Tri-State Generation & Transmission Association 10-Q 14 Aug 17 2017 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	6 Months Ended
	Jun. 30, 2017shares
Document and Entity Information
Entity Registrant Name	Tri-State Generation & Transmission Association, Inc.
Entity Central Index Key	1,637,880
Document Type	10-Q
Document Period End Date	Jun. 30, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Document Fiscal Period Focus	Q2
Document Fiscal Year Focus	2,017
Entity Common Stock, Shares Outstanding	0

Consolidated Statements of Fina

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Electric Plant
In service	$ 5,761,091	$ 5,682,613
Construction work in progress	209,024	212,081
Total electric plant	5,970,115	5,894,694
Less allowances for depreciation and amortization	(2,425,069)	(2,361,555)
Net electric plant	3,545,046	3,533,139
Other plant	247,113	234,457
Less allowances for depreciation, amortization, and depletion	(100,392)	(89,809)
Net other plant	146,721	144,648
Total property, plant and equipment	3,691,767	3,677,787
Other assets and investments
Investment in other associations	140,413	139,350
Investments in and advances to coal mines	18,286	18,176
Restricted cash and investments	1,000	1,000
Intangible assets, net of accumulated amortization	14,648	18,310
Other noncurrent assets	11,828	11,542
Total other assets and investments	186,175	188,378
Current assets
Cash and cash equivalents	139,431	165,893
Restricted cash and investments	1,075	997
Deposits and advances	40,728	25,141
Accounts receivable—Members	114,700	97,925
Other accounts receivable	17,158	24,837
Coal inventory	55,896	63,945
Materials and supplies	86,392	87,768
Total current assets	455,380	466,506
Deferred charges
Regulatory assets	478,472	395,615
Prepayment—NRECA Retirement Security Plan	40,491	43,627
Other	46,754	139,378
Total deferred charges	565,717	578,620
Total assets	4,899,039	4,911,291
Capitalization
Patronage capital equity	989,681	961,364
Accumulated other comprehensive income (loss)	(279)	(286)
Noncontrolling interest	109,820	109,147
Total equity	1,099,222	1,070,225
Long-term debt	3,069,987	3,139,705
Total capitalization	4,169,209	4,209,930
Current liabilities
Member advances	6,731	11,363
Accounts payable	108,955	105,511
Short-term borrowing	240,206	119,901
Accrued expenses	28,357	32,719
Accrued interest	32,437	34,166
Accrued property taxes	16,987	27,584
Current maturities of long-term debt	77,337	107,903
Total current liabilities	511,010	439,147
Deferred credits and other liabilities
Regulatory liabilities	72,729	95,512
Deferred income tax liability	30,517	30,517
Intangible liabilities	1,765	3,263
Asset retirement obligations	55,980	58,583
Other	49,487	66,164
Total deferred credits and other liabilities	210,478	254,039
Accumulated postretirement benefit and postemployment obligations	8,342	8,175
Total equity and liabilities	$ 4,899,039	$ 4,911,291

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Operating Revenues
Member electric sales	$ 292,259	$ 275,517	$ 574,674	$ 547,286
Non-member electric sales	25,313	25,054	60,471	55,176
Other	21,329	20,051	42,185	41,622
Total revenues	338,901	320,622	677,330	644,084
Operating expenses
Purchased power	82,356	76,558	158,775	147,593
Fuel	58,508	51,560	119,321	112,550
Production	61,088	57,016	110,649	107,998
Transmission	40,486	39,132	74,286	75,592
General and administrative	4,841	6,392	12,021	11,502
Depreciation, amortization, and depletion	41,090	41,873	87,762	80,776
Coal mining	9,584	7,398	17,760	15,671
Other	3,978	3,690	8,768	9,020
Operating expenses	301,931	283,619	589,342	560,702
Operating margins	36,970	37,003	87,988	83,382
Other income
Interest	1,135	1,059	2,220	2,133
Capital credits from cooperatives	151	184	4,397	4,695
Membership withdrawal	2,500		5,000
Other income	409	694	1,429	1,735
Total other income	4,195	1,937	13,046	8,563
Interest expense, net of amounts capitalized	36,299	35,924	72,648	71,344
Income tax expense (benefit)	(302)	350	(604)	350
Net margins including noncontrolling interest	5,168	2,666	28,990	20,251
Net income attributable to noncontrolling interest	(377)	(129)	(673)	(181)
Net margins attributable to the Association	$ 4,791	$ 2,537	$ 28,317	$ 20,070

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Consolidated Statements of Comprehensive Income
Net margins including noncontrolling interest	$ 5,168	$ 2,666	$ 28,990	$ 20,251
Other comprehensive income (loss):
Unrealized gain (loss) on securities available for sale	22	21	46	(1)
Amortization of actuarial gain on postretirement benefit obligation included in net income	(19)	(23)	(39)	(45)
Other comprehensive income (loss)	3	(2)	7	(46)
Comprehensive income including noncontrolling interest	5,171	2,664	28,997	20,205
Net comprehensive income attributable to noncontrolling interest	(377)	(129)	(673)	(181)
Comprehensive income attributable to the Association	$ 4,794	$ 2,535	$ 28,324	$ 20,024

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, 2015	$ 952,082	$ 589	$ 108,757
Change in Equity
Net margins attributable to the Association	20,070			$ 20,070
Retirement of patronage capital	(12,466)
Unrealized gain (loss) on securities available for sale		(1)
Amortization of actuarial gain on postretirement benefit obligation included in net income		(45)
Net income attributable to noncontrolling interest			181	181
Equity distribution to noncontrolling interest			(59)
Equity at end of period at Jun. 30, 2016	959,686	543	108,879	1,069,108
Equity at beginning of period at Dec. 31, 2016	961,364	(286)	109,147	1,070,225
Change in Equity
Net margins attributable to the Association	28,317			28,317
Unrealized gain (loss) on securities available for sale		46
Amortization of actuarial gain on postretirement benefit obligation included in net income		(39)
Net income attributable to noncontrolling interest			673	673
Equity at end of period at Jun. 30, 2017	$ 989,681	$ (279)	$ 109,820	$ 1,099,222

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Operating activities
Net margins including noncontrolling interest	$ 28,990	$ 20,251
Adjustments to reconcile net margins to net cash used in operating activities:
Depreciation, amortization, and depletion	87,762	80,776
Amortization of intangible asset	3,662	3,662
Amortization of NRECA Retirement Security Plan prepayment	2,686	2,686
Amortization of debt issuance costs	1,003	940
Impairment loss - Holcomb Expansion	93,494
Deferred Holcomb Expansion impairment loss	(93,494)
Deferred membership withdrawal income		47,572
Recognition of deferred membership withdrawal income	(5,000)
Capital credit allocations from cooperatives and income from coal mines over refund distributions	(1,233)	(2,190)
Recognition of deferred revenue	(15,000)
Change in restricted cash and investments	(78)	(78)
Changes in operating assets and liabilities:
Accounts receivable	(13,382)	(3,424)
Coal inventory	8,049	(2,965)
Materials and supplies	1,376	(1,224)
Accounts payable and accrued expenses	6,703	3,475
Accrued interest	(1,729)	(312)
Accrued property taxes	(10,597)	(9,431)
Other deferred credits - TEP transmission settlement	(15,521)
Other deferred credits - TEP transmission refund		2,313
Other	(17,557)	(9,811)
Net cash provided by operating activities	60,134	132,240
Investing activities
Purchases of plant	(98,150)	(93,953)
Changes in deferred charges	321	(7,698)
Proceeds from other investments	61	313
Net cash used in investing activities	(97,768)	(101,338)
Financing activities
Changes in Member advances	(5,799)	754
Payments of long-term debt	(100,393)	(408,584)
Proceeds from issuance of debt		307,135
Increase in short-term borrowings, net	120,305	94,948
Retirement of patronage capital	(3,023)	(15,345)
Proceeds from investment in securities pledged as collateral		4,647
Other	82	(231)
Net cash provided by (used in) financing activities	11,172	(16,676)
Net increase (decrease) in cash and cash equivalents	(26,462)	14,226
Cash and cash equivalents - beginning	165,893	144,587
Cash and cash equivalents - end	139,431	158,813
Supplemental cash flow information:
Cash paid for interest	80,729	78,696
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$ (2,776)	$ (4,525)

PRESENTATION OF FINANCIAL INFOR

PRESENTATION OF FINANCIAL INFORMATION	6 Months Ended
	Jun. 30, 2017
PRESENTATION OF FINANCIAL INFORMATION
PRESENTATION OF FINANCIAL INFORMATION	NOTE 1 – PRESENTATION OF FINANCIAL INFORMATION The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. These unaudited consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2016 filed with the SEC. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Our consolidated financial position as of June 30, 2017, results of operations for the three and six months ended June 30, 2017 and 2016, and cash flows for the six months ended June 30, 2017 and 2016 are not necessarily indicative of the results that may be expected for an entire year or any other period. Basis of Consolidation Our consolidated financial statements include the accounts of Tri-State Generation and Transmission Association, Inc. (“Tri-State”, “we”, “our”, “us” or “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. 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 other operating expenses is included in our consolidated financial statements. Our share in each jointly owned facility is as follows as of June 30, 2017 (dollars in thousands): Electric Construction Tri-State Plant in Accumulated Work In Share Service Depreciation Progress Yampa Project - Craig Generating Station Units 1 and 2 24.00 % $ 349,958 $ 235,028 $ 46,928 MBPP - Laramie River Station 24.13 % 409,998 297,022 15,787 San Juan Project – San Juan Unit 3 8.20 % 82,688 77,138 — Total $ 842,644 $ 609,188 $ 62,715 Depreciation Rates Effective January 1, 2017, we adopted depreciation rates that reflect rates determined in a depreciation rate study for our transmission plant and most of our general plant. We expect that the new rates will result in a reduction in 2017 transmission and general plant depreciation expense of approximately $20.0 million. A depreciation rate study has been performed during 2017 for our generation plant and these rates will be adopted prospectively beginning July 1, 2017. We expect that the new rates will result in an increase in 2017 generation plant depreciation expense of approximately $0.5 million. Reclassifications Certain reclassifications have been made to the prior year financial statements to conform to the 2017 presentation.

ACCOUNTING FOR RATE REGULATION

ACCOUNTING FOR RATE REGULATION	6 Months Ended
	Jun. 30, 2017
ACCOUNTING FOR RATE REGULATION
ACCOUNTING FOR RATE REGULATION	NOTE 2 – 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 of Directors (“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 that we expect to recover from our member distribution systems (“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 revenue, other income, or a reduction in expense concurrent with their recovery in rates. Regulatory assets and liabilities are as follows (dollars in thousands): June 30, December 31, 2017 2016 Regulatory assets Deferred income tax expense (1) $ 30,517 $ 30,517 Deferred prepaid lease expense – Craig Unit 3 Lease (2) 6,473 9,710 Deferred prepaid lease expense – Springerville Unit 3 Lease (3) 89,441 90,587 Goodwill – J.M. Shafer (4) 56,268 57,692 Goodwill – Colowyo Coal (5) 39,777 40,294 Deferred debt prepayment transaction costs (6) 162,502 166,815 Deferred Holcomb Expansion impairment loss (7) 93,494 — Total regulatory assets 478,472 395,615 Regulatory liabilities Interest rate swaps (8) 9,357 12,140 Deferred revenues (9) 20,800 35,800 Membership withdrawal (10) 42,572 47,572 Total regulatory liabilities 72,729 95,512 Net regulatory asset $ 405,743 $ 300,103 (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 Unit 3 (“Craig 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 June 30, 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 impairment loss related to development costs, including costs for the option to purchase development rights, for a new coal-fired generating unit or units at Holcomb Generating Station (“Holcomb Expansion”). On March 17, 2017, the Kansas Supreme Court issued a decision upholding the air permit for one unit at Holcomb Generating Station of 895 megawatts. The air permit expires if construction of the Holcomb Expansion does not commence within 18 months. Although a final decision has not been made by our Board on whether to proceed with the construction of the Holcomb Expansion, we have assessed the probability of us entering into construction for the Holcomb Expansion as remote. Based on this assessment, we have determined that the costs incurred for the Holcomb Expansion are impaired and not recoverable. At the discretion of our Board, the impaired loss has been deferred as a regulatory asset and will be recovered from our Members in rates. The plan for the recovery has not been determined by our Board. Once the plan for recovery is determined, the deferred impairment loss will be recognized in other operating expenses. See Note 5 – Other Deferred Charges. (8) 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 6 – Long-Term Debt and Note 11 – Fair Value. (9) 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 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. $15.0 million of this deferred revenue was recognized in non-member electric sales revenue for the six-month period ended June 30, 2017. The remaining deferred non-member electric sales revenues will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods. (10) Represents the 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. from membership in us. As part of our Board approving the 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. $5.0 million of this deferred membership withdrawal income was recognized in other income for the six-month period ended June 30, 2017. The remaining deferred membership withdrawal income will be refunded to Members through reduced rates when recognized in other income in future periods.

INVESTMENTS IN OTHER ASSOCIATIO

INVESTMENTS IN OTHER ASSOCIATIONS	6 Months Ended
	Jun. 30, 2017
INVESTMENTS IN OTHER ASSOCIATIONS
INVESTMENTS IN OTHER ASSOCIATIONS	NOTE 3 – 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.

RESTRICTED CASH AND INVESTMENTS

RESTRICTED CASH AND INVESTMENTS	6 Months Ended
	Jun. 30, 2017
RESTRICTED CASH AND INVESTMENTS
RESTRICTED CASH AND INVESTMENTS	NOTE 4 – 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 are funds that have been 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.

OTHER DEFERRED CHARGES

OTHER DEFERRED CHARGES	6 Months Ended
	Jun. 30, 2017
OTHER DEFERRED CHARGES.
OTHER DEFERRED CHARGES	NOTE 5 – 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. Preliminary surveys and investigations was primarily comprised of expenditures for the Holcomb Expansion of $91.3 million as of December 31, 2016. There was no balance for the Holcomb Expansion as of June 30, 2017 because we have determined that the costs incurred for the Holcomb Expansion have been impaired. The impairment loss was deferred at the discretion of our Board. See Note 2 – Accounting for Rate Regulation. 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 Generating Station Units 1 and 2, and San Juan Project – San Juan Unit 3. We also make advance payments to the operating agent of Springerville Unit 3. In 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 June 30, 2017, 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): June 30, December 31, 2017 2016 Preliminary surveys and investigations $ 21,013 $ 111,592 Advances to operating agents of jointly owned facilities 11,693 11,871 Interest rate swaps 9,357 12,140 Other 4,691 3,775 Total other deferred charges $ 46,754 $ 139,378

LONG-TERM DEBT

LONG-TERM DEBT	6 Months Ended
	Jun. 30, 2017
LONG-TERM DEBT.
LONG-TERM DEBT	NOTE 6 – LONG-TERM DEBT The mortgage notes payable and pollution control revenue bonds of $2.7 billion are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates of $419 million are secured by the assets of Springerville Unit 3. We also have three unsecured notes in the aggregate amount of $45.9 million as of June 30, 2017. All long-term debt contains certain restrictive financial covenants, including a debt service ratio requirement and equity to capitalization ratio requirement. We have a secured revolving credit facility with Bank of America, N.A. and CoBank, ACB as Joint Lead Arrangers in the amount of $750 million (“Revolving Credit Agreement”) that expires on July 26, 2019. We had no outstanding borrowings as of June 30, 2017 and December 31, 2016. There is a 364-day, direct pay letter of credit issued under the Revolving Credit Agreement and provided by Bank of America, N.A. for the $46.8 million Moffat County, CO pollution control revenue bonds. As of June 30, 2017, we have $462.1 million in total aggregate availability (including $259.8 million under the commercial paper back-up sublimit) under the Revolving Credit Agreement. Long-term debt consists of the following (dollars in thousands): June 30, December 31, 2017 2016 Total debt $ 3,159,329 $ 3,259,721 Less debt issuance costs (21,342) (22,255) Less debt discounts (10,466) (10,569) Plus debt premiums 19,803 20,711 Total debt adjusted for discounts, premiums and debt issuance costs 3,147,324 3,247,608 Less current maturities (77,337) (107,903) Long-term debt $ 3,069,987 $ 3,139,705 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 11 ‑ 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 $ 90,000 2.355 % 30 year - LIBOR April 2019 April 2049 Interest rate swap - June 2016 80,000 2.304 30 year - LIBOR June 2019 June 2049 $ (1) We will pay. (2) We will receive.

SHORT-TERM BORROWINGS

SHORT-TERM BORROWINGS	6 Months Ended
	Jun. 30, 2017
SHORT-TERM BORROWINGS
SHORT-TERM BORROWINGS	NOTE 7 – SHORT-TERM BORROWINGS We have a commercial paper program under which we issue unsecured commercial paper in aggregate amounts not exceeding the commercial paper sublimit under our Revolving Credit Agreement, which was $500 million at June 30, 2017. 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): June 30, December 31, 2017 2016 Commercial paper outstanding, net of discounts $ 240,206 $ 119,901 Weighted average interest rate 1.35 % 0.89 % At June 30, 2017, $259.8 million of the commercial paper back-up sublimit remained available under the Revolving Credit Agreement. See Note 6 – Long-Term Debt.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	6 Months Ended
	Jun. 30, 2017
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS	NOTE 8 – 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 and 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. New Horizon Mine started final reclamation June 8, 2017. 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): June 30, 2017 Asset retirement obligation at beginning of period $ 58,583 Liabilities incurred 456 Liabilities settled (500) Accretion expense 1,246 Change in cash flow estimate (3,805) Asset retirement obligation at end of period $ 55,980 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 OTHE

OTHER DEFERRED CREDITS AND OTHER LIABILITIES	6 Months Ended
	Jun. 30, 2017
OTHER DEFERRED CREDITS AND OTHER LIABILITIES
OTHER DEFERRED CREDITS AND OTHER LIABILITIES	NOTE 9 – OTHER DEFERRED CREDITS AND OTHER LIABILITIES In 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 $21.4 and $20.6 million as of June 30, 2017 and December 31, 2016, respectively, which is recorded as 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. In 2016, due to uncertainties regarding the ultimate outcome of this matter, we recorded the total receipt of $15.5 million 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 recognized $7.75 million that we retained as a reduction in transmission expense on our statement of operations during the first quarter of 2017. 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. 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. The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands): June 30, December 31, 2017 2016 Transmission easements $ 21,430 $ 20,562 TEP transmission refund — 15,521 Unearned revenue 3,755 4,000 Customer deposits 3,002 3,338 Other 21,300 22,743 Total other deferred credits and other liabilities $ 49,487 $ 66,164

INCOME TAXES

INCOME TAXES	6 Months Ended
	Jun. 30, 2017
INCOME TAXES
INCOME TAXES	NOTE 10 – 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 settled or received through future rate revenues. We had an income tax benefit of $0.6 million for the six months ended June 30, 2017 and income tax expense of $0.4 million for the six months ended June 30, 2016. The 2017 income tax benefit of $0.6 million is due to an alternative minimum tax credit refund in lieu of bonus depreciation.

FAIR VALUE

FAIR VALUE	6 Months Ended
	Jun. 30, 2017
FAIR VALUE
FAIR VALUE	NOTE 11 – 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 or in the most advantageous market when no principal market exists. The fair value measurement 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, 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): As of June 30, 2017 As of December 31, 2016 Amortized Estimated Amortized Estimated Cost Fair Value Cost Fair Value Marketable securities $ 845 $ 1,007 $ 987 $ 1,103 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 $45.2 million as of June 30, 2017 and $49.1 million as of December 31, 2016, 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): As of June 30, 2017 As of December 31, 2016 Principal Estimated Principal Estimated Amount Fair Value Amount Fair Value Total debt $ 3,159,329 $ 3,457,045 $ 3,259,721 $ 3,543,640 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 6 – 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 credits and other liabilities on our consolidated statements of financial position. At June 30, 2017, the fair value of our interest rate swaps was an unrealized gain of $9.4 million, which was deferred in accordance with our regulatory accounting. See Note 2 – Accounting for Rate Regulation.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	6 Months Ended
	Jun. 30, 2017
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”). The Owner Lessor is the owner of the Springerville Unit 3. We, as general partner of the Springerville Partnership, 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 $821.8 million and $832.3 million at June 30, 2017 and December 31, 2016, respectively, the long-term debt of $432.1 million and $472.1 million at June 30, 2017 and December 31, 2016, respectively, accrued interest associated with the long-term debt of $12.4 million and $13.4 million at June 30, 2017 and December 31, 2016, respectively, and the 49 percent noncontrolling equity interest in the Springerville Partnership of $109.8 million and $109.1 million at June 30, 2017 and December 31, 2016, respectively. Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization expense of $5.2 million for the three months ended June 30, 2017 and the comparable period in 2016. Our consolidated statements of operations also include interest expense of $7.1 million for the three months ended June 30, 2017 and $7.6 million for the comparable period in 2016. Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization expense of $10.5 million for the six months ended June 30, 2017 and the comparable period in 2016. Our consolidated statements of operations also include interest expense of $14.3 million for the six months ended June 30, 2017 and $15.3 million for the comparable period in 2016. 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, Inc. (“WFA”) : 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 Western Fuels-Wyoming. 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 at June 30, 2017 and December 31, 2016, and is included in investments in other associations. Western Fuels – Wyoming (“WFW”) : WFW, the owner and operator of the Dry Fork Mine in Gillette, WY, was organized for the purpose of acquiring and supplying coal, through long-term coal supply agreements, to be used in the production of electric energy at the Laramie River Station (owned by the participants of MBPP) and at the Dry Fork Station (owned by Basin). WFA owns 100 percent of the class AA shares and 75 percent of the class BB shares of WFW, while the participants of MBPP (of which we have a 24.13 percent undivided interest) own the remaining 25 percent of class BB shares of WFW. The pricing structure of the coal supply agreements is designed to recover the costs of production of the Dry Fork Mine and therefore the coal supply agreements provide the financial support for the operation of the Dry Fork Mine. There isn’t sufficient equity at risk at WFW for it to finance its activities without additional financial support. Therefore, WFW is considered a variable interest entity in which we have a variable interest. The power to direct the activities that most significantly impact WFW’s economic performance (which includes operations, maintenance and reclamation activities) is shared with the equity interest holders since each member has representation on the WFW board of directors whose actions require joint approval. Therefore, we are not the primary beneficiary of WFW and the entity is not consolidated. Trapper Mining, Inc. (“Trapper Mining”) : Trapper Mining is a cooperative organized for the purpose of mining, selling and delivering coal from the Trapper Mine to the Craig Generating 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 the additional financial support. Therefore, Trapper Mining is considered a variable interest entity in which we have a variable interest. The power to direct the activities that most significantly impact Trapper Mining’s economic performance (which includes operations, maintenance and reclamation activities) is shared with the cooperative members since each member has representation on the Trapper Mining board of directors whose actions require joint approval. Therefore, we are not the primary beneficiary of Trapper Mining and the entity is not consolidated. We record our investment in Trapper Mining using the equity method. Our membership interest in Trapper Mining was $14.8 million at June 30, 2017 and $14.5 million at December 31, 2016.

LEGAL

LEGAL	6 Months Ended
	Jun. 30, 2017
LEGAL
LEGAL	NOTE 13 – LEGAL Other than as disclosed below, there are no new material litigation or proceedings pending or threatened against us or any material developments in any material existing pending litigation or proceedings. We have an option to purchase development rights for the Holcomb Expansion pursuant to a Purchase Option and Development Agreement (“PODA”). The July 2007 PODA with Sunflower and other Sunflower parties calls for us to make option payments totaling $55 million to Sunflower and/or the other Sunflower parties in exchange for the development rights. Upon execution of the PODA, we paid $25 million. In 2008, we paid $5 million and the remainder would be paid on the purchase date. The purchase date will be designated by us, Sunflower and the other parties to the PODA after we exercise our option to acquire the development rights. The purchase date has not been determined. After various appeals related to the air permit, on March 17, 2017, the Kansas Supreme Court issued a decision upholding the air permit issued by the Kansas Department of Health and Environment for one new coal‑fired generating unit at Holcomb Generating Station of 895 megawatts. Our Board has not made a decision to proceed with the construction of this project, including whether or not to exercise our option to acquire the development rights. Excluding the cost of land and water rights, we have determined that the cost incurred for developing the Holcomb Expansion of $93.5 million as of June 30, 2017 has been impaired. The impairment loss was deferred at the discretion of our Board. See Note 2 – Accounting for Rate Regulation. 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. Although we have not settled this matter, we have reached separate confidential stipulations on damages with all plaintiff groups, reserving the right to appeal liability issues. 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. For further discussion regarding legal proceedings, see our annual report on Form 10-K for the year ended December 31, 2016 “Item 8 – FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA – Notes to Consolidated Financial Statements – Note 13 ‑ Commitments and Contingencies – Legal.”

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	6 Months Ended
	Jun. 30, 2017
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS	NOTE 14 – NEW ACCOUNTING PRONOUNCEMENTS In March 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2017-07, Compensation-Retirement Benefits (Topic 715)-Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost . This amendment disaggregates the accounting for the service cost component of the net periodic benefit cost of an entity’s defined benefit pension and other postretirement benefit plans from the other components of the net periodic benefit cost (such as interest expense, recognition of actuarial gain or loss on postretirement benefit obligations, and amortization of prior service cost or credit). The service cost component is to be included in the same income statement line item(s) as other employee compensation costs arising from services rendered during the period. The other components of the net periodic benefit cost are to be included separately from the line item(s) that include service cost and outside of any subtotal of operating income, if one is presented. ASU 2017-07 also limits the portion of net benefit cost that is eligible for capitalization to property, plant and equipment to the current service cost component. This amendment is effective for fiscal years beginning after December 31, 2017, including interim periods within those annual periods. 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 results of operations. 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. 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 February 2016, the FASB issued ASU 2016-02, Leases (Topic 842). This amendment requires a lessee to recognize substantially all leases (whether operating or finance leases) on the balance sheet as a right-of-use asset and an associated lease liability. Short-term leases of 12 months or less are excluded from this amendment. A right-of-use asset represents a lessee’s right to use (control the use of) the underlying asset for the lease term. A lease liability represents a lessee’s liability to make lease payments. The right-of-use asset and the lease liability are initially measured at the present value of the lease payments over the lease term. For finance leases, the lessee subsequently recognizes interest expense and amortization of the right-of-use asset, similar to accounting for capital leases under current GAAP. For operating leases, the lessee subsequently recognizes straight-line lease expense over the life of the lease. Lessor accounting remains substantially the same as that applied under current GAAP. This amendment 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 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 May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606), as amended by subsequent ASU amendments 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. 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). While we have not yet selected a transition method, we currently expect to use the modified retrospective approach. We are currently evaluating the impact of Topic 606, including the transition method, on our financial position and results of operations. Our evaluation process includes, but is not limited to, identifying contracts within the scope of Topic 606, reviewing the contracts, and documenting our analysis of these contracts. We have evaluated our wholesale electric service contracts with our 43 Members, which was $574.7 million, or 85 percent, of our operating revenue for the six months ended June 30, 2017. Our Members are billed on a monthly basis per an energy rate and demand rate(s) for energy consumed during the period. We transfer control of the electricity over time and the Member simultaneously receives and consumes the benefits of the electricity. The amount we invoice a Member on a monthly basis corresponds directly with the value to the Member of our performance. Accordingly, we do not believe there will be material impact to our recognition of revenue from the sale of electricity to our Members. We have evaluated the significant contracts for our non-member electric sales revenue. Our non-member electric sales revenue was $60.5 million, or 9 percent, of our operating revenue for the six months ended June 30, 2017. We do not believe there will be a material impact to our recognition of revenue from the sale of electricity to non-members. We are currently evaluating the impact of the new standard on our remaining operating revenue. The American Institute of Certified Public Accountants Power and Utilities Revenue Recognition Task Force is currently assessing the impact of this update on contributions in aid of construction (“CIAC”). CIAC represents funds collected from Members as an investment in property, plant and equipment. CIAC is recorded 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, in accordance with standard industry practice. This net amount (after contribution) is the amount subject to ratemaking. If it is determined that CIAC is within the scope of Topic 606, it could have a material impact on our financial position and results of operations.

PRESENTATION OF FINANCIAL INF21

PRESENTATION OF FINANCIAL INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2017
PRESENTATION OF FINANCIAL INFORMATION
Schedule of jointly owned facilities	Our share in each jointly owned facility is as follows as of June 30, 2017 (dollars in thousands): Electric Construction Tri-State Plant in Accumulated Work In Share Service Depreciation Progress Yampa Project - Craig Generating Station Units 1 and 2 24.00 % $ 349,958 $ 235,028 $ 46,928 MBPP - Laramie River Station 24.13 % 409,998 297,022 15,787 San Juan Project – San Juan Unit 3 8.20 % 82,688 77,138 — Total $ 842,644 $ 609,188 $ 62,715

ACCOUNTING FOR RATE REGULATION

ACCOUNTING FOR RATE REGULATION (Tables)	6 Months Ended
	Jun. 30, 2017
ACCOUNTING FOR RATE REGULATION
Schedule of regulatory assets and liabilities	Regulatory assets and liabilities are as follows (dollars in thousands): June 30, December 31, 2017 2016 Regulatory assets Deferred income tax expense (1) $ 30,517 $ 30,517 Deferred prepaid lease expense – Craig Unit 3 Lease (2) 6,473 9,710 Deferred prepaid lease expense – Springerville Unit 3 Lease (3) 89,441 90,587 Goodwill – J.M. Shafer (4) 56,268 57,692 Goodwill – Colowyo Coal (5) 39,777 40,294 Deferred debt prepayment transaction costs (6) 162,502 166,815 Deferred Holcomb Expansion impairment loss (7) 93,494 — Total regulatory assets 478,472 395,615 Regulatory liabilities Interest rate swaps (8) 9,357 12,140 Deferred revenues (9) 20,800 35,800 Membership withdrawal (10) 42,572 47,572 Total regulatory liabilities 72,729 95,512 Net regulatory asset $ 405,743 $ 300,103 (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 Unit 3 (“Craig 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 June 30, 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 impairment loss related to development costs, including costs for the option to purchase development rights, for a new coal-fired generating unit or units at Holcomb Generating Station (“Holcomb Expansion”). On March 17, 2017, the Kansas Supreme Court issued a decision upholding the air permit for one unit at Holcomb Generating Station of 895 megawatts. The air permit expires if construction of the Holcomb Expansion does not commence within 18 months. Although a final decision has not been made by our Board on whether to proceed with the construction of the Holcomb Expansion, we have assessed the probability of us entering into construction for the Holcomb Expansion as remote. Based on this assessment, we have determined that the costs incurred for the Holcomb Expansion are impaired and not recoverable. At the discretion of our Board, the impaired loss has been deferred as a regulatory asset and will be recovered from our Members in rates. The plan for the recovery has not been determined by our Board. Once the plan for recovery is determined, the deferred impairment loss will be recognized in other operating expenses. See Note 5 – Other Deferred Charges. (8) 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 6 – Long-Term Debt and Note 11 – Fair Value. (9) 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 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. $15.0 million of this deferred revenue was recognized in non-member electric sales revenue for the six-month period ended June 30, 2017. The remaining deferred non-member electric sales revenues will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods. Represents the 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. from membership in us. As part of our Board approving the 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. $5.0 million of this deferred membership withdrawal income was recognized in other income for the six-month period ended June 30, 2017. The remaining deferred membership withdrawal income will be refunded to Members through reduced rates when recognized in other income in future periods.

OTHER DEFERRED CHARGES (Tables)

OTHER DEFERRED CHARGES (Tables)	6 Months Ended
	Jun. 30, 2017
OTHER DEFERRED CHARGES.
Schedule of Other Deferred Charges	Other deferred charges are as follows (dollars in thousands): June 30, December 31, 2017 2016 Preliminary surveys and investigations $ 21,013 $ 111,592 Advances to operating agents of jointly owned facilities 11,693 11,871 Interest rate swaps 9,357 12,140 Other 4,691 3,775 Total other deferred charges $ 46,754 $ 139,378

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	6 Months Ended
	Jun. 30, 2017
LONG-TERM DEBT.
Schedule of long-term debt	Long-term debt consists of the following (dollars in thousands): June 30, December 31, 2017 2016 Total debt $ 3,159,329 $ 3,259,721 Less debt issuance costs (21,342) (22,255) Less debt discounts (10,466) (10,569) Plus debt premiums 19,803 20,711 Total debt adjusted for discounts, premiums and debt issuance costs 3,147,324 3,247,608 Less current maturities (77,337) (107,903) Long-term debt $ 3,069,987 $ 3,139,705
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 $ 90,000 2.355 % 30 year - LIBOR April 2019 April 2049 Interest rate swap - June 2016 80,000 2.304 30 year - LIBOR June 2019 June 2049 $ (1) We will pay. We will receive.

SHORT-TERM BORROWINGS (Tables)

SHORT-TERM BORROWINGS (Tables)	6 Months Ended
	Jun. 30, 2017
SHORT-TERM BORROWINGS
Schedule of commercial paper	Commercial paper consisted of the following (dollars in thousands): June 30, December 31, 2017 2016 Commercial paper outstanding, net of discounts $ 240,206 $ 119,901 Weighted average interest rate 1.35 % 0.89 %

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	6 Months Ended
	Jun. 30, 2017
ASSET RETIREMENT OBLIGATION
Schedule of Asset Retirement Obligations	Aggregate carrying amounts of asset retirement obligations are as follows (dollars in thousands): June 30, 2017 Asset retirement obligation at beginning of period $ 58,583 Liabilities incurred 456 Liabilities settled (500) Accretion expense 1,246 Change in cash flow estimate (3,805) Asset retirement obligation at end of period $ 55,980

OTHER DEFERRED CREDITS AND OT27

OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Tables)	6 Months Ended
	Jun. 30, 2017
OTHER DEFERRED CREDITS AND OTHER LIABILITIES
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): June 30, December 31, 2017 2016 Transmission easements $ 21,430 $ 20,562 TEP transmission refund — 15,521 Unearned revenue 3,755 4,000 Customer deposits 3,002 3,338 Other 21,300 22,743 Total other deferred credits and other liabilities $ 49,487 $ 66,164

FAIR VALUE (Tables)

FAIR VALUE (Tables)	6 Months Ended
	Jun. 30, 2017
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): As of June 30, 2017 As of December 31, 2016 Amortized Estimated Amortized Estimated Cost Fair Value Cost Fair Value Marketable securities $ 845 $ 1,007 $ 987 $ 1,103
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): As of June 30, 2017 As of December 31, 2016 Principal Estimated Principal Estimated Amount Fair Value Amount Fair Value Total debt $ 3,159,329 $ 3,457,045 $ 3,259,721 $ 3,543,640

PRESENTATION OF FINANCIAL INF29

PRESENTATION OF FINANCIAL INFORMATION - Jointly Owned Facilities (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)facility
Jointly owned facilities
Number of jointly owned facilities | facility	3
Electric plant in service	$ 842,644
Accumulated depreciation	609,188
Construction work in progress	$ 62,715
Yampa
Jointly owned facilities
Tri-State share (as a percent)	24.00%
Electric plant in service	$ 349,958
Accumulated depreciation	235,028
Construction work in progress	$ 46,928
MBPP
Jointly owned facilities
Tri-State share (as a percent)	24.13%
Electric plant in service	$ 409,998
Accumulated depreciation	297,022
Construction work in progress	$ 15,787
San Juan Project
Jointly owned facilities
Tri-State share (as a percent)	8.20%
Electric plant in service	$ 82,688
Accumulated depreciation	$ 77,138

PRESENTATION OF FINANCIAL INF30

PRESENTATION OF FINANCIAL INFORMATION - Depreciation Rates (Details) - Forecast $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Transmission and General Plant | Adopted Depreciation Rates
Depreciation rates
Expected increase (decrease) in annual depreciation expense associated with revised depreciation rates	$ (20)
Generation plant
Depreciation rates
Expected increase (decrease) in annual depreciation expense associated with revised depreciation rates	$ 0.5

ACCOUNTING FOR RATE REGULATIO31

ACCOUNTING FOR RATE REGULATION (Details) $ in Thousands	Mar. 17, 2017facilityMW	Jun. 30, 2017USD ($)	Dec. 31, 2016USD ($)	Jun. 30, 2016USD ($)
Regulatory assets and liabilities
Regulatory assets		$ 478,472	$ 395,615
Regulatory liabilities		72,729	95,512
Net regulatory asset		405,743	300,103
Interest rate swaps
Regulatory assets and liabilities
Regulatory liabilities		9,357	12,140
Deferred revenue
Regulatory assets and liabilities
Regulatory liabilities		20,800	35,800
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		42,572	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
Non-member electric sales | Deferred revenue
Regulatory assets and liabilities
Deferred revenue recognized		15,000	9,200
Other Income | Deferred revenue from membership withdrawal
Regulatory assets and liabilities
Deferred revenue recognized		5,000
Deferred income tax expense
Regulatory assets and liabilities
Regulatory assets		30,517	30,517
Deferred prepaid lease expense | Craig Unit 3 Lease
Regulatory assets and liabilities
Regulatory assets		6,473	9,710
Annual amortization expense		6,500
Deferred prepaid lease expense | Springerville Unit 3 Lease
Regulatory assets and liabilities
Regulatory assets		89,441	90,587
Annual amortization expense		$ 2,300
Amortization period		47 years
Goodwill | TCP
Regulatory assets and liabilities
Regulatory assets		$ 56,268	57,692
Annual amortization expense		$ 2,800
Amortization period		25 years
Goodwill | Colowyo Coal
Regulatory assets and liabilities
Regulatory assets		$ 39,777	40,294
Annual amortization expense		$ 1,000
Amortization period		44 years
Deferred debt prepayment transaction costs
Regulatory assets and liabilities
Regulatory assets		$ 162,502	$ 166,815
Annual amortization expense		$ 8,600
Amortization period		21 years 4 months 24 days
Holcomb Expansion
Regulatory assets and liabilities
Regulatory assets		$ 93,494
Number of new coal-fired generating units by permit issued | facility	1
Generating unit capacity (in megawatts) | MW	895
Period during which construction must begin under air permit	18 months

OTHER DEFERRED CHARGES (Details

OTHER DEFERRED CHARGES (Details) - USD ($) $ in Thousands	Mar. 17, 2017	Jun. 30, 2017	Dec. 31, 2016
Other deferred charges
Preliminary surveys and investigations		$ 21,013	$ 111,592
Advances to operating agents of jointly owned facilities		11,693	11,871
Interest rate swaps		9,357	12,140
Other		4,691	3,775
Total other deferred charges		46,754	139,378
Holcomb Expansion
Other deferred charges
Preliminary surveys and investigations		$ 0	$ 91,300
Period during which construction must begin under air permit	18 months

LONG-TERM DEBT - Other Informat

LONG-TERM DEBT - Other Information (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)instrument	Dec. 31, 2016USD ($)
Unsecured debt
Number of unsecured debt instruments | instrument	3
Unsecured notes	$ 45,900
Credit facility information
Outstanding borrowings	3,159,329	$ 3,259,721
Mortgage notes payable and Pollution Control revenue bonds
Credit facility information
Outstanding borrowings	2,700,000
Pollution control revenue bonds, Moffat County, CO Variable Rate Demand Series 2009, due 2036
Credit facility information
Outstanding borrowings	46,800
Springerville Certificates
Credit facility information
Outstanding borrowings	419,000
Revolving Credit Agreement
Credit facility information
Maximum borrowing capacity	750,000
Outstanding borrowings	0	$ 0
Available borrowing capacity	$ 462,100
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
Commercial Paper | Revolving Credit Agreement
Credit facility information
Available borrowing capacity	$ 259,800

LONG-TERM DEBT - Components (De

LONG-TERM DEBT - Components (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Long-term debt, components
Total debt	$ 3,159,329	$ 3,259,721
Less debt issuance costs	(21,342)	(22,255)
Less debt discounts	(10,466)	(10,569)
Plus debt premiums	19,803	20,711
Total debt adjusted for discounts, premiums and debt issuance costs	3,147,324	3,247,608
Less current maturities	(77,337)	(107,903)
Long-term debt	$ 3,069,987	$ 3,139,705

LONG-TERM DEBT - Interest Rate

LONG-TERM DEBT - Interest Rate Swaps (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)
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	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Short-term borrowings
Amount outstanding	$ 240,206	$ 119,901
Commercial Paper
Short-term borrowings
Maximum amount per commercial paper sublimit	500,000
Amount outstanding	$ 240,206	$ 119,901
Weighted average interest rate	1.35%	0.89%
Commercial Paper | Maximum
Short-term borrowings
Term of issuance	397 days
Revolving Credit Agreement
Short-term borrowings
Available borrowing capacity	$ 462,100
Revolving Credit Agreement | Commercial Paper
Short-term borrowings
Available borrowing capacity	$ 259,800

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)
Aggregate carrying amounts of asset retirement obligations
Asset retirement obligation at beginning of period	$ 58,583
Liabilities incurred	456
Liabilities settled	(500)
Accretion expense	1,246
Change in cash flow estimate	(3,805)
Asset retirement obligation at end of period	$ 55,980

OTHER DEFERRED CREDITS AND OT38

OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Details) - USD ($) $ in Thousands	Jan. 12, 2017	Mar. 31, 2017	Jun. 30, 2017	Dec. 31, 2016
Deferred credits and other liabilities
Transmission easements			$ 21,430	$ 20,562
TEP transmission refund				15,521
Unearned revenue			3,755	4,000
Customer deposits			3,002	3,338
Other			21,300	22,743
Total other deferred credits and other liabilities			49,487	66,164
Transmission Right of Way Easements
Deferred credits and other liabilities
Total due for easement right of way			34,500
TEP | Transmission Services Agreement
Deferred credits and other liabilities
Payment for transmission services settlement	$ 7,750
Reduction in transmission expense		$ 7,750
Other Deferred Credits and Other Liabilities | Transmission Right of Way Easements
Deferred credits and other liabilities
Transmission easements			$ 21,400	20,600
Other Deferred Credits | TEP | Transmission Services Agreement
Deferred credits and other liabilities
Refund received on transmission services agreements				$ 15,500

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
INCOME TAXES
Income tax expense (benefit)	$ (302)	$ 350	$ (604)	$ 350
Alternative minimum tax benefit			$ (600)

FAIR VALUE (Details)

FAIR VALUE (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Fair value:
Interest rate swaps	$ 9,357	$ 12,140
Principal Amount
Fair value:
Marketable securities	845	987
Long-term debt	3,159,329	3,259,721
Estimated Fair Value
Fair value:
Cash and cash equivalents	45,200	49,100
Estimated Fair Value | Level 2
Fair value:
Long-term debt	3,457,045	3,543,640
Estimated Fair Value | Recurring | Level 1
Fair value:
Marketable securities	1,007	$ 1,103
Estimated Fair Value | Recurring | Level 2
Fair value:
Interest rate swaps	$ 9,400

VARIABLE INTEREST ENTITIES - Co

VARIABLE INTEREST ENTITIES - Consolidated Entities (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Consolidated Variable Interest Entities
Noncontrolling interest included in consolidated statements of financial position (in dollars)	$ 109,820		$ 109,820		$ 109,147
Interest expense (in dollars)	$ 36,299	$ 35,924	$ 72,648	$ 71,344
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%		49.00%		49.00%
Noncontrolling interest included in consolidated statements of financial position (in dollars)	$ 109,800		$ 109,800		$ 109,100
Depreciation and amortization (in dollars)	5,200	5,200	10,500	10,500
Interest expense (in dollars)	7,100	$ 7,600	14,300	$ 15,300
Springerville Partnership | Primary Beneficiary | Electric Plant
Consolidated Variable Interest Entities
Assets of variable interest entity included in consolidated statements of financial position (in dollars)	821,800		821,800		832,300
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)	432,100		432,100		472,100
Springerville Partnership | Primary Beneficiary | Accrued interest included in long-term debt
Consolidated Variable Interest Entities
Liabilities of variable interest entity included in consolidated statements of financial position (in dollars)	$ 12,400		$ 12,400		$ 13,400
Springerville Partnership | Primary Beneficiary | Springerville Unit 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%		100.00%

VARIABLE INTEREST ENTITIES - Un

VARIABLE INTEREST ENTITIES - Unconsolidated Entities (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Unconsolidated Variable Interest Entities
Investment in other associations (in dollars)	$ 140,413	$ 139,350
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	2,200
Trapper Mining | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments in other associations
Unconsolidated Variable Interest Entities
Investment in coal mine	$ 14,800	$ 14,500
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%

LEGAL - Purchase Option and Dev

LEGAL - Purchase Option and Development Agreement (Details) - Holcomb Expansion $ in Millions	Mar. 17, 2017facilityMW	Jul. 31, 2007USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2008USD ($)
Purchase Option and Development Agreement
Number of new coal-fired generating units by permit issued | facility	1
Generating unit capacity (in megawatts) | MW	895
Other Deferred Charges
Purchase Option and Development Agreement
Project development costs incurred			$ 93.5
Sunflower and other Sunflower parties | Purchase Option and Development Agreement
Purchase Option and Development Agreement
Total amount of option payments		$ 55
Option payments made for development rights		$ 25		$ 5

LEGAL - Las Conchas Fire (Detai

LEGAL - Las Conchas Fire (Details) - Damages from Las Conchas fire $ in Millions	Oct. 28, 2015	Jun. 30, 2011plaintiff	Jun. 30, 2017USD ($)
Litigation information
Number of plaintiff groups | plaintiff		6
Pending litigation
Litigation information
Liability insurance coverage | $			$ 100
Pending litigation | JMEC
Litigation information
Percentage negligent	75.00%
Pending litigation | Tri-State
Litigation information
Percentage negligent	20.00%
Pending litigation | United States Forest Service
Litigation information
Percentage negligent	5.00%

NEW ACCOUNTING PRONOUNCEMENTS (

NEW ACCOUNTING PRONOUNCEMENTS (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)customer	Jun. 30, 2016USD ($)
NEW ACCOUNTING PRONOUNCEMENTS
Number of Members | customer			43
Member electric sales	$ 292,259	$ 275,517	$ 574,674	$ 547,286
Member sales as a percent of operating revenue			85.00%
Non-member electric sales	$ 25,313	$ 25,054	$ 60,471	$ 55,176
Member sales as a percent of operating revenue			9.00%