Tri-State Generation & Transmission Association 10-Q 8 Aug 24 2024 Q2 Quarterly report Financial data

Cover

Cover - shares	6 Months Ended
	Jun. 30, 2024	Aug. 08, 2024
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2024
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 Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		0
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	Q2
Entity Central Index Key	0001637880
Amendment Flag	false

Consolidated Statements of Fina

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Jun. 30, 2024	Dec. 31, 2023
Electric plant
In service	$ 5,673,803	$ 5,722,679
Construction work in progress	256,301	163,954
Total electric plant	5,930,104	5,886,633
Less allowances for depreciation and amortization	(2,772,281)	(2,739,924)
Net electric plant	3,157,823	3,146,709
Other plant	950,982	952,318
Less allowances for depreciation, amortization and depletion	(726,882)	(711,896)
Net other plant	224,100	240,422
Total property, plant and equipment	3,381,923	3,387,131
Other assets and investments
Investments in other associations	185,673	187,684
Investments in and advances to coal mines	1,715	1,619
Restricted cash and investments	172,252	3,408
Other noncurrent assets	14,579	15,264
Total other assets and investments	374,219	207,975
Current assets
Cash and cash equivalents	110,498	106,005
Restricted cash and investments	697	605
Short-term investments	95,000	0
Deposits and advances	79,102	37,455
Accounts receivable—Utility Members	93,883	101,394
Other accounts receivable	27,446	23,123
Coal inventory	71,083	54,979
Materials and supplies	110,450	106,893
Total current assets	588,159	430,454
Deferred charges
Regulatory assets	903,354	919,483
Prepayment—NRECA Retirement Security Plan	2,686	5,372
Other	56,579	36,121
Total deferred charges	962,619	960,976
Total assets	5,306,920	4,986,536
Capitalization
Patronage capital equity	887,861	984,581
Accumulated other comprehensive loss	(801)	(839)
Noncontrolling interest	129,738	134,269
Total equity	1,016,798	1,118,011
Long-term debt	2,706,512	2,896,506
Total capitalization	3,723,310	4,014,517
Current liabilities
Utility Member advances	10,656	14,333
Accounts payable	151,507	123,674
Short-term borrowings	116,101	184,305
Accrued expenses	34,317	39,268
Current asset retirement obligations	18,822	21,635
Accrued interest	22,545	24,549
Accrued property taxes	20,437	31,986
Current maturities of long-term debt	191,729	223,523
Total current liabilities	566,114	663,273
Deferred credits and other liabilities
Regulatory liabilities	693,835	2,317
Deferred income tax liability	15,223	15,223
Asset retirement and environmental reclamation obligations	202,982	195,566
Other	94,623	84,125
Total deferred credits and other liabilities	1,006,663	297,231
Accumulated postretirement benefit and postemployment obligations	10,833	11,515
Total equity and liabilities	$ 5,306,920	$ 4,986,536

Consolidated Statements of Oper

Consolidated Statements of Operations (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Operating revenues
Other	$ 23,544	$ 14,686	$ 43,648	$ 32,544
Operating revenues	337,499	318,455	689,048	682,506
Operating expenses
Purchased power	98,840	95,281	191,910	196,106
Fuel	32,208	44,773	108,548	126,703
Production	47,057	54,423	89,183	97,975
Transmission	44,964	46,280	92,522	95,308
General and administrative	23,830	23,577	45,563	42,075
Depreciation, amortization and depletion	44,152	42,690	88,776	85,071
Coal mining	1,027	4,130	2,105	5,769
Other	3,250	2,417	6,200	8,712
Operating expenses	295,328	313,571	624,807	657,719
Operating margins	42,171	4,884	64,241	24,787
Other income
Interest	4,941	1,480	6,440	2,810
Capital credits from cooperatives	0	6	1,281	1,958
Other income	(1,197)	487	4,123	2,042
Total other income	3,744	1,973	11,844	6,810
Interest expense
Interest	45,379	42,602	89,705	83,366
Interest charged during construction	(2,765)	(1,107)	(4,597)	(2,090)
Interest expense, net of amounts capitalized	42,614	41,495	85,108	81,276
Income tax expense	0	23	0	45
Net margins including noncontrolling interest	3,301	(34,661)	(9,023)	(49,724)
Net margin attributable to noncontrolling interest	(2,793)	(2,524)	(5,497)	(4,918)
Net margins attributable to the Association	508	(37,185)	(14,520)	(54,642)
Utility Member electric sales
Operating revenues
Operating revenues	258,286	274,225	554,112	566,401
Non-member electric sales
Operating revenues
Operating revenues	38,768	18,486	74,387	60,436
Rate stabilization
Operating revenues
Operating revenues	16,901	11,064	16,901	22,821
Provision for rate refunds
Operating revenues
Operating revenues	$ 0	$ (6)	$ 0	$ 304

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Net margins including noncontrolling interest	$ 3,301	$ (34,661)	$ (9,023)	$ (49,724)
Other comprehensive income (loss):
Unrealized gain (loss) on securities available for sale	55	(45)	65	16
Other comprehensive income (loss)	148	(166)	38	(225)
Comprehensive income (loss) including noncontrolling interest	3,449	(34,827)	(8,985)	(49,949)
Net comprehensive income attributable to noncontrolling interest	(2,793)	(2,524)	(5,497)	(4,918)
Comprehensive income (loss) attributable to the Association	656	(37,351)	(14,482)	(54,867)
Postretirement Medical Benefit Plans
Other comprehensive income (loss):
Amortization of prior service credit into other income	(127)	(410)	(536)	(819)
Executive Benefit Restoration Plan
Other comprehensive income (loss):
Amortization of prior service credit into other income	$ 220	$ 289	$ 509	$ 578

Consolidated Statements of Equi

Consolidated Statements of Equity (Unaudited) - 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, 2022				$ 984,865	$ (468)			$ 126,180
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net margins attributable to the Association	$ (54,642)			(54,642)
Retirement of patronage capital				0
Unrealized gain (loss) on securities available for sale	16				16
Amortization of prior service credit into other income		$ (819)	$ 578			$ (819)	$ 578
Net comprehensive income attributable to noncontrolling interest	(4,918)							4,918
Equity distribution to noncontrolling interest								(949)
Equity at end of period at Jun. 30, 2023	1,059,679			930,223	(693)			130,149
Equity at beginning of period at Mar. 31, 2023				967,408	(527)			127,625
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net margins attributable to the Association	(37,185)			(37,185)
Retirement of patronage capital				0
Unrealized gain (loss) on securities available for sale	(45)				(45)
Amortization of prior service credit into other income		(410)	289			(410)	289
Net comprehensive income attributable to noncontrolling interest	(2,524)							2,524
Equity distribution to noncontrolling interest								0
Equity at end of period at Jun. 30, 2023	1,059,679			930,223	(693)			130,149
Equity at beginning of period at Dec. 31, 2023	1,118,011			984,581	(839)			134,269
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net margins attributable to the Association	(14,520)			(14,520)
Retirement of patronage capital				(82,200)
Unrealized gain (loss) on securities available for sale	65				65
Amortization of prior service credit into other income		(536)	509			(536)	509
Net comprehensive income attributable to noncontrolling interest	(5,497)							5,497
Equity distribution to noncontrolling interest								(10,028)
Equity at end of period at Jun. 30, 2024	1,016,798			887,861	(801)			129,738
Equity at beginning of period at Mar. 31, 2024				969,553	(949)			126,945
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net margins attributable to the Association	508			508
Retirement of patronage capital				(82,200)
Unrealized gain (loss) on securities available for sale	55				55
Amortization of prior service credit into other income		$ (127)	$ 220			$ (127)	$ 220
Net comprehensive income attributable to noncontrolling interest	(2,793)							2,793
Equity distribution to noncontrolling interest								0
Equity at end of period at Jun. 30, 2024	$ 1,016,798			$ 887,861	$ (801)			$ 129,738

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023
Operating activities
Net margins including noncontrolling interest	$ (9,023)	$ (49,724)
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion	88,776	85,071
Amortization of NRECA Retirement Security Plan prepayment	2,686	2,686
Amortization of debt issuance costs	1,462	1,178
Deposits associated with generator interconnection requests	9,932	11,127
Rate stabilization revenue	(16,901)	(22,821)
Capital credit allocations from cooperatives and income from coal mines under refund distributions	1,914	1,466
Changes in operating assets and liabilities:
Accounts receivable	3,188	24,901
Coal inventory	(16,105)	(9,711)
Materials and supplies	(3,557)	(10,505)
Accounts payable and accrued expenses	(527)	(15,617)
Accrued interest	(2,004)	(2,479)
Accrued property taxes	(11,548)	(15,134)
Deferred membership withdrawal	709,395	0
Other	(14,101)	6,459
Net cash provided by operating activities	743,587	6,897
Investing activities
Purchases of plant	(155,210)	(80,920)
Sale of electric plant	75,000	0
Sale of non-utility assets	3,136	0
Purchase of investments	(95,000)	0
Changes in deferred charges	(5,245)	443
Net cash used in investing activities	(177,319)	(80,477)
Financing activities
Changes in Member advances	(3,677)	(272)
Payments of long-term debt	(222,881)	(69,005)
Proceeds from issuance of long-term debt	0	450,000
Debt issuance costs	(8)	(605)
Change in short-term borrowings, net	(68,304)	(273,502)
Retirement of patronage capital	(87,414)	(5,446)
Equity distribution to noncontrolling interest	(10,028)	(949)
Other	(527)	(482)
Net cash provided by (used in) financing activities	(392,839)	99,739
Net increase in cash, cash equivalents and restricted cash and investments	173,429	26,159
Cash, cash equivalents and restricted cash and investments – beginning	110,018	110,682
Cash, cash equivalents and restricted cash and investments – ending	283,447	136,841
Supplemental cash flow information:
Cash paid for interest	86,937	83,477
Cash paid for income taxes	0	0
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$ (2,769)	$ (1,169)

PRESENTATION OF FINANCIAL INFOR

PRESENTATION OF FINANCIAL INFORMATION	6 Months Ended
	Jun. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
PRESENTATION OF FINANCIAL INFORMATION	PRESENTATION OF FINANCIAL INFORMATION The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. These unaudited consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2023 filed with the SEC. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Our consolidated financial position as of June 30, 2024, results of operations for the three and six months ended June 30, 2024 and 2023, and cash flows for the six months ended June 30, 2024 and 2023 are not necessarily indicative of the results that may be expected for an entire year or any other period. Basis of Consolidation We are 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-one electric distribution member systems who are Class A members to which we provided 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 (A-40) 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. On July 30, 2024, FERC issued an order accepting our A-41 formula rate to our Class A members, effective August 1, 2024, subject to refund. FERC further set our A-41 ra te filing for settlement and hearing procedures and confirmed our accounting treatment, including amortization, and creation of regulatory assets for Escalante Generating Station, Rifle Generating Station, Craig Generating Station Units 2 and 3 and the New Horizon Mine environmental obligation. However, FERC did not currently authorize us to recover the regulatory assets that represent acquisition costs/goodwill for J.M Shafer Generating Station and Colowyo Coal Company LP (“Colowyo Coal”), with an aggregate balance of $68.9 million as of June 30, 2024. These costs were on our books prior to us becoming subject to FERC's jurisdiction. FERC stated in its order accepting our A-41 rate schedule that we did not request express authorization to recover acquisition costs including goodwill in our rates. We are evaluating next steps regarding these costs. On May 1, 2024, United Power, Inc. (“United Power") withdrew from membership in us and terminated its wholesale electric service contract with us pursuant to Rate Schedule 281 ( contract termination payment methodology) on-file with FERC and a Membership Withdrawal Agreement with United Power . United Power’s contract termination payment amount was $709.4 million. United Power paid us an exit fee in cash of $627.2 million, after a regulatory liabilities credit and United Power relinquishing its right to any patronage capital in us resulting in a discounted patronage capital credit of $82.2 million. Such amounts remain subject to true up in accordance with Rate Schedule 281 and United Power's Membership Withdrawal Agreement. On May 8, 2024, we also sold to United Power certain assets for $75.0 million that were primarily used to serve United Power's load after our receipt of approval from FERC on May 1, 2024. Of the total contract termination payment, $530.1 million was membership withdrawal that was deferred as a regulatory liability. The remaining $179.3 million of United Power's contract termination payment related to a transmission credit for the portion of transmission debt allocated to United Power that was deferred as required by FERC's order on our Rate Schedule 281 . For the fiscal year 2023 and the six months ended June 30, 2024, United Power constituted 19.7 percent and 13.7 percent, respectively, of our revenue from our Utility Member sales. We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with GAAP, the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes. The accompanying financial statements reflect the consolidated accounts of Tri-State Generation and Transmission Association, Inc. (“Tri-State”, “we”, “our”, “us” or “the Association”), our wholly-owned and majority-owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 17 – Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. We have eliminated all intercompany balances and transactions in consolidation. Accounting Pronouncement - Not Yet Adopted In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) 2023-09 – Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The purpose of ASU 2023-09 is to enhance the transparency and decision usefulness of income tax disclosures by providing additional information related to the following: (1) Rate reconciliation: ASU 2023-09 requires a tabular rate reconciliation using both percentages and dollar amounts of the reported income tax expense (or benefit) from continuing operations to the product of income (or loss) from continuing operating before income taxes and the applicable statutory federal income tax rate of the county of domicile using specific categories. The following specific categories are required to be disclosed in the rate reconciliation; state and local income tax (qualitative disclosure required for states that make up over 50% of this category), foreign tax effect, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, changes in unrecognized tax benefits, and any other item that meets the 5 percent threshold. (2) Income taxes paid: ASU 2023-09 requires all reporting entities to disclose the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign jurisdictions. It also requires additional disaggregation of income taxes paid to an individual jurisdiction equal to or greater than 5 percent of total income taxes paid (net of refunds). Entities are required to disclose pre-tax income (or loss) from continuing operations disaggregated by domestic and foreign along with income tax expense (or benefit) disaggregated by federal, state, and foreign components. ASU 2023-09 is effective for public business entities for annual periods beginning after December 15, 2024, with early adoption and retrospective or prospective application permitted. We have evaluated the impact of ASU 2023-09 and believe that the adoption of this update will not have a material impact on our consolidated financial statement disclosures.

ACCOUNTING FOR RATE REGULATION

ACCOUNTING FOR RATE REGULATION	6 Months Ended
	Jun. 30, 2024
Regulatory Assets and Liabilities Disclosure [Abstract]
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 that 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): June 30, December 31, Regulatory assets Deferred income tax expense (1) $ 15,223 $ 15,223 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 73,406 74,551 Acquisition costs – J.M. Shafer (3) 36,325 37,749 Acquisition costs – Colowyo Coal (4) 32,545 33,062 Deferred debt prepayment transaction costs (5) 102,103 106,417 Deferred Holcomb expansion impairment loss (6) 72,458 74,795 New Horizon Mine environmental obligation (7) 44,869 44,869 Unrecovered plant (8) 526,425 532,817 Total regulatory assets 903,354 919,483 Regulatory liabilities Interest rate swap - realized gain (9) and other 1,625 1,854 Membership withdrawal (10) 513,699 463 Withdrawal related transmission credit (11) 178,511 — Total regulatory liabilities 693,835 2,317 Net regulatory asset $ 209,519 $ 917,166 (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 through rates. (3) Represents acquisition costs related to our acquisition of an entity that owned J.M. Shafer Generating Station in December 2011. Acquisition costs are 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 through rates. (4) Represents acquisition costs related to our acquisition of Colowyo Coal in December 2011. Acquisition costs are 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 through 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 through 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 depreciation, amortization and depletion expense in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members through rates. (7) Represents $44.9 million of New Horizon Mine environmental obligation expense that was recognized as a regulatory item in 2023. The regulatory asset for the deferred environmental obligation expense will be amortized to expense in the amount of $1.8 million annually over 25 years. (8) Represents deferral of the impairment losses and other closure costs related to the early retirement of the Escalante, Rifle and Craig Generating Station Units 2 and 3. 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 the Escalante Generating Station, and recovered from our Utility Members through rates. The deferred impairment loss for Rifle Generating Station 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. We recognized the early retirement of Craig Generating Station Units 2 and 3 and concluded the impairment of incurred costs is probable of recovery through future rates. We recognized an impairment loss of $261.6 million and deferred the loss in accordance with accounting for rate regulation. The deferred impairment loss will be amortized to depreciation, amortization and depletion expense beginning in October 2028 through 2039 for Craig Generating Station Unit 2 and January 2030 through 2043 for Craig Generating Station Unit 3. These amortization periods are the depreciable lives of Craig Generating Station Unit 2 and 3. The annual amortization is expected to approximate the former annual Craig Generation Station Unit 2 and 3 depreciation for the remaining life of the asset. (9) 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. (10) Represents the remaining balance of the deferred recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. On May 1, 2024, United Power withdrew from membership in us and terminated its wholesale electric service contract with us pursuant to Rate Schedule 281 on-file with FERC and a Membership Withdrawal Agreement. United Power's contract termination payment amount was $709.4 million, of which $530.1 million was membership withdrawal that was deferred by our Board as a regulatory liability. The deferred membership withdrawal will be refunded to Utility Members through reduced rates when recognized in operating revenues in future periods with the oldest vintage year used first. (11) Represents the remaining $179.3 million of United Power's transmission credit related to taking transmission service from us. A portion of a withdrawing member's contract termination payment is allocated to transmission debt that is deferred as required by FERC's order on Rate Schedule 281. The transmission credit, plus interest at FERC's prescribed interest rate, is refunded to the withdrawing member on a monthly basis if the withdrawing member takes transmission service from us and amortized on a straight-line basis over the remaining term. If the withdrawing member's transmission bill for a given month is lower than the credit amount that would be due, the difference is forfeited by the withdrawing member.

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	6 Months Ended
	Jun. 30, 2024
Public Utilities, Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Our 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 : As of June 30, 2024, 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 % $ 3,089,810 $ (1,699,258) $ 1,390,552 Transmission plant 1.11 % to 2.09 % 1,895,240 (701,422) 1,193,818 General plant 1.46 % to 9.53 % 448,016 (274,586) 173,430 Other 2.75 % to 10.00 % 240,737 (97,015) 143,722 Electric plant in service (at cost) $ 5,673,803 $ (2,772,281) 2,901,522 Construction work in progress 256,301 Electric plant $ 3,157,823 In March 2024, we executed an asset purchase agreement to purchase the 145 MW Axial Basin Solar project being developed in northwestern Colorado. Concurrent with execution of the purchase agreement, we also executed an engineering, procurement and construction contract with an affiliate of the developer of the project. In April 2024, we closed on the acquisition of Axial Basin Solar project and issued a notice to proceed with construction to the contractor. In April 2024, we executed an asset purchase agreement to purchase the 110 MW Dolores Canyon Solar project being developed in southwestern Colorado. Concurrent with execution of the purchase agreement, we also executed an engineering, procurement and construction contract with an affiliate of the developer of the project. In May 2024, we closed on the acquisition of Dolores Canyon Solar project and issued a notice to proceed with construction to the contractor. Both acquisitions were accounted for as an asset acquisition in accordance with the accounting requirements for business combinations since we purchased the project assets and not a business. As such, the asset acquisitions and subsequent facility development costs are being capitalized which is included in construction work in progress as of June 30, 2024. Both projects are expected to achieve commercial operation in the second half of 2025. As of December 31, 2023, 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 % $ 3,082,133 $ (1,669,941) $ 1,412,192 Transmission plant 1.11 % to 2.09 % 1,983,629 (708,412) 1,275,217 General plant 1.46 % to 9.53 % 410,856 (266,013) 144,843 Other 2.75 % to 10.00 % 246,061 (95,558) 150,503 Electric plant in service (at cost) $ 5,722,679 $ (2,739,924) 2,982,755 Construction work in progress 163,954 Electric plant $ 3,146,709 JOINTLY OWNED FACILITIES : Our share in each jointly owned facility is as follows as of June 30, 2024 (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 % $ 392,510 $ 362,750 $ — MBPP - Laramie River Station 28.50 % 537,127 349,594 7,047 Total $ 929,637 $ 712,344 $ 7,047 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): June 30, December 31, Colowyo Mine assets $ 395,438 $ 396,441 New Horizon Mine assets 6,320 6,448 Accumulated depreciation and depletion (199,278) (184,239) Net mine assets 202,480 218,650 Non-utility assets 549,224 549,430 Accumulated depreciation (527,604) (527,658) Net non-utility assets 21,620 21,772 Net other plant $ 224,100 $ 240,422

INVESTMENTS IN OTHER ASSOCIATIO

INVESTMENTS IN OTHER ASSOCIATIONS	6 Months Ended
	Jun. 30, 2024
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
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): June 30, December 31, Basin Electric Power Cooperative $ 135,652 $ 135,652 National Rural Utilities Cooperative Finance Corporation - patronage capital 12,451 12,451 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,054 15,054 CoBank, ACB 16,946 18,809 Other 5,570 5,718 Investments in other associations $ 185,673 $ 187,684 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 the six months ended June 30, 2024 or during 2023.

CASH, CASH EQUIVALENTS AND REST

CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS	6 Months Ended
	Jun. 30, 2024
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents [Abstract]
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 are amounts that have been restricted by contract that are expected to be settled within one year. These funds are therefore classified as current on our consolidated statements of financial position. The other funds are for amounts restricted by contract or other legal reasons that are expected to be settled beyond one year. These funds are classified as noncurrent and are included in other assets and investments on our consolidated statements of financial position. 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): June 30, December 31, Cash and cash equivalents $ 110,498 $ 106,005 Restricted cash and investments - current 697 605 Restricted cash and investments - noncurrent (1) 172,252 3,408 Cash, cash equivalents and restricted cash and investments $ 283,447 $ 110,018 (1) The increase in restricted cash and investments - noncurrent was primarily related to the contract termination payment, which was restricted by contract.

CONTRACT ASSETS AND CONTRACT LI

CONTRACT ASSETS AND CONTRACT LIABILITIES	6 Months Ended
	Jun. 30, 2024
Change in Contract with Customer, Asset and Liability [Abstract]
CONTRACT ASSETS AND CONTRACT LIABILITIES	CONTRACT ASSETS AND CONTRACT LIABILITIES 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 13 – 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. During the six months ended June 30, 2024, we recognized $0.6 million of this unearned revenue in other operating revenues on our consolidated statements of operations. Our contract assets and liabilities consist of the following (dollars in thousands): June 30, December 31, Accounts receivable - Utility Members $ 93,883 $ 101,394 Other accounts receivable - trade: Non-member electric sales 16,048 9,657 Other 11,279 11,077 Total other accounts receivable - trade 27,327 20,734 Other accounts receivable - nontrade 119 2,389 Total other accounts receivable $ 27,446 $ 23,123 Contract liabilities (unearned revenue) $ 3,589 $ 4,159

OTHER DEFERRED CHARGES

OTHER DEFERRED CHARGES	6 Months Ended
	Jun. 30, 2024
Deferred Costs [Abstract]
OTHER DEFERRED CHARGES	OTHER DEFERRED CHARGES The following other deferred charges are reflected on our consolidated statements of financial position (dollars in thousands): June 30, December 31, Preliminary surveys and investigations $ 14,980 $ 12,845 Advances to operating agents of jointly owned facilities 7,995 2,750 Operating lease right-of-use assets 10,319 6,477 Other 23,285 14,049 Total other deferred charges $ 56,579 $ 36,121 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 15 – Leases.

LONG-TERM DEBT

LONG-TERM DEBT	6 Months Ended
	Jun. 30, 2024
Debt Disclosure [Abstract]
LONG-TERM DEBT	LONG-TERM DEBT We have $2.7 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”). 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 debt service ratio ("DSR") requirement on an annual basis and an equity to capitalization ratio ("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 and includes a swingline sublimit of $125 million, a letter of credit sublimit of $75 million, and a commercial paper back-up sublimit of $500 million. As of June 30, 2024, we had $404 million in availability (including $384 million under the commercial paper back-up sublimit) under the 2022 Revolving Credit Agreement. Long-term debt consists of the following (dollars in thousands): June 30, December 31, Total debt $ 2,914,553 $ 3,137,534 Less debt issuance costs (18,269) (19,723) Less debt discounts (8,531) (8,678) Plus debt premiums 10,488 10,896 Total debt adjusted for debt issuance costs, discounts and premiums 2,898,241 3,120,029 Less current maturities (191,729) (223,523) Long-term debt $ 2,706,512 $ 2,896,506

SHORT-TERM BORROWINGS

SHORT-TERM BORROWINGS	6 Months Ended
	Jun. 30, 2024
Short-Term Debt [Abstract]
SHORT-TERM BORROWINGS	SHORT-TERM BORROWINGS We 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. Short-term borrowings consisted of the following (dollars in thousands): June 30, December 31, Commercial paper outstanding, net of discounts $ 116,001 $ 184,205 Short-term borrowings - other $ 100 $ 100 Weighted average interest rate 5.51 % 5.62 %

ASSET RETIREMENT AND ENVIRONMEN

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS	6 Months Ended
	Jun. 30, 2024
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies Disclosure [Abstract]
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 market risk premium. Upon settlement of an asset retirement obligation, we will apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability. 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. 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. Two pits at the Colowyo Mine are in final reclamation with the other pit still being actively mined. Generation: We have asset retirement obligations related to equipment, dams, ponds, wells 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): Six Months Ended June 30, 2024 Obligations at beginning of period $ 217,201 Liabilities incurred 3,456 Liabilities settled (2,450) Accretion expense 3,597 Total obligations at end of period $ 221,804 Less current obligations at end of period (18,822) Long-term obligations at end of period $ 202,982 The New Horizon Mine environmental remediation liability is $67.3 million as of June 30, 2024. 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 statements of operations. We continue to evaluate the New Horizon Mine and Colowyo Mine post reclamation obligations and will make adjustments to these obligations as needed. 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. In May 2024, the Environmental Protection Agency ("EPA") published a final rule regarding groundwater monitoring, corrective action, closure, and post-closure care requirements for all coal combustion residuals management units under the Resource Conservation and Recovery Act. We are analyzing the final rule for possible impacts on our operations.

OTHER DEFERRED CREDITS AND OTHE

OTHER DEFERRED CREDITS AND OTHER LIABILITIES	6 Months Ended
	Jun. 30, 2024
Deferred Credits and Other Liabilities [Abstract]
OTHER DEFERRED CREDITS AND OTHER LIABILITIES	OTHER DEFERRED CREDITS AND OTHER LIABILITIES The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands): June 30, December 31, Transmission easements $ 17,949 $ 17,862 OATT deposits 38,059 27,872 Financial liabilities - reclamation 12,564 16,895 Customer deposits 13,251 12,091 Contract liabilities (unearned revenue) - noncurrent 2,871 3,125 Operating lease liabilities - noncurrent 5,461 1,396 Other 4,468 4,884 Total other deferred credits and other liabilities $ 94,623 $ 84,125 In 2015, we renewed transmission right-of-way easements on tribal nation lands where certain of our electric transmission lines are located. $26.1 million will be paid by us for these easements from 2024 through the individual easement terms ending between 2035 and 2047. The present values for the remaining easement payments were $17.9 million as of June 30, 2024 and December 31, 2023 which are 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 reclamation costs at jointly owned facilities in which we have undivided interests in. A lease liability represents a lessee’s obligation to make lease payments over the lease term. The long-term portion of our lease liabilities are included in other deferred credits and other liabilities and the current portion of our lease liabilities are included in current liabilities. See Note 15 – Leases. 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.

EMPLOYEE BENEFIT PLANS

EMPLOYEE BENEFIT PLANS	6 Months Ended
	Jun. 30, 2024
Retirement Benefits [Abstract]
EMPLOYEE BENEFIT PLANS	EMPLOYEE BENEFIT PLANS 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 post employment medical benefits to employees on long-term disability. The plans were unfunded as of June 30, 2024, 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 post employment obligations on our consolidated statements of financial position as follows (dollars in thousands): Six Months Ended June 30, 2024 Postretirement medical benefit obligation at beginning of period $ 924 Interest cost 29 Benefit payments (net of contributions by participants) (180) Postretirement medical benefit obligation at end of period $ 773 Postemployment medical benefit obligation at end of period 243 Total postretirement and postemployment medical obligations at end of period $ 1,016 The service cost component of our net periodic benefit cost, if any, 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 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 postretirement medical benefit obligation. The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligations are included in accumulated other comprehensive income as follows (dollars in thousands): Six Months Ended June 30, 2024 Amounts included in accumulated other comprehensive income at beginning of period $ 1,114 Amortization of prior service credit into other income (536) Amounts included in accumulated other comprehensive income at end of period $ 578 Defined Benefit Plans 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 post employment obligations on our consolidated statements of financial position as follows (dollars in thousands): Six Months Ended June 30, 2024 Executive benefit restoration obligation at beginning of period $ 10,158 Service cost 148 Interest cost 220 Benefit payments (898) Executive benefit restoration at end of period $ 9,628 Fair value of plan assets at beginning of period $ 10,298 Benefits paid (898) Actual return on plan assets 153 Fair value of plan assets at end of period $ 9,553 Net liability recognized at end of period $ 75 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. We have 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): Six Months Ended June 30, 2024 Accumulated other comprehensive loss at beginning of period $ (1,639) Amortization of prior service cost into other income 509 Accumulated other comprehensive loss at end of period $ (1,130)

REVENUE

REVENUE	6 Months Ended
	Jun. 30, 2024
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 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 – Utility Members on our consolidated statements of financial position. 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): Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 Non-member electric sales: Long-term contracts $ 29,813 $ 8,996 $ 51,188 $ 21,796 Short-term contracts 8,955 9,490 23,199 38,640 Rate stabilization 16,901 11,064 16,901 22,821 Provision for rate refunds — (6) — 304 Coal sales 1,814 3,315 3,458 4,394 Other 21,730 11,371 40,190 28,150 Total non-member electric sales and other operating revenue $ 79,213 $ 44,230 $ 134,936 $ 116,105 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 Rate stabilization represents revenue recognition from withdrawal of former Utility Members from membership in us that was previously deferred in accordance with accounting requirements related to regulated operations. We recognized $16.9 million of deferred membership withdrawal for the six months ended June 30, 2024 compared to $22.8 million of deferred membership withdrawal for the six months ended June 30, 2023. See Note 2 - Accounting for Rate Regulation. Coal sales Coal sales revenue results from the sale of coal from the Colowyo Mine 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. We recognize coal sales revenue in other operating revenue on our consolidated statements of operations. Other operating revenue Other operating revenue consists primarily of wheeling, transmission and lease revenue. Other operating revenue also includes revenue we receive from our Non-Utility Members. Wheeling revenue is earned 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

INCOME TAXES

INCOME TAXES	6 Months Ended
	Jun. 30, 2024
Income Tax Disclosure [Abstract]
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. We adopted the normalization method January 1, 2020 pursuant to FERC regulation. Our subsidiaries not subject to FERC regulation continued 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 payables that will be settled or received through future rate revenues. Under ASC 740-270, we calculate an estimate of the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full fiscal year to income or loss (pretax income or loss excluding unusual or infrequently occurring discrete items) for the reporting period, after regulatory affect. Our consolidated statements of operations included no income tax expense or benefit for the six months ended June 30, 2024 and an income tax expense of $45 thousand for the comparable period in 2023. We are continuing to evaluate the tax impacts of the contract termination payment received from United Power. Any current tax expense expected to be realized as a result of this contract termination payment, if any, will be recorded in the fourth quarter of 2024 when the amount of deferred revenue recognized will be known. On August 16, 2022, the Inflation Reduction Act of 2022 (the "IRA") was enacted into law. 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 and other guidance to be released by the U.S. Department of the Treasury, the U.S. Department of Agriculture and other governmental agencies over time. We are monitoring developments and evaluating opportunities to utilize these incentives. In September 2023, we submitted a Letter of Interest to apply for a funding award of low-cost loans and grants through the New Empowering Rural America ("New ERA") Program. In March 2024, we received an Invitation to Proceed from the U.S. Department of Agriculture to complete the New ERA Program Application, and in June 2024, we submitted our Application. The New ERA Program implements the $9.7 billion funded in the IRA.

LEASES

LEASES	6 Months Ended
	Jun. 30, 2024
Leases [Abstract]
LEASES	LEASES Leasing Arrangements as Lessee 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. 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 expense. Operating Leases 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 $0.7 million for the three months ended June 30, 2024 and $0.6 million for the comparable period in 2023. Rent expense for all short-term and long-term operating leases was $1.3 million for the six months ended June 30, 2024 and $1.2 million for the comparable period in 2023. Rent expense is included in various categories of operating expenses on our consolidated statements of operations based on the type and purpose of the lease. In May 2024, we entered into several land leases in connection with our acquisition of the Dolores Canyon Solar project being developed in southwestern Colorado and commencing construction on such project. The term of those leases is 30 years with two five-year renewal option periods which we are reasonably assured to exercise. Our consolidated statements of financial position include the following lease components (dollars in thousands): June 30, December 31, Operating leases: Operating lease right-of-use assets $ 13,238 $ 9,072 Less: Accumulated amortization (2,919) (2,595) Net operating lease right-of-use assets $ 10,319 $ 6,477 Operating lease liabilities - current $ (471) $ (371) Operating lease liabilities - noncurrent (5,461) (1,396) Total operating lease liabilities $ (5,932) $ (1,767) Finance leases: Finance lease right-of-use assets $ 95 $ — Less: Accumulated amortization (7) — Net finance lease right-of-use assets $ 88 $ — Finance lease liabilities - current $ (46) $ — Finance lease liabilities - noncurrent (37) — Total finance lease liabilities $ (83) $ — Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Operating leases 32.1 7.0 Finance leases 1.9 0.0 Weighted-average discount rate Operating leases 6.91 % 4.68 % Finance leases 6.99% —% Future expected minimum lease commitments under operating leases are as follows (dollars in thousands): Operating Leases Finance Leases Total Year 1 $ 703 $ 51 $ 754 Year 2 517 38 555 Year 3 531 — 531 Year 4 838 — 838 Year 5 432 — 432 Thereafter 12,401 — 12,401 Total lease payments $ 15,422 $ 89 $ 15,511 Less imputed interest (9,490) (6) (9,496) Total $ 5,932 $ 83 $ 6,015 Leasing Arrangements as Lessor We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $4.7 million and $1.7 million for the three months ended June 30, 2024 and 2023 and $6.4 million and $3.4 million for the six months ended June 30, 2024 and 2023, respectively, are included in other operating revenue on our consolidated statements of operations. In May 2024, the conditions for the effectiveness of a tolling agreement with a third party were satisfied for our two 70 MW units at our Knutson Generating Station for all capacity and energy through the operation of both units. In substance, this agreement was determined to be a lease in accordance with the accounting standards for leases as the third party has the right to the economic benefits of the asset and controls the use of the asset by its contractual rights, including the ability to direct the timing of dispatch of energy.
LEASES	LEASES Leasing Arrangements as Lessee 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. 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 expense. Operating Leases 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 $0.7 million for the three months ended June 30, 2024 and $0.6 million for the comparable period in 2023. Rent expense for all short-term and long-term operating leases was $1.3 million for the six months ended June 30, 2024 and $1.2 million for the comparable period in 2023. Rent expense is included in various categories of operating expenses on our consolidated statements of operations based on the type and purpose of the lease. In May 2024, we entered into several land leases in connection with our acquisition of the Dolores Canyon Solar project being developed in southwestern Colorado and commencing construction on such project. The term of those leases is 30 years with two five-year renewal option periods which we are reasonably assured to exercise. Our consolidated statements of financial position include the following lease components (dollars in thousands): June 30, December 31, Operating leases: Operating lease right-of-use assets $ 13,238 $ 9,072 Less: Accumulated amortization (2,919) (2,595) Net operating lease right-of-use assets $ 10,319 $ 6,477 Operating lease liabilities - current $ (471) $ (371) Operating lease liabilities - noncurrent (5,461) (1,396) Total operating lease liabilities $ (5,932) $ (1,767) Finance leases: Finance lease right-of-use assets $ 95 $ — Less: Accumulated amortization (7) — Net finance lease right-of-use assets $ 88 $ — Finance lease liabilities - current $ (46) $ — Finance lease liabilities - noncurrent (37) — Total finance lease liabilities $ (83) $ — Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Operating leases 32.1 7.0 Finance leases 1.9 0.0 Weighted-average discount rate Operating leases 6.91 % 4.68 % Finance leases 6.99% —% Future expected minimum lease commitments under operating leases are as follows (dollars in thousands): Operating Leases Finance Leases Total Year 1 $ 703 $ 51 $ 754 Year 2 517 38 555 Year 3 531 — 531 Year 4 838 — 838 Year 5 432 — 432 Thereafter 12,401 — 12,401 Total lease payments $ 15,422 $ 89 $ 15,511 Less imputed interest (9,490) (6) (9,496) Total $ 5,932 $ 83 $ 6,015 Leasing Arrangements as Lessor We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $4.7 million and $1.7 million for the three months ended June 30, 2024 and 2023 and $6.4 million and $3.4 million for the six months ended June 30, 2024 and 2023, respectively, are included in other operating revenue on our consolidated statements of operations. In May 2024, the conditions for the effectiveness of a tolling agreement with a third party were satisfied for our two 70 MW units at our Knutson Generating Station for all capacity and energy through the operation of both units. In substance, this agreement was determined to be a lease in accordance with the accounting standards for leases as the third party has the right to the economic benefits of the asset and controls the use of the asset by its contractual rights, including the ability to direct the timing of dispatch of energy.

FAIR VALUE

FAIR VALUE	6 Months Ended
	Jun. 30, 2024
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 or in the most advantageous market when no principal market exists. The fair value measurement accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows: Level 1 inputs are based upon quoted prices for identical instruments traded in active (exchange-traded) markets. Valuations are obtained from readily available pricing sources for market transactions (observable market data) involving identical assets or liabilities. Level 2 inputs are based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques (such as option pricing models, discounted cash flow models) for which all significant assumptions are observable in the market. Level 3 inputs consist of unobservable market data which is typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity. In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified in Level 3. Executive Benefit Restoration Plan Trust We have 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 marketable securities are as follows (dollars in thousands): June 30, 2024 December 31, 2023 Cost Estimated Cost Estimated Marketable securities $ 9,987 $ 9,553 $ 10,821 $ 10,298 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 fair values of our marketable securities are as follows (dollars in thousands): June 30, 2024 December 31, 2023 Cost Estimated Cost Estimated Marketable securities $ 557 $ 564 $ 576 $ 530 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 $256.0 million as of June 30, 2024 and $83.0 million as of December 31, 2023. Debt The fair values of long-term debt, excluding amounts reclassified from short-term 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): June 30, 2024 December 31, 2023 Principal Estimated Principal Estimated Total long-term debt $ 2,914,553 $ 2,615,600 $ 3,137,534 $ 2,909,301

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	6 Months Ended
	Jun. 30, 2024
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): June 30, December 31, Net electric plant $ 694,790 $ 703,859 Noncontrolling interest 129,737 134,269 Long-term debt 173,091 206,027 Accrued interest 4,997 5,968 Our consolidated statements of operations include the following Springerville Partnership expenses for the three and six months ended June 30, 2024 and 2023 (dollars in thousands): Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 Depreciation, amortization and depletion $ 4,535 $ 4,535 $ 9,069 $ 9,069 Interest 2,852 3,401 5,885 7,068 The revenue associated with the Springerville Partnership lease has been eliminated in consolidation. Income, losses and cash flows of the Springerville Partnership are allocated to the general and limited partners based on their equity ownership percentages. The net income or loss attributable to the 49 percent non-controlling equity interest in the Springerville Partnership is reflected on our consolidated statements of operations.

LEGAL

LEGAL	6 Months Ended
	Jun. 30, 2024
Commitments and Contingencies Disclosure [Abstract]
LEGAL	LEGAL Other than as disclosed below, we do not expect any litigation or proceeding pending or threatened against us to have a potential material effect on our financial condition, results of operations or cash flows. CTP Proceeding: Pursuant to our Bylaws, a 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 Member shall be permitted to withdraw until it has met all its contractual obligations to us. On September 1, 2021, we filed with FERC a modified contract termination payment methodology tariff as Rate Schedule 281 that provides a process should a Utility Member elect to withdraw from membership in us and terminate its wholesale electric service contract. The tariff process includes requirements for a two-year notice and the payment to us of a contract termination payment. On October 29, 2021, FERC accepted our modified contract termination payment methodology, effective November 1, 2021, subject to refund. FERC set the matter for hearing and instituted a concurrent Federal Power Act ("FPA") section 206 proceeding to determine the justness and reasonableness of our modified methodology. On April 29, 2022, both United Power and Northwest Rural Public Power District ("NRPPD") provided us notices to withdraw from membership in us, with a May 1, 2024 withdrawal effective date. On December 19, 2023, FERC issued an order adopting a modified balance sheet approach for the contract termination payment methodology (" FERC December 19 Order") . On January 18, 2024, we, United Power, and others filed requests for rehearing with FERC of the FERC December 19 Order . Our request for rehearing included FERC's rejection of our lost revenue approach and also certain clarifications. On February 20, 2024, FERC issued a notice stating the parties' requests for rehearing were denied by operation of law, but FERC stated it will address the merits of the requests in a subsequent order. On March 28, 2024, we filed a petition for review of the FERC December 19 Order with the United States Court of Appeals for the Tenth Circuit (" 10th Circuit Court of Appeals"), Case No. 24-9516 . On April 8, 2024, United Power filed a petition for review of the FERC December 19 Order with the United States Court of Appeals for the District of Columbia Circuit (" DC Circuit Court of Appeals"), Case No. 24-1081. United Power, Mountain Parks Electric, Inc. ("MPEI"), NRPPD, Basin Electric Power Cooperative ("Basin"), and La Plata Electric Association, Inc. ("LPEA") have filed notices of interventions in our petition for review with the 10th Circuit Court of Appeals. On May 2, 2024, FERC filed with the DC Circuit Court of Appeals a motion to transfer United Power's petition for review filed in the DC Circuit Court of Appeals to the 10th Circuit Court of Appeals. On May 14, 2024, the DC Circuit Court of Appeals granted a motion to transfer United Power’s petition to the 10th Circuit Court of Appeals, Case No. 24-9532. On May 23, 2024, FERC issued a substantive order on rehearing, which modifies the discussion in, but sustains the results of, the FERC December 19 Order (“May 23 Order”). On May 31, 2024, we filed a petition for review of the May 23 Order, Case No. 24-9538, with the 10th Circuit Court of Appeals. On June 3, 2024, the 10th Circuit Court of Appeals issued an order partially consolidating Case No. 24-9538 with Case Nos. 24-9516 and 24-9532 for purposes of briefing. Briefing is scheduled to begin in October 2024. On July 2, 2024, United Power, NRPPD, MPEI and LPEA filed with the 10th Circuit Court of Appeals a joint motion to transfer our petition for review to the DC Circuit Court of Appeals. On July 17, 2024, we filed a response opposing this joint motion to transfer. On July 23, 2024, the court denied the joint motion to transfer our petition for review from the 10th Circuit Court of Appeals. On January 25, 2024, we filed a revised Rate Schedule 281 with FERC with the contract termination methodology based upon the FERC December 19 Order. On March 29, 2024, FERC issued an order accepting our revised Rate Schedule 281, subject to further compliance filing, and established hearing and settlement judge procedures related to our sleeving administrative fee methodology set forth in our revised Rate Schedule 281. On April 12, 2024, we submitted a further revised Rate Schedule 281 as directed by FERC's March 2024 order. On June 28, 2024, we submitted a further revised Rate Schedule 281 as directed by FERC's May 23 Order. FERC has not issued an order on our April 2024 or June 2024 revised Rate Schedule 281 so our January 2024 Rate Schedule 281 is currently on-file with FERC. On May 1, 2024, United Power withdrew from membership in us and terminated its wholesale electric service contract with us pursuant to Rate Schedule 281 on-file with FERC and a Membership Withdrawal Agreement with United Power. United Power’s contract termination payment amount was $709.4 million. United Power paid us an exit fee in cash of $627.2 million, after a regulatory liabilities credit and United Power relinquishing its right to any patronage capital in us resulting in a discounted patronage capital credit of $82.2 million. Such amounts remain subject to true-up in accordance with Rate Schedule 281 and United Power's Membership Withdrawal Agreement. As provided in the Membership Withdrawal Agreement, United Power's exit fee is also subject to true-up in the event Rate Schedule 281 and the amount paid by United Power are modified pursuant to a subsequent final and non-appealable FERC order, including resolution of the petitions for review filed by us and United Power. It is not possible to predict the outcome of this matter or whether we will be required to refund any amounts to United Power or if United Power will be required to pay us any additional amounts. NRPPD did not comply with Rate Schedule 281 on-file with FERC and made no contract termination payment to us. NRPPD’s wholesale electric service contract with us remains in effect an d NRPPD remains a Class A member of us. NRPPD’s April 29, 2022 notice of intent to withdraw is deemed null and void. NRPPD is disputing our position that their wholesale electric service contract with us remains in effect and NRPPD remains a Class A member of us. It is not possible to predict the outcome of the proceedings related to NRPPD's status as a Class A member or its position that it has terminated its wholesale electric service contracts with us and whether we will suffer any liability or loss from the proceedings. LPEA's La Plata County District Court Complaint . On November 10, 2023, LPEA filed a complaint with the La Plata County District Court, Case No. 2023CV30148, against us. The complaint alleges, among other things, that we have breached our Bylaws and our wholesale electric service contract with LPEA by failing to provide equitable terms and conditions for LPEA to withdraw from us and by violating the implied covenant of good faith and fair dealing. LPEA seeks a declaratory order that we have materially breached our Bylaws and our wholesale electric service contract and that LPEA is relieved from any further obligation to perform under those agreements, or in the alternative, damages from us for such alleged breach. On January 10, 2024, we filed a motion to dismiss stating that LPEA's claims are barred by federal preemption and the statute of limitations. On July 18, 2024, the court denied our motion to dismiss, ruling that the case was not preempted by FERC's jurisdiction and should not be dismissed for violating the statute of limitations. On August 1, 2024, we filed our answer denying all of the allegations in LPEA's complaint and that LPEA is entitled to any relief. It is not possible to predict the ou tcome of this matter, whether we will incur any liability in connection with this matter, and in the event of liability, if any, the amount or type of damages, equitable relief or other legal relief that could be awarded or granted. NRPPD Complaint: On March 25, 2024, NRPPD filed a FPA section 206 proceeding with FERC, Docket No. EL24-93, against us and Basin seeking FERC to exercise primary jurisdiction over the interpretation of the FERC December 19 Order and our Amended and Restated Wholesale Power Contract for the Eastern Interconnection with Basin ("Basin Eastern WPC"). In particular, NRPPD requests that FERC hold that NRPPD’s withdrawal from us is permissible under the Basin Eastern WPC and that NRPPD’s contract termination payment calculation is the appropriate contract termination payment. NRPPD further seeks refunds from us because Basin has allegedly overcharged us and thus NRPPD for sa les of power and energy under the Basin Eastern WPC for Basin’s financial losses caused by Basin’s Urea facility. On May 8, 2024, we and Basin separately filed answers to NRPPD's complaint. Both us and Basin requested FERC to deny NRPPD's complaint. We also requested to the extent FERC determines that NRPPD's withdrawal is permissible under the Basin Eastern WPC that we can be permitted to allocate the withdrawing member its portion of costs related to the Basin Eastern WPC pursuant to our Rate Schedule 281 to prevent the cost of the obligation from shifting to remaining members. On May 28, 2024, NRPPD filed a response to our and Basin's answers and again asserted that its withdrawal from us is permissible under the Basin Eastern WPC and if, prohibited, the Basin Eastern WPC be held not just and reasonable and NRPPD be permitted to withdraw from us. It is not possible to predict the ou tcome of this matter or whether we will incur any liability or loss in connection with this matter. 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, Docket No. 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, Case No. 22-1169. On August 18, 2022, we filed a motion to intervene with the DC Circuit Court of Appeals and an order granting our 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. On October 31, 2023, the final briefs were filed in this consolidated proceeding. On July 9, 2024, the DC Circuit Court of Appeals issued an order vacating FERC's order and remanding the case back to FERC to conduct a Mobile-Sierra analysis. 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.

PRESENTATION OF FINANCIAL INF_2

PRESENTATION OF FINANCIAL INFORMATION (Policies)	6 Months Ended
	Jun. 30, 2024
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Consolidation	Basis of Consolidation We are 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-one electric distribution member systems who are Class A members to which we provided 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 (A-40) 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. On July 30, 2024, FERC issued an order accepting our A-41 formula rate to our Class A members, effective August 1, 2024, subject to refund. FERC further set our A-41 ra te filing for settlement and hearing procedures and confirmed our accounting treatment, including amortization, and creation of regulatory assets for Escalante Generating Station, Rifle Generating Station, Craig Generating Station Units 2 and 3 and the New Horizon Mine environmental obligation. However, FERC did not currently authorize us to recover the regulatory assets that represent acquisition costs/goodwill for J.M Shafer Generating Station and Colowyo Coal Company LP (“Colowyo Coal”), with an aggregate balance of $68.9 million as of June 30, 2024. These costs were on our books prior to us becoming subject to FERC's jurisdiction. FERC stated in its order accepting our A-41 rate schedule that we did not request express authorization to recover acquisition costs including goodwill in our rates. We are evaluating next steps regarding these costs. The accompanying financial statements reflect the consolidated accounts of Tri-State Generation and Transmission Association, Inc. (“Tri-State”, “we”, “our”, “us” or “the Association”), our wholly-owned and majority-owned subsidiaries, and certain variable interest entities for which we or our subsidiaries are the primary beneficiaries. See Note 17 – Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. We have eliminated all intercompany balances and transactions in consolidation.
Basis of Accounting	We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with GAAP, the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes.
Accounting Pronouncement - Not Yet Adopted	Accounting Pronouncement - Not Yet Adopted In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) 2023-09 – Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The purpose of ASU 2023-09 is to enhance the transparency and decision usefulness of income tax disclosures by providing additional information related to the following: (1) Rate reconciliation: ASU 2023-09 requires a tabular rate reconciliation using both percentages and dollar amounts of the reported income tax expense (or benefit) from continuing operations to the product of income (or loss) from continuing operating before income taxes and the applicable statutory federal income tax rate of the county of domicile using specific categories. The following specific categories are required to be disclosed in the rate reconciliation; state and local income tax (qualitative disclosure required for states that make up over 50% of this category), foreign tax effect, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, changes in unrecognized tax benefits, and any other item that meets the 5 percent threshold. (2) Income taxes paid: ASU 2023-09 requires all reporting entities to disclose the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign jurisdictions. It also requires additional disaggregation of income taxes paid to an individual jurisdiction equal to or greater than 5 percent of total income taxes paid (net of refunds). Entities are required to disclose pre-tax income (or loss) from continuing operations disaggregated by domestic and foreign along with income tax expense (or benefit) disaggregated by federal, state, and foreign components. ASU 2023-09 is effective for public business entities for annual periods beginning after December 15, 2024, with early adoption and retrospective or prospective application permitted. We have evaluated the impact of ASU 2023-09 and believe that the adoption of this update will not have a material impact on our consolidated financial statement disclosures.

ACCOUNTING FOR RATE REGULATION

ACCOUNTING FOR RATE REGULATION (Tables)	6 Months Ended
	Jun. 30, 2024
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets and Liabilities	Regulatory assets and liabilities are as follows (dollars in thousands): June 30, December 31, Regulatory assets Deferred income tax expense (1) $ 15,223 $ 15,223 Deferred prepaid lease expense – Springerville Unit 3 Lease (2) 73,406 74,551 Acquisition costs – J.M. Shafer (3) 36,325 37,749 Acquisition costs – Colowyo Coal (4) 32,545 33,062 Deferred debt prepayment transaction costs (5) 102,103 106,417 Deferred Holcomb expansion impairment loss (6) 72,458 74,795 New Horizon Mine environmental obligation (7) 44,869 44,869 Unrecovered plant (8) 526,425 532,817 Total regulatory assets 903,354 919,483 Regulatory liabilities Interest rate swap - realized gain (9) and other 1,625 1,854 Membership withdrawal (10) 513,699 463 Withdrawal related transmission credit (11) 178,511 — Total regulatory liabilities 693,835 2,317 Net regulatory asset $ 209,519 $ 917,166 (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 through rates. (3) Represents acquisition costs related to our acquisition of an entity that owned J.M. Shafer Generating Station in December 2011. Acquisition costs are 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 through rates. (4) Represents acquisition costs related to our acquisition of Colowyo Coal in December 2011. Acquisition costs are 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 through 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 through 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 depreciation, amortization and depletion expense in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members through rates. (7) Represents $44.9 million of New Horizon Mine environmental obligation expense that was recognized as a regulatory item in 2023. The regulatory asset for the deferred environmental obligation expense will be amortized to expense in the amount of $1.8 million annually over 25 years. (8) Represents deferral of the impairment losses and other closure costs related to the early retirement of the Escalante, Rifle and Craig Generating Station Units 2 and 3. 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 the Escalante Generating Station, and recovered from our Utility Members through rates. The deferred impairment loss for Rifle Generating Station 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. We recognized the early retirement of Craig Generating Station Units 2 and 3 and concluded the impairment of incurred costs is probable of recovery through future rates. We recognized an impairment loss of $261.6 million and deferred the loss in accordance with accounting for rate regulation. The deferred impairment loss will be amortized to depreciation, amortization and depletion expense beginning in October 2028 through 2039 for Craig Generating Station Unit 2 and January 2030 through 2043 for Craig Generating Station Unit 3. These amortization periods are the depreciable lives of Craig Generating Station Unit 2 and 3. The annual amortization is expected to approximate the former annual Craig Generation Station Unit 2 and 3 depreciation for the remaining life of the asset. (9) 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. (10) Represents the remaining balance of the deferred recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. On May 1, 2024, United Power withdrew from membership in us and terminated its wholesale electric service contract with us pursuant to Rate Schedule 281 on-file with FERC and a Membership Withdrawal Agreement. United Power's contract termination payment amount was $709.4 million, of which $530.1 million was membership withdrawal that was deferred by our Board as a regulatory liability. The deferred membership withdrawal will be refunded to Utility Members through reduced rates when recognized in operating revenues in future periods with the oldest vintage year used first. (11) Represents the remaining $179.3 million of United Power's transmission credit related to taking transmission service from us. A portion of a withdrawing member's contract termination payment is allocated to transmission debt that is deferred as required by FERC's order on Rate Schedule 281. The transmission credit, plus interest at FERC's prescribed interest rate, is refunded to the withdrawing member on a monthly basis if the withdrawing member takes transmission service from us and amortized on a straight-line basis over the remaining term. If the withdrawing member's transmission bill for a given month is lower than the credit amount that would be due, the difference is forfeited by the withdrawing member.

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	6 Months Ended
	Jun. 30, 2024
Public Utilities, Property, Plant and Equipment [Abstract]
Schedule of Investment in Electric Plant	ELECTRIC PLANT : As of June 30, 2024, 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 % $ 3,089,810 $ (1,699,258) $ 1,390,552 Transmission plant 1.11 % to 2.09 % 1,895,240 (701,422) 1,193,818 General plant 1.46 % to 9.53 % 448,016 (274,586) 173,430 Other 2.75 % to 10.00 % 240,737 (97,015) 143,722 Electric plant in service (at cost) $ 5,673,803 $ (2,772,281) 2,901,522 Construction work in progress 256,301 Electric plant $ 3,157,823 As of December 31, 2023, 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 % $ 3,082,133 $ (1,669,941) $ 1,412,192 Transmission plant 1.11 % to 2.09 % 1,983,629 (708,412) 1,275,217 General plant 1.46 % to 9.53 % 410,856 (266,013) 144,843 Other 2.75 % to 10.00 % 246,061 (95,558) 150,503 Electric plant in service (at cost) $ 5,722,679 $ (2,739,924) 2,982,755 Construction work in progress 163,954 Electric plant $ 3,146,709
Schedule of Jointly Owned Facilities	JOINTLY OWNED FACILITIES : Our share in each jointly owned facility is as follows as of June 30, 2024 (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 % $ 392,510 $ 362,750 $ — MBPP - Laramie River Station 28.50 % 537,127 349,594 7,047 Total $ 929,637 $ 712,344 $ 7,047
Schedule of Other Plant Assets (Excluding Utility Assets)	Other plant assets are as follows (dollars in thousands): June 30, December 31, Colowyo Mine assets $ 395,438 $ 396,441 New Horizon Mine assets 6,320 6,448 Accumulated depreciation and depletion (199,278) (184,239) Net mine assets 202,480 218,650 Non-utility assets 549,224 549,430 Accumulated depreciation (527,604) (527,658) Net non-utility assets 21,620 21,772 Net other plant $ 224,100 $ 240,422

INVESTMENTS IN OTHER ASSOCIAT_2

INVESTMENTS IN OTHER ASSOCIATIONS (Tables)	6 Months Ended
	Jun. 30, 2024
Investments in and Advances to Affiliates, Schedule of Investments [Abstract]
Schedule of Investments in Other Associations	Investments in other associations are as follows (dollars in thousands): June 30, December 31, Basin Electric Power Cooperative $ 135,652 $ 135,652 National Rural Utilities Cooperative Finance Corporation - patronage capital 12,451 12,451 National Rural Utilities Cooperative Finance Corporation - capital term certificates 15,054 15,054 CoBank, ACB 16,946 18,809 Other 5,570 5,718 Investments in other associations $ 185,673 $ 187,684

CASH, CASH EQUIVALENTS AND RE_2

CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS (Tables)	6 Months Ended
	Jun. 30, 2024
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents [Abstract]
Schedule of Cash, Cash Equivalents and 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): June 30, December 31, Cash and cash equivalents $ 110,498 $ 106,005 Restricted cash and investments - current 697 605 Restricted cash and investments - noncurrent (1) 172,252 3,408 Cash, cash equivalents and restricted cash and investments $ 283,447 $ 110,018 (1) The increase in restricted cash and investments - noncurrent was primarily related to the contract termination payment, which was restricted by contract.

CONTRACT ASSETS AND CONTRACT _2

CONTRACT ASSETS AND CONTRACT LIABILITIES (Tables)	6 Months Ended
	Jun. 30, 2024
Change in Contract with Customer, Asset and Liability [Abstract]
Schedule of Contract Assets and Liabilities	Our contract assets and liabilities consist of the following (dollars in thousands): June 30, December 31, Accounts receivable - Utility Members $ 93,883 $ 101,394 Other accounts receivable - trade: Non-member electric sales 16,048 9,657 Other 11,279 11,077 Total other accounts receivable - trade 27,327 20,734 Other accounts receivable - nontrade 119 2,389 Total other accounts receivable $ 27,446 $ 23,123 Contract liabilities (unearned revenue) $ 3,589 $ 4,159

OTHER DEFERRED CHARGES (Tables)

OTHER DEFERRED CHARGES (Tables)	6 Months Ended
	Jun. 30, 2024
Deferred Costs [Abstract]
Schedule of Other Deferred Charges	The following other deferred charges are reflected on our consolidated statements of financial position (dollars in thousands): June 30, December 31, Preliminary surveys and investigations $ 14,980 $ 12,845 Advances to operating agents of jointly owned facilities 7,995 2,750 Operating lease right-of-use assets 10,319 6,477 Other 23,285 14,049 Total other deferred charges $ 56,579 $ 36,121

LONG-TERM DEBT (Tables)

LONG-TERM DEBT (Tables)	6 Months Ended
	Jun. 30, 2024
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long-term debt consists of the following (dollars in thousands): June 30, December 31, Total debt $ 2,914,553 $ 3,137,534 Less debt issuance costs (18,269) (19,723) Less debt discounts (8,531) (8,678) Plus debt premiums 10,488 10,896 Total debt adjusted for debt issuance costs, discounts and premiums 2,898,241 3,120,029 Less current maturities (191,729) (223,523) Long-term debt $ 2,706,512 $ 2,896,506

SHORT-TERM BORROWINGS (Tables)

SHORT-TERM BORROWINGS (Tables)	6 Months Ended
	Jun. 30, 2024
Short-Term Debt [Abstract]
Schedule of Short-Term Borrowings	Short-term borrowings consisted of the following (dollars in thousands): June 30, December 31, Commercial paper outstanding, net of discounts $ 116,001 $ 184,205 Short-term borrowings - other $ 100 $ 100 Weighted average interest rate 5.51 % 5.62 %

ASSET RETIREMENT AND ENVIRONM_2

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS (Tables)	6 Months Ended
	Jun. 30, 2024
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): Six Months Ended June 30, 2024 Obligations at beginning of period $ 217,201 Liabilities incurred 3,456 Liabilities settled (2,450) Accretion expense 3,597 Total obligations at end of period $ 221,804 Less current obligations at end of period (18,822) Long-term obligations at end of period $ 202,982

OTHER DEFERRED CREDITS AND OT_2

OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Tables)	6 Months Ended
	Jun. 30, 2024
Deferred Credits and Other Liabilities [Abstract]
Schedule of Other Deferred Credits and Other Liabilities	The following other deferred credits and other liabilities are reflected on our consolidated statements of financial position (dollars in thousands): June 30, December 31, Transmission easements $ 17,949 $ 17,862 OATT deposits 38,059 27,872 Financial liabilities - reclamation 12,564 16,895 Customer deposits 13,251 12,091 Contract liabilities (unearned revenue) - noncurrent 2,871 3,125 Operating lease liabilities - noncurrent 5,461 1,396 Other 4,468 4,884 Total other deferred credits and other liabilities $ 94,623 $ 84,125

EMPLOYEE BENEFIT PLANS (Tables)

EMPLOYEE BENEFIT PLANS (Tables)	6 Months Ended
	Jun. 30, 2024
Retirement Benefits [Abstract]
Schedule of Employee Benefit Plan Obligations	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 post employment obligations on our consolidated statements of financial position as follows (dollars in thousands): Six Months Ended June 30, 2024 Postretirement medical benefit obligation at beginning of period $ 924 Interest cost 29 Benefit payments (net of contributions by participants) (180) Postretirement medical benefit obligation at end of period $ 773 Postemployment medical benefit obligation at end of period 243 Total postretirement and postemployment medical obligations at end of period $ 1,016 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 post employment obligations on our consolidated statements of financial position as follows (dollars in thousands): Six Months Ended June 30, 2024 Executive benefit restoration obligation at beginning of period $ 10,158 Service cost 148 Interest cost 220 Benefit payments (898) Executive benefit restoration at end of period $ 9,628 Fair value of plan assets at beginning of period $ 10,298 Benefits paid (898) Actual return on plan assets 153 Fair value of plan assets at end of period $ 9,553 Net liability recognized at end of period $ 75
Schedule of Net Unrecognized Actuarial Gains and Losses on Employee Benefit Plan Obligations	The net unrecognized actuarial gains and losses related to the postretirement medical benefit obligations are included in accumulated other comprehensive income as follows (dollars in thousands): Six Months Ended June 30, 2024 Amounts included in accumulated other comprehensive income at beginning of period $ 1,114 Amortization of prior service credit into other income (536) Amounts included in accumulated other comprehensive income at end of period $ 578 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): Six Months Ended June 30, 2024 Accumulated other comprehensive loss at beginning of period $ (1,639) Amortization of prior service cost into other income 509 Accumulated other comprehensive loss at end of period $ (1,130)

REVENUE (Tables)

REVENUE (Tables)	6 Months Ended
	Jun. 30, 2024
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): Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 Non-member electric sales: Long-term contracts $ 29,813 $ 8,996 $ 51,188 $ 21,796 Short-term contracts 8,955 9,490 23,199 38,640 Rate stabilization 16,901 11,064 16,901 22,821 Provision for rate refunds — (6) — 304 Coal sales 1,814 3,315 3,458 4,394 Other 21,730 11,371 40,190 28,150 Total non-member electric sales and other operating revenue $ 79,213 $ 44,230 $ 134,936 $ 116,105

LEASES (Tables)

LEASES (Tables)	6 Months Ended
	Jun. 30, 2024
Leases [Abstract]
Schedule of Lease Components	Our consolidated statements of financial position include the following lease components (dollars in thousands): June 30, December 31, Operating leases: Operating lease right-of-use assets $ 13,238 $ 9,072 Less: Accumulated amortization (2,919) (2,595) Net operating lease right-of-use assets $ 10,319 $ 6,477 Operating lease liabilities - current $ (471) $ (371) Operating lease liabilities - noncurrent (5,461) (1,396) Total operating lease liabilities $ (5,932) $ (1,767) Finance leases: Finance lease right-of-use assets $ 95 $ — Less: Accumulated amortization (7) — Net finance lease right-of-use assets $ 88 $ — Finance lease liabilities - current $ (46) $ — Finance lease liabilities - noncurrent (37) — Total finance lease liabilities $ (83) $ — Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Operating leases 32.1 7.0 Finance leases 1.9 0.0 Weighted-average discount rate Operating leases 6.91 % 4.68 % Finance leases 6.99% —%
Schedule of Future Expected Minimum Lease Commitments under Operating Leases	Future expected minimum lease commitments under operating leases are as follows (dollars in thousands): Operating Leases Finance Leases Total Year 1 $ 703 $ 51 $ 754 Year 2 517 38 555 Year 3 531 — 531 Year 4 838 — 838 Year 5 432 — 432 Thereafter 12,401 — 12,401 Total lease payments $ 15,422 $ 89 $ 15,511 Less imputed interest (9,490) (6) (9,496) Total $ 5,932 $ 83 $ 6,015

FAIR VALUE (Tables)

FAIR VALUE (Tables)	6 Months Ended
	Jun. 30, 2024
Fair Value Disclosures [Abstract]
Schedule of Cost and Fair Values of Assets and Liabilities	The cost and fair values of our marketable securities are as follows (dollars in thousands): June 30, 2024 December 31, 2023 Cost Estimated Cost Estimated Marketable securities $ 9,987 $ 9,553 $ 10,821 $ 10,298 June 30, 2024 December 31, 2023 Cost Estimated Cost Estimated Marketable securities $ 557 $ 564 $ 576 $ 530 June 30, 2024 December 31, 2023 Principal Estimated Principal Estimated Total long-term debt $ 2,914,553 $ 2,615,600 $ 3,137,534 $ 2,909,301

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	6 Months Ended
	Jun. 30, 2024
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): June 30, December 31, Net electric plant $ 694,790 $ 703,859 Noncontrolling interest 129,737 134,269 Long-term debt 173,091 206,027 Accrued interest 4,997 5,968 Our consolidated statements of operations include the following Springerville Partnership expenses for the three and six months ended June 30, 2024 and 2023 (dollars in thousands): Three Months Ended June 30, Six Months Ended June 30, 2024 2023 2024 2023 Depreciation, amortization and depletion $ 4,535 $ 4,535 $ 9,069 $ 9,069 Interest 2,852 3,401 5,885 7,068

PRESENTATION OF FINANCIAL INF_3

PRESENTATION OF FINANCIAL INFORMATION - Narrative (Details) $ in Thousands			6 Months Ended	12 Months Ended
	May 08, 2024 USD ($)	May 01, 2024 USD ($)	Jun. 30, 2024 USD ($) member_system class_of_membership non-utility_member	Dec. 31, 2023 USD ($)
Disaggregation of Revenue [Line Items]
Number of classes of members | class_of_membership			3
Regulatory assets			$ 903,354	$ 919,483
Amount received for contract termination payment		$ 709,400
Exit fee related to contract termination payment		627,200
Patronage capital credit related to contract termination payment		82,200
Proceeds from sale of assets	$ 75,000
Regulatory liability			693,835	2,317
Transmission credit portion of contract termination payment		179,300
Deferred membership withdrawal income
Disaggregation of Revenue [Line Items]
Regulatory liability		$ 530,100	513,699	$ 463
J.M. Shafer and Colowyo Coal | Acquisition costs
Disaggregation of Revenue [Line Items]
Regulatory assets			$ 68,900
Class A Members
Disaggregation of Revenue [Line Items]
Number of members | member_system			41
Class B Members
Disaggregation of Revenue [Line Items]
Number of members | member_system			0
Non-Utility Members
Disaggregation of Revenue [Line Items]
Number of members | non-utility_member			3
United Power, Inc. | Revenue Benchmark | Customer Concentration Risk
Disaggregation of Revenue [Line Items]
Concentration risk (as a percent)			13.70%	19.70%

ACCOUNTING FOR RATE REGULATIO_2

ACCOUNTING FOR RATE REGULATION (Details) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended			6 Months Ended
	May 01, 2024	Oct. 31, 2017	Jun. 30, 2024	Mar. 31, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 903,354			$ 903,354		$ 919,483
Regulatory liabilities			693,835			693,835		2,317
Net regulatory asset			209,519			209,519		917,166
Amount received for contract termination payment	$ 709,400
Transmission credit portion of contract termination payment	179,300
Rate stabilization
Regulatory Asset and Liability [Line Items]
Revenue from contract with customer			16,901		$ 11,064	$ 16,901	$ 22,821
First Mortgage Obligations, Series 2017A , Tranche 1, 3.34%, due through 2029
Regulatory Asset and Liability [Line Items]
Term of issuance						12 years
Craig Generating Station Unit 2 And 3
Regulatory Asset and Liability [Line Items]
Impairment losses of long-lived assets				$ 261,600
Interest rate swaps, realized gain
Regulatory Asset and Liability [Line Items]
Regulatory liabilities			1,625			$ 1,625		1,854
Proceeds from settlement of interest rate swaps		$ 4,600
Deferred membership withdrawal income
Regulatory Asset and Liability [Line Items]
Regulatory liabilities	$ 530,100		513,699			513,699		463
Transmission credit
Regulatory Asset and Liability [Line Items]
Regulatory liabilities			178,511			178,511		0
Deferred income tax expense
Regulatory Asset and Liability [Line Items]
Regulatory assets			15,223			15,223		15,223
Deferred prepaid lease expense | Springerville Unit 3 Lease
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 73,406			73,406		74,551
Annual amortization expense of regulatory asset						$ 2,300
Amortization period			47 years			47 years
Acquisition costs | J.M. Shafer
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 36,325			$ 36,325		37,749
Annual amortization expense of regulatory asset						$ 2,800
Amortization period			25 years			25 years
Acquisition costs | Colowyo Coal
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 32,545			$ 32,545		33,062
Annual amortization expense of regulatory asset						$ 1,000
Amortization period			44 years			44 years
Deferred debt prepayment transaction costs
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 102,103			$ 102,103		106,417
Annual amortization expense of regulatory asset						$ 8,600
Amortization period			21 years 4 months 24 days			21 years 4 months 24 days
Deferred impairment loss | Escalante Generating Station
Regulatory Asset and Liability [Line Items]
Annual amortization expense of regulatory asset						$ 12,200
Deferred impairment loss | Rifle Generating Station
Regulatory Asset and Liability [Line Items]
Annual amortization expense of regulatory asset						600
Deferred impairment loss | Holcomb Expansion
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 72,458			72,458		74,795
Annual amortization expense of regulatory asset						$ 4,700
Amortization period			20 years			20 years
Deferred impairment loss | J.M. Shafer
Regulatory Asset and Liability [Line Items]
Amortization period			25 years			25 years
Deferred impairment loss | Unrecovered Plants
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 526,425			$ 526,425		532,817
Environmental Obligation
Regulatory Asset and Liability [Line Items]
Regulatory assets			$ 44,869			44,869		$ 44,869
Annual amortization expense of regulatory asset						$ 1,800
Amortization period			25 years			25 years

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Electric Plant (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Electric Plant
Accumulated Depreciation	$ (2,772,281)	$ (2,739,924)
Construction work in progress	256,301	163,954
Net electric plant	3,157,823	3,146,709
Electric Plant
Electric Plant
Plant In Service	5,673,803	5,722,679
Accumulated Depreciation	(2,772,281)	(2,739,924)
Net Book Value	2,901,522	2,982,755
Construction work in progress	256,301	163,954
Net electric plant	3,157,823	3,146,709
Generation plant
Electric Plant
Plant In Service	3,089,810	3,082,133
Accumulated Depreciation	(1,699,258)	(1,669,941)
Net Book Value	$ 1,390,552	$ 1,412,192
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	$ 1,895,240	$ 1,983,629
Accumulated Depreciation	(701,422)	(708,412)
Net Book Value	$ 1,193,818	$ 1,275,217
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	$ 448,016	$ 410,856
Accumulated Depreciation	(274,586)	(266,013)
Net Book Value	$ 173,430	$ 144,843
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	$ 240,737	$ 246,061
Accumulated Depreciation	(97,015)	(95,558)
Net Book Value	$ 143,722	$ 150,503
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 - Jointly Owned Facilities (Details) $ in Thousands	Jun. 30, 2024 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service	$ 929,637
Accumulated Depreciation	712,344
Construction Work In Progress	$ 7,047
Yampa Project - Craig Generating Station Units 1 and 2
Jointly Owned Utility Plant Interests [Line Items]
Tri-State Share (as a percent)	24%
Electric Plant in Service	$ 392,510
Accumulated Depreciation	362,750
Construction Work In Progress	$ 0
MBPP - Laramie River Station
Jointly Owned Utility Plant Interests [Line Items]
Tri-State Share (as a percent)	28.50%
Electric Plant in Service	$ 537,127
Accumulated Depreciation	349,594
Construction Work In Progress	$ 7,047

PROPERTY, PLANT AND EQUIPMENT_3

PROPERTY, PLANT AND EQUIPMENT - Other Plant (Details) - USD ($) $ in Thousands	Jun. 30, 2024	Dec. 31, 2023
Other Plant Assets
Other plant assets	$ 950,982	$ 952,318
Less allowances for depreciation, amortization and depletion	(726,882)	(711,896)
Net other plant	224,100	240,422
Mine assets
Other Plant Assets
Less allowances for depreciation, amortization and depletion	(199,278)	(184,239)
Net other plant	202,480	218,650
Mine assets | Colowyo Mine
Other Plant Assets
Other plant assets	395,438	396,441
Mine assets | New Horizon Mine
Other Plant Assets
Other plant assets	6,320	6,448
Non-utility assets
Other Plant Assets
Other plant assets	549,224	549,430
Less allowances for depreciation, amortization and depletion	(527,604)	(527,658)
Net other plant	$ 21,620	$ 21,772
Elk Ridge
Property, Plant and Equipment [Line Items]
Ownership interest held by parent (as a percent)	100%

INVESTMENTS IN OTHER ASSOCIAT_3

INVESTMENTS IN OTHER ASSOCIATIONS (Details) - USD ($)	6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	$ 185,673,000		$ 187,684,000
Impairment during the period	0	$ 0
Basin Electric Power Cooperative
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	135,652,000		135,652,000
National Rural Utilities Cooperative Finance Corporation - patronage capital
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	12,451,000		12,451,000
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		15,054,000
CoBank, ACB
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	16,946,000		18,809,000
Other
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	$ 5,570,000		$ 5,718,000

CASH, CASH EQUIVALENTS AND RE_3

CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS (Details) - USD ($) $ in Thousands	Jun. 30, 2024	Dec. 31, 2023	Jun. 30, 2023	Dec. 31, 2022
Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	$ 110,498	$ 106,005
Restricted cash and investments - current	697	605
Restricted cash and investments - noncurrent	172,252	3,408
Cash, cash equivalents and restricted cash and investments	$ 283,447	$ 110,018	$ 136,841	$ 110,682

CONTRACT ASSETS AND CONTRACT _3

CONTRACT ASSETS AND CONTRACT LIABILITIES (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Contract liabilities recognized	$ 600
Accounts receivable
Accounts receivable—Utility Members	93,883	$ 101,394
Other accounts receivable - trade:	27,446	23,123
Contract liabilities
Contract liabilities (unearned revenue)	3,589	4,159
Other accounts receivable - trade
Accounts receivable
Other accounts receivable - trade:	27,327	20,734
Other accounts receivable - trade | Non-member electric sales
Accounts receivable
Other accounts receivable - trade:	16,048	9,657
Other accounts receivable - trade | Other
Accounts receivable
Other accounts receivable - trade:	11,279	11,077
Other accounts receivable - nontrade
Accounts receivable
Other accounts receivable - trade:	$ 119	$ 2,389

OTHER DEFERRED CHARGES (Details

OTHER DEFERRED CHARGES (Details) - USD ($) $ in Thousands	Jun. 30, 2024	Dec. 31, 2023
Deferred Costs [Abstract]
Preliminary surveys and investigations	$ 14,980	$ 12,845
Advances to operating agents of jointly owned facilities	7,995	2,750
Operating lease right-of-use assets	10,319	6,477
Other	23,285	14,049
Total other deferred charges	$ 56,579	$ 36,121

LONG-TERM DEBT - Narrative (Det

LONG-TERM DEBT - Narrative (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Long-term debt	$ 2,706,512	$ 2,896,506
2022 Revolving Credit Agreement | Commercial Paper
Debt Instrument [Line Items]
Maximum borrowing capacity	500,000
Available borrowing capacity	384,000
Line of Credit | 2022 Revolving Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity	520,000
Swingline sublimit	125,000
Letter of credit sublimit	75,000
Available borrowing capacity	$ 404,000
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 | Springerville certificates, 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	Jun. 30, 2024	Dec. 31, 2023
Long-term debt, components
Total debt	$ 2,914,553	$ 3,137,534
Less debt issuance costs	(18,269)	(19,723)
Less debt discounts	(8,531)	(8,678)
Plus debt premiums	10,488	10,896
Total debt adjusted for debt issuance costs, discounts and premiums	2,898,241	3,120,029
Less current maturities	(191,729)	(223,523)
Long-term debt	$ 2,706,512	$ 2,896,506

SHORT-TERM BORROWINGS (Details)

SHORT-TERM BORROWINGS (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Short-Term Debt [Line Items]
Short-term borrowings	$ 116,101	$ 184,305
Weighted average interest rate (as a percent)	5.51%	5.62%
Short-term Borrowings - Other
Short-Term Debt [Line Items]
Short-term borrowings	$ 100	$ 100
Commercial Paper
Short-Term Debt [Line Items]
Short-term borrowings	116,001	$ 184,205
Commercial Paper | Commercial Paper
Short-Term Debt [Line Items]
Commercial paper outstanding, including short term and long term	116,000
Commercial Paper | 2022 Revolving Credit Agreement
Short-Term Debt [Line Items]
Maximum amount per commercial paper sublimit	500,000
Available borrowing capacity	$ 384,000
Commercial Paper | 2022 Revolving Credit Agreement | Maximum
Short-Term Debt [Line Items]
Term of issuance	397 days

ASSET RETIREMENT AND ENVIRONM_3

ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2024 USD ($) pit
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies [Line Items]
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	2
New Horizon Mine
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies [Line Items]
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	6 Months Ended
	Jun. 30, 2024	Dec. 31, 2023
Asset Retirement Obligation and Accrual for Environmental Loss Contingencies [Roll Forward]
Obligations at beginning of period	$ 217,201
Liabilities incurred	3,456
Liabilities settled	(2,450)
Accretion expense	3,597
Total obligations at end of period	221,804
Less current obligations at end of period	(18,822)
Long-term obligations at end of period	$ 202,982	$ 195,566

OTHER DEFERRED CREDITS AND OT_3

OTHER DEFERRED CREDITS AND OTHER LIABILITIES - Summary (Details) - USD ($) $ in Thousands	Jun. 30, 2024	Dec. 31, 2023
Deferred Credits and Other Liabilities [Abstract]
Transmission easements	$ 17,949	$ 17,862
OATT deposits	38,059	27,872
Financial liabilities - reclamation	12,564	16,895
Customer deposits	13,251	12,091
Contract liabilities (unearned revenue) - noncurrent	2,871	3,125
Operating lease liabilities - noncurrent	5,461	1,396
Other	4,468	4,884
Total other deferred credits and other liabilities	$ 94,623	$ 84,125

OTHER DEFERRED CREDITS AND OT_4

OTHER DEFERRED CREDITS AND OTHER LIABILITIES - Narrative (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Jun. 30, 2024	Dec. 31, 2023
Deferred credits and other liabilities
Transmission easements		$ 17,949	$ 17,862
Transmission Right of Way Easements
Deferred credits and other liabilities
Total due for easement right of way	$ 26,100
Transmission Right of Way Easements | Other Deferred Credits and Other Liabilities
Deferred credits and other liabilities
Transmission easements		$ 17,900

EMPLOYEE BENEFIT PLANS - Postre

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other than Pensions - Obligations (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2024 USD ($) plan
Medical Benefit Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Total postretirement and postemployment medical obligations at end of period	$ 1,016
Postretirement Medical Benefit Plans
Defined Contribution Plan Disclosure [Line Items]
Threshold of unrecognized amount of actuarial gains and losses as a proportion of projected benefit obligation (as a percent)	10%
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Postretirement medical benefit obligation at beginning of period	$ 924
Interest cost	29
Benefit payments (net of contributions by participants)	(180)
Total postretirement and postemployment medical obligations at end of period	773
Postemployment Medical Benefit Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Total postretirement and postemployment medical obligations at end of period	$ 243
Executive Benefit Restoration Plan
Defined Contribution Plan Disclosure [Line Items]
Threshold of unrecognized amount of actuarial gains and losses as a proportion of projected benefit obligation (as a percent)	10%
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Postretirement medical benefit obligation at beginning of period	$ 10,158
Interest cost	220
Benefit payments (net of contributions by participants)	(898)
Total postretirement and postemployment medical obligations at end of period	$ 9,628
Non-bargaining unit employees | Medical Benefit Plans
Defined Contribution Plan Disclosure [Line Items]
Number of plans | plan	3
Non-bargaining unit employees | Medical Benefit Plans | Maximum
Defined Contribution Plan Disclosure [Line Items]
Qualifying age	65 years
Non-bargaining unit employees | Postretirement Medical Benefit Plans
Defined Contribution Plan Disclosure [Line Items]
Number of plans | plan	2
Non-bargaining unit employees | Postretirement Medical Benefit Plans | Minimum
Defined Contribution Plan Disclosure [Line Items]
Qualifying age	55 years
Non-bargaining unit employees | Postemployment Medical Benefit Plans
Defined Contribution Plan Disclosure [Line Items]
Number of plans | plan	3

EMPLOYEE BENEFIT PLANS - Post_2

EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other than Pensions - Actuarial Gains and Losses (Details) - Postretirement Medical Benefit Plans - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Roll Forward]
Amounts included in accumulated other comprehensive income at beginning of period			$ 1,114
Amortization of prior service credit into other income	$ (127)	$ (410)	(536)	$ (819)
Amounts included in accumulated other comprehensive income at end of period	$ 578		$ 578

EMPLOYEE BENEFIT PLANS - NRECA

EMPLOYEE BENEFIT PLANS - NRECA Executive Benefit Restoration Plan - Obligations (Details) - Executive Benefit Restoration Plan $ in Thousands	6 Months Ended
	Jun. 30, 2024 USD ($)
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Postretirement medical benefit obligation at beginning of period	$ 10,158
Service cost	148
Interest cost	220
Benefit payments	(898)
Total postretirement and postemployment medical obligations at end of period	9,628
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	10,298
Benefits paid	(898)
Actual return on plan assets	153
Fair value of plan assets at end of period	9,553
Net liability recognized at end of period	$ 75
Threshold of unrecognized amount of actuarial gains and losses as a proportion of projected benefit obligation (as a percent)	10%

EMPLOYEE BENEFIT PLANS - NREC_2

EMPLOYEE BENEFIT PLANS - NRECA Executive Benefit Restoration Plan - Actuarial Gains and Losses (Details) - Executive Benefit Restoration Plan - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Roll Forward]
Amounts included in accumulated other comprehensive income at beginning of period			$ (1,639)
Amortization of prior service credit into other income	$ 220	$ 289	509	$ 578
Amounts included in accumulated other comprehensive income at end of period	$ (1,130)		$ (1,130)

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2024 USD ($)	Jun. 30, 2023 USD ($)	Jun. 30, 2024 USD ($) demand_rate billing_component	Jun. 30, 2023 USD ($)
Disaggregation of Revenue [Line Items]
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
Rate stabilization
Disaggregation of Revenue [Line Items]
Revenue from contract with customer | $	$ 16,901	$ 11,064	$ 16,901	$ 22,821

REVENUE - Summary (Details)

REVENUE - Summary (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Disaggregation of Revenue [Line Items]
Other	$ 23,544	$ 14,686	$ 43,648	$ 32,544
Operating revenues	337,499	318,455	689,048	682,506
Total non-member electric sales and other operating revenue
Disaggregation of Revenue [Line Items]
Operating revenues	79,213	44,230	134,936	116,105
Non-member electric sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	38,768	18,486	74,387	60,436
Rate stabilization
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	16,901	11,064	16,901	22,821
Provision for rate refunds
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0	(6)	0	304
Coal sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,814	3,315	3,458	4,394
Other
Disaggregation of Revenue [Line Items]
Other	21,730	11,371	40,190	28,150
Long-term contracts | Non-member electric sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	29,813	8,996	51,188	21,796
Short-term contracts | Non-member electric sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 8,955	$ 9,490	$ 23,199	$ 38,640

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023
Income Tax Disclosure [Abstract]
Income tax expense	$ 0	$ 23	$ 0	$ 45

LEASES - Narrative (Details)

LEASES - Narrative (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2024 USD ($) renewal_option	Jun. 30, 2023 USD ($)	Jun. 30, 2024 USD ($) renewal_option	Jun. 30, 2023 USD ($)
Leases [Abstract]
Operating lease expense	$ 0.7	$ 0.6	$ 1.3	$ 1.2
Operating lease term	30 years		30 years
Operating lease, number of renewal options | renewal_option	2		2
Operating lease, renewal option term	5 years		5 years
Lease revenue	$ 4.7	$ 1.7	$ 6.4	$ 3.4

LEASES - Lease Components (Deta

LEASES - Lease Components (Details) - USD ($) $ in Thousands	Jun. 30, 2024	Dec. 31, 2023
Operating Lease [Abstract]
Operating lease right-of-use assets	$ 13,238	$ 9,072
Less: Accumulated amortization	(2,919)	(2,595)
Net operating lease right-of-use assets	10,319	6,477
Operating lease liabilities - current	(471)	(371)
Operating lease liabilities - noncurrent	(5,461)	(1,396)
Total operating lease liabilities	$ (5,932)	$ (1,767)
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	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
Finance Lease [Abstract]
Finance lease right-of-use assets	$ 95	$ 0
Less: Accumulated amortization	(7)	0
Net finance lease right-of-use assets	88	0
Finance lease liabilities - current	(46)	0
Finance lease liabilities - noncurrent	(37)	0
Total finance lease liabilities	$ (83)	$ 0
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other	Other
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Accrued expenses	Accrued expenses
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other	Other
Weighted-average remaining lease term (in years)
Operating leases, weighted average remaining lease term	32 years 1 month 6 days	7 years
Finance leases, weighted average remaining lease term	1 year 10 months 24 days	0 years
Weighted-average discount rate
Operating leases, weighted average discount rate (as a percent)	6.91%	4.68%
Finance leases, weighted average discount rate (as a percent)	6.99%	0%

LEASES - Future Minimum Lease C

LEASES - Future Minimum Lease Commitments (Details) - USD ($) $ in Thousands	Jun. 30, 2024	Dec. 31, 2023
Operating Leases
Year 1	$ 703
Year 2	517
Year 3	531
Year 4	838
Year 5	432
Thereafter	12,401
Total lease payments	15,422
Less imputed interest	(9,490)
Total	5,932	$ 1,767
Finance Leases
Year 1	51
Year 2	38
Year 3	0
Year 4	0
Year 5	0
Thereafter	0
Total lease payments	89
Less imputed interest	(6)
Total	83	$ 0
Total
Year 1	754
Year 2	555
Year 3	531
Year 4	838
Year 5	432
Thereafter	12,401
Total lease payments	15,511
Less imputed interest	(9,496)
Total	$ 6,015

FAIR VALUE (Details)

FAIR VALUE (Details) - USD ($) $ in Thousands	Jun. 30, 2024	Dec. 31, 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 256,000	$ 83,000
Cost
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	2,914,553	3,137,534
Cost | EBT Trust Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	9,987	10,821
Cost | Director and Executive Elective Deferred Compensation Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	557	576
Estimated Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	2,615,600	2,909,301
Estimated Fair Value | EBT Trust Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	9,553	10,298
Estimated Fair Value | Director and Executive Elective Deferred Compensation Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	$ 564	$ 530

VARIABLE INTEREST ENTITIES - Na

VARIABLE INTEREST ENTITIES - Narrative (Details)	6 Months Ended
	Jun. 30, 2024
Variable Interest Entity, Primary Beneficiary | Springerville Unit 3 Lease
Variable Interest Entity [Line Items]
Financial and other support provided (as a percent)	100%
Springerville Partnership
Variable Interest Entity [Line Items]
Equity interest (as a percent)	51%
General partner interest (as a percent)	1%
Springerville Partnership | Other Limited Partners
Variable Interest Entity [Line Items]
Ownership interest held by noncontrolling interest (as a percent)	49%
Springerville Unit 3 Holding LLC | Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Ownership interest held by parent (as a percent)	100%

VARIABLE INTEREST ENTITIES - Su

VARIABLE INTEREST ENTITIES - Summary (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2024	Jun. 30, 2023	Jun. 30, 2024	Jun. 30, 2023	Dec. 31, 2023
Variable Interest Entity [Line Items]
Net electric plant	$ 3,157,823		$ 3,157,823		$ 3,146,709
Noncontrolling interest	129,738		129,738		134,269
Long-term debt	2,706,512		2,706,512		2,896,506
Accrued interest	22,545		22,545		24,549
Interest	42,614	$ 41,495	85,108	$ 81,276
Variable Interest Entity, Primary Beneficiary | Reportable Legal Entities
Variable Interest Entity [Line Items]
Net electric plant	694,790		694,790		703,859
Noncontrolling interest	129,737		129,737		134,269
Long-term debt	173,091		173,091		206,027
Accrued interest	4,997		4,997		$ 5,968
Depreciation, amortization and depletion	4,535	4,535	9,069	9,069
Interest	$ 2,852	$ 3,401	$ 5,885	$ 7,068

LEGAL (Details)

LEGAL (Details) $ in Millions		3 Months Ended
	May 01, 2024 USD ($)	Jun. 30, 2022 USD ($)	Jun. 30, 2024	Aug. 31, 2020 $ / MWh
Commitments and Contingencies Disclosure [Abstract]
Notice period for contract termination payment			2 years
Amount received for contract termination payment	$ 709.4
Exit fee related to contract termination payment	627.2
Patronage capital credit related to contract termination payment	$ 82.2
Soft-cap price for short term spot market sales (per megawatt hour) | $ / MWh				1,000
Funds in excess of soft-cap		$ 2.9
Energy sales refunded to third party		$ 0.4