Tri-State Generation & Transmission Association 10-Q 12 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	9 Months Ended
	Sep. 30, 2015shares
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	Sep. 30, 2015
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	Q3
Document Fiscal Year Focus	2,015
Entity Common Stock, Shares Outstanding	0

Consolidated Statements of Fina

Consolidated Statements of Financial Position (unaudited) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Electric Plant
In service	$ 5,414,256	$ 5,193,236
Construction work in progress	176,020	206,097
Total electric plant	5,590,276	5,399,333
Less allowances for depreciation and amortization	(2,214,237)	(2,129,173)
Net electric plant	3,376,039	3,270,160
Other plant	230,064	210,694
Accumulated depreciation and depletion	(69,741)	(58,117)
Net other plant	160,323	152,577
Total property, plant and equipment	3,536,362	3,422,737
Other assets and investments
Investments in other associations	119,170	117,976
Investments in and advances to coal mines	17,264	15,016
Restricted cash and investments	4,931	39,376
Intangible assets	27,465	32,958
Other noncurrent assets	13,034	12,531
Total other assets and investments	181,864	217,857
Current assets
Cash and cash equivalents	195,209	92,468
Restricted cash and investments	10,323	9,784
Deposits and advances	27,055	22,224
Accounts receivable—Members	94,044	105,723
Other accounts receivable	16,349	25,693
Coal inventory	69,843	40,673
Materials and supplies	84,201	80,069
Total current assets	497,024	376,634
Deferred charges
Regulatory assets	416,109	426,043
Prepayment—NRECA Retirement and Security Plan	50,525	54,665
Other	179,672	178,454
Total deferred charges	646,306	659,162
Total assets	4,861,556	4,676,390
Capitalization
Patronage capital equity	983,381	908,669
Accumulated other comprehensive income (loss)	(914)	(828)
Noncontrolling interest	108,855	109,302
Total equity	1,091,322	1,017,143
Long-term debt	3,290,824	3,165,960
Total capitalization	4,382,146	4,183,103
Current liabilities
Member advances	9,442	14,576
Accounts payable	92,184	103,177
Accrued expenses	24,103	30,005
Accrued interest	49,082	32,517
Accrued property taxes	25,898	26,010
Current maturities of long‑term debt	97,409	94,342
Total current liabilities	298,118	300,627
Deferred credits and other liabilities
Regulatory liabilities	45,000	45,000
Deferred income tax liability	24,417	17,230
Intangible liabilities	6,850	9,424
Asset retirement obligation	58,655	53,754
Other	37,876	59,121
Total deferred credits and other liabilities	172,798	184,529
Accumulated postretirement benefit and postemployment obligations	8,494	8,131
Total equity and liabilities	$ 4,861,556	$ 4,676,390

Consolidated Statements of Oper

Consolidated Statements of Operations (unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Operating Revenues
Member electric sales	$ 334,009	$ 319,671	$ 858,840	$ 840,539
Non-member electric sales	30,394	50,530	95,242	160,590
Other	23,699	26,278	68,324	71,836
Total revenues	388,102	396,479	1,022,406	1,072,965
Operating expenses
Purchased power	91,001	99,260	235,422	251,687
Fuel	65,586	80,665	162,430	224,967
Production	55,485	53,292	179,382	167,470
Transmission	39,851	37,476	114,922	110,103
General and administrative	5,421	6,435	17,044	19,725
Depreciation and amortization	38,371	34,275	109,317	96,360
Coal mining	7,096	9,477	23,039	30,922
Other	3,879	5,996	11,504	14,378
Operating expenses	306,690	326,876	853,060	915,612
Operating margins	81,412	69,603	169,346	157,353
Other income
Interest Income	1,071	3,038	3,241	9,357
Capital credits from cooperatives	754	1,720	5,995	3,758
Other income	808	749	2,659	2,424
Total other income	2,633	5,507	11,895	15,539
Interest expense, net of amounts capitalized	35,846	34,986	106,919	105,617
Income taxes	0	0	0	0
Net margins including noncontrolling interest	48,199	40,124	74,322	67,275
Net loss attributable to noncontrolling interest	103	327	390	1,060
Net margins attributable to the Association	$ 48,302	$ 40,451	$ 74,712	$ 68,335

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Consolidated Statements of Comprehensive Income (unaudited)
Net margins including noncontrolling interest	$ 48,199	$ 40,124	$ 74,322	$ 67,275
Other comprehensive income (loss):
Unrealized loss on securities available for sale	(89)	(18)	(112)	(2)
Reclassification adjustment for actuarial (gain) loss on postretirement benefit obligation included in net income	9	(90)	26	(269)
Other comprehensive income (loss)	(80)	(108)	(86)	(271)
Comprehensive income including noncontrolling interest	48,119	40,016	74,236	67,004
Net comprehensive loss attributable to noncontrolling interest	103	327	390	1,060
Comprehensive income attributable to the Association	$ 48,222	$ 40,343	$ 74,626	$ 68,064

Consolidated Statements of Equi

Consolidated Statements of Equity (unaudited) - 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 including noncontrolling interest	68,335		(1,060)	$ 67,275
Retirement of patronage capital	(10,000)
Unrealized loss on securities available for sale		(2)
Reclassification adjustment for actuarial (gain)/loss on postretirement benefit obligation included in net income		(269)
Equity distribution to noncontrolling interest			(55)
Equity at end of period at Sep. 30, 2014	923,714	3,064	109,625	1,036,403
Equity at beginning of period at Dec. 31, 2014	908,669	(828)	109,302	1,017,143
Change in Equity
Net margins including noncontrolling interest	74,712		(390)	74,322
Unrealized loss on securities available for sale		(112)
Reclassification adjustment for actuarial (gain)/loss on postretirement benefit obligation included in net income		26
Equity distribution to noncontrolling interest			(57)
Equity at end of period at Sep. 30, 2015	$ 983,381	$ (914)	$ 108,855	$ 1,091,322

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Operating activities
Net margins including noncontrolling interest	$ 74,322	$ 67,275
Adjustments to reconcile net margins to net cash used in operating activities:
Depreciation and amortization	109,317	94,341
Amortization of intangible asset	5,493	5,493
Amortization of NRECA Retirement and Security Plan prepayment	4,140	4,140
Amortization of debt issuance costs	1,400	696
Capital credit allocations from cooperatives and income from coal mines over refund distributions	(3,698)	(1,136)
Recognition of deferred revenue		(15,000)
Change in restricted cash and investments	29,148	29,213
Changes in operating assets and liabilities:
Accounts receivable	21,026	15,794
Coal inventory	(29,170)	13,462
Materials and supplies	(4,132)	(5,373)
Accounts payable and accrued expenses	(10,845)	(7,843)
Accrued interest	16,565	895
Accrued property taxes	(112)	2,531
Other deferred credits - BNSF settlement	(29,381)
Other	11,084	4,260
Net cash provided by operating activities	195,157	208,748
Investing activities
Purchases of plant	(217,929)	(157,526)
Changes in deferred charges	1,495	(5,652)
Proceeds from other investments	407	6,498
Net cash used in investing activities	(216,027)	(156,680)
Financing activities
Member advances	(5,134)	1,436
Payments of long-term debt	(101,772)	(273,275)
Proceeds from issuance of debt	230,185	79,676
Decrease in advance payments to RUS		38,908
Retirement of patronage capital	(4,213)	(13,849)
Change in restricted cash and investments	323	48,000
Proceeds from investment in securities pledged as collateral	4,222	4,526
Net cash provided by (used in) financing activities	123,611	(114,578)
Net decrease in cash and cash equivalents	102,741	(62,510)
Cash and cash equivalents - beginning	92,468	193,057
Cash and cash equivalents - end	195,209	130,547
Supplemental cash flow information:
Cash paid for interest	101,480	100,303
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$ (1,152)	$ (769)

PRESENTATION OF FINANCIAL INFOR

PRESENTATION OF FINANCIAL INFORMATION	9 Months Ended
	Sep. 30, 2015
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 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 U.S. generally accepted accounting principles (“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 2014 Annual Report in our Registration Statement on Form S-4 (Registration No. 333-203560) that was declared effective by the SEC on July 29, 2015. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. The results of operations for the three and nine months ended September 30, 2015 and 2014 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., our wholly-owned and majority-owned subsidiaries and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries (see Note 10 – 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 (“BEPC”)) 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. Our share in each jointly owned facility is as follows as of September 30, 2015 (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 $ $ $

ACCOUNTING FOR RATE REGULATION

ACCOUNTING FOR RATE REGULATION	9 Months Ended
	Sep. 30, 2015
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, 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 Members through rates approved by our Board of Directors 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 of Directors in accordance with our rate policy. Regulatory assets and liabilities are as follows (thousands): September 30, December 31, 2015 2014 Regulatory assets Deferred income tax expense (1) $ $ Deferred prepaid lease expense- Craig 3 Lease (2) Deferred prepaid lease expense- Springerville 3 Lease (3) Goodwill – J.M. Shafer (4) Goodwill – Colowyo Coal (5) Deferred debt prepayment transaction costs (6) Regulatory liabilities Deferred revenues (7) Net regulatory asset $ $ (1) A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. (2) Deferral of loss on acquisition related to the Craig Generating Station Unit 3 prepaid lease expense upon acquisitions of equity interests in 2002 and 2006. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $6.5 million annually through the remaining original life of the lease ending in 2018 and recovered from our Members in rates. (3) Deferral of loss on acquisition related to the Springerville Generating Station Unit 3 prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $2.3 million annually through the 47 -year period ending in 2056 and recovered from our Members in rates. (4) Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP in December 2011. Goodwill is being amortized to depreciation and amortization expense in the amount of $2.8 million annually through the 25 -year period ending in 2036 and recovered from our Members in rates. (5) Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation and amortization expense through the 44 -year period ending in 2056 and recovered from our Members in rates. (6) Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation and amortization expense in the amount of $8.6 million annually over the 21.4 -year average life of the new debt issued and recovered from our Members in rates. (7) Represents deferral of the recognition of $10 million of non-member electric sales revenue received in 2008 and $35 million of non-member electric sales revenue received in 2011. These deferred non-member electric sales revenues will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods.

INVESTMENTS IN OTHER ASSOCIATIO

INVESTMENTS IN OTHER ASSOCIATIONS	9 Months Ended
	Sep. 30, 2015
INVESTMENTS IN OTHER ASSOCIATIONS
INVESTMENTS IN OTHER ASSOCIATIONS	NOTE 3 – INVESTMENTS IN OTHER ASSOCIATIONS Investments in other associations include our investment in the patronage capital of other cooperatives and these investments are typically accounted for using the cost method. 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. Investments in cooperatives where we have significant influence over operating and financial policy are accounted for using the equity method. 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	9 Months Ended
	Sep. 30, 2015
RESTRICTED CASH AND INVESTMENTS
RESTRICTED CASH AND INVESTMENTS	NOTE 4 – RESTRICTED CASH AND INVESTMENTS Restricted cash and investments represent funds designated by our Board of Directors 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 is therefore a current asset on the statements of financial position. The other funds are noncurrent and are included in other assets and investments. We have investments in U.S. Treasury Notes pledged as collateral in connection with the in-substance defeasance for the principal outstanding and future interest payments on the Coal Contract Receivable Collateralized Bonds (“Colowyo Bonds”). The balances in these investments are described as investments in securities pledged as collateral in the table below. A portion of the defeasance investment is for Colowyo Bond debt payments within one year and is, therefore, a current asset on the consolidated statements of financial position. The remainder of the investment is noncurrent. We received $29.4 million in 2009 from the BNSF Railway Company (“BNSF”) as a reduction of prior coal delivery shipping charges as the result of the decision of the Surface Transportation Board (“STB”). However, BNSF appealed the decision and the funds were subject to refund in the event BNSF was ultimately successful in its appeal. These funds were designated by our Board of Directors to be held as restricted cash. In May 2015, BNSF, Western Fuels Association (“WFA”) and BEPC filed a joint petition at the STB informing the STB that the parties had entered into a rail transportation agreement settling all matters at issue. In June 2015, the STB granted the joint petition, which resolved the uncertainties related to the outcome of this matter and the $29.4 million of cash related to the BNSF settlement was no longer designated as restricted. Restricted cash and investments are as follows (thousands): September 30, December 31, 2015 2014 Investments in securities pledged as collateral $ $ Funds restricted by contract Restricted cash and investments - current BNSF settlement — Funds restricted by contract Investments in securities pledged as collateral Restricted cash and investments - noncurrent Total restricted cash and investments $ $

OTHER DEFERRED CHARGES

OTHER DEFERRED CHARGES	9 Months Ended
	Sep. 30, 2015
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 may 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 of Directors, which has budgetary and rate-setting authority. As of September 30, 2015 , preliminary surveys and investigations was primarily comprised of expenditures for the Holcomb Station Project of $85.5 million and $28.2 million for a transmission project located in eastern Colorado (“Eastern Plains Transmission Project”). We make advance payments to the operating agents of jointly owned facilities. We account for debt issuance costs as deferred debt expense. Deferred debt expense is amortized to interest expense, net of amounts capitalized using an effective interest method over the life of the respective debt issuance. As of September 30, 2015 , the remaining amortization periods for debt issuance costs range from approximately 2 to 34 years. Other deferred charges are as follows (thousands): September 30, December 31, 2015 2014 Preliminary surveys and investigations $ $ Advances to operating agents of jointly owned facilities Debt issuance costs Other Total other deferred charges $ $

LONG-TERM DEBT

LONG-TERM DEBT	9 Months Ended
	Sep. 30, 2015
LONG-TERM DEBT NOTE
LONG-TERM DEBT	NOTE 6 – 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 one unsecured note. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Generating Station Unit 3. The Colowyo Bonds are secured by funds deposited with the trustee as part of the in-substance defeasance and an unconditional guarantee by us. All long-term debt contains certain restrictive financial covenants, including a debt service ratio requirement and an 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 (“2011 Credit Agreement”). We had outstanding borrowings of $261 million and $50 million at September 30, 2015 and December 31, 2014, respectively, and an issued letter of credit in the principal amount of $46.8 million plus accrued interest supported by the 2011 Credit Agreement. As of September 30, 2015, we have $441 million in availability under the 2011 Credit Agreement. Long-term debt consists of the following (thousands): September 30, December 31, 2015 2014 Total debt $ $ Less current maturities Long-term debt $ $

OTHER DEFERRED CREDITS AND OTHE

OTHER DEFERRED CREDITS AND OTHER LIABILITIES	9 Months Ended
	Sep. 30, 2015
OTHER DEFERRED CREDITS AND OTHER LIABILITIES
OTHER DEFERRED CREDITS AND OTHER LIABILITIES	NOTE 7 – OTHER DEFERRED CREDITS AND OTHER LIABILITIES We received $29.4 million in 2009 from BNSF as a reduction of prior coal delivery shipping charges as the result of the decision of the STB. However, BNSF appealed the decision and the funds were subject to refund in the event BNSF was ultimately successful in its appeal . Due to uncertainties regarding the ultimate outcome of this matter, we did not recognize the benefit of the receipt of the $29.4 million in 2009. In May 2015, BNSF, WFA, and BEPC filed a joint petition at the STB informing the STB that the parties had entered into a rail transportation agreement settling all matters at issue. In June 2015, the STB granted the joint petition, which resolved the uncertainties related to the outcome of this matter. Therefore, pursuant to the BNSF rate settlement, $24.4 million was recognized in June 2015 as a reduction to fuel expense. 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. Other deferred credits and other liabilities are as follows (thousands): September 30, December 31, 2015 2014 BNSF rate settlement proceeds not recognized in income $ — $ Customer deposits Unearned revenue Other deferred credits Total other deferred credits and other liabilities $ $

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2015
INCOME TAXES
INCOME TAXES	NOTE 8 – 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 no income tax expense or benefit for the three and nine months ended September 30, 2015 and 2014 .

FAIR VALUE

FAIR VALUE	9 Months Ended
	Sep. 30, 2015
FAIR VALUE
FAIR VALUE	NOTE 9 – 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 measurements accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows: Level 1 inputs utilize observable market data in active markets for identical assets or liabilities. Level 2 inputs consist of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 inputs consist of unobservable market data which is typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Marketable Securities We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are classified as available-for-sale and are measured at fair value on a recurring basis. The estimated fair value of the investments is included in other noncurrent assets on our consolidated statements of financial position. The unrealized gains are reported as a component of accumulated other comprehensive income. Changes in the net unrealized gains or losses are reported as a component of comprehensive income. The carrying amounts and fair values of our marketable securities are as follows (thousands): As of September 30, 2015 As of December 31, 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Marketable securities $ $ $ $ The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The unrealized gains at September 30, 2015 and December 31, 2014 are reported as a component of accumulated other comprehensive income as of those dates. Changes in the net unrealized gains or losses are reported as a component of comprehensive income. Long-Term Debt The fair values of long-term debt were estimated using discounted cash flow analyses based on our current incremental borrowings rates for similar types of borrowing arrangements. These valuation assumptions utilize observable inputs based on market data obtained from independent sources and are therefore considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market corroborated inputs). The carrying amounts and fair values of our long-term debt are as follows (thousands): As of September 30, 2015 As of December 31, 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Long-term debt $ $ $ $ We did not have any financial assets or liabilities measured at fair value on a recurring basis that are included in the Level 3 fair value category.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	9 Months Ended
	Sep. 30, 2015
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES	NOTE 10 – 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 Generating Station 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 Generating Station 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 Generating Station Unit 3 assets and are responsible for 100 percent of the operation, maintenance and capital expenditures of Springerville Generating Station 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 $858.6 and $874.4 million at September 30, 2015 and December 31, 2014 , respectively, the long-term debt of $511.6 and $548.1 million at September 30, 2015 and December 31, 2014 , respectively, accrued interest associated with the long-term debt of $5.7 million and $15.2 million at September 30, 2015 and December 31, 2014 , respectively, and the 49 percent noncontrolling equity interest in the Springerville Partnership of $108.9 and $109.3 million at September 30, 2015 and December 31, 2014 , respectively. Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization expense of $5.3 million for the three months ended September 30, 2015 and the comparable period in 2014 . Our consolidated statements of operations also include interest expense of $8.0 million for the three months ended September 30, 2015 and $8.5 million for the comparable period in 2014 . Our consolidated statements of operations include the Springerville Partnership’s depreciation and amortization expense of $15.8 million for the nine months ended September 30, 2015 and the comparable period in 2014 . Our consolidated statements of operations also include interest expense of $24.3 million for the nine months ended September 30, 2015 and $25.6 million for the comparable period in 2014 . The net losses attributable to the 49 percent noncontrolling equity interest in the Springerville Partnership are reflected on our consolidated statements of operations. The revenue associated with the Springerville Partnership lease has been eliminated in consolidation. Income, losses and cash flows of the Springerville Partnership are allocated to the general and limited partners based on their equity ownership percentages. Unconsolidated Variable Interest Entities Western Fuels Association (“WFA”) : WFA is a not-for-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 Generating Station 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 September 30, 2015 and $2.3 million at December 31, 2014 , respectively, 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 BEPC). 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 (the owners of the Craig Generating Station Units 1 and 2). 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 $15.5 million at September 30, 2015 and $13.7 million at December 31, 2014 .

Legal

Legal	9 Months Ended
	Sep. 30, 2015
LEGAL
LEGAL	NOTE 11 – LEGAL In June 2011, a wildfire in New Mexico, known as the Las Conchas Fire, burned for five days in northern New Mexico, primarily on national forest service land in the Santa Fe National Forest. Six plaintiff groups, comprised of property owners in the area of the Las Conchas Fire, filed separate lawsuits against our Member, Jemez Mountains Electric Cooperative, Inc. (“JMEC”) in the Thirteenth District Court, Sandoval County in the State of New Mexico. Plaintiffs alleged that the fire ignited when a tree growing outside the right of way fell onto a distribution line owned by JMEC as a result of high winds. On January 7, 2014, the court allowed all parties and related parties to amend their complaints to include the addition of us as a party defendant. These cases are State Farm Fire and Casualty Company, et. al. v. Jemez Mountains Electric Cooperative, Inc., et. al. (amended complaint filed March 6, 2014); Elizabeth Ora Cox, et. al., v. Jemez Mountains Electric Cooperative, Inc., et. al. (second amended complaint filed January 31, 2014); Norman Armijo, et. al., v. Jemez Mountains Electric Cooperative, Inc., et al. (amended complaint filed January 16, 2014); United Services Automobile Association, et. al. v. Jemez Mountains Electric Cooperative, Inc. (amended complaint filed March 6, 2014); Jemez Pueblo v. Jemez Mountains Electric Cooperative, Inc., et. al. (filed June 10, 2013); and Pueblo De Cochiti., et. al. v. Jemez Mountains Electric Cooperative, Inc., et. al. (filed June 10, 2013). The allegations in each case are similar. Plaintiffs allege that we owed them independent duties to inspect and maintain the right-of-way for JMEC’s distribution line and that we are also jointly liable for any negligence by JMEC under joint venture and alter ego theories. On June 16, 2014, we filed multiple motions for summary judgment including for plaintiffs’ claims related to nuisance, trespass, negligence per se, independent duty, joint venture and alter ego. On December 29, 2014, we received a demand letter from the U.S. Department of Justice for costs incurred as a result of the fire, also alleging the joint venture theory. JMEC has settled with the subrogated insurers, executing and funding the deal on December 30, 2014 and on February 7, 2015, the court dismissed the subrogated insurers’ claims against us with prejudice. Settlement demands have been received from plaintiffs Jemez Pueblo and Pueblo de Cochiti claiming damages in the amount of approximately $34.4 million and $23.9 million, respectively, focusing mainly on damages arising from flooding subsequent to the fire. On March 9, 2015, the court granted our motions for summary judgment related to nuisance, trespass, negligence per se, and alter ego, but denied our motions related to independent duty and joint venture. On March 17, 2015, we filed an application for interlocutory appeal with the New Mexico Court of Appeals related to the district court’s denial of our motions for summary judgment for plaintiffs’ claims related to independent duty and joint venture. The New Mexico Court of Appeals denied our application for interlocutory appeal on May 27, 2015. A jury trial commenced on September 28, 2015. On October 28, 2015, the jury affirmed our position that we and JMEC did not operate as a joint venture or joint enterprise. The jury found JMEC was 75 percent negligent, Tri-State was 20 percent negligent, and the United States Forest Service was 5 percent negligent, and each had a role in causing the fire. We are evaluating our options regarding an appeal of the case. A separate trial will occur at a later date to determine the amount of damages. We maintain $100 million in liability insurance coverage for this matter. Although we cannot predict the outcome of these matters at this point in time, we do not expect them to have a material adverse effect on our financial condition or our future results of operations or cash flows. On February 9, 2015, Delta-Montrose Electric Association (‘‘DMEA’’) filed a Petition For Declaratory Order with the United States Federal Energy Regulatory Commission (‘‘FERC’’) seeking a declaratory order from FERC finding that its wholesale electric service contract with us is subject to FERC jurisdiction because we have paid off all our Rural Utilities Service debt; that the wholesale electric service contract cannot be read to preclude DMEA from purchasing power from a ‘‘qualifying facility,’’ which is a co-generator or renewable small power producer capable of producing up to 80 MW, pursuant to the provisions of PURPA and FERC regulations thereunder; and that DMEA has the right under FERC’s PURPA regulations to negotiate its purchase power price from a ‘‘qualifying facility’’ and to reduce its purchases from us by that amount even if that amount exceeds its contractual obligation to purchase from us. We filed our motion to intervene and protest with FERC related to such petition on March 11, 2015. DMEA filed a motion to answer and answer to our protest on March 26, 2015. We filed a motion for leave to answer and answer to DMEA’s answer on April 2, 2015. On June 18, 2015, FERC issued an order stating (a) DMEA is obligated to purchase from “qualifying facilities” offering available energy and capacity and such sales may be at negotiated rates and (b) we are not subject to the general FERC rate jurisdiction under the Federal Powers Act (“FPA”). On July 20, 2015, Kit Carson Electric Cooperative, Inc. (“Kit Carson”) filed a Motion for Clarification or Alternatively, Rehearing with FERC seeking a clarification of the FERC order, or alternatively, a rehearing, to the extent the FERC order applies to any of our policies or the application of any of our policies regarding Kit Carson’s obligations under PURPA to purchase renewable energy from a “qualifying facility” and as it relates to Kit Carson’s obligation to purchase and receive at least 95 percent of its electric power requirements from us under the wholesale electric service contract. On August 3, 2015, we filed a motion for leave to answer and answer to Kit Carson’s motion requesting FERC to deny Kit Carson’s motion because it is beyond the scope of FERC’s order in the proceeding and not within FERC’s jurisdiction under the FPA. On October 15, 2015, FERC denied Kit Carson’s Motion for Clarification or Alternatively, Rehearing stating FERC’s earlier order does not need further clarification and further restating that DMEA was obligated to purchase power from any “qualifying facility” that can deliver its power to DMEA regardless of any conflicting contract terms found in the wholesale electric service contract. We do not expect the FERC order or the denial of Kit Carson’s motion to have a material adverse effect on our financial condition or our future results of operations or cash flows. We are evaluating our options regarding its impact on our wholesale electric service contracts with our Members. In February 2013, WildEarth Guardians (‘‘WEG’’) filed suit against the United States Office of Surface Mining, Reclamation and Enforcement (‘‘OSM’’), in the United States District Court for the District of Colorado, alleging OSM’s failure to involve the public and address the economic impacts of coal mining throughout the Rocky Mountain West prior to mine plan approval. The suit alleged unlawful mine plan approval of mines located in Colorado, Montana, New Mexico, and Wyoming. The court granted intervention to several mine owners, including Colowyo Coal and Trapper Mining. The Colowyo Mine plan in WEG’s suit was approved in 2007 and the Trapper Mine plan in WEG’s suit was approved in 2009. In February 2014, the court agreed to sever the claims and transfer venue for the mines located outside of Colorado. In August 2014, WEG submitted its opening brief on the part of the case that remained in Colorado as Civil Action No. 1:13-cv-00518-RBJ. OSM’s responsive brief was filed on October 7, 2014, and Trapper Mining and Colowyo Coal, as intervenors, each filed a responsive brief on October 20, 2014. WEG asked the court to declare that OSM’s approval of the mine plans violated the National Environmental Policy Act (‘‘NEPA’’) and for the court to vacate the approvals until OSM demonstrates compliance with the act. Oral arguments took place on April 24, 2015. On May 8, 2015, the court issued an order agreeing with WEG that OSM’s approval of the mine plans violated NEPA. The court noted that the majority of the coal covered by the permit at Trapper Mine had already been mined, but ordered that no remaining coal covered by the permit be mined prior to approval of a new permit revision. With respect to the Colowyo Mine, the court determined that immediate vacatur of the Colowyo Mine plan did not outweigh the potential harm. The court deferred an immediate vacatur order for a period of 120 days from May 8, 2015 and expected the OSM during that time to address the deficiencies in the permitting process. On May 29, 2015, Colowyo Coal filed a Notice of Appeal and Motion to Stay the Order issued by the court. On July 25, 2015, the court denied Colowyo Coal’s Motion to Stay the Order. On July 27, 2015, OSM released a draft remedial environmental assessment of Colowyo Coal’s mining permit modification with a preliminary Finding of No Significant Impact. On August 31, 2015, OSM signed an environmental assessment of Colowyo Coal’s mine permit modification with a Finding of No Significant Impact, which was approved by the Assistant Secretary on September 2, 2015. On September 4, 2015, OSM filed a Notice of Compliance stating OSM had complied with the court’s May 8, 2015 order, thus obviating the need for entry of a vacatur order.

NEW ACCOUNTING PRONOUNCEMENTS

NEW ACCOUNTING PRONOUNCEMENTS	9 Months Ended
	Sep. 30, 2015
NEW ACCOUNTING PRONOUNCEMENTS
NEW ACCOUNTING PRONOUNCEMENTS	NOTE 12 – NEW ACCOUNTING PRONOUNCEMENTS In February 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-02, Consolidation (Topic 810), Amendments to the Consolidation Analysis . The amendments in this ASU affect reporting entities that are required to evaluate whether they should consolidate certain legal entities. All legal entities are subject to reevaluation under the revised consolidation model. Specifically, ASU 2015-02: (1) modifies the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities, (2) eliminates the presumption that a general partner should consolidate a limited partnership, and (3) affects the consolidation analysis of reporting entities that are involved with variable interest entities, particularly those that have fee arrangements and related party relationships. For public business entities, ASU 2015-02 is effective for the fiscal years, and for interim periods within those fiscal years, beginning after December 15, 2015. Early adoption is permitted, including adoption in an interim period. A reporting entity may apply the amendments in this ASU using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the fiscal year of adoption. A reporting entity also may apply the amendments retrospectively. The adoption of this amendment is not expected to have a material impact on our financial position and results of operations. In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) . Subsequently, FASB issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date . ASU 2014-09 replaces current revenue guidance, which was based on a risks and rewards model, with a transfer of control model. The core principle under the new transfer of control model states that revenue should be recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. To achieve the core principle, this amendment requires the following steps: (1) identify the contract(s) with the customer, (2) identify the performance obligations in the contract, (3) determine the transaction price, (4) allocate the transaction price to the performance obligations in the contract, and (5) recognize revenue when (or as) the entity satisfies a performance obligation. This amendment also requires additional quantitative and qualitative disclosures sufficient enough to enable users of financial information to understand the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. For public business entities, this amendment is effective for the fiscal year beginning January 1, 2018 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes footnote disclosures). Reporting entities have the option to adopt the standard as early as the original January 1, 2017 effective date of this amendment. We are currently evaluating the impact of this amendment on our financial position and results of operations.

PRESENTATION OF FINANCIAL INF19

PRESENTATION OF FINANCIAL INFORMATION (Tables)	9 Months Ended
	Sep. 30, 2015
PRESENTATION OF FINANCIAL INFORMATION
Schedule of jointly owned facilities	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 $ $ $

ACCOUNTING FOR RATE REGULATION

ACCOUNTING FOR RATE REGULATION (Tables)	9 Months Ended
	Sep. 30, 2015
ACCOUNTING FOR RATE REGULATION
Schedule of regulatory assets and liabilities	Regulatory assets and liabilities are as follows (thousands): September 30, December 31, 2015 2014 Regulatory assets Deferred income tax expense (1) $ $ Deferred prepaid lease expense- Craig 3 Lease (2) Deferred prepaid lease expense- Springerville 3 Lease (3) Goodwill – J.M. Shafer (4) Goodwill – Colowyo Coal (5) Deferred debt prepayment transaction costs (6) Regulatory liabilities Deferred revenues (7) Net regulatory asset $ $ (1) A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues. (2) Deferral of loss on acquisition related to the Craig Generating Station Unit 3 prepaid lease expense upon acquisitions of equity interests in 2002 and 2006. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $6.5 million annually through the remaining original life of the lease ending in 2018 and recovered from our Members in rates. (3) Deferral of loss on acquisition related to the Springerville Generating Station Unit 3 prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation and amortization expense in the amount of $2.3 million annually through the 47 -year period ending in 2056 and recovered from our Members in rates. (4) Represents goodwill related to our acquisition of Thermo Cogeneration Partnership, LP in December 2011. Goodwill is being amortized to depreciation and amortization expense in the amount of $2.8 million annually through the 25 -year period ending in 2036 and recovered from our Members in rates. (5) Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation and amortization expense through the 44 -year period ending in 2056 and recovered from our Members in rates. (6) Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation and amortization expense in the amount of $8.6 million annually over the 21.4 -year average life of the new debt issued and recovered from our Members in rates. (7) Represents deferral of the recognition of $10 million of non-member electric sales revenue received in 2008 and $35 million of non-member electric sales revenue received in 2011. These deferred non-member electric sales revenues will be refunded to Members through reduced rates when recognized in non-member electric sales revenue in future periods.

RESTRICTED CASH AND INVESTMEN21

RESTRICTED CASH AND INVESTMENTS (Tables)	9 Months Ended
	Sep. 30, 2015
RESTRICTED CASH AND INVESTMENTS
Schedule of Restricted Cash and Investments	September 30, December 31, 2015 2014 Investments in securities pledged as collateral $ $ Funds restricted by contract Restricted cash and investments - current BNSF settlement — Funds restricted by contract Investments in securities pledged as collateral Restricted cash and investments - noncurrent Total restricted cash and investments $ $

OTHER DEFERRED CHARGES (Tables)

OTHER DEFERRED CHARGES (Tables)	9 Months Ended
	Sep. 30, 2015
OTHER DEFERRED CHARGES.
Schedule of Other Deferred Charges	September 30, December 31, 2015 2014 Preliminary surveys and investigations $ $ Advances to operating agents of jointly owned facilities Debt issuance costs Other Total other deferred charges $ $

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	9 Months Ended
	Sep. 30, 2015
LONG-TERM DEBT NOTE
Schedule of long-term debt	September 30, December 31, 2015 2014 Total debt $ $ Less current maturities Long-term debt $ $

OTHER DEFERRED CREDITS AND OT24

OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Tables)	9 Months Ended
	Sep. 30, 2015
OTHER DEFERRED CREDITS AND OTHER LIABILITIES
Schedule of other deferred credits and other liabilities	September 30, December 31, 2015 2014 BNSF rate settlement proceeds not recognized in income $ — $ Customer deposits Unearned revenue Other deferred credits Total other deferred credits and other liabilities $ $

FAIR VALUE (Tables)

FAIR VALUE (Tables)	9 Months Ended
	Sep. 30, 2015
Marketable securities
FAIR VALUE
Schedule of carrying amounts and fair values of assets and liabilities	As of September 30, 2015 As of December 31, 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Marketable securities $ $ $ $
Long-term debt
FAIR VALUE
Schedule of carrying amounts and fair values of assets and liabilities	As of September 30, 2015 As of December 31, 2014 Carrying Estimated Carrying Estimated Amount Fair Value Amount Fair Value Long-term debt $ $ $ $

PRESENTATION OF FINANCIAL INF26

PRESENTATION OF FINANCIAL INFORMATION (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2015USD ($)facility
Jointly owned facilities
Number of jointly owned facilities | facility	3
Electric plant in service	$ 821,302
Accumulated depreciation	578,921
Construction work in progress	$ 28,043
Yampa
Jointly owned facilities
Tri-State share (as a percent)	24.00%
Electric plant in service	$ 345,409
Accumulated depreciation	228,607
Construction work in progress	$ 19,398
MBPP
Jointly owned facilities
Tri-State share (as a percent)	24.13%
Electric plant in service	$ 391,790
Accumulated depreciation	290,879
Construction work in progress	$ 8,504
San Juan Project
Jointly owned facilities
Tri-State share (as a percent)	8.20%
Electric plant in service	$ 84,103
Accumulated depreciation	59,435
Construction work in progress	$ 141

ACCOUNTING FOR RATE REGULATIO27

ACCOUNTING FOR RATE REGULATION (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Regulatory assets and liabilities
Regulatory assets	$ 416,109	$ 426,043
Regulatory liabilities	45,000	45,000
Net regulatory asset	371,109	381,043
Deferred revenue
Regulatory assets and liabilities
Regulatory liabilities	45,000	45,000
Deferred revenue received in 2008
Regulatory assets and liabilities
Amortization expense	10,000
Deferred revenue received in 2011
Regulatory assets and liabilities
Amortization expense	35,000
Craig 3 Lease
Regulatory assets and liabilities
Annual amortization expense	6,500
Deferred income tax expense
Regulatory assets and liabilities
Regulatory assets	24,417	17,230
Deferred prepaid lease expense | Craig 3 Lease
Regulatory assets and liabilities
Regulatory assets	17,802	22,656
Deferred prepaid lease expense | Springerville 3 Lease
Regulatory assets and liabilities
Regulatory assets	93,450	95,168
Annual amortization expense	$ 2,300
Remaining amortization period	47 years
Goodwill | J.M. Shafer
Regulatory assets and liabilities
Regulatory assets	$ 61,253	63,390
Annual amortization expense	$ 2,800
Remaining amortization period	25 years
Goodwill | Colowyo Coal
Regulatory assets and liabilities
Regulatory assets	$ 41,585	43,526
Remaining amortization period	44 years
Deferred debt prepayment transaction costs
Regulatory assets and liabilities
Regulatory assets	$ 177,602	$ 184,073
Remaining amortization period	21 years 4 months 24 days
Amortization expense	$ 8,600

RESTRICTED CASH AND INVESTMEN28

RESTRICTED CASH AND INVESTMENTS (Details) - USD ($) $ in Thousands	1 Months Ended	9 Months Ended
	Jun. 30, 2015	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2009
Restricted cash and investments
Restricted cash and investments - current		$ 10,323		$ 9,784
Restricted cash and investments - noncurrent		4,931		39,376
Restricted cash and investments		15,254		49,160
Restricted cash released due to settlement		29,148	$ 29,213
Securities pledged as collateral
Restricted cash and investments
Restricted cash and investments - current		9,498		9,192
Restricted cash and investments - noncurrent		3,931		8,995
Funds restricted by contract
Restricted cash and investments
Restricted cash and investments - current		825		592
Restricted cash and investments - noncurrent		$ 1,000		1,000
BNSF settlement
Restricted cash and investments
Restricted cash and investments - noncurrent				$ 29,381
Restricted cash and investments					$ 29,400
Restricted cash released due to settlement	$ 29,400

OTHER DEFERRED CHARGES (Details

OTHER DEFERRED CHARGES (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014
Other deferred charges
Preliminary surveys and investigations	$ 136,667	$ 131,693
Advances to operating agents of jointly owned facilities	19,072	20,567
Debt issuance costs	21,669	22,254
Other	2,264	3,940
Total other deferred charges	$ 179,672	$ 178,454
Minimum
Other deferred charges
Remaining amortization periods	2 years
Maximum
Other deferred charges
Remaining amortization periods	34 years
Holcomb Station Project
Other deferred charges
Preliminary surveys and investigations	$ 85,500
Eastern Plains Transmission Project
Other deferred charges
Preliminary surveys and investigations	$ 28,200

LONG-TERM DEBT - Terms (Details

LONG-TERM DEBT - Terms (Details) $ in Thousands	Sep. 30, 2015USD ($)instrument	Dec. 31, 2014USD ($)
Notes payable and credit facility information
Number of unsecured debt instruments | instrument	1
Amount outstanding	$ 3,388,233	$ 3,260,302
2011 Credit Agreement
Notes payable and credit facility information
Maximum borrowing capacity	750,000
Amount outstanding	261,000	$ 50,000
Letter of credit, issued	46,800
Available borrowing capacity	$ 441,000

LONG-TERM DEBT - Components (De

LONG-TERM DEBT - Components (Details) - USD ($) $ in Thousands	Sep. 30, 2015	Dec. 31, 2014
Long-term debt, components
Total debt	$ 3,388,233	$ 3,260,302
Less current maturities	(97,409)	(94,342)
Long-term debt	$ 3,290,824	$ 3,165,960

OTHER DEFERRED CREDITS AND OT32

OTHER DEFERRED CREDITS AND OTHER (Details) - USD ($) $ in Thousands	1 Months Ended
	Jun. 30, 2015	Sep. 30, 2015	Dec. 31, 2014	Dec. 31, 2009
Other deferred credits and other liabilities
Settlement proceeds not recognized in income			$ 29,381
Customer deposits		$ 6,166	2,464
Unearned revenue		4,726	4,210
Other deferred credits		26,984	23,066
Total other deferred credits and other liabilities		$ 37,876	$ 59,121
BNSF settlement
Other deferred credits and other liabilities
Net settlement recorded as fuel expense offset	$ 24,400
Settlement proceeds not recognized in income				$ 29,400

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
INCOME TAXES
Income tax expense or benefit	$ 0	$ 0	$ 0	$ 0

FAIR VALUE (Details)

FAIR VALUE (Details) - Recurring - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Level 3
Fair value:
Financial assets measured at Level 3	$ 0	$ 0
Financial liabilities measured at Level 3	0	0
Carrying Amount | Level 1
Fair value:
Marketable securities	939,000	1,095,000
Carrying Amount | Level 2
Fair value:
Long-term debt	3,388,233,000	3,260,302,000
Estimated Fair Value | Level 1
Fair value:
Marketable securities	1,081,000	1,349,000
Estimated Fair Value | Level 2
Fair value:
Long-term debt	$ 3,719,615,000	$ 3,716,513,000

VARIABLE INTEREST ENTITIES - Co

VARIABLE INTEREST ENTITIES - Consolidated Entities (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Consolidated Variable Interest Entities
Noncontrolling interest included in consolidated statements of financial position (in dollars)	$ 108,855		$ 108,855		$ 109,302
Depreciation and amortization (in dollars)	38,371	$ 34,275	109,317	$ 96,360
Interest expense (in dollars)	$ 35,846	34,986	$ 106,919	105,617
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%
Noncontrolling interest included in consolidated statements of financial position (in dollars)	$ 108,900		$ 108,900		109,300
Depreciation and amortization (in dollars)	5,300	5,300	15,800	15,800
Interest expense (in dollars)	8,000	$ 8,500	24,300	$ 25,600
Springerville Partnership | Primary Beneficiary | Net electric plant
Consolidated Variable Interest Entities
Assets of variable interest entity included in consolidated statements of financial position (in dollars)	858,600		858,600		874,400
Springerville Partnership | Primary Beneficiary | Long-term debt
Consolidated Variable Interest Entities
Liabilities of variable interest entity included in consolidated statements of financial position (in dollars)	511,600		511,600		548,100
Springerville Partnership | Primary Beneficiary | Accrued interest included in long-term debt
Consolidated Variable Interest Entities
Liabilities of variable interest entity included in consolidated statements of financial position (in dollars)	$ 5,700		$ 5,700		$ 15,200
Springerville Partnership | Primary Beneficiary | Springerville 3 Lease
Consolidated Variable Interest Entities
Percentage of financial and other support provided			100.00%
Springerville Partnership | Springerville Unit 3 Holding LLC
Consolidated Variable Interest Entities
Ownership interest held by parent (as a percent)	100.00%		100.00%

VARIABLE INTEREST ENTITIES - Un

VARIABLE INTEREST ENTITIES - Unconsolidated Entities (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
WFA | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments in other associations
Unconsolidated Variable Interest Entities
Investment in other association (in dollars)	$ 2.2	$ 2.3
Trapper Mining | Unconsolidated Variable Interest Entity - not primary beneficiary | Investments in other associations
Unconsolidated Variable Interest Entities
Investment in other association (in dollars)	$ 15.5	$ 13.7
WFA | WFW | Class AA shares
Unconsolidated Variable Interest Entities
Ownership interest held by parent (as a percent)	100.00%
WFA | 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 (Details)

LEGAL (Details)	Oct. 28, 2015USD ($)	Jul. 20, 2015	May. 08, 2015	Feb. 09, 2015MW	Jun. 10, 2013USD ($)	Jun. 30, 2011plaintiff	Sep. 30, 2015USD ($)
Damages from fire
Litigation information
Number of plaintiff groups | plaintiff						6
Pending litigation | Damages from fire
Litigation information
Liability insurance coverage							$ 100,000,000
Pending litigation | Damages from fire | JMEC
Litigation information
Percentage negligent	$ 75
Pending litigation | Damages from fire | Tri-State
Litigation information
Percentage negligent	20
Pending litigation | Damages from fire | United States Forest Service
Litigation information
Percentage negligent	$ 5
Jemez Pueblo | Damages from fire
Litigation information
Damages sought					$ 34,400,000
Pueblo de Cochiti | Damages from fire
Litigation information
Damages sought					$ 23,900,000
DMEA Petition for Declaratory Order
Litigation information
Maximum production capacity (in MW) | MW				80
Kit Carson Motion for Clarification | Minimum
Litigation information
Minimum percent of purchase and receive obligation (as a percent)		95.00%
WEG vs. OSM | Vacatur | Permitting Revision
Litigation information
Vacatur order, duration			120 days