatory assets and liabilities
Regulatory liabilities		35,800	45,000
Deferred revenue recognized		9,200
Deferred revenue received in 2008
Regulatory assets and liabilities
Regulatory liabilities		10,000
Deferred revenue expected to be recognized in 2017		10,000
Deferred revenue received in 2011
Regulatory assets and liabilities
Regulatory liabilities		35,000
Deferred revenue expected to be recognized in 2017		20,000
Deferred revenue from membership withdrawal
Regulatory assets and liabilities
Regulatory liabilities		47,572
Deferred revenue expected to be recognized in 2017		10,000
KCEC | Deferred revenue from membership withdrawal
Regulatory assets and liabilities
Deferred membership withdrawal income	$ 47,600
Craig 3 Lease
Regulatory assets and liabilities
Annual amortization expense		6,500
Deferred income tax expense
Regulatory assets and liabilities
Regulatory assets		30,517	28,629
Deferred prepaid lease expense | Craig 3 Lease
Regulatory assets and liabilities
Regulatory assets		9,710	16,183
Deferred prepaid lease expense | Springerville 3 Lease
Regulatory assets and liabilities
Regulatory assets		90,587	92,878
Annual amortization expense		$ 2,300
Amortization period		47 years
Goodwill | TCP
Regulatory assets and liabilities
Regulatory assets		$ 57,692	60,541
Annual amortization expense		$ 2,800
Amortization period		25 years
Goodwill | Colowyo Coal
Regulatory assets and liabilities
Regulatory assets		$ 40,294	41,327
Annual amortization expense		$ 1,000
Amortization period		44 years
Deferred debt prepayment transaction costs
Regulatory assets and liabilities
Regulatory assets		$ 166,815	175,444
Annual amortization expense		$ 8,600
Amortization period		21 years 4 months 24 days
Interest rate swaps
Regulatory assets and liabilities
Regulatory liabilities		$ 12,140
Other
Regulatory assets and liabilities
Regulatory assets			$ 79
Withdrawal Agreement | KCEC
Regulatory assets and liabilities
Net cash received from the early termination of membership	37,000
Early termination fees received for withdrawal from membership	49,500
Retirement of patronage capital	$ 12,500

SUMMARY OF SIGNIFICANT ACCOUN38

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Electric Plant and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
ELECTRIC PLANT AND DEPRECIATION:
Interest rates charged during construction (as a percent)	4.70%	4.40%	4.70%
Interest capitalized during construction	$ 13.8	$ 13.5	$ 15

SUMMARY OF SIGNIFICANT ACCOUN39

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Investments in Other Associations (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Investments in other associations
Investment in other associations (in dollars)	$ 139,350	$ 123,686
Basin Electric Power Cooperative
Investments in other associations
Investment in other associations (in dollars)	99,301	84,875
National Rural Utilities Cooperative Finance Corporation
Investments in other associations
Investment in other associations (in dollars)	26,933	26,808
CoBank, ACB
Investments in other associations
Investment in other associations (in dollars)	7,217	6,212
Western Fuels Association
Investments in other associations
Investment in other associations (in dollars)	2,245	2,275
Other
Investments in other associations
Investment in other associations (in dollars)	$ 3,654	$ 3,516

SUMMARY OF SIGNIFICANT ACCOUN40

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Investments in and Advances to Coal Mines (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Investments in and advances to coal mines
Investments in and advances to coal mines	$ 18,176	$ 16,221
Trapper Mining
Investments in and advances to coal mines
Investment in coal mine	14,503	14,072
Dry Fork Mine
Investments in and advances to coal mines
Advances	$ 3,673	$ 2,149

SUMMARY OF SIGNIFICANT ACCOUN41

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Investments and Marketable Securities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Director and Executive Deferred Compensation Plans
Marketable securities
Available-for-sale securities, amortized cost	$ 1	$ 1
Available-for-sale securities, fair value	1.1	1.2
Net unrealized gain	0.1	0.1
Securities pledged as collateral | Colowyo Bonds, 10.19%, due through 2016 | US Treasury Notes
Restricted cash and investments
Investments in securities pledged as collateral	0	8.7
Defeasance investment, principal	$ 0	7.4
Unamortized premium		0.2
Restricted cash		$ 1.1

SUMMARY OF SIGNIFICANT ACCOUN42

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
INVENTORIES:
Coal inventory	$ 63,945	$ 59,277
Owned Generating Stations
INVENTORIES:
Coal inventory	$ 46,000	$ 42,200

SUMMARY OF SIGNIFICANT ACCOUN43

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Deferred Charges (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Other deferred charges
Preliminary surveys and investigations	$ 111,592	$ 107,146
Advances to operating agents of jointly owned facilities	11,871	11,537
Interest rate swaps	12,140
Other	3,775	3,852
Total other deferred charges	139,378	122,535
Holcomb Station Project
Other deferred charges
Preliminary surveys and investigations	$ 91,300	$ 86,700

SUMMARY OF SIGNIFICANT ACCOUN44

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Asset Retirement Obligation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Aggregate carrying amounts of asset retirement obligations
Asset retirement obligation at beginning of period	$ 55,215	$ 53,754
Liabilities incurred	5,844	1,802
Liabilities settled	(1,298)	(3,028)
Accretion expense	3,751	3,324
Change in cash flow estimate	(4,929)	(637)
Asset retirement obligation at end of period	$ 58,583	$ 55,215

SUMMARY OF SIGNIFICANT ACCOUN45

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Deferred Credits and Other Liabilities (Details) - USD ($) $ in Thousands	Jan. 12, 2017	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Deferred credits and other liabilities
Transmission easements			$ 20,562	$ 21,416
Customer deposits			3,338	6,116
Unearned revenue			4,000	4,803
Other			22,743	25,088
Total other deferred credits and other liabilities			66,164	$ 57,423
Transmission Services Agreement | TEP
Deferred credits and other liabilities
Refund received on transmission services agreements			15,500
Payment for transmission services settlement	$ 7,750
Reduction in transmission expense		$ 7,750
TEP transmission refund			15,521
Transmission Right of Way Easements
Deferred credits and other liabilities
Total due for easement right of way			$ 34,500

SUMMARY OF SIGNIFICANT ACCOUN46

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Memberships (Details) - Members $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)customer	Dec. 31, 2015USD ($)customer
Memberships
Number of Members | customer	43	44
Membership fee per member | $	$ 5	$ 5

SUMMARY OF SIGNIFICANT ACCOUN47

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Interchange Power (Details) - Accounts Payable - Interchange Power - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
INTERCHANGE POWER:
Interchange liability	$ 1.9	$ 1.6
Purchased Power Expense
INTERCHANGE POWER:
Net interchange activity, expense (income)	$ 0.3	$ 0.1	$ (0.5)

SUMMARY OF SIGNIFICANT ACCOUN48

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - New Accounting Pronouncements (Details) $ in Billions	12 Months Ended
	Dec. 31, 2016USD ($)customer	Dec. 31, 2015USD ($)customer	Dec. 31, 2014USD ($)
Electric sales	$ 1.3	$ 1.2	$ 1.3
Members
Number of Members | customer	43	44
Electric sales	$ 1.1
Member sales as a percent of operating revenue	84.00%

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Electric Plant (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Electric Plant
Electric plant in service (at cost)	$ 5,682,613	$ 5,486,518
Construction work in progress	212,081	216,279
Less allowances for depreciation and amortization	(2,361,555)	(2,240,732)
Net electric plant	3,533,139	3,462,065
Electric Plant
Electric Plant
Generation plant	3,542,578	3,498,248
Transmission plant	1,407,846	1,294,151
General plant	461,148	430,842
Other plant	271,041	263,277
Electric plant in service (at cost)	5,682,613	5,486,518
Construction work in progress	212,081	216,279
Less allowances for depreciation and amortization	(2,361,555)	(2,240,732)
Net electric plant	$ 3,533,139	$ 3,462,065
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 EQUIPMENT50

PROPERTY, PLANT AND EQUIPMENT - Construction Commitments (Details) - Electric Plant - Construction Commitments $ in Millions	Dec. 31, 2016USD ($)
Construction commitments
Total obligation	$ 56.5
Future commitments
2,017	51.9
2,018	4.2
2,019	$ 0.4

PROPERTY, PLANT AND EQUIPMENT51

PROPERTY, PLANT AND EQUIPMENT - Revised SIP (Details) $ in Thousands	4 Months Ended	12 Months Ended
	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)MW	Dec. 31, 2015USD ($)
Jointly owned facilities
Net book value	$ 3,533,139		$ 3,533,139	$ 3,462,065
Increase in asset retirement obligation			$ (4,929)	$ (637)
Adopted Depreciation Rates | Forecast
Jointly owned facilities
Expected increase (decrease) in annual depreciation expense associated with shortened asset life		$ (21,000)
Craig Generating Station Unit 1
Jointly owned facilities
Increase in monthly depreciation expense	$ 200
Craig Generating Station Unit 1 | Tri-State
Jointly owned facilities
Generating unit capacity (in megawatts) | MW			102
Tri-State share (as a percent)	24.00%		24.00%
Net book value	$ 28,900		$ 28,900
Increase in depreciation expense	800
Expected increase (decrease) in annual depreciation expense associated with shortened asset life			2,300
Nucla Generating Station
Jointly owned facilities
Net book value	62,600		62,600
Increase in depreciation expense	2,800
Expected increase (decrease) in annual depreciation expense associated with shortened asset life			8,400
Increase in monthly depreciation expense	$ 700
Increase in asset retirement obligation			$ 2,900

PROPERTY, PLANT AND EQUIPMENT52

PROPERTY, PLANT AND EQUIPMENT - Jointly Owned Facilities (Details) $ in Thousands	Dec. 31, 2016USD ($)
Jointly owned facilities
Electric plant in service	$ 833,006
Accumulated depreciation	598,016
Construction work in progress	$ 55,397
Yampa
Jointly owned facilities
Tri-State share (as a percent)	24.00%
Electric plant in service	$ 346,736
Accumulated depreciation	232,273
Construction work in progress	$ 40,473
MBPP
Jointly owned facilities
Tri-State share (as a percent)	24.13%
Electric plant in service	$ 403,582
Accumulated depreciation	293,825
Construction work in progress	$ 14,924
San Juan Project
Jointly owned facilities
Tri-State share (as a percent)	8.20%
Electric plant in service	$ 82,688
Accumulated depreciation	$ 71,918

PROPERTY, PLANT AND EQUIPMENT53

PROPERTY, PLANT AND EQUIPMENT - Other Plant (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Other Plant Assets
Other plant assets	$ 234,457	$ 227,957
Less allowances for depreciation, amortization, and depletion	(89,809)	(73,471)
Net other plant	$ 144,648	154,486
Elk Ridge
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
Less allowances for depreciation, amortization, and depletion	$ (83,595)	(67,601)
Net other plant	138,593	148,087
Mine assets | Colowyo Mine
Other Plant Assets
Other plant assets	173,626	166,157
Mine assets | New Horizon Mine
Other Plant Assets
Other plant assets	47,404	48,373
Mine assets | Fort Union Mine
Other Plant Assets
Other plant assets	1,158	1,158
Non-utility assets
Other Plant Assets
Other plant assets	12,269	12,269
Less allowances for depreciation, amortization, and depletion	(6,214)	(5,870)
Net other plant	$ 6,055	$ 6,399

INTANGIBLES - Intangible Assets

INTANGIBLES - Intangible Assets (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2011
INTANGIBLE ASSETS:
Amortization of intangible asset	$ 7,324	$ 7,324	$ 7,324
Future amortization of intangible assets
Intangible assets, net	18,310	25,634
Purchase Power Agreement
INTANGIBLE ASSETS:
Amortization of intangible asset	$ 7,300	$ 7,300	$ 7,300
Intangible asset, remaining life (in years)	3 years
Future amortization of intangible assets
2,017	$ 7,324
2,018	7,324
2,019	3,662
Intangible assets, net	$ 18,310
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, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2011
Intangible Liabilities
Amortization benefit	$ 2,900	$ 3,200	$ 3,200
Intangible liabilities, future amortization
Intangible liability, total	3,263	6,221
Colowyo Coal
Intangible Liabilities
Intangible liability				$ 18,000
Intangible liabilities, future amortization
Amortization benefit in next year	3,300
Intangible liability, total	$ 3,300	$ 6,200

LONG-TERM DEBT - Components (De

LONG-TERM DEBT - Components (Details) $ in Thousands	Dec. 31, 2016USD ($)instrument	Dec. 31, 2015USD ($)
Unsecured debt
Number of unsecured debt instruments | instrument	3
Unsecured notes	$ 49,600
Long-term debt, components
Total debt	3,259,721	$ 3,371,679
Less debt issuance costs	(22,255)	(21,201)
Less debt discounts	(10,569)	(8,739)
Plus debt premiums	20,711	23,218
Total debt adjusted for discounts, premiums and debt issuance costs	3,247,608	3,364,957
Less current maturities	(107,903)	(91,419)
Long-term debt	3,139,705	3,273,538
3.66% to 8.08% CFC, due through 2028
Long-term debt, components
Total debt	$ 83,653	86,979
3.66% to 8.08% CFC, due through 2028 | Minimum
Interest rate terms
Stated interest rate (as a percent)	3.66%
3.66% to 8.08% CFC, due through 2028 | Maximum
Interest rate terms
Stated interest rate (as a percent)	8.08%
2.63% to 6.17% CoBank, ACB, due through 2042
Long-term debt, components
Total debt	$ 268,045	278,086
2.63% to 6.17% CoBank, ACB, due through 2042 | Minimum
Interest rate terms
Stated interest rate (as a percent)	2.63%
2.63% to 6.17% CoBank, ACB, due through 2042 | Maximum
Interest rate terms
Stated interest rate (as a percent)	6.17%
First Mortgage Bonds, Series 2016A, 4.25% due 2046
Long-term debt, components
Total debt	$ 250,000
Interest rate terms
Stated interest rate (as a percent)	4.25%
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	$ 81,429	108,571
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, due through 2026
Long-term debt, components
Total debt	$ 598	644
Variable rate CFC, LIBOR-based term loan, due through 2049
Long-term debt, components
Total debt	102,220	102,220
Variable rate CoBank, ACB, LIBOR-based term loan, due through 2044
Long-term debt, components
Total debt	102,220	102,220
Revolving Credit Agreement
Long-term debt, components
Total debt		271,000
Pollution control revenue bonds, City of Gallup, NM, 5.00%, Series 2005, due through 2017
Long-term debt, components
Total debt	$ 5,540	10,815
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
Springerville certificates, Series A, 6.04%, due through 2018
Long-term debt, components
Total debt	$ 52,994	89,968
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, 10.19%, due through 2016
Long-term debt, components
Total debt		7,693
Interest rate terms
Stated interest rate (as a percent)	10.19%
Other
Long-term debt, components
Total debt	$ 1,222	$ 1,683

LONG-TERM DEBT - Other Informat

LONG-TERM DEBT - Other Information (Details) - USD ($)	Jul. 27, 2016	Nov. 30, 2015	Sep. 30, 2015	Dec. 31, 2016	May 23, 2016	Dec. 31, 2015	Jul. 30, 2015	Oct. 30, 2014
Credit facility information
Outstanding borrowings				$ 3,259,721,000		$ 3,371,679,000
Series 2016A Bonds
Bonds
Face amount of debt issued					$ 250,000,000
Stated interest rate (as a percent)					4.25%
Series 2016A Bonds | Registration Rights Agreement
Credit facility information
Proceeds from exchange of long-term debt	$ 0
First Mortgage Bonds, Series 2016A, Unregistered | Registration Rights Agreement
Credit facility information
Face amount of debt exchanged	250,000,000
First Mortgage Bonds, Series 2016A, Registered | Registration Rights Agreement
Bonds
Face amount of debt issued	$ 250,000,000
Series 2014 Bonds
Bonds
Face amount of debt issued								$ 500,000,000
Series 2014 Bonds | Registration Rights Agreement
Credit facility information
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
Credit facility information
Outstanding borrowings				46,800,000		46,800,000
Revolving Credit Agreement
Credit facility information
Maximum borrowing capacity				750,000,000
Outstanding borrowings						271,000,000
Available borrowing capacity				582,400,000
Revolving Credit Agreement
Credit facility information
Outstanding borrowings				$ 0		$ 271,000,000
Revolving Credit Agreement | Pollution control revenue bonds, Moffat County, CO Variable Rate Demand Series 2009, due 2036 | Bank of America
Credit facility information
Letter of credit, period		364 days		364 days
Commercial Paper | Revolving Credit Agreement
Credit facility information
Available borrowing capacity				$ 380,100,000

LONG-TERM DEBT - Annual Maturit

LONG-TERM DEBT - Annual Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Annual maturities of total debt adjusted for debt issuance costs, discounts and premiums
2,017	$ 107,903
2,018	78,186
2,019	97,638
2,020	84,695
2,021	90,956
Thereafter	2,788,230
Total debt adjusted for discounts, premiums and debt issuance costs	$ 3,247,608	$ 3,364,957

LONG-TERM DEBT - Interest Rate

LONG-TERM DEBT - Interest Rate Swaps (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Interest rate swaps
Interest rate swaps
Notional Amount	$ 170,000
Interest Rate Swap - April 2016
Interest rate swaps
Notional Amount	$ 90,000
Fixed Rate	2.355%
Benchmark Interest Rate	30 year - LIBOR
Effective Date	Apr. 1, 2019
Maturity Date	Apr. 1, 2049
Interest Rate Swap - June 2016
Interest rate swaps
Notional Amount	$ 80,000
Fixed Rate	2.304%
Benchmark Interest Rate	30 year - LIBOR
Effective Date	Jun. 1, 2019
Maturity Date	Jun. 1, 2049

SHORT-TERM BORROWINGS (Details)

SHORT-TERM BORROWINGS (Details) - USD ($) $ in Thousands	1 Months Ended
	May 31, 2016	Dec. 31, 2016
Short-term borrowings
Amount outstanding		$ 119,901
Commercial Paper
Short-term borrowings
Amount outstanding		$ 119,901
Weighted average interest rate		0.89%
Commercial Paper | Maximum
Short-term borrowings
Maximum amount per commercial paper sublimit	$ 500,000
Term of issuance	397 days
Revolving Credit Agreement | Commercial Paper
Short-term borrowings
Available borrowing capacity		$ 380,100

FAIR VALUE (Details)

FAIR VALUE (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Fair value:
Interest rate swaps	$ 12,140
Principal Amount
Fair value:
Marketable securities	987	$ 1,022
Long-term debt	3,259,721	3,371,679
Estimated Fair Value
Fair value:
Cash and cash equivalents	49,100	75,100
Estimated Fair Value | Level 2
Fair value:
Long-term debt	3,543,640	3,616,946
Estimated Fair Value | Recurring | Level 1
Fair value:
Marketable securities	1,103	$ 1,151
Estimated Fair Value | Recurring | Level 2 | Other Deferred Charges
Fair value:
Interest rate swaps	$ 12,100

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income tax expense (benefit)	$ (1,417)	$ 0	$ 0
Alternative minimum tax expense	500
Alternative Minimum Tax Credit Carryforwards
Tax credit carryforwards	$ 1,900

INCOME TAXES - Net Deferred Tax

INCOME TAXES - Net Deferred Tax Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Deferred tax assets
Safe harbor lease receivables	$ 33,355	$ 35,945
Net operating loss carryforwards	142,286	152,936
Alternative minimum tax credit carryforwards	2,417	3,834
Deferred Tax Assets, Deferred Income	30,583	16,933
Colowyo Coal- coal contract intangible liability	1,228	2,341
Other	41,066	35,332
Deferred tax assets, total	250,935	247,321
Deferred tax liabilities
Basis differences- property, plant and equipment	162,928	160,494
Capital credits from other associations	44,268	38,663
Deferred debt prepayment transaction costs	62,773	66,020
Other	11,483	10,773
Deferred tax liabilities, total	281,452	275,950
Net deferred tax liability	(30,517)	(28,629)
Deferred tax treatment of regulatory assets
Regulatory assets	395,615	415,081
Deferred income tax expense
Deferred tax treatment of regulatory assets
Increase in net deferred tax liability not recognized as expense	1,900
Regulatory assets	$ 30,517	$ 28,629

INCOME TAXES - Effective Tax Ra

INCOME TAXES - Effective Tax Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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	5.85%	(0.58%)	1.40%
Postretirement medical actuarial gains and losses	1.04%	(1.09%)	2.44%
Various book tax differences	(7.66%)	2.84%	4.52%
Regulatory treatment of deferred taxes	(3.79%)	(1.17%)	(8.36%)
Effective tax rate	(4.56%)	0.00%	0.00%

INCOME TAXES - Operating Loss a

INCOME TAXES - Operating Loss and Tax Credit Carryforwards (Details) $ in Millions	Dec. 31, 2016USD ($)
Federal
Carryforwards
Net operating loss carryforwards	$ 378.1
Alternative Minimum Tax Credit Carryforwards
Carryforwards
Tax credit carryforwards	$ 1.9

LEASES - Lessor (Details)

LEASES - Lessor (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)facilityMW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Operating leases - LESSOR
Generating units, accumulated depreciation	$ 2,361,555	$ 2,240,732
Gas tolling arrangement
Operating leases - LESSOR
Lease revenues	17,500	30,100	$ 30,600
Generation plant	114,000	223,000
Generating units, accumulated depreciation	$ 63,000	$ 106,000
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 | Third Party
Operating leases - LESSOR
Number of generating station units | facility	2
Gas tolling arrangement | Limon Generating Station
Operating leases - LESSOR
Number of generating station units | facility	2
Gas tolling arrangement | Limon Generating Station | Third Party
Operating leases - LESSOR
Number of generating station units | facility	1

LEASES - Lessor - Minimum Lease

LEASES - Lessor - Minimum Lease Payments Receivable (Details) - Gas tolling arrangement $ in Thousands	Dec. 31, 2016USD ($)
Minimum future lease revenues
2,017	$ 11,268
2,018	11,269
2,019	5,634
Total minimum future lease revenues	$ 28,171

LEASES - Lessee (Details)

LEASES - Lessee (Details) - Gas tolling arrangement - Brush Generating Station $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)MW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Operating leases - LESSEE
Megawatt usage | MW	70
Term of agreement	10 years
Rent expense	$ 5,300	$ 5,300	$ 5,300
Operating lease commitments
2,017	5,678
2,018	5,855
2,019	6,031
Total operating lease commitments	$ 17,564

RELATED PARTIES (Details)

RELATED PARTIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
RELATED PARTIES
Capital credit allocations	$ 20,349	$ 9,189	$ 8,684
Trapper Mining
RELATED PARTIES
Tri-State share (as a percent)	26.57%	26.57%	26.57%
Investment in coal mine	$ 14,500	$ 14,100
Trapper Mining | Capital Credits from Cooperatives
RELATED PARTIES
Capital credit allocations	500	500	$ 500
Trapper Mining | Coal
RELATED PARTIES
Purchases	$ 16,900	$ 17,700	$ 30,600
Trapper Mining | Coal | Yampa
RELATED PARTIES
Percent of purchases supplied by related party	26.00%	26.00%	35.00%

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 ($)	Dec. 31, 2016USD ($)employee	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
DEFINED BENEFIT PLAN
Number of employees | employee					1,585
DEFINED CONTRIBUTION PLAN
Employee contribution, maximum percentage of eligible earnings					100.00%
Contributions made					$ 3,000,000	$ 3,000,000	$ 2,900,000
Collective bargaining agreements and their bargaining unit employees
DEFINED CONTRIBUTION PLAN
Contributions made					$ 0
Non-bargaining unit employees, Colowyo Coal employees
DEFINED CONTRIBUTION PLAN
Employer contribution, maximum percentage of eligible earnings					7.00%
Non-bargaining unit employees, excluding Colowyo Coal employees
DEFINED CONTRIBUTION PLAN
Employer contribution, maximum percentage of eligible earnings					1.00%
Maximum | Non-bargaining unit employees, Colowyo Coal employees
DEFINED CONTRIBUTION PLAN
Employer matching contribution, maximum percentage of employee contributions					5.00%
Defined benefit pension plan | Collective bargaining agreements and their bargaining unit employees
DEFINED BENEFIT PLAN
Number of employees | employee					335
RS Plan | Defined benefit pension 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					$ 24,800,000	$ 22,900,000	$ 21,500,000
Plan funded status	At least 80 percent	At least 80 percent
RS Plan Contribution Prepayment Option | Defined benefit pension plan
DEFINED BENEFIT PLAN
Prepayment amount, multiple of annual required contribution			2.5
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					223
New Horizon Mine | Collective bargaining agreements and their bargaining unit employees
DEFINED CONTRIBUTION PLAN
Employee contribution, maximum percentage of eligible earnings					1.00%

EMPLOYEE BENEFIT PLANS - Postre

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other Than Pensions, Plans, Amendments and Obligations (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)plan	Dec. 31, 2015USD ($)plan
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 medical benefit and postemployment medical benefit obligations
Postretirement medical benefit obligation at beginning of year	$ 6,901
Postretirement and/or postemployment medical benefit obligation at end of year	8,174	$ 6,901
Postretirement Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
Postretirement medical benefit obligation at beginning of year	6,723	7,713
Service cost	549	593
Interest cost	285	270
Plan amendments - prior service cost		(896)
Benefit payments (net of contributions by participants)	(382)	(325)
Actuarial (gain) loss	821	(632)
Postretirement and/or postemployment medical benefit obligation at end of year	7,996	$ 6,723
Postretirement Medical Benefit Plans Amendment
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan		3
Age after which participants are no longer eligible for benefit coverage		65 years
Percentage reduction in liability		11.50%
Annual amortization of prior service cost		$ 100
Postemployment Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
Postretirement medical benefit obligation at beginning of year	178
Postretirement and/or postemployment medical benefit obligation at end of year	$ 178	$ 178
Non-bargaining unit employees | Medical Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3
Non-bargaining unit employees | Medical Plans | Maximum
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Qualifying age	65 years
Non-bargaining unit employees | Postretirement Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	2
Non-bargaining unit employees | Postretirement Medical Benefit Plans | Minimum
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Qualifying age	55 years
Non-bargaining unit employees | Postemployment Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3

EMPLOYEE BENEFIT PLANS - Post72

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, 2016	Dec. 31, 2015
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	$ 460	$ (1,082)
Reclassification adjustment included in income	38	14
Plan amendments - prior service cost		896
Amortization of prior period cost	79
Actuarial gain (loss) per actuarial study	(821)	632
Actuarial gain (loss) included in accumulated other comprehensive income at end of year	$ (402)	$ 460
Assumptions used
Weighted-average discount rate	3.77%
Initial health care cost trend (2015)	7.65%
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 5 months 12 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	$ 814
1% decrease, Accumulated postretirement medical benefit obligation	(708)
1% increase, Net periodic postretirement medical benefit expense	125
1% decrease, Net periodic postretirement medical benefit expense	$ (105)

EMPLOYEE BENEFIT PLANS - Expect

EMPLOYEE BENEFIT PLANS - Expected Future Benefits (Details) - Postretirement Medical Benefit Plans $ in Thousands	Dec. 31, 2016USD ($)
Expected future benefits to be paid related to the postretirement medical benefit obligation
2,017	$ 500
2,018	548
2,019	607
2,020	643
2,021	624
2022 and thereafter	3,257
Total	$ 6,179

VARIABLE INTEREST ENTITIES - Co

VARIABLE INTEREST ENTITIES - Consolidated Entities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Consolidated Variable Interest Entities
Noncontrolling interest included in consolidated statements of financial position (in dollars)	$ 109,147	$ 108,757
Interest expense (in dollars)	$ 144,877	142,570	$ 142,357
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)	$ 109,100	108,800
Depreciation and amortization (in dollars)	21,000	21,000	21,000
Interest expense (in dollars)	30,400	32,300	$ 34,100
Springerville Partnership | Primary Beneficiary | Electric Plant
Consolidated Variable Interest Entities
Assets of variable interest entity included in consolidated statements of financial position (in dollars)	832,300	853,300
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)	472,100	511,000
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)	$ 13,400	$ 14,300
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, 2016	Dec. 31, 2015
Unconsolidated Variable Interest Entities
Investment in other associations (in dollars)	$ 139,350	$ 123,686
Western Fuels Association
Unconsolidated Variable Interest Entities
Investment in other associations (in dollars)	2,245	2,275
Western Fuels Association | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments in other associations
Unconsolidated Variable Interest Entities
Investment in other associations (in dollars)	2,200	2,300
Trapper Mining
Unconsolidated Variable Interest Entities
Investment in coal mine	14,503	14,072
Trapper Mining | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments in other associations
Unconsolidated Variable Interest Entities
Investment in coal mine	$ 14,500	$ 14,100
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 | 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, 2016MW
Public Service Company of Colorado | Supply Contracts
Sales commitments
Megawatts	100
Salt River Project Agricultural Improvement and Power District | Long-term Supply Contracts
Sales commitments
Megawatts	100

COMMITMENTS AND CONTINGENCIES77

COMMITMENTS AND CONTINGENCIES - Coal Purchase Requirements (Details) - Coal $ in Thousands	Dec. 31, 2016USD ($)
Annual minimum coal purchases under contracts
2,017	$ 105,457
2,018	103,389
2,019	104,686
2,020	82,612
2,021	61,538
Thereafter	2,654
Total obligation	$ 460,336

COMMITMENTS AND CONTINGENCIES78

COMMITMENTS AND CONTINGENCIES - Electric Power Purchase Agreements (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)statejurisdictioncontractMW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
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 | $	$ 82,575	$ 89,986	$ 91,639
Basin Electric Power Cooperative
Electric Power Purchase Agreements
Megawatts purchased | MW	225
Costs under the above electric power purchase agreements | $	$ 145,557	$ 127,500	$ 132,649
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 CONTINGENCIES79

COMMITMENTS AND CONTINGENCIES - New Mexico Regulatory (Details) - Members $ in Millions	Oct. 02, 2014USD ($)	Nov. 30, 2012customer	Dec. 31, 2016customer	Dec. 31, 2015USD ($)customer	Dec. 31, 2014USD ($)
Rate setting
Number of Members | customer			43	44
New Mexico Public Regulation Commission ("NMPRC") | A-37 Wholesale Rate | New Mexico
Rate setting
Number of protests filed | customer		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

COMMITMENTS AND CONTINGENCIES80

COMMITMENTS AND CONTINGENCIES - Purchase Option and Development Agreement (Details) $ in Thousands	Dec. 16, 2010facilityMW	Jul. 26, 2007USD ($)	Dec. 31, 2008USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Purchase Option and Development Agreement
Preliminary surveys and investigations				$ 111,592	$ 107,146
Holcomb Station Project
Purchase Option and Development Agreement
Preliminary surveys and investigations				91,300	$ 86,700
Holcomb Station Project | Other Deferred Charges | Purchase Option and Development Agreement
Purchase Option and Development Agreement
Preliminary surveys and investigations				$ 91,300
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 CONTINGENCIES81

COMMITMENTS AND CONTINGENCIES - FERC Declaratory Order Petition (Details)	12 Months Ended
	Dec. 31, 2016entity
COMMITMENTS AND CONTINGENCIES
Percent limitation on Member self-supply of power	5.00%
Number of filed motions to intervene	4
Number of other generation and transmission cooperatives which have filed Request for Rehearing with FERC	5

COMMITMENTS AND CONTINGENCIES82

COMMITMENTS AND CONTINGENCIES - Las Conchas Fire (Details) - Damages from fire	Oct. 28, 2015USD ($)	Jun. 30, 2011plaintiff	Dec. 31, 2016USD ($)
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

QUARTERLY FINANCIAL DATA (UNA83

QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) - USD ($) $ in Thousands	3 Months Ended								4 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
QUARTERLY FINANCIAL DATA (UNAUDITED)
Operating revenues	$ 323,491	$ 384,791	$ 322,234	$ 323,462	$ 313,042	$ 388,102	$ 305,913	$ 328,391		$ 1,353,978	$ 1,335,448	$ 1,395,091
Operating margin	11,425	52,199	37,003	46,379	8,623	81,412	38,550	49,384		147,006	177,969	181,877
Net margins attributable to the Association	(6,061)	17,739	$ 2,537	$ 17,533	$ (21,299)	$ 48,302	$ 6,284	$ 20,126		31,748	53,413	64,236
Increase in operating revenues over comparable period in 2015	10,400
Recognition of deferred revenue										9,200		20,000
Increase in operating expenses over comparable period in 2015	7,600	25,900
Increase in purchased power expense over comparable period in 2015	16,700
Increase in depreciation, amortization and depletion expense over comparable period in 2015	4,500
Decrease in fuel expense over comparable period in 2015	$ 13,900
Increase in average cost per megawatt hour for purchased power over comparable period in 2015	3.50%
Increase in capital credits from cooperatives over comparable period in 2015	$ 11,400
Capital credit allocations										$ 20,349	$ 9,189	$ 8,684
Decrease in operating margins over comparable period in 2015		$ 29,200
Increase in net margins attributable to the Association over comparable period in 2015	15,200
Basin Electric Power Cooperative
QUARTERLY FINANCIAL DATA (UNAUDITED)
Capital credit allocations	14,400
Nucla Generating Station
QUARTERLY FINANCIAL DATA (UNAUDITED)
Increase in monthly depreciation expense									$ 700
Craig Generating Station Unit 1
QUARTERLY FINANCIAL DATA (UNAUDITED)
Increase in monthly depreciation expense									$ 200
Craig Generating Station Unit 1 | Nucla Generating Station
QUARTERLY FINANCIAL DATA (UNAUDITED)
Increase in depreciation, amortization and depletion expense over comparable period in 2015	3,600
Deferred revenue received in 2011
QUARTERLY FINANCIAL DATA (UNAUDITED)
Recognition of deferred revenue	$ 9,200