Tri-State Generation & Transmission Association 10-K 10 Mar 23 2022 FY Annual report Financial data

Cover

Cover - USD ($)	12 Months Ended
	Dec. 31, 2022	Mar. 10, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	333-212006
Entity Registrant Name	TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.
Entity Incorporation, State or Country Code	CO
Entity Tax Identification Number	84-0464189
Entity Address, Address Line One	1100 West 116th Avenue
Entity Address, City or Town	Westminster
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80234
City Area Code	303
Local Phone Number	452-6111
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	Yes
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		0
Documents Incorporated by Reference	NONE.
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Central Index Key	0001637880
Amendment Flag	false
Entity Public Float			$ 0

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
Auditor Information [Abstract]
Auditor Firm ID	42
Auditor Name	Ernst & Young LLP
Auditor Location	Denver, Colorado

Consolidated Statements of Fina

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Electric plant
In service	$ 5,659,423	$ 5,606,732
Construction work in progress	81,555	107,636
Total electric plant	5,740,978	5,714,368
Less allowances for depreciation and amortization	(2,392,363)	(2,367,197)
Net electric plant	3,348,615	3,347,171
Other plant	954,144	1,093,922
Less allowances for depreciation, amortization and depletion	(694,774)	(823,087)
Net other plant	259,370	270,835
Total property, plant and equipment	3,607,985	3,618,006
Other assets and investments
Investments in other associations	177,477	163,097
Investments in and advances to coal mines	1,914	2,273
Restricted cash and investments	4,257	4,101
Other noncurrent assets	15,828	15,873
Total other assets and investments	199,476	185,344
Current assets
Cash and cash equivalents	105,852	100,555
Restricted cash and investments	573	480
Deposits and advances	34,233	34,042
Accounts receivable—Members	103,246	95,630
Other accounts receivable	32,436	21,571
Coal inventory	34,723	59,701
Materials and supplies	93,514	87,234
Total current assets	404,577	399,213
Deferred charges
Regulatory assets	650,421	665,693
Prepayment—NRECA Retirement Security Plan	10,745	16,117
Other	40,445	35,139
Total deferred charges	701,611	716,949
Total assets	4,913,649	4,919,512
Capitalization
Patronage capital equity	984,865	994,865
Accumulated other comprehensive loss	(468)	(1,460)
Noncontrolling interest	126,180	119,100
Total equity	1,110,577	1,112,505
Long-term debt	2,869,963	3,101,870
Total capitalization	3,980,540	4,214,375
Current liabilities
Member advances	17,070	17,217
Accounts payable	109,109	105,965
Short-term borrowings	274,102	49,997
Accrued expenses	42,506	32,882
Current asset retirement obligations	5,419	7,003
Accrued interest	25,431	25,716
Accrued property taxes	36,477	33,877
Current maturities of long-term debt	92,920	93,039
Total current liabilities	603,034	365,696
Deferred credits and other liabilities
Regulatory liabilities	49,931	146,021
Deferred income tax liability	19,275	18,987
Asset retirement and environmental reclamation obligations	181,588	83,278
Other	68,374	78,319
Total deferred credits and other liabilities	319,168	326,605
Accumulated postretirement benefit and postemployment obligations	10,907	12,836
Total equity and liabilities	$ 4,913,649	$ 4,919,512

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating revenues
Other	$ 61,420	$ 56,341	$ 53,545
Operating revenues	1,533,571	1,400,801	1,352,295
Operating expenses
Purchased power	409,513	381,477	335,814
Fuel	329,046	236,089	234,844
Production	177,413	185,016	171,188
Transmission	175,889	182,327	170,933
General and administrative	79,640	57,243	69,796
Depreciation, amortization and depletion	184,047	190,237	185,243
Coal mining	9,899	5,323	11,691
Other	53,509	7,191	15,126
Operating expenses	1,418,956	1,244,903	1,194,635
Operating margins	114,615	155,898	157,660
Other income
Interest	4,447	3,609	4,218
Capital credits from cooperatives	26,185	9,466	11,803
Other	10,027	4,152	1,831
Other income	40,659	17,227	17,852
Interest expense
Interest	148,609	143,328	151,423
Interest charged during construction	(1,486)	(3,786)	(6,088)
Interest expense, net of amounts capitalized	147,123	139,542	145,335
Income tax expense (benefit)	(249)	295	(534)
Net margins including noncontrolling interest	8,400	33,288	30,711
Net margin attributable to noncontrolling interest	(8,400)	(6,942)	(5,590)
Net margins attributable to the Association	0	26,346	25,121
Member electric sales
Operating revenues
Operating revenues	1,213,234	1,161,291	1,196,232
Non-member electric sales
Operating revenues
Operating revenues	163,355	114,908	90,382
Rate stabilization
Operating revenues
Operating revenues	95,613	78,457	12,136
Provision for rate refunds
Operating revenues
Operating revenues	$ (51)	$ (10,196)	$ 0

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Net margins including noncontrolling interest	$ 8,400	$ 33,288	$ 30,711
Other comprehensive income (loss):
Unrealized loss on securities available for sale	(333)	(108)	0
Other comprehensive income (loss)	992	4,254	(4,196)
Comprehensive income including noncontrolling interest	9,392	37,542	26,515
Net comprehensive income attributable to noncontrolling interest	(8,400)	(6,942)	(5,590)
Comprehensive income attributable to the Association	992	30,600	20,925
Postretirement Medical Benefit Plans
Other comprehensive income (loss):
Unrecognized prior service credit (cost)	0	5,698	0
Unrecognized actuarial gain (loss)	32	784	625
Amortization of actuarial (gain) loss	102	78	0
Amortization of prior service cost (credit)	(1,636)	(2,139)	(79)
Executive Benefit Restoration Plan
Other comprehensive income (loss):
Unrecognized prior service credit (cost)	(308)	(1,050)	(4,674)
Unrecognized actuarial gain (loss)	1,740	(778)	(1,980)
Amortization of actuarial (gain) loss	426	515	0
Amortization of prior service cost (credit)	1,156	1,113	1,912
Curtailment and settlement	$ (187)	$ 141	$ 0

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Postretirement Medical Benefit Plans	Executive Benefit Restoration Plan	Patronage capital	Accumulated other comprehensive income (loss)	Accumulated other comprehensive income (loss) Postretirement Medical Benefit Plans	Accumulated other comprehensive income (loss) Executive Benefit Restoration Plan	Noncontrolling interest
Equity at beginning of period at Dec. 31, 2019				$ 1,031,063	$ (1,518)			$ 111,717
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net margins attributable to the Association	$ 25,121			25,121
Retirement of patronage capital				(77,665)
Unrealized loss on securities available for sale	0
Reclassification adjustment for actuarial (gain) loss		$ 0	$ 0
Reclassification adjustment for prior service cost (credit)		(79)	1,912			$ (79)	$ 1,912
Curtailment and settlement			0
Unrecognized prior service credit (cost)		0	(4,674)				(4,674)
Unrecognized actuarial gain (loss)		625	(1,980)			625	(1,980)
Net comprehensive income attributable to noncontrolling interest	(5,590)							5,590
Equity distribution to noncontrolling interest								(2,456)
Equity at end of period at Dec. 31, 2020	1,087,656			978,519	(5,714)			114,851
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net margins attributable to the Association	26,346			26,346
Retirement of patronage capital				(10,000)
Unrealized loss on securities available for sale	(108)				(108)
Reclassification adjustment for actuarial (gain) loss		78	515			78	515
Reclassification adjustment for prior service cost (credit)		(2,139)	1,113			(2,139)	1,113
Curtailment and settlement			141				141
Unrecognized prior service credit (cost)		5,698	(1,050)			5,698	(1,050)
Unrecognized actuarial gain (loss)		784	(778)			784	(778)
Net comprehensive income attributable to noncontrolling interest	(6,942)							6,942
Equity distribution to noncontrolling interest								(2,693)
Equity at end of period at Dec. 31, 2021	1,112,505			994,865	(1,460)			119,100
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net margins attributable to the Association	0
Retirement of patronage capital				(10,000)
Unrealized loss on securities available for sale	(333)				(333)
Reclassification adjustment for actuarial (gain) loss		102	426			102	426
Reclassification adjustment for prior service cost (credit)		(1,636)	1,156			(1,636)	1,156
Curtailment and settlement			(187)				(187)
Unrecognized prior service credit (cost)		0	(308)				(308)
Unrecognized actuarial gain (loss)		$ 32	$ 1,740			$ 32	$ 1,740
Net comprehensive income attributable to noncontrolling interest	(8,400)							8,400
Equity distribution to noncontrolling interest								(1,320)
Equity at end of period at Dec. 31, 2022	$ 1,110,577			$ 984,865	$ (468)			$ 126,180

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating activities
Net margins including noncontrolling interest	$ 8,400	$ 33,288	$ 30,711
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion	184,047	190,237	185,243
Amortization of NRECA Retirement Security Plan prepayment	5,372	5,372	5,372
Amortization of debt issuance costs	3,105	2,479	2,460
Impairment loss	29,098	0	274,645
Deferred impairment loss and other closure costs	(29,098)	0	(283,047)
Deferred membership withdrawal income	0	0	110,165
Deposits associated with generator interconnection requests	6,716	17,130	0
Rate stabilization	(95,613)	(78,457)	(12,136)
Capital credit allocations from cooperatives and income from coal mines under (over) refund distributions	(14,115)	512	(1,268)
Changes in operating assets and liabilities:
Accounts receivable	(30,135)	(3,618)	17,358
Coal inventory	24,978	(3,453)	(5,571)
Materials and supplies	(6,281)	(4,714)	(40)
Accounts payable and accrued expenses	19,102	13,114	(844)
Accrued interest	(285)	(1,804)	(2,196)
Accrued property taxes	2,600	1,082	3,665
New Horizon Mine environmental obligation	44,869	0	0
Other	(164)	(1,261)	6,402
Net cash provided by operating activities	152,596	169,907	330,919
Investing activities
Purchases of plant	(121,527)	(118,422)	(142,152)
Sale of electric plant	0	0	26,000
Changes in deferred charges	(4,617)	(13,054)	(4,885)
Proceeds from other investments	94	72	733
Net cash used in investing activities	(126,050)	(131,404)	(120,304)
Financing activities
Changes in Member advances	(282)	183	(7,837)
Payments of long-term debt	(232,946)	(94,288)	(282,757)
Proceeds from issuance of long-term debt	0	0	425,000
Debt issuance costs	(1,475)	0	(637)
Change in short-term borrowings, net	224,105	49,997	(252,323)
Retirement of patronage capital	(8,445)	(18,067)	(70,881)
Equity distribution to noncontrolling interest	(1,320)	(2,693)	(2,456)
Other	(637)	(573)	(418)
Net cash used in financing activities	(21,000)	(65,441)	(192,309)
Net increase (decrease) in cash, cash equivalents and restricted cash and investments	5,546	(26,938)	18,306
Cash, cash equivalents and restricted cash and investments – beginning	105,136	132,074	113,768
Cash, cash equivalents and restricted cash and investments – ending	110,682	105,136	132,074
Supplemental cash flow information:
Cash paid for interest	145,350	143,394	152,570
Cash paid for income taxes	0	0	0
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$ (1,076)	$ 1,383	$ 440

ORGANIZATION

ORGANIZATION	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION	ORGANIZATION Tri‑State Generation and Transmission Association, Inc. (“Tri-State,” “we,” “our,” “us,” or “the Association”) is a taxable wholesale electric power generation and transmission cooperative operating on a not-for-profit basis serving large portions of Colorado, Nebraska, New Mexico and Wyoming. We were incorporated under the laws of the State of Colorado in 1952. We have three classes of membership: Class A – utility full requirements members, Class B - utility partial requirements members, and non-utility members. We have forty-two electric distribution member systems who are Class A members, to which we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members. We have three non-utility members ("Non-Utility Members"). Our Class A members and any Class B members are collectively referred to as our "Utility Members." Our Class A members, any Class B members, and Non-Utility Members are collectively referred to as our "Members." Our rates are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). On December 23, 2019, our stated rate to our Class A members was filed at FERC and was accepted by FERC on March 20, 2020. On August 2, 2021, FERC approved our settlement agreement related to our stated rate to our Class A members. See Note 14—Commitments and Contingencies—Legal. We also sell a portion of our electric power to other utilities in our regions pursuant to long-term contracts and short-term sale arrangements. In 2022, 2021 and 2020, total megawatt‑hours sold were 18.6 , 17.6 and 17.5 million, respectively, of which 88.8, 89.1 and 90.8 percent, respectively, were sold to Utility Members. Total revenue from electric sales was $1.4 billion for 2022 and $1.3 billion for 2021 and 2020 of which 82.4, 86.4, and 92.1 percent in 2022, 2021 and 2020, respectively, was from Utility Member sales. Energy resources were provided by our generation and purchased power, of which 54.3, 52.1 and 58.2 percent in 2022, 2021 and 2020, respectively, were from our generation. Power is provided to Utility Members at rates determined by our Board of Directors (“Board”), subject to FERC approval. Rates are designed to recover all costs and provide margins to increase Utility Members’ equity and to meet certain financial covenants, including a debt service ratio (“DSR”) requirement and equity to capitalization ratio (“ECR”) requirement. We supply wholesale power to our Utility Members through the utilization of a portfolio of resources, including generation and transmission facilities, long‑term purchase contracts and short‑term energy purchases. Our generating facilities also include undivided ownership interests in jointly owned generating facilities. See Note 3—Property, Plant and Equipment. In support of our coal-fired generating facilities, we have direct ownership in coal mines. We, including our subsidiaries, employ 1,105 people, of which 215 are subject to collective bargaining agreements. None of these agreements expire within one year.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES BASIS OF CONSOLIDATION: Our consolidated financial statements include the accounts of the Association, our wholly owned and majority owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 13—Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. All significant intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) as applied to regulated enterprises. JOINTLY OWNED FACILITIES: We own undivided interests in two jointly owned generating 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) and the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)). Each participant in these agreements receives a portion of the total output of the generation facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and operating expenses is included in our consolidated financial statements. See Note 3—Property, Plant and Equipment. SEGMENT REPORTING: We were organized for the purpose of supplying wholesale power to our Utility Members and do so through the utilization of a portfolio of resources, including generation and transmission facilities, long‑term purchase contracts and short‑term energy purchases. In support of our coal-fired generating resources, we have direct ownership in coal mines. Our Board serves as our chief operating decision maker who manages and reviews our operating results and allocates resources as one operating segment. Therefore, we have one reportable segment for financial reporting purposes. USE OF ESTIMATES: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. IMPAIRMENT EVALUATION: Long-lived assets (property, plant and equipment, intangible assets, investments and preliminary surveys and investigation costs) that are held and used are evaluated for impairment whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. An impairment loss is recognized when estimated undiscounted cash flows expected to result from the use of the asset plus net proceeds expected from disposition of the asset (if any) are less than the carrying value of the asset. When an impairment loss is recognized, the carrying amount of the asset is reduced to its estimated fair value based on quoted market prices or other valuation techniques. In 2022, we recognized an impairment loss of $3.7 million associated with the early retirement of the Rifle Generating Station. We also recognized an impairment loss of $25.4 million associated with additional asset retirement obligations at the Nucla and Escalante Generating Stations related to a change in cost estimates. There were no impairments of long-lived assets recognized in 2021. In 2020, we recognized an impairment loss of $274.6 million associated with the early retirement of the Escalante Generating Station. These impairment losses were deferred in accordance with the accounting requirements related to regulated operations at the discretion of our Board and subject to FERC approval, if applicable. See Note 2—Accounting for Rate Regulation. VARIABLE INTEREST ENTITIES: We evaluate our arrangements and relationships with other entities, including our investments in other associations in accordance with the accounting standard related to consolidation of variable interest entities. This guidance requires us to identify variable interests (contractual, ownership or other financial interests) in other entities and whether any of those entities in which we have a variable interest meet the criteria of a variable interest entity. An entity is considered to be a variable interest entity when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. In making this assessment, we consider the potential that our arrangements and relationships with other entities provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of an entity, the ability to directly or indirectly make decisions about the entity’s activities and other factors. If an entity that we have a variable interest in meets the criteria of a variable interest entity, we must determine whether we are the primary beneficiary of that entity. The primary beneficiary is the entity that has the power to direct the activities of the variable interest entity that most significantly impact the variable interest entity’s economic performance, and the obligation to absorb losses or the right to receive benefits from the variable interest entity that could be potentially significant to the variable interest entity. If we are determined to be the primary beneficiary of (has controlling financial interest in) a variable interest entity, then we would be required to consolidate that entity. In certain situations, it may be determined that power is shared among multiple unrelated parties such that no one party has the power to direct the activities of a variable interest entity that most significantly impact the variable interest entity’s economic performance (decisions about those activities require the consent of each of the parties sharing power). In accordance with the accounting guidance prescribed by consolidation of variable interest entities, if the determination is made that power is shared among multiple unrelated parties, then no party is the primary beneficiary. See Note 13—Variable Interest Entities. ACCOUNTING FOR RATE REGULATION: In accordance with the accounting requirements related to regulated operations, some revenues and expenses have been deferred at the discretion of our Board, subject to FERC approval, if based on regulatory orders or other available evidence, it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs we expect to recover from our Utility Members based on rates approved by the applicable authority. Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to our Utility Members based on rates approved by the applicable authority. Expected recovery of deferred costs and returning deferred credits are based on specific ratemaking decisions by FERC or precedent for each item. We recognize regulatory assets as expenses and regulatory liabilities as operating revenue, other income, or a reduction in expense concurrent with their recovery through rates. Regulatory assets and liabilities are as follows (dollars in thousands): December 31, December 31, Regulatory assets Deferred income tax expense (1) $ 19,279 $ 18,742 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 76,842 79,133 Goodwill – J.M. Shafer (3) 40,598 43,447 Goodwill – Colowyo Coal (4) 34,095 35,128 Deferred debt prepayment transaction costs (5) 115,045 123,674 Deferred Holcomb expansion impairment loss (6) 79,470 84,145 Unrecovered plant (7) 285,092 281,424 Total regulatory assets 650,421 665,693 Regulatory liabilities Interest rate swap - realized gain (8) and other 2,341 2,818 Membership withdrawal (9) 47,590 143,203 Total regulatory liabilities 49,931 146,021 Net regulatory asset $ 600,490 $ 519,672 ___________________________________________ (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) Represents deferral of the 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 Utility Members in rates. (3) 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 Utility Members in rates. (4) 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 Utility Members in rates. (5) 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 period ending in 2036 and recovered from our Utility Members in rates. (6) Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. The regulatory asset for the deferred impairment loss is being amortized to other operating expenses in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members in rates. (7) Represents deferral of the impairment losses and other closure costs related to the early retirement of the Nucla, Escalante and Rifle Generating Stations. The deferred impairment loss for Nucla Generating Station was amortized to depreciation, amortization and depletion expense through December 2022 and recovered from our Utility Members through rates. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $12.2 million annually over the 25-year period ending in December 2045, which was the depreciable life of Escalante Generating Station, and recovered from our Utility Members through rates. The annual amortization approximates the former annual Escalante Generating Station depreciation for the remaining life of the asset. In March 2022, our Board took action for the early retirement of Rifle Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement, we recognized an impairment loss of $3.7 million during the first quarter of 2022. The Rifle Generating Station was retired from service on September 30, 2022. The deferred impairment loss is being amortized to depreciation, amortization and depletion expense in the amount of $0.6 million annually through December 2028, which was the depreciable life of the Rifle Generating Station, and recovered from our Utility Members in rates. (8) Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12- year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods. (9) Represents the deferral of the recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. The deferred membership withdrawal income will be refunded to Utility Members through reduced rates when recognized in operating revenues in future periods. During 2022, $95.6 million was recognized in operating revenues as part of our rate stabilization measures. ELECTRIC PLANT AND DEPRECIATION: Electric plant is stated at cost. The cost of internally constructed assets includes payroll, overhead costs and interest charged during construction. Interest rates charged during construction were 2.3 percent for 2022, 4.4 percent for 2021 and 4.6 percent for 2020. During 2022, Tri-State transitioned from using the "Indirect Costs" ("IDC") rate to the FERC prescribed "Allowance For Funds Used During Construction" ("AFUDC") rate. AFUDC is defined as the gross allowance for borrowed funds used during construction. The AFUDC rate is calculated with the assumption that short-term debt is the first source of funds used for construction. Any construction not covered by the short-term debt is then assumed to be covered by long-term debt. The AFUDC rate varies from the IDC rate, which assumes that total debt was used to cover construction costs. The amount of interest capitalized during construction was $1.5, $3.8 and $6.1 million during 2022, 2021 and 2020, respectively. At the time that units of electric plant are retired, original cost and cost of removal, net of the salvage value, are charged to the allowance for depreciation. Replacements of electric plant that involve less than a designated unit value are charged to maintenance expense when incurred. Electric plant is depreciated based upon estimated depreciation rates and useful lives that are periodically re‑evaluated. See Note 3—Property, Plant and Equipment. COAL RESERVES AND DEPLETION: Coal reserves are recorded at cost. Depletion of coal reserves is computed using the units‑of‑production method utilizing only proven and probable reserves. LEASES: We determine if an arrangement is a lease upon commencement of the contract. If an arrangement is determined to be a long-term lease (greater than 12 months), we recognize a right-of-use asset and lease liability based on the present value of the future minimum lease payments over the lease term at the commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Our lease terms may also include options to extend or terminate the lease when it is reasonably certain that we will exercise those options. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. Right-of-use assets are included in other deferred charges, the current portion of lease liabilities is included in accrued expenses and the long-term portion of lease liabilities is included in other deferred credits and other liabilities on our consolidated statements of financial position. See Note 11—Leases. We have elected to apply the short-term lease exception for contracts that have a lease term of twelve months or less and do not include an option to purchase the underlying asset. Therefore, we do not recognize a right-of-use asset or lease liability for such contracts. We recognize short-term lease payments as expense on a straight-line basis over the lease term. Variable lease payments that do not depend on an index or rate are recognized as incurred. INVESTMENTS IN OTHER ASSOCIATIONS: Investments in other associations include investments in the patronage capital of other cooperatives and other required investments in the organizations. Our investment in a cooperative increases when a cooperative allocates patronage capital credits to us, and it decreases when we receive a cash retirement of the allocated capital credits from the cooperative. A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative. Investments in other associations are as follows (dollars in thousands): December 31, December 31, Basin Electric Power Cooperative $ 127,640 $ 116,826 National Rural Utilities Cooperative Finance Corporation - patronage capital 12,172 12,076 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,054 15,149 CoBank, ACB 16,727 12,985 Other 5,884 6,061 Investments in other associations $ 177,477 $ 163,097 Our investments in other associations are considered equity securities without readily determinable fair values, and as such are measured at cost minus impairment. We have evaluated these investments for indicators of impairment. There were no impairments of these investments recognized during 2022, 2021 or 2020. CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS: We consider highly liquid investments with an original maturity of three months or less to be cash equivalents. The fair value of cash equivalents approximates their carrying values due to their short-term maturity. Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds have been restricted by contract and 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 restricted by contract or other legal reasons and 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. The following table provides a reconciliation of cash, cash equivalents and restricted cash and investments reported within our consolidated statements of financial position that sum to the total of the same such amount shown in our consolidated statements of cash flows (dollars in thousands): December 31, December 31, Cash and cash equivalents $ 105,852 $ 100,555 Restricted cash and investments - current 573 480 Restricted cash and investments - noncurrent 4,257 4,101 Cash, cash equivalents and restricted cash and investments $ 110,682 $ 105,136 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 measured at fair value on a recurring basis with changes in fair value recognized in earnings. 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 cost and estimated fair value of the investments at December 31, 2022 were $0.6 million and $0.5 million, respectively. The cost and estimated fair value of the investments at December 31, 2021 were each $0.6 million. INVENTORIES: Coal inventories at our owned generating facilities are stated at LIFO (last‑in, first‑out) cost and were $3.7 million and $27.1 million as of December 31, 2022 and 2021, respectively. The remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost. In 2022, we realized lower coal fuel expense of $14.5 million as a result of a LIFO inventory liquidation at our generating facilities. 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 Utility Members through rates subject to approval by our Board and FERC. 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 and Yampa Project – Craig Generating Station Units 1 and 2. We also make advance payments to the operating agent of Springerville Unit 3. A right-of-use asset represents a lessee's right to control the use of the underlying asset for the lease term. Right-of-use assets are included in other deferred charges and presented net of accumulated amortization. See Note 11—Leases. Other deferred charges are as follows (dollars in thousands): December 31, December 31, Preliminary surveys and investigations $ 13,048 $ 12,366 Advances to operating agents of jointly owned facilities 7,324 4,422 Operating lease right-of-use assets 6,771 7,529 Other 13,302 10,822 Total other deferred charges $ 40,445 $ 35,139 DEBT ISSUANCE COSTS: We account for debt issuance costs as a direct deduction of the associated long-term debt carrying amount consistent with the accounting for debt discounts and premiums. Deferred debt issuance costs are amortized to interest expense using an effective interest method over the life of the respective debt. ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS : We account for current obligations associated with the future retirement of tangible long-lived assets and environmental reclamation 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 a market risk premium. As changes in estimates occur, such as mine plans, estimated costs, and timing of the performance of reclamation activities, we make revisions to the asset and obligation at the appropriate discount rate. Upon settlement of an asset retirement obligation, we apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability. Environmental reclamation costs are accrued based on management’s best estimate at the end of each period of the costs expected to be incurred. Such cost estimates may include ongoing care, maintenance and monitoring costs. Changes in reclamation estimates are reflected in earnings in the period an estimate is revised. Estimates of future expenditures for environmental reclamation obligations are not discounted. See Note 4—Asset Retirement and Environmental Reclamation Obligations. 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. We will pay $27.2 million for these easements from 2022 through the individual easement terms ending between 2036 and 2040. The present value of the remaining easement payments was $18.6 million and $19.3 million as of December 31, 2022 and December 31, 2021, respectively, which is recorded as other deferred credits and other liabilities. OATT deposits represent refundable transmission customer deposits related to interconnection and transmission requests from third parties. An OATT deposit is refundable should the interconnection or transmission request not move forward. Financial liabilities-reclamation represent financial obligations that we have for our share of the reclamation costs at jointly owned facilities in which we have undivided interests in. A contract liability represents an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration from the customer. We have received deposits from others and these deposits are reflected in contract liabilities (unearned revenue) until recognized in other operating revenues 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): December 31, December 31, Transmission easements $ 18,636 $ 19,339 OATT deposits 17,476 24,327 Financial liabilities - reclamation 12,429 13,122 Customer deposits 11,247 9,287 Contract liabilities (unearned revenue) - noncurrent 3,765 3,523 Operating lease liabilities - noncurrent 1,251 1,622 Other 3,570 7,099 Total other deferred credits and other liabilities $ 68,374 $ 78,319 PATRONAGE CAPITAL: Our net margins are treated as advances of capital from our Members and are allocated to our Utility Members on the basis of their electricity purchases from us and to our Non-Utility Members as provided in their respective membership agreements. Margins not yet distributed to Members constitute patronage capital. Patronage capital is held for the account of our Members and is distributed through patronage capital retirements when our Board deems it appropriate to do so, subject to debt instrument restrictions. ELECTRIC SALES REVENUE: Revenue from electric energy deliveries is recognized when delivered. See Note 10—Revenue. OTHER OPERATING REVENUE: Other operating revenue consists primarily of wheeling, transmission, and coal sales revenue. See Note 10—Revenue. 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, which requires that deferred tax assets and liabilities be determined based on the expected future income tax consequences of events that have been recognized in the consolidated financial statements. Under the normalization method, changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit). Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. 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. See Note 9—Income Taxes. INTERCHANGE POWER: We occasionally engage in interchanges, or non‑cash swapping, of energy. Based on the assumption that all energy interchanged will eventually be received or delivered in‑kind, interchanged energy is generally valued at the average cost of fuel to generate power. Additionally, portions of the energy interchanged are valued per contract with the utility involved in the interchange. When we are in a net energy advance position, the advanced energy balance is recorded as an asset. If we owe energy, the net energy balance owed to others is recorded as a liability. The net activity for the year is included in purchased power expense. The interchange liability balance of $4.7 million and $2.9 million at December 31, 2022 and 2021, respectively, is included in accounts payable. The net interchange activity recorded in purchased power expense was an expense of $1.5 million in 2022, an expense of $0.6 million in 2021 and a credit of $0.1 million in 2020. ACCOUNTING PRONOUNCEMENTS - ADOPTED: In October 2021, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance. The purpose of ASU 2021-10 is to increase the transparency of government assistance that is accounted for by applying a grant or contribution model by analogy, including disclosures of the types of assistance, the accounting for the assistance, and the effect of the assistance on an entity's financial statements. Prior to the issuance of ASU 2021-10, there was a lack of specific authoritative guidance in GAAP. This guidance excludes transactions in the scope of specific GAAP, such as tax incentives accounted for under Accounting Standards Codification ("ASC") 740, Income Taxes. ASU 2021-10 is effective for annual periods beginning after December 15, 2021, with early adoption and retrospective or prospective application permitted. We have evaluated the impact of adopting ASU 2021-10 and believe that the adoption of this update will not have a material impact on our consolidated financial statement disclosures.

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2022
Public Utilities, Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENTOur property, plant and equipment consists of electric plant and other plant. Both of these are discussed below and are included on our consolidated statements of financial position. ELECTRIC PLANT : At December 31, 2022, our investment in electric plant and the related annual rates of depreciation or amortization calculated using the straight‑line method are as follows (dollars in thousands): Annual Depreciation Rate Plant In Accumulated Net Book Generation plant 0.89 % to 6.27 % $ 3,048,918 $ (1,353,042) $ 1,695,876 Transmission plant 1.11 % to 2.09 % 1,956,378 (690,517) 1,265,861 General plant 1.46 % to 9.53 % 412,879 (257,761) 155,118 Other 2.75 % to 10.00 % 241,248 (91,043) 150,205 Electric plant in service (at cost) $ 5,659,423 $ (2,392,363) 3,267,060 Construction work in progress 81,555 Electric plant $ 3,348,615 At December 31, 2021, our investment in electric plant and the related annual rates of depreciation or amortization calculated using the straight‑line method are as follows (dollars in thousands): Annual Depreciation Rate Plant In Accumulated Net Book Generation plant 0.89 % to 6.27 % $ 3,049,233 $ (1,318,197) $ 1,731,036 Transmission plant 1.11 % to 2.09 % 1,879,148 (672,556) 1,206,592 General plant 1.46 % to 9.53 % 406,693 (251,567) 155,126 Other 2.75 % to 10.00 % 271,658 (124,877) 146,781 Electric plant in service (at cost) $ 5,606,732 $ (2,367,197) 3,239,535 Construction work in progress 107,636 Electric plant $ 3,347,171 At December 31, 2022, we had $56.5 million of commitments to complete construction projects, of which approximately $19.6, $19.6 and $17.3 million are expected to be incurred in 2023, 2024 and 2025, respectively. JOINTLY OWNED FACILITIES : Our share in each jointly owned facility is as follows as of December 31, 2022 (these electric plant in service, accumulated depreciation and construction work in progress amounts are included in the electric plant table above) (dollars in thousands): Tri-State Electric Accumulated Construction Yampa Project - Craig Generating Station Units 1 and 2 24.00 % $ 391,689 $ 261,366 $ 163 MBPP - Laramie River Station 28.50 % 530,692 341,882 2,621 Total $ 922,381 $ 603,248 $ 2,784 OTHER PLANT : Other plant consists of mine assets (discussed below) and non‑utility assets which consist of facilities not in service, land and irrigation equipment. We own 100 percent of Elk Ridge Mining and Reclamation, LLC (“Elk Ridge”), organized for the purpose of acquiring coal reserves and supplying coal to us. Elk Ridge is the owner of the Colowyo Mine, a surface coal mine near Craig, Colorado and the New Horizon Mine, near Nucla, Colorado. The New Horizon Mine is in post-reclamation monitoring and no longer produces coal. The expenses related to the Colowyo Mine coal used by us are included in fuel expense on our consolidated statements of operations. Other plant assets are as follows (dollars in thousands): December 31, December 31, Colowyo Mine assets $ 386,898 $ 376,868 New Horizon Mine assets 5,995 5,061 Accumulated depreciation and depletion (155,653) (133,951) Net mine assets 237,240 247,978 Non-utility assets 561,251 711,993 Accumulated depreciation (539,121) (689,136) Net non-utility assets 22,130 22,857 Net other plant $ 259,370 $ 270,835

ASSET RETIREMENT AND ENVIRONMEN

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies Disclosure [Abstract]
ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS	ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS Coal mines: We have asset retirement obligations for the final reclamation costs and environmental obligations for post-reclamation monitoring related to the Colowyo Mine and the New Horizon Mine. The New Horizon Mine is currently in post-reclamation monitoring. One pit at the Colowyo Mine began final reclamation in 2020 with the other remaining pits still being actively mined. Generation: We have asset retirement obligations related to equipment, dams, ponds, wells, ash landfill and underground storage tanks at the generating stations. Aggregate carrying amounts of asset retirement obligations and environmental reclamation obligations are as follows (dollars in thousands): 2022 2021 Obligations at beginning of period $ 90,281 $ 138,089 Liabilities incurred — 1,475 Liabilities settled (3,184) (4,934) Accretion expense 6,163 2,409 Change in estimate 93,747 (46,758) Total obligations at end of period $ 187,007 $ 90,281 Less current obligations at end of period (5,419) (7,003) Long-term obligations at end of period $ 181,588 $ 83,278 During 2022, we increased the asset retirement obligations related to two pits at the Colowyo Mine by $12.1 million due to revised cost estimates, with an offsetting decrease in the asset retirement obligation related to the third pit of $1.4 million due to reclamation costs paid and a gain on settlement. In the second quarter of 2022, we increased the environmental reclamation obligation at the New Horizon Mine by $44.9 million due to revised cost estimates. The New Horizon Mine environmental remediation liability is $67.3 million as of December 31, 2022. Of this amount, $36.8 million is recorded on a discounted basis, using a discount rate of 3.25 percent, with total estimated undiscounted future cash outflows of $57.9 million. Environmental obligation expense is included in other operating expenses on our consolidated statement of operations. Although the entire environmental obligation has been expensed, we may seek future rate recovery in upcoming rate filings with FERC. We continue to evaluate the New Horizon Mine and the Colowyo Mine post reclamation obligations and will make adjustments to these obligations as needed. Also, during 2022, we recorded an additional asset retirement obligation of $36.8 million related to a change in cost estimates for our pond, ash landfill and post-closure reclamation obligations at various generating stations. 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.

CONTRACT ASSETS AND CONTRACT LI

CONTRACT ASSETS AND CONTRACT LIABILITIES	12 Months Ended
	Dec. 31, 2022
Change in Contract with Customer, Asset and Liability [Abstract]
CONTRACT ASSETS AND CONTRACT LIABILITIES	CONTRACT ASSETS AND CONTRACT LIABILITIES Contract Assets A contract asset represents an entity’s right to consideration in exchange for goods or services that the entity has transferred to a customer when that right is conditioned on something other than the passage of time (for example, the entity’s future performance). We have no contract assets as of December 31, 2022 and December 31, 2021. Accounts Receivable We record accounts receivable for our unconditional rights to consideration arising from our performance under contracts with our Members and other parties. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period determined to be uncollectible. See Note 10—Revenue. Contract liabilities (unearned revenue) A contract liability represents an entity’s obligation to transfer goods or services to a customer, for which the entity has received consideration from the customer. We have received deposits from others, and these deposits are reflected in unearned revenue (included in other deferred credits and other liabilities on our consolidated statements of financial position) before revenue is recognized, resulting in contract liabilities. We recognized $0.8 million of this unearned revenue in 2022 in other operating revenues on our consolidated statements of operations. Our contract assets, accounts receivable and liabilities consist of the following (dollars in thousands): December 31, December 31, Accounts receivable - Members $ 103,246 $ 95,630 Other accounts receivable - trade: Non-member electric sales 17,213 5,684 Other 9,141 13,505 Total other accounts receivable - trade 26,354 19,189 Other accounts receivable - nontrade 6,082 2,382 Total other accounts receivable $ 32,436 $ 21,571 Contract liabilities (unearned revenue) $ 5,123 $ 5,372

LONG-TERM DEBT

LONG-TERM DEBT	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT We have $2.9 billion of long-term debt which consists of mortgage notes payable, pollution control revenue bonds and the Springerville certificates. 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 (“Master Indenture”) except for one unsecured note in the aggregate amount of $4.1 million as of December 31, 2022. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. All long-term debt contains certain restrictive financial covenants, including a DSR requirement on an annual basis and an ECR requirement of at least 18 percent at the end of each fiscal year. Other than long-term debt for the Springerville certificates that has a DSR requirement of at least 1.02 on an annual basis, all other long-term debt contains a DSR requirement of at least 1.10 on an annual basis. A DSR below 1.025 under the Master Indenture would require us to transfer all cash to a special fund managed by the trustee of the Master Indenture. We have a secured revolving credit facility with National Rural Utilities Cooperative Finance Corporation ("CFC"), as lead arranger and administrative agent, in the amount of $520 million (“2022 Revolving Credit Agreement”) that expires on April 25, 2027. We had no outstanding borrowings under the 2022 Revolving Credit Agreement as of December 31, 2022. As of December 31, 2022, we had $246 million in availability (including $226 million under the commercial paper back-up sublimit) under the 2022 Revolving Credit Agreement. On October 3, 2022, we remarketed the Moffat County, CO pollution control revenue bonds on their mandatory tender date into a new 5-year term rate mode at 2.9 percent ending October 1, 2027. On July 26, 2022, we completed a tender offer in an aggregate amount of $100 million of our First Mortgage Bonds, Series 2014E-1 (due 2024). We paid a total of $100.2 million in aggregate for the purchase of the bonds, including early tender payments. The transaction was funded using available cash and short-term borrowings. Long-term debt, including applicable terms and interest rates as of December 31, 2022, consists of the following (dollars in thousands): December 31, December 31, Mortgage notes payable 2.32% to 3.66% CFC, due through 2028 $ 85,855 $ 106,182 2.63% to 4.43% CoBank, ACB, due through 2042 174,985 204,163 First Mortgage Obligations, Series 2017A, Tranche 1, 3.34%, due through 2029 60,000 60,000 First Mortgage Obligations, Series 2017A, Tranche 2, 3.39%, due through 2029 60,000 60,000 First Mortgage Bonds, Series 2016A, 4.25% due 2046 228,783 250,000 First Mortgage Bonds, Series 2014E-1, 3.70% due 2024 128,002 244,714 First Mortgage Bonds, Series 2014E-2, 4.70% due 2044 250,000 250,000 First Mortgage Bonds, Series 2010A, 6.00% due 2040 499,805 500,000 First Mortgage Obligations, Series 2014B, Tranche 1, 3.90%, due through 2033 180,000 180,000 First Mortgage Obligations, Series 2014B, Tranche 2, 4.30%, due through 2039 20,000 20,000 First Mortgage Obligations, Series 2014B, Tranche 3, 4.45%, due through 2045 550,000 550,000 Variable rate CFC, as determined by CFC, due through 2026 — 324 Variable rate CFC, LIBOR-based term loan, due through 2049 152,220 152,220 Variable rate CoBank, ACB, LIBOR-based term loans, due through 2044 296,430 297,039 Pollution control revenue bonds Moffat County, CO, 2.90% term rate through October 2027, Series 2009, due 2036 46,800 46,800 Springerville certificates Series B, 7.14%, due through 2033 248,601 292,985 Total long-term debt $ 2,981,481 $ 3,214,427 Less debt issuance costs (21,481) (23,110) Less debt discounts (8,960) (9,398) Plus debt premiums 11,843 12,990 Total debt adjusted for discounts, premiums and debt issuance costs $ 2,962,883 $ 3,194,909 Less current maturities (92,920) (93,039) Long-term debt $ 2,869,963 $ 3,101,870 Annual maturities of total long-term debt adjusted for debt issuance costs, discounts and premiums at December 31, 2022 are as follows (dollars in thousands): 2023 $ 92,920 2024 (1) 223,835 2025 88,819 2026 90,440 2027 92,323 Thereafter 2,374,546 $ 2,962,883 ___________________________________________ (1) Includes $128 million bullet maturity for the First Mortgage Bonds, Series 2014 E-1.

SHORT-TERM BORROWINGS

SHORT-TERM BORROWINGS	12 Months Ended
	Dec. 31, 2022
Short-Term Debt [Abstract]
SHORT-TERM BORROWINGS	SHORT-TERM BORROWINGSWe have a commercial paper program under which we issue unsecured commercial paper in aggregate amounts not exceeding the commercial paper back-up sublimit under our 2022 Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our 2022 Revolving Credit Agreement. The commercial paper issuances are used to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances vary but may not exceed 397 days from the date of issue. The commercial paper notes are classified as current and are included in current liabilities as short-term borrowings on our consolidated statements of financial position. Commercial paper consisted of the following (dollars in thousands): 2022 2021 Commercial paper outstanding, net of discounts $ 274,102 $ 49,997 Weighted average interest rate 4.61 % 0.20 % At December 31, 2022, $226 million of the commercial paper back-up sublimit remained available under the 2022 Revolving Credit Agreement. See Note 6—Long-Term Debt.

FAIR VALUE

FAIR VALUE	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
FAIR VALUE	FAIR VALUE Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal market, or in the most advantageous market when no principal market exists. The fair value measurements accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows: Level 1 inputs are based upon quoted prices for identical instruments traded in active (exchange-traded) markets. Valuations are obtained from readily available pricing sources for market transactions (observable market data) involving identical assets or liabilities. Level 2 inputs are based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques (such as option pricing models and discounted cash flow models), for which all significant assumptions are observable in the market. Level 3 inputs consist of unobservable market data which is typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Executive Benefit Restoration Plan Trust In December 2020, we established an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary. The trust consists of investments in equity and debt securities and are measured at fair value on a recurring basis. Changes in the fair value of investments in equity securities are recognized in earnings, and changes in fair value of investments in debt securities classified as available-for-sale are recognized in other comprehensive income until realized. 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 cost and fair values of our investments in the Executive Benefit Restoration Plan trust are as follows (dollars in thousands): December 31, 2022 December 31, 2021 Cost Estimated Cost Estimated Marketable securities $ 10,604 $ 9,808 $ 8,850 $ 8,640 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 measured at fair value on a recurring basis with changes in fair value recognized in earnings. 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 amortized cost and fair values of our marketable securities are as follows (dollars in thousands): December 31, 2022 December 31, 2021 Cost Estimated Cost Estimated Marketable securities $ 558 $ 489 $ 597 $ 598 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 $101.8 million and $95.3 million as of December 31, 2022 and 2021, 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): December 31, 2022 December 31, 2021 Principal Estimated Principal Estimated Total long-term debt $ 2,981,481 $ 2,725,606 $ 3,214,427 $ 3,759,991

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES We had no current income tax expenses or benefits in 2022 or 2021 after regulatory treatment. We had a deferred income tax benefit of $0.2 million in 2022 and deferred income tax expense of $0.3 million in 2021. We utilize the liability method of accounting for income taxes, which requires that deferred tax assets and liabilities be determined based on the expected future income tax consequences of events that have been recognized in the consolidated financial statements. As a FERC jurisdictional entity, we recognize deferred income tax expense under the normalization method whereby changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit). Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. 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. Components of our net deferred tax liability are as follows (dollars in thousands): December 31, December 31, Deferred tax assets Net operating loss carryforwards $ 165,636 $ 144,602 Operating lease liabilities 105,039 114,237 Deferred revenues and membership withdrawal 16,028 38,784 Safe harbor lease receivables 8,939 8,135 Other 43,795 30,578 339,437 336,336 Less valuation allowance — — 339,437 336,336 Deferred tax liabilities Basis differences- property, plant and equipment and other 166,568 159,696 Operating lease right-of-use assets 125,939 130,111 Capital credits from other associations 34,236 31,622 Deferred debt prepayment transaction costs 27,381 29,434 Other 4,588 4,460 358,712 355,323 Net deferred tax liability $ (19,275) $ (18,987) Net deferred tax liabilities increased by $0.3 million in 2022 which is deferred and reflected as an increase in the regulatory asset established for deferred income tax expense. The accounting for regulatory assets is discussed further in Note 2—Accounting for Rate Regulation. The regulatory asset balance associated with deferred income tax expense under the liability method is $19.3 million and $18.7 million at December 31, 2022 and 2021, respectively. The reconciliation between pretax GAAP income and deferred income tax expense (benefit) is as follows (dollars in thousands): 2022 2021 2020 Pretax GAAP income at Federal statutory rate $ — $ 5,435 $ 5,271 Pretax GAAP income at State statutory rate, net of federal benefit — 725 703 Patronage exclusion — (6,159) (5,974) Asset retirement and environmental reclamation obligations 16,655 10,917 (14,230) Deferred revenues and membership withdrawal (22,759) 18,673 (29,519) Operating liabilities, net of right-of-use assets (1) (4,919) 1,165 5,277 Valuation Allowance — — (30,468) Net operating loss carryforward 21,034 (27,539) 367 Other items, net (9,445) (2,531) 17,543 Impairment — — 20,554 Regulatory treatment of deferred taxes (815) (391) 29,942 Total deferred income tax expense (benefit) $ (249) $ 295 $ (534) We had an estimated consolidated tax loss of $93.1 million for 2022. At December 31, 2022, we have an estimated consolidated federal net operating loss carryforward of $696.0 million of which pre-2018 tax years in the amount of $444.5 million are subject to expiration periods between 2031 and 2037 and $251.5 million have no expiration. We have $438.2 million of state net operating loss carryforwards, of which $405.1 million is subject to expiration periods between 2031 and 2041 and $33.1 million have no expiration. We did not establish a valuation allowance because it is more likely than not that the benefit from the federal and state deferred tax assets will be realized in the future. We file a U.S. federal consolidated income tax return and income tax returns in state jurisdictions where required. The statute of limitations remains open for federal and state returns for the years 2018 forward. We do not have any liabilities recorded for uncertain tax positions. On August 16, 2022, the Inflation Reduction Act of 2022 (the "IRA") was enacted into law. The IRA imposes a 15 percent minimum tax based on consolidated GAAP profits of $1 billion or more. As a cooperative operating primarily for the benefit of its Members, we do not expect to be impacted by the 15 percent minimum tax because we do not expect to realize GAAP profits meeting or exceeding the required threshold. The IRA imposes a 1 percent excise tax on the fair market value of stock repurchases made by covered corporations after December 31, 2022. Since we do not issue stock, we are not impacted by the stock buyback excise tax. In addition, the IRA enacted many provisions intended to mitigate climate change by providing various sources of funding and tax credit incentives for investments designed to reduce greenhouse gas emissions. These provisions do not impact our current consolidated financial statements, but could affect future financial statements due to the impact of such investments. These provisions are subject to regulations to be released by the Department of the Treasury over time. We are evaluating these provisions and will continue to monitor developments and evaluate opportunities to utilize these incentives in the future.

REVENUE

REVENUE	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE Revenue from Contracts with Customers Our revenues are derived primarily from the sale of wholesale electric service to our Utility Members pursuant to long-term wholesale electric service contracts. Our contracts with our forty-two Utility Members extend through 2050. Member electric sales Revenues from wholesale electric power sales to our Utility Members are primarily from our Class A rate schedule filed with FERC. Our Class A rate schedule for electric power sales to our Utility Members consist of three billing components: an energy rate and two demand rates. Our Class A rate schedule is variable and is approved by our Board and FERC. Energy and demand have the same pattern of transfer to our Utility Members and are both measurements of the electric power provided to our Utility Members. Therefore, the provision of electric power to our Utility Members is one performance obligation. Prior to our Utility Members’ requirement for electric power, we do not have a contractual right to consideration as we are not obligated to provide electric power until the Utility Member requires each incremental unit of electric power. We transfer control of the electric power to our Utility Members over time and our Utility Members simultaneously receive and consume the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method, meter readings are taken at the end of each month for billing purposes, energy and demand are determined after the meter readings and Utility Members are invoiced based on the meter reading. Payments from our Utility Members are received in accordance with the wholesale electric service contracts’ terms, which is less than 30 days from the invoice date. Utility Member electric sales revenue is recorded as Utility Member electric sales on our consolidated statements of operations and accounts receivable – Members on our consolidated statements of financial position. Revenue from one Utility Member, United Power, Inc. ("United Power"), was $223.6 million, or 18.4 percent, of our Utility Member revenue and 14.7 percent of our total operating revenues in 2022. No other Utility Member exceeded 10 percent of our Utility Member revenue or our total operating revenues in 2022. In addition to our Utility Member electric sales, we have non-member electric sales and other operating revenue which consist of several revenue streams. The following revenue is reflected on our consolidated statements of operations as follows (dollars in thousands): 2022 2021 2020 Non-member electric sales: Long-term contracts $ 56,570 $ 44,383 $ 46,172 Short-term contracts 106,785 70,525 44,210 Rate stabilization 95,613 78,457 12,136 Provision for rate refunds (51) (10,196) — Coal Sales 7,021 4,951 7,326 Other 54,399 51,390 46,219 Total non-member electric sales and other operating revenue $ 320,337 $ 239,510 $ 156,063 Non-member electric sales Revenues from wholesale electric power sales to non-members are primarily from long-term contracts and short-term market sales. Prior to our customers’ demand for energy, we do not have a contractual right to consideration as we are not obligated to provide energy until the customer demands each incremental unit of energy. We transfer control of the energy to our customer over time and our customer simultaneously receives and consumes the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method. Payments are received in accordance with the contract terms, which is less than 30 days after the invoice is received by the customer. Rate Stabilization Revenue Rate stabilization represents recognition of income from withdrawal of former Utility Members from membership in us or non-member electric sales revenue that was previously deferred in accordance with accounting requirements related to regulated operations. We recognized $95.6 million of deferred membership withdrawal income for the year ended December 31, 2022, and $78.5 million and $12.1 million of deferred non-member electric sales revenue for the years ended December 31, 2021 and December 31, 2020, respectively, as directed by our Board. See Note 2—Accounting for Rate Regulation. Provision for Rate Refunds Provision for rate refunds represents refund of certain revenues based on a FERC order. Based upon a FERC order requiring us to refund certain revenue from power sales in the Western Area Colorado Missouri (“WACM”) balancing authority area, in the third quarter of 2022, we reserved $2.0 million as a preliminary estimate of the amount to be refunded. As required by FERC, in December 2022, we distributed refunds of $2.7 million. See Note 15 - Commitments and Contingencies - Legal. Such an amount was offset by the recognition of a favorable adjustment during the second quarter of 2022 of approximately $2.9 million for the amount in excess of an accrual that was previously recorded related to certain energy sales to third parties in excess of the soft-cap for short-term, spot market sales of $1,000 per megawatt hour established by the Western Electricity Coordinating Council. See Note 15 - Commitments and Contingencies- Legal. Other operating revenue Other operating revenue consists primarily of wheeling, transmission and coal sales revenue. Other operating revenue also includes revenue we receive from our Non-Utility Members. Wheeling revenue is received when we charge other energy companies for transmitting electricity over our transmission lines (payments are received in accordance with the contract terms which is within 20 days of the date the invoice is received). Transmission revenue is from Southwest Power Pool’s scheduling of transmission across our transmission assets in the Eastern Interconnection because of our membership in it (Southwest Power Pool collects the revenue from the customer and pays us for the scheduling, system control, dispatch transmission service, and the annual transmission revenue requirement). Each of these services or goods are provided over time and progress toward completion of our performance obligations are measured using the output method. Coal sales revenue results from the sale of coal from the Colowyo Mine and other locations to third parties. We have an obligation to deliver coal and progress of completion toward our performance obligation is measured using the output method. Our performance obligation is completed as coal is delivered.

LEASES

LEASES	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
LEASES	LEASES Leasing Arrangements as Lessee We have lease agreements as lessee for the right to use various facilities and operational assets. Rent expense for all short-term and long-term operating leases was $2.7 million in 2022 and $3.5 million in 2021. Rent expense is included in operating expenses on our consolidated statements of operations. As of December 31, 2022, there were no arrangements accounted for as finance leases. Our consolidated statements of financial position include the following lease components (dollars in thousands): December 31, December 31, Operating leases Operating lease right-of-use assets $ 8,784 $ 9,081 Less: Accumulated amortization (2,013) (1,552) Net operating lease right-of-use assets $ 6,771 $ 7,529 Operating lease liabilities – current $ (441) $ (491) Operating lease liabilities – noncurrent (1,251) (1,622) Total operating lease liabilities $ (1,692) $ (2,113) Operating leases Weighted average remaining lease term (years) 7.6 7.6 Weighted average discount rate 3.87 % 3.79 % Future expected minimum lease commitments under operating leases are as follows (dollars in thousands): Year 1 $ 386 Year 2 342 Year 3 151 Year 4 431 Year 5 94 Thereafter 549 Total lease payments $ 1,953 Less imputed interest (261) Total $ 1,692 Leasing Arrangements as Lessor We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $7.1 million in 2022 and $7.3 million in 2021 are included in other operating revenue on our consolidated statements of operations. The lease arrangement with the Springerville Partnership is not reflected in our lease right right-of-use asset or liability balances as the associated revenues and expenses are eliminated in consolidation. See Note 13—Variable Interest Entities. However, as the noncontrolling interest associated with this lease arrangement generates book-tax differences, a deferred tax asset and liability have been recorded. See Note 9—Income Taxes.
LEASES	LEASES Leasing Arrangements as Lessee We have lease agreements as lessee for the right to use various facilities and operational assets. Rent expense for all short-term and long-term operating leases was $2.7 million in 2022 and $3.5 million in 2021. Rent expense is included in operating expenses on our consolidated statements of operations. As of December 31, 2022, there were no arrangements accounted for as finance leases. Our consolidated statements of financial position include the following lease components (dollars in thousands): December 31, December 31, Operating leases Operating lease right-of-use assets $ 8,784 $ 9,081 Less: Accumulated amortization (2,013) (1,552) Net operating lease right-of-use assets $ 6,771 $ 7,529 Operating lease liabilities – current $ (441) $ (491) Operating lease liabilities – noncurrent (1,251) (1,622) Total operating lease liabilities $ (1,692) $ (2,113) Operating leases Weighted average remaining lease term (years) 7.6 7.6 Weighted average discount rate 3.87 % 3.79 % Future expected minimum lease commitments under operating leases are as follows (dollars in thousands): Year 1 $ 386 Year 2 342 Year 3 151 Year 4 431 Year 5 94 Thereafter 549 Total lease payments $ 1,953 Less imputed interest (261) Total $ 1,692 Leasing Arrangements as Lessor We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $7.1 million in 2022 and $7.3 million in 2021 are included in other operating revenue on our consolidated statements of operations. The lease arrangement with the Springerville Partnership is not reflected in our lease right right-of-use asset or liability balances as the associated revenues and expenses are eliminated in consolidation. See Note 13—Variable Interest Entities. However, as the noncontrolling interest associated with this lease arrangement generates book-tax differences, a deferred tax asset and liability have been recorded. See Note 9—Income Taxes.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	12 Months Ended
	Dec. 31, 2022
Retirement Benefits [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS DEFINED BENEFIT PLAN: Substantially all of our 1,105 employees participate in the National Rural Electric Cooperative Association Retirement Security Plan (“RS Plan”) except for the 191 employees of Colowyo Coal and any non-bargaining employees hired May 1, 2021 or later and bargaining employees hired July 1, 2021 or later. The RS Plan is a defined benefit pension plan qualified under Section 401(a) and tax‑exempt under Section 501(a) of the Internal Revenue Code. It is considered a multiemployer plan under the accounting standards for compensation ‑ retirement benefits. The plan sponsor’s Employer Identification Number is 53‑116145 and the Plan Number is 333. A unique characteristic of a multiemployer plan compared to a single employer plan is that all plan assets are available to pay benefits to any plan participant. Separate asset accounts are not maintained for participating employers. This means that assets contributed by one employer may be used to provide benefits to employees of other participating employers. Our contributions to the RS Plan in each of the years 2022, 2021 and 2020 represented less than 5 percent of the total contributions made each year to the plan by all participating employers. We made contributions to the RS Plan of $25.2, $26.7 and $27.5 million in 2022, 2021 and 2020, respectively. In December 2012, the National Rural Electric Cooperative Association (“NRECA”) approved an option to allow participating cooperatives in the RS Plan to make a contribution prepayment and reduce future required contributions. The prepayment amount is a cooperative’s share, as of January 1, 2013, of future contributions required to fund the RS Plan’s unfunded value of benefits earned to date using RS Plan actuarial valuation assumptions. The prepayment amount is equal to approximately 2.5 times a cooperative’s annual RS Plan required contribution as of January 1, 2013. After making the prepayment, the annual contribution was reduced by approximately 25 percent, retroactive to January 1, 2013. The reduced annual contribution is expected to continue for approximately 15 years. However, changes in interest rates, asset returns, other plan experiences different from expected, plan assumption changes and other factors may have an impact on future contributions and the 15-year period. In May 2013, we elected to make a contribution prepayment of $71.2 million to the RS Plan. This contribution prepayment was determined to be a long‑term prepayment and therefore recorded in deferred charges and amortized beginning January 1, 2013 over the 13‑year period calculated by subtracting the average age of our workforce from our normal retirement age under the RS Plan. Our contributions to the RS Plan include contributions for substantially all of the 215 bargaining unit employees that are made in accordance with collective bargaining agreements. We ceased to add new bargaining employees hired July 1, 2021 or later and non-bargaining employees hired May 1, 2021 or later to the RS Plan. For the RS Plan, a “zone status” determination is not required, and therefore not determined, under the Pension Protection Act (“Act”) of 2006. In addition, the accumulated benefit obligations and plan assets are not determined or allocated separately by individual employer. In total, the RS Plan was over 80 percent funded at both January 1, 2022 and January 1, 2021, based on the Act funding target and the Act actuarial value of assets on those dates. Because the provisions of the Act do not apply to the RS Plan, funding improvement plans and surcharges are not applicable. Future contribution requirements are determined each year as part of the actuarial valuation of the plan and may change as a result of plan experience. We participate in the NRECA Pension Restoration Plan and the NRECA Executive Benefit Restoration Plan, both of which are intended to provide a supplemental benefit to the defined benefit plan for an eligible group of highly compensated employees. Eligible employees include the Chief Executive Officer and any other employees that become eligible. All our executive employees with a hire date prior to May 1, 2021 participate in one of the following pension restoration plans: the NRECA Pension Restoration Plan or the NRECA Executive Benefit Restoration Plan. Eligibility is determined annually and is based on January 1 base salary that exceeds the limits of the defined benefit plan. Employees hired May 1, 2021 or later are not eligible for either plan. The NRECA Executive Benefit Restoration Plan obligations are determined annually (during the first quarter of the subsequent year) by an NRECA actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): 2022 2021 Executive benefit restoration obligation at beginning of period $ 9,852 $ 7,379 Service cost 468 440 Interest cost 300 205 Plan amendments - prior service cost 308 1,050 Curtailment (292) — Benefit payments (110) — Actuarial (gain) loss (2,041) 778 Executive benefit restoration obligation at end of period $ 8,485 $ 9,852 Fair value of plan assets at beginning of year $ 8,640 $ 6,955 Employer contributions 1,734 1,762 Benefits paid (109) — Actual return on plan assets (457) (77) Fair value of plan assets at end of year $ 9,808 $ 8,640 Net (asset) liability recognized $ (1,323) $ 1,212 The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations. In December 2020, we established an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary. In accordance with the accounting standard related to defined benefit pension plans, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other income on our consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the executive benefit restoration obligation. The net unrecognized actuarial gains and losses related to the executive benefit restoration obligations are included in accumulated other comprehensive income as follows (dollars in thousands): 2022 2021 Accumulated other comprehensive loss at beginning of period $ (4,932) $ (4,873) Plan amendments - prior service cost (308) (1,050) Amortization of prior service cost into other income 1,156 1,113 Amortization of actuarial loss 426 515 Curtailment and settlement (187) 141 Unrecognized actuarial gain (loss) 1,740 (778) Accumulated other comprehensive loss at end of period $ (2,105) $ (4,932) DEFINED CONTRIBUTION PLANS: We offer one 401(k) plan to all of our employees. We contribute 1 percent of employee base salary for all non-bargaining employees hired prior to May 1, 2021. All non-bargaining employees hired May 1, 2021 or later and all bargaining employees hired July 1, 2021 or later are eligible for a maximum employer contribution of 10 percent which includes an employer base contribution and an employer match up to IRS allowed annual maximum. We offer one 401(k) plan to all employees of Colowyo Coal at the Colowyo Mine. We contribute 7 percent of employee salary and match up to an additional 5 percent of employee contributions for employees hired prior to May 1, 2021 and provide a maximum employer contribution of 10 percent which includes an employer base contribution and an employer match for employees hired May 1, 2021 or later. All employees are eligible to contribute up to 75 percent of their salary on a pre-tax basis. Under all plans, total 401(k) contributions are not to exceed annual IRS limitations which are set annually. Employees who have attained age 50 in a calendar year are eligible for the catch-up contribution with maximum contribution limits determined annually by the IRS. We made contributions to the plan of $3.9 million, $3.3 million, and $3.5 million in 2022, 2021, and 2020, respectively. Effective January 1, 2022 we adopted a 409(a) non-qualified plan. Senior managers, vice presidents and executive officers hired prior to May 1, 2021 are eligible to participate and contribute to the plan, but are not eligible for any employer contribution. Executive officers hired on or after May 1, 2021 will be eligible to participate and contribute to the plan, and are eligible for the employer contribution. The employer contribution is effective once the eligible executive has reached the maximum allowed contribution and employer contribution and match in our base 401(k) plan and includes a maximum employer contribution of 10 percent which includes an employer base contribution and an employer match. We made minimal contributions to the plan in 2022. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS: We sponsor three medical plans for all non‑bargaining unit employees under the age of 65. Two of the plans provide postretirement medical benefits to full‑time non‑bargaining unit employees and retirees who receive benefits under those plans, who have attained age 55, and who elect to participate. All three of these non‑bargaining unit medical plans offer postemployment medical benefits to employees on long‑term disability. The plans were unfunded at December 31, 2022, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost‑sharing features such as deductibles. As of June 30, 2021, the plans ceased to provide postretirement medical benefits for employees who retire after June 30, 2021. The postretirement medical benefit and post-employment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): 2022 2021 Postretirement medical benefit obligation at beginning of period $ 2,809 $ 9,985 Interest cost 47 36 Benefit payments (net of contributions by participants) (732) (730) Actuarial gain (32) (784) Plan amendments — (5,698) Postretirement medical benefit obligation at end of period $ 2,092 $ 2,809 Postemployment medical benefit obligation at end of period 97 419 Total postretirement and postemployment medical obligations at end of period $ 2,189 $ 3,228 The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations. In accordance with the accounting standard related to postretirement benefits other than pensions, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other comprehensive income on our consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess amount is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the postretirement medical benefit obligation. The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligation are included in accumulated other comprehensive income as follows (dollars in thousands): 2022 2021 Amounts included in accumulated other comprehensive income at beginning of period $ 3,580 $ (841) Amortization of prior service credit into other income (1,636) (2,139) Amortization of actuarial loss into other income 102 78 Actuarial gain 32 784 Plan amendments — 5,698 Amounts included in accumulated other comprehensive income at end of period $ 2,078 $ 3,580 The assumptions used in the 2022 actuarial study performed for our postretirement medical benefit obligation were as follows: Weighted-average discount rate 1.82 % Initial health care cost trend (2018) 7.00 % Ultimate health care cost trend 4.50 % Year that the rate reached the ultimate health care cost trend rate 2027 Expected return on plan assets (unfunded) N/A Average remaining service lives of active plan participants (years) 2.99 The following are the expected future benefits to be paid (net of contributions by participants) related to the postretirement medical benefit obligation during the next ten years (dollars in thousands): 2023 $ 576,432 2024 482,090 2025 379,064 2026 298,176 2027 200,190 2028 through 2032 362,795 $ 2,298,747

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2022
Variable Interest Entity or Potential VIE, Information Unavailability, Disclosures [Abstract]
VARIABLE INTEREST ENTITIES	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. 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. Assets and liabilities of the Springerville Partnership that are included in our consolidated statements of financial position are as follows (dollars in thousands): December 31, December 31, Net electric plant $ 721,997 $ 740,135 Noncontrolling interest 126,180 119,101 Long-term debt 254,876 300,220 Accrued interest 7,400 8,721 Our consolidated statements of operations include the following Springerville Partnership expenses (dollars in thousands): Twelve Months Ended December 31, 2022 December 31, 2021 December 31, 2020 Depreciation, amortization and depletion $ 18,138 $ 18,138 $ 18,138 Interest 17,064 20,038 22,798 The revenue and lease expense 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. 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.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES SALES: We have a resource-contingent power sales contract with Salt River Project Agricultural Improvement and Power District of 100 megawatts through August 31, 2036. COAL PURCHASE REQUIREMENTS: We are committed to purchase coal for our generating plants under contracts that expire between 2024 and 2041. These contracts require us to purchase a minimum quantity of coal at prices subject to escalation reflecting cost increases incurred by the suppliers due to market conditions. The coal purchase projection includes estimated future prices. As of December 31, 2022, the minimum coal to be purchased under these contracts is as follows (dollars in thousands): 2023 $ 30,627 2024 23,217 2025 10,113 2026 6,882 2027 6,825 Thereafter 88,247 $ 165,911 Our coal purchases were $124.0 million in 2022, $97.9 million in 2021, and $101.2 million in 2020. ELECTRIC POWER PURCHASE AGREEMENTS: Our largest long‑term electric power purchase contracts are with Basin and Western Area Power Administration (“WAPA”). We purchase from Basin power pursuant to two contracts: one relating to all the power which we require to serve our Utility Members’ load in the Eastern Interconnection and one relating to fixed scheduled quantities of electric power in the Western Interconnection. Both contracts with Basin continue through December 31, 2050 and are subject to automatic extension thereafter. We purchase renewable power under long-term contracts, including hydroelectric power from WAPA and from specified renewable generating facilities, including wind, solar and small hydro. We purchase from WAPA power pursuant to two contracts relating to WAPA’s Loveland Area Projects (one which terminates September 30, 2024 and one which commences delivery on October 1, 2024 and terminates September 30, 2054) and three contracts relating to WAPA’s Salt Lake City Area Integrated Projects (two which terminate September 30, 2024 and one which commences delivery on October 1, 2024 and terminates September 30, 2057). As of December 31, 2022, we have entered into renewable power purchase contracts to purchase the entire output from specified renewable facilities totaling approximately 1,521 MWs, including 674 MWs of wind‑based power purchase agreements and 820 MWs of solar‑based power purchase agreements that expire between 2030 and 2042. Costs under the above electric power purchase agreements were as follows (dollars in thousands): 2022 2021 2020 Basin $ 148,146 $ 146,532 $ 152,461 WAPA 67,791 70,107 72,491 Renewables, other than WAPA 85,601 71,565 69,255 ENVIRONMENTAL: As with most electric utilities, we are subject to extensive federal, state and local environmental requirements that regulate, among other things, air emissions, water discharges and the use and management of hazardous and solid wastes. Compliance with these requirements requires significant expenditures for the installation, maintenance and operation of pollution control equipment, monitoring systems and other equipment or facilities. Our operations are subject to environmental laws and regulations that are complex, change frequently and have historically become more stringent and numerous over time. Federal, state, and local standards and procedures that regulate environmental impact of our operations are subject to change. Consequently, there is no assurance that environmental regulations applicable to our facilities will not become materially more stringent, or that we will always be able to obtain all required operating permits. More stringent standards may require us to modify the design or operation of existing facilities or purchase emission allowances. An inability to comply with environmental standards could result in reduced operating levels or the complete shutdown of our facilities that are not in compliance, including the shutting down of additional generating facilities or the shutting down of individual coal-fired generating facilities earlier than scheduled. The cost impact of the implementation of regulation on existing legislation and future legislation or regulation will depend upon the specific requirements thereof and cannot be determined at this time, but it could have a significant effect on our financial condition, results of operations and cash flow. From time to time, we are alleged to be in violation or in default under orders, statutes, rules, regulations, permits or compliance plans relating to the environment. Additionally, we may need to deal with notices of violation, enforcement proceedings or challenges to construction or operating permits. In addition, we may be involved in legal proceedings arising in the ordinary course of business. However, we believe our facilities are currently in compliance with such regulatory and operating permit requirements. LEGAL: FERC Tariff and Declaratory Order. Because of increased pressure by states to regulate our rates and charges with impact in other states setting up untenable conflict, we sought consistent federal jurisdiction by FERC. This was accomplished with the addition of non-cooperative members in 2019, specifically MIECO, Inc., as a Non-Utility Member on September 3, 2019. On the same date, we became FERC jurisdictional for our Utility Member rates, transmission service, and our market-based rates. We filed our tariff for wholesale electric service and transmission at FERC in December 2019. In addition, on December 23, 2019, we filed our Petition for Declaratory Order ("Jurisdictional PDO") with FERC, EL20-16-000, asking FERC to confirm our jurisdiction under the Federal Power Act ("FPA") and that FERC’s jurisdiction preempts the jurisdiction of the Colorado Public Utilities Commission ("COPUC") to address any rate related issues, including the complaints filed by United Power and La Plata Electric Association ("LPEA") with the COPUC. On March 20, 2020, FERC issued orders regarding our Jurisdictional PDO and our tariff filings. FERC’s orders generally accepted our tariff filings and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactive to September 3, 2019. However, FERC specifically provided that no refunds are due on our Utility Member rates and our transmission service rates prior to March 26, 2020. FERC also did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered FPA section 206 proceedings to determine the justness and reasonableness of our rates and wholesale electric service contracts. On August 2, 2021, FERC approved our settlement agreement related to our Utility Member stated rate, as further discussed belo w. On March 7, 2022, FERC approved our settlement agreement related to our transmission service rates. On August 28, 2020, FERC issued an order (“August 28 Order”) on rehearing related to our Jurisdictional PDO which modified its March 20, 2020 decision on our Jurisdictional PDO by finding exclusive jurisdiction over our contract termination payments related to our Utility Members and preempting the jurisdiction of the COPUC as of September 3, 2019. On December 16, 2020, United Power filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit Court of Appeals") related to FERC’s August 28 Order, 20-1256. On September 16, 2022, the D.C. Circuit Court of Appeals denied United Power's petition related to FERC’s August 28 Order and affirmed FERC's exclusive jurisdiction over our contract termination payments. Petitions for review related to our tariff filings, including our Utility Member rates, have been filed with the D.C. Circuit Court of Appeals by other parties. On December 29, 2022, an order was issued by the court to hold all the cases before the D.C. Circuit Court of Appeals in abeyance, directing the parties to file motions to govern future proceedings by March 29, 2023. On August 2, 2021, FERC approved our settlement agreement related to our Utility Member stated rate, including our wholesale electric service contracts and certain of our Board policies filed with FERC. With the exception of four reserved issues contingent on United Power being a settling party, the settlement resolved all issues set for hearing and settlement procedures related to our Utility Member rates. The settlement provides for us to implement a two-stage, graduated reduction in the charges making up our Class A rate schedule of two percent starting from March 1, 2021 until the first anniversary and four percent reduction (additional two percent reduction from then current rates) thereafter until the date a new Class A wholesale rate schedule is approved by FERC and goes into effect. The settlement rates will remain in effect at least through May 31, 2023 and during such time period, we and the settlement parties have agreed, with limited exceptions, to a moratorium on any filings related to our Class A rate schedule, including any rate increases to our Class A rate schedule. We have also agreed to file a new Class A rate schedule after May 31, 2023 and prior to September 1, 2023. During the moratorium, we established a rate design committee to oversee the development of the new rate. Three of the reserved issues are related to the transmission component of our rates and the fourth relates to our community solar program. Additionally, with the exception of one reserved issue regarding transmission demand charges applicable to certain electric storage resources, each of the reserved issues will have prospective effect only, with the intent that any FERC rulings would be implemented in future rate filings. A hearing on the four reserved issues occurred in March 2022 before an administrative law judge at FERC and an initial decision was issued by an administrative law judge on May 26, 2022. On the three reserved issues that will have a prospective effect only, the initial decision provides that we must also unbundle in our bills to our Utility Members our transmission costs, including ancillary services and other costs, and, in our future rate filings, we must directly assign to our Utility Members the costs of radial facilities that do not meet FERC's standards for being included in our rolled-in transmission demand rate. In addition, the initial decision provided that our Board policy for our community solar program was unduly discriminatory because it advantaged small Utility Members to the disadvantage of larger Utility Members. With regard to the reserved issue regarding transmission demand charges applicable to certain electric storage resources, the initial decision agreed with our Board policy of billing Utility Members for the transmission demand costs that includes all of a Utility Member's transmission demand, including such Utility Member's electric storage resource. On June 26, 2022, we, United Power, and certain other Utility Members filed exceptions to the initial decision. Because exceptions were taken to the initial decision, the initial decision and exceptions are now pending before the Commissioners of FERC for a decision on the four reserved issues. It is not possible to predict the outcome of the four reserved issues related to our member rates docket. In addition, we cannot predict the outcome of any petitions for review filed with the D.C. Circuit Court of Appeals. LPEA and United Power COPUC Complaints . Pursuant to our Bylaws, a Utility Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no Utility Member shall be permitted to withdraw until it has met all its contractual obligations to us, including all obligations under its wholesale electric service contract with us. On November 5, 2019, LPEA filed a formal complaint with the COPUC alleging that we hindered LPEA’s ability to seek withdrawal from us. On November 6, 2019, United Power filed a formal complaint with the COPUC, alleging that we hindered United Power’s ability to explore its power supply options by either withdrawing from us or continuing as a Utility Member under a partial requirements contract. On November 20, 2019, the COPUC consolidated the two proceedings into one, 19F-0621E. On October 22, 2020, the COPUC determined that COPUC’s jurisdiction over United Power and LPEA’s complaints was preempted by FERC and dismissed both complaints without prejudice. On January 27, 2021, United Power filed a Writ for Certiorari or Judicial Review, an appeal, in the Denver County District Court, 2021CV30325, of the COPUC's decision to dismiss United Power's complaint. On February 17, 2021, the Denver County District Court granted our unopposed motion to intervene as a defendant in United Power’s appeal of the COPUC’s dismissal. On November 3, 2022, United Power filed a motion to dismiss the appeal with prejudice that was granted by the court on November 23, 2022. United Power's Adams District Court Complaint. On May 4, 2020, United Power filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court, 2020CV30649, against us and our three Non-Utility Members. On July 2, 2021, the court granted United Power's motion to amend its May 2020 complaint to amend its claims as to our three Non-Utility Members and to add a claim that our addition of the Non-Utility Members violated Colorado law. On July 30, 2021, we filed a partial motion to dismiss a majority of United Power's claims. On July 30, 2021, the three Non-Utility Members filed a joint motion to dismiss all claims by United Power against the Non-Utility Members. On March 23, 2022, the court issued an order regarding our and the Non-Utility Members’ motions to dismiss. The court dismissed some of the claims against us and the Non-Utility Members, including the civil conspiracy claim. After the dismissal, the remaining claims include seeking declaratory orders that the addition of the Non-Utility Members violated Colorado law, the April 2019 Bylaws amendment that allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void, and the April 2020 Board approvals related to the methodology to calculate a contract termination payment and buy-down payment formula do not apply to United Power and are void, and that we have breached our Bylaws and our wholesale electric service contract with United Power. On April 6, 2022, we and each Non-Utility Member filed their respective answers to the first amended complaint denying that United Power is entitled to any relief and requesting the court enter judgment of dismissal. We are also requesting declaratory judgements that the April 2019 Bylaws amendment and the April 2020 Board approvals related to the methodology to calculate a contract termination payment and buy-down payment formula are valid. On April 27, 2022, United Power filed a reply asserting that we are not entitled to any relief on our requests for declaratory judgement. A jury trial is scheduled for June 2023. In United Power's February 2023 expert report, United Power asserts that its damages are in the range of $483 million to $533 million, plus interest after the date of the expert report. It is not possible to predict the outcome of this matter, whether we will incur any liability in connection with this matter, and in the event of liability, if any, the amount of damages that could be awarded. FERC - Market Based Rate Authority. On December 27, 2021, we submitted to FERC our triennial market power update for the Southwest and Northwest regions in support of our continued authority to sell energy, capacity, and ancillary services at market-based rates in both the Southwest and Northwest regions. Our filing reflected that we pass the supplier indicative screens in the Public Service Company of Colorado (“PSCO”), Public Service Company of New Mexico (“PNM”), and the WACM balancing authority areas and the wholesale market share screens in the PSCO and PNM balancing authority areas, but fail the wholesale market share indicative screen in the WACM balancing authority area in all seasons. Due to such failure, on February 28, 2022, FERC instituted a FPA section 206 proceeding to determine whether our market-based rate authority in the WACM balancing authority area remains just and reasonable and established a refund effective date of March 7, 2022 for market-based sales after such date. FERC issued a show cause order as to why FERC should not revoke our market-based rate authority in the WACM balancing authority area. On April 29, 2022, we filed a response to the show cause order . FERC issued a decision on September 22, 2022 that revoked our market-based rate authorization in the WACM balancing authority area. Such revocation means that we cannot sell power in the WACM balancing authority area to non-members at bilaterally negotiated “market-based” rates. The FERC order instead required us to file, within 30 days of the order, a tariff for cost-based rates applicable to non-member sales in the WACM balancing authority area that would otherwise have been made under our market-based rate tariff. The order further required us to refund any revenue from power sales in the WACM balancing authority area to non-members on or after March 7, 2022 in excess of the cost-based rates, and submit a refund report within 30 days of the order. On October 7, 2022, FERC granted our motion to extend the deadline until December 21, 2022 to make the above referenced filings. As required by FERC, in December 2022, we distributed refunds with applicable interest of $2.7 million. On December 14, 2022, we also filed a cost-based rate tariff with FERC for our sales in the WACM balancing authority area, and such cost-based rate tariff was used to calculate the amount refunded. On February 27, 2023, FERC accepted our cost-based rate tariff. Energy Sales - Soft-Cap. In August 2020, we made certain energy sales to third parties in excess of the soft-cap price for short-term, spot market sales of $1,000 per megawatt hour established by the Western Electricity Coordinating Council. On October 7, 2020, we filed a report with FERC justifying the sales above the soft-cap and we did not recognize the revenue for the energy sales in excess of the soft-cap, EL21-65-000. Based upon additional guidance from FERC, we filed a supplemental report on July 19, 2021. On May 20, 2022, FERC issued an order directing us to refund only certain amounts of the energy sales revenue in excess of the soft-cap. Based upon the FERC order, in the second quarter of 2022, we recognized approximately $2.9 million in excess of the soft-cap and refunded $0.4 million to a third party. On July 22, 2022, the California Public Utilities Commission filed a petition for review with the DC Circuit Court of Appeals of FERC’s May 20, 2022 order, 22-1169. On August 18, 2022, we filed a motion to intervene with the DC Circuit Court of Appeals and an order granting said motion was issued on September 6, 2022. On January 24, 2023, the parties to the proceeding filed a motion with the court to consolidate this proceeding with other related proceedings with the DC Circuit Court of Appeals and proposed a procedural schedule with final briefings due in October 2023. On March 6, 2023, the DC Circuit Court of Appeals granted the motion to consolidate the proceedings. It is not possible to predict the outcome of this matter or whether we will be required to refund any additional amounts to third parties.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTSWe evaluated subsequent events through March 10, 2023, which is the date when the financial statements were issued.

SUMMARY OF SIGNIFICANT ACCOUN_2

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
BASIS OF CONSOLIDATION	BASIS OF CONSOLIDATION: Our consolidated financial statements include the accounts of the Association, our wholly owned and majority owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 13—Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. All significant intercompany balances and transactions have been eliminated in consolidation. The accompanying consolidated statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) as applied to regulated enterprises.
JOINTLY OWNED FACILITIES	JOINTLY OWNED FACILITIES:  We own undivided interests in two jointly owned generating 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) and the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)). 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.
SEGMENT REPORTING	SEGMENT REPORTING: We were organized for the purpose of supplying wholesale power to our Utility Members and do so through the utilization of a portfolio of resources, including generation and transmission facilities, long‑term purchase contracts and short‑term energy purchases. In support of our coal-fired generating resources, we have direct ownership in coal mines. Our Board serves as our chief operating decision maker who manages and reviews our operating results and allocates resources as one operating segment. Therefore, we have one reportable segment for financial reporting purposes.
USE OF ESTIMATES	USE OF ESTIMATES: The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.
IMPAIRMENT EVALUATION	IMPAIRMENT EVALUATION:  Long-lived assets (property, plant and equipment, intangible assets, investments and preliminary surveys and investigation costs) that are held and used are evaluated for impairment whenever events or changes in circumstances indicate the carrying value of an asset may not be recoverable. An impairment loss is recognized when estimated undiscounted cash flows expected to result from the use of the asset plus net proceeds expected from disposition of the asset (if any) are less than the carrying value of the asset. When an impairment loss is recognized, the carrying amount of the asset is reduced to its estimated fair value based on quoted market prices or other valuation techniques. In 2022, we recognized an impairment loss of $3.7 million associated with the early retirement of the Rifle Generating Station. We also recognized an impairment loss of $25.4 million associated with additional asset retirement obligations at the Nucla and Escalante Generating Stations related to a change in cost estimates. There were no impairments of long-lived assets recognized in 2021. In 2020, we recognized an impairment loss of $274.6 million associated with the early retirement of the Escalante Generating Station. These impairment losses were deferred in accordance with the accounting requirements related to regulated operations at the discretion of our Board and subject to FERC approval, if applicable.
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES:  We evaluate our arrangements and relationships with other entities, including our investments in other associations in accordance with the accounting standard related to consolidation of variable interest entities. This guidance requires us to identify variable interests (contractual, ownership or other financial interests) in other entities and whether any of those entities in which we have a variable interest meet the criteria of a variable interest entity. An entity is considered to be a variable interest entity when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. In making this assessment, we consider the potential that our arrangements and relationships with other entities provide subordinated financial support, the potential for us to absorb losses or rights to residual returns of an entity, the ability to directly or indirectly make decisions about the entity’s activities and other factors. If an entity that we have a variable interest in meets the criteria of a variable interest entity, we must determine whether we are the primary beneficiary of that entity. The primary beneficiary is the entity that has the power to direct the activities of the variable interest entity that most significantly impact the variable interest entity’s economic performance, and the obligation to absorb losses or the right to receive benefits from the variable interest entity that could be potentially significant to the variable interest entity. If we are determined to be the primary beneficiary of (has controlling financial interest in) a variable interest entity, then we would be required to consolidate that entity. In certain situations, it may be determined that power is shared among multiple unrelated parties such that no one party has the power to direct the activities of a variable interest entity that most significantly impact the variable interest entity’s economic performance (decisions about those activities require the consent of each of the parties sharing power). In accordance with the accounting guidance prescribed by consolidation of variable interest entities, if the determination is made that power is shared among multiple unrelated parties, then no party is the primary beneficiary.
ACCOUNTING FOR RATE REGULATION	ACCOUNTING FOR RATE REGULATION: In accordance with the accounting requirements related to regulated operations, some revenues and expenses have been deferred at the discretion of our Board, subject to FERC approval, if based on regulatory orders or other available evidence, it is probable that these amounts will be refunded or recovered through future rates. Regulatory assets are costs we expect to recover from our Utility Members based on rates approved by the applicable authority. Regulatory liabilities represent probable future reductions in rates associated with amounts that are expected to be refunded to our Utility Members based on rates approved by the applicable authority. Expected recovery of deferred costs and returning deferred credits are based on specific ratemaking decisions by FERC or precedent for each item. We recognize regulatory assets as expenses and regulatory liabilities as operating revenue, other income, or a reduction in expense concurrent with their recovery through rates.
ELECTRIC PLANT AND DEPRECIATION	ELECTRIC PLANT AND DEPRECIATION:  Electric plant is stated at cost. The cost of internally constructed assets includes payroll, overhead costs and interest charged during construction. Interest rates charged during construction were 2.3 percent for 2022, 4.4 percent for 2021 and 4.6 percent for 2020. During 2022, Tri-State transitioned from using the "Indirect Costs" ("IDC") rate to the FERC prescribed "Allowance For Funds Used During Construction" ("AFUDC") rate. AFUDC is defined as the gross allowance for borrowed funds used during construction. The AFUDC rate is calculated with the assumption that short-term debt is the first source of funds used for construction. Any construction not covered by the short-term debt is then assumed to be covered by long-term debt. The AFUDC rate varies from the IDC rate, which assumes that total debt was used to cover construction costs. The amount of interest capitalized during construction was $1.5, $3.8 and $6.1 million during 2022, 2021 and 2020, respectively. At the time that units of electric plant are retired, original cost and cost of removal, net of the salvage value, are charged to the allowance for depreciation. Replacements of electric plant that involve less than a designated unit value are charged to maintenance expense when incurred. Electric plant is depreciated based upon estimated depreciation rates and useful lives that are periodically re‑evaluated.
COAL RESERVES AND DEPLETION	COAL RESERVES AND DEPLETION: Coal reserves are recorded at cost. Depletion of coal reserves is computed using the units‑of‑production method utilizing only proven and probable reserves.
LEASES	LEASES: We determine if an arrangement is a lease upon commencement of the contract. If an arrangement is determined to be a long-term lease (greater than 12 months), we recognize a right-of-use asset and lease liability based on the present value of the future minimum lease payments over the lease term at the commencement date. As most of our leases do not provide an implicit rate, we use our incremental borrowing rate based on the information available at commencement date in determining the present value of future payments. Our lease terms may also include options to extend or terminate the lease when it is reasonably certain that we will exercise those options. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term. Right-of-use assets are included in other deferred charges, the current portion of lease liabilities is included in accrued expenses and the long-term portion of lease liabilities is included in other deferred credits and other liabilities on our consolidated statements of financial position. See Note 11—Leases. We have elected to apply the short-term lease exception for contracts that have a lease term of twelve months or less and do not include an option to purchase the underlying asset. Therefore, we do not recognize a right-of-use asset or lease liability for such contracts. We recognize short-term lease payments as expense on a straight-line basis over the lease term. Variable lease payments that do not depend on an index or rate are recognized as incurred.
INVESTMENTS IN OTHER ASSOCIATIONS	INVESTMENTS IN OTHER ASSOCIATIONS: Investments in other associations include investments in the patronage capital of other cooperatives and other required investments in the organizations. Our investment in a cooperative increases when a cooperative allocates patronage capital credits to us, and it decreases when we receive a cash retirement of the allocated capital credits from the cooperative. A cooperative allocates its patronage capital credits to us based upon our patronage (amount of business done) with the cooperative. Investments in other associations are as follows (dollars in thousands): December 31, December 31, Basin Electric Power Cooperative $ 127,640 $ 116,826 National Rural Utilities Cooperative Finance Corporation - patronage capital 12,172 12,076 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,054 15,149 CoBank, ACB 16,727 12,985 Other 5,884 6,061 Investments in other associations $ 177,477 $ 163,097
CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS	CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS: We consider highly liquid investments with an original maturity of three months or less to be cash equivalents. The fair value of cash equivalents approximates their carrying values due to their short-term maturity. Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds have been restricted by contract and 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 restricted by contract or other legal reasons and 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.
MARKETABLE SECURITIES	MARKETABLE SECURITIES:  We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are measured at fair value on a recurring basis with changes in fair value recognized in earnings. 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.
INVENTORIES	INVENTORIES: Coal inventories at our owned generating facilities are stated at LIFO (last‑in, first‑out) cost and were $3.7 million and $27.1 million as of December 31, 2022 and 2021, respectively. The remaining coal inventories, other fuel, and materials and supplies inventories are stated at average cost. In 2022, we realized lower coal fuel expense of $14.5 million as a result of a LIFO inventory liquidation at our generating facilities.
OTHER DEFERRED CHARGES	OTHER DEFERRED CHARGES: We make expenditures for preliminary surveys and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the preliminary survey and investigation expenditures will be reclassified to electric plant - construction work in progress. If the work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating expense account, or the expense could be deferred as a regulatory asset to be recovered from our Utility Members through rates subject to approval by our Board and FERC. 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 and Yampa Project – Craig Generating Station Units 1 and 2. We also make advance payments to the operating agent of Springerville Unit 3.
DEBT ISSUANCE COSTS	DEBT ISSUANCE COSTS:  We account for debt issuance costs as a direct deduction of the associated long-term debt carrying amount consistent with the accounting for debt discounts and premiums. Deferred debt issuance costs are amortized to interest expense using an effective interest method over the life of the respective debt.
ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS	ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS : We account for current obligations associated with the future retirement of tangible long-lived assets and environmental reclamation 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 a market risk premium. As changes in estimates occur, such as mine plans, estimated costs, and timing of the performance of reclamation activities, we make revisions to the asset and obligation at the appropriate discount rate. Upon settlement of an asset retirement obligation, we apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability.
OTHER DEFERRED CREDITS AND OTHER LIABILITIES	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. We will pay $27.2 million for these easements from 2022 through the individual easement terms ending between 2036 and 2040. The present value of the remaining easement payments was $18.6 million and $19.3 million as of December 31, 2022 and December 31, 2021, respectively, which is recorded as other deferred credits and other liabilities. OATT deposits represent refundable transmission customer deposits related to interconnection and transmission requests from third parties. An OATT deposit is refundable should the interconnection or transmission request not move forward. Financial liabilities-reclamation represent financial obligations that we have for our share of the reclamation costs at jointly owned facilities in which we have undivided interests in. A contract liability represents an entity’s obligation to transfer goods or services to a customer for which the entity has received consideration from the customer. We have received deposits from others and these deposits are reflected in contract liabilities (unearned revenue) until recognized in other operating revenues 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.
PATRONAGE CAPITAL	PATRONAGE CAPITAL: Our net margins are treated as advances of capital from our Members and are allocated to our Utility Members on the basis of their electricity purchases from us and to our Non-Utility Members as provided in their
ELECTRIC SALES REVENUE AND OTHER OPERATING REVENUE	ELECTRIC SALES REVENUE:  Revenue from electric energy deliveries is recognized when delivered.OTHER OPERATING REVENUE:  Other operating revenue consists primarily of wheeling, transmission, and coal sales revenue.
INCOME TAXES	INCOME TAXES:  We are a taxable cooperative subject to federal and state taxation. As a taxable electric cooperative, we are allowed a tax exclusion for margins allocated as patronage capital. We utilize the liability method of accounting for income taxes, which requires that deferred tax assets and liabilities be determined based on the expected future income tax consequences of events that have been recognized in the consolidated financial statements. Under the normalization method, changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit). Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. 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.
INTERCHANGE POWER	INTERCHANGE POWER:  We occasionally engage in interchanges, or non‑cash swapping, of energy. Based on the assumption that all energy interchanged will eventually be received or delivered in‑kind, interchanged energy is generally valued at the average cost of fuel to generate power. Additionally, portions of the energy interchanged are valued per contract with the utility involved in the interchange. When we are in a net energy advance position, the advanced energy balance is recorded as an asset. If we owe energy, the net energy balance owed to others is recorded as a liability. The net activity for the year is included in purchased power expense.
ACCOUNTING PRONOUNCEMENTS - ADOPTED	ACCOUNTING PRONOUNCEMENTS - ADOPTED: In October 2021, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance. The purpose of ASU 2021-10 is to increase the transparency of government assistance that is accounted for by applying a grant or contribution model by analogy, including disclosures of the types of assistance, the accounting for the assistance, and the effect of the assistance on an entity's financial statements. Prior to the issuance of ASU 2021-10, there was a lack of specific authoritative guidance in GAAP. This guidance excludes transactions in the scope of specific GAAP, such as tax incentives accounted for under Accounting Standards Codification ("ASC") 740, Income Taxes. ASU 2021-10 is effective for annual periods beginning after December 15, 2021, with early adoption and retrospective or prospective application permitted. We have evaluated the impact of adopting ASU 2021-10 and believe that the adoption of this update will not have a material impact on our consolidated financial statement disclosures.
RECLASSIFICATIONS	RECLASSIFICATIONS:  Certain reclassifications have been made to the prior year financial statements to conform to the 2022 presentation.

SUMMARY OF SIGNIFICANT ACCOUN_3

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Schedule of Regulatory Assets and Liabilities	Regulatory assets and liabilities are as follows (dollars in thousands): December 31, December 31, Regulatory assets Deferred income tax expense (1) $ 19,279 $ 18,742 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 76,842 79,133 Goodwill – J.M. Shafer (3) 40,598 43,447 Goodwill – Colowyo Coal (4) 34,095 35,128 Deferred debt prepayment transaction costs (5) 115,045 123,674 Deferred Holcomb expansion impairment loss (6) 79,470 84,145 Unrecovered plant (7) 285,092 281,424 Total regulatory assets 650,421 665,693 Regulatory liabilities Interest rate swap - realized gain (8) and other 2,341 2,818 Membership withdrawal (9) 47,590 143,203 Total regulatory liabilities 49,931 146,021 Net regulatory asset $ 600,490 $ 519,672 ___________________________________________ (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) Represents deferral of the 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 Utility Members in rates. (3) 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 Utility Members in rates. (4) 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 Utility Members in rates. (5) 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 period ending in 2036 and recovered from our Utility Members in rates. (6) Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. The regulatory asset for the deferred impairment loss is being amortized to other operating expenses in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members in rates. (7) Represents deferral of the impairment losses and other closure costs related to the early retirement of the Nucla, Escalante and Rifle Generating Stations. The deferred impairment loss for Nucla Generating Station was amortized to depreciation, amortization and depletion expense through December 2022 and recovered from our Utility Members through rates. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $12.2 million annually over the 25-year period ending in December 2045, which was the depreciable life of Escalante Generating Station, and recovered from our Utility Members through rates. The annual amortization approximates the former annual Escalante Generating Station depreciation for the remaining life of the asset. In March 2022, our Board took action for the early retirement of Rifle Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement, we recognized an impairment loss of $3.7 million during the first quarter of 2022. The Rifle Generating Station was retired from service on September 30, 2022. The deferred impairment loss is being amortized to depreciation, amortization and depletion expense in the amount of $0.6 million annually through December 2028, which was the depreciable life of the Rifle Generating Station, and recovered from our Utility Members in rates. (8) Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12- year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods. (9) Represents the deferral of the recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. The deferred membership withdrawal income will be refunded to Utility Members through reduced rates when recognized in operating revenues in future periods. During 2022, $95.6 million was recognized in operating revenues as part of our rate stabilization measures.
Schedule of Investments in Other Associations	Investments in other associations are as follows (dollars in thousands): December 31, December 31, Basin Electric Power Cooperative $ 127,640 $ 116,826 National Rural Utilities Cooperative Finance Corporation - patronage capital 12,172 12,076 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,054 15,149 CoBank, ACB 16,727 12,985 Other 5,884 6,061 Investments in other associations $ 177,477 $ 163,097
Schedule of Cash, Cash Equivalents, Restricted Cash and Investments	The following table provides a reconciliation of cash, cash equivalents and restricted cash and investments reported within our consolidated statements of financial position that sum to the total of the same such amount shown in our consolidated statements of cash flows (dollars in thousands): December 31, December 31, Cash and cash equivalents $ 105,852 $ 100,555 Restricted cash and investments - current 573 480 Restricted cash and investments - noncurrent 4,257 4,101 Cash, cash equivalents and restricted cash and investments $ 110,682 $ 105,136
Schedule of Other Deferred Charges	Other deferred charges are as follows (dollars in thousands): December 31, December 31, Preliminary surveys and investigations $ 13,048 $ 12,366 Advances to operating agents of jointly owned facilities 7,324 4,422 Operating lease right-of-use assets 6,771 7,529 Other 13,302 10,822 Total other deferred charges $ 40,445 $ 35,139
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): December 31, December 31, Transmission easements $ 18,636 $ 19,339 OATT deposits 17,476 24,327 Financial liabilities - reclamation 12,429 13,122 Customer deposits 11,247 9,287 Contract liabilities (unearned revenue) - noncurrent 3,765 3,523 Operating lease liabilities - noncurrent 1,251 1,622 Other 3,570 7,099 Total other deferred credits and other liabilities $ 68,374 $ 78,319

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2022
Public Utilities, Property, Plant and Equipment [Abstract]
Schedule of Investment in Electric Plant	ELECTRIC PLANT : At December 31, 2022, our investment in electric plant and the related annual rates of depreciation or amortization calculated using the straight‑line method are as follows (dollars in thousands): Annual Depreciation Rate Plant In Accumulated Net Book Generation plant 0.89 % to 6.27 % $ 3,048,918 $ (1,353,042) $ 1,695,876 Transmission plant 1.11 % to 2.09 % 1,956,378 (690,517) 1,265,861 General plant 1.46 % to 9.53 % 412,879 (257,761) 155,118 Other 2.75 % to 10.00 % 241,248 (91,043) 150,205 Electric plant in service (at cost) $ 5,659,423 $ (2,392,363) 3,267,060 Construction work in progress 81,555 Electric plant $ 3,348,615 At December 31, 2021, our investment in electric plant and the related annual rates of depreciation or amortization calculated using the straight‑line method are as follows (dollars in thousands): Annual Depreciation Rate Plant In Accumulated Net Book Generation plant 0.89 % to 6.27 % $ 3,049,233 $ (1,318,197) $ 1,731,036 Transmission plant 1.11 % to 2.09 % 1,879,148 (672,556) 1,206,592 General plant 1.46 % to 9.53 % 406,693 (251,567) 155,126 Other 2.75 % to 10.00 % 271,658 (124,877) 146,781 Electric plant in service (at cost) $ 5,606,732 $ (2,367,197) 3,239,535 Construction work in progress 107,636 Electric plant $ 3,347,171
Schedule of Jointly Owned Facilities	JOINTLY OWNED FACILITIES : Our share in each jointly owned facility is as follows as of December 31, 2022 (these electric plant in service, accumulated depreciation and construction work in progress amounts are included in the electric plant table above) (dollars in thousands): Tri-State Electric Accumulated Construction Yampa Project - Craig Generating Station Units 1 and 2 24.00 % $ 391,689 $ 261,366 $ 163 MBPP - Laramie River Station 28.50 % 530,692 341,882 2,621 Total $ 922,381 $ 603,248 $ 2,784
Schedule of Other Plant Assets (Excluding Utility Assets)	Other plant assets are as follows (dollars in thousands): December 31, December 31, Colowyo Mine assets $ 386,898 $ 376,868 New Horizon Mine assets 5,995 5,061 Accumulated depreciation and depletion (155,653) (133,951) Net mine assets 237,240 247,978 Non-utility assets 561,251 711,993 Accumulated depreciation (539,121) (689,136) Net non-utility assets 22,130 22,857 Net other plant $ 259,370 $ 270,835

ASSET RETIREMENT AND ENVIRONM_2

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies Disclosure [Abstract]
Schedule of Asset Retirement Obligations and Environmental Reclamation Obligations	Aggregate carrying amounts of asset retirement obligations and environmental reclamation obligations are as follows (dollars in thousands): 2022 2021 Obligations at beginning of period $ 90,281 $ 138,089 Liabilities incurred — 1,475 Liabilities settled (3,184) (4,934) Accretion expense 6,163 2,409 Change in estimate 93,747 (46,758) Total obligations at end of period $ 187,007 $ 90,281 Less current obligations at end of period (5,419) (7,003) Long-term obligations at end of period $ 181,588 $ 83,278

CONTRACT ASSETS AND CONTRACT _2

CONTRACT ASSETS AND CONTRACT LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2022
Change in Contract with Customer, Asset and Liability [Abstract]
Schedule of Contract Assets and Liabilities	Our contract assets, accounts receivable and liabilities consist of the following (dollars in thousands): December 31, December 31, Accounts receivable - Members $ 103,246 $ 95,630 Other accounts receivable - trade: Non-member electric sales 17,213 5,684 Other 9,141 13,505 Total other accounts receivable - trade 26,354 19,189 Other accounts receivable - nontrade 6,082 2,382 Total other accounts receivable $ 32,436 $ 21,571 Contract liabilities (unearned revenue) $ 5,123 $ 5,372

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long-term debt, including applicable terms and interest rates as of December 31, 2022, consists of the following (dollars in thousands): December 31, December 31, Mortgage notes payable 2.32% to 3.66% CFC, due through 2028 $ 85,855 $ 106,182 2.63% to 4.43% CoBank, ACB, due through 2042 174,985 204,163 First Mortgage Obligations, Series 2017A, Tranche 1, 3.34%, due through 2029 60,000 60,000 First Mortgage Obligations, Series 2017A, Tranche 2, 3.39%, due through 2029 60,000 60,000 First Mortgage Bonds, Series 2016A, 4.25% due 2046 228,783 250,000 First Mortgage Bonds, Series 2014E-1, 3.70% due 2024 128,002 244,714 First Mortgage Bonds, Series 2014E-2, 4.70% due 2044 250,000 250,000 First Mortgage Bonds, Series 2010A, 6.00% due 2040 499,805 500,000 First Mortgage Obligations, Series 2014B, Tranche 1, 3.90%, due through 2033 180,000 180,000 First Mortgage Obligations, Series 2014B, Tranche 2, 4.30%, due through 2039 20,000 20,000 First Mortgage Obligations, Series 2014B, Tranche 3, 4.45%, due through 2045 550,000 550,000 Variable rate CFC, as determined by CFC, due through 2026 — 324 Variable rate CFC, LIBOR-based term loan, due through 2049 152,220 152,220 Variable rate CoBank, ACB, LIBOR-based term loans, due through 2044 296,430 297,039 Pollution control revenue bonds Moffat County, CO, 2.90% term rate through October 2027, Series 2009, due 2036 46,800 46,800 Springerville certificates Series B, 7.14%, due through 2033 248,601 292,985 Total long-term debt $ 2,981,481 $ 3,214,427 Less debt issuance costs (21,481) (23,110) Less debt discounts (8,960) (9,398) Plus debt premiums 11,843 12,990 Total debt adjusted for discounts, premiums and debt issuance costs $ 2,962,883 $ 3,194,909 Less current maturities (92,920) (93,039) Long-term debt $ 2,869,963 $ 3,101,870
Schedule of Annual Maturities of Long-term Debt	Annual maturities of total long-term debt adjusted for debt issuance costs, discounts and premiums at December 31, 2022 are as follows (dollars in thousands): 2023 $ 92,920 2024 (1) 223,835 2025 88,819 2026 90,440 2027 92,323 Thereafter 2,374,546 $ 2,962,883 ___________________________________________ (1) Includes $128 million bullet maturity for the First Mortgage Bonds, Series 2014 E-1.

SHORT-TERM BORROWINGS (Tables)

SHORT-TERM BORROWINGS (Tables)	12 Months Ended
	Dec. 31, 2022
Short-Term Debt [Abstract]
Schedule of Commercial Paper	Commercial paper consisted of the following (dollars in thousands): 2022 2021 Commercial paper outstanding, net of discounts $ 274,102 $ 49,997 Weighted average interest rate 4.61 % 0.20 %

FAIR VALUE (Tables)

FAIR VALUE (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Schedule of Cost and Fair Values of Assets and Liabilities	The cost and fair values of our investments in the Executive Benefit Restoration Plan trust are as follows (dollars in thousands): December 31, 2022 December 31, 2021 Cost Estimated Cost Estimated Marketable securities $ 10,604 $ 9,808 $ 8,850 $ 8,640 December 31, 2022 December 31, 2021 Cost Estimated Cost Estimated Marketable securities $ 558 $ 489 $ 597 $ 598 December 31, 2022 December 31, 2021 Principal Estimated Principal Estimated Total long-term debt $ 2,981,481 $ 2,725,606 $ 3,214,427 $ 3,759,991

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Schedule of Components of Net Deferred Tax Assets (Liabilities)	Components of our net deferred tax liability are as follows (dollars in thousands): December 31, December 31, Deferred tax assets Net operating loss carryforwards $ 165,636 $ 144,602 Operating lease liabilities 105,039 114,237 Deferred revenues and membership withdrawal 16,028 38,784 Safe harbor lease receivables 8,939 8,135 Other 43,795 30,578 339,437 336,336 Less valuation allowance — — 339,437 336,336 Deferred tax liabilities Basis differences- property, plant and equipment and other 166,568 159,696 Operating lease right-of-use assets 125,939 130,111 Capital credits from other associations 34,236 31,622 Deferred debt prepayment transaction costs 27,381 29,434 Other 4,588 4,460 358,712 355,323 Net deferred tax liability $ (19,275) $ (18,987)
Schedule of Effective Income Tax Reconciliation	The reconciliation between pretax GAAP income and deferred income tax expense (benefit) is as follows (dollars in thousands): 2022 2021 2020 Pretax GAAP income at Federal statutory rate $ — $ 5,435 $ 5,271 Pretax GAAP income at State statutory rate, net of federal benefit — 725 703 Patronage exclusion — (6,159) (5,974) Asset retirement and environmental reclamation obligations 16,655 10,917 (14,230) Deferred revenues and membership withdrawal (22,759) 18,673 (29,519) Operating liabilities, net of right-of-use assets (1) (4,919) 1,165 5,277 Valuation Allowance — — (30,468) Net operating loss carryforward 21,034 (27,539) 367 Other items, net (9,445) (2,531) 17,543 Impairment — — 20,554 Regulatory treatment of deferred taxes (815) (391) 29,942 Total deferred income tax expense (benefit) $ (249) $ 295 $ (534)

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Schedule of Revenue from Contracts with Non-Member Customers and Other Operating Revenue	The following revenue is reflected on our consolidated statements of operations as follows (dollars in thousands): 2022 2021 2020 Non-member electric sales: Long-term contracts $ 56,570 $ 44,383 $ 46,172 Short-term contracts 106,785 70,525 44,210 Rate stabilization 95,613 78,457 12,136 Provision for rate refunds (51) (10,196) — Coal Sales 7,021 4,951 7,326 Other 54,399 51,390 46,219 Total non-member electric sales and other operating revenue $ 320,337 $ 239,510 $ 156,063

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Schedule of Lease Components	Our consolidated statements of financial position include the following lease components (dollars in thousands): December 31, December 31, Operating leases Operating lease right-of-use assets $ 8,784 $ 9,081 Less: Accumulated amortization (2,013) (1,552) Net operating lease right-of-use assets $ 6,771 $ 7,529 Operating lease liabilities – current $ (441) $ (491) Operating lease liabilities – noncurrent (1,251) (1,622) Total operating lease liabilities $ (1,692) $ (2,113) Operating leases Weighted average remaining lease term (years) 7.6 7.6 Weighted average discount rate 3.87 % 3.79 %
Schedule of Expected Minimum Lease Commitments under Operating Leases	Future expected minimum lease commitments under operating leases are as follows (dollars in thousands): Year 1 $ 386 Year 2 342 Year 3 151 Year 4 431 Year 5 94 Thereafter 549 Total lease payments $ 1,953 Less imputed interest (261) Total $ 1,692

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2022
Retirement Benefits [Abstract]
Schedule of Postretirement Medical Benefit and Postemployment Medical Benefit Obligations	The NRECA Executive Benefit Restoration Plan obligations are determined annually (during the first quarter of the subsequent year) by an NRECA actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): 2022 2021 Executive benefit restoration obligation at beginning of period $ 9,852 $ 7,379 Service cost 468 440 Interest cost 300 205 Plan amendments - prior service cost 308 1,050 Curtailment (292) — Benefit payments (110) — Actuarial (gain) loss (2,041) 778 Executive benefit restoration obligation at end of period $ 8,485 $ 9,852 Fair value of plan assets at beginning of year $ 8,640 $ 6,955 Employer contributions 1,734 1,762 Benefits paid (109) — Actual return on plan assets (457) (77) Fair value of plan assets at end of year $ 9,808 $ 8,640 Net (asset) liability recognized $ (1,323) $ 1,212 The postretirement medical benefit and post-employment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands): 2022 2021 Postretirement medical benefit obligation at beginning of period $ 2,809 $ 9,985 Interest cost 47 36 Benefit payments (net of contributions by participants) (732) (730) Actuarial gain (32) (784) Plan amendments — (5,698) Postretirement medical benefit obligation at end of period $ 2,092 $ 2,809 Postemployment medical benefit obligation at end of period 97 419 Total postretirement and postemployment medical obligations at end of period $ 2,189 $ 3,228
Schedule of Net Unrecognized Actuarial Gains and Losses Related to Postretirement Medical Benefit Obligation Included in Accumulated Other Comprehensive Income	The net unrecognized actuarial gains and losses related to the executive benefit restoration obligations are included in accumulated other comprehensive income as follows (dollars in thousands): 2022 2021 Accumulated other comprehensive loss at beginning of period $ (4,932) $ (4,873) Plan amendments - prior service cost (308) (1,050) Amortization of prior service cost into other income 1,156 1,113 Amortization of actuarial loss 426 515 Curtailment and settlement (187) 141 Unrecognized actuarial gain (loss) 1,740 (778) Accumulated other comprehensive loss at end of period $ (2,105) $ (4,932) The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligation are included in accumulated other comprehensive income as follows (dollars in thousands): 2022 2021 Amounts included in accumulated other comprehensive income at beginning of period $ 3,580 $ (841) Amortization of prior service credit into other income (1,636) (2,139) Amortization of actuarial loss into other income 102 78 Actuarial gain 32 784 Plan amendments — 5,698 Amounts included in accumulated other comprehensive income at end of period $ 2,078 $ 3,580
Schedule of Assumptions Used in Actuarial Study Performed for Postretirement Medical Benefit Obligation	The assumptions used in the 2022 actuarial study performed for our postretirement medical benefit obligation were as follows: Weighted-average discount rate 1.82 % Initial health care cost trend (2018) 7.00 % Ultimate health care cost trend 4.50 % Year that the rate reached the ultimate health care cost trend rate 2027 Expected return on plan assets (unfunded) N/A Average remaining service lives of active plan participants (years) 2.99
Schedule of Expected Future Benefits to be Paid Related to Postretirement Medical Benefit Obligation	The following are the expected future benefits to be paid (net of contributions by participants) related to the postretirement medical benefit obligation during the next ten years (dollars in thousands): 2023 $ 576,432 2024 482,090 2025 379,064 2026 298,176 2027 200,190 2028 through 2032 362,795 $ 2,298,747

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2022
Variable Interest Entity or Potential VIE, Information Unavailability, Disclosures [Abstract]
Schedule of Consolidated Variable Interest Entities	Assets and liabilities of the Springerville Partnership that are included in our consolidated statements of financial position are as follows (dollars in thousands): December 31, December 31, Net electric plant $ 721,997 $ 740,135 Noncontrolling interest 126,180 119,101 Long-term debt 254,876 300,220 Accrued interest 7,400 8,721 Our consolidated statements of operations include the following Springerville Partnership expenses (dollars in thousands): Twelve Months Ended December 31, 2022 December 31, 2021 December 31, 2020 Depreciation, amortization and depletion $ 18,138 $ 18,138 $ 18,138 Interest 17,064 20,038 22,798

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Commitments	As of December 31, 2022, the minimum coal to be purchased under these contracts is as follows (dollars in thousands): 2023 $ 30,627 2024 23,217 2025 10,113 2026 6,882 2027 6,825 Thereafter 88,247 $ 165,911
Schedule of Costs under Electric Power Purchase Agreements	Costs under the above electric power purchase agreements were as follows (dollars in thousands): 2022 2021 2020 Basin $ 148,146 $ 146,532 $ 152,461 WAPA 67,791 70,107 72,491 Renewables, other than WAPA 85,601 71,565 69,255

ORGANIZATION (Details)

ORGANIZATION (Details) $ in Thousands, MWh in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) employee MWh class_of_membership non-utility_member member_system	Dec. 31, 2021 USD ($) MWh	Dec. 31, 2020 USD ($) MWh
Concentration Risk [Line Items]
Number of classes of members | class_of_membership	3
Number of electric distribution member systems | member_system	42
Number of non-utility members | non-utility_member	3
Total megawatt-hours sold | MWh	18.6	17.6	17.5
Energy resources, proportion supplied by generation (as a percent)	54.30%	52.10%	58.20%
Number of employees | employee	1,105
Workforce Subject to Collective Bargaining Arrangements | Unionized Employees Concentration Risk
Concentration Risk [Line Items]
Number of employees | employee	215
Member electric sales
Concentration Risk [Line Items]
Revenue from contract with customer | $	$ 1,213,234	$ 1,161,291	$ 1,196,232
Electric sales
Concentration Risk [Line Items]
Revenue from contract with customer | $	$ 1,400,000	$ 1,300,000	$ 1,300,000
Utility Member | Member electric sales | Total Megawatt-Hours | Customer Concentration
Concentration Risk [Line Items]
Concentration risk (as a percent)	88.80%	89.10%	90.80%
Utility Member | Member electric sales | Electric Sales Provided by Generation | Customer Concentration
Concentration Risk [Line Items]
Concentration risk (as a percent)	82.40%	86.40%	92.10%

SUMMARY OF SIGNIFICANT ACCOUN_4

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Jointly Owned Facilities (Details)	12 Months Ended
	Dec. 31, 2022 facility
Accounting Policies [Abstract]
Number of jointly owned facilities	2

SUMMARY OF SIGNIFICANT ACCOUN_5

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Segments and Impairment Losses (Details) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($) operating_segment reportable_segment	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Impairment of long-lived assets
Number of operating segments | operating_segment		1
Number of reportable segments | reportable_segment		1
Impairment losses of long-lived assets		$ 29,098	$ 0	$ 274,645
Rifle Generating Station
Impairment of long-lived assets
Impairment losses of long-lived assets	$ 3,700	3,700
Nucla and Escalante Generating Stations
Impairment of long-lived assets
Impairment losses of long-lived assets		$ 25,400
Escalante Generating Station
Impairment of long-lived assets
Impairment losses of long-lived assets				$ 274,600

SUMMARY OF SIGNIFICANT ACCOUN_6

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Oct. 31, 2017	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 650,421	$ 665,693
Regulatory liabilities			49,931	146,021
Net regulatory asset			600,490	519,672
Impairment losses of long-lived assets			29,098	0	$ 274,645
Rate stabilization
Regulatory Asset and Liability [Line Items]
Revenue from contract with customer			$ 95,613	78,457	12,136
First Mortgage Obligations, Series 2017A, Tranche 1, 3.34%, due through 2029 | Secured Debt
Regulatory Asset and Liability [Line Items]
Term of issuance			12 years
Escalante Generating Station
Regulatory Asset and Liability [Line Items]
Impairment losses of long-lived assets					$ 274,600
Rifle Generating Station
Regulatory Asset and Liability [Line Items]
Impairment losses of long-lived assets		$ 3,700	$ 3,700
Interest Rate Swaps, Realized Gain
Regulatory Asset and Liability [Line Items]
Regulatory liabilities			2,341	2,818
Deferral of realized gain	$ 4,600
Membership Withdrawal
Regulatory Asset and Liability [Line Items]
Regulatory liabilities			47,590	143,203
Deferred Revenue | Rate stabilization
Regulatory Asset and Liability [Line Items]
Revenue from contract with customer			95,600
Deferred Income Tax Expense
Regulatory Asset and Liability [Line Items]
Regulatory assets			19,279	18,742
Deferred Prepaid Lease Expense | Springerville Unit 3 Lease
Regulatory Asset and Liability [Line Items]
Regulatory assets			76,842	79,133
Annual amortization expense			$ 2,300
Amortization period			47 years
Goodwill | Thermo Cogeneration Partnership
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 40,598	43,447
Annual amortization expense			$ 2,800
Amortization period			25 years
Goodwill | Colowyo Coal
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 34,095	35,128
Annual amortization expense			$ 1,000
Amortization period			44 years
Deferred Debt Prepayment Transaction Costs
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 115,045	123,674
Annual amortization expense			$ 8,600
Amortization period			21 years 4 months 24 days
Deferred Impairment Loss | Escalante Generating Station
Regulatory Asset and Liability [Line Items]
Annual amortization expense			$ 12,200
Amortization period			25 years
Deferred Impairment Loss | Rifle Generating Station
Regulatory Asset and Liability [Line Items]
Annual amortization expense			$ 600
Deferred Impairment Loss | Nucla and Escalante Generating Stations
Regulatory Asset and Liability [Line Items]
Regulatory assets			285,092	281,424
Deferred Impairment Loss | Holcomb Expansion
Regulatory Asset and Liability [Line Items]
Regulatory assets			79,470	$ 84,145
Annual amortization expense			$ 4,700
Amortization period			20 years

SUMMARY OF SIGNIFICANT ACCOUN_7

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Electric Plant and Depreciation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
ELECTRIC PLANT AND DEPRECIATION:
Interest rates charged during construction (as a percent)	2.30%	4.40%	4.60%
Interest capitalized during construction	$ 1.5	$ 3.8	$ 6.1

SUMMARY OF SIGNIFICANT ACCOUN_8

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Investments in Other Associations (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	$ 177,477,000	$ 163,097,000
Impairment during the period	0	0	$ 0
Basin Electric Power Cooperative
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	127,640,000	116,826,000
National Rural Utilities Cooperative Finance Corporation - patronage capital
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	12,172,000	12,076,000
National Rural Utilities Cooperative Finance Corporation - capital term certificates
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	15,054,000	15,149,000
CoBank, ACB
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	16,727,000	12,985,000
Other
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	$ 5,884,000	$ 6,061,000

SUMMARY OF SIGNIFICANT ACCOUN_9

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Cash, Cash Equivalents, Restricted Cash and Investments (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash, cash equivalents and restricted cash and investments
Cash and cash equivalents	$ 105,852	$ 100,555
Restricted cash and investments - current	573	480
Restricted cash and investments - noncurrent	4,257	4,101
Cash, cash equivalents and restricted cash and investments	$ 110,682	$ 105,136	$ 132,074	$ 113,768

SUMMARY OF SIGNIFICANT ACCOU_10

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Marketable Securities (Details) - Director and Executive Elective Deferred Compensation Investments - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Estimated Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	$ 489	$ 598
Principal Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	$ 558	$ 597

SUMMARY OF SIGNIFICANT ACCOU_11

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
INVENTORIES:
Coal inventory	$ 34,723	$ 59,701
Owned Generating Stations
INVENTORIES:
Coal inventory	3,700	$ 27,100
LIFO inventory liquidation	$ 14,500

SUMMARY OF SIGNIFICANT ACCOU_12

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Deferred Charges (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Preliminary surveys and investigations	$ 13,048	$ 12,366
Advances to operating agents of jointly owned facilities	7,324	4,422
Operating lease right-of-use assets	6,771	7,529
Other	13,302	10,822
Total other deferred charges	$ 40,445	$ 35,139

SUMMARY OF SIGNIFICANT ACCOU_13

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Deferred Credits and Other Liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Deferred Credits [Line Items]
Present value of transmission easement payments	$ 18,636	$ 19,339
Other Deferred Credits and Other Liabilities [Abstract]
Transmission easements	18,636	19,339
OATT deposits	17,476	24,327
Financial liabilities - reclamation	12,429	13,122
Customer deposits	11,247	9,287
Contract liabilities (unearned revenue) - noncurrent	3,765	3,523
Operating lease liabilities - noncurrent	1,251	1,622
Other	3,570	7,099
Total other deferred credits and other liabilities	68,374	78,319
Transmission - Right of Way Easements
Deferred Credits [Line Items]
Total due for easement right of way	27,200
Present value of transmission easement payments	18,600	19,300
Other Deferred Credits and Other Liabilities [Abstract]
Transmission easements	$ 18,600	$ 19,300

SUMMARY OF SIGNIFICANT ACCOU_14

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Interchange Power (Details) - Accounts Payable - Interchange Power - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Nonmonetary Transaction [Line Items]
Interchange liability	$ 4.7	$ 2.9
Purchased Power Expense
Nonmonetary Transaction [Line Items]
Net interchange activity, credit (expense)	$ (1.5)	$ (0.6)	$ 0.1

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Electric Plant (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Electric Plant
Plant In Service	$ 5,659,423	$ 5,606,732
Accumulated Depreciation	(2,392,363)	(2,367,197)
Construction work in progress	81,555	107,636
Net electric plant	3,348,615	3,347,171
Electric Plant
Electric Plant
Plant In Service	5,659,423	5,606,732
Accumulated Depreciation	(2,392,363)	(2,367,197)
Net Book Value	3,267,060	3,239,535
Construction work in progress	81,555	107,636
Net electric plant	3,348,615	3,347,171
Generation plant
Electric Plant
Plant In Service	3,048,918	3,049,233
Accumulated Depreciation	(1,353,042)	(1,318,197)
Net Book Value	$ 1,695,876	$ 1,731,036
Generation plant | Minimum
Electric Plant
Annual Depreciation Rate (as a percent)	0.89%	0.89%
Generation plant | Maximum
Electric Plant
Annual Depreciation Rate (as a percent)	6.27%	6.27%
Transmission plant
Electric Plant
Plant In Service	$ 1,956,378	$ 1,879,148
Accumulated Depreciation	(690,517)	(672,556)
Net Book Value	$ 1,265,861	$ 1,206,592
Transmission plant | Minimum
Electric Plant
Annual Depreciation Rate (as a percent)	1.11%	1.11%
Transmission plant | Maximum
Electric Plant
Annual Depreciation Rate (as a percent)	2.09%	2.09%
General plant
Electric Plant
Plant In Service	$ 412,879	$ 406,693
Accumulated Depreciation	(257,761)	(251,567)
Net Book Value	$ 155,118	$ 155,126
General plant | Minimum
Electric Plant
Annual Depreciation Rate (as a percent)	1.46%	1.46%
General plant | Maximum
Electric Plant
Annual Depreciation Rate (as a percent)	9.53%	9.53%
Other
Electric Plant
Plant In Service	$ 241,248	$ 271,658
Accumulated Depreciation	(91,043)	(124,877)
Net Book Value	$ 150,205	$ 146,781
Other | Minimum
Electric Plant
Annual Depreciation Rate (as a percent)	2.75%	2.75%
Other | Maximum
Electric Plant
Annual Depreciation Rate (as a percent)	10%	10%

PROPERTY, PLANT AND EQUIPMENT_2

PROPERTY, PLANT AND EQUIPMENT - Construction Commitments (Details) - Electric Plant - Construction Commitments $ in Millions	Dec. 31, 2022 USD ($)
Long-Term Purchase Commitment [Line Items]
Total obligation	$ 56.5
Future commitments
2023	19.6
2024	19.6
2025	$ 17.3

PROPERTY, PLANT AND EQUIPMENT_3

PROPERTY, PLANT AND EQUIPMENT - Jointly Owned Facilities (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service	$ 922,381
Accumulated Depreciation	603,248
Construction Work In Progress	$ 2,784
Yampa
Jointly Owned Utility Plant Interests [Line Items]
Tri-State share (as a percent)	24%
Electric Plant in Service	$ 391,689
Accumulated Depreciation	261,366
Construction Work In Progress	$ 163
MBPP
Jointly Owned Utility Plant Interests [Line Items]
Tri-State share (as a percent)	28.50%
Electric Plant in Service	$ 530,692
Accumulated Depreciation	341,882
Construction Work In Progress	$ 2,621

PROPERTY, PLANT AND EQUIPMENT_4

PROPERTY, PLANT AND EQUIPMENT - Other Plant (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Other Plant Assets
Other plant assets	$ 954,144	$ 1,093,922
Less allowances for depreciation, amortization and depletion	(694,774)	(823,087)
Net other plant	259,370	270,835
Mine assets
Other Plant Assets
Less allowances for depreciation, amortization and depletion	(155,653)	(133,951)
Net other plant	237,240	247,978
Mine assets | Colowyo Mine
Other Plant Assets
Other plant assets	386,898	376,868
Mine assets | New Horizon Mine
Other Plant Assets
Other plant assets	5,995	5,061
Non-utility assets
Other Plant Assets
Other plant assets	561,251	711,993
Less allowances for depreciation, amortization and depletion	(539,121)	(689,136)
Net other plant	$ 22,130	$ 22,857
Elk Ridge
Property, Plant and Equipment [Line Items]
Ownership interest held by parent (as a percent)	100%

ASSET RETIREMENT AND ENVIRONM_3

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS - Narrative (Details) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2022 USD ($)	Dec. 31, 2022 USD ($) asset_retirement_obligation pit
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies [Line Items]
Number of coal mine asset retirement obligations revised | asset_retirement_obligation		2
Increase (decrease) in asset retirement obligations		$ 36.8
Environmental Loss Contingency, Statement Of Financial Position, Extensible Enumeration, Not Disclosed Flag		environmental remediation liability
Colowyo Mine Pit - Final Reclamation
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies [Line Items]
Number of mine pits in final reclamation | pit		1
Increase (decrease) in asset retirement obligations		$ (1.4)
Colowyo Mine Pits - Actively Mined
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies [Line Items]
Increase (decrease) in asset retirement obligations		12.1
New Horizon Mine
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies [Line Items]
Increase (decrease) in environmental reclamation obligations	$ 44.9
Environmental reclamation obligations		67.3
Discounted basis of environmental reclamation obligation		$ 36.8
Discount rate of environmental reclamation obligations (as a percent)		3.25%
Undiscounted future cash outflows of environmental reclamation obligations		$ 57.9

ASSET RETIREMENT AND ENVIRONM_4

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS - Summary (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation and Accrual for Environmental Loss Contingencies [Roll Forward]
Obligations at beginning of period	$ 90,281	$ 138,089
Liabilities incurred	0	1,475
Liabilities settled	(3,184)	(4,934)
Accretion expense	6,163	2,409
Change in estimate	93,747	(46,758)
Total obligations at end of period	187,007	90,281
Less current obligations at end of period	(5,419)	(7,003)
Long-term obligations at end of period	$ 181,588	$ 83,278

CONTRACT ASSETS AND CONTRACT _3

CONTRACT ASSETS AND CONTRACT LIABILITIES (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Contract assets	$ 0	$ 0
Accounts receivable
Accounts receivable—Members	103,246,000	95,630,000
Other accounts receivable	32,436,000	21,571,000
Contract liabilities
Contract liabilities (unearned revenue)	5,123,000	5,372,000
Other accounts receivable - trade
Accounts receivable
Other accounts receivable	26,354,000	19,189,000
Other accounts receivable - trade | Non-member electric sales
Accounts receivable
Other accounts receivable	17,213,000	5,684,000
Other accounts receivable - trade | Other
Accounts receivable
Other accounts receivable	9,141,000	13,505,000
Other accounts receivable - nontrade
Accounts receivable
Other accounts receivable	6,082,000	$ 2,382,000
Other operating revenue
Accounts, Notes, Loans and Financing Receivable [Line Items]
Contract liabilities recognized	$ 800,000

LONG-TERM DEBT - Narrative (Det

LONG-TERM DEBT - Narrative (Details) $ in Thousands			12 Months Ended
	Oct. 03, 2022	Jul. 26, 2022 USD ($)	Dec. 31, 2022 USD ($) note	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Debt Instrument [Line Items]
Long-term debt			$ 2,869,963	$ 3,101,870
Number of unsecured debt instruments | note			1
Unsecured notes			$ 4,100
Outstanding borrowings			2,981,481	3,214,427
Aggregate payment for purchase of debt			232,946	94,288	$ 282,757
2022 Revolving Credit Agreement | Commercial Paper
Debt Instrument [Line Items]
Available borrowing capacity			226,000
2022 Revolving Credit Agreement | Line of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity			520,000
Outstanding borrowings			0
Available borrowing capacity			246,000
Series B, 7.14%, due through 2033
Debt Instrument [Line Items]
Outstanding borrowings			$ 248,601	292,985
Stated interest rate (as a percent)			7.14%
Moffat County, CO, 2.90% term rate through October 2027, Series 2009, due 2036
Debt Instrument [Line Items]
Outstanding borrowings			$ 46,800	46,800
Stated interest rate (as a percent)			2.90%
Moffat County, CO, 2.90% term rate through October 2027, Series 2009, due 2036 | Secured Debt
Debt Instrument [Line Items]
Term of debt instrument	5 years
Stated interest rate (as a percent)	2.90%
First Mortgage Bonds, Series 2014E-1, 3.70% due 2024
Debt Instrument [Line Items]
Outstanding borrowings			$ 128,002	$ 244,714
Stated interest rate (as a percent)			3.70%
First Mortgage Bonds, Series 2014E-1, 3.70% due 2024 | Secured Debt
Debt Instrument [Line Items]
Aggregate amount of tender offer		$ 100,000
Aggregate payment for purchase of debt		$ 100,200
Minimum
Debt Instrument [Line Items]
Equity to capitalization ratio (ECR) requirement (as a percent)			18%
Debt service ratio (DSR) requirement			1.025
Minimum | All Other Long-Term Debt
Debt Instrument [Line Items]
Debt service ratio (DSR) requirement			1.10
Minimum | Series B, 7.14%, due through 2033 | Mortgages
Debt Instrument [Line Items]
Debt service ratio (DSR) requirement			1.02

LONG-TERM DEBT - Summary (Detai

LONG-TERM DEBT - Summary (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Long-term debt, components
Total debt	$ 2,981,481	$ 3,214,427
Less debt issuance costs	(21,481)	(23,110)
Less debt discounts	(8,960)	(9,398)
Plus debt premiums	11,843	12,990
Total debt adjusted for debt issuance costs, discounts and premiums	2,962,883	3,194,909
Less current maturities	(92,920)	(93,039)
Long-term debt	2,869,963	3,101,870
2.32% to 3.66% CFC, due through 2028
Long-term debt, components
Total debt	$ 85,855	106,182
2.32% to 3.66% CFC, due through 2028 | Minimum
Interest rate terms
Stated interest rate (as a percent)	2.32%
2.32% to 3.66% CFC, due through 2028 | Maximum
Interest rate terms
Stated interest rate (as a percent)	3.66%
2.63% to 4.43% CoBank, ACB, due through 2042
Long-term debt, components
Total debt	$ 174,985	204,163
2.63% to 4.43% CoBank, ACB, due through 2042 | Minimum
Interest rate terms
Stated interest rate (as a percent)	2.63%
2.63% to 4.43% CoBank, ACB, due through 2042 | Maximum
Interest rate terms
Stated interest rate (as a percent)	4.43%
First Mortgage Obligations, Series 2017A, Tranche 1, 3.34%, due through 2029
Long-term debt, components
Total debt	$ 60,000	60,000
Interest rate terms
Stated interest rate (as a percent)	3.34%
First Mortgage Obligations, Series 2017A, Tranche 2, 3.39%, due through 2029
Long-term debt, components
Total debt	$ 60,000	60,000
Interest rate terms
Stated interest rate (as a percent)	3.39%
First Mortgage Bonds, Series 2016A, 4.25% due 2046
Long-term debt, components
Total debt	$ 228,783	250,000
Interest rate terms
Stated interest rate (as a percent)	4.25%
First Mortgage Bonds, Series 2014E-1, 3.70% due 2024
Long-term debt, components
Total debt	$ 128,002	244,714
Interest rate terms
Stated interest rate (as a percent)	3.70%
First Mortgage Bonds, Series 2014E-2, 4.70% due 2044
Long-term debt, components
Total debt	$ 250,000	250,000
Interest rate terms
Stated interest rate (as a percent)	4.70%
First Mortgage Bonds, Series 2010A, 6.00% due 2040
Long-term debt, components
Total debt	$ 499,805	500,000
Interest rate terms
Stated interest rate (as a percent)	6%
First Mortgage Obligations, Series 2014B, Tranche 1, 3.90%, due through 2033
Long-term debt, components
Total debt	$ 180,000	180,000
Interest rate terms
Stated interest rate (as a percent)	3.90%
First Mortgage Obligations, Series 2014B, Tranche 2, 4.30%, due through 2039
Long-term debt, components
Total debt	$ 20,000	20,000
Interest rate terms
Stated interest rate (as a percent)	4.30%
First Mortgage Obligations, Series 2014B, Tranche 3, 4.45%, due through 2045
Long-term debt, components
Total debt	$ 550,000	550,000
Interest rate terms
Stated interest rate (as a percent)	4.45%
Variable rate CFC, as determined by CFC, due through 2026
Long-term debt, components
Total debt	$ 0	324
Variable rate CFC, LIBOR-based term loan, due through 2049
Long-term debt, components
Total debt	152,220	152,220
Variable rate CoBank, ACB, LIBOR-based term loans, due through 2044
Long-term debt, components
Total debt	296,430	297,039
Moffat County, CO, 2.90% term rate through October 2027, Series 2009, due 2036
Long-term debt, components
Total debt	$ 46,800	46,800
Interest rate terms
Stated interest rate (as a percent)	2.90%
Series B, 7.14%, due through 2033
Long-term debt, components
Total debt	$ 248,601	$ 292,985
Interest rate terms
Stated interest rate (as a percent)	7.14%

LONG-TERM DEBT - Annual Maturit

LONG-TERM DEBT - Annual Maturities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Annual maturities of total debt adjusted for debt issuance costs, discounts and premiums
2023	$ 92,920
2024	223,835
2025	88,819
2025	90,440
2027	92,323
Thereafter	2,374,546
Total debt adjusted for debt issuance costs, discounts and premiums	2,962,883	$ 3,194,909
First Mortgage Bonds, Series 2014E-1, 3.70% due 2024 | Secured Debt
Annual maturities of total debt adjusted for debt issuance costs, discounts and premiums
2025	$ 128,000

SHORT-TERM BORROWINGS (Details)

SHORT-TERM BORROWINGS (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Short-Term Debt [Line Items]
Amount outstanding	$ 274,102	$ 49,997
Commercial Paper
Short-Term Debt [Line Items]
Amount outstanding	$ 274,102	$ 49,997
Weighted average interest rate (as a percent)	4.61%	0.20%
2022 Revolving Credit Agreement | Commercial Paper
Short-Term Debt [Line Items]
Maximum amount per commercial paper sublimit	$ 500,000
Available borrowing capacity	$ 226,000
2022 Revolving Credit Agreement | Commercial Paper | Maximum
Short-Term Debt [Line Items]
Term of issuance	397 days

FAIR VALUE (Details)

FAIR VALUE (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 101,800	$ 95,300
Principal Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	2,981,481	3,214,427
Principal Amount | EBT Trust Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	10,604	8,850
Principal Amount | Director and Executive Elective Deferred Compensation Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	558	597
Estimated Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	2,725,606	3,759,991
Estimated Fair Value | EBT Trust Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	9,808	8,640
Estimated Fair Value | Director and Executive Elective Deferred Compensation Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	$ 489	$ 598

INCOME TAXES - Narrative (Detai

INCOME TAXES - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Current income tax expense (benefit)	$ 0	$ 0
Deferred income tax expense (benefit)	$ (0.2)	$ 0.3

INCOME TAXES - Net Deferred Tax

INCOME TAXES - Net Deferred Tax Liability (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Deferred tax assets
Net operating loss carryforwards	$ 165,636	$ 144,602
Operating lease liabilities	105,039	114,237
Deferred revenues and membership withdrawal	16,028	38,784
Safe harbor lease receivables	8,939	8,135
Other	43,795	30,578
Deferred tax assets, gross	339,437	336,336
Less valuation allowance	0	0
Deferred tax assets, net	339,437	336,336
Deferred tax liabilities
Basis differences- property, plant and equipment and other	166,568	159,696
Operating lease right-of-use assets	125,939	130,111
Capital credits from other associations	34,236	31,622
Deferred debt prepayment transaction costs	27,381	29,434
Other	4,588	4,460
Deferred tax liabilities, total	358,712	355,323
Net deferred tax liability	(19,275)	(18,987)
Deferred tax treatment of regulatory assets
Decrease in net deferred tax liabilities	300
Regulatory assets	650,421	665,693
Deferred Income Tax Expense
Deferred tax treatment of regulatory assets
Regulatory assets	$ 19,279	$ 18,742

INCOME TAXES - Effective Income

INCOME TAXES - Effective Income Tax Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Effective income tax reconciliation:
Pretax GAAP income at Federal statutory rate	$ 0	$ 5,435	$ 5,271
Pretax GAAP income at State statutory rate, net of federal benefit	0	725	703
Patronage exclusion	0	(6,159)	(5,974)
Asset retirement and environmental reclamation obligations	16,655	10,917	(14,230)
Deferred revenues and membership withdrawal	(22,759)	18,673	(29,519)
Operating liabilities, net of right-of-use assets	(4,919)	1,165	5,277
Valuation Allowance	0	0	(30,468)
Net operating loss carryforward	21,034	(27,539)	367
Other items, net	(9,445)	(2,531)	17,543
Impairment	0	0	20,554
Regulatory treatment of deferred taxes	(815)	(391)	29,942
Total deferred income tax expense (benefit)	$ (249)	$ 295	$ (534)

INCOME TAXES - Operating Loss a

INCOME TAXES - Operating Loss and Tax Credit Carryforwards (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Carryforwards
Taxable loss	$ 93.1
Federal
Carryforwards
Net operating loss carryforwards	696
Net operating loss carryforwards, subject to expiration	444.5
Net operating loss carryforwards, not subject to expiration	251.5
State
Carryforwards
Net operating loss carryforwards	438.2
Net operating loss carryforwards, subject to expiration	405.1
Net operating loss carryforwards, not subject to expiration	$ 33.1

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) $ in Thousands	1 Months Ended	12 Months Ended
	Dec. 31, 2022 USD ($) $ / MWh	Dec. 31, 2022 USD ($) billing_component utility_member demand_rate $ / MWh	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Sep. 30, 2022 USD ($)	Aug. 31, 2020 $ / MWh
Disaggregation of Revenue [Line Items]
Number of utility members | utility_member		42
Number of billing components of Class A rate schedule for electric power sales to Members | billing_component		3
Number of demand rates | demand_rate		2
Accrual for provision for rate refund					$ 2,000
Rate refunds distributed during period	$ 2,700
Soft-cap price for short term spot market sales (per megawatt hour) | $ / MWh	1,000	1,000				1,000
Member electric sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		$ 1,213,234	$ 1,161,291	$ 1,196,232
Rate stabilization
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		95,613	$ 78,457	$ 12,136
United Power, Inc.
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		$ 223,600
United Power, Inc. | Revenue Benchmark | Customer Concentration
Disaggregation of Revenue [Line Items]
Concentration risk (as a percent)		14.70%
United Power, Inc. | Member electric sales | Revenue Benchmark | Customer Concentration
Disaggregation of Revenue [Line Items]
Concentration risk (as a percent)		18.40%

REVENUE - Summary (Details)

REVENUE - Summary (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of revenue
Other		$ 61,420	$ 56,341	$ 53,545
Operating revenues		1,533,571	1,400,801	1,352,295
Non-member electric sales and other operating revenue
Disaggregation of revenue
Operating revenues		320,337	239,510	156,063
Non-member electric sales
Disaggregation of revenue
Revenue from contract with customer		163,355	114,908	90,382
Non-member electric sales | Long-term contracts
Disaggregation of revenue
Revenue from contract with customer		56,570	44,383	46,172
Non-member electric sales | Short-term contracts
Disaggregation of revenue
Revenue from contract with customer		106,785	70,525	44,210
Rate stabilization
Disaggregation of revenue
Revenue from contract with customer		95,613	78,457	12,136
Provision for rate refunds
Disaggregation of revenue
Revenue from contract with customer	$ 2,900	(51)	(10,196)	0
Coal Sales
Disaggregation of revenue
Revenue from contract with customer		7,021	4,951	7,326
Other
Disaggregation of revenue
Other		$ 54,399	$ 51,390	$ 46,219

LEASES - Narrative (Details)

LEASES - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) finance_lease	Dec. 31, 2021 USD ($)
Leases [Abstract]
Operating lease expense	$ 2.7	$ 3.5
Number of finance leases | finance_lease	0
Lease revenue	$ 7.1	$ 7.3

LEASES - Lease Components (Deta

LEASES - Lease Components (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating lease right-of-use assets	$ 8,784	$ 9,081
Less: Accumulated amortization	(2,013)	(1,552)
Net operating lease right-of-use assets	6,771	7,529
Operating lease liabilities – current	(441)	(491)
Operating lease liabilities – noncurrent	(1,251)	(1,622)
Total operating lease liabilities	$ (1,692)	$ (2,113)
Weighted average remaining lease term (years)	7 years 7 months 6 days	7 years 7 months 6 days
Weighted average discount rate (as a percent)	3.87%	3.79%
Operating lease right-of-use asset, Statement of Financial Position line item	Other	Other
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accrued expenses	Accrued expenses
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other	Other

LEASES - Future Minimum Lease C

LEASES - Future Minimum Lease Commitments (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Year 1	$ 386
Year 2	342
Year 3	151
Year 4	431
Year 5	94
Thereafter	549
Total lease payments	1,953
Less imputed interest	(261)
Total	$ 1,692	$ 2,113

EMPLOYEE BENEFIT PLANS - Define

EMPLOYEE BENEFIT PLANS - Defined Benefit Plan (Details) $ in Millions		1 Months Ended	12 Months Ended
	Jan. 01, 2013	May 31, 2013 USD ($)	Dec. 31, 2022 USD ($) employee	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Jan. 01, 2022	Jan. 01, 2021
Defined Benefit Plan Disclosure [Line Items]
Number of employees			1,105
RS Plan | Multiemployer Plans, Pension
Defined Benefit Plan Disclosure [Line Items]
Employer contributions to plan | $			$ 25.2	$ 26.7	$ 27.5
Funded amount (as a percent)						80%	80%
RS Plan Contribution Prepayment Option | Multiemployer Plans, Pension
Defined Benefit Plan Disclosure [Line Items]
Prepayment amount, multiple of annual required contribution	2.5
Reduction in the annual contribution (as a percent)	25%
Reduced annual contribution period			15 years
Contribution prepayment | $		$ 71.2
Amortization period of prepayment	13 years
Collective bargaining agreements and their bargaining unit employees
Defined Benefit Plan Disclosure [Line Items]
Number of employees			215
Maximum | Non-bargaining unit employees, Colowyo Coal employees
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution, maximum proportion of employee contributions (as a percent)			5%	5%	5%
Colowyo Coal
Defined Benefit Plan Disclosure [Line Items]
Number of employees			191

EMPLOYEE BENEFIT PLANS - Postre

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other than Pensions, Plans, Amendments and Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Threshold for unrecognized amount of actuarial gains and losses as a proportion of projected benefit obligation (as a percent)	10%
Executive Benefit Restoration Plan
Postretirement medical benefit and postemployment medical benefit obligations
Executive benefit restoration/ postretirement and/or postemployment medical obligations at beginning of period	$ 9,852	$ 7,379
Service cost	468	440
Interest cost	300	205
Plan amendments	308	1,050
Curtailment	(292)	0
Benefit payments	(110)	0
Actuarial (gain) loss	(2,041)	778
Executive benefit restoration/ postretirement and/or postemployment medical obligations at end of period	8,485	9,852
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of year	8,640	6,955
Employer contributions	1,734	1,762
Benefits paid	(109)	0
Actual return on plan assets	(457)	(77)
Fair value of plan assets at end of year	9,808	8,640
Net (asset) liability recognized	(1,323)	1,212
Medical Plans
Postretirement medical benefit and postemployment medical benefit obligations
Executive benefit restoration/ postretirement and/or postemployment medical obligations at beginning of period	3,228
Executive benefit restoration/ postretirement and/or postemployment medical obligations at end of period	2,189	3,228
Postretirement Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
Executive benefit restoration/ postretirement and/or postemployment medical obligations at beginning of period	2,809	9,985
Interest cost	47	36
Plan amendments	0	(5,698)
Benefit payments	(732)	(730)
Actuarial (gain) loss	(32)	(784)
Executive benefit restoration/ postretirement and/or postemployment medical obligations at end of period	2,092	2,809
Postemployment Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
Executive benefit restoration/ postretirement and/or postemployment medical obligations at beginning of period	419
Executive benefit restoration/ postretirement and/or postemployment medical obligations at end of period	$ 97	$ 419

EMPLOYEE BENEFIT PLANS - Post_2

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other than Pensions, Actuarial Gains and Losses, and Assumptions (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Executive Benefit Restoration Plan
Net unrecognized actuarial gains and losses related to the postretirement medical benefit obligation are included in accumulated other comprehensive income
Amounts included in accumulated other comprehensive income at beginning of period	$ (4,932)	$ (4,873)
Plan amendments - prior service cost	(308)	(1,050)
Amortization of prior service credit into other income	1,156	1,113	$ 1,912
Amortization of actuarial (gain) loss	426	515	0
Curtailment and settlement	(187)	141	0
Unrecognized actuarial gain (loss)	1,740	(778)	(1,980)
Amounts included in accumulated other comprehensive income at end of period	(2,105)	(4,932)	(4,873)
Postretirement Medical Benefit Plans
Net unrecognized actuarial gains and losses related to the postretirement medical benefit obligation are included in accumulated other comprehensive income
Amounts included in accumulated other comprehensive income at beginning of period	3,580	(841)
Amortization of prior service credit into other income	(1,636)	(2,139)	(79)
Amortization of actuarial (gain) loss	102	78	0
Unrecognized actuarial gain (loss)	32	784	625
Plan amendments	0	5,698
Amounts included in accumulated other comprehensive income at end of period	$ 2,078	$ 3,580	$ (841)
Assumptions used
Weighted-average discount rate (as a percent)	1.82%
Initial health care cost trend (2018) (as a percent)	7%
Ultimate health care cost trend (as a percent)	4.50%
Year that the rate reached the ultimate health care cost trend rate	2027
Average remaining service lives of active plan participants (years)	2 years 11 months 26 days

EMPLOYEE BENEFIT PLANS - Defi_2

EMPLOYEE BENEFIT PLANS - Defined Contribution Plans (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) plan	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
401(k) Plan
Defined Contribution Plan Disclosure [Line Items]
Number of plans	1
Employee contribution, maximum proportion of eligible earnings (as a percent)	75%
Employer contributions made | $	$ 3.9	$ 3.3	$ 3.5
409(a) Plan | Hired After May 1, 2021
Defined Contribution Plan Disclosure [Line Items]
Maximum employer contribution (as a percent)	10%
Non-bargaining unit employees, excluding Colowyo Coal employees | 401(k) Plan | Hired Prior To May 1, 2021
Defined Contribution Plan Disclosure [Line Items]
Employer contribution, maximum proportion of eligible earnings (as a percent)	1%
Non-bargaining unit employees, excluding Colowyo Coal employees | 401(k) Plan | Hired After May 1, 2021
Defined Contribution Plan Disclosure [Line Items]
Maximum employer contribution (as a percent)	10%
Non-bargaining unit employees, Colowyo Coal employees | Maximum
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, maximum proportion of employee contributions (as a percent)	5%	5%	5%
Non-bargaining unit employees, Colowyo Coal employees | 401(k) Plan
Defined Contribution Plan Disclosure [Line Items]
Number of plans	1
Non-bargaining unit employees, Colowyo Coal employees | 401(k) Plan | Hired Prior To May 1, 2021
Defined Contribution Plan Disclosure [Line Items]
Employer contribution, maximum proportion of eligible earnings (as a percent)	7%
Maximum employer contribution (as a percent)	10%
Non-bargaining unit employees, Colowyo Coal employees | 401(k) Plan | Maximum | Hired Prior To May 1, 2021
Defined Contribution Plan Disclosure [Line Items]
Employer matching contribution, maximum proportion of employee contributions (as a percent)	5%

EMPLOYEE BENEFIT PLANS - Post_3

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other than Pensions (Details) - Non-bargaining unit employees	12 Months Ended
	Dec. 31, 2022 plan
Medical Plans
Defined Contribution Plan Disclosure [Line Items]
Number of plans	3
Postretirement Medical Benefit Plans
Defined Contribution Plan Disclosure [Line Items]
Number of plans	2
Postemployment Medical Benefit Plans
Defined Contribution Plan Disclosure [Line Items]
Number of plans	3

EMPLOYEE BENEFIT PLANS - Expect

EMPLOYEE BENEFIT PLANS - Expected Future Benefits (Details) - Postretirement Medical Benefit Plans $ in Thousands	Dec. 31, 2022 USD ($)
Defined Contribution Plan Disclosure [Line Items]
2023	$ 576,432
2024	482,090
2025	379,064
2026	298,176
2027	200,190
2028 through 2032	362,795
Total	$ 2,298,747

VARIABLE INTEREST ENTITIES (Det

VARIABLE INTEREST ENTITIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Variable Interest Entity [Line Items]
Net electric plant	$ 3,348,615	$ 3,347,171
Noncontrolling interest	126,180	119,100
Long-term debt	2,869,963	3,101,870
Accrued interest	$ 25,431	25,716
Springerville Partnership
Variable Interest Entity [Line Items]
Equity interest (as a percent)	51%
General partner interest (as a percent)	1%
Variable Interest Entity, Primary Beneficiary | Springerville Unit 3 Lease
Variable Interest Entity [Line Items]
Proportion of financial and other support provided (as a percent)	100%
Variable Interest Entity, Primary Beneficiary | Springerville Unit 3 Holding LLC
Variable Interest Entity [Line Items]
Ownership interest held by parent (as a percent)	100%
Variable Interest Entity, Primary Beneficiary | Reportable Legal Entities
Variable Interest Entity [Line Items]
Net electric plant	$ 721,997	740,135
Noncontrolling interest	126,180	119,101
Long-term debt	254,876	300,220
Accrued interest	7,400	8,721
Depreciation, amortization and depletion	18,138	18,138	$ 18,138
Interest	$ 17,064	$ 20,038	$ 22,798
Other Limited Partners | Springerville Partnership
Variable Interest Entity [Line Items]
Ownership interest held by noncontrolling interest (as a percent)	49%

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - Sales Commitments (Details)	12 Months Ended
	Dec. 31, 2022 MW
Salt River Project Agricultural Improvement and Power District | Supply Contracts
Supply Commitment [Line Items]
Megawatts	100

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - Coal Purchase Requirements (Details) - Coal - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Annual minimum coal purchases under contracts
2023	$ 30,627
2024	23,217
2025	10,113
2026	6,882
2027	6,825
Thereafter	88,247
Total obligation	165,911
Purchases during the period	$ 124,000	$ 97,900	$ 101,200

COMMITMENTS AND CONTINGENCIES_3

COMMITMENTS AND CONTINGENCIES - Electric Power Purchase Agreements (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) contract MW	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
WAPA
Long-Term Contract for Purchase of Electric Power [Line Items]
Costs under electric power purchase agreements | $	$ 67,791	$ 70,107	$ 72,491
Basin Electric Power Cooperative
Long-Term Contract for Purchase of Electric Power [Line Items]
Number of contracts	2
Costs under electric power purchase agreements | $	$ 148,146	146,532	152,461
Other Renewables
Long-Term Contract for Purchase of Electric Power [Line Items]
Megawatts purchased | MW	1,521
Costs under electric power purchase agreements | $	$ 85,601	$ 71,565	$ 69,255
Wind-based Power
Long-Term Contract for Purchase of Electric Power [Line Items]
Megawatts purchased | MW	674
Solar-based Power
Long-Term Contract for Purchase of Electric Power [Line Items]
Megawatts purchased | MW	820
Loveland Area Projects | WAPA
Long-Term Contract for Purchase of Electric Power [Line Items]
Number of contracts	2
Loveland Area Projects, Contract Terminating 2024 | WAPA
Long-Term Contract for Purchase of Electric Power [Line Items]
Number of contracts	1
Loveland Area Projects, Contract Terminating 2054 | WAPA
Long-Term Contract for Purchase of Electric Power [Line Items]
Number of contracts	1
Eastern Interconnection | Basin Electric Power Cooperative
Long-Term Contract for Purchase of Electric Power [Line Items]
Number of contracts	1
Western Interconnection | Basin Electric Power Cooperative
Long-Term Contract for Purchase of Electric Power [Line Items]
Number of contracts	1
Salt Lake City Area Integrated Projects | WAPA
Long-Term Contract for Purchase of Electric Power [Line Items]
Number of contracts	3
Salt Lake City Area Integrated Projects, Contracts Terminating 2024 | WAPA
Long-Term Contract for Purchase of Electric Power [Line Items]
Number of contracts	2
Salt Lake City Area Integrated Projects, Contract Terminating 2057 | WAPA
Long-Term Contract for Purchase of Electric Power [Line Items]
Number of contracts	1

COMMITMENTS AND CONTINGENCIES_4

COMMITMENTS AND CONTINGENCIES - Legal (Details) $ in Millions	1 Months Ended		3 Months Ended
	Feb. 28, 2023 USD ($)	Dec. 31, 2022 USD ($) $ / MWh	Jun. 30, 2022 USD ($)	Mar. 01, 2022	Mar. 01, 2021	Aug. 31, 2020 $ / MWh
Other Commitments [Line Items]
Rate reduction due to settlement (as a percent)				4%	2%
Rate refunds distributed during period		$ 2.7
Soft-cap price for short term spot market sales (per megawatt hour) | $ / MWh		1,000				1,000
Funds in excess of soft-cap			$ 2.9
Energy sales refunded to third party			$ 0.4
United Power's Adams District Court | Minimum | Subsequent Event
Other Commitments [Line Items]
Damages sought	$ 483
United Power's Adams District Court | Maximum | Subsequent Event
Other Commitments [Line Items]
Damages sought	$ 533