10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

__________________________________

FORM 10-Q

(Mark One)

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2022

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 333-212006

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

(Exact name of registrant as specified in its charter)

Colorado		84-0464189
(State or other jurisdiction of incorporation or organization)		(I.R.S. employer identification number)
1100 West 116th Avenue
Westminster,	Colorado	80234
(Address of principal executive offices)		(Zip Code)

(303) 452-6111

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☐ No ☒ (Note: The registrant is not subject to the filing requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 (the “Exchange Act”), but voluntarily files reports with the Securities and Exchange Commission).

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ☐ Accelerated filer ☐

Non-accelerated Filer ☒ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
None	None	None

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date. The registrant is a membership corporation and has no authorized or outstanding equity securities.

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

INDEX TO QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED JUNE 30, 2022

		Page Number
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Financial Position as of June 30, 2022 (unaudited) and December 31, 2021	1
	Consolidated Statements of Operations — Three and Six Months Ended June 30, 2022 and 2021 (unaudited)	2
	Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, 2022 and 2021 (unaudited)	3
	Consolidated Statements of Equity — Three and Six Ended June 30, 2022 and 2021 (unaudited)	4
	Consolidated Statements of Cash Flows — Six Months Ended June 30, 2022 and 2021 (unaudited)	5
	Notes to Unaudited Consolidated Financial Statements For the Three and Six Months Ended June 30, 2022 and 2021	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33
Item 4.	Controls and Procedures	34
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	34
Item 4.	Mine Safety Disclosures	34
Item 6.	Exhibits	34
SIGNATURES

i

GLOSSARY

The following abbreviations and acronyms used in this quarterly report on Form 10-Q are defined below:

Abbreviations or Acronyms	Definition
2018 Revolving Credit Agreement	Credit Agreement, dated as of April 25, 2018, between us and CFC, as administrative agent
2022 Revolving Credit Agreement	Amended and Restated Credit Agreement, dated as of April 25, 2022, between us and CFC, as administrative agent
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
Basin	Basin Electric Power Cooperative
Board	Board of Directors
CDPHE	Colorado Department of Public Health and Environment
CFC	National Rural Utilities Cooperative Finance Corporation
CoBank	CoBank, ACB
Colowyo Coal	Colowyo Coal Company L.P., a subsidiary of ours
COPUC	Colorado Public Utilities Commission
D.C. Circuit Court of Appeals	United States Court of Appeals for the District of Columbia Circuit
DSR	Debt Service Ratio (as defined in our Master Indenture)
ECR	Equity to Capitalization Ratio (as defined in our Master Indenture)
EPA	Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings Inc.
FPA	Federal Power Act, as amended
GAAP	accounting principles generally accepted in the United States
Jurisdictional PDO	our Petition for Declaratory Order on Jurisdiction under Part II of Federal Power Act, filed with FERC on December 23, 2019, EL20-16-000
kWh	kilowatt hour
LIBOR	London Interbank Offered Rate
LPEA	La Plata Electric Association, Inc.
Master Indenture	Master First Mortgage Indenture, Deed of Trust and Security Agreement, dated effective as of December 15, 1999, between us and U.S. Bank Trust Company, National Association, as successor trustee
MBPP	Missouri Basin Power Project
Members	our Utility Members and Non-Utility Members
Moody’s	Moody’s Investors Services, Inc.
MW	megawatt
MWh	megawatt hour
Non-Utility Members	our non-utility members
OATT	Open Access Transmission Tariff
S&P	S & P Global Ratings
SEC	Securities and Exchange Commission
Springerville Partnership	Springerville Unit 3 Partnership LP, a subsidiary of ours
Springerville Unit 3	Springerville Generating Station Unit 3
Term SOFR	the implied rate on the future movement in the Secured Overnight Financing Rate (or "SOFR") over a future reference period
Tri-State, We, Our, Us, the Association	Tri-State Generation and Transmission Association, Inc.

ii

United Power	United Power, Inc.
Utility Members	our electric distribution member systems, consisting of both Class A members and Class B members

iii

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains “forward-looking statements.” All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy and development, construction, operation, or closure of facilities (often, but not always, identified through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “forecast,” “projection,” “target” and “outlook”) are forward-looking statements.

Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements.

iv

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Financial Position

(dollars in thousands)

	June 30, 2022		December 31, 2021
ASSETS	(unaudited)
Property, plant and equipment
Electric plant
In service	$	5,669,932	$	5,606,732
Construction work in progress	80,774		107,636
Total electric plant	5,750,706		5,714,368
Less allowances for depreciation and amortization	(2,397,715)		(2,367,197)
Net electric plant	3,352,991		3,347,171
Other plant	933,479		1,093,922
Less allowances for depreciation, amortization and depletion	(673,691)		(823,087)
Net other plant	259,788		270,835
Total property, plant and equipment	3,612,779		3,618,006
Other assets and investments
Investments in other associations	164,259		163,097
Investments in and advances to coal mines	2,171		2,273
Restricted cash and investments	3,746		4,101
Other noncurrent assets	16,102		15,873
Total other assets and investments	186,278		185,344
Current assets
Cash and cash equivalents	96,841		100,555
Restricted cash and investments	663		480
Deposits and advances	35,672		34,042
Accounts receivable—Utility Members	111,571		95,630
Other accounts receivable	25,563		21,571
Land held for sale	411		—
Coal inventory	55,689		59,701
Materials and supplies	92,274		87,234
Total current assets	418,684		399,213
Deferred charges
Regulatory assets	674,378		665,693
Prepayment—NRECA Retirement Security Plan	13,431		16,117
Other	41,037		35,139
Total deferred charges	728,846		716,949
Total assets	$	4,946,587	$	4,919,512
EQUITY AND LIABILITIES
Capitalization
Patronage capital equity	$	924,243	$	994,865
Accumulated other comprehensive loss	(2,196)		(1,460)
Noncontrolling interest	122,894		119,100
Total equity	1,044,941		1,112,505
Long-term debt	2,896,050		3,101,870
Total capitalization	3,940,991		4,214,375
Current liabilities
Utility Member advances	19,784		17,217
Accounts payable	126,605		105,965
Short-term borrowings	179,699		49,997
Accrued expenses	32,264		32,882
Current asset retirement obligations	4,953		7,003
Accrued interest	24,230		25,716
Accrued property taxes	19,976		33,877
Current maturities of long-term debt	201,575		93,039
Total current liabilities	609,086		365,696
Deferred credits and other liabilities
Regulatory liabilities	120,436		146,021
Deferred income tax liability	19,023		18,987
Asset retirement and environmental reclamation obligations	168,364		83,278
Other	75,761		78,319
Total deferred credits and other liabilities	383,584		326,605
Accumulated postretirement benefit and postemployment obligations	12,926		12,836
Total equity and liabilities	$	4,946,587	$	4,919,512

The accompanying notes are an integral part of these consolidated financial statements.

1

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Operations (unaudited)

(dollars in thousands)

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Operating revenues
Utility Member electric sales	$	286,568	$	274,445	$	568,815	$	547,243
Non-member electric sales	34,214		16,188		57,158		33,529
Rate stabilization	17,462		19,957		25,345		40,790
Other	13,718		15,712		25,846		30,712
	351,962		326,302		677,164		652,274
Operating expenses
Purchased power	105,738		86,552		193,038		173,569
Fuel	68,247		45,870		130,721		106,417
Production	50,254		52,841		88,050		93,742
Transmission	42,053		41,948		89,235		86,619
General and administrative	18,893		11,897		39,166		26,484
Depreciation, amortization and depletion	45,269		46,483		86,743		99,238
Coal mining	3,849		966		5,375		2,507
Other	47,302		1,282		48,339		3,833
	381,605		287,839		680,667		592,409
Operating margins	(29,643)		38,463		(3,503)		59,865
Other income
Interest	928		907		1,786		1,784
Capital credits from cooperatives	1		2		4,595		4,275
Other income (expense)	(14)		1,032		871		1,889
	915		1,941		7,252		7,948
Interest expense
Interest	35,309		36,092		70,990		72,207
Interest charged during construction	(397)		(1,004)		(792)		(1,978)
	34,912		35,088		70,198		70,229
Income tax expense	19		110		37		219
Net margins including noncontrolling interest	(63,659)		5,206		(66,486)		(2,635)
Net margin attributable to noncontrolling interest	(2,128)		(1,762)		(4,136)		(3,411)
Net margins attributable to the Association	$	(65,787)	$	3,444	$	(70,622)	$	(6,046)

The accompanying notes are an integral part of these consolidated financial statements.

2

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Comprehensive Income (Loss) (unaudited)

(dollars in thousands)

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Net margins including noncontrolling interest	$	(63,659)	$	5,206	$	(66,486)	$	(2,635)
Other comprehensive loss:
Unrealized loss on securities available for sale	(56)		(7)		(232)		(41)
Amortization of prior service credit on postretirement benefit obligation included in net margin	(535)		(20)		(1,070)		(40)
Amortization of actuarial loss on executive benefit restoration obligation included in net margin	—		—		—		312
Amortization of prior service cost on executive benefit restoration obligation included in net margin	283		239		566		459
Unrecognized prior service cost	—		—		—		(1,121)
Other comprehensive income (loss)	(308)		212		(736)		(431)
Comprehensive income (loss) including noncontrolling interest	(63,967)		5,418		(67,222)		(3,066)
Net comprehensive income attributable to noncontrolling interest	(2,128)		(1,762)		(4,136)		(3,411)
Comprehensive income (loss) attributable to the Association	$	(66,095)	$	3,656	$	(71,358)	$	(6,477)

The accompanying notes are an integral part of these consolidated financial statements.

3

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Equity (unaudited)

(dollars in thousands)

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Patronage capital equity at beginning of period	$	990,030	$	969,029	$	994,865	$	978,519
Net margins attributable to the Association	(65,787)		3,444		(70,622)		(6,046)
Patronage capital equity at end of period	924,243		972,473		924,243		972,473
Accumulated other comprehensive loss at beginning of period	(1,888)		(6,357)		(1,460)		(5,714)
Unrealized loss on securities available for sale	(56)		(7)		(232)		(41)
Reclassification adjustment of prior service credit on postretirement benefit obligation included in net margin	(535)		(20)		(1,070)		(40)
Reclassification adjustment for actuarial loss on executive benefit restoration obligation included in net margin	—		—		—		312
Reclassification adjustment for prior service cost on executive benefit restoration obligation included in net margin	283		239		566		459
Unrecognized prior service cost	—		—		—		(1,121)
Accumulated other comprehensive loss at end of period	(2,196)		(6,145)		(2,196)		(6,145)
Noncontrolling interest at beginning of period	120,766		113,807		119,100		114,851
Net comprehensive income attributable to noncontrolling interest	2,128		1,762		4,136		3,411
Equity distribution to noncontrolling interest	—		—		(342)		(2,693)
Noncontrolling interest at end of period	122,894		115,569		122,894		115,569
Total equity at end of period	$	1,044,941	$	1,081,897	$	1,044,941	$	1,081,897

The accompanying notes are an integral part of these consolidated financial statements.

4

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Cash Flows (unaudited)

(dollars in thousands)

	Six Months Ended June 30,
	2022		2021
Operating activities
Net margins including noncontrolling interest	$	(66,486)	$	(2,635)
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion	86,743		99,238
Amortization of NRECA Retirement Security Plan prepayment	2,686		2,686
Amortization of debt issuance costs	1,738		1,249
Impairment loss	29,250		—
Deferred impairment loss	(29,250)		—
Rate stabilization revenue	(25,345)		(40,790)
Deposits associated with generator interconnection requests	9,766		17,130
Capital credit allocations from cooperatives and income from coal mines over refund distributions	(1,135)		(957)
Changes in operating assets and liabilities:
Accounts receivable	(24,984)		(19,250)
Coal inventory	4,013		(9,202)
Materials and supplies	(5,040)		(249)
Accounts payable and accrued expenses	26,027		23,681
Accrued interest	(1,486)		(1,628)
Accrued property taxes	(13,901)		(14,640)
New Horizon Mine environmental obligation	44,869		—
Other	(9,723)		(1,935)
Net cash provided by operating activities	27,742		52,698
Investing activities
Purchases of plant	(56,115)		(52,030)
Changes in deferred charges	(3,644)		(5,325)
Proceeds from other investments	75		72
Net cash used in investing activities	(59,684)		(57,283)
Financing activities
Changes in Member advances	2,433		2,499
Payments of long-term debt	(97,417)		(73,946)
Debt issuance costs	(1,311)		—
Change in short-term borrowings, net	129,702		79,968
Retirement of patronage capital	(4,564)		(13,705)
Equity distribution to noncontrolling interest	(342)		(2,693)
Other	(445)		(409)
Net cash provided by (used in) financing activities	28,056		(8,286)
Net decrease in cash, cash equivalents and restricted cash and investments	(3,886)		(12,871)
Cash, cash equivalents and restricted cash and investments – beginning	105,136		132,074
Cash, cash equivalents and restricted cash and investments – ending	$	101,250	$	119,203
Supplemental cash flow information:
Cash paid for interest	$	70,942	$	72,904
Cash paid for income taxes	$	—	$	—
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$	(2,606)	$	397

The accompanying notes are an integral part of these consolidated financial statements.

5

Tri-State Generation and Transmission Association, Inc.

Notes to Unaudited Consolidated Financial Statements

For the Three and Six Months Ended June 30, 2022 and 2021

NOTE 1 – PRESENTATION OF FINANCIAL INFORMATION

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“GAAP”) for interim financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. These unaudited consolidated financial statements should be read in conjunction with the financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2021 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, 2022, results of operations for the three and six months ended June 30, 2022 and 2021, and cash flows for the six months ended June 30, 2022 and 2021 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-two electric distribution member systems who are Class A members to which we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members. We have three non-utility members (“Non-Utility Members”). Our Class A members and any Class B members are collectively referred to as our “Utility Members.” Our Class A members, any Class B members, and Non-Utility Members are collectively referred to as our “Members.” The addition of Non-Utility Members in 2019 and specifically the addition of MIECO, Inc. on September 3, 2019 removed the exemption from the Federal Energy Regulatory Commission’s (“FERC”) regulation for us, thus subjecting us to full rate and transmission jurisdiction by FERC effective September 3, 2019. Our stated rate to our Class A members was filed at FERC on December 23, 2019 and was accepted by FERC on March 20, 2020. On August 2, 2021, FERC approved our settlement agreement related to our stated rate to our Class A members. See Note 17 – Legal.

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 16 – Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. We have eliminated all significant intercompany balances and transactions in consolidation.

Jointly Owned Facilities

We own undivided interests in two jointly owned generating facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common. These projects include the Yampa Project (operated by us) and the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)). Each participant in these agreements receives a portion of the total output of the generating facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and other operating expenses is included in our consolidated financial statements.

6

Our share in each jointly owned facility is as follows as of June 30, 2022 (dollars in thousands):

	Tri-State Share		Electric Plant in Service		Accumulated Depreciation		Construction Work In Progress
Yampa Project - Craig Generating Station Units 1 and 2	24.00	%	$	391,913	$	258,163	$	291
MBPP - Laramie River Station	28.50	%	525,986		339,367		4,168
Total			$	917,899	$	597,530	$	4,459

NOTE 2 – 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 of Directors (“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, 2022		December 31, 2021
Regulatory assets
Deferred income tax expense (1)	$	18,742	$	18,742
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)	77,988		79,133
Goodwill – J.M. Shafer (3)	42,023		43,447
Goodwill – Colowyo Coal (4)	34,611		35,128
Deferred debt prepayment transaction costs (5)	119,360		123,674
Deferred Holcomb expansion impairment loss (6)	81,807		84,145
Unrecovered plant (7)	299,847		281,424
Total regulatory assets	674,378		665,693
Regulatory liabilities
Interest rate swap - realized gain (8) and other	2,577		2,818
Membership withdrawal (9)	117,859		143,203
Total regulatory liabilities	120,436		146,021
Net regulatory asset	$	553,942	$	519,672

(1)A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues.

(2)Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Utility Members through rates.

(3)Represents goodwill related to our acquisition of an entity that owned J.M. Shafer Generating Station in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Utility Members through rates.

(4)Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Utility Members through rates.

7

(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 deferral of the impairment losses related to the early retirement of the Nucla, Escalante and Rifle Generating Stations. The deferred impairment loss for Nucla and Escalante Generating Stations is being amortized to depreciation, amortization and depletion expense in the amount of $7.7 million annually through December 2022 and $12.3 million annually over the 25-year period ending in December 2045, respectively, and recovered from our Utility Members through rates. In March 2022, our Board took action for the early retirement of the Rifle Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement, we recognized an impairment loss of $3.7 million during the first quarter of 2022. The Rifle Generating Station is anticipated to be retired from service in October 2022. Once retired, the deferred impairment loss will be amortized to depreciation, amortization and depletion expense through December 2028, which was the depreciable life of the Rifle Generating Station, and recovered from our Utility Members in rates.

(8)Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12-year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods.

(9) Represents the deferral of the recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. The deferred membership withdrawal income will be refunded to Utility Members through reduced rates when recognized in operating revenues in future periods. For the six months ended June 30, 2022, $25.3 million was recognized in operating revenues as part of our rate stabilization measures.

NOTE 3 – 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, 2022		December 31, 2021
Basin Electric Power Cooperative	$	116,826	$	116,826
National Rural Utilities Cooperative Finance Corporation - patronage capital	12,076		12,076
National Rural Utilities Cooperative Finance Corporation - capital term certificates	15,074		15,149
CoBank, ACB	14,328		12,985
Other	5,955		6,061
Investments in other associations	$	164,259	$	163,097

Our investments in other associations are considered equity securities without readily determinable fair values, and as such are measured at cost minus impairment. We have evaluated these investments for indicators of impairment. There were no impairments of these investments recognized during the six months ended June 30, 2022 or during 2021.

NOTE 4 – 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

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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, 2022		December 31, 2021
Cash and cash equivalents	$	96,841	$	100,555
Restricted cash and investments - current	663		480
Restricted cash and investments - noncurrent	3,746		4,101
Cash, cash equivalents and restricted cash and investments	$	101,250	$	105,136

NOTE 5 – 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 12 – 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, 2022, we recognized $0.7 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, 2022		December 31, 2021
Accounts receivable - Utility Members	$	111,571	$	95,630
Other accounts receivable - trade:
Non-member electric sales	10,133		5,684
Other	8,446		13,505
Total other accounts receivable - trade	18,579		19,189
Other accounts receivable - nontrade	6,984		2,382
Total other accounts receivable	$	25,563	$	21,571
Contract liabilities (unearned revenue)	$	5,207	$	5,372

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NOTE 6 – OTHER DEFERRED CHARGES

The following other deferred charges are reflected on our consolidated statements of financial position (dollars in thousands):

	June 30, 2022		December 31, 2021
Preliminary surveys and investigations	$	12,743	$	12,366
Advances to operating agents of jointly owned facilities	7,556		4,422
Operating lease right-of-use assets	6,997		7,529
Other	13,741		10,822
Total other deferred charges	$	41,037	$	35,139

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 14 – Leases.

NOTE 7 – LONG-TERM DEBT

We have $2.9 billion of long-term debt which consists of mortgage notes payable, pollution control revenue bonds and the Springerville certificates. The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement (“Master Indenture”) except for one unsecured note in the amount of $8.1 million as of June 30, 2022. Additionally, $100.0 million of our First Mortgage Bonds, Series 2014E-1 was reclassified to current maturities due to a public tender offer of such bonds which was completed in July 2022. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. All long-term debt contains certain restrictive financial covenants, including a debt service ratio requirement on an annual basis and an equity to capitalization ratio requirement of at least 18 percent at the end of each fiscal year. Other than the Springerville certificates that has a debt service ratio requirement of at least 1.02 on an annual basis, all other long-term debt contains a debt service ratio requirement of at least 1.10 on an annual basis.

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 extends through 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, 2022, we had $340.0 million in availability under the 2022 Revolving Credit Agreement.

Long-term debt consists of the following (dollars in thousands):

	June 30, 2022		December 31, 2021
Total debt	$	3,117,011	$	3,214,427
Less debt issuance costs	(22,684)		(23,110)
Less debt discounts	(9,118)		(9,398)
Plus debt premiums	12,416		12,990
Total debt adjusted for debt issuance costs, discounts and premiums	3,097,625		3,194,909
Less current maturities	(201,575)		(93,039)
Long-term debt	$	2,896,050	$	3,101,870

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NOTE 8 – 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.

Commercial paper consisted of the following (dollars in thousands):

	June 30, 2022			December 31, 2021
Commercial paper outstanding, net of discounts	$	179,699		$	49,997
Weighted average interest rate	1.86		%	0.19		%

At June 30, 2022, $320.0 million of the commercial paper back-up sublimit remained available under the 2022 Revolving Credit Agreement. See Note 7 – Long-Term Debt.

NOTE 9 – 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. One pit at the Colowyo Mine began final reclamation in 2020 with the other remaining pits still being actively mined.

Generation: We have asset retirement obligations related to equipment, dams, ponds, wells and underground storage tanks at the generating stations.

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Aggregate carrying amounts of asset retirement obligations and environmental reclamation obligations are as follows (dollars in thousands):

	Six Months Ended June 30, 2022
Obligations at beginning of period	$	90,281
Liabilities settled	(3,889)
Accretion expense	1,448
Change in estimate	85,477
Total obligations at end of period	$	173,317
Less current obligations at end of period	(4,953)
Long-term obligations at end of period	$	168,364

In the second quarter of 2022, we increased the environmental reclamation obligation at the New Horizon Mine by $44.9 million due to revised cost estimates. The New Horizon Mine environmental remediation liability that has been recorded is $67.3 million as of June 30, 2022. Of this amount, $36.8 million is recorded on a discounted basis, using a discount rate of 3.25 percent, with total estimated undiscounted future cash outflows of $57.9 million. Environmental obligation expense is included in other operating expenses on our consolidated statement of operations. Although the entire environmental obligation has been expensed, we may seek future rate recovery in upcoming rate filings with FERC. We continue to evaluate the New Horizon Mine and Colowyo Mine post reclamation obligations and will make adjustments to these obligations as needed. Also in the second quarter of 2022, we recorded an additional asset retirement obligation of $40.6 million related to a change in cost estimates for our pond, ash landfill and post-closure reclamation obligations at various generating stations.

We also have asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations attached to transmission and other easements that are considered by us to be operated in perpetuity and therefore the measurement of the obligation is not possible. A liability will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates as is needed to employ a present value technique to estimate fair value.

NOTE 10 – 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, 2022		December 31, 2021
Transmission easements	$	18,857	$	19,339
Operating lease liabilities - noncurrent	1,403		1,622
Contract liabilities (unearned revenue) - noncurrent	3,351		3,523
Customer deposits	8,632		9,287
Financial liabilities - reclamation	11,756		13,122
OATT deposits	24,520		24,327
Other	7,242		7,099
Total other deferred credits and other liabilities	$	75,761	$	78,319

In 2015, we renewed transmission right-of-way easements on tribal nation lands where certain of our electric transmission lines are located. $27.8 million will be paid by us for these easements from 2022 through the individual easement terms ending between 2036 and 2040. The present values for the remaining easement payments were $18.9 million and $19.3 million as of June 30, 2022 and December 31, 2021, respectively, which are recorded as other deferred credits and other liabilities.

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 14 – 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

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(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.

Financial liabilities - reclamation represents the financial obligation for our share of reclamation at San Juan Mine (related to our former ownership in the San Juan Generating Station) and our share of reclamation at Laramie River Station (related to our ownership share in MBPP).

OATT deposits primarily represent deposits that are received by us related to generator interconnection requests that may be returned if the project does proceed to completion.

NOTE 11 – 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 at June 30, 2022, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles. As of June 30, 2021, the plans ceased to provide postretirement medical benefits for employees who retire after June 30, 2021.

The postretirement medical benefit and post employment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and post employment obligations on our consolidated statements of financial position as follows (dollars in thousands):

	Six Months Ended June 30, 2022
Postretirement medical benefit obligation at beginning of period	$	2,809
Service cost	—
Interest cost	18
Benefit payments (net of contributions by participants)	(324)
Postretirement medical benefit obligation at end of period	$	2,503
Postemployment medical benefit obligation at end of period	392
Total postretirement and postemployment medical obligations at end of period	$	2,895

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, 2022
Accumulated other comprehensive income at beginning of period	$	3,580
Amortization of prior service credit into other income	(1,070)
Accumulated other comprehensive income at end of period	$	2,510

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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, 2022
Executive benefit restoration obligation at beginning of period	$	9,852
Service cost	185
Interest cost	104
Benefit payments	(111)
Executive benefit restoration at end of period	$	10,030
Fair value of plan assets at beginning of period	$	8,640
Employer contributions	303
Actual return on plan assets	$	(192)
Fair value of plan assets at end of period	$	8,751
Net liability recognized at end of period	$	1,279

The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations. In December 2020, we established an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary.

In accordance with the accounting standard related to defined benefit pension plans, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other income on our consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the executive benefit restoration obligation.

The net unrecognized actuarial gains and losses related to the executive benefit restoration obligations are included in accumulated other comprehensive income as follows (dollars in thousands):

	Six Months Ended June 30, 2022
Accumulated other comprehensive loss at beginning of period	$	(4,932)
Amortization of prior service cost into other income	566
Accumulated other comprehensive loss at end of period	$	(4,366)

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NOTE 12 – 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 42 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,
	2022		2021		2022		2021
Non-member electric sales:
Long-term contracts	$	12,970	$	10,093	$	25,250	$	18,799
Short-term contracts	21,244		6,095		31,908		14,730
Rate stabilization	17,462		19,957		25,345		40,790
Other	13,718		15,712		25,846		30,712
Total non-member electric sales and other operating revenue	$	65,394	$	51,857	$	108,349	$	105,031

Non-member electric sales

Revenues from wholesale electric power sales to non-members are primarily from long-term contracts and short-term market sales. Prior to our customers’ demand for energy, we do not have a contractual right to consideration as we are not obligated to provide energy until the customer demands each incremental unit of energy. We transfer control of the energy to our customer over time and our customer simultaneously receives and consumes the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method. Payments are received in accordance with the contract terms, which is less than 30 days after the invoice is received by the customer.

Rate Stabilization Revenue

We recognized $17.5 million and $25.3 million of deferred membership withdrawal income for the three and six months ended June 30, 2022, respectively, as directed by our Board. See Note 2 - Accounting for Rate Regulation.

Other operating revenue

Other operating revenue consists primarily of wheeling, transmission, and coal sales revenue. Other operating revenue also includes revenue we receive from our Non-Utility Members. Wheeling revenue is earned when we charge other energy companies for transmitting electricity over our transmission lines (payments are received in accordance with the contract terms

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which is within 20 days of the date the invoice is received). Transmission revenue is from Southwest Power Pool’s scheduling of transmission across our transmission assets in the Eastern Interconnection because of our membership in it (Southwest Power Pool collects the revenue from the customer and pays us for the scheduling, system control, dispatch transmission service, and the annual transmission revenue requirement). Each of these services or goods are provided over time and progress toward completion of our performance obligations are measured using the output method. Coal sales revenue results from the sale of coal from the Colowyo Mine and other locations to third parties. We have an obligation to deliver coal and progress of completion toward our performance obligation is measured using the output method. Our performance obligation is completed as coal is delivered.

NOTE 13 – 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. Effective January 1, 2020, we adopted the normalization method of recognizing deferred income taxes pursuant to FERC regulation. Under the normalization method, changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit).

Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues.

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. Our consolidated statements of operations included an income tax expense of $37,000 for the six months ended June 30, 2022 and $219,000 for the comparable period in 2021.

NOTE 14 – 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 current liabilities 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.

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, 2022 and $0.9 million for the comparable period in 2021. Rent expense for all short-term and long-term operating leases was $1.5 million for the six months ended June 30, 2022 and $1.9 million for the comparable period in 2021. 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. As of June 30, 2022, there were no arrangements accounted for as finance leases.

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Our consolidated statements of financial position include the following lease components (dollars in thousands):

	June 30, 2022			December 31, 2021
Operating leases
Operating lease right-of-use assets	$	8,936		$	9,081
Less: Accumulated amortization	(1,939)			(1,552)
Net operating lease right-of-use assets	$	6,997		$	7,529
Operating lease liabilities - current	$	(401)		$	(491)
Operating lease liabilities - noncurrent	(1,403)			(1,622)
Total operating lease liabilities	$	(1,804)		$	(2,113)
Operating leases
Weighted average remaining lease term (years)	7.5			7.6
Weighted average discount rate	3.82		%	3.79		%

Future expected minimum lease commitments under operating leases are as follows (dollars in thousands):

Year 1	$	290
Year 2	385
Year 3	278
Year 4	482
Year 5	94
Thereafter	596
Total lease payments	$	2,125
Less imputed interest	(321)
Total	$	1,804

Leasing Arrangements as Lessor

We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $1.8 million and $1.7 million for the three months ended June 30, 2022 and 2021, respectively, and $3.5 million for the six months ended June 30, 2022 and 2021 are included in other operating revenue on our consolidated statements of operations.

The lease arrangement with the Springerville Partnership is not reflected in our lease right right-of-use asset or liability balances as the associated revenues and expenses are eliminated in consolidation. See Note 16- Variable Interest Entities. However, as the non-controlling interest associated with this lease arrangement generates book-tax differences, a deferred tax asset and liability have been recorded.

NOTE 15 – 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.

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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

In December 2020, we established an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary. The trust consists of investments in equity and debt securities and are measured at fair value on a recurring basis. Changes in the fair value of investments in equity securities are recognized in earnings and changes in fair value of investments in debt securities classified as available-for-sale are recognized in other comprehensive income until realized. The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The cost and fair values of our marketable securities are as follows (dollars in thousands):

	June 30, 2022				December 31, 2021
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	9,407	$	8,751	$	8,850	$	8,640

Marketable Securities

We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are measured at fair value on a recurring basis with changes in fair value recognized in earnings. The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The cost and fair values of our marketable securities are as follows (dollars in thousands):

	June 30, 2022				December 31, 2021
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	550	$	481	$	597	$	598

Cash Equivalents

We invest portions of our cash and cash equivalents in commercial paper, money market funds, and other highly liquid investments. The fair value of these investments approximates our cost basis in the investments. In aggregate, the fair value was $67.7 million as of June 30, 2022 and $95.3 million as of December 31, 2021.

Debt

The fair values of long-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,

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liabilities (adjusted) and market corroborated inputs). The principal amounts and fair values of our debt are as follows (dollars in thousands):

	June 30, 2022				December 31, 2021
	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
Total long-term debt	$	3,117,011	$	3,017,268	$	3,214,427	$	3,759,991

NOTE 16 – 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, 2022		December 31, 2021
Net electric plant	$	731,066	$	740,135
Noncontrolling interest	122,896		119,100
Long-term debt	255,354		300,220
Accrued interest	7,400		8,721

Our consolidated statements of operations include the following Springerville Partnership expenses for the three and six months ended June 30, 2022 and 2021 (dollars in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2022		2021		2022		2021
Depreciation, amortization and depletion	$	4,535	$	4,535	$	9,069	$	9,069
Interest	3,958		4,956		8,662		10,141

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.

NOTE 17 – 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.

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FERC Tariff and Declaratory Order: Because of increased pressure by states to regulate our rates and charges with impact in other states setting up untenable conflict, we sought consistent federal jurisdiction by FERC. This was accomplished with the addition of non-cooperative members in 2019, specifically MIECO, Inc. as a Non-Utility Member on September 3, 2019. On the same date, we became FERC jurisdictional for our Utility Member rates, transmission service, and our market based rates. We filed our tariff for wholesale electric service and transmission at FERC in December 2019. In addition, on December 23, 2019, we filed our Petition for Declaratory Order ("Jurisdictional PDO") with FERC, EL20-16-000, asking FERC to confirm our jurisdiction under the Federal Power Act ("FPA") and that FERC’s jurisdiction preempts the jurisdiction of the Colorado Public Utilities Commission ("COPUC") to address any rate related issues, including the complaints filed by United Power, Inc. ("United Power") and La Plata Electric Association ("LPEA") with the COPUC.

On March 20, 2020, FERC issued orders regarding our Jurisdictional PDO and our tariff filings. FERC’s orders generally accepted our tariff filings and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactive to September 3, 2019. However, FERC specifically provided that no refunds are due on our Utility Member rates and our transmission service rates prior to March 26, 2020. FERC also did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered FPA section 206 proceedings to determine the justness and reasonableness of our rates and wholesale electric service contracts. On August 2, 2021, FERC approved our settlement agreement related to our Utility Member stated rate, as further discussed below. On March 7, 2022, FERC approved our settlement agreement related to our transmission service rates.

On August 28, 2020, FERC issued an order (“August 28 Order”) on rehearing related to our Jurisdictional PDO which modified its March 20, 2020 decision on our Jurisdictional PDO by finding exclusive jurisdiction over our contract termination payments related to our Utility Members and preempting the jurisdiction of the COPUC as of September 3, 2019. On December 16, 2020, United Power filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit Court of Appeals") related to FERC’s August 28 Order, 20-1256. On March 30, 2022, oral arguments occurred before the D.C. Circuit Court of Appeals regarding the Jurisdictional PDO.

Petitions for review related to our tariff filings, including our Utility Member rates, have been filed with the D.C. Circuit Court of Appeals by other parties. On June 22, 2022, an order was issued by the court to hold all the cases before the D.C. Circuit Court of Appeals in abeyance other than related to the Jurisdictional PDO, directing the parties to file motions to govern future proceedings by September 20, 2022.

On August 2, 2021, FERC approved our settlement agreement related to our Utility Member stated rate, including our wholesale electric service contracts and certain of our Board policies filed with FERC. With the exception of four reserved issues contingent on United Power being a settling party, the settlement resolved all issues set for hearing and settlement procedures related to our Utility Member rates. The settlement provides for us to implement a two-stage, graduated reduction in the charges making up our Class A rate schedule of two percent starting from March 1, 2021 until the first anniversary and four percent reduction (additional two percent reduction from then current rates) thereafter until the date a new Class A wholesale rate schedule is approved by FERC and goes into effect. The settlement rates will remain in effect at least through May 31, 2023 and during such time period, we and the settlement parties have agreed, with limited exceptions, to a moratorium on any filings related to our Class A rate schedule, including any rate increases to our Class A rate schedule. We have also agreed to file a new Class A rate schedule after May 31, 2023 and prior to September 1, 2023. During the moratorium, we have established a rate design committee to oversee the development of the new rate. Three of the reserved issues are related to the transmission component of our rates and the fourth relates to our community solar program. Additionally, with the exception of one reserved issue regarding transmission demand charges applicable to certain electric storage resources, each of the reserved issues will have prospective effect only, with the intent that any FERC rulings would be implemented in future rate filings.

A hearing on the four reserved issued occurred in March 2022 before an administrative law judge at FERC and an initial decision was issued by an administrative law judge on May 26, 2022. On the three reserved issues that will have a prospective effect only, the initial decision provides that we must also unbundle in our bills to our Utility Members our transmission costs, including ancillary services and other costs, and, in our future rate filings, we must directly assign to our Utility Members the costs of radial facilities that do not meet FERC's standards for being included in our rolled-in transmission demand rate. In addition, the initial decision provided that our Board policy for our community solar program was unduly discriminatory because it advantaged small Utility Members to the disadvantage of larger Utility Members. With regard to the reserved issue regarding transmission demand charges applicable to certain electric storage resources, the initial decision agreed with our Board policy of billing Utility Members for the transmission demand costs that includes all of a Utility Member's transmission demand, including such Utility Member's electric storage resource. On June 26, 2022, we, United Power, and certain other Utility Members filed exceptions to the initial decision. Because exceptions were taken to the initial decision, the initial decision and exceptions are now before the commissioners of FERC for a decision on the four reserved issues.

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It is not possible to predict the outcome of the four reserved issues related to our member rates docket. In addition, we cannot predict the outcome of any petitions for review filed with the D.C. Circuit Court of Appeals.

LPEA and United Power COPUC Complaints: Pursuant to our Bylaws, a Utility Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no Utility Member shall be permitted to withdraw until it has met all its contractual obligations to us, including all obligations under its wholesale electric service contract with us. On November 5, 2019, LPEA filed a formal complaint with the COPUC alleging that we hindered LPEA’s ability to seek withdrawal from us. On November 6, 2019, United Power filed a formal complaint with the COPUC, alleging that we hindered United Power’s ability to explore its power supply options by either withdrawing from us or continuing as a Utility Member under a partial requirements contract. On November 20, 2019, the COPUC consolidated the two proceedings into one, 19F-0621E.

A hearing was held on May 18-20, 2020. On July 10, 2020, the administrative law judge issued a recommended decision, but the COPUC on its own motion stayed the recommended decision. On September 18, 2020, LPEA and United Power filed a Joint Motion to Lodge FERC’s August 28 Order, and asserted additional corporate law arguments related to the legality of our addition of Non-Utility Members. On October 22, 2020, the COPUC determined that COPUC’s jurisdiction over United Power and LPEA’s complaints was preempted by FERC, the COPUC does not have jurisdiction over corporate law matters, and dismissed both complaints without prejudice. On January 27, 2021, United Power filed a Writ for Certiorari or Judicial Review, an appeal, in the Denver County District Court, 2021CV30325, of the COPUC's decision to dismiss United Power's complaint. On February 17, 2021, the Denver County District Court granted our unopposed motion to intervene as a defendant in United Power’s appeal of the COPUC’s dismissal. United Power, the COPUC, and us have all filed respective briefs with the court. The court heard oral arguments on September 17, 2021. It is not possible to predict the outcome of this matter.

United Power's Adams District Court Complaint: On May 4, 2020, United Power filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court, 2020CV30649, against us and our three Non-Utility Members. On July 2, 2021, the court granted United Power's motion to amend its May 2020 complaint, including to add LPEA as an additional plaintiff, to amend its claims as to our three Non-Utility Members, and to add a claim that our addition of the Non-Utility Members violated Colorado law. On July 30, 2021, we filed a partial motion to dismiss a majority of United Power's and LPEA's claims. On July 30, 2021, the three Non-Utility Members filed a joint motion to dismiss all claims by United Power and LPEA against the Non-Utility Members.

On March 23, 2022, the court issued an order regarding our and the Non-Utility Members’ motions to dismiss. The court dismissed some of the claims against us and the Non-Utility Members, including the civil conspiracy claim. After the dismissal, the remaining claims include seeking declaratory orders that the addition of the Non-Utility Members violated Colorado law, the April 2019 Bylaws amendment that allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void, and the April 2020 Board approvals related to the methodology to calculate a contract termination payment and buy-down payment formula do not apply to United Power and are void, and that we have breached the wholesale electric service contract with United Power.

On April 6, 2022, we and each Non-Utility Member filed their respective answers to the first amended complaint denying that United Power and LPEA are entitled to any relief and requesting the court enter judgment of dismissal. We also asserted counterclaims against United Power and LPEA, and relief from United Power’s and LPEA’s breach of our Bylaws and declaratory judgement that the April 2019 Bylaws amendment and the April 2020 Board approvals related to the methodology to calculate a contract termination payment and buy-down payment formula are valid. On April 27, 2022, United Power and LPEA filed a reply to our counterclaims asserting that we are not entitled to any relief on our counterclaims. A jury trial is scheduled for June 2023. In the initial disclosures from United Power, United Power asserts that its damages in 2020 and 2021 exceed $87 million and United Power anticipates damages of $41 million in 2022 and $43 million each year thereafter that it remains a Utility Member of us.

On June 7, 2022, LPEA filed a stipulation by all parties to the case that all claims brought by LPEA against us and our three Non-Utility Members, along with counterclaims brought by us against LPEA, are to be dismissed. In addition, the stipulation provided for LPEA to be removed from the case. On June 8, 2022, the court issued an order dismissing LPEA from the case. It is not possible to predict the outcome of this matter or whether we will incur any liability in connection with this matter.

TAPP Complaint: On September 24, 2021, TransAmerican Power Products, Inc. (“TAPP”) filed a complaint in Adams County District Court, 2021CV31089, against us alleging breach of contract and breach of implied covenant of good faith and fair dealing related to an invoice for TAPP’s supply of materials for a transmission project. TAPP seeks damages of approximately $3 million. On November 9, 2021, we filed an answer and counterclaims against TAPP disputing any amount is owed to TAPP

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and seeking damages for TAPP's breach of contract. A jury trial is scheduled for April 2023. It is not possible to predict the outcome of this matter or whether we will incur any liability in connection with this matter.

Basin Complaint: On December 17, 2021, Basin filed a complaint with the United States District Court District of North Dakota Eastern Division, 3:21-cv-00220-PDW-ARS, against us alleging that the filing of our modified contract termination payment tariff filed with FERC on September 1, 2021 constitutes a breach of our wholesale power contract with Basin for the Eastern Interconnection. On February 28, 2022, Basin filed a first amended compliant adding a new claim for anticipatory breach of contract. Basin seeks, among other things, for the court to require us to amend our modified contract termination payment tariff to exclude our Eastern Interconnection Utility Members. On March 29, 2022, we filed a motion to dismiss Basin’s first amended complaint. It is not possible to predict the outcome of this matter or whether we will incur any liability 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, 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 $383,760 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. 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.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are a taxable wholesale electric power generation and transmission cooperative operating on a not-for-profit basis. We were formed by our Utility Members for the purpose of providing wholesale power and transmission services to our Utility Members (which are distribution electric cooperatives and public power districts) for their resale of the power to their retail consumers. Our Utility Members serve large portions of Colorado, Nebraska, New Mexico and Wyoming. We also sell a portion of our generated electric power to other utilities in our regions pursuant to long-term contracts and short-term sale arrangements. Our Utility Members provide retail electric service to suburban and rural residences, farms and ranches, cities, towns and communities, as well as large and small businesses and industries.

We are owned entirely by our forty-five Members. We have three classes of membership: Class A - utility full requirements members, Class B - utility partial requirements members, and non-utility members. For our forty-two Class A members, we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members, and therefore all our Utility Members are currently Class A members. We have three Non-Utility Members. Thirty-eight of our Utility Members are not-for-profit, electric distribution cooperative associations. Four Utility Members are public power districts, which are political subdivisions of the State of Nebraska. We became regulated as a public utility under Part II of the FPA on September 3, 2019 when we admitted a Non-Utility Member, MIECO, Inc. (a non-governmental/non-electric cooperative entity), as a new Member/owner.

We supply and transmit our Utility Members’ electric power requirements through a portfolio of resources, including generation and transmission facilities, long term purchase contracts and short term energy purchases. We own, lease, have undivided percentage interests in, or long-term purchase contracts with respect to various generating facilities. Our diverse generation portfolio provides us with maximum available power of 4,440 MWs, of which approximately 1,366 MWs comes from renewables. We estimate that in 2021 over a third of the energy our Utility Members used came from clean sources.

We sold 8.6 million MWhs for the six months ended June 30, 2022, of which 90.0 percent was to Utility Members. Total revenue from electric sales was $626.0 million for the six months ended June 30, 2022 of which 90.9 percent was from Utility Member sales. Our results for the six months ended June 30, 2022 were primarily impacted by higher temperatures and drought conditions, which resulted in increased energy demand, and rate stabilization measures.

•Utility Member electric sales increased $21.6 million, or 3.9 percent, primarily due to higher sales volume as loads return to pre-pandemic levels and drought conditions in the West created greater demand for irrigation and higher temperatures resulted in increased cooling needs.

•Non-member electric sales increased $23.6 million, or 70.5 percent, primarily due to higher long-term and short-term market sales during the six month period ended June 30, 2022.

•Purchased power expense increased $19.5 million, or 11.2 percent, primarily due to coal transportation constraints at a certain generating facility that resulted in reduced generation from that facility and outages at certain generating facilities both of which resulted in higher short-term purchases of power during 2022.

•Fuel expense increased $24.3 million, or 22.8 percent, primarily due to higher natural gas prices resulting from increased demand and constraints on supply resulting from market conditions, along with higher transportation costs for coal.

•Depreciation, amortization and depletion expense decreased $12.5 million, or 12.6 percent, primarily due to revisions to asset retirement obligations related to the South Taylor pit at the Colowyo Mine during the prior year.

•Other operating expenses increased $35.7 million primarily due to the recording of an additional environmental obligation of $44.9 million related to revised cost estimates at New Horizon Mine.

Our Bylaws and Wholesale Electric Service Contracts

Our Bylaws require each Utility Member, unless otherwise specified in a written agreement or the terms of the Bylaws, to purchase from us electric power and energy as provided in the Utility Member's contract with us. This contract is the wholesale electric service contract with each Utility Member, which is an all-requirements contract. Each wholesale electric service contract obligates us to sell and deliver to the Utility Member, and obligates the Utility Member to purchase and receive, at least 95 percent of its electric power requirements from us. Our wholesale electric service contracts with our 42 Utility Members extend through 2050. Each Utility Member may elect to provide up to 5 percent of its electric power requirements from distributed or renewable generation owned or controlled by the Utility Member. As of June 30, 2022, 21 Utility Members have enrolled in this program with capacity totaling approximately 145 MWs of which 129 MWs are in operation.

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Pursuant to our wholesale electric service contracts with our Utility Members, we convened a contract committee in 2019 and 2020, consisting of a representative from each Utility Member, to review the wholesale electric service contracts and to discuss alternative contracts for our Utility Members, including partial requirements contracts. Upon recommendations from the contract committee, our Board approved a community solar program, a partial requirements structure, including a buy-down payment methodology, and a methodology to calculate a contract termination payment. For further information see “Item 1 – BUSINESS – MEMBERS” in our annual report on Form 10-K for the year ended December 31, 2021.

Under the new partial requirements membership construct, Utility Members can request to self-supply up to approximately 50 percent of their load requirements, subject to availability in the open season, in addition to the current 5 percent self-supply provision under the wholesale electric service contract and the community solar program. During our initial "open season" partial requirements nomination period that was completed in May 2021, three Utility Members were allocated an aggregate of 203 MWs of self-supply out of an available pool of 300 MWs. In January 2022, our Board approved an extension of the initial open season to offer the remaining 97 MWs of the 300 MWs of self-supply to the Utility Members who did not participate in 2021. During our extension of the initial "open season" partial requirements nomination period that was completed in May 2022, three additional Utility Members were allocated an aggregate of 97 MWs of self-supply. A total of six Utility Members have been allocated an aggregate of 300 MWs of self-supply. No Utility Member has executed a partial requirements contract to become a Class B member.

The Utility Members that choose the partial requirements option will be obligated to make a buy-down payment to us. Our Board-approved buy-down payment methodology for a Class A member to become a Class B member was accepted by FERC in 2020, subject to refund. FERC referred it to FERC’s hearing and settlement judge procedures. On April 28, 2022, we filed a proposed settlement agreement for approval with FERC related to our buy-down payment methodology. The proposed settlement agreement resolves all issue set for hearing and settlement procedures related to our buy-down payment methodology. Virtually all of the parties to the proceeding either support or do not oppose the resolution of the proceeding related to the buy-down payment methodology. Only United Power filed comments opposing the proposed settlement agreement. The three Utility Members allocated self-supply during the initial "open season" are parties to the settlement. The settlement agreement resolves the level of the buy-down payment that a partial requirements Utility Member would pay us, and certain of the commercial terms and operational considerations applicable to the Utility Members that intend to become Class B partial requirements members. Class B members will continue to pay our Class A rate for load served by us and continue to purchase full-requirements transmission service from us. On July 12, 2022, the FERC settlement judge filed a report of contested settlement and stated the settlement is now before the commissioners at FERC for consideration.

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. In September 2021, we filed with FERC a modified contract termination payment methodology tariff. The modified contract termination payment methodology is designed to protect the financial interests of our remaining Utility Members if a Utility Member elects to withdraw from membership in us. Our September 2021 tariff filing includes requirements for a two-year notice and the payment of a contract termination payment to us. In October 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 FPA section 206 proceeding to determine the justness and reasonableness of our modified methodology. A hearing on our modified contract termination payment methodology occurred in May 2022 before an administrative law judge at FERC with an initial decision expected to be issued by the administrative law judge by September 29, 2022. For further information see “Item 1 – BUSINESS – MEMBERS  - Relationship with Members” in our annual report on Form 10-K for the year ended December 31, 2021.

Three of our Utility Members, in December 2021, provided us conditional notices of their intent to withdraw from membership in us, including United Power and Northwest Rural Public Power District, with a January 1, 2024 withdrawal effective date. We filed certain answers to these conditional notices with FERC explaining that conditional notices are defective under the contract termination payment tariff and therefore a nullity. On April 21, 2022, FERC issued an order agreeing with our position that conditional notices are not permitted under our contract termination payment tariff and the conditional notices are invalid.

On April 29, 2022, both United Power and Northwest Rural Public Power District provided us notices to withdraw from membership in us, with a May 1, 2024 withdrawal effective date.

In May 2020, United Power filed a complaint for declaratory judgement and damages against us alleging, among other things, that the April 2019 Bylaws amendment that allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void and that we have breached our wholesale electric service contract with United Power. In July 2021, the court granted United Power's motion to amend its May 2020 compliant to add LPEA as an additional plaintiff and to add a claim that our addition of the Non-Utility Members violated Colorado law. In March 2022, the

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court dismissed some of the claims against us in response to our July 2021 partial motion for summary judgement. In April 2022, we filed our answer to the remaining claims. In June 2022, LPEA withdrew from the case. See Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for further information.

Responsible Energy Plan and Colorado Electric Resource Plan

Responsible Energy Plan

In July 2019, our Board established that we would pursue a transition to a cleaner energy portfolio by developing a Responsible Energy Plan. In January 2020, we released our Responsible Energy Plan. With our Responsible Energy Plan, we are implementing a clean energy transition while being responsible to our employees, Members, communities, and environment. The plan was developed with input from our Board, our Utility Members and external stakeholders. Our plan is dynamic and will change as Utility Members' needs change, new technologies become available and market conditions evolve. Over the past two years, we and our Utility Members have made great strides implementing the plan, which has allowed us to set new goals beyond those identified in January 2020. Some of the highlights of the Responsible Energy Plan include:

•Eliminating all emissions from our coal-fired generating facilities in Colorado and New Mexico by 2030.

•By 2024, 50 percent of the electricity our Utility Members use is expected to come from clean energy.

•More local renewables for Utility Members through contract flexibility.

•Promoting participation in a regional transmission organization.

•Expanding electric vehicle infrastructure and beneficial electrification.

For further information regarding our Responsible Energy Plan, see “Item 1 – BUSINESS — MEMBERS – Responsible Energy Plan” in our annual report on Form 10-K for the year ended December 31, 2021.

Colorado Electric Resource Plan

In December 2020, we filed our first Phase I Electric Resource Plan under the COPUC rules related to electric resource plans, which contained our Preferred Plan. In September 2021, we submitted to the COPUC our Revised Preferred Plan in connection with Phase I of our 2020 Electric Resource Plan that modeled the addition of 2,050 MWs of additional renewable resources and more than 200 MWs of electric storage during the resource acquisition period of 2021 to 2030. In January 2022, we reached a comprehensive settlement agreement that was filed with the COPUC for approval. On March 28, 2022, the administrative law judge for the COPUC recommended approval of the settlement agreement and the approval became effective on April 18, 2022. The settlement agreement sets emissions reduction targets for our wholesale electricity sales in Colorado as follows: at least 26 percent in 2025, 36 percent in 2026, 46 percent in 2027, and 80 percent in 2030, with respect to the verified 2005 baseline. For further information, see “Item 1 – BUSINESS — POWER SUPPLY RESOURCES – Resource Planning” in our annual report on Form 10-K for the year ended December 31, 2021.

With the settlement agreement approved, we began Phase II of our 2020 Electric Resource Plan and issued in May 2022 a request for proposal of capacity and energy bids, with a focus on projects that support emissions reductions. These projects would be scheduled to come online in 2025 and 2026. The bidding process is expected to close in September 2022, and we expect to file in early 2023 our implementation report with the COPUC.

On April 1, 2022, we made a filing with the COPUC that would, if approved, result in the retirement of our 85 MW natural-gas, combined-cycle Rifle Generating Station on or about October 6, 2022. On July 22, 2022, we filed a unanimous comprehensive settlement agreement with all intervenors in the process supporting the retirement of Rifle Generating Station on or about October 6, 2022. Our Rifle Generating Station runs infrequently. The Rifle Generating Station came online in 1987 and we purchased the facility in 2002.

Critical Accounting Policies

The preparation of our financial statements in conformity with GAAP requires that our management make estimates and assumptions that affect the amounts reported in our consolidated financial statements. We base these estimates and assumptions on information available as of the date of the financial statements and they are not necessarily indicative of the results to be expected for the year. As of June 30, 2022, there were no material changes in our critical accounting policies as disclosed in our annual report on Form 10-K for the year ended December 31, 2021.

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Factors Affecting Results

Master Indenture

As of June 30, 2022, we had approximately $2.9 billion of secured indebtedness outstanding under our Master Indenture. Substantially all of our tangible assets and certain of our intangible assets are pledged as collateral under our Master Indenture. Our Master Indenture requires us to establish rates annually that are reasonably expected to achieve a DSR of at least 1.10 on an annual basis and permits us to incur additional secured obligations as long as after giving effect to the additional secured obligation, we will continue to meet the DSR requirement on both a historical and pro forma basis. Our Master Indenture also requires us to maintain an ECR of at least 18 percent at the end of each fiscal year. Pursuant to our Master Indenture, DSR and ECR are calculated based on unconsolidated Tri-State financials and calculated in accordance with the system of accounts proscribed by FERC, not GAAP.

Margins and Patronage Capital

We operate on a cooperative basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to meet certain financial requirements and to establish reasonable reserves. Revenues in excess of current period costs in any year are designated as net margins in our consolidated statements of operations. Net margins are treated as advances of capital by our Members and are allocated to our Utility Members on the basis of revenue from electricity purchases from us and to our Non-Utility Members as provided in their respective membership agreement.

Our Board Policy for Financial Goals and Capital Credits, approved and subject to change by our Board, sets guidelines to achieve margins and retain patronage capital sufficient to maintain a sound financial position and to allow for the orderly retirement of capital credits allocated to our Utility Members. On a periodic basis, our Board will determine whether to retire any patronage capital, and in what amounts, to our Members. To date, we have retired approximately $493.2 million of patronage capital to our Members.

Pursuant to our Board Policy for Financial Goals and Capital Credits, we set rates to achieve a DSR and ECR in excess of the requirements under our Master Indenture in order to mitigate the risk of potential negative variances between budgeted margins and actual margins. This policy establishes a goal of our Board on an annual or quarterly basis to either defer revenues and incomes as a regulatory liability or recognize previously deferred revenues and incomes (as available) in an amount that will result in a DSR equal to a DSR goal for the applicable year as set forth in the policy. As allowed by our Bylaws, the deferral or recognition of previously deferred revenues and income is for the purpose of stabilizing margins and limiting rate increases from year to year. This policy, subject to change by our Board, sets a DSR goal of 1.195 for the twelve months ended December 31, 2022 and a ECR goal of 24.0 percent as of December 31, 2022.

Rates and Regulation

On September 3, 2019, we became FERC jurisdictional for our Utility Member rates, transmission service, and our market based rates. In December 2019, we filed with FERC our tariff filings, including our stated rate cost of service filing, market based rate authorization, and transmission OATT. In March 2020, FERC issued orders generally accepting our tariff filings, subject to refund for sales after March 26, 2020. FERC did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered FPA section 206 proceedings to determine the justness and reasonableness of our rates, including our Class A wholesale rate schedule (A-40) referenced below, and wholesale electric service contracts. On August 2, 2021, FERC approved our settlement agreement related to our Utility Member stated rate that provides for us to implement a two-stage, graduated reduction in the charges making up our A-40 rate of two percent starting from March 1, 2021 until the first anniversary and four percent reduction (additional two percent reduction from then current rates) on March 1, 2022 until the date a new Class A wholesale rate schedule goes into effect. See Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for further information.

Our electric sales revenues are derived from wholesale electric service sales to our Utility Members and non-member purchasers. Revenues from wholesale electric power sales to our non-member purchasers is pursuant to our market based rate authority.

Revenues from electric power sales to our Utility Members are primarily from our Class A wholesale rate schedule filed with FERC. In 2021 and 2022, our Class A rate schedule (A-40) for electric power sales to our Utility Members consist of three billing components: an energy rate and two demand rates. Utility Member rates for energy and demand are set by our Board, consistent with the provision of reliable cost-based supply of electricity over the long term to our Utility Members. Energy is the physical electricity delivered to our Utility Members. The energy rate was billed based upon a price per kWh of physical

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energy delivered and the two demand rates (a generation demand and a transmission/delivery demand) were both billed based on the Utility Member’s highest thirty-minute integrated total demand measured in each monthly billing period during our peak period from noon to 10:00 pm daily, Monday through Saturday, with the exception of six holidays.

Our Class A rate schedule (A-40) was filed at FERC as a “stated rate.” While our Board still has authority to determine our rates, those rates, including any change to the rate or rate structure, must be approved by FERC subject to outside comments. As part of the FERC approved settlement agreement, we and the settlement parties have agreed, with limited exceptions, to a moratorium on any filings related to our Class A rate schedule, including any rate increases to our Class A rate schedule, at least through May 31, 2023. A rate design committee consisting of a representative from each Utility Member is working on the development of a new rate to our Utility Members.

Our Board may from time to time, subject to FERC approval, create new regulatory assets or liabilities or modify the expected recovery period through rates of existing regulatory assets or liabilities. The amounts involved may be material. We continually evaluate options to achieve the goal to lower wholesale rates to our Utility Members.

Tax Status

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. Effective January 1, 2020, we adopted the normalization method for recognizing deferred income taxes pursuant to FERC regulation. Under the normalization method, changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit). Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues.

Results of Operations

General

Our electric sales revenues are derived from wholesale electric service sales to our Utility Members and non-member purchasers. See “Factors Affecting Results – Rates and Regulation” for a description of our energy and demand rates to our Utility Members. Long-term contract sales to non-members generally include energy and demand components. Short-term sales to non-members are sold at market prices after consideration of incremental production costs. Demand billings to non-members are typically billed per kilowatt of capacity reserved or committed to that customer.

Weather has a significant effect on the usage of electricity by impacting both the electricity used per hour and the total peak demand for electricity. Consequently, weather has a significant impact on our revenues. Relatively higher summer or lower winter temperatures tend to increase the usage of electricity for heating, air conditioning and irrigation. Mild weather generally reduces the usage of electricity because heating, air conditioning and irrigation systems are operated less frequently. The amount of precipitation during the growing season (generally May through September) also impacts irrigation use. Other factors affecting our Utility Members’ usage of electricity include:

•the amount, size and usage of machinery and electronic equipment;

•the expansion or contraction of operations among our Utility Members’ commercial and industrial customers;

•the general growth in population;

•COVID-19 and governmental orders related to COVID-19; and

•economic conditions.

Impacts of Supply Chain and Inflation

Our ability to meet our Utility Members' electric power requirements and complete our capital projects are dependent on maintaining an efficient supply chain. The procurement and delivery of materials and equipment have been impacted by the current domestic and global supply chain disruptions. We are experiencing shortages of critical items and longer lead-times on the procurement of certain materials and equipment, along with interruptions in production and shipping. Supply chain disruptions have contributed to higher prices for materials and equipment. We are also experiencing increased fuel costs for

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natural gas and costs for transportation of coal. We continue to monitor and are currently evaluating potential impacts to our operations and estimated capital expenditures and timing of projects related to inflationary pressures and supply chain disruptions.

We have several long-term solar power purchase agreements that were expected to commence commercial operation in 2023. Some developers have indicated they are experiencing difficulties due to supply chain issues and the United States Department of Commerce anti-circumvention investigation. We have agreed to allow additional flexibility for these projects, including extending the anticipated commercial operation dates to 2024.

Three months ended June 30, 2022 compared to three months ended June 30, 2021

Operating Revenues

Our operating revenues are primarily derived from electric power sales to our Utility Members and non-member purchasers. Other operating revenue consists primarily of wheeling, transmission, and coal sales. Other operating revenue also includes revenue we receive from certain of our Non-Utility Members. The following is a comparison of our operating revenues and energy sales in MWh by type of purchaser for the three months ended June 30, 2022 and 2021 (dollars in thousands):

	Three Months Ended June 30,				Period-to-period Change
	2022		2021		Amount		Percent
Operating revenues
Utility Member electric sales	$	286,568	$	274,445	$	12,123	4.4	%
Non-member electric sales	34,214		16,188		18,026		111.4	%
Rate stabilization	17,462		19,957		(2,495)		(12.5)	%
Other	13,718		15,712		(1,994)		(12.7)	%
Total operating revenues	$	351,962	$	326,302	$	25,660	7.9	%
Energy sales (in MWh):
Utility Member electric sales	3,856,662		3,661,010		195,652		5.3	%
Non-member electric sales	441,124		368,944		72,180		19.6	%
	4,297,786		4,029,954		267,832		6.6	%

•Utility Member electric sales revenue increased primarily due to higher sales volume as loads continue a return to pre-pandemic usage levels.

•Non-member electric sales increased primarily due to higher long-term and short-term market sales. Long-term sales increased 26,992 MWhs, or 20.5 percent, to 158,752 MWhs for the three months ended June 30, 2022 compared to 131,760 MWhs for the same period in 2021. Short-term market sales increased 45,188 MWhs, or 19.1 percent, to 282,372 MWhs for the three months ended June 30, 2022 compared to 237,184 MWhs for the same period in 2021.

•In accordance with our Board Policy for Financial Goals and Capital Credits, we recognized $17.5 million of previously deferred membership withdrawal income during the three months ended June 30, 2022 compared to $20.0 million of previously deferred non-member electric sales revenue during the same period in 2021. In order to meet our 2022 financial goals, we expect to recognize additional previously deferred membership withdrawal income during the remainder of 2022.

Operating Expenses

Our operating expenses are primarily comprised of the costs that we incur to supply and transmit our Utility Members’ electric power requirements through a portfolio of resources, including generation and transmission facilities, long-term purchase contracts and short-term energy purchases and the costs associated with any sales of power to non-members.

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The following is a summary of the components of our operating expenses for the three months ended June 30, 2022 and 2021 (dollars in thousands):

	Three Months Ended June 30,				Period-to-period Change
	2022		2021		Amount		Percent
Operating expenses
Purchased power	$	105,738	$	86,552	$	19,186	22.2	%
Fuel	68,247		45,870		22,377		48.8	%
Production	50,254		52,841		(2,587)		(4.9)	%
Transmission	42,053		41,948		105		0.3	%
General and administrative	18,893		11,897		6,996		58.8	%
Depreciation, amortization and depletion	45,269		46,483		(1,214)		(2.6)	%
Coal mining	3,849		966		2,883		298.4	%
Other	47,302		1,282		46,020		*
Total operating expenses	$	381,605	$	287,839	$	93,766	32.6	%
* Calculation not meaningful

•Purchased power expense increased primarily due to an increase of 233,977 MWhs purchased during the three months ended June 30, 2022 compared to the same period in 2021. Increased purchases were primarily due to coal transportation constraints at a certain generating facility that resulted in reduced generation from that facility and outages at certain generating facilities both of which resulted in higher short-term purchases of power during 2022. Additionally, the average price was 8.8 percent higher during the three months ended June 30, 2022 compared to the same period in 2021.

•Fuel expense increased primarily due to higher natural gas prices as a result of increased demand and constraints on supply as a result of market conditions along with higher transportation costs for coal.

•Other operating expenses increased primarily due to the recording of an additional environmental obligation of $44.9 million related to revised cost estimates at New Horizon Mine.

Six months ended June 30, 2022 compared to six months ended June 30, 2021

Operating Revenues

The following is a comparison of our operating revenues and energy sales in MWh by type of purchaser for the six months ended June 30, 2022 and 2021 (dollars in thousands):

	Six Months Ended June 30,				Period-to-period Change
	2022		2021		Amount		Percent
Operating revenues
Utility Member electric sales	$	568,815	$	547,243	$	21,572	3.9	%
Non-member electric sales	57,158		33,529		23,629		70.5	%
Rate stabilization	25,345		40,790		(15,445)		(37.9)	%
Other	25,846		30,712		(4,866)		(15.8)	%
Total operating revenues	677,164		652,274		$	24,890	3.8	%
Energy sales (in MWh):
Utility Member electric sales	7,714,308		7,369,142		345,166		4.7	%
Non-member electric sales	854,869		619,010		235,859		38.1	%
	8,569,177		7,988,152		581,025		7.3	%

•Utility Member electric sales revenue increased primarily due to higher sales volume as loads continue a return to pre-pandemic usage levels.

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•Non-member electric sales increased primarily due to higher long-term and short-term market sales. Long-term sales increased 130,855 MWhs, or 65.2 percent, to 331,718 MWhs for the six months ended June 30, 2022 compared to 200,863 MWhs for the same period in 2021. Short-term market sales increased 105,004  MWhs, or 25.1 percent, to 523,151 MWhs for the six months ended June 30, 2022 compared to 418,147 MWhs for the same period in 2021.

•In accordance with our Board Policy for Financial Goals and Capital Credits, we recognized $25.3 million of previously deferred membership withdrawal income during the six months ended June 30, 2022 compared to $40.8 million of previously deferred non-member electric sales revenue during the same period in 2021. In order to meet our 2022 financial goals, we expect to recognize additional previously deferred membership withdrawal income during the remainder of 2022.

Operating Expenses

The following is a summary of the components of our operating expenses for the six months ended June 30, 2022 and 2021 (dollars in thousands):

	Six Months Ended June 30,				Period-to-period Change
	2022		2021		Amount		Percent
Operating expenses
Purchased power	193,038		173,569		$	19,469	11.2	%
Fuel	130,721		106,417		24,304		22.8	%
Production	88,050		93,742		(5,692)		(6.1)	%
Transmission	89,235		86,619		2,616		3.0	%
General and administrative	39,166		26,484		12,682		47.9	%
Depreciation, amortization and depletion	86,743		99,238		(12,495)		(12.6)	%
Coal mining	5,375		2,507		2,868		114.4	%
Other	48,339		3,833		44,506		*
Total operating expenses	$	680,667	$	592,409	$	88,258	14.9	%
* Calculation not meaningful

•Purchased power expense increased primarily due to an increase of 307,702 MWhs purchased during the six months ended June 30, 2022 compared to the same period in 2021. Increased purchases were primarily due to coal transportation constraints at a certain generating facility that resulted in reduced generation from that facility and outages at certain generating facilities both of which resulted in higher short-term purchases of power during 2022. Additionally, the average price was 2.9 percent higher during the six months ended June 30, 2022 compared to the same period in 2021.

•Fuel expense increased primarily due to higher natural gas prices resulting from increased demand and constraints on supply resulting from market conditions, along with higher transportation costs for coal.

•General and administrative expense increased primarily due to lower recoveries of general and administrative costs from joint project activities, an increase in outside professional services and an overall increase in expenses related to general and administration labor and benefits.

•Depreciation, amortization and depletion expense primarily decreased due to revisions to asset retirement obligation related to the South Taylor pit at the Colowyo Mine during the prior year.

•Other operating expenses increased primarily due to the recording of an additional environmental obligation of $44.9 million related to revised cost estimates at New Horizon Mine.

Financial condition as of June 30, 2022 compared to December 31, 2021

The principal changes in our financial condition from December 31, 2021 to June 30, 2022 were due to increases and decreases in the following:

Assets

•Regulatory assets increased $8.7 million, or 1.3 percent, to $674.4 million as of June 30, 2022 compared to $665.7 million as of December 31, 2021. The increase was primarily due to the recognition of additional asset retirement obligations of $25.5 million at the Escalante and Nucla Generating Stations during the second quarter of

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2022 and the recognition of $3.7 million during the first quarter of 2022 related to the deferred impairment loss at Rifle Generating Station. These increases were partially offset by amortization of $20.5 million to depreciation, amortization and depletion expense and recovered from our Utility Members through rates.

Liabilities

•Long-term debt decreased $205.8 million, or 6.6 percent, to $2.896 billion as of June 30, 2022 compared to $3.102 billion as of December 31, 2021 and current maturities of long-term debt increased $108.6 million, or 116.7 percent, to $201.6 million as of June 30, 2022 compared to $93.0 million as of December 31, 2021. The net decrease of $97.2 million was primarily due to debt payments of $97.4 million (principally $44.4 million for the Springerville certificates and $16.3 million of CoBank and CFC debt). During the six month period ending June 30, 2022, we repurchased and cancelled $36.7 million of our First Mortgage Bonds, Series 2014E-1 and our First Mortgage Bonds, Series 2016A. Additionally, $100.0 million of our First Mortgage Bonds, Series 2014E-1 was reclassified to current maturities due to a public tender offer of such bonds which was completed in July 2022. See “Liquidity and Capital Resources” for more information on the tender offer.

•Short-term borrowings increased $129.7 million, or 259.4 percent, to $179.7 million as of June 30, 2022 compared to $50.0 million as of December 31, 2021. The increase was due to commercial paper activity during 2022 primarily related to early repurchase and cancellation of certain of our bonds.

•Regulatory liabilities decreased $25.6 million, or 17.5 percent, to $120.4 million as of June 30, 2022 compared to $146.0 million as of December 31, 2021. The decrease was primarily due to the recognition of $25.3 million of previously deferred membership withdrawal income. In order to better align with our financial goals, we recognize deferred revenue and income on a quarterly basis when it is reasonably estimable that recognition is required to meet our financial goals during 2022.

•Asset retirement and environmental reclamation obligations increased $85.1 million, or 102.2 percent, to $168.4 million as of June 30, 2022 compared to $83.3 million as of December 31, 2021. The increase was due to the recording of an additional environmental obligation of $44.9 million related to revised cost estimates at New Horizon Mine and additional asset retirement obligations of $40.6 million related to an update in cost estimates for obligations related to our ponds, ash land fill and post-closure reclamation and monitoring at various generating facilities.

Liquidity and Capital Resources

We finance our operations, working capital needs and capital expenditures from operating revenues and issuance of short-term and long-term borrowings. As of June 30, 2022, we had $96.8 million in cash and cash equivalents. Our committed credit arrangement as of June 30, 2022 is as follows (dollars in thousands):

	Authorized Amount			Available June 30, 2022
2022 Revolving Credit Agreement	$	520,000	(1)	$	340,000

(1)The amount of this facility that can be used to support commercial paper is limited to $500 million.

On April 25, 2022, our prior revolving credit agreement, known as the the 2018 Revolving Credit Agreement, was amended and restated by the 2022 Revolving Credit Agreement in the amount of $520 million. The 2022 Revolving Credit Agreement 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, of which $125 million of the swingline sublimit, $75 million of the letter of credit sublimit, and $320 million of the commercial paper back-up sublimit remained available as of June 30, 2022.

The 2022 Revolving Credit Agreement is secured under our Master Indenture and has a term extending through April 25, 2027, unless extended as provided therein. The 2022 Revolving Credit Agreement uses Term SOFR loans instead of LIBOR rate loans. Funds advanced under the 2022 Revolving Credit Agreement bear interest either at adjusted Term SOFR rates or alternative base rates, at our option. The adjusted Term SOFR rate is the Term SOFR rate for the term of the advance plus a margin (1.125 percent as of June 30, 2022) based on our credit ratings. Base rate loans bear interest at the alternate base rate plus a margin (0.125 percent as of June 30, 2022) based on our credit ratings. The alternate base rate is the highest of (a) the federal funds rate plus ½ of 1.00 percent, (b) the prime rate, and (c) the adjusted Term SOFR rate plus 1.00 percent and plus a margin (1.125 percent as of June 30, 2022) based on our credit ratings.

The 2022 Revolving Credit Agreement contains customary representations, warranties, covenants, events of default and acceleration, including financial DSR and ECR requirements in line with the covenants contained in our Master Indenture and

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similar to the 2018 Revolving Credit Agreement. A violation of these covenants would result in the inability to borrow under the facility.

Under our commercial paper program, our Board authorized us to issue commercial paper in amounts that do not exceed the commercial paper back-up sublimit under our 2022 Revolving Credit Agreement, which was $500 million as of June 30, 2022, thereby providing 100 percent dedicated support for any commercial paper outstanding. As of June 30, 2022, we had $180 million of commercial paper outstanding (prior to netting discounts) and $320 million available on the commercial paper back-up sublimit.

On July 13, 2022, we announced cash tender offers to purchase for cash up to $100 million aggregate principal amount of our First Mortgage Bonds, Series 2014E-1 (due 2024), our First Mortgage Bonds, Series 2014E-2 (due 2044), and our First Mortgage Bonds, Series 2016A (due 2046). The early tender offer deadline was July 26, 2022 and $100 million principal amount of our Series 2014E-1 (due 2024) bonds were tendered and accepted. We paid a total of $100.2 million in aggregate for purchase of the bonds, including early tender payments. We paid for the purchase of the bonds with available cash and commercial paper.

In addition to the July 2022 tender offers, we have previously purchased our outstanding debt through cash purchases in open market purchases. In the future, we may from time to time purchase additional outstanding debt through cash purchases and/or exchanges for other securities, in open market purchases, privately negotiated transactions, additional tender offers, or otherwise and may continue to seek to retire or purchase our outstanding debt in the future. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. We are mindful of our debt and its maturities and we continually evaluate options to ensure that our balance sheet and capital structure is aligned with our business and the long-term health of our company.

We believe we have sufficient liquidity to fund operations and capital financing needs from projected cash on hand, our commercial paper program, and the 2022 Revolving Credit Agreement.

Cash Flow

Cash is provided by operating activities and issuance of debt. Capital expenditures and debt service payments comprise a significant use of cash.

Six months ended June 30, 2022 compared to six months ended June 30, 2021

Operating activities. Net cash provided by operating activities was $27.7 million for the six months ended June 30, 2022 compared to $52.7 million for the same period in 2021, a decrease in net cash provided by operating activities of $25.0 million. The decrease in net cash provided by operating activities was impacted by an increase in purchased power expense, the timing of cash collected from Member accounts receivable and lower cash deposits related to interconnection customers.

Investing activities. Net cash used in investing activities was $59.7 million for the six months ended June 30, 2022 compared to $57.3 million for the same period in 2021, an increase in net cash used in investing activities of $2.4 million. The increase in net cash used in investing activities was primarily due to net additional investments in utility plant. This increase was partially offset by a decrease in net cash used in investing activities related to timing of payments we made to operating agents of jointly owned facilities to fund our share of costs to be incurred under each project.

Financing activities. Net cash provided by financing activities was $28.1 million for the six months ended June 30, 2022 compared to net cash used in financing activities of $8.3 million for the same period in 2021, an increase in net cash provided by financing activities of $36.4 million. The increase in net cash provided by financing activities was primarily due to an increase in short-term borrowings of $49.7 million partially offset by higher principal payments of long-term debt of $23.5 million.

Capital Expenditures

We forecast our capital expenditures annually as part of our long-term planning. We regularly review these projections to update our calculations to reflect changes in our future plans, facility closures, facility costs, market factors and other items affecting our forecasts. After taking into account our Responsible Energy Plan, in the years 2022 through 2026, we forecast that we may invest approximately $877 million in new facilities and upgrades to our existing facilities.

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Our actual capital expenditures depend on a variety of factors, including assumptions related to our Responsible Energy Plan and our Revised Preferred Plan in conjunction with Phase I of our 2020 Electric Resource Plan approved by the COPUC, Utility Member load growth, availability of necessary permits, regulatory changes, environmental requirements, construction delays and costs, supply chain issues, inflation, and ability to access capital in credit markets. Thus, actual capital expenditures may vary significantly from our projections.

Capital projects include several transmission projects to improve reliability and load-serving capability throughout our service area.

Changing Environmental Regulations

We are subject to extensive federal, state and local environmental requirements. These environmental laws, rules and regulations are complex and change frequently. The following are recent developments relating to environmental regulations and litigation that may impact us.

Collom Air Permit

In November 2019, the Collom air permit revision for the Collom pit at the Colowyo Mine was issued by CDPHE. In December 2019, the Center for Biological Diversity and Sierra Club filed a new case challenging the CDPHE’s issuance of the Collom air permit revision. In October 2020, the judge issued an order affirming the CDPHE’s issuance of the minor source construction air permit to Collom. The Center for Biological Diversity and Sierra Club appealed the decision to the Colorado Court of Appeals. In March 2022, the Colorado Court of Appeals affirmed the District Court's decision upholding the air permit for Collom. In May 2022, the Center for Biological Diversity and Sierra Club filed a Petition for Writ of Certiorari with the Colorado Supreme Court. We and the State of Colorado filed responses in opposition to the petition.

Greenhouse Gas Regulation

In June 2022, the United States Supreme Court issued its opinion in West Virginia v. EPA, finding that the EPA exceeded its Clean Air Act section 111(d) authority when it promulgated the Clean Power Plan. The Supreme Court vacated and remanded the case back to the D.C. Circuit Court of Appeals for further proceedings consistent with the opinion. The Biden administration is expected to begin another, new rulemaking and has stated its intent to issue a new proposed rule in 2022.

For further discussion regarding potential effects on our business from environmental regulations, see “Item 1 –  – BUSINESS — ENVIRONMENTAL REGULATION” and “Item 1 – RISK FACTORS" in our annual report on Form 10-K for the year ended December 31, 2021.

Rating Triggers

Our current senior secured ratings are “A3 (stable outlook)” by Moody’s, “BBB+ (negative outlook)” by S&P, and “A- (stable outlook)” by Fitch. Our current short-term ratings are “A-2” by S&P and “F1” by Fitch.

Our 2022 Revolving Credit Agreement includes a pricing grid related to the Term SOFR spread, commitment fee and letter of credit fees due under the facility. A downgrade of our senior secured ratings could result in an increase in each of these pricing components. We do not believe that any such increase would be significant or have a material adverse effect on our financial condition or our future results of operations.

We currently have contracts that require adequate assurance of performance. These include natural gas supply contracts and financial risk management contracts. Some of the contracts are directly tied to us maintaining investment grade credit ratings by S&P and Moody’s. We may enter into additional contracts which may contain similar adequate assurance requirements. If we are required to provide such adequate assurances, we do not believe the amounts will be significant or that they will have a material adverse effect on our financial condition or our future results of operations.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

There have been no material changes to market risks during the most recent fiscal quarter from those reported in our annual report on Form 10-K for the year ended December 31, 2021.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

Changes in Internal Controls

There have been no changes in our internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Information required by this Item is contained in Note 17 to the Unaudited Consolidated Financial Statements in Item 1.

Item 4. Mine Safety Disclosures

Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.104) is included in Exhibit 95 to this quarterly report on Form 10-Q.

Item 6. Exhibits

Exhibit Number	Description of Exhibit
31.1	Rule 13a-14(a)/15d-14(a) Certification, by Duane Highley (Principal Executive Officer).
31.2	Rule 13a-14(a)/15d-14(a) Certification, by Patrick L. Bridges (Principal Financial Officer).
32.1	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Duane Highley (Principal Executive Officer).
32.2	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Patrick L. Bridges (Principal Financial Officer).
95	Mine Safety Disclosure Exhibit.
101	XBRL Interactive Data File.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	Tri-State Generation and Transmission Association, Inc.
Date: August 12, 2022	By:	/s/ Duane Highley
		Duane Highley
		Chief Executive Officer
Date: August 12, 2022		/s/ Patrick L. Bridges
		Patrick L. Bridges
		Senior Vice President/Chief Financial Officer (Principal Financial Officer)

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EX-31.1

EXHIBIT 31.1

Rule 13a-14(a)/15d-14(a) Certification, by Duane Highley

(Principal Executive Officer)

I, Duane Highley, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Tri-State Generation and Transmission Association, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 12, 2022

/s/ Duane Highley

Duane Highley

Chief Executive Officer

1

EX-31.2

EXHIBIT 31.2

Rule 13a-14(a)/15d-14(a) Certification, by Patrick L. Bridges

(Principal Financial Officer)

I, Patrick L. Bridges, certify that:

1.I have reviewed this quarterly report on Form 10-Q of Tri-State Generation and Transmission Association, Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal controls over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)Designed such internal controls over financial reporting, or caused such internal controls over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 12, 2022

/s/ Patrick L. Bridges

Patrick L. Bridges

Senior Vice President/Chief Financial Officer

1

EX-32.1

EXHIBIT 32.1

Certification Pursuant to 18 U.S.C. 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report on Form 10-Q of Tri-State Generation and Transmission Association, Inc. (the “Company”) for the quarterly period ended June 30, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Duane Highley, the Chief Executive Officer of the Company certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

Date: August 12, 2022

/s/ Duane Highley

Duane Highley

Chief Executive Officer

1

EX-32.2

EXHIBIT 32.2

Certification Pursuant to 18 U.S.C. 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report on Form 10-Q of Tri-State Generation and Transmission Association, Inc. (the “Company”) for the quarterly period ended June 30, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Patrick L. Bridges, the Senior Vice President/Chief Financial Officer of the Company certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated.

Date: August 12, 2022

/s/ Patrick L. Bridges

Patrick L. Bridges

Senior Vice President/Chief Financial Officer

1

EX-95

Exhibit 95

Mine Safety and Health Administration Safety Data

Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) requires issuers that are operators, or that have subsidiaries that is an operator, of a coal or other mine to include in periodic reports filed with the Securities and Exchange Commission certain information relating to citations and orders for violations of standards under the Federal Mine Safety and Health Act of 1977. The following tables disclose information required under the Dodd-Frank Act during the second quarter of 2022. The mine data retrieval system maintained by MSHA may show information that is different than what is provided herein. Any such difference may be attributed to the need to update that information on MSHA’s system and/or other factors.

			Section			Total Dollar
			104(d)			Value of	Total Number
Mine Name /		Section	Citations	Section	Section	MSHA	of Mining
MSHA	Section 104	104(b)	and	110(b)(2)	107(a)	Assessments	Related
Identification	S&S Citations	Orders	Orders	Violations	Orders	Proposed	Fatalities
Number	(#)	(#)	(#)	(#)	(#)	(in Thousands, $)	(#)
Colowyo Mine / 0502962	0	0	0	0	0	0	0

		Received
		Notice of
	Received	Potential to
	Notice of	Have Pattern	Legal Actions	Legal Actions	Legal Actions
	Pattern of Violations	of Violations	Pending	Initiated	Resolved
Mine Name /	Under	Under	as of the	During the	During the
MSHA	Section	Section	Three Months Ended	Three Months Ended	Three Months Ended
Identification	104(e)	104(e)	June 30, 2022	June 30, 2022	June 30, 2022
Number	(yes/no)	(yes/no)	(#)	(#)	(#)
Colowyo Mine / 0502962	No	No	0	0	0

1

The number of legal actions pending before the Federal Mine Safety and Health Review Commission as of June 30, 2022 that fall into each of the following categories is as follows:

						Appeals of
				Complaints for		judges'
	Contests of	Contests of		discharge,		decisions or
	Citations/	Proposed	Complaints for	discrimination,	Applications for	orders to
	Orders	Penalties	compensation	or interference	temporary relief	FMSHRC
Mine Name /	referenced in	referenced in	referenced in	referenced in	referenced in	referenced in
MSHA	Subpart B,	Subpart C,	Subpart D,	Subpart E,	Subpart F	Subpart H
Identification	29CFR	29CFR	29CFR	29CFR	29CFR	29CFR
Number	Part 2700	Part 2700	Part 2700	Part 2700	Part 2700	Part 2700
Colowyo Mine / 0502962	0	0	0	0	0	0

2

XML

Cover - shares	6 Months Ended
	Jun. 30, 2022	Aug. 12, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2022
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	2022
Document Fiscal Period Focus	Q2
Entity Central Index Key	0001637880
Amendment Flag	false

XML

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Electric plant
In service	$ 5,669,932	$ 5,606,732
Construction work in progress	80,774	107,636
Total electric plant	5,750,706	5,714,368
Less allowances for depreciation and amortization	(2,397,715)	(2,367,197)
Net electric plant	3,352,991	3,347,171
Other plant	933,479	1,093,922
Less allowances for depreciation, amortization and depletion	(673,691)	(823,087)
Net other plant	259,788	270,835
Total property, plant and equipment	3,612,779	3,618,006
Other assets and investments
Investments in other associations	164,259	163,097
Investments in and advances to coal mines	2,171	2,273
Restricted cash and investments	3,746	4,101
Other noncurrent assets	16,102	15,873
Total other assets and investments	186,278	185,344
Current assets
Cash and cash equivalents	96,841	100,555
Restricted cash and investments	663	480
Deposits and advances	35,672	34,042
Accounts receivable - Utility Members	111,571	95,630
Other accounts receivable	25,563	21,571
Land held for sale	411	0
Coal inventory	55,689	59,701
Materials and supplies	92,274	87,234
Total current assets	418,684	399,213
Deferred charges
Regulatory assets	674,378	665,693
Prepayment—NRECA Retirement Security Plan	13,431	16,117
Other	41,037	35,139
Total deferred charges	728,846	716,949
Total assets	4,946,587	4,919,512
Capitalization
Patronage capital equity	924,243	994,865
Accumulated other comprehensive loss	(2,196)	(1,460)
Noncontrolling interest	122,894	119,100
Total equity	1,044,941	1,112,505
Long-term debt	2,896,050	3,101,870
Total capitalization	3,940,991	4,214,375
Current liabilities
Utility Member advances	19,784	17,217
Accounts payable	126,605	105,965
Short-term borrowings	179,699	49,997
Accrued expenses	32,264	32,882
Current asset retirement obligations	4,953	7,003
Accrued interest	24,230	25,716
Accrued property taxes	19,976	33,877
Current maturities of long-term debt	201,575	93,039
Total current liabilities	609,086	365,696
Deferred credits and other liabilities
Regulatory liabilities	120,436	146,021
Deferred income tax liability	19,023	18,987
Long-term obligations at end of period	168,364	83,278
Other	75,761	78,319
Total deferred credits and other liabilities	383,584	326,605
Accumulated postretirement benefit and postemployment obligations	12,926	12,836
Total equity and liabilities	$ 4,946,587	$ 4,919,512

XML

Consolidated Statements of Operations (unaudited) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Operating revenues
Other	$ 13,718,000	$ 15,712,000	$ 25,846,000	$ 30,712,000
Operating revenues	351,962,000	326,302,000	677,164,000	652,274,000
Operating expenses
Purchased power	105,738,000	86,552,000	193,038,000	173,569,000
Fuel	68,247,000	45,870,000	130,721,000	106,417,000
Production	50,254,000	52,841,000	88,050,000	93,742,000
Transmission	42,053,000	41,948,000	89,235,000	86,619,000
General and administrative	18,893,000	11,897,000	39,166,000	26,484,000
Depreciation, amortization and depletion	45,269,000	46,483,000	86,743,000	99,238,000
Coal mining	3,849,000	966,000	5,375,000	2,507,000
Other	47,302,000	1,282,000	48,339,000	3,833,000
Operating expenses	381,605,000	287,839,000	680,667,000	592,409,000
Operating margins	(29,643,000)	38,463,000	(3,503,000)	59,865,000
Other income
Interest	928,000	907,000	1,786,000	1,784,000
Capital credits from cooperatives	1,000	2,000	4,595,000	4,275,000
Other income (expense)	(14,000)	1,032,000	871,000	1,889,000
Total other income	915,000	1,941,000	7,252,000	7,948,000
Interest expense
Interest	35,309,000	36,092,000	70,990,000	72,207,000
Interest charged during construction	(397,000)	(1,004,000)	(792,000)	(1,978,000)
Interest expense, net of amounts capitalized	34,912,000	35,088,000	70,198,000	70,229,000
Income tax expense	19,000	110,000	37,000	219,000
Net margins including noncontrolling interest	(63,659,000)	5,206,000	(66,486,000)	(2,635,000)
Net margin attributable to noncontrolling interest	(2,128,000)	(1,762,000)	(4,136,000)	(3,411,000)
Net margins attributable to the Association	(65,787,000)	3,444,000	(70,622,000)	(6,046,000)
Utility Member electric sales
Operating revenues
Operating revenues	286,568,000	274,445,000	568,815,000	547,243,000
Non-member electric sales
Operating revenues
Operating revenues	34,214,000	16,188,000	57,158,000	33,529,000
Rate stabilization
Operating revenues
Operating revenues	$ 17,462,000	$ 19,957,000	$ 25,345,000	$ 40,790,000

XML

Consolidated Statements of Comprehensive Income (Loss) (unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Net margins including noncontrolling interest	$ (63,659)	$ 5,206	$ (66,486)	$ (2,635)
Other comprehensive loss:
Unrealized loss on securities available for sale	(56)	(7)	(232)	(41)
Unrecognized prior service cost	0	0	0	(1,121)
Other comprehensive income (loss)	(308)	212	(736)	(431)
Comprehensive income (loss) including noncontrolling interest	(63,967)	5,418	(67,222)	(3,066)
Net comprehensive income attributable to noncontrolling interest	(2,128)	(1,762)	(4,136)	(3,411)
Comprehensive income (loss) attributable to the Association	(66,095)	3,656	(71,358)	(6,477)
Postretirement Medical Benefit Plans
Other comprehensive loss:
Amortization of prior service credit into other income	(535)	(20)	(1,070)	(40)
Executive Benefit Restoration Plan
Other comprehensive loss:
Amortization of prior service credit into other income	283	239	566	459
Amortization of actuarial (gain) loss into income	$ 0	$ 0	$ 0	$ 312

XML

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, 2020				$ 978,519	$ (5,714)			$ 114,851
Change in Equity
Net margins attributable to the Association	$ (6,046)			(6,046)
Unrealized loss on securities available for sale	(41)				(41)
Amortization of prior service credit into other income		$ (40)	$ 459			$ (40)	$ 459
Amortization of actuarial (gain) loss into income			312				312
Unrecognized prior service cost	(1,121)				(1,121)
Net comprehensive income attributable to noncontrolling interest	(3,411)							3,411
Equity distribution to noncontrolling interest								(2,693)
Equity at end of period at Jun. 30, 2021	1,081,897			972,473	(6,145)			115,569
Equity at beginning of period at Mar. 31, 2021				969,029	(6,357)			113,807
Change in Equity
Net margins attributable to the Association	3,444			3,444
Unrealized loss on securities available for sale	(7)				(7)
Amortization of prior service credit into other income		(20)	239			(20)	239
Amortization of actuarial (gain) loss into income			0
Unrecognized prior service cost	0
Net comprehensive income attributable to noncontrolling interest	(1,762)							1,762
Equity at end of period at Jun. 30, 2021	1,081,897			972,473	(6,145)			115,569
Equity at beginning of period at Dec. 31, 2021	1,112,505			994,865	(1,460)			119,100
Change in Equity
Net margins attributable to the Association	(70,622)			(70,622)
Unrealized loss on securities available for sale	(232)				(232)
Amortization of prior service credit into other income		(1,070)	566			(1,070)	566
Amortization of actuarial (gain) loss into income			0
Unrecognized prior service cost	0
Net comprehensive income attributable to noncontrolling interest	(4,136)							4,136
Equity distribution to noncontrolling interest								(342)
Equity at end of period at Jun. 30, 2022	1,044,941			924,243	(2,196)			122,894
Equity at beginning of period at Mar. 31, 2022				990,030	(1,888)			120,766
Change in Equity
Net margins attributable to the Association	(65,787)			(65,787)
Unrealized loss on securities available for sale	(56)				(56)
Amortization of prior service credit into other income		$ (535)	283			$ (535)	$ 283
Amortization of actuarial (gain) loss into income			$ 0
Unrecognized prior service cost	0
Net comprehensive income attributable to noncontrolling interest	(2,128)							2,128
Equity at end of period at Jun. 30, 2022	$ 1,044,941			$ 924,243	$ (2,196)			$ 122,894

XML

Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Operating activities
Net margins including noncontrolling interest	$ (66,486)	$ (2,635)
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion	86,743	99,238
Amortization of NRECA Retirement Security Plan prepayment	2,686	2,686
Amortization of debt issuance costs	1,738	1,249
Impairment loss	29,250	0
Deferred impairment loss	(29,250)	0
Rate stabilization revenue	(25,345)	(40,790)
Deposits associated with generator interconnection requests	9,766	17,130
Capital credit allocations from cooperatives and income from coal mines over refund distributions	(1,135)	(957)
Changes in operating assets and liabilities:
Accounts receivable	(24,984)	(19,250)
Coal inventory	4,013	(9,202)
Materials and supplies	(5,040)	(249)
Accounts payable and accrued expenses	26,027	23,681
Accrued interest	(1,486)	(1,628)
Accrued property taxes	(13,901)	(14,640)
New Horizon Mine environmental obligation	44,869	0
Other	(9,723)	(1,935)
Net cash provided by operating activities	27,742	52,698
Investing activities
Purchases of plant	(56,115)	(52,030)
Changes in deferred charges	(3,644)	(5,325)
Proceeds from other investments	75	72
Net cash used in investing activities	(59,684)	(57,283)
Financing activities
Changes in Member advances	2,433	2,499
Payments of long-term debt	(97,417)	(73,946)
Debt issuance costs	(1,311)	0
Change in short-term borrowings, net	129,702	79,968
Retirement of patronage capital	(4,564)	(13,705)
Equity distribution to noncontrolling interest	(342)	(2,693)
Other	(445)	(409)
Net cash provided by (used in) financing activities	28,056	(8,286)
Net decrease in cash, cash equivalents and restricted cash and investments	(3,886)	(12,871)
Cash, cash equivalents and restricted cash and investments – beginning	105,136	132,074
Cash, cash equivalents and restricted cash and investments – ending	101,250	119,203
Supplemental cash flow information:
Cash paid for interest	70,942	72,904
Cash paid for income taxes	0	0
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$ (2,606)	$ 397

XML

PRESENTATION OF FINANCIAL INFORMATION

6 Months Ended

Jun. 30, 2022

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, 2021 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, 2022, results of operations for the three and six months ended June 30, 2022 and 2021, and cash flows for the six months ended June 30, 2022 and 2021 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-two electric distribution member systems who are Class A members to which we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members. We have three non-utility members (“Non-Utility Members”). Our Class A members and any Class B members are collectively referred to as our “Utility Members.” Our Class A members, any Class B members, and Non-Utility Members are collectively referred to as our “Members.” The addition of Non-Utility Members in 2019 and specifically the addition of MIECO, Inc. on September 3, 2019 removed the exemption from the Federal Energy Regulatory Commission’s (“FERC”) regulation for us, thus subjecting us to full rate and transmission jurisdiction by FERC effective September 3, 2019. Our stated rate to our Class A members was filed at FERC on December 23, 2019 and was accepted by FERC on March 20, 2020. On August 2, 2021, FERC approved our settlement agreement related to our stated rate to our Class A members. See Note 17 – Legal.

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 16 – Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. We have eliminated all significant intercompany balances and transactions in consolidation.

Jointly Owned Facilities

We own undivided interests in two jointly owned generating facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common. These projects include the Yampa Project (operated by us) and the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)). Each participant in these agreements receives a portion of the total output of the generating facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and other operating expenses is included in our consolidated financial statements.

Our share in each jointly owned facility is as follows as of June 30, 2022 (dollars in thousands):

	Tri-State Share		Electric Plant in Service		Accumulated Depreciation		Construction Work In Progress
Yampa Project - Craig Generating Station Units 1 and 2	24.00	%	$	391,913	$	258,163	$	291
MBPP - Laramie River Station	28.50	%	525,986		339,367		4,168
Total			$	917,899	$	597,530	$	4,459

XML

ACCOUNTING FOR RATE REGULATION

6 Months Ended

Jun. 30, 2022

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 of Directors (“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, 2022		December 31, 2021
Regulatory assets
Deferred income tax expense (1)	$	18,742	$	18,742
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)	77,988		79,133
Goodwill – J.M. Shafer (3)	42,023		43,447
Goodwill – Colowyo Coal (4)	34,611		35,128
Deferred debt prepayment transaction costs (5)	119,360		123,674
Deferred Holcomb expansion impairment loss (6)	81,807		84,145
Unrecovered plant (7)	299,847		281,424
Total regulatory assets	674,378		665,693
Regulatory liabilities
Interest rate swap - realized gain (8) and other	2,577		2,818
Membership withdrawal (9)	117,859		143,203
Total regulatory liabilities	120,436		146,021
Net regulatory asset	$	553,942	$	519,672

(1)A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues.

(2)Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Utility Members through rates.

(3)Represents goodwill related to our acquisition of an entity that owned J.M. Shafer Generating Station in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Utility Members through rates.

(4)Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Utility Members 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 deferral of the impairment losses related to the early retirement of the Nucla, Escalante and Rifle Generating Stations. The deferred impairment loss for Nucla and Escalante Generating Stations is being amortized to depreciation, amortization and depletion expense in the amount of $7.7 million annually through December 2022 and $12.3 million annually over the 25-year period ending in December 2045, respectively, and recovered from our Utility Members through rates. In March 2022, our Board took action for the early retirement of the Rifle Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement, we recognized an impairment loss of $3.7 million during the first quarter of 2022. The Rifle Generating Station is anticipated to be retired from service in October 2022. Once retired, the deferred impairment loss will be amortized to depreciation, amortization and depletion expense through December 2028, which was the depreciable life of the Rifle Generating Station, and recovered from our Utility Members in rates.

(8)Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12-year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods.

(9) Represents the deferral of the recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. The deferred membership withdrawal income will be refunded to Utility Members through reduced rates when recognized in operating revenues in future periods. For the six months ended June 30, 2022, $25.3 million was recognized in operating revenues as part of our rate stabilization measures.

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INVESTMENTS IN OTHER ASSOCIATIONS

6 Months Ended

Jun. 30, 2022

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, 2022		December 31, 2021
Basin Electric Power Cooperative	$	116,826	$	116,826
National Rural Utilities Cooperative Finance Corporation - patronage capital	12,076		12,076
National Rural Utilities Cooperative Finance Corporation - capital term certificates	15,074		15,149
CoBank, ACB	14,328		12,985
Other	5,955		6,061
Investments in other associations	$	164,259	$	163,097

Our investments in other associations are considered equity securities without readily determinable fair values, and as such are measured at cost minus impairment. We have evaluated these investments for indicators of impairment. There were no impairments of these investments recognized during the six months ended June 30, 2022 or during 2021.

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CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS

6 Months Ended

Jun. 30, 2022

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, 2022		December 31, 2021
Cash and cash equivalents	$	96,841	$	100,555
Restricted cash and investments - current	663		480
Restricted cash and investments - noncurrent	3,746		4,101
Cash, cash equivalents and restricted cash and investments	$	101,250	$	105,136

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CONTRACT ASSETS AND CONTRACT LIABILITIES

6 Months Ended

Jun. 30, 2022

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 12 – 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, 2022, we recognized $0.7 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, 2022		December 31, 2021
Accounts receivable - Utility Members	$	111,571	$	95,630
Other accounts receivable - trade:
Non-member electric sales	10,133		5,684
Other	8,446		13,505
Total other accounts receivable - trade	18,579		19,189
Other accounts receivable - nontrade	6,984		2,382
Total other accounts receivable	$	25,563	$	21,571
Contract liabilities (unearned revenue)	$	5,207	$	5,372

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OTHER DEFERRED CHARGES

6 Months Ended

Jun. 30, 2022

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, 2022		December 31, 2021
Preliminary surveys and investigations	$	12,743	$	12,366
Advances to operating agents of jointly owned facilities	7,556		4,422
Operating lease right-of-use assets	6,997		7,529
Other	13,741		10,822
Total other deferred charges	$	41,037	$	35,139

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 14 – Leases.

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LONG-TERM DEBT

6 Months Ended

Jun. 30, 2022

Debt Disclosure [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT

We have $2.9 billion of long-term debt which consists of mortgage notes payable, pollution control revenue bonds and the Springerville certificates. The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement (“Master Indenture”) except for one unsecured note in the amount of $8.1 million as of June 30, 2022. Additionally, $100.0 million of our First Mortgage Bonds, Series 2014E-1 was reclassified to current maturities due to a public tender offer of such bonds which was completed in July 2022. Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. All long-term debt contains certain restrictive financial covenants, including a debt service ratio requirement on an annual basis and an equity to capitalization ratio requirement of at least 18 percent at the end of each fiscal year. Other than the Springerville certificates that has a debt service ratio requirement of at least 1.02 on an annual basis, all other long-term debt contains a debt service ratio requirement of at least 1.10 on an annual basis.

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 extends through 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, 2022, we had $340.0 million in availability under the 2022 Revolving Credit Agreement.

Long-term debt consists of the following (dollars in thousands):

	June 30, 2022		December 31, 2021
Total debt	$	3,117,011	$	3,214,427
Less debt issuance costs	(22,684)		(23,110)
Less debt discounts	(9,118)		(9,398)
Plus debt premiums	12,416		12,990
Total debt adjusted for debt issuance costs, discounts and premiums	3,097,625		3,194,909
Less current maturities	(201,575)		(93,039)
Long-term debt	$	2,896,050	$	3,101,870

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SHORT-TERM BORROWINGS

6 Months Ended

Jun. 30, 2022

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.

Commercial paper consisted of the following (dollars in thousands):

	June 30, 2022			December 31, 2021
Commercial paper outstanding, net of discounts	$	179,699		$	49,997
Weighted average interest rate	1.86		%	0.19		%

At June 30, 2022, $320.0 million of the commercial paper back-up sublimit remained available under the 2022 Revolving Credit Agreement. See Note 7 – Long-Term Debt.

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ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS

6 Months Ended

Jun. 30, 2022

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. One pit at the Colowyo Mine began final reclamation in 2020 with the other remaining pits still being actively mined.

Generation: We have asset retirement obligations related to equipment, dams, ponds, wells 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, 2022
Obligations at beginning of period	$	90,281
Liabilities settled	(3,889)
Accretion expense	1,448
Change in estimate	85,477
Total obligations at end of period	$	173,317
Less current obligations at end of period	(4,953)
Long-term obligations at end of period	$	168,364

In the second quarter of 2022, we increased the environmental reclamation obligation at the New Horizon Mine by $44.9 million due to revised cost estimates. The New Horizon Mine environmental remediation liability that has been recorded is $67.3 million as of June 30, 2022. Of this amount, $36.8 million is recorded on a discounted basis, using a discount rate of 3.25 percent, with total estimated undiscounted future cash outflows of $57.9 million. Environmental obligation expense is included in other operating expenses on our consolidated statement of operations. Although the entire environmental obligation has been expensed, we may seek future rate recovery in upcoming rate filings with FERC. We continue to evaluate the New Horizon Mine and Colowyo Mine post reclamation obligations and will make adjustments to these obligations as needed. Also in the second quarter of 2022, we recorded an additional asset retirement obligation of $40.6 million related to a change in cost estimates for our pond, ash landfill and post-closure reclamation obligations at various generating stations.

We also have asset retirement obligations with indeterminate settlement dates. These are made up primarily of obligations attached to transmission and other easements that are considered by us to be operated in perpetuity and therefore the measurement of the obligation is not possible. A liability will be recognized in the period in which sufficient information exists to estimate a range of potential settlement dates as is needed to employ a present value technique to estimate fair value.

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OTHER DEFERRED CREDITS AND OTHER LIABILITIES

6 Months Ended

Jun. 30, 2022

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, 2022		December 31, 2021
Transmission easements	$	18,857	$	19,339
Operating lease liabilities - noncurrent	1,403		1,622
Contract liabilities (unearned revenue) - noncurrent	3,351		3,523
Customer deposits	8,632		9,287
Financial liabilities - reclamation	11,756		13,122
OATT deposits	24,520		24,327
Other	7,242		7,099
Total other deferred credits and other liabilities	$	75,761	$	78,319

In 2015, we renewed transmission right-of-way easements on tribal nation lands where certain of our electric transmission lines are located. $27.8 million will be paid by us for these easements from 2022 through the individual easement terms ending between 2036 and 2040. The present values for the remaining easement payments were $18.9 million and $19.3 million as of June 30, 2022 and December 31, 2021, respectively, which are recorded as other deferred credits and other liabilities.

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 14 – 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.

Financial liabilities - reclamation represents the financial obligation for our share of reclamation at San Juan Mine (related to our former ownership in the San Juan Generating Station) and our share of reclamation at Laramie River Station (related to our ownership share in MBPP).

OATT deposits primarily represent deposits that are received by us related to generator interconnection requests that may be returned if the project does proceed to completion.

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EMPLOYEE BENEFIT PLANS

6 Months Ended

Jun. 30, 2022

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 at June 30, 2022, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles. As of June 30, 2021, the plans ceased to provide postretirement medical benefits for employees who retire after June 30, 2021.

The postretirement medical benefit and post employment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and post employment obligations on our consolidated statements of financial position as follows (dollars in thousands):

	Six Months Ended June 30, 2022
Postretirement medical benefit obligation at beginning of period	$	2,809
Service cost	—
Interest cost	18
Benefit payments (net of contributions by participants)	(324)
Postretirement medical benefit obligation at end of period	$	2,503
Postemployment medical benefit obligation at end of period	392
Total postretirement and postemployment medical obligations at end of period	$	2,895

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, 2022
Accumulated other comprehensive income at beginning of period	$	3,580
Amortization of prior service credit into other income	(1,070)
Accumulated other comprehensive income at end of period	$	2,510

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, 2022
Executive benefit restoration obligation at beginning of period	$	9,852
Service cost	185
Interest cost	104
Benefit payments	(111)
Executive benefit restoration at end of period	$	10,030
Fair value of plan assets at beginning of period	$	8,640
Employer contributions	303
Actual return on plan assets	$	(192)
Fair value of plan assets at end of period	$	8,751
Net liability recognized at end of period	$	1,279

The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations. In December 2020, we established an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary.

In accordance with the accounting standard related to defined benefit pension plans, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other income on our consolidated statements of financial position. If the unrecognized amount is in excess of 10 percent of the projected benefit obligation, amounts are reclassified out of accumulated other comprehensive income and included in net income as the excess is amortized over the average remaining service lives of the active plan participants. Unrecognized actuarial gains and losses have been determined per actuarial studies for the executive benefit restoration obligation.

The net unrecognized actuarial gains and losses related to the executive benefit restoration obligations are included in accumulated other comprehensive income as follows (dollars in thousands):

	Six Months Ended June 30, 2022
Accumulated other comprehensive loss at beginning of period	$	(4,932)
Amortization of prior service cost into other income	566
Accumulated other comprehensive loss at end of period	$	(4,366)

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REVENUE

6 Months Ended

Jun. 30, 2022

Revenue from Contract with Customer [Abstract]

REVENUE

REVENUE

Revenue from Contracts with Customers

Our revenues are derived primarily from the sale of wholesale electric service to our Utility Members pursuant to long-term wholesale electric service contracts. Our contracts with our 42 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,
	2022		2021		2022		2021
Non-member electric sales:
Long-term contracts	$	12,970	$	10,093	$	25,250	$	18,799
Short-term contracts	21,244		6,095		31,908		14,730
Rate stabilization	17,462		19,957		25,345		40,790
Other	13,718		15,712		25,846		30,712
Total non-member electric sales and other operating revenue	$	65,394	$	51,857	$	108,349	$	105,031

Non-member electric sales

Revenues from wholesale electric power sales to non-members are primarily from long-term contracts and short-term market sales. Prior to our customers’ demand for energy, we do not have a contractual right to consideration as we are not obligated to provide energy until the customer demands each incremental unit of energy. We transfer control of the energy to our customer over time and our customer simultaneously receives and consumes the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method. Payments are received in accordance with the contract terms, which is less than 30 days after the invoice is received by the customer.

Rate Stabilization Revenue

We recognized $17.5 million and $25.3 million of deferred membership withdrawal income for the three and six months ended June 30, 2022, respectively, as directed by our Board. See Note 2 - Accounting for Rate Regulation.

Other operating revenue

Other operating revenue consists primarily of wheeling, transmission, and coal sales revenue. Other operating revenue also includes revenue we receive from our Non-Utility Members. Wheeling revenue is 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 the annual transmission revenue requirement). Each of these services or goods are provided over time and progress toward completion of our performance obligations are measured using the output method. Coal sales revenue results from the sale of coal from the Colowyo Mine and other locations to third parties. We have an obligation to deliver coal and progress of completion toward our performance obligation is measured using the output method. Our performance obligation is completed as coal is delivered.

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INCOME TAXES

6 Months Ended

Jun. 30, 2022

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. Effective January 1, 2020, we adopted the normalization method of recognizing deferred income taxes pursuant to FERC regulation. Under the normalization method, changes in deferred tax assets or liabilities result in deferred income tax expense (benefit) and any recorded income tax expense (benefit) therefore includes both the current income tax expense (benefit) and the deferred income tax expense (benefit).

Our subsidiaries are not subject to FERC regulation and continue to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be settled or received through future rate revenues.

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. Our consolidated statements of operations included an income tax expense of $37,000 for the six months ended June 30, 2022 and $219,000 for the comparable period in 2021.

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LEASES

6 Months Ended

Jun. 30, 2022

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 current liabilities 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.

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, 2022 and $0.9 million for the comparable period in 2021. Rent expense for all short-term and long-term operating leases was $1.5 million for the six months ended June 30, 2022 and $1.9 million for the comparable period in 2021. 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. As of June 30, 2022, there were no arrangements accounted for as finance leases.

Our consolidated statements of financial position include the following lease components (dollars in thousands):

	June 30, 2022			December 31, 2021
Operating leases
Operating lease right-of-use assets	$	8,936		$	9,081
Less: Accumulated amortization	(1,939)			(1,552)
Net operating lease right-of-use assets	$	6,997		$	7,529
Operating lease liabilities - current	$	(401)		$	(491)
Operating lease liabilities - noncurrent	(1,403)			(1,622)
Total operating lease liabilities	$	(1,804)		$	(2,113)
Operating leases
Weighted average remaining lease term (years)	7.5			7.6
Weighted average discount rate	3.82		%	3.79		%

Future expected minimum lease commitments under operating leases are as follows (dollars in thousands):

Year 1	$	290
Year 2	385
Year 3	278
Year 4	482
Year 5	94
Thereafter	596
Total lease payments	$	2,125
Less imputed interest	(321)
Total	$	1,804

Leasing Arrangements as Lessor

We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $1.8 million and $1.7 million for the three months ended June 30, 2022 and 2021, respectively, and $3.5 million for the six months ended June 30, 2022 and 2021 are included in other operating revenue on our consolidated statements of operations.

The lease arrangement with the Springerville Partnership is not reflected in our lease right right-of-use asset or liability balances as the associated revenues and expenses are eliminated in consolidation. See Note 16- Variable Interest Entities. However, as the non-controlling interest associated with this lease arrangement generates book-tax differences, a deferred tax asset and liability have been recorded.

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 current liabilities 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.

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, 2022 and $0.9 million for the comparable period in 2021. Rent expense for all short-term and long-term operating leases was $1.5 million for the six months ended June 30, 2022 and $1.9 million for the comparable period in 2021. 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. As of June 30, 2022, there were no arrangements accounted for as finance leases.

Our consolidated statements of financial position include the following lease components (dollars in thousands):

	June 30, 2022			December 31, 2021
Operating leases
Operating lease right-of-use assets	$	8,936		$	9,081
Less: Accumulated amortization	(1,939)			(1,552)
Net operating lease right-of-use assets	$	6,997		$	7,529
Operating lease liabilities - current	$	(401)		$	(491)
Operating lease liabilities - noncurrent	(1,403)			(1,622)
Total operating lease liabilities	$	(1,804)		$	(2,113)
Operating leases
Weighted average remaining lease term (years)	7.5			7.6
Weighted average discount rate	3.82		%	3.79		%

Future expected minimum lease commitments under operating leases are as follows (dollars in thousands):

Year 1	$	290
Year 2	385
Year 3	278
Year 4	482
Year 5	94
Thereafter	596
Total lease payments	$	2,125
Less imputed interest	(321)
Total	$	1,804

Leasing Arrangements as Lessor

We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $1.8 million and $1.7 million for the three months ended June 30, 2022 and 2021, respectively, and $3.5 million for the six months ended June 30, 2022 and 2021 are included in other operating revenue on our consolidated statements of operations.

The lease arrangement with the Springerville Partnership is not reflected in our lease right right-of-use asset or liability balances as the associated revenues and expenses are eliminated in consolidation. See Note 16- Variable Interest Entities. However, as the non-controlling interest associated with this lease arrangement generates book-tax differences, a deferred tax asset and liability have been recorded.

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FAIR VALUE

6 Months Ended

Jun. 30, 2022

Fair Value Disclosures [Abstract]

FAIR VALUE

FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal 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

In December 2020, we established an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary. The trust consists of investments in equity and debt securities and are measured at fair value on a recurring basis. Changes in the fair value of investments in equity securities are recognized in earnings and changes in fair value of investments in debt securities classified as available-for-sale are recognized in other comprehensive income until realized. The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The cost and fair values of our marketable securities are as follows (dollars in thousands):

	June 30, 2022				December 31, 2021
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	9,407	$	8,751	$	8,850	$	8,640

Marketable Securities

We hold marketable securities in connection with the directors’ and executives’ elective deferred compensation plans which consist of investments in stock funds, bond funds and money market funds. These securities are measured at fair value on a recurring basis with changes in fair value recognized in earnings. The estimated fair value of the investments is based upon their active market value (Level 1 inputs) and is included in other noncurrent assets on our consolidated statements of financial position. The cost and fair values of our marketable securities are as follows (dollars in thousands):

	June 30, 2022				December 31, 2021
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	550	$	481	$	597	$	598

Cash Equivalents

We invest portions of our cash and cash equivalents in commercial paper, money market funds, and other highly liquid investments. The fair value of these investments approximates our cost basis in the investments. In aggregate, the fair value was $67.7 million as of June 30, 2022 and $95.3 million as of December 31, 2021.

Debt

The fair values of long-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, 2022				December 31, 2021
	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
Total long-term debt	$	3,117,011	$	3,017,268	$	3,214,427	$	3,759,991

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VARIABLE INTEREST ENTITIES

6 Months Ended

Jun. 30, 2022

Variable Interest Entity or Potential VIE, Information Unavailability, Disclosures [Abstract]

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

The following is a description of our financial interests in variable interest entities that we consider significant. This includes an entity for which we are determined to be the primary beneficiary and therefore consolidate.

Consolidated Variable Interest Entity

Springerville Partnership: We own a 51 percent equity interest, including the 1 percent general partner equity interest, in the Springerville Partnership, which is the 100 percent owner of Springerville Unit 3 Holding LLC (“Owner Lessor”). The Owner Lessor is the owner of the Springerville Unit 3. We, as general partner of the Springerville Partnership, have the full, exclusive and complete right, power and discretion to operate, manage and control the affairs of the Springerville Partnership and take certain actions necessary to maintain the Springerville Partnership in good standing without the consent of the limited partners. Additionally, the Owner Lessor has historically not demonstrated an ability to finance its activities without additional financial support. The financial support is provided by our remittance of lease payments in order to permit the Owner Lessor, the holder of the Springerville Unit 3 assets, to pay the debt obligations and equity returns of the Springerville Partnership. We have the primary risk (expense) exposure in operating the Springerville Unit 3 assets and are responsible for 100 percent of the operation, maintenance and capital expenditures of Springerville Unit 3 and the decisions related to those expenditures including budgeting, financing and dispatch of power. Based on all these facts, it was determined that we are the primary beneficiary of the Owner Lessor. Therefore, the Springerville Partnership and Owner Lessor have been consolidated by us.

Assets and liabilities of the Springerville Partnership that are included in our consolidated statements of financial position are as follows (dollars in thousands):

	June 30, 2022		December 31, 2021
Net electric plant	$	731,066	$	740,135
Noncontrolling interest	122,896		119,100
Long-term debt	255,354		300,220
Accrued interest	7,400		8,721

Our consolidated statements of operations include the following Springerville Partnership expenses for the three and six months ended June 30, 2022 and 2021 (dollars in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2022		2021		2022		2021
Depreciation, amortization and depletion	$	4,535	$	4,535	$	9,069	$	9,069
Interest	3,958		4,956		8,662		10,141

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.

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LEGAL

6 Months Ended

Jun. 30, 2022

Commitments and Contingencies Disclosure [Abstract]

LEGAL

LEGALOther 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.

FERC Tariff and Declaratory Order: Because of increased pressure by states to regulate our rates and charges with impact in other states setting up untenable conflict, we sought consistent federal jurisdiction by FERC. This was accomplished with the addition of non-cooperative members in 2019, specifically MIECO, Inc. as a Non-Utility Member on September 3, 2019. On the same date, we became FERC jurisdictional for our Utility Member rates, transmission service, and our market based rates. We filed our tariff for wholesale electric service and transmission at FERC in December 2019. In addition, on December 23, 2019, we filed our Petition for Declaratory Order ("Jurisdictional PDO") with FERC, EL20-16-000, asking FERC to confirm our jurisdiction under the Federal Power Act ("FPA") and that FERC’s jurisdiction preempts the jurisdiction of the Colorado Public Utilities Commission ("COPUC") to address any rate related issues, including the complaints filed by United Power, Inc. ("United Power") and La Plata Electric Association ("LPEA") with the COPUC.

On March 20, 2020, FERC issued orders regarding our Jurisdictional PDO and our tariff filings. FERC’s orders generally accepted our tariff filings and recognized that we became FERC jurisdictional on September 3, 2019, but did not make the tariffs retroactive to September 3, 2019. However, FERC specifically provided that no refunds are due on our Utility Member rates and our transmission service rates prior to March 26, 2020. FERC also did not determine that our Utility Member rates and transmission service rates were just and reasonable and ordered FPA section 206 proceedings to determine the justness and reasonableness of our rates and wholesale electric service contracts. On August 2, 2021, FERC approved our settlement agreement related to our Utility Member stated rate, as further discussed below. On March 7, 2022, FERC approved our settlement agreement related to our transmission service rates.

On August 28, 2020, FERC issued an order (“August 28 Order”) on rehearing related to our Jurisdictional PDO which modified its March 20, 2020 decision on our Jurisdictional PDO by finding exclusive jurisdiction over our contract termination payments related to our Utility Members and preempting the jurisdiction of the COPUC as of September 3, 2019. On December 16, 2020, United Power filed a petition for review with the United States Court of Appeals for the District of Columbia Circuit ("D.C. Circuit Court of Appeals") related to FERC’s August 28 Order, 20-1256. On March 30, 2022, oral arguments occurred before the D.C. Circuit Court of Appeals regarding the Jurisdictional PDO.

Petitions for review related to our tariff filings, including our Utility Member rates, have been filed with the D.C. Circuit Court of Appeals by other parties. On June 22, 2022, an order was issued by the court to hold all the cases before the D.C. Circuit Court of Appeals in abeyance other than related to the Jurisdictional PDO, directing the parties to file motions to govern future proceedings by September 20, 2022.

On August 2, 2021, FERC approved our settlement agreement related to our Utility Member stated rate, including our wholesale electric service contracts and certain of our Board policies filed with FERC. With the exception of four reserved issues contingent on United Power being a settling party, the settlement resolved all issues set for hearing and settlement procedures related to our Utility Member rates. The settlement provides for us to implement a two-stage, graduated reduction in the charges making up our Class A rate schedule of two percent starting from March 1, 2021 until the first anniversary and four percent reduction (additional two percent reduction from then current rates) thereafter until the date a new Class A wholesale rate schedule is approved by FERC and goes into effect. The settlement rates will remain in effect at least through May 31, 2023 and during such time period, we and the settlement parties have agreed, with limited exceptions, to a moratorium on any filings related to our Class A rate schedule, including any rate increases to our Class A rate schedule. We have also agreed to file a new Class A rate schedule after May 31, 2023 and prior to September 1, 2023. During the moratorium, we have established a rate design committee to oversee the development of the new rate. Three of the reserved issues are related to the transmission component of our rates and the fourth relates to our community solar program. Additionally, with the exception of one reserved issue regarding transmission demand charges applicable to certain electric storage resources, each of the reserved issues will have prospective effect only, with the intent that any FERC rulings would be implemented in future rate filings.

A hearing on the four reserved issued occurred in March 2022 before an administrative law judge at FERC and an initial decision was issued by an administrative law judge on May 26, 2022. On the three reserved issues that will have a prospective effect only, the initial decision provides that we must also unbundle in our bills to our Utility Members our transmission costs, including ancillary services and other costs, and, in our future rate filings, we must directly assign to our Utility Members the costs of radial facilities that do not meet FERC's standards for being included in our rolled-in transmission demand rate. In addition, the initial decision provided that our Board policy for our community solar program was unduly discriminatory because it advantaged small Utility Members to the disadvantage of larger Utility Members. With regard to the reserved issue regarding transmission demand charges applicable to certain electric storage resources, the initial decision agreed with our Board policy of billing Utility Members for the transmission demand costs that includes all of a Utility Member's transmission demand, including such Utility Member's electric storage resource. On June 26, 2022, we, United Power, and certain other Utility Members filed exceptions to the initial decision. Because exceptions were taken to the initial decision, the initial decision and exceptions are now before the commissioners of FERC for a decision on the four reserved issues.

It is not possible to predict the outcome of the four reserved issues related to our member rates docket. In addition, we cannot predict the outcome of any petitions for review filed with the D.C. Circuit Court of Appeals.

LPEA and United Power COPUC Complaints: Pursuant to our Bylaws, a Utility Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no Utility Member shall be permitted to withdraw until it has met all its contractual obligations to us, including all obligations under its wholesale electric service contract with us. On November 5, 2019, LPEA filed a formal complaint with the COPUC alleging that we hindered LPEA’s ability to seek withdrawal from us. On November 6, 2019, United Power filed a formal complaint with the COPUC, alleging that we hindered United Power’s ability to explore its power supply options by either withdrawing from us or continuing as a Utility Member under a partial requirements contract. On November 20, 2019, the COPUC consolidated the two proceedings into one, 19F-0621E.

A hearing was held on May 18-20, 2020. On July 10, 2020, the administrative law judge issued a recommended decision, but the COPUC on its own motion stayed the recommended decision. On September 18, 2020, LPEA and United Power filed a Joint Motion to Lodge FERC’s August 28 Order, and asserted additional corporate law arguments related to the legality of our addition of Non-Utility Members. On October 22, 2020, the COPUC determined that COPUC’s jurisdiction over United Power and LPEA’s complaints was preempted by FERC, the COPUC does not have jurisdiction over corporate law matters, and dismissed both complaints without prejudice. On January 27, 2021, United Power filed a Writ for Certiorari or Judicial Review, an appeal, in the Denver County District Court, 2021CV30325, of the COPUC's decision to dismiss United Power's complaint. On February 17, 2021, the Denver County District Court granted our unopposed motion to intervene as a defendant in United Power’s appeal of the COPUC’s dismissal. United Power, the COPUC, and us have all filed respective briefs with the court. The court heard oral arguments on September 17, 2021. It is not possible to predict the outcome of this matter.

United Power's Adams District Court Complaint: On May 4, 2020, United Power filed a Complaint for Declaratory Judgement and Damages in the Adams County District Court, 2020CV30649, against us and our three Non-Utility Members. On July 2, 2021, the court granted United Power's motion to amend its May 2020 complaint, including to add LPEA as an additional plaintiff, to amend its claims as to our three Non-Utility Members, and to add a claim that our addition of the Non-Utility Members violated Colorado law. On July 30, 2021, we filed a partial motion to dismiss a majority of United Power's and LPEA's claims. On July 30, 2021, the three Non-Utility Members filed a joint motion to dismiss all claims by United Power and LPEA against the Non-Utility Members.

On March 23, 2022, the court issued an order regarding our and the Non-Utility Members’ motions to dismiss. The court dismissed some of the claims against us and the Non-Utility Members, including the civil conspiracy claim. After the dismissal, the remaining claims include seeking declaratory orders that the addition of the Non-Utility Members violated Colorado law, the April 2019 Bylaws amendment that allows our Board to establish one or more classes of membership in addition to the then existing all-requirements class of membership is void, and the April 2020 Board approvals related to the methodology to calculate a contract termination payment and buy-down payment formula do not apply to United Power and are void, and that we have breached the wholesale electric service contract with United Power.

On April 6, 2022, we and each Non-Utility Member filed their respective answers to the first amended complaint denying that United Power and LPEA are entitled to any relief and requesting the court enter judgment of dismissal. We also asserted counterclaims against United Power and LPEA, and relief from United Power’s and LPEA’s breach of our Bylaws and declaratory judgement that the April 2019 Bylaws amendment and the April 2020 Board approvals related to the methodology to calculate a contract termination payment and buy-down payment formula are valid. On April 27, 2022, United Power and LPEA filed a reply to our counterclaims asserting that we are not entitled to any relief on our counterclaims. A jury trial is scheduled for June 2023. In the initial disclosures from United Power, United Power asserts that its damages in 2020 and 2021 exceed $87 million and United Power anticipates damages of $41 million in 2022 and $43 million each year thereafter that it remains a Utility Member of us.

On June 7, 2022, LPEA filed a stipulation by all parties to the case that all claims brought by LPEA against us and our three Non-Utility Members, along with counterclaims brought by us against LPEA, are to be dismissed. In addition, the stipulation provided for LPEA to be removed from the case. On June 8, 2022, the court issued an order dismissing LPEA from the case. It is not possible to predict the outcome of this matter or whether we will incur any liability in connection with this matter.

TAPP Complaint: On September 24, 2021, TransAmerican Power Products, Inc. (“TAPP”) filed a complaint in Adams County District Court, 2021CV31089, against us alleging breach of contract and breach of implied covenant of good faith and fair dealing related to an invoice for TAPP’s supply of materials for a transmission project. TAPP seeks damages of approximately $3 million. On November 9, 2021, we filed an answer and counterclaims against TAPP disputing any amount is owed to TAPP

and seeking damages for TAPP's breach of contract. A jury trial is scheduled for April 2023. It is not possible to predict the outcome of this matter or whether we will incur any liability in connection with this matter.

Basin Complaint: On December 17, 2021, Basin filed a complaint with the United States District Court District of North Dakota Eastern Division, 3:21-cv-00220-PDW-ARS, against us alleging that the filing of our modified contract termination payment tariff filed with FERC on September 1, 2021 constitutes a breach of our wholesale power contract with Basin for the Eastern Interconnection. On February 28, 2022, Basin filed a first amended compliant adding a new claim for anticipatory breach of contract. Basin seeks, among other things, for the court to require us to amend our modified contract termination payment tariff to exclude our Eastern Interconnection Utility Members. On March 29, 2022, we filed a motion to dismiss Basin’s first amended complaint. It is not possible to predict the outcome of this matter or whether we will incur any liability 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, 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 $383,760 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. 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.

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PRESENTATION OF FINANCIAL INFORMATION (Policies)	6 Months Ended
	Jun. 30, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Consolidation	Basis of ConsolidationWe 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-two electric distribution member systems who are Class A members to which we provide electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members. We have three non-utility members (“Non-Utility Members”). Our Class A members and any Class B members are collectively referred to as our “Utility Members.” Our Class A members, any Class B members, and Non-Utility Members are collectively referred to as our “Members.” The addition of Non-Utility Members in 2019 and specifically the addition of MIECO, Inc. on September 3, 2019 removed the exemption from the Federal Energy Regulatory Commission’s (“FERC”) regulation for us, thus subjecting us to full rate and transmission jurisdiction by FERC effective September 3, 2019. Our stated rate to our Class A members was filed at FERC on December 23, 2019 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.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 16 – Variable Interest Entities. Our consolidated financial statements also include our undivided interests in jointly owned facilities. We have eliminated all significant 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.

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PRESENTATION OF FINANCIAL INFORMATION (Tables)

6 Months Ended

Jun. 30, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Jointly Owned Facilities

Our share in each jointly owned facility is as follows as of June 30, 2022 (dollars in thousands):

	Tri-State Share		Electric Plant in Service		Accumulated Depreciation		Construction Work In Progress
Yampa Project - Craig Generating Station Units 1 and 2	24.00	%	$	391,913	$	258,163	$	291
MBPP - Laramie River Station	28.50	%	525,986		339,367		4,168
Total			$	917,899	$	597,530	$	4,459

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ACCOUNTING FOR RATE REGULATION (Tables)

6 Months Ended

Jun. 30, 2022

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities

Regulatory assets and liabilities are as follows (dollars in thousands):

	June 30, 2022		December 31, 2021
Regulatory assets
Deferred income tax expense (1)	$	18,742	$	18,742
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)	77,988		79,133
Goodwill – J.M. Shafer (3)	42,023		43,447
Goodwill – Colowyo Coal (4)	34,611		35,128
Deferred debt prepayment transaction costs (5)	119,360		123,674
Deferred Holcomb expansion impairment loss (6)	81,807		84,145
Unrecovered plant (7)	299,847		281,424
Total regulatory assets	674,378		665,693
Regulatory liabilities
Interest rate swap - realized gain (8) and other	2,577		2,818
Membership withdrawal (9)	117,859		143,203
Total regulatory liabilities	120,436		146,021
Net regulatory asset	$	553,942	$	519,672

(1)A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payable that will be received or settled through future rate revenues.

(2)Represents deferral of the loss on acquisition related to the Springerville Generating Station Unit 3 (“Springerville Unit 3”) prepaid lease expense upon acquiring a controlling interest in the Springerville Unit 3 Partnership LP (“Springerville Partnership”) in 2009. The regulatory asset for the deferred prepaid lease expense is being amortized to depreciation, amortization and depletion expense in the amount of $2.3 million annually through the 47-year period ending in 2056 and recovered from our Utility Members through rates.

(3)Represents goodwill related to our acquisition of an entity that owned J.M. Shafer Generating Station in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $2.8 million annually through the 25-year period ending in 2036 and recovered from our Utility Members through rates.

(4)Represents goodwill related to our acquisition of Colowyo Coal Company LP (“Colowyo Coal”) in December 2011. Goodwill is being amortized to depreciation, amortization and depletion expense in the amount of $1.0 million annually through the 44-year period ending in 2056 and recovered from our Utility Members 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 deferral of the impairment losses related to the early retirement of the Nucla, Escalante and Rifle Generating Stations. The deferred impairment loss for Nucla and Escalante Generating Stations is being amortized to depreciation, amortization and depletion expense in the amount of $7.7 million annually through December 2022 and $12.3 million annually over the 25-year period ending in December 2045, respectively, and recovered from our Utility Members through rates. In March 2022, our Board took action for the early retirement of the Rifle Generating Station and the deferral of any impairment loss in accordance with accounting for rate regulation. In conjunction with the early retirement, we recognized an impairment loss of $3.7 million during the first quarter of 2022. The Rifle Generating Station is anticipated to be retired from service in October 2022. Once retired, the deferred impairment loss will be amortized to depreciation, amortization and depletion expense through December 2028, which was the depreciable life of the Rifle Generating Station, and recovered from our Utility Members in rates.

(8)Represents deferral of a realized gain of $4.6 million related to the October 2017 settlement of a forward starting interest rate swap. This realized gain was deferred as a regulatory liability and is being amortized to interest expense over the 12-year term of the First Mortgage Obligations, Series 2017A and refunded to Utility Members through reduced rates when recognized in future periods.

(9) Represents the deferral of the recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. The deferred membership withdrawal income will be refunded to Utility Members through reduced rates when recognized in operating revenues in future periods. For the six months ended June 30, 2022, $25.3 million was recognized in operating revenues as part of our rate stabilization measures.

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INVESTMENTS IN OTHER ASSOCIATIONS (Tables)

6 Months Ended

Jun. 30, 2022

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, 2022		December 31, 2021
Basin Electric Power Cooperative	$	116,826	$	116,826
National Rural Utilities Cooperative Finance Corporation - patronage capital	12,076		12,076
National Rural Utilities Cooperative Finance Corporation - capital term certificates	15,074		15,149
CoBank, ACB	14,328		12,985
Other	5,955		6,061
Investments in other associations	$	164,259	$	163,097

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CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS (Tables)

6 Months Ended

Jun. 30, 2022

Cash, Cash Equivalents, Restricted Cash, and Restricted Cash Equivalents [Abstract]

Schedule of Cash and Cash Equivalents

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, 2022		December 31, 2021
Cash and cash equivalents	$	96,841	$	100,555
Restricted cash and investments - current	663		480
Restricted cash and investments - noncurrent	3,746		4,101
Cash, cash equivalents and restricted cash and investments	$	101,250	$	105,136

Schedule of Restricted Cash

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, 2022		December 31, 2021
Cash and cash equivalents	$	96,841	$	100,555
Restricted cash and investments - current	663		480
Restricted cash and investments - noncurrent	3,746		4,101
Cash, cash equivalents and restricted cash and investments	$	101,250	$	105,136

Schedule of 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, 2022		December 31, 2021
Cash and cash equivalents	$	96,841	$	100,555
Restricted cash and investments - current	663		480
Restricted cash and investments - noncurrent	3,746		4,101
Cash, cash equivalents and restricted cash and investments	$	101,250	$	105,136

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CONTRACT ASSETS AND CONTRACT LIABILITIES (Tables)

6 Months Ended

Jun. 30, 2022

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, 2022		December 31, 2021
Accounts receivable - Utility Members	$	111,571	$	95,630
Other accounts receivable - trade:
Non-member electric sales	10,133		5,684
Other	8,446		13,505
Total other accounts receivable - trade	18,579		19,189
Other accounts receivable - nontrade	6,984		2,382
Total other accounts receivable	$	25,563	$	21,571
Contract liabilities (unearned revenue)	$	5,207	$	5,372

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OTHER DEFERRED CHARGES (Tables)

6 Months Ended

Jun. 30, 2022

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, 2022		December 31, 2021
Preliminary surveys and investigations	$	12,743	$	12,366
Advances to operating agents of jointly owned facilities	7,556		4,422
Operating lease right-of-use assets	6,997		7,529
Other	13,741		10,822
Total other deferred charges	$	41,037	$	35,139

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LONG-TERM DEBT (Tables)

6 Months Ended

Jun. 30, 2022

Debt Disclosure [Abstract]

Schedule of Long-term Debt

Long-term debt consists of the following (dollars in thousands):

	June 30, 2022		December 31, 2021
Total debt	$	3,117,011	$	3,214,427
Less debt issuance costs	(22,684)		(23,110)
Less debt discounts	(9,118)		(9,398)
Plus debt premiums	12,416		12,990
Total debt adjusted for debt issuance costs, discounts and premiums	3,097,625		3,194,909
Less current maturities	(201,575)		(93,039)
Long-term debt	$	2,896,050	$	3,101,870

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SHORT-TERM BORROWINGS (Tables)

6 Months Ended

Jun. 30, 2022

Short-Term Debt [Abstract]

Schedule of Commercial Paper

Commercial paper consisted of the following (dollars in thousands):

	June 30, 2022			December 31, 2021
Commercial paper outstanding, net of discounts	$	179,699		$	49,997
Weighted average interest rate	1.86		%	0.19		%

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ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS (Tables)

6 Months Ended

Jun. 30, 2022

Asset Retirement Obligation And Accrual For Environmental Loss Contingencies Disclosure [Abstract]

Schedule of Asset Retirement Obligations and Environmental Reclamation Obligations

Aggregate carrying amounts of asset retirement obligations and environmental reclamation obligations are as follows (dollars in thousands):

	Six Months Ended June 30, 2022
Obligations at beginning of period	$	90,281
Liabilities settled	(3,889)
Accretion expense	1,448
Change in estimate	85,477
Total obligations at end of period	$	173,317
Less current obligations at end of period	(4,953)
Long-term obligations at end of period	$	168,364

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OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Tables)

6 Months Ended

Jun. 30, 2022

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, 2022		December 31, 2021
Transmission easements	$	18,857	$	19,339
Operating lease liabilities - noncurrent	1,403		1,622
Contract liabilities (unearned revenue) - noncurrent	3,351		3,523
Customer deposits	8,632		9,287
Financial liabilities - reclamation	11,756		13,122
OATT deposits	24,520		24,327
Other	7,242		7,099
Total other deferred credits and other liabilities	$	75,761	$	78,319

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EMPLOYEE BENEFIT PLANS (Tables)

6 Months Ended

Jun. 30, 2022

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, 2022
Postretirement medical benefit obligation at beginning of period	$	2,809
Service cost	—
Interest cost	18
Benefit payments (net of contributions by participants)	(324)
Postretirement medical benefit obligation at end of period	$	2,503
Postemployment medical benefit obligation at end of period	392
Total postretirement and postemployment medical obligations at end of period	$	2,895

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, 2022
Executive benefit restoration obligation at beginning of period	$	9,852
Service cost	185
Interest cost	104
Benefit payments	(111)
Executive benefit restoration at end of period	$	10,030
Fair value of plan assets at beginning of period	$	8,640
Employer contributions	303
Actual return on plan assets	$	(192)
Fair value of plan assets at end of period	$	8,751
Net liability recognized at end of period	$	1,279

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, 2022
Accumulated other comprehensive income at beginning of period	$	3,580
Amortization of prior service credit into other income	(1,070)
Accumulated other comprehensive income at end of period	$	2,510

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, 2022
Accumulated other comprehensive loss at beginning of period	$	(4,932)
Amortization of prior service cost into other income	566
Accumulated other comprehensive loss at end of period	$	(4,366)

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REVENUE (Tables)

6 Months Ended

Jun. 30, 2022

Revenue from Contract with Customer [Abstract]

Schedule of Revenue from Contracts with Non-member Customers and Other Operating Revenue

The following revenue is reflected on our consolidated statements of operations as follows (dollars in thousands):

	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Non-member electric sales:
Long-term contracts	$	12,970	$	10,093	$	25,250	$	18,799
Short-term contracts	21,244		6,095		31,908		14,730
Rate stabilization	17,462		19,957		25,345		40,790
Other	13,718		15,712		25,846		30,712
Total non-member electric sales and other operating revenue	$	65,394	$	51,857	$	108,349	$	105,031

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LEASES (Tables)

6 Months Ended

Jun. 30, 2022

Leases [Abstract]

Schedule of Lease Components

Our consolidated statements of financial position include the following lease components (dollars in thousands):

	June 30, 2022			December 31, 2021
Operating leases
Operating lease right-of-use assets	$	8,936		$	9,081
Less: Accumulated amortization	(1,939)			(1,552)
Net operating lease right-of-use assets	$	6,997		$	7,529
Operating lease liabilities - current	$	(401)		$	(491)
Operating lease liabilities - noncurrent	(1,403)			(1,622)
Total operating lease liabilities	$	(1,804)		$	(2,113)
Operating leases
Weighted average remaining lease term (years)	7.5			7.6
Weighted average discount rate	3.82		%	3.79		%

Schedule of Future Expected Minimum Lease Commitments under Operating Leases

Future expected minimum lease commitments under operating leases are as follows (dollars in thousands):

Year 1	$	290
Year 2	385
Year 3	278
Year 4	482
Year 5	94
Thereafter	596
Total lease payments	$	2,125
Less imputed interest	(321)
Total	$	1,804

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FAIR VALUE (Tables)

6 Months Ended

Jun. 30, 2022

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, 2022				December 31, 2021
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	9,407	$	8,751	$	8,850	$	8,640

The cost and fair values of our marketable securities are as follows (dollars in thousands):

	June 30, 2022				December 31, 2021
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	550	$	481	$	597	$	598

The principal amounts and fair values of our debt are as follows (dollars in thousands):

	June 30, 2022				December 31, 2021
	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
Total long-term debt	$	3,117,011	$	3,017,268	$	3,214,427	$	3,759,991

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VARIABLE INTEREST ENTITIES (Tables)

6 Months Ended

Jun. 30, 2022

Variable Interest Entity or Potential VIE, Information Unavailability, Disclosures [Abstract]

Schedule of Consolidated Variable Interest Entities

Assets and liabilities of the Springerville Partnership that are included in our consolidated statements of financial position are as follows (dollars in thousands):

	June 30, 2022		December 31, 2021
Net electric plant	$	731,066	$	740,135
Noncontrolling interest	122,896		119,100
Long-term debt	255,354		300,220
Accrued interest	7,400		8,721

Our consolidated statements of operations include the following Springerville Partnership expenses for the three and six months ended June 30, 2022 and 2021 (dollars in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2022		2021		2022		2021
Depreciation, amortization and depletion	$	4,535	$	4,535	$	9,069	$	9,069
Interest	3,958		4,956		8,662		10,141

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PRESENTATION OF FINANCIAL INFORMATION - Narrative (Details)	6 Months Ended
	Jun. 30, 2022 member_system facility
Disaggregation of Revenue [Line Items]
Number of classes of members	3
Number of jointly owned facilities | facility	2
Class A Members
Disaggregation of Revenue [Line Items]
Number of members	42
Class B Members
Disaggregation of Revenue [Line Items]
Number of members	0
Non-Utility Members
Disaggregation of Revenue [Line Items]
Number of members	3

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PRESENTATION OF FINANCIAL INFORMATION - Jointly Owned Facilities (Details) $ in Thousands	Jun. 30, 2022 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Electric Plant in Service	$ 917,899
Accumulated Depreciation	597,530
Construction Work In Progress	$ 4,459
Yampa Project - Craig Generating Station Units 1 and 2
Jointly Owned Utility Plant Interests [Line Items]
Tri-State Share (as a percent)	24.00%
Electric Plant in Service	$ 391,913
Accumulated Depreciation	258,163
Construction Work In Progress	$ 291
MBPP - Laramie River Station
Jointly Owned Utility Plant Interests [Line Items]
Tri-State Share (as a percent)	28.50%
Electric Plant in Service	$ 525,986
Accumulated Depreciation	339,367
Construction Work In Progress	$ 4,168

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ACCOUNTING FOR RATE REGULATION (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended			6 Months Ended
	Oct. 31, 2017	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Regulatory Asset and Liability [Line Items]
Regulatory assets		$ 674,378			$ 674,378		$ 665,693
Regulatory liabilities		120,436			120,436		146,021
Net regulatory asset		553,942			553,942		519,672
Rate stabilization
Regulatory Asset and Liability [Line Items]
Revenue from contract with customer		17,462		$ 19,957	25,345	$ 40,790
Interest rate swaps, realized gain
Regulatory Asset and Liability [Line Items]
Regulatory liabilities		2,577			2,577		2,818
Proceeds from settlement of interest rate swaps	$ 4,600
Deferred membership withdrawal income
Regulatory Asset and Liability [Line Items]
Regulatory liabilities		117,859			117,859		143,203
Deferred non-member electric sales | Rate stabilization
Regulatory Asset and Liability [Line Items]
Revenue from contract with customer					$ 25,300
Rifle Generating Station
Regulatory Asset and Liability [Line Items]
Impairment loss			$ 3,700
First Mortgage Obligations, Series 2017A , Tranche 1, 3.34%, due through 2029
Regulatory Asset and Liability [Line Items]
Term of issuance					12 years
Deferred income tax expense
Regulatory Asset and Liability [Line Items]
Regulatory assets		18,742			$ 18,742		18,742
Deferred prepaid lease expense | Springerville Unit 3 Lease
Regulatory Asset and Liability [Line Items]
Regulatory assets		77,988			77,988		79,133
Annual amortization expense					$ 2,300
Amortization period					47 years
Goodwill | J.M. Shafer
Regulatory Asset and Liability [Line Items]
Regulatory assets		42,023			$ 42,023		43,447
Annual amortization expense					$ 2,800
Amortization period					25 years
Goodwill | Colowyo Coal
Regulatory Asset and Liability [Line Items]
Regulatory assets		34,611			$ 34,611		35,128
Annual amortization expense					$ 1,000
Amortization period					44 years
Deferred debt prepayment transaction costs
Regulatory Asset and Liability [Line Items]
Regulatory assets		119,360			$ 119,360		123,674
Annual amortization expense					$ 8,600
Amortization period					21 years 4 months 24 days
Deferred impairment loss | Unrecovered Plants
Regulatory Asset and Liability [Line Items]
Regulatory assets		299,847			$ 299,847		281,424
Deferred impairment loss | Holcomb Expansion
Regulatory Asset and Liability [Line Items]
Annual amortization expense					7,700
Deferred impairment loss | Escalante Generating Station
Regulatory Asset and Liability [Line Items]
Annual amortization expense					12,300
Deferred impairment loss | Holcomb Expansion
Regulatory Asset and Liability [Line Items]
Regulatory assets		$ 81,807			81,807		$ 84,145
Annual amortization expense					$ 4,700
Amortization period					20 years

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INVESTMENTS IN OTHER ASSOCIATIONS (Details) - USD ($)	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	$ 164,259,000		$ 163,097,000
Impairment during the period	0	$ 0
Basin Electric Power Cooperative
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	116,826,000		116,826,000
National Rural Utilities Cooperative Finance Corporation - patronage capital
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	12,076,000		12,076,000
National Rural Utilities Cooperative Finance Corporation - capital term certificates
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	15,074,000		15,149,000
CoBank, ACB
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	14,328,000		12,985,000
Other
Equity Securities without Readily Determinable Fair Value [Line Items]
Investments in other associations	$ 5,955,000		$ 6,061,000

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CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021	Jun. 30, 2021	Dec. 31, 2020
Cash, cash equivalents, restricted cash and investments
Cash and cash equivalents	$ 96,841	$ 100,555
Restricted cash and investments - current	663	480
Restricted cash and investments - noncurrent	3,746	4,101
Cash, cash equivalents and restricted cash and investments	$ 101,250	$ 105,136	$ 119,203	$ 132,074

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CONTRACT ASSETS AND CONTRACT LIABILITIES (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Accounts receivable
Accounts receivable - Utility Members	$ 111,571	$ 95,630
Other accounts receivable - trade:	25,563	21,571
Contract liabilities
Contract liabilities (unearned revenue)	5,207	5,372
Other accounts receivable - trade
Accounts receivable
Other accounts receivable - trade:	18,579	19,189
Other accounts receivable - trade | Non-member electric sales
Accounts receivable
Other accounts receivable - trade:	10,133	5,684
Other accounts receivable - trade | Other
Accounts receivable
Other accounts receivable - trade:	8,446	13,505
Other accounts receivable - nontrade
Accounts receivable
Other accounts receivable - trade:	6,984	$ 2,382
Other operating revenue
Contract liabilities
Contract liabilities recognized	$ 700

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OTHER DEFERRED CHARGES (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Deferred Costs [Abstract]
Preliminary surveys and investigations	$ 12,743	$ 12,366
Advances to operating agents of jointly owned facilities	7,556	4,422
Operating lease right-of-use assets	6,997	7,529
Other	13,741	10,822
Total other deferred charges	$ 41,037	$ 35,139

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LONG-TERM DEBT - Narrative (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2022 USD ($) note	Mar. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Debt Instrument [Line Items]
Long-term debt	$ 2,896,050		$ 3,101,870
Number of unsecured debt instruments | note	1
Unsecured notes	$ 8,100
Current maturities of long-term debt	$ 201,575		$ 93,039
Minimum
Debt Instrument [Line Items]
Equity to capitalization ratio (ECR) requirement (as a percent)	18.00%
Debt service ratio (DSR) requirement	1.10
First Mortgage Bonds, Series 2014E-1
Debt Instrument [Line Items]
Current maturities of long-term debt	$ 100,000
Springerville certificates, Series B, 7.14%, due through 2033
Debt Instrument [Line Items]
Debt service ratio (DSR) requirement	1.02
2022 Revolving Credit Agreement
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 520,000
Available borrowing capacity	$ 340,000
2022 Revolving Credit Agreement | Commercial Paper
Debt Instrument [Line Items]
Available borrowing capacity	$ 320,000
Swingline
Debt Instrument [Line Items]
Maximum borrowing capacity		125,000
Letter of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity		75,000
Commercial Paper
Debt Instrument [Line Items]
Maximum borrowing capacity		$ 500,000

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LONG-TERM DEBT - Summary (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Long-term debt, components
Total debt	$ 3,117,011	$ 3,214,427
Less debt issuance costs	(22,684)	(23,110)
Less debt discounts	(9,118)	(9,398)
Plus debt premiums	12,416	12,990
Total debt adjusted for debt issuance costs, discounts and premiums	3,097,625	3,194,909
Less current maturities	(201,575)	(93,039)
Long-term debt	$ 2,896,050	$ 3,101,870

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SHORT-TERM BORROWINGS (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Short-Term Debt [Line Items]
Commercial paper outstanding, net of discounts	$ 179,699	$ 49,997
2022 Revolving Credit Agreement
Short-Term Debt [Line Items]
Available borrowing capacity	340,000
Commercial Paper | 2018 Revolving Credit Agreement
Short-Term Debt [Line Items]
Commercial paper outstanding, net of discounts		$ 49,997
Weighted average interest rate (as a percent)		0.19%
Commercial Paper | 2022 Revolving Credit Agreement
Short-Term Debt [Line Items]
Maximum amount per commercial paper sublimit	500,000
Commercial paper outstanding, net of discounts	$ 179,699
Weighted average interest rate (as a percent)	1.86%
Available borrowing capacity	$ 320,000

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ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS - Narrative (Details) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2022 USD ($)	Jun. 30, 2022 USD ($) pit
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies [Line Items]
Discount rate of environmental reclamation obligations (as a percent)	3.25%	3.25%
Additional asset retirement obligations recorded	$ 40.6
Colowyo Mine
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies [Line Items]
Number of mine pits in final reclamation | pit		1
New Horizon Mine
Asset Retirement Obligation And Accrual For Environmental Loss Contingencies [Line Items]
Increase in environmental reclamation obligations	44.9
Environmental reclamation obligations	67.3	$ 67.3
Discounted basis of environmental reclamation obligation	36.8	36.8
Undiscounted future cash outflows of environmental reclamation obligations	$ 57.9	$ 57.9

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ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS - Summary (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Asset Retirement Obligation and Accrual for Environmental Loss Contingencies [Roll Forward]
Obligations at beginning of period	$ 90,281
Liabilities settled	(3,889)
Accretion expense	1,448
Change in estimate	85,477
Total obligations at end of period	173,317
Less current obligations at end of period	(4,953)
Long-term obligations at end of period	$ 168,364	$ 83,278

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OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Jun. 30, 2022	Dec. 31, 2021
Deferred credits and other liabilities
Transmission easements		$ 18,857	$ 19,339
Operating lease liabilities - noncurrent		1,403	1,622
Contract liabilities (unearned revenue) - noncurrent		3,351	3,523
Customer deposits		8,632	9,287
Financial liabilities - reclamation		11,756	13,122
OATT deposits		24,520	24,327
Other		7,242	7,099
Total other deferred credits and other liabilities		75,761	78,319
Transmission Right of Way Easements
Deferred credits and other liabilities
Total due for easement right of way	$ 27,800
Transmission Right of Way Easements | Other Deferred Credits and Other Liabilities
Deferred credits and other liabilities
Transmission easements		$ 18,900	$ 19,300

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EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other Than Pensions, Obligations (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2022 USD ($) plan
Medical Benefit Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Total postretirement and postemployment medical obligations at end of period	$ 2,895
Postretirement Medical Benefit Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Postretirement medical benefit obligation at beginning of period	2,809
Service cost	0
Interest cost	18
Benefit payments (net of contributions by participants)	(324)
Total postretirement and postemployment medical obligations at end of period	$ 2,503
Threshold of unrecognized amount of actuarial gains and losses as a proportion of projected benefit obligation (as a percent)	10.00%
Postemployment Medical Benefit Plans
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Total postretirement and postemployment medical obligations at end of period	$ 392
Non-bargaining unit employees | Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3
Non-bargaining unit employees | Medical Benefit Plans | Maximum
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Qualifying age	65 years
Non-bargaining unit employees | Postretirement Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	2
Non-bargaining unit employees | Postretirement Medical Benefit Plans | Minimum
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Qualifying age	55 years
Non-bargaining unit employees | Postemployment Medical Benefit Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3

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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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Roll Forward]
Accumulated other comprehensive income at beginning of period			$ 3,580
Amortization of prior service credit into other income	$ (535)	$ (20)	(1,070)	$ (40)
Accumulated other comprehensive income at end of period	$ 2,510		$ 2,510

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EMPLOYEE BENEFIT PLANS - NRECA Executive Benefit Restoration Plan, Obligations (Details) - Executive Benefit Restoration Plan $ in Thousands	6 Months Ended
	Jun. 30, 2022 USD ($)
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Postretirement medical benefit obligation at beginning of period	$ 9,852
Service cost	185
Interest cost	104
Benefit payments	(111)
Total postretirement and postemployment medical obligations at end of period	10,030
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets at beginning of period	8,640
Employer contributions	303
Actual return on plan assets	(192)
Fair value of plan assets at end of period	8,751
Net liability recognized at end of period	$ 1,279
Threshold of unrecognized amount of actuarial gains and losses as a proportion of projected benefit obligation (as a percent)	10.00%

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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, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Accumulated Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Net of Tax [Roll Forward]
Accumulated other comprehensive income at beginning of period			$ (4,932)
Amortization of prior service credit into other income	$ 283	$ 239	566	$ 459
Accumulated other comprehensive income at end of period	$ (4,366)		$ (4,366)

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REVENUE - Narrative (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2022 USD ($) utility_member billing_component demand_rate	Jun. 30, 2021 USD ($)
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 | $	$ 17,462	$ 19,957	$ 25,345	$ 40,790
Member Contracts Extending Through 2050
Disaggregation of Revenue [Line Items]
Number of contracts | utility_member			42

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REVENUE - Summary (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Revenue [Line Items]
Other	$ 13,718	$ 15,712	$ 25,846	$ 30,712
Total non-member electric sales and other operating revenue	351,962	326,302	677,164	652,274
Total non-member electric sales and other operating revenue
Disaggregation of Revenue [Line Items]
Total non-member electric sales and other operating revenue	65,394	51,857	108,349	105,031
Non-member electric sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	34,214	16,188	57,158	33,529
Non-member electric sales | Long-term contracts
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	12,970	10,093	25,250	18,799
Non-member electric sales | Short-term contracts
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	21,244	6,095	31,908	14,730
Rate stabilization
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	17,462	19,957	25,345	40,790
Other
Disaggregation of Revenue [Line Items]
Other	$ 13,718	$ 15,712	$ 25,846	$ 30,712

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INCOME TAXES (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ 19,000	$ 110,000	$ 37,000	$ 219,000

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LEASES - Leasing Arrangements as Lessee (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2022 USD ($) arrangement	Jun. 30, 2021 USD ($)
Leases [Abstract]
Operating lease expense | $	$ 0.7	$ 0.9	$ 1.5	$ 1.9
Number of finance leases | arrangement			0

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LEASES - Lease Components (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Leases [Abstract]
Operating lease right-of-use assets	$ 8,936	$ 9,081
Less: Accumulated amortization	(1,939)	(1,552)
Net operating lease right-of-use assets	6,997	7,529
Operating lease liabilities - current	(401)	(491)
Operating lease liabilities - noncurrent	(1,403)	(1,622)
Total operating lease liabilities	$ (1,804)	$ (2,113)
Weighted average remaining lease term (years)	7 years 6 months	7 years 7 months 6 days
Weighted average discount rate (as a percent)	3.82%	3.79%
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	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

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LEASES - Future Minimum Lease Commitments (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Future expected minimum lease commitments under operating leases
Year 1	$ 290
Year 2	385
Year 3	278
Year 4	482
Year 5	94
Thereafter	596
Total lease payments	2,125
Less imputed interest	(321)
Total	$ 1,804	$ 2,113

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LEASES - Leasing Arrangements as Lessor (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Leases [Abstract]
Lease revenue	$ 1.8	$ 1.7	$ 3.5	$ 3.5

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FAIR VALUE (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash and cash equivalents	$ 67,700	$ 95,300
Cost
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	3,117,011	3,214,427
Cost | EBT Trust Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	9,407	8,850
Cost | Director and Executive Elective Deferred Compensation Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	550	597
Estimated Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total long-term debt	3,017,268	3,759,991
Estimated Fair Value | EBT Trust Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	8,751	8,640
Estimated Fair Value | Director and Executive Elective Deferred Compensation Investments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Marketable securities	$ 481	$ 598

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VARIABLE INTEREST ENTITIES - Consolidated Entities (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Consolidated Variable Interest Entities
Net electric plant	$ 3,352,991		$ 3,352,991		$ 3,347,171
Noncontrolling interest	122,894		122,894		119,100
Long-term debt	2,896,050		2,896,050		3,101,870
Accrued interest	24,230		24,230		25,716
Interest	34,912	$ 35,088	70,198	$ 70,229
Variable Interest Entity, Primary Beneficiary | Reportable Legal Entities
Consolidated Variable Interest Entities
Net electric plant	731,066		731,066		740,135
Noncontrolling interest	122,896		122,896		119,100
Long-term debt	255,354		255,354		300,220
Accrued interest	7,400		7,400		$ 8,721
Depreciation, amortization and depletion	4,535	4,535	9,069	9,069
Interest	$ 3,958	$ 4,956	$ 8,662	$ 10,141
Variable Interest Entity, Primary Beneficiary | Springerville Unit 3 Lease
Consolidated Variable Interest Entities
Percentage of financial and other support provided			100.00%
Springerville Partnership
Consolidated Variable Interest Entities
Equity interest			51.00%
General partner interest			1.00%
Springerville Partnership | Other Limited Partners
Consolidated Variable Interest Entities
Ownership interest held by noncontrolling interest	49.00%		49.00%
Springerville Unit 3 Holding LLC | Variable Interest Entity, Primary Beneficiary
Consolidated Variable Interest Entities
Ownership interest held by parent	100.00%		100.00%

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LEGAL (Details)		3 Months Ended	12 Months Ended		24 Months Ended
	Sep. 24, 2021 USD ($)	Jun. 30, 2022 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Mar. 01, 2022	Mar. 01, 2021	Aug. 31, 2020 $ / MWh
Other legal
Rate reduction due to settlement (as a percent)						4.00%	2.00%
Soft-cap price for short term spot market sales (per megawatt hour) | $ / MWh								1,000
Funds in excess of soft-cap		$ 2,900,000
Energy sales refunded to third party		$ 383,760
TransAmerican Power Products
Other legal
Damages sought	$ 3,000,000
United Power's Adams District Court
Other legal
Damages sought					$ 87,000,000
United Power's Adams District Court | Forecast
Other legal
Damages sought			$ 43,000,000	$ 41,000,000