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, 2021

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 x (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. The registrant has filed all Exchange Act reports for the preceding 12 months (or for such shorter period that the registrant was required to file such reports)).

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 o

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 o Accelerated filer o

Non-accelerated Filer x 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. o

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

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, 2021

		Page Number
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Financial Position as of June 30, 2021 (unaudited) and December 31, 2020	1
	Consolidated Statements of Operations — Three and Six Months Ended June 30, 2021 and 2020 (unaudited)	2
	Consolidated Statements of Comprehensive Income — Three and Six Months Ended June 30, 2021 and 2020 (unaudited)	3
	Consolidated Statements of Equity — Three and Six Months Ended June 30, 2021 and 2020 (unaudited)	4
	Consolidated Statements of Cash Flows — Six Months Ended June 30, 2021 and 2020 (unaudited)	5
	Notes to Unaudited Consolidated Financial Statements For the Three and Six Months Ended June 30, 2021 and 2020	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	33
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	33
Item 4.	Mine Safety Disclosures	33
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
Basin	Basin Electric Power Cooperative
Board	Board of Directors
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
COVID-19	coronavirus disease 2019 that was declared a pandemic by the World Health Organization in March 2020
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)
DMEA	Delta-Montrose Electric Association
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 Wells Fargo Bank, National Association, as 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
Revolving Credit Agreement	Credit Agreement, dated as of April 25, 2018, between us and CFC, as administrative agent
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
Tri-State, We, Our, Us, the Association	Tri-State Generation and Transmission Association, Inc.
United Power	United Power, Inc.
Utility Members	our electric distribution member systems, consisting of both Class A members and Class B members

ii

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.

iii

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, 2021		December 31, 2020
ASSETS	(unaudited)
Property, plant and equipment
Electric plant
In service	$	6,240,314	$	6,254,652
Construction work in progress	91,093		89,447
Total electric plant	6,331,407		6,344,099
Less allowances for depreciation and amortization	(2,985,644)		(2,991,393)
Net electric plant	3,345,763		3,352,706
Other plant	408,995		456,924
Less allowances for depreciation, amortization and depletion	(153,250)		(133,012)
Net other plant	255,745		323,912
Total property, plant and equipment	3,601,508		3,676,618
Other assets and investments
Investments in other associations	164,223		162,975
Investments in and advances to coal mines	2,437		2,799
Restricted cash and investments	4,366		4,682
Other noncurrent assets	15,987		14,889
Total other assets and investments	187,013		185,345
Current assets
Cash and cash equivalents	114,494		127,187
Restricted cash and investments	343		205
Deposits and advances	35,932		32,012
Accounts receivable—Utility Members	110,126		96,637
Other accounts receivable	25,513		20,570
Electric plant held for sale	—		4,877
Coal inventory	64,963		55,762
Materials and supplies	82,368		82,119
Total current assets	433,739		419,369
Deferred charges
Regulatory assets	688,747		710,268
Prepayment—NRECA Retirement Security Plan	18,803		21,490
Other	41,223		33,646
Total deferred charges	748,773		765,404
Total assets	$	4,971,033	$	5,046,736
EQUITY AND LIABILITIES
Capitalization
Patronage capital equity	$	972,473	$	978,519
Accumulated other comprehensive loss	(6,145)		(5,714)
Noncontrolling interest	115,569		114,851
Total equity	1,081,897		1,087,656
Long-term debt	3,138,826		3,200,181
Total capitalization	4,220,723		4,287,837
Current liabilities
Utility Member advances	19,091		16,592
Accounts payable	117,437		98,654
Short-term borrowings	79,968		—
Accrued expenses	29,588		40,736
Current asset retirement obligations	6,679		11,044
Accrued interest	25,892		27,520
Accrued property taxes	18,155		32,794
Current maturities of long-term debt	75,718		87,587
Total current liabilities	372,528		314,927
Deferred credits and other liabilities
Regulatory liabilities	183,907		224,953
Deferred income tax liability	19,811		19,591
Asset retirement and environmental reclamation obligations	78,362		127,045
Other	76,351		54,600
Total deferred credits and other liabilities	358,431		426,189
Accumulated postretirement benefit and postemployment obligations	19,351		17,783
Total equity and liabilities	$	4,971,033	$	5,046,736

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,
	2021		2020		2021		2020
Operating revenues
Utility Member electric sales	$	274,445	$	286,997	$	547,243	$	579,760
Non-member electric sales	36,145		16,625		74,319		32,438
Other	15,712		10,034		30,712		20,924
	326,302		313,656		652,274		633,122
Operating expenses
Purchased power	86,552		86,653		173,569		157,668
Fuel	45,870		39,549		106,417		100,618
Production	52,841		39,709		93,742		82,897
Transmission	41,948		41,646		86,619		83,186
General and administrative	11,897		16,041		26,484		32,256
Depreciation, amortization and depletion	46,483		44,311		99,238		91,335
Coal mining	966		1,087		2,507		3,821
Other	1,282		3,055		3,833		10,738
	287,839		272,051		592,409		562,519
Operating margins	38,463		41,605		59,865		70,603
Other income
Interest	907		984		1,784		2,289
Capital credits from cooperatives	2		135		4,275		3,488
Other income	1,032		401		1,889		151
	1,941		1,520		7,948		5,928
Interest expense
Interest	36,092		37,993		72,207		76,860
Interest charged during construction	(1,004)		(1,601)		(1,978)		(3,562)
	35,088		36,392		70,229		73,298
Income tax expense (benefit)	110		(121)		219		(330)
Net margins including noncontrolling interest	5,206		6,854		(2,635)		3,563
Net margin attributable to noncontrolling interest	(1,762)		(1,421)		(3,411)		(2,740)
Net margins attributable to the Association	$	3,444	$	5,433	$	(6,046)	$	823

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,
	2021		2020		2021		2020
Net margins including noncontrolling interest	$	5,206	$	6,854	$	(2,635)	$	3,563
Other comprehensive income (loss):
Unrealized loss on securities available for sale	(7)		—		(41)		—
Amortization of actuarial loss on postretirement benefit obligation included in net margin	219		177		731		1,110
Unrecognized prior service cost	—		—		(1,121)		(7,373)
Other comprehensive income (loss)	212		177		(431)		(6,263)
Comprehensive income (loss) including noncontrolling interest	5,418		7,031		(3,066)		(2,700)
Net comprehensive income attributable to noncontrolling interest	(1,762)		(1,421)		(3,411)		(2,740)
Comprehensive income (loss) attributable to the Association	$	3,656	$	5,610	$	(6,477)	$	(5,440)

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,
	2021		2020		2021		2020
Patronage capital equity at beginning of period	$	969,029	$	1,026,453	$	978,519	$	1,031,063
Net margins attributable to the Association	3,444		5,433		(6,046)		823
Retirement of patronage capital	—		(47,665)		—		(47,665)
Patronage capital equity at end of period	972,473		984,221		972,473		984,221
Accumulated other comprehensive loss at beginning of period	(6,357)		(7,958)		(5,714)		(1,518)
Unrealized loss on securities available for sale	(7)		—		(41)		—
Amortization of prior service cost	219		177		731		1,110
Unrecognized prior service cost	—		—		(1,121)		(7,373)
Accumulated other comprehensive loss at end of period	(6,145)		(7,781)		(6,145)		(7,781)
Noncontrolling interest at beginning of period	113,807		111,768		114,851		111,717
Net comprehensive income attributable to noncontrolling interest	1,762		1,421		3,411		2,740
Equity distribution to noncontrolling interest	—		—		(2,693)		(1,268)
Noncontrolling interest at end of period	115,569		113,189		115,569		113,189
Total equity at end of period	$	1,081,897	$	1,089,629	$	1,081,897	$	1,089,629

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,
	2021		2020
Operating activities
Net margins including noncontrolling interest	$	(2,635)	$	3,563
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion	99,238		91,335
Amortization of NRECA Retirement Security Plan prepayment	2,686		2,686
Amortization of debt issuance costs	1,249		1,204
Impairment loss	—		259,761
Deferred impairment loss and other closure costs	—		(268,163)
Recognition of deferred revenue	(40,790)		—
Deferred membership withdrawal income	—		110,165
Deposits associated with generator interconnection requests	17,130		—
Capital credit allocations from cooperatives and income from coal mines under (over) refund distributions	(957)		2,775
Changes in operating assets and liabilities:
Accounts receivable	(19,250)		(3,457)
Coal inventory	(9,202)		(13,914)
Materials and supplies	(249)		256
Accounts payable and accrued expenses	23,681		11,753
Accrued interest	(1,628)		(1,447)
Accrued property taxes	(14,640)		(10,307)
Other	(1,935)		(12,966)
Net cash provided by operating activities	52,698		173,244
Investing activities
Purchases of plant	(52,030)		(68,059)
Sale of electric plant	—		26,000
Changes in deferred charges	(5,325)		(3,007)
Proceeds from other investments	72		68
Net cash used in investing activities	(57,283)		(44,998)
Financing activities
Changes in Member advances	2,499		(2,896)
Payments of long-term debt	(73,946)		(142,792)
Proceeds from issuance of long-term debt	—		425,000
Debt issuance costs	—		(527)
Change in short-term borrowings, net	79,968		(112,520)
Retirement of patronage capital	(13,705)		(60,991)
Equity distribution to noncontrolling interest	(2,693)		(1,268)
Other	(409)		(279)
Net cash provided by (used in) financing activities	(8,286)		103,727
Net increase (decrease) in cash, cash equivalents and restricted cash and investments	(12,871)		231,973
Cash, cash equivalents and restricted cash and investments – beginning	132,074		113,768
Cash, cash equivalents and restricted cash and investments – ending	$	119,203	$	345,741
Supplemental cash flow information:
Cash paid for interest	$	72,904	$	77,787
Cash paid for income taxes	$	—	$	—
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$	397	$	594

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, 2021 and 2020

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, 2020 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, 2021, results of operations for the three and six months ended June 30, 2021 and 2020, and cash flows for the six months ended June 30, 2021 and 2020 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 generation facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common. These projects include the Yampa Project (operated by us) and the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)). Each participant in these agreements receives a portion of the total output of the generation facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and other operating expenses is included in our consolidated financial statements.

Effective as of August 1, 2021, our ownership share in MBPP increased to 28.5 percent due to our acquisition of Wyoming Municipal Power Agency’s ownership share in MBPP. The purchase represents an additional 1.37 percent undivided ownership interest in MBPP, which includes transmission and water rights and approximately 23 megawatts of generation.

6

Our share in each jointly owned facility is as follows as of June 30, 2021 (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	%	$	391,698	$	251,323	$	653
MBPP - Laramie River Station	27.13	%	500,485		318,715		3,096
Total			$	892,183	$	570,038	$	3,749

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, 2021		December 31, 2020
Regulatory assets
Deferred income tax expense (1)	$	19,641	$	19,641
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)	80,278		81,424
Goodwill – J.M. Shafer (3)	44,872		46,296
Goodwill – Colowyo Coal (4)	35,645		36,161
Deferred debt prepayment transaction costs (5)	127,988		132,302
Deferred Holcomb expansion impairment loss (6)	86,482		88,819
Unrecovered plant (7)	293,841		305,625
Total regulatory assets	688,747		710,268
Regulatory liabilities
Interest rate swap - realized gain (8) and other	3,037		3,293
Deferred revenues (9)	22,927		63,717
Deferred membership withdrawal income (10)	157,943		157,943
Total regulatory liabilities	183,907		224,953
Net regulatory asset	$	504,840	$	485,315

(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 Thermo Cogeneration Partnership, LP 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.

7

(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 and Escalante Generating Stations. The deferred impairment loss for Nucla Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 3.3-year period ending in December 2022 and recovered from our Utility Members through rates. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 25-year period ending in December 2045, which was the depreciable life of Escalante Generating Station, and recovered from our Utility Members through rates. The annual amortization approximates the former annual Escalante Generating Station depreciation for the remaining life of the asset.

(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 deferral of the recognition of non-member electric sales revenues. These deferred non-member electric sales revenues will be refunded to Utility Members as part of our rate stabilization measures when recognized in non-member electric sales revenue in future periods.

(10)Represents the deferral of the recognition of other income related to the withdrawal of former Utility Members from membership in us. The total deferred membership withdrawal income will be refunded to Utility Members as part of our rate stabilization measures when recognized in other income in future periods.

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, 2021		December 31, 2020
Basin Electric Power Cooperative	$	118,295	$	118,295
National Rural Utilities Cooperative Finance Corporation - patronage capital	11,933		11,933
National Rural Utilities Cooperative Finance Corporation - capital term certificates	15,149		15,221
CoBank, ACB	12,707		11,141
Other	6,139		6,385
Investments in other associations	$	164,223	$	162,975

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, 2021 or during 2020.

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.

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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, 2021		December 31, 2020
Cash and cash equivalents	$	114,494	$	127,187
Restricted cash and investments - current	343		205
Restricted cash and investments - noncurrent	4,366		4,682
Cash, cash equivalents and restricted cash and investments	$	119,203	$	132,074

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, 2021, 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, 2021		December 31, 2020
Accounts receivable - Utility Members	$	110,126	$	96,637
Other accounts receivable - trade:
Non-member electric sales	7,423		5,231
Other	16,603		9,785
Total other accounts receivable - trade	24,026		15,016
Other accounts receivable - nontrade	1,487		5,554
Total other accounts receivable	$	25,513	$	20,570
Contract liabilities (unearned revenue)	$	5,598	$	6,025

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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, 2021		December 31, 2020
Preliminary surveys and investigations	$	12,188	$	12,886
Advances to operating agents of jointly owned facilities	6,507		2,071
Operating lease right-of-use assets	7,688		7,985
Other	14,840		10,704
Total other deferred charges	$	41,223	$	33,646

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 $3.1 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 $15.8 million as of June 30, 2021. 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 $650 million (“Revolving Credit Agreement”) that expires on April 25, 2023 and includes a swingline sublimit of $100 million, a letter of credit sublimit of $75 million, and a commercial paper back-up sublimit of $500 million. As of June 30, 2021, we had $570.0 million in availability under the Revolving Credit Agreement.

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

	June 30, 2021		December 31, 2020
Total debt	$	3,234,768	$	3,308,715
Less debt issuance costs	(24,341)		(25,590)
Less debt discounts	(9,530)		(9,659)
Plus debt premiums	13,647		14,302
Total debt adjusted for debt issuance costs, discounts and premiums	3,214,544		3,287,768
Less current maturities	(75,718)		(87,587)
Long-term debt	$	3,138,826	$	3,200,181

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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 Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our 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, 2021			December 31, 2020
Commercial paper outstanding, net of discounts	$	79,968		$	—
Weighted average interest rate	0.18		%	—		%

At June 30, 2021, $420.0 million of the commercial paper back-up sublimit remained available under the 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. Estimates of future expenditures for environmental reclamation obligations are not discounted.

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 2019 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, 2021
Obligations at beginning of period	$	138,089
Liabilities incurred	—
Liabilities settled	(135)
Accretion expense	1,411
Change in cash flow estimate	(54,324)
Total obligations at end of period	$	85,041
Less current obligations at end of period	(6,679)
Long-term obligations at end of period	$	78,362

In the second quarter of 2021, we recorded a reduction of the Colowyo Mine reclamation liability of $50.0 million. This reduction was primarily related to a change in the mine plan of South Taylor pit at the Colowyo Mine. After obtaining regulatory approval, the South Taylor pit life was extended through 2027 to mine the highwall, which resulted in a lower estimated obligation at the end of the mining period. The West pit is currently in final reclamation. In 2019, we recorded an additional reclamation obligation liability of $22.4 million due to anticipated revision to the New Horizon Mine reclamation plan to accommodate an alternative post mine land use as necessary for final mine reclamation. We continue to evaluate the Colowyo Mine and New Horizon Mine post reclamation obligations and will make adjustments to these obligations as needed.

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

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, 2021		December 31, 2020
Transmission easements	$	19,531	$	19,983
Operating lease liabilities - noncurrent	1,689		1,590
Contract liabilities (unearned revenue) - noncurrent	3,520		3,702
Customer deposits	8,900		7,712
Financial liabilities - reclamation	11,931		12,081
Deposits associated with generator interconnection requests	17,130		—
Other	13,650		9,532
Total other deferred credits and other liabilities	$	76,351	$	54,600

In 2015, we renewed transmission right of way easements on tribal nation lands where certain of our electric transmission lines are located. $29.4 million will be paid by us for these easements from 2021 through the individual easement terms ending between 2036 and 2040. The present values for the remaining easement payments were $19.5 and $20.0 million as of June 30, 2021 and December 31, 2020, 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.

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 postemployment medical benefits to employees on long-term disability. The plans were unfunded at June 30, 2021, 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 postemployment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands):

	Six Months Ended June 30, 2021
Postretirement medical benefit obligation at beginning of period	$	9,985
Service cost	301
Interest cost	129
Benefit payments (net of contributions by participants)	(296)
Postretirement medical benefit obligation at end of period	$	10,119
Postemployment medical benefit obligation at end of period	419
Total postretirement and postemployment medical obligations at end of period	$	10,538

The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations.

In accordance with the accounting standard related to postretirement benefits other than pensions, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other 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, 2021
Accumulated other comprehensive loss at beginning of period	$	(841)
Amortization of prior service credit into other income	(39)
Accumulated other comprehensive loss at end of period	$	(880)

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.

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Eligible employees include the Chief Executive Officer and any other employees that become eligible. All our executive employees currently 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. As of April 30, 2021, the plans ceased to add new participants and no new executives will be eligible for the plan.

The NRECA Executive Benefit Restoration Plan obligations are determined annually (during the first quarter of the subsequent year) by an NRECA actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands):

	Six Months Ended June 30, 2021
Executive benefit restoration obligation at beginning of period	$	7,379
Service cost	204
Interest cost	109
Actuarial loss	1,121
Executive benefit restoration at end of period	$	8,813
Fair value of plan assets at beginning of period	$	6,955
Employer contributions	806
Actual return on plan assets	$	61
Fair value of plan assets at end of period	$	7,822
Net liability recognized	$	991

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, 2021
Accumulated other comprehensive loss at beginning of period	$	(4,873)
Amortization of prior service cost into other income	459
Amortization of actuarial loss	171
Curtailment and settlement	141
Unrecognized actuarial loss	(1,121)
Accumulated other comprehensive loss at end of period	$	(5,223)

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NOTE 12 – REVENUE

Revenue from Contracts with Customers

Our revenues are derived primarily from the sale of electric power 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 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,
	2021		2020		2021		2020
Non-member electric sales:
Long-term contracts	$	10,093	$	11,251	$	18,799	$	23,395
Short-term contracts	6,096		5,374		14,730		9,043
Recognition of deferred revenue	19,956		—		40,790		—
Other	15,712		10,034		30,712		20,924
Total non-member electric sales and other operating revenue	$	51,857	$	26,659	$	105,031	$	53,362

Non-member electric sales

Revenues from 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.

Other operating revenue

Other operating revenue consists primarily of wheeling, transmission, water and coal sales revenue. Other operating revenue also includes revenue we receive from two of 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

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transmission service, and the annual transmission revenue requirement). Water revenue is derived from supplying water resources to a paper manufacturer located adjacent to the Escalante Generating Station (payments from the customer are received in accordance with the contract terms which is less than 15 days from the invoice date). 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 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. Our consolidated statements of operations included an income tax expense of $0.2 million for the six months ended June 30, 2021 and an income tax benefit of $0.3 million for the comparable period in 2020.

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 $0.9 million for the three months ended June 30, 2021 and $0.7 million for the comparable period in 2020. Rent expense for all short-term and long-term operating leases was $1.9 million for the six months ended June 20, 2021 and $1.6 million for the comparable period in 2020. Rent expense is included in operating expenses on our consolidated statements of operations. As of June 30, 2021, 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, 2021			December 31, 2020
Operating leases
Operating lease right-of-use assets	$	9,237		$	9,223
Less: Accumulated amortization	(1,549)			(1,238)
Net operating lease right-of-use assets	$	7,688		$	7,985
Operating lease liabilities - current	$	(464)		$	(526)
Operating lease liabilities - noncurrent	(1,689)			(1,590)
Total operating lease liabilities	$	(2,153)		$	(2,116)
Operating leases
Weighted average remaining lease term (years)	7.7			7.6
Weighted average discount rate	3.75		%	3.84		%

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

Year 1	$	550
Year 2	415
Year 3	374
Year 4	247
Year 5	91
Thereafter	650
Total lease payments	$	2,327
Less imputed interest	(174)
Total	$	2,153

Leasing Arrangements As Lessor

We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $1.7 million and $1.6 million for the three months ended June 30, 2021 and 2020, respectively, and $3.5 million and $3.2 million for the six months ended June 30, 2021 and 2020 respectively, 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 noncontrolling 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.

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, 2021				December 31, 2020
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
EBR Trust investments	$	7,822	$	7,743	$	6,955	$	6,955

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, 2021				December 31, 2020
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	513	$	556	$	491	$	478

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 $105.9 million as of June 30, 2021 and $94.6 million as of December 31, 2020.

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):

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	June 30, 2021				December 31, 2020
	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
Total long-term debt	$	3,234,768	$	3,825,737	$	3,308,715	$	3,908,497

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 and also entities for which we are not the primary beneficiary and therefore do not consolidate.

Consolidated Variable Interest Entity

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

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, 2021		December 31, 2020
Net electric plant	$	749,204	$	758,273
Noncontrolling interest	115,571		114,852
Long-term debt	300,789		342,355
Accrued interest	8,721		9,942

Our consolidated statements of operations include the following Springerville Partnership expenses for the three and six months ended June 30, 2021 and 2020 (dollars in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
Depreciation, amortization and depletion	$	4,535	$	4,535	$	9,069	$	9,069
Interest	4,956		5,651		10,141		11,511

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 noncontrolling 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 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 206 proceedings to determine the justness and reasonableness of our rates and wholesale electric service contracts. FERC also rejected our Board Policy 115 (“BP 115”) and member project contracts related to our Utility Members’ election to provide up to 5 percent of their electric power requirements pursuant to their wholesale electric service contracts on the grounds that the initial filing was incomplete without Board Policy 101 (“BP 101”) related to the self-supply in excess of the 5 percent annual allowance. The tariff rates were referred to an administrative law judges to encourage settlement of material issues and to hold a hearings if settlements is not reached. Any refunds to the applicable tariff rates would only apply for sales after March 26, 2020. On April 30, 2021, we filed a proposed settlement agreement related to our Utility Member stated rate, including BP 115, BP 101, and Board Policy 119 (“BP 119”), with FERC for approval, as further discussed below. The settlement proceedings for our transmission service rates are continuing. FERC’s March 20, 2020 order regarding our Jurisdictional PDO denied our requested declaration regarding the preemption of the United Power and LPEA proceeding at the COPUC stating the proceeding was not currently preempted.

On April 13, 2020, we filed a request for rehearing limited to the issue of preemption of the United Power and LPEA proceeding at the COPUC related to the contract termination payment amount as described in our Jurisdictional PDO. 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 by finding exclusive jurisdiction over our contract termination payments and preempting the jurisdiction of the COPUC as of September 3, 2019.

On July 1, 2020, we re-submitted our BP 101, BP 115, and all existing member project contracts with FERC for acceptance and on August 28, 2020 FERC accepted the filings effective August 31, 2020. FERC also ordered a 206 proceeding to determine whether our July 1 filed documents are just and reasonable and set them for settlement and hearing procedures, which were consolidated with the settlement and hearing procedures in effect for our member rates docket. United Power has 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 acceptance of our July 1 filed documents and such matter is being held in abeyance pending resolution of the Jurisdictional PDO appeal discussed below.

On October 19, 2020, we filed our BP 119 related to our community solar program that provides for our Utility Members to develop community solar projects up to specified annual output limits separate from and in addition to the 5 percent self-supply provision of the wholesale electric service contracts and our first community solar contract with a Utility Member with FERC for acceptance. On December 18, 2020, FERC accepted BP 119 and the community solar contract, to be effective December 19, 2020, subject to refund. FERC referred it to FERC’s hearing and settlement judge procedures, which were consolidated with the settlement and hearing procedures in effect for our member rates docket.

On July 13, 2020, we filed a petition for review with the D.C. Circuit Court of Appeals to protect our interest, and requested review of FERC’s order granting in part and denying in part our Jurisdictional PDO and FERC’s order granting rehearings for further consideration. Petitions for review related to both the Jurisdictional PDO and tariff filings have been filed with the D.C. Circuit Court of Appeals by other parties, including United Power. On September 18, 2020, FERC filed to hold the appeals in abeyance. On September 29, 2020, an order was issued considering the motion to hold the case in abeyance, directing the parties to file motions to govern future proceedings by January 11, 2021. FERC, United Power, and the other parties reached agreement on the procedures and schedule for the Jurisdictional PDO and abeyance on all non-Jurisdictional PDO matters and such filing was made to the D.C. Circuit Court of Appeals. On June 7, 2021, United Power filed its brief with the D.C. Circuit Court of Appeals regarding the Jurisdictional PDO.

On April 30, 2021, we filed a proposed settlement agreement related to our Utility Member stated rate, including our wholesale electric service contracts, BP 115, BP 101, and BP 119, with FERC for approval. With the exception of four reserved issues

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contingent on United Power being a settling party, the settlement resolves 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 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 will establish 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. On June 30, 2021, the Chief Judge terminated the settlement judge procedures for our member rates docket. On August 2, 2021, FERC approved this settlement agreement and we will file a motion with FERC to set a procedure schedule for the four reserved issues.

It is not possible to predict if FERC will require us to refund amounts to our customers for sales after March 26, 2020 on outstanding issues, if settlements will be reached without a hearing on our transmission service rates and tariff, or the outcome of the four reserved issues related to our member rates docket. In addition, we cannot predict the outcome of the 206 proceedings or 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 proceeding 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 asserting 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 November 25, 2020, LPEA and United Power jointly filed an application for rehearing, reargument, and reconsideration with the COPUC of its October 22, 2020 decision. The COPUC denied LPEA's and United Power's November 25 application. 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. It is not possible to predict the outcome in this matter.

United Power's Adams District Court Complaints: 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 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, the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are also void, that we have breached the wholesale electric service contract with United Power, and that we and our three Non-Utility Members conspired to deprive the COPUC of jurisdiction over the contract termination payment of our Colorado Utility Members. On June 20, 2020, we filed our answer denying United Power’s allegations and request for relief, and asked the court to dismiss United Power’s claims. We asserted counterclaims against United Power, and are seeking relief from United Power’s breach of our Bylaws and declaratory judgement that the April 2019 Bylaws amendment and the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are valid. On June 20, 2020, the three Non-Utility Members filed a joint motion to dismiss. On December 10, 2020, the Non-Utility Members motion to dismiss was granted. On December 23, 2020, United Power sought to amend its May 2020 compliant to add LPEA as an additional plaintiff and to add the claims from its November 2020 complaint, discussed below, into its amended complaint and to dismiss the November 2020 complaint against us. 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 and to amend its claims as to our three Non-Utility Members. On July 30, 2021, we filed a partial motion to dismiss a majority of United Power's and LPEA's claims, including

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claims related to the April 2019 Bylaws amendment, the April 2020 Board approvals, and that we conspired with our Non-Utility Members. 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. It is not possible to predict the outcome of this matter or whether we will incur any liability in connection with this matter.

In addition, on November 23, 2020, United Power filed a Complaint for Declaratory Relief in the Adams County District Court, 2020CV031496, against us seeking for the court to declare that our addition of the Non-Utility Members violated Colorado law. On December 11, 2020, we moved to dismiss United Power's November 2020 compliant because it repeats the claims pending in the May 2020 complaint proceeding. On July 21, 2021, United Power filed a notice of voluntary dismissal without prejudice of its November 2020 complaint. On July 22, 2021, the court entered in order granting United Power’s request to dismiss the November 2020 case without prejudice.

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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, have tolling arrangements or long-term purchase contracts with respect to, various generating facilities. Our diverse generation portfolio provides us with maximum available power of 4,197 MWs, of which approximately 1,166 MWs comes from renewables. In April 2021, the 104 MW Crossing Trails Wind Farm achieved commercial operation and we began purchasing energy pursuant to a fifteen year power purchase agreement. In 2020, we estimate that nearly a third of the energy delivered by us and our Utility Members to our Utility Members’ customers came from non-carbon emitting resources.

We sold 8.0 million MWhs for the six months ended June 30, 2021, of which 92.2 percent was to Utility Members. Total revenue from electric sales was $621.6 million for the six months ended June 30, 2021 of which 88.0 percent was from Utility Member sales. Our results for the six months ended June 30, 2021 were primarily impacted by seasonal weather changes, including record cold winter weather in February, and rate stabilization measures.

•Utility Member electric sales decreased $32.5 million, or 5.6 percent, primarily due to reduced membership and a rate reduction in our Utility Member stated rate.

•Non-member electric sales increased $41.9 million, or 129.1 percent, primarily due to rate stabilization measures. In order to better align with our financial goals, we have begun to recognize deferred revenue on a quarterly basis when it is reasonably estimable that recognition is required to meet our financial goals during 2021.

•Purchased power expense increased $15.9 million, or 10.1 percent, primarily due to decreased generation from our generating resources because of maintenance activities and favorable market conditions for purchasing power.

•Depreciation, amortization and depletion expense increased $7.9 million, or 8.7 percent, primarily due to revisions to asset retirement obligations related to the South Taylor pit at the Colowyo Mine during the prior year.

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, 2021, 20 Utility Members have enrolled in this program with capacity totaling approximately 138 MWs of which 126 MWs are in operation.

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

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payment methodology, and a “Make-Whole” methodology for a contract termination payment. Each of these items recommended by the contract committee representing our Utility Members were filed with FERC for approval in 2020. FERC accepted each of these items, subject to refund, and referred them to FERC's hearing and settlement judge procedures. During our first "open season" partial requirements nomination period that was completed in May 2021, three Utility Members submitted nominations for an aggregate of 209 MWs of self-supply out of an available pool of 300 MWs. For further information see “Item 1 – BUSINESS – MEMBERS – Contract Committee” in our annual report on Form 10-K for the year ended December 31, 2020.

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. In April 2020, the Board approved a “Make-Whole” methodology for a contract termination payment designed to leave remaining Utility Members in the same economic position after a Utility Member terminates its wholesale electric service contract as the remaining Utility Members would have been had the Utility Member not terminated. In April 2020, we filed with FERC the Board approved contract termination payment methodology. In June 2020, FERC accepted our contract termination payment methodology and referred it to FERC’s hearing and settlement judge procedures. In late 2020, certain Utility Members formally requested a contract termination payment amount for planning purposes. In January 2021, we notified each of these Utility Members that the contract termination payment calculation is time-intensive and complex and that we were working on a contract termination procedure to be filed with FERC. In late February 2021, seven of our Utility Members filed a complaint with FERC seeking the contract termination payment amount on an expedited basis. In March 2021, we filed a motion to dismiss and answer. In March 2021, our Board approved a contract termination procedures Board policy that was filed with FERC for approval. In May 2021, FERC rejected our proposed contract termination procedures Board policy. In June 2021, FERC issued a show cause order to us regarding our contract termination payment calculation and specifically regarding procedures for our Utility Members to obtain such calculations prior to making their termination decision. A number of our Utility Members and other parties have intervened in such matter. In July 2021, we filed our response to the show cause order and described a plan to file a simpler and more transparent modified contract termination methodology approved by our Board by September 1, 2021. The modified methodology eliminates our Board discretion over a Utility Member's withdrawal and provides a clear procedure and direct path to obtain a calculation without any delay or fees. The modified methodology continues to protect the financial interests of our remaining Utility Members if a Utility Member elects to withdraw. Our July 2021 filing also included the contract termination payment amount for each of our Utility Members under the modified contract termination methodology assuming a January 1, 2024 withdraw date. No Utility Member has requested to terminate its wholesale electric service contract with us or to withdraw from membership.

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 the wholesale electric service contract with United Power. In November 2020, United Power filed a complaint for declaratory relief against us seeking for the court to declare that our addition of the Non-Utility Members violated Colorado law. In December 2020, United Power sought to amend its May 2020 compliant to add LPEA as an additional plaintiff and to add the claims from its November 2020 complaint into its amended complaint and to dismiss the November 2020 complaint against us. In July 2021, the court granted United Power's motion to amend its May 2020 complaint and to add LPEA as an additional plaintiff. In July 2021, we filed a partial motion to dismiss the amended May 2020 complaint. In July 2021, United Power's November 2020 complaint was voluntarily dismissed by United Power. See Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for further information.

Responsible Energy Plan

In January 2020, we announced our Responsible Energy Plan, which will advance our clean energy transition. 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.

As part of our Responsible Energy Plan, in January 2020, we announced the early retirements of Craig Station by 2030 and Escalante Station by the end of 2020. In connection with such early retirements, our Board continues to evaluate the creation of additional regulatory assets and use of regulatory liabilities to achieve the goal to lower wholesale rates to our Utility Members. A creation of regulatory assets to defer expenses associated with these early retirements or the utilization of regulatory liabilities would require FERC approval.

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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, 2020.

COVID-19 Impacts

The COVID-19 pandemic has adversely impacted economic activity and conditions worldwide, including workforces, liquidity, capital markets, consumer behavior, supply chains, and macroeconomic conditions.

We have experienced changes in the load patterns of our Utility Members and decreased sales to our Utility Members and Utility Member revenue due to disruptions of operations from our Utility Members' commercial customers. We continue to monitor the impacts of COVID-19. The extent to which the COVID-19 pandemic may continue to impact our results of operations, including the long-term nature of the impacts, depends on numerous evolving factors, which are highly uncertain and difficult to predict, including the adoption rate of the COVID-19 vaccines, the impact of the delta variant, the scope and the timing to further contain the virus or treat its impact, and to what extent normal economic and operating conditions can resume, among others. We currently believe that we have sufficient liquidity to meet our anticipated capital and operating requirements. It is possible that actual, perceived or projected negative impacts to our business or Utility Members’ businesses from the impacts of COVID-19 could be the impetus for negative rating action by credit rating agencies.

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, 2021, 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, 2020.

Factors Affecting Results

Master Indenture

As of June 30, 2021, 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

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from year to year. This policy, subject to change by our Board, sets a DSR goal of 1.190 for the twelve months ended December 31, 2021 and a ECR goal of 23.5 percent as of December 31, 2021.

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 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. The tariff rates were referred to an administrative law judge to encourage settlement of material issues and to hold a hearing if settlement is not reached. 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 current rates) thereafter 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 electric power sales to our Utility Members and non-member purchasers. Revenues from 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 2020 and 2021, 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 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.

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.

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Results of Operations

General

Our electric sales revenues are derived from electric power 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.

Three months ended June 30, 2021 compared to three months ended June 30, 2020

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, water and coal sales. Other operating revenue also includes revenue we receive from two 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, 2021 and 2020 (dollars in thousands):

	Three Months Ended June 30,				Period-to-period Change
	2021		2020		Amount		Percent
Operating revenues
Utility Member electric sales	$	274,445	$	286,997	$	(12,552)	(4.4)	%
Non-member electric sales	36,145		16,625		19,520		117.4	%
Other	15,712		10,034		5,678		56.6	%
Total operating revenues	$	326,302	$	313,656	$	12,646	4.0	%
Energy sales (in MWh):
Utility Member electric sales	3,661,010		3,725,077		(64,067)		(1.7)	%
Non-member electric sales	368,944		337,334		31,610		9.4	%
	4,029,954		4,062,411		(32,457)		(0.8)	%

•Utility Member electric sales decreased, in terms of MWhs sold, primarily due to the withdrawal of DMEA in June 2020. DMEA represented 2.9 percent of Utility Member revenue during the three months ended June 30, 2020. The decrease in Utility Member electric sales revenue caused by lower sales volume was slightly compounded by a 2.7 percent lower average price during the three months ended June 30, 2021 when compared to the same period in 2020. The decrease in average price was primarily due to a two percent settlement rate reduction effective as of March 1, 2021. See Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for further information.

•Non-member electric sales increased primarily due to rate stabilization measures. In accordance with our Board Policy for Financial Goals and Capital Credits, we recognized $20.0 million of previously deferred revenue during the three months ended June 30, 2021 compared to none during the same period in 2020. In order to better align with our financial goals, we have begun to recognize deferred revenue on a quarterly basis when it is reasonably estimable that

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recognition is required to meet our financial goals during 2021. We expect to recognize additional previously deferred revenue during the remainder of 2021 in order to meet our financial goals.

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.

The following is a summary of the components of our operating expenses for the three months ended June 30, 2021 and 2020 (dollars in thousands):

	Three Months Ended June 30,				Period-to-period Change
	2021		2020		Amount		Percent
Operating expenses
Purchased power	$	86,552	$	86,653	$	(101)	(0.1)	%
Fuel	45,870		39,549		6,321		16.0	%
Production	52,841		39,709		13,132		33.1	%
Transmission	41,948		41,646		302		0.7	%
General and administrative	11,897		16,041		(4,144)		(25.8)	%
Depreciation, amortization and depletion	46,483		44,311		2,172		4.9	%
Coal mining	966		1,087		(121)		(11.1)	%
Other	1,282		3,055		(1,773)		(58.0)	%
Total operating expenses	$	287,839	$	272,051	$	15,788	5.8	%

•Fuel expense increased primarily due to increased generation at our combined-cycle and simple-cycle combustion generating stations as well as increased natural gas prices. Generation increased 17.1 percent at our combined-cycle and simple-cycle combustion generating stations during the three months ended June 30, 2021 compared to the same period in 2020. Natural gas costs at these generating stations increased $4.6 million, or 136.3 percent, during the same period.

•Production expense increased primarily due to the performance during the three months ended June 30, 2021 of scheduled maintenance postponed during the prior year as a result of COVID-19. Maintenance expense increased $14.0 million, or 88.2 percent, during the three months ended June 30, 2021 compared to the same period in 2020.

Six months ended June 30, 2021 compared to six months ended June 30, 2020

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, 2021 and 2020 (dollars in thousands):

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	Six Months Ended June 30,				Period-to-period Change
	2021		2020		Amount		Percent
Operating revenues
Utility Member electric sales	$	547,243	$	579,760	$	(32,517)	(5.6)	%
Non-member electric sales	74,319		32,438		41,881		129.1	%
Other	30,712		20,924		9,788		46.8	%
Total operating revenues	$	652,274	$	633,122	$	19,152	3.0	%
Energy sales (in MWh):
Utility Member electric sales	7,369,142		7,734,868		(365,726)		(4.7)	%
Non-member electric sales	619,010		644,011		(25,001)		(3.9)	%
	7,988,152		8,378,879		(390,727)		(4.7)	%

•Utility Member electric sales decreased, in terms of MWhs sold, primarily due to the withdrawal of DMEA in June 2020 and continued economic impacts of COVID-19 during the year, in particular, from our Utility Members’ commercial customers. DMEA represented 3.4 percent of Utility Member revenue during the six months ended June 30, 2020. The decrease in Utility Member electric sales revenue caused by lower sales volume was slightly compounded by a 0.9 percent lower average price during the six months ended June 30, 2021 when compared to the same period in 2020. The decrease in average price was primarily due to a two percent settlement rate reduction effective as of March 1, 2021. See Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for further information.

•Non-member electric sales increased primarily due to rate stabilization measures. In accordance with our Board Policy for Financial Goals and Capital Credits, we recognized $40.8 million of previously deferred revenue during the six months ended June 30, 2021 compared to none during the same period in 2020.

Operating Expenses

The following is a summary of the components of our operating expenses for the six months ended June 30, 2021 and 2020 (dollars in thousands):

	Six Months Ended June 30,				Period-to-period Change
	2021		2020		Amount		Percent
Operating expenses
Purchased power	$	173,569	$	157,668	$	15,901	10.1	%
Fuel	106,417		100,618		5,799		5.8	%
Production	93,742		82,897		10,845		13.1	%
Transmission	86,619		83,186		3,433		4.1	%
General and administrative	26,484		32,256		(5,772)		(17.9)	%
Depreciation, amortization and depletion	99,238		91,335		7,903		8.7	%
Coal mining	2,507		3,821		(1,314)		(34.4)	%
Other	3,833		10,738		(6,905)		(64.3)	%
Total operating expenses	$	592,409	$	562,519	$	29,890	5.3	%

•Purchased power expense increased primarily due to decreased generation from our generating resources because of scheduled maintenance as well as favorable market conditions for purchasing power during the six months ended June 30, 2021 compared to the same period in 2020. Generation decreased 14.1 percent during the six months ended June 30, 2021 compared to the same period in 2020. Purchased power increased (in MWhs) 8.4 percent for the six months ended June 30, 2021 compared to the same period in 2020. The average price was 1.8 percent higher during the six months ended June 30, 2021 compared to the same period in 2020. As a result of the mid-February extreme weather event, we incurred approximately $4.9 million in energy imbalance charges from other utilities, which is a component of purchased power.

•Production expense increased primarily due to the performance of scheduled maintenance postponed during the prior year as a result of COVID-19. Scheduled maintenance was performed at several generating facilities during the

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six months ended June 30, 2021, resulting in $16.3 million in increased maintenance costs compared to the same period in 2020. Maintenance expenses were slightly offset by a decrease of $5.4 million in general production expenses during the six months ended June 30, 2021 compared to the same period in 2021.

•Depreciation, amortization and depletion expense increased primarily due to revisions to asset retirement obligations related to the South Taylor pit at the Colowyo Mine during the prior year, which began to depreciate during January 2021.

Financial condition as of June 30, 2021 compared to December 31, 2020

The principal changes in our financial condition from December 31, 2020 to June 30, 2021 were due to increases and decreases in the following:

Assets

•Other plant decreased $57.8 million, or 12.4 percent, to $409.0 million as of June 30, 2021 compared to $466.8 million as of December 31, 2020. The decrease was primarily due to a reduction in the asset retirement obligation of $49.1 million in 2021 for the Colowyo Coal South Taylor pit and non-utility asset retirements of $9.7 million.

•Deposits and advances increased $3.9 million, or 12.3 percent, to $35.9 million as of June 30, 2021 compared to $32.0 million as of December 31, 2020. The increase was primarily due to prepayments of annual insurance, memberships and licenses. These prepayments are being amortized to expense over the term of the related insurance, membership or license period.

Liabilities

•Long-term debt decreased $61.4 million, or 1.9 percent, to $3.139 billion as of June 30, 2021 compared to $3.200 billion as of December 31, 2020 and current maturities of long-term debt decreased $11.9 million, or 13.6 percent, to $75.7 million as of June 30, 2021 compared to $87.6 million as of December 31, 2020. The net decrease of $73.3 million was primarily due to debt payments of $73.9 million (principally $41.0 million for the Springerville certificates). In April 2021, we paid off the remaining $22.0 million balance of the First Mortgage Obligations, Series 2009C.

•Regulatory liabilities decreased $41.1 million, or 18.3 percent, to $183.9 million as of June 30, 2021 compared to $225.0 million as of December 31, 2020. The decrease was primarily due to the recognition of $40.8 million of previously deferred non-member electric sales revenues. In order to better align with our financial goals, we have begun to recognize deferred revenue on a quarterly basis when it is reasonably estimable that recognition is required to meet our financial goals during 2021.

•Asset retirement and environmental reclamation obligations decreased $48.6 million, or 38.3 percent, to $78.4 million as of June 30, 2021 compared to $127.0 million as of December 31, 2020. The decrease was primarily due to a reduction in the Colowyo Mine reclamation liability of $50.0 million in the second quarter of 2021. This reduction was primarily related to a change in the mine plan of South Taylor pit at the Colowyo Mine. After obtaining regulatory approval, the South Taylor pit life was extended through 2027 to mine the highwall, which resulted in a lower estimated obligation at the end of the mining period.

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, 2021, we had $114.5 million in cash and cash equivalents. Our committed credit arrangement as of June 30, 2021 is as follows (dollars in thousands):

	Authorized Amount			Available June 30, 2021
Revolving Credit Agreement	$	650,000	(1)	$	570,000

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

We have a secured Revolving Credit Agreement with aggregate commitments of $650 million. The Revolving Credit Agreement includes a swingline sublimit of $100 million, a letter of credit sublimit of $75 million, and a commercial paper back-up sublimit of $500 million, of which $100 million of the swingline sublimit, $75 million of the letter of credit sublimit, and $420 million of the commercial paper back-up sublimit remained available as of June 30, 2021.

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The Revolving Credit Agreement is secured under the Master Indenture and has a maturity date of April 25, 2023, unless extended as provided therein. Funds advanced under the Revolving Credit Agreement are either LIBOR rate loans or base rate loans, at our option. LIBOR rate loans bear interest at the adjusted LIBOR rate for the term of the advance plus a margin (currently 1.125 percent) based on our credit ratings. Base rate loans bear interest at the alternate base rate plus a margin (currently 0.125 percent) 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 one-month LIBOR rate plus 1.00 percent. Upon discontinuation of the LIBOR rate, the Revolving Credit Agreement provides for CFC and us to endeavor to establish an alternative rate that gives due consideration to the then prevailing market convention for determining a rate of interest for syndicated loans in the United States. Upon discontinuation of the LIBOR rate and if no alternative rate has been established by CFC and us, all funds advances will be at base rate loans. We had no outstanding borrowings as of June 30, 2021.

The 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. 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 Revolving Credit Agreement, which was $500 million at June 30, 2021, thereby providing 100 percent dedicated support for any commercial paper outstanding. As of June 30, 2021, we had $80 million of commercial paper outstanding (prior to netting discounts) and $420 million available on the commercial paper back-up sublimit.

We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for other securities, in open market purchases, privately negotiated transactions or otherwise. 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 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, 2021 compared to six months ended June 30, 2020

Operating activities. Net cash provided by operating activities was $52.7 million for the six months ended June 30, 2021 compared to $173.2 million for the same period in 2020, a decrease in net cash provided by operating activities of $120.5 million. Substantially all of the decrease was due to proceeds related to the DMEA withdrawal in 2020 compared to no proceeds in 2021.

Investing activities. Net cash used in investing activities was $57.3 million for the six months ended June 30, 2021 compared to $45.0 million for the same period in 2020, an increase in net cash used in investing activities of $12.3 million. The increase was primarily due to proceeds from the sale of electric plant related to the DMEA withdrawal in 2020 compared to no proceeds from the sale of electric plant in 2021. Partially offsetting this increase was a reduction in generation and transmission improvements and system upgrades for the six months ended June 30, 2021 compared to the same period in 2020.

Financing activities. Net cash used in financing activities was $8.3 million for the six months ended June 30, 2021 compared to net cash provided by financing activities of $103.7 million for the same period in 2020, a decrease of $112.0 million. The decrease was primarily due to lower proceeds from issuance of long-term debt in 2021 compared to 2020 (during 2020, we borrowed $125 million from the First Mortgage Obligations, Series 2020A, $100 million from the First Mortgage Obligations, Series 2020B, and $200 million from our Revolving Credit Agreement). These decreases were partially offset by an increase in short-term borrowings of $80.0 million and lower principal payments of long-term debt in 2021 compared to 2020.

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

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affecting our forecasts. After taking into account our Responsible Energy Plan, in the years 2021 through 2025, we forecast that we may invest approximately $799 million in new facilities and upgrades to our existing facilities.

Our actual capital expenditures depend on a variety of factors, including assumptions related to our Responsible Energy Plan and 2020 Electric Resource Plan, Utility Member load growth, availability of necessary permits, regulatory changes, environmental requirements, construction delays and costs, 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.

Contractual Commitments

Indebtedness. As of June 30, 2021, we had $3.2 billion in outstanding obligations, including approximately $2.9 billion of debt outstanding secured on a parity basis under our Master Indenture, $80.0 million in short-term borrowings, one unsecured loan agreement totaling $15.8 million and the Springerville certificates totaling $293.0 million (which are secured only by a mortgage and lien on Springerville Unit 3 and the Springerville lease). Our debt secured by the lien of our Master Indenture includes notes payable to CFC and CoBank (with the exception of one unsecured note), the First Mortgage Bonds, Series 2010A, the First Mortgage Obligations, Series 2014B, the First Mortgage Bonds, Series 2014E-1 and E-2, First Mortgage Bonds, Series 2016A, First Mortgage Obligations, Series 2017A, pollution control revenue bonds, and amounts outstanding, if any, under the Revolving Credit Agreement. Substantially all of our assets are pledged as collateral under the Master Indenture.

Construction Obligations. We have commitments to complete certain construction projects associated with improving the reliability of the generating facilities and the transmission system.

Coal Purchase Obligations. We have commitments to purchase coal for our generating facilities under long-term contracts that expire between 2021 and 2041. These contracts require us to purchase a minimum quantity of coal at prices that are subject to escalation clauses that reflect cost increases incurred by the suppliers and market conditions. Our coal purchase obligations exclude any purchases we have with our subsidiaries.

Environmental Regulations

We are subject to various federal, state and local laws, rules and regulations with regard to air quality, including greenhouse gases, water quality, and other environmental matters. These environmental laws, rules and regulations are complex and change frequently. For a discussion regarding potential effects on our business from environmental regulations, see also “Item 1 – BUSINESS – ENVIRONMENTAL REGULATION” and “Item 1A – RISK FACTORS” in our annual report on Form 10-K for the year ended December 31, 2020.

Responsible Energy Plan

On June 8, 2021, the COPUC issued an interim decision deeming our 2020 Electric Resource Plan application complete and referring the case to an administrative law judge. On June 21, 2021, the administrative law judge issued an interim decision setting the procedural schedule for our 2020 Electric Resource Plan proceeding, including a remote hearing scheduled January 31 through February 4, 2022. The procedural schedule accommodates the modeling of five additional Electric Resource Plan scenarios requested by parties to the proceeding. The results of the additional modeling will be filed alongside our supplemental direct testimony on September 28, 2021. For further information regarding our 2020 Electric Resource Plan, see “Item 1 – BUSINESS — POWER SUPPLY RESOURCES – Resource Planning” in our annual report on Form 10-K for the year ended December 31, 2020.

Rating Triggers

Our current senior secured ratings are “A3 (stable outlook)” by Moody’s, “BBB+ (stable 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 Revolving Credit Agreement includes a pricing grid related to the LIBOR spread, commitment fee and letter of credit fees due under the facility. We also have a term loan agreement that includes a pricing grid related to the LIBOR spread. A downgrade of our senior secured ratings could result in an increase in each of these pricing components. We do not believe that

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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, coal purchase contracts, and financial risk management contracts. Some of the contracts are directly tied to our credit rating generally being maintained at or above investment grade 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, 2020.

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.

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Item 6. Exhibits

Exhibit Number	Description of Exhibit
10.3.2	Amendment No. 13 to Missouri Basin Power Project—Laramie River Electric Generating Station and Transmission System Participation Agreement, dated as of May 27, 2021, amongst Basin Electric Power Cooperative, Tri-State, City of Lincoln, Nebraska, Wyoming Municipal Power Agency, and Western Minnesota Municipal Power Agency
10.10.1	Form of First Amendment to Commercial Paper Dealer Agreement between Tri-State, as issuer, and the Dealer party thereto
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 9, 2021	By:	/s/ Duane Highley
		Duane Highley
		Chief Executive Officer
Date: August 9, 2021		/s/ Patrick L. Bridges
		Patrick L. Bridges
		Senior Vice President/Chief Financial Officer (Principal Financial Officer)

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EX-10.3.2

Exhibit 10.3.2

MISSOURI BASIN POWER PROJECT

* * *

LARAMIE RIVER ELECTRIC GENERATING STATION AND TRANSMISSION SYSTEM PARTICIPATION AGREEMENT AMENDMENT NO. 13

This Amendment No. 13 (“Amendment”), dated as of May 27, 2021, by and between BASIN ELECTRIC POWER COOPERATIVE, a North Dakota corporation (“Basin Electric”); TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC., a Colorado corporation (“Tri-State”); CITY OF LINCOLN, NEBRASKA, a Nebraska municipal corporation operating the Lincoln Electric System (“L.E.S.”); WYOMING MUNICIPAL POWER AGENCY, a public corporation of the State of Wyoming (“Wyoming Municipal”); and WESTERN MINNESOTA MUNICIPAL POWER AGENCY, a municipal corporation and political subdivision of the State of Minnesota (“Western Minnesota”), all of whom may be collectively referred to as the “Parties” and individually referred to as “Party.” Capitalized terms used herein without definition shall have the respective meanings set forth in the Participation Agreement (as defined below).

W I T N E S S E T H:

WHEREAS, the Parties have entered into a document entitled “Missouri Basin Power Project * * * Laramie River Electric Generating Station and Transmission System Participation Agreement,” executed on various dates during the months of November and December, 1975, taking effect as of May 25, 1977, and amended from time to time (the “Participation Agreement”); and

WHEREAS, the Parties wish to amend the Participation Agreement to reflect the transfer of all of Wyoming Municipal’s 1.37% Entitlement Share to Tri-State, the assignment of all of Wyoming Municipal’s interest in the Participation Agreement to Tri-State, and to remove Wyoming Municipal as a Party to the Participation Agreement; and

WHEREAS, in addition, the Parties wish to make certain other amendments to the Participation Agreement.

NOW THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereto hereby agree as follows:

1.AMENDMENTS TO PARTICIPATION AGREEMENT:

1.1    As of the Effective Date, Section 4.8 of the Participation Agreement shall be amended in its entirety to read as follows:

“4.8 ENTITLEMENT SHARE: The percentage of undivided ownership of each Participant in the Project as follows:

A.Basin Electric = 42.27 percent

B.Tri-State = 28.50 percent

C.Western Minnesota = 16.47 percent

D.L.E.S. = 12.76 percent”

Page 1 of 3

Without further amendment or change, all Project Agreements shall be construed and the terms thereof applied in a manner consistent with the foregoing change of Parties and Entitlement Shares.

1.2    As of the Effective Date, Section 6.8 of the Participation Agreement shall be amended in its entirety to read as follows:

“6.8 Any action or determination of the Engineering and Operating Committee, the Audit Committee, and the Management Committee shall require a vote of three (3) out of the four (4) Participants, acting through their respective representatives, provided that such three (3) Participants collectively own more than fifty (50) percent of the Entitlement Shares.”

1.3    As of the Effective Date, Section 16.8 of the Participation Agreement shall be amended in its entirety to read as follows:

“16.8    The purchase of the interest by the Participants having elected to purchase the same shall be fully consummated within one year following the date upon which the initial notice was given under Section 16.4 hereof, unless the Participants are then diligently pursuing required authorizations or approvals to effect such transfer or are then diligently pursuing or defending appeals from orders entered or authorizations issued in connection with such transfer, in which event the transfer shall be consummated and the buyer shall tender payment within six (6) months following the date upon which the final order is entered or authorization issued in connection with such transfer.”

1.4    As of the Effective Date, Section C-1 of Exhibit C of the Participation Agreement shall be amended to delete the words “Wyoming Municipal Power Agency,” or “Wyoming Municipal,” in each instance that it appears.

2.    NOTICE OF TRANSFER: Wyoming Municipal provided notice pursuant to Section 16 of the Participation Agreement for the proposed sale of its 1.37% Entitlement Share. Only Tri-State elected to purchase Wyoming Municipal’s interest and therefore Wyoming Municipal may proceed with the transfer of all its interest to Tri-State. With respect to the transfer, assignment and sale of Wyoming Municipal’s 1.37% Entitlement Share to Tri-State and the assignment of all of Wyoming Municipal’s interest in the Project Agreements to Tri-State (collectively, the “Wyoming Municipal Transaction”), each Party, individually, by signing this Amendment, hereby (a) recognizes and consents to the Wyoming Municipal Transaction and (b) knowingly, freely, and definitively agrees, without any conditions, that the Wyoming Municipal Transaction has been accomplished in accordance with the Participation Agreement, including, but not limited to, Section 16 of the Participation Agreement. This consent does not in any way alter or amend any other transactions or agreements between various Parties, except as expressly agreed by such Parties, nor does it waive any rights or obligations under the Project Agreements, except as expressly agreed by the Parties.

3.    WYOMING MUNICIPAL NO LONGER A PARTY:

3.1    As of the Effective Date, Wyoming Municipal shall no longer be a Party to the Participation Agreement or any other Project Agreement.

Page 2 of 3

3.2    As of the Effective Date, the following parts and sections of the Participation Agreement are also revised or deleted as appropriate to remove any reference to Wyoming Municipal or its predecessor in interest: the cover page and Sections 1, 2.6, and 32.1.

4.    MUTUAL REPRESENTATIONS AND WARRANTIES: As of the date first written above, each Party represents and warrants to the other Parties that (i) it possesses full power and authority to enter into and perform this Amendment; (ii) the execution, delivery and performance of this Amendment by it have been duly authorized by it; (iii) except for the acceptance of this Amendment by the Federal Energy Regulatory Commission (“FERC”), the execution, delivery and performance of this Amendment by it does not require the consent or approval of, filing with, nor notice to any other person, which if not obtained would prevent it from performing its obligations hereunder. Each Party further represents and warrants to the other Parties that the execution, delivery and performance of this Amendment does not violate any federal, state or municipal laws, rules or regulations applicable to such Party.

5.    EFFECT OF AMENDMENT NOT OBTAINING REQUIRED APPROVALS: In the event that the transfer referred to in this Amendment does not occur, this Amendment shall be null and void without any further action by any Participant.

6.    RURAL UTILITIES SERVICE. The Participants acknowledge and agree that Basin Electric and Tri-State are no longer borrowers from the Rural Utilities Service (f/k/a Rural Electrification Administration) and therefore that, as of the Effective Date, all terms of the Project Agreements granting the Administrator any right in or interest under the Project Agreements shall have no further force or effect whatsoever.

7.    EFFECTIVE DATE: As Basin Electric and Tri-State are no longer borrowers from the Rural Utilities Service, no approval by the Administrator of the Rural Utilities Service is required. As Basin Electric and Tri-State have filed the Participation Agreement with FERC, FERC’s approval or acceptance for filing of this Amendment is required. This Amendment is effective on the latest of (“Effective Date”) (1) the closing date of the Wyoming Municipal Transaction, (2) the effective date established by FERC upon the final and unappealable acceptance for filing of this Amendment, and (3) the effective date established by FERC upon the final and unappealable acceptance for filing of the amendments of any other Project Agreements filed with FERC associated with the Wyoming Municipal Transaction. Tri-State will provide written notice to all other Participants of the Effective Date.

IN WITNESS HEREOF, the Parties have caused this Amendment No. 13 to be executed and delivered as of the date first written above.

[SIGNATURE PAGES TO FOLLOW]

Page 3 of 3

(SEAL)    BASIN ELECTRIC POWER COOPERATIVE

By: /s/ Paul M. Sukut

Title: Chief Executive Officer & General Manager

ATTEST:

By: /s/ Mark Foss

Title: Assistant Secretary

ACKNOWLEDGMENT

STATE OF NORTH DAKOTA)

                ) ss    

COUNTY OF BURLEIGH     )

On this 25th day of May, 2021, before me personally appeared Paul M. Sukut, to me personally known, who, having been by me first duly sworn, did say that he is the Chief Executive Officer and General Manager of Basin Electric Power Cooperative, the corporation described in and which executed the foregoing instrument; that the seal affixed to said instrument is the corporate seal of said corporation; and that said instrument was signed and sealed on behalf of said corporation by authority of its board of directors; and said Paul M. Sukut acknowledged said instrument to be the free act and deed of said corporation.

    IN WITNESS WHEREOF, I have hereunto set my hand and affixed my notarial seal on

the day and year in this certificate first above written.

(SEAL)                            Notary Public:

/s/ Sheila E. Wald

My Commission Expires: May 2, 2022

(SEAL)    TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

By: /s/ Patrick L. Bridges

Title: Senior Vice President/Chief Financial

Officer, serving as Acting Chief Executive

Officer

ACKNOWLEDGMENT

STATE OF COLORADO    )

) ss

COUNTY OF ADAMS        )

On this 25 day of May, 2021, before me personally appeared Patrick L. Bridges, to me personally known, who, having been by me first duly sworn, did say that he is the Senior Vice President/Chief Financial Officer, serving as Acting Chief Executive Officer of Tri-State Generation and Transmission Association, Inc., the corporation described in and which executed the foregoing instrument; that the seal affixed to said instrument is the corporate seal of said corporation; and that said instrument was signed and sealed on behalf of said corporation by authority of its board of directors; and said Patrick L. Bridges acknowledged said instrument to be the free act and deed of said corporation.

    IN WITNESS WHEREOF, I have hereunto set my hand and affixed my notarial seal on

the day and year in this certificate first above written.

(SEAL)                            Notary Public:

/s/ Diane K. Byers

My Commission Expires: Sep 4, 2024

    WESTERN MINNESOTA MUNICIPAL POWER AGENCY

By: /s/ Thomas J. Heller

Title: Assisstant Secretary & Assistant Treasurer

ATTEST:

By: __/s/ Merlin Sawyer

Title: Assistant Secretary

ACKNOWLEDGMENT

STATE OF SOUTH DAKOTA    )

                ) ss    

COUNTY OF LINCOLN    )

On this 27th day of May, 2021, before me personally appeared Thomas J. Heller, to me personally known, who, having been by me first duly sworn, did say that he is the Assistant Secretary and Assistant Treasurer of Western Minnesota Municipal Power Agency, the agency described in and which executed the foregoing instrument; and that said instrument was signed and sealed on behalf of said agency by authority of its board of directors; and said Thomas J. Heller acknowledged said instrument to be the free act and deed of said agency.

    IN WITNESS WHEREOF, I have hereunto set my hand and affixed my notarial seal on

the day and year in this certificate first above written.

(SEAL)                            Notary Public:

/s/ Daniel J. Harmelink

My Commission Expires: June 1, 2023

(SEAL)    CITY OF LINCOLN, NEBRASKA

By: /s/ Kevin G. Wailes

Title:     Chief Executive Officer

Lincoln Electric System

ATTEST:

By: /s/ Shelley Sahling-Zart

Title: Vice President & General Counsel

ACKNOWLEDGMENT

STATE OF NEBRASKA    )

                ) ss    

COUNTY OF LANCASTER    )

On this 27 day of May, 2021, before me personally appeared Kevin G. Wailes, to me personally known, who, having been by me first duly sworn, did say that he is the Administrator & Chief Executive Officer of Lincoln Electric System, which executed the foregoing instrument; and that said instrument was signed on behalf of Lincoln Electric System by authority of its Administrative Board; and said Kevin G. Wailes acknowledged said instrument to be the free act and deed of said Lincoln Electric System.

    IN WITNESS WHEREOF, I have hereunto set my hand and affixed my notarial seal on

the day and year in this certificate first above written.

(SEAL)                            Notary Public:

/s/ Michelle L. Miller

My Commission Expires: September 19, 2023

    WYOMING MUNICIPAL POWER AGENCY

By: /s/ Rosemary Henry

Title: Executive Director

ATTEST:

By: /s/ James L Harty

Title: Operations Manager

ACKNOWLEDGMENT

STATE OF WYOMING    )

                ) ss    

COUNTY OF NIOBRARA    )

On this 26th day of May, 2021, before me personally appeared Rosemary K. Henry, to me personally known, who, having been by me first duly sworn, did say that she is the Executive Director of Wyoming Municipal Power Agency, the corporation described in and which executed the foregoing instrument; that that said instrument was signed on behalf of said corporation by authority of its board of directors; and said Rosemary K. Henry acknowledged said instrument to be the free act and deed of said corporation.

    IN WITNESS WHEREOF, I have hereunto set my hand and affixed my notarial seal on

the day and year in this certificate first above written.

(SEAL)                            Notary Public:

/s/ Michelle G. Burt

My Commission Expires: 2/10/2024

EX-10.10.1

Exhibit 10.10.1

FIRST AMENDMENT TO COMMERCIAL PAPER DEALER AGREEMENT

THIS FIRST AMENDMENT TO COMMERCIAL PAPER DEALER AGREEMENT (the “First Amendment”) is entered into on this 10th day of May, 2021 by and between Tri-State Generation and Transmission Association, Inc. (“Issuer”) and ____________ (“Dealer”).

Background Information

A. Issuer and Dealer are parties to that certain Commercial Paper Dealer Agreement dated May 12, 2016 (the “Agreement”) concerning notes issued pursuant to that certain Issuing and Paying Agency Agreement also dated May 12, 2016 by and between Issuer and ________________ (the “Issuing and Paying Agency Agreement”).

B. The Issuer desires to make certain amendments to the Agreement because it became regulated as a public utility under Part II of the Federal Power Act, as amended.

Agreement

The parties hereby acknowledge the accuracy of the foregoing Background Information and agree as follows:

1. Defined Terms. Unless the context as used herein requires otherwise, capitalized terms used but not defined in this First Amendment shall have the meaning given to them in the Agreement.

2. Amendments. 

2.1    Section 1.3 of the Agreement is hereby deleted in its entirety and restated as follows:

The Notes shall be in a minimum denomination of $250,000 or integral multiples of $1,000 in excess thereof, will bear such interest rates, if interest bearing, or will be sold at such discount from their face amounts, as shall be agreed upon by the Dealer and the Issuer, shall have a maturity not exceeding 397 days from the date of issuance and may have such terms as are specified in Exhibit C hereto or the Private Placement Memorandum. In addition, at no time shall the interest rate on any Note exceed the highest interest rate authorized by the Federal Energy Regulatory Commission (“FERC”) for the Issuer’s short-term indebtedness from time to time, (such rate, the “Maximum Rate”). The Issuer shall advise the Dealer in writing of any Maximum Rate applicable to a Floating Rate Note (as defined in Exhibit C). The Issuer agrees that nothing in this Section 1.3 shall require the Dealer to monitor the Issuer’s compliance with the Federal Power Act or any orders of the FERC authorizing the Issuer’s indebtedness. The Notes shall not contain any provision for extension, renewal or automatic “rollover.”

2.2    Section 2.6 of the Agreement is hereby deleted in its entirety and restated as follows:

No consent or action of, or filing or registration with, any governmental or public regulatory body or authority, including the SEC, is required to authorize, or is otherwise required in connection with the execution, delivery or performance of, this Agreement, the Notes or the Issuing and Paying Agency Agreement, except (i) for the filing by the Issuer of a current report on Form 8-K with the SEC or as may be required by the securities or Blue Sky laws of the various states in connection with the offer and sale of the Notes and (ii) for the authorization to issue short-term debt granted by the FERC, which has been obtained and is in full force and effect.

2.3    Section 3 of the Agreement is hereby amended to add the following new Section 3.10:

The Issuer shall ensure that the principal amount of the Notes outstanding, together with other outstanding short-term indebtedness of the Issuer, will not exceed the amount authorized by

1

FERC. The Issuer agrees that it shall not issue any Note bearing a rate of interest in excess of the highest interest rate then authorized by the FERC for the Issuer’s short-term indebtedness, and with respect to any Floating Rate Note shall advise the Dealer in writing of the applicable Maximum Rate.

3. No Other Modifications. Except as expressly provided in this First Amendment, all of the terms and conditions of the Agreement shall remain unchanged and in full force and effect.

4. Binding Effect. This First Amendment shall be binding upon and inure to the benefit of the parties hereto and their respective successors and assigns.

5. Governing Law. This First Amendment shall be governed by and construed in accordance with the laws of the State of New York.

6. Conflict. In the event of any inconsistency or conflict between this First Amendment and the Agreement, the terms, provisions and conditions of this First Amendment shall govern and control.

7. Counterparts. This First Amendment may be executed in separate counterparts, each of which shall be deemed to be an original but all of which shall constitute one and the same instrument.

[Signatures Commence on the Following Page]

2

IN WITNESS WHEREOF, the parties hereto have caused this First Amendment to be executed as of the date and year first above written.

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.,

as Issuer

By:

Name: Patrick L. Bridges

Title: Senior Vice President/Chief Financial Officer

___________________________________________

as Dealer

By:

Name:

Title:

3

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 9, 2021

/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 9, 2021

/s/ Patrick L. Bridges

Patrick L. Bridges

Senior Vice President/Chief Financial Officer

1

EX-32

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, 2021, 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 9, 2021

/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, 2021, 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 9, 2021

/s/ Duane Highley

Duane Highley

Chief Executive 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 2021. 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	1	0	0	0	0	0.4	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, 2021	June 30, 2021	June 30, 2021
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, 2021 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 Page - shares	6 Months Ended
	Jun. 30, 2021	Aug. 09, 2021
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2021
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		0
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q2
Entity Central Index Key	0001637880
Amendment Flag	false

XML

Consolidated Statements of Financial Position - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Electric plant
In service	$ 6,240,314	$ 6,254,652
Construction work in progress	91,093	89,447
Total electric plant	6,331,407	6,344,099
Less allowances for depreciation and amortization	(2,985,644)	(2,991,393)
Net electric plant	3,345,763	3,352,706
Other plant	408,995	456,924
Less allowances for depreciation, amortization and depletion	(153,250)	(133,012)
Net other plant	255,745	323,912
Total property, plant and equipment	3,601,508	3,676,618
Other assets and investments
Investments in other associations	164,223	162,975
Investments in and advances to coal mines	2,437	2,799
Restricted cash and investments	4,366	4,682
Other noncurrent assets	15,987	14,889
Total other assets and investments	187,013	185,345
Current assets
Cash and cash equivalents	114,494	127,187
Restricted cash and investments	343	205
Deposits and advances	35,932	32,012
Accounts receivable—Utility Members	110,126	96,637
Other accounts receivable	25,513	20,570
Electric plant held for sale	0	4,877
Coal inventory	64,963	55,762
Materials and supplies	82,368	82,119
Total current assets	433,739	419,369
Deferred charges
Regulatory assets	688,747	710,268
Prepayment—NRECA Retirement Security Plan	18,803	21,490
Other	41,223	33,646
Total deferred charges	748,773	765,404
Total assets	4,971,033	5,046,736
Capitalization
Patronage capital equity	972,473	978,519
Accumulated other comprehensive loss	(6,145)	(5,714)
Noncontrolling interest	115,569	114,851
Total equity	1,081,897	1,087,656
Long-term debt	3,138,826	3,200,181
Total capitalization	4,220,723	4,287,837
Current liabilities
Utility Member advances	19,091	16,592
Accounts payable	117,437	98,654
Short-term borrowings	79,968	0
Accrued expenses	29,588	40,736
Current asset retirement obligations	6,679	11,044
Accrued interest	25,892	27,520
Accrued property taxes	18,155	32,794
Current maturities of long-term debt	75,718	87,587
Total current liabilities	372,528	314,927
Deferred credits and other liabilities
Regulatory liabilities	183,907	224,953
Deferred income tax liability	19,811	19,591
Asset retirement and environmental reclamation obligations	78,362	127,045
Other	76,351	54,600
Total deferred credits and other liabilities	358,431	426,189
Accumulated postretirement benefit and postemployment obligations	19,351	17,783
Total equity and liabilities	$ 4,971,033	$ 5,046,736

XML

Consolidated Statements of Operations (unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Operating revenues
Other	$ 15,712	$ 10,034	$ 30,712	$ 20,924
Operating revenues	326,302	313,656	652,274	633,122
Operating expenses
Purchased power	86,552	86,653	173,569	157,668
Fuel	45,870	39,549	106,417	100,618
Production	52,841	39,709	93,742	82,897
Transmission	41,948	41,646	86,619	83,186
General and administrative	11,897	16,041	26,484	32,256
Depreciation, amortization and depletion	46,483	44,311	99,238	91,335
Coal mining	966	1,087	2,507	3,821
Other	1,282	3,055	3,833	10,738
Operating expenses	287,839	272,051	592,409	562,519
Operating margins	38,463	41,605	59,865	70,603
Other income
Interest	907	984	1,784	2,289
Capital credits from cooperatives	2	135	4,275	3,488
Other income	1,032	401	1,889	151
Total other income	1,941	1,520	7,948	5,928
Interest expense
Interest	36,092	37,993	72,207	76,860
Interest charged during construction	(1,004)	(1,601)	(1,978)	(3,562)
Interest expense, net of amounts capitalized	35,088	36,392	70,229	73,298
Income tax expense (benefit)	110	(121)	219	(330)
Net margins including noncontrolling interest	5,206	6,854	(2,635)	3,563
Net margin attributable to noncontrolling interest	(1,762)	(1,421)	(3,411)	(2,740)
Net margins attributable to the Association	3,444	5,433	(6,046)	823
Utility Member electric sales
Operating revenues
Operating revenues	274,445	286,997	547,243	579,760
Non-member electric sales
Operating revenues
Operating revenues	$ 36,145	$ 16,625	$ 74,319	$ 32,438

XML

Consolidated Statements of Comprehensive Income (Loss) (unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Statement of Comprehensive Income [Abstract]
Net margins including noncontrolling interest	$ 5,206	$ 6,854	$ (2,635)	$ 3,563
Other comprehensive loss:
Unrealized loss on securities available for sale	(7)	0	(41)	0
Amortization of actuarial loss on postretirement benefit obligation included in net margin	219	177	731	1,110
Unrecognized prior service cost	0	0	(1,121)	(7,373)
Other comprehensive income (loss)	212	177	(431)	(6,263)
Comprehensive income (loss) including noncontrolling interest	5,418	7,031	(3,066)	(2,700)
Net comprehensive income attributable to noncontrolling interest	(1,762)	(1,421)	(3,411)	(2,740)
Comprehensive income (loss) attributable to the Association	$ 3,656	$ 5,610	$ (6,477)	$ (5,440)

XML

Consolidated Statements of Equity (unaudited) - USD ($) $ in Thousands	Total	Patronage capital	Accumulated other comprehensive income (loss)	Noncontrolling interest
Equity at beginning of period at Dec. 31, 2019		$ 1,031,063	$ (1,518)	$ 111,717
Change in Equity
Net margins attributable to the Association	$ 823	823
Retirement of patronage capital		(47,665)
Unrealized loss on securities available for sale	0
Amortization of prior service cost	1,110		1,110
Unrecognized prior service cost	(7,373)		(7,373)
Net comprehensive income attributable to noncontrolling interest	2,740			2,740
Equity distribution to noncontrolling interest				(1,268)
Equity at end of period at Jun. 30, 2020	1,089,629	984,221	(7,781)	113,189
Equity at beginning of period at Mar. 31, 2020		1,026,453	(7,958)	111,768
Change in Equity
Net margins attributable to the Association	5,433	5,433
Retirement of patronage capital		(47,665)
Unrealized loss on securities available for sale	0
Amortization of prior service cost	177		177
Unrecognized prior service cost	0
Net comprehensive income attributable to noncontrolling interest	1,421			1,421
Equity at end of period at Jun. 30, 2020	1,089,629	984,221	(7,781)	113,189
Equity at beginning of period at Dec. 31, 2020	1,087,656	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 cost	731		731
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 cost	219		219
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

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Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Operating activities
Net margins including noncontrolling interest	$ (2,635)	$ 3,563
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion	99,238	91,335
Amortization of NRECA Retirement Security Plan prepayment	2,686	2,686
Amortization of debt issuance costs	1,249	1,204
Impairment loss	0	259,761
Deferred impairment loss and other closure costs	0	(268,163)
Recognition of deferred revenue	(40,790)	0
Deferred membership withdrawal income	0	110,165
Deposits associated with generator interconnection requests	17,130	0
Capital credit allocations from cooperatives and income from coal mines under (over) refund distributions	(957)	2,775
Changes in operating assets and liabilities:
Accounts receivable	(19,250)	(3,457)
Coal inventory	(9,202)	(13,914)
Materials and supplies	(249)	256
Accounts payable and accrued expenses	23,681	11,753
Accrued interest	(1,628)	(1,447)
Accrued property taxes	(14,640)	(10,307)
Other	(1,935)	(12,966)
Net cash provided by operating activities	52,698	173,244
Investing activities
Purchases of plant	(52,030)	(68,059)
Sale of electric plant	0	26,000
Changes in deferred charges	(5,325)	(3,007)
Proceeds from other investments	72	68
Net cash used in investing activities	(57,283)	(44,998)
Financing activities
Changes in Member advances	2,499	(2,896)
Payments of long-term debt	(73,946)	(142,792)
Proceeds from issuance of long-term debt	0	425,000
Debt issuance costs	0	(527)
Change in short-term borrowings, net	79,968	(112,520)
Retirement of patronage capital	(13,705)	(60,991)
Equity distribution to noncontrolling interest	(2,693)	(1,268)
Other	(409)	(279)
Net cash provided by (used in) financing activities	(8,286)	103,727
Net increase (decrease) in cash, cash equivalents and restricted cash and investments	(12,871)	231,973
Cash, cash equivalents and restricted cash and investments – beginning	132,074	113,768
Cash, cash equivalents and restricted cash and investments – ending	119,203	345,741
Supplemental cash flow information:
Cash paid for interest	72,904	77,787
Cash paid for income taxes	0	0
Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$ 397	$ 594

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PRESENTATION OF FINANCIAL INFORMATION

6 Months Ended

Jun. 30, 2021

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, 2020 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, 2021, results of operations for the three and six months ended June 30, 2021 and 2020, and cash flows for the six months ended June 30, 2021 and 2020 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 generation facilities that are operated by the operating agent of each facility under joint facility ownership agreements with other utilities as tenants in common. These projects include the Yampa Project (operated by us) and the Missouri Basin Power Project (“MBPP”) (operated by Basin Electric Power Cooperative (“Basin”)). Each participant in these agreements receives a portion of the total output of the generation facilities, which approximates its percentage ownership. Each participant provides its own financing for its share of each facility and accounts for its share of the cost of each facility. The operating agent for each of these projects allocates the fuel and operating expenses to each participant based upon its share of the use of the facility. Therefore, our share of the plant asset cost, interest, depreciation and other operating expenses is included in our consolidated financial statements.

Effective as of August 1, 2021, our ownership share in MBPP increased to 28.5 percent due to our acquisition of Wyoming Municipal Power Agency’s ownership share in MBPP. The purchase represents an additional 1.37 percent undivided ownership interest in MBPP, which includes transmission and water rights and approximately 23 megawatts of generation.

Our share in each jointly owned facility is as follows as of June 30, 2021 (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	%	$	391,698	$	251,323	$	653
MBPP - Laramie River Station	27.13	%	500,485		318,715		3,096
Total			$	892,183	$	570,038	$	3,749

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ACCOUNTING FOR RATE REGULATION

6 Months Ended

Jun. 30, 2021

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, 2021		December 31, 2020
Regulatory assets
Deferred income tax expense (1)	$	19,641	$	19,641
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)	80,278		81,424
Goodwill – J.M. Shafer (3)	44,872		46,296
Goodwill – Colowyo Coal (4)	35,645		36,161
Deferred debt prepayment transaction costs (5)	127,988		132,302
Deferred Holcomb expansion impairment loss (6)	86,482		88,819
Unrecovered plant (7)	293,841		305,625
Total regulatory assets	688,747		710,268
Regulatory liabilities
Interest rate swap - realized gain (8) and other	3,037		3,293
Deferred revenues (9)	22,927		63,717
Deferred membership withdrawal income (10)	157,943		157,943
Total regulatory liabilities	183,907		224,953
Net regulatory asset	$	504,840	$	485,315

(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 Thermo Cogeneration Partnership, LP 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 and Escalante Generating Stations. The deferred impairment loss for Nucla Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 3.3-year period ending in December 2022 and recovered from our Utility Members through rates. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 25-year period ending in December 2045, which was the depreciable life of Escalante Generating Station, and recovered from our Utility Members through rates. The annual amortization approximates the former annual Escalante Generating Station depreciation for the remaining life of the asset.

(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 deferral of the recognition of non-member electric sales revenues. These deferred non-member electric sales revenues will be refunded to Utility Members as part of our rate stabilization measures when recognized in non-member electric sales revenue in future periods.

(10)Represents the deferral of the recognition of other income related to the withdrawal of former Utility Members from membership in us. The total deferred membership withdrawal income will be refunded to Utility Members as part of our rate stabilization measures when recognized in other income in future periods.

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INVESTMENTS IN OTHER ASSOCIATIONS

6 Months Ended

Jun. 30, 2021

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, 2021		December 31, 2020
Basin Electric Power Cooperative	$	118,295	$	118,295
National Rural Utilities Cooperative Finance Corporation - patronage capital	11,933		11,933
National Rural Utilities Cooperative Finance Corporation - capital term certificates	15,149		15,221
CoBank, ACB	12,707		11,141
Other	6,139		6,385
Investments in other associations	$	164,223	$	162,975

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, 2021 or during 2020.

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CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS

6 Months Ended

Jun. 30, 2021

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 INVESTMENTSWe 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, 2021		December 31, 2020
Cash and cash equivalents	$	114,494	$	127,187
Restricted cash and investments - current	343		205
Restricted cash and investments - noncurrent	4,366		4,682
Cash, cash equivalents and restricted cash and investments	$	119,203	$	132,074

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CONTRACT ASSETS AND CONTRACT LIABILITIES

6 Months Ended

Jun. 30, 2021

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, 2021, 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, 2021		December 31, 2020
Accounts receivable - Utility Members	$	110,126	$	96,637
Other accounts receivable - trade:
Non-member electric sales	7,423		5,231
Other	16,603		9,785
Total other accounts receivable - trade	24,026		15,016
Other accounts receivable - nontrade	1,487		5,554
Total other accounts receivable	$	25,513	$	20,570
Contract liabilities (unearned revenue)	$	5,598	$	6,025

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OTHER DEFERRED CHARGES

6 Months Ended

Jun. 30, 2021

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, 2021		December 31, 2020
Preliminary surveys and investigations	$	12,188	$	12,886
Advances to operating agents of jointly owned facilities	6,507		2,071
Operating lease right-of-use assets	7,688		7,985
Other	14,840		10,704
Total other deferred charges	$	41,223	$	33,646

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, 2021

Debt Disclosure [Abstract]

LONG-TERM DEBT

LONG-TERM DEBT

We have $3.1 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 $15.8 million as of June 30, 2021. 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 $650 million (“Revolving Credit Agreement”) that expires on April 25, 2023 and includes a swingline sublimit of $100 million, a letter of credit sublimit of $75 million, and a commercial paper back-up sublimit of $500 million. As of June 30, 2021, we had $570.0 million in availability under the Revolving Credit Agreement.

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

	June 30, 2021		December 31, 2020
Total debt	$	3,234,768	$	3,308,715
Less debt issuance costs	(24,341)		(25,590)
Less debt discounts	(9,530)		(9,659)
Plus debt premiums	13,647		14,302
Total debt adjusted for debt issuance costs, discounts and premiums	3,214,544		3,287,768
Less current maturities	(75,718)		(87,587)
Long-term debt	$	3,138,826	$	3,200,181

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SHORT-TERM BORROWINGS

6 Months Ended

Jun. 30, 2021

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 Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our 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, 2021			December 31, 2020
Commercial paper outstanding, net of discounts	$	79,968		$	—
Weighted average interest rate	0.18		%	—		%

At June 30, 2021, $420.0 million of the commercial paper back-up sublimit remained available under the Revolving Credit Agreement. See Note 7 – Long-Term Debt.

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ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS

6 Months Ended

Jun. 30, 2021

Asset Retirement Obligation 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. Estimates of future expenditures for environmental reclamation obligations are not discounted.

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 2019 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, 2021
Obligations at beginning of period	$	138,089
Liabilities incurred	—
Liabilities settled	(135)
Accretion expense	1,411
Change in cash flow estimate	(54,324)
Total obligations at end of period	$	85,041
Less current obligations at end of period	(6,679)
Long-term obligations at end of period	$	78,362

In the second quarter of 2021, we recorded a reduction of the Colowyo Mine reclamation liability of $50.0 million. This reduction was primarily related to a change in the mine plan of South Taylor pit at the Colowyo Mine. After obtaining regulatory approval, the South Taylor pit life was extended through 2027 to mine the highwall, which resulted in a lower estimated obligation at the end of the mining period. The West pit is currently in final reclamation. In 2019, we recorded an additional reclamation obligation liability of $22.4 million due to anticipated revision to the New Horizon Mine reclamation plan to accommodate an alternative post mine land use as necessary for final mine reclamation. We continue to evaluate the Colowyo Mine and New Horizon Mine post reclamation obligations and will make adjustments to these obligations as needed.

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

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OTHER DEFERRED CREDITS AND OTHER LIABILITIES

6 Months Ended

Jun. 30, 2021

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, 2021		December 31, 2020
Transmission easements	$	19,531	$	19,983
Operating lease liabilities - noncurrent	1,689		1,590
Contract liabilities (unearned revenue) - noncurrent	3,520		3,702
Customer deposits	8,900		7,712
Financial liabilities - reclamation	11,931		12,081
Deposits associated with generator interconnection requests	17,130		—
Other	13,650		9,532
Total other deferred credits and other liabilities	$	76,351	$	54,600

In 2015, we renewed transmission right of way easements on tribal nation lands where certain of our electric transmission lines are located. $29.4 million will be paid by us for these easements from 2021 through the individual easement terms ending between 2036 and 2040. The present values for the remaining easement payments were $19.5 and $20.0 million as of June 30, 2021 and December 31, 2020, 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.

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EMPLOYEE BENEFIT PLANS

6 Months Ended

Jun. 30, 2021

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 postemployment medical benefits to employees on long-term disability. The plans were unfunded at June 30, 2021, 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 postemployment medical benefit obligations are determined annually (during the fourth quarter) by an independent actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands):

	Six Months Ended June 30, 2021
Postretirement medical benefit obligation at beginning of period	$	9,985
Service cost	301
Interest cost	129
Benefit payments (net of contributions by participants)	(296)
Postretirement medical benefit obligation at end of period	$	10,119
Postemployment medical benefit obligation at end of period	419
Total postretirement and postemployment medical obligations at end of period	$	10,538

The service cost component of our net periodic benefit cost is included in operating expenses on our consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other income (expense) on our consolidated statements of operations.

In accordance with the accounting standard related to postretirement benefits other than pensions, actuarial gains and losses are not recognized in income but are instead recorded in accumulated other 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, 2021
Accumulated other comprehensive loss at beginning of period	$	(841)
Amortization of prior service credit into other income	(39)
Accumulated other comprehensive loss at end of period	$	(880)

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 currently 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. As of April 30, 2021, the plans ceased to add new participants and no new executives will be eligible for the plan.

The NRECA Executive Benefit Restoration Plan obligations are determined annually (during the first quarter of the subsequent year) by an NRECA actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands):

	Six Months Ended June 30, 2021
Executive benefit restoration obligation at beginning of period	$	7,379
Service cost	204
Interest cost	109
Actuarial loss	1,121
Executive benefit restoration at end of period	$	8,813
Fair value of plan assets at beginning of period	$	6,955
Employer contributions	806
Actual return on plan assets	$	61
Fair value of plan assets at end of period	$	7,822
Net liability recognized	$	991

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, 2021
Accumulated other comprehensive loss at beginning of period	$	(4,873)
Amortization of prior service cost into other income	459
Amortization of actuarial loss	171
Curtailment and settlement	141
Unrecognized actuarial loss	(1,121)
Accumulated other comprehensive loss at end of period	$	(5,223)

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REVENUE

6 Months Ended

Jun. 30, 2021

Revenue from Contract with Customer [Abstract]

REVENUE

REVENUE

Revenue from Contracts with Customers

Our revenues are derived primarily from the sale of electric power 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 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,
	2021		2020		2021		2020
Non-member electric sales:
Long-term contracts	$	10,093	$	11,251	$	18,799	$	23,395
Short-term contracts	6,096		5,374		14,730		9,043
Recognition of deferred revenue	19,956		—		40,790		—
Other	15,712		10,034		30,712		20,924
Total non-member electric sales and other operating revenue	$	51,857	$	26,659	$	105,031	$	53,362

Non-member electric sales

Revenues from 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.

Other operating revenue

Other operating revenue consists primarily of wheeling, transmission, water and coal sales revenue. Other operating revenue also includes revenue we receive from two of 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). Water revenue is derived from supplying water resources to a paper manufacturer located adjacent to the Escalante Generating Station (payments from the customer are received in accordance with the contract terms which is less than 15 days from the invoice date). 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 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, 2021
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXESWe 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. Our consolidated statements of operations included an income tax expense of $0.2 million for the six months ended June 30, 2021 and an income tax benefit of $0.3 million for the comparable period in 2020.

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LEASES

6 Months Ended

Jun. 30, 2021

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 $0.9 million for the three months ended June 30, 2021 and $0.7 million for the comparable period in 2020. Rent expense for all short-term and long-term operating leases was $1.9 million for the six months ended June 20, 2021 and $1.6 million for the comparable period in 2020. Rent expense is included in operating expenses on our consolidated statements of operations. As of June 30, 2021, 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, 2021			December 31, 2020
Operating leases
Operating lease right-of-use assets	$	9,237		$	9,223
Less: Accumulated amortization	(1,549)			(1,238)
Net operating lease right-of-use assets	$	7,688		$	7,985
Operating lease liabilities - current	$	(464)		$	(526)
Operating lease liabilities - noncurrent	(1,689)			(1,590)
Total operating lease liabilities	$	(2,153)		$	(2,116)
Operating leases
Weighted average remaining lease term (years)	7.7			7.6
Weighted average discount rate	3.75		%	3.84		%

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

Year 1	$	550
Year 2	415
Year 3	374
Year 4	247
Year 5	91
Thereafter	650
Total lease payments	$	2,327
Less imputed interest	(174)
Total	$	2,153

Leasing Arrangements As Lessor

We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $1.7 million and $1.6 million for the three months ended June 30, 2021 and 2020, respectively, and $3.5 million and $3.2 million for the six months ended June 30, 2021 and 2020 respectively, 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 noncontrolling 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, 2021

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.

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, 2021				December 31, 2020
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
EBR Trust investments	$	7,822	$	7,743	$	6,955	$	6,955

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, 2021				December 31, 2020
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	513	$	556	$	491	$	478

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 $105.9 million as of June 30, 2021 and $94.6 million as of December 31, 2020.

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, 2021				December 31, 2020
	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
Total long-term debt	$	3,234,768	$	3,825,737	$	3,308,715	$	3,908,497

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VARIABLE INTEREST ENTITIES

6 Months Ended

Jun. 30, 2021

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 and also entities for which we are not the primary beneficiary and therefore do not consolidate.

Consolidated Variable Interest Entity

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

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, 2021		December 31, 2020
Net electric plant	$	749,204	$	758,273
Noncontrolling interest	115,571		114,852
Long-term debt	300,789		342,355
Accrued interest	8,721		9,942

Our consolidated statements of operations include the following Springerville Partnership expenses for the three and six months ended June 30, 2021 and 2020 (dollars in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
Depreciation, amortization and depletion	$	4,535	$	4,535	$	9,069	$	9,069
Interest	4,956		5,651		10,141		11,511

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 noncontrolling equity interest in the Springerville Partnership is reflected on our consolidated statements of operations.

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LEGAL

6 Months Ended

Jun. 30, 2021

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 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 206 proceedings to determine the justness and reasonableness of our rates and wholesale electric service contracts. FERC also rejected our Board Policy 115 (“BP 115”) and member project contracts related to our Utility Members’ election to provide up to 5 percent of their electric power requirements pursuant to their wholesale electric service contracts on the grounds that the initial filing was incomplete without Board Policy 101 (“BP 101”) related to the self-supply in excess of the 5 percent annual allowance. The tariff rates were referred to an administrative law judges to encourage settlement of material issues and to hold a hearings if settlements is not reached. Any refunds to the applicable tariff rates would only apply for sales after March 26, 2020. On April 30, 2021, we filed a proposed settlement agreement related to our Utility Member stated rate, including BP 115, BP 101, and Board Policy 119 (“BP 119”), with FERC for approval, as further discussed below. The settlement proceedings for our transmission service rates are continuing. FERC’s March 20, 2020 order regarding our Jurisdictional PDO denied our requested declaration regarding the preemption of the United Power and LPEA proceeding at the COPUC stating the proceeding was not currently preempted.

On April 13, 2020, we filed a request for rehearing limited to the issue of preemption of the United Power and LPEA proceeding at the COPUC related to the contract termination payment amount as described in our Jurisdictional PDO. 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 by finding exclusive jurisdiction over our contract termination payments and preempting the jurisdiction of the COPUC as of September 3, 2019.

On July 1, 2020, we re-submitted our BP 101, BP 115, and all existing member project contracts with FERC for acceptance and on August 28, 2020 FERC accepted the filings effective August 31, 2020. FERC also ordered a 206 proceeding to determine whether our July 1 filed documents are just and reasonable and set them for settlement and hearing procedures, which were consolidated with the settlement and hearing procedures in effect for our member rates docket. United Power has 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 acceptance of our July 1 filed documents and such matter is being held in abeyance pending resolution of the Jurisdictional PDO appeal discussed below.

On October 19, 2020, we filed our BP 119 related to our community solar program that provides for our Utility Members to develop community solar projects up to specified annual output limits separate from and in addition to the 5 percent self-supply provision of the wholesale electric service contracts and our first community solar contract with a Utility Member with FERC for acceptance. On December 18, 2020, FERC accepted BP 119 and the community solar contract, to be effective December 19, 2020, subject to refund. FERC referred it to FERC’s hearing and settlement judge procedures, which were consolidated with the settlement and hearing procedures in effect for our member rates docket.

On July 13, 2020, we filed a petition for review with the D.C. Circuit Court of Appeals to protect our interest, and requested review of FERC’s order granting in part and denying in part our Jurisdictional PDO and FERC’s order granting rehearings for further consideration. Petitions for review related to both the Jurisdictional PDO and tariff filings have been filed with the D.C. Circuit Court of Appeals by other parties, including United Power. On September 18, 2020, FERC filed to hold the appeals in abeyance. On September 29, 2020, an order was issued considering the motion to hold the case in abeyance, directing the parties to file motions to govern future proceedings by January 11, 2021. FERC, United Power, and the other parties reached agreement on the procedures and schedule for the Jurisdictional PDO and abeyance on all non-Jurisdictional PDO matters and such filing was made to the D.C. Circuit Court of Appeals. On June 7, 2021, United Power filed its brief with the D.C. Circuit Court of Appeals regarding the Jurisdictional PDO.

On April 30, 2021, we filed a proposed settlement agreement related to our Utility Member stated rate, including our wholesale electric service contracts, BP 115, BP 101, and BP 119, with FERC for approval. With the exception of four reserved issues

contingent on United Power being a settling party, the settlement resolves 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 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 will establish 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. On June 30, 2021, the Chief Judge terminated the settlement judge procedures for our member rates docket. On August 2, 2021, FERC approved this settlement agreement and we will file a motion with FERC to set a procedure schedule for the four reserved issues.

It is not possible to predict if FERC will require us to refund amounts to our customers for sales after March 26, 2020 on outstanding issues, if settlements will be reached without a hearing on our transmission service rates and tariff, or the outcome of the four reserved issues related to our member rates docket. In addition, we cannot predict the outcome of the 206 proceedings or 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 proceeding 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 asserting 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 November 25, 2020, LPEA and United Power jointly filed an application for rehearing, reargument, and reconsideration with the COPUC of its October 22, 2020 decision. The COPUC denied LPEA's and United Power's November 25 application. 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. It is not possible to predict the outcome in this matter.

United Power's Adams District Court Complaints: 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 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, the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are also void, that we have breached the wholesale electric service contract with United Power, and that we and our three Non-Utility Members conspired to deprive the COPUC of jurisdiction over the contract termination payment of our Colorado Utility Members. On June 20, 2020, we filed our answer denying United Power’s allegations and request for relief, and asked the court to dismiss United Power’s claims. We asserted counterclaims against United Power, and are seeking relief from United Power’s breach of our Bylaws and declaratory judgement that the April 2019 Bylaws amendment and the April 2020 Board approvals related to a “Make-Whole” methodology for a contract termination payment and buy-down payment formula are valid. On June 20, 2020, the three Non-Utility Members filed a joint motion to dismiss. On December 10, 2020, the Non-Utility Members motion to dismiss was granted. On December 23, 2020, United Power sought to amend its May 2020 compliant to add LPEA as an additional plaintiff and to add the claims from its November 2020 complaint, discussed below, into its amended complaint and to dismiss the November 2020 complaint against us. 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 and to amend its claims as to our three Non-Utility Members. On July 30, 2021, we filed a partial motion to dismiss a majority of United Power's and LPEA's claims, including

claims related to the April 2019 Bylaws amendment, the April 2020 Board approvals, and that we conspired with our Non-Utility Members. 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. It is not possible to predict the outcome of this matter or whether we will incur any liability in connection with this matter.

In addition, on November 23, 2020, United Power filed a Complaint for Declaratory Relief in the Adams County District Court, 2020CV031496, against us seeking for the court to declare that our addition of the Non-Utility Members violated Colorado law. On December 11, 2020, we moved to dismiss United Power's November 2020 compliant because it repeats the claims pending in the May 2020 complaint proceeding. On July 21, 2021, United Power filed a notice of voluntary dismissal without prejudice of its November 2020 complaint. On July 22, 2021, the court entered in order granting United Power’s request to dismiss the November 2020 case without prejudice.

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PRESENTATION OF FINANCIAL INFORMATION (Tables)

6 Months Ended

Jun. 30, 2021

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, 2021 (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	%	$	391,698	$	251,323	$	653
MBPP - Laramie River Station	27.13	%	500,485		318,715		3,096
Total			$	892,183	$	570,038	$	3,749

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ACCOUNTING FOR RATE REGULATION (Tables)

6 Months Ended

Jun. 30, 2021

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of regulatory assets and liabilities

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

	June 30, 2021		December 31, 2020
Regulatory assets
Deferred income tax expense (1)	$	19,641	$	19,641
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)	80,278		81,424
Goodwill – J.M. Shafer (3)	44,872		46,296
Goodwill – Colowyo Coal (4)	35,645		36,161
Deferred debt prepayment transaction costs (5)	127,988		132,302
Deferred Holcomb expansion impairment loss (6)	86,482		88,819
Unrecovered plant (7)	293,841		305,625
Total regulatory assets	688,747		710,268
Regulatory liabilities
Interest rate swap - realized gain (8) and other	3,037		3,293
Deferred revenues (9)	22,927		63,717
Deferred membership withdrawal income (10)	157,943		157,943
Total regulatory liabilities	183,907		224,953
Net regulatory asset	$	504,840	$	485,315

(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 Thermo Cogeneration Partnership, LP 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 and Escalante Generating Stations. The deferred impairment loss for Nucla Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 3.3-year period ending in December 2022 and recovered from our Utility Members through rates. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $11.3 million annually over the 25-year period ending in December 2045, which was the depreciable life of Escalante Generating Station, and recovered from our Utility Members through rates. The annual amortization approximates the former annual Escalante Generating Station depreciation for the remaining life of the asset.

(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 deferral of the recognition of non-member electric sales revenues. These deferred non-member electric sales revenues will be refunded to Utility Members as part of our rate stabilization measures when recognized in non-member electric sales revenue in future periods.

(10)Represents the deferral of the recognition of other income related to the withdrawal of former Utility Members from membership in us. The total deferred membership withdrawal income will be refunded to Utility Members as part of our rate stabilization measures when recognized in other income in future periods.

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INVESTMENTS IN OTHER ASSOCIATIONS (Tables)

6 Months Ended

Jun. 30, 2021

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, 2021		December 31, 2020
Basin Electric Power Cooperative	$	118,295	$	118,295
National Rural Utilities Cooperative Finance Corporation - patronage capital	11,933		11,933
National Rural Utilities Cooperative Finance Corporation - capital term certificates	15,149		15,221
CoBank, ACB	12,707		11,141
Other	6,139		6,385
Investments in other associations	$	164,223	$	162,975

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

6 Months Ended

Jun. 30, 2021

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

Schedule of cash, cash equivalents and restricted cash and investments

The following table provides a reconciliation of cash, cash equivalents and restricted cash and investments reported within our consolidated statements of financial position that sum to the total of the same such amount shown in our consolidated statements of cash flows (dollars in thousands):

	June 30, 2021		December 31, 2020
Cash and cash equivalents	$	114,494	$	127,187
Restricted cash and investments - current	343		205
Restricted cash and investments - noncurrent	4,366		4,682
Cash, cash equivalents and restricted cash and investments	$	119,203	$	132,074

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CONTRACT ASSETS AND CONTRACT LIABILITIES (Tables)

6 Months Ended

Jun. 30, 2021

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, 2021		December 31, 2020
Accounts receivable - Utility Members	$	110,126	$	96,637
Other accounts receivable - trade:
Non-member electric sales	7,423		5,231
Other	16,603		9,785
Total other accounts receivable - trade	24,026		15,016
Other accounts receivable - nontrade	1,487		5,554
Total other accounts receivable	$	25,513	$	20,570
Contract liabilities (unearned revenue)	$	5,598	$	6,025

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OTHER DEFERRED CHARGES (Tables)

6 Months Ended

Jun. 30, 2021

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, 2021		December 31, 2020
Preliminary surveys and investigations	$	12,188	$	12,886
Advances to operating agents of jointly owned facilities	6,507		2,071
Operating lease right-of-use assets	7,688		7,985
Other	14,840		10,704
Total other deferred charges	$	41,223	$	33,646

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LONG-TERM DEBT (Tables)

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Schedule of long-term debt

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

	June 30, 2021		December 31, 2020
Total debt	$	3,234,768	$	3,308,715
Less debt issuance costs	(24,341)		(25,590)
Less debt discounts	(9,530)		(9,659)
Plus debt premiums	13,647		14,302
Total debt adjusted for debt issuance costs, discounts and premiums	3,214,544		3,287,768
Less current maturities	(75,718)		(87,587)
Long-term debt	$	3,138,826	$	3,200,181

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SHORT-TERM BORROWINGS (Tables)

6 Months Ended

Jun. 30, 2021

Short-term Debt [Abstract]

Schedule of Commercial Paper Notes

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

	June 30, 2021			December 31, 2020
Commercial paper outstanding, net of discounts	$	79,968		$	—
Weighted average interest rate	0.18		%	—		%

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ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS (Tables)

6 Months Ended

Jun. 30, 2021

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

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

	Six Months Ended June 30, 2021
Obligations at beginning of period	$	138,089
Liabilities incurred	—
Liabilities settled	(135)
Accretion expense	1,411
Change in cash flow estimate	(54,324)
Total obligations at end of period	$	85,041
Less current obligations at end of period	(6,679)
Long-term obligations at end of period	$	78,362

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OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Tables)

6 Months Ended

Jun. 30, 2021

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, 2021		December 31, 2020
Transmission easements	$	19,531	$	19,983
Operating lease liabilities - noncurrent	1,689		1,590
Contract liabilities (unearned revenue) - noncurrent	3,520		3,702
Customer deposits	8,900		7,712
Financial liabilities - reclamation	11,931		12,081
Deposits associated with generator interconnection requests	17,130		—
Other	13,650		9,532
Total other deferred credits and other liabilities	$	76,351	$	54,600

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EMPLOYEE BENEFIT PLANS (Tables)

6 Months Ended

Jun. 30, 2021

Retirement Benefits [Abstract]

Schedule of employee benefit plan obligations

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

	Six Months Ended June 30, 2021
Postretirement medical benefit obligation at beginning of period	$	9,985
Service cost	301
Interest cost	129
Benefit payments (net of contributions by participants)	(296)
Postretirement medical benefit obligation at end of period	$	10,119
Postemployment medical benefit obligation at end of period	419
Total postretirement and postemployment medical obligations at end of period	$	10,538

The NRECA Executive Benefit Restoration Plan obligations are determined annually (during the first quarter of the subsequent year) by an NRECA actuary and are included in accumulated postretirement benefit and postemployment obligations on our consolidated statements of financial position as follows (dollars in thousands):

	Six Months Ended June 30, 2021
Executive benefit restoration obligation at beginning of period	$	7,379
Service cost	204
Interest cost	109
Actuarial loss	1,121
Executive benefit restoration at end of period	$	8,813
Fair value of plan assets at beginning of period	$	6,955
Employer contributions	806
Actual return on plan assets	$	61
Fair value of plan assets at end of period	$	7,822
Net liability recognized	$	991

Schedule of the net unrecognized actuarial gains and losses related to 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, 2021
Accumulated other comprehensive loss at beginning of period	$	(841)
Amortization of prior service credit into other income	(39)
Accumulated other comprehensive loss at end of period	$	(880)

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, 2021
Accumulated other comprehensive loss at beginning of period	$	(4,873)
Amortization of prior service cost into other income	459
Amortization of actuarial loss	171
Curtailment and settlement	141
Unrecognized actuarial loss	(1,121)
Accumulated other comprehensive loss at end of period	$	(5,223)

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REVENUE (Tables)

6 Months Ended

Jun. 30, 2021

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,
	2021		2020		2021		2020
Non-member electric sales:
Long-term contracts	$	10,093	$	11,251	$	18,799	$	23,395
Short-term contracts	6,096		5,374		14,730		9,043
Recognition of deferred revenue	19,956		—		40,790		—
Other	15,712		10,034		30,712		20,924
Total non-member electric sales and other operating revenue	$	51,857	$	26,659	$	105,031	$	53,362

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LEASES (Tables)

6 Months Ended

Jun. 30, 2021

Leases [Abstract]

Schedule of lease components

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

	June 30, 2021			December 31, 2020
Operating leases
Operating lease right-of-use assets	$	9,237		$	9,223
Less: Accumulated amortization	(1,549)			(1,238)
Net operating lease right-of-use assets	$	7,688		$	7,985
Operating lease liabilities - current	$	(464)		$	(526)
Operating lease liabilities - noncurrent	(1,689)			(1,590)
Total operating lease liabilities	$	(2,153)		$	(2,116)
Operating leases
Weighted average remaining lease term (years)	7.7			7.6
Weighted average discount rate	3.75		%	3.84		%

Schedule of expected minimum lease commitments under operating leases

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

Year 1	$	550
Year 2	415
Year 3	374
Year 4	247
Year 5	91
Thereafter	650
Total lease payments	$	2,327
Less imputed interest	(174)
Total	$	2,153

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FAIR VALUE (Tables)

6 Months Ended

Jun. 30, 2021

Fair Value Disclosures [Abstract]

Schedule of carrying amounts and fair values of assets and liabilities

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

	June 30, 2021				December 31, 2020
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
EBR Trust investments	$	7,822	$	7,743	$	6,955	$	6,955

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

	June 30, 2021				December 31, 2020
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	513	$	556	$	491	$	478

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

	June 30, 2021				December 31, 2020
	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
Total long-term debt	$	3,234,768	$	3,825,737	$	3,308,715	$	3,908,497

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VARIABLE INTEREST ENTITIES (Tables)

6 Months Ended

Jun. 30, 2021

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, 2021		December 31, 2020
Net electric plant	$	749,204	$	758,273
Noncontrolling interest	115,571		114,852
Long-term debt	300,789		342,355
Accrued interest	8,721		9,942

Our consolidated statements of operations include the following Springerville Partnership expenses for the three and six months ended June 30, 2021 and 2020 (dollars in thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
Depreciation, amortization and depletion	$	4,535	$	4,535	$	9,069	$	9,069
Interest	4,956		5,651		10,141		11,511

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PRESENTATION OF FINANCIAL INFORMATION (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2021 USD ($) memberSystem facility	Aug. 01, 2021 MW
Jointly owned facilities
Number of classes of members | memberSystem	3
Number of jointly owned facilities | facility	2
Electric Plant in Service	$ 892,183
Accumulated Depreciation	570,038
Construction Work In Progress	$ 3,749
Yampa Project - Craig Generating Station Units 1 and 2
Jointly owned facilities
Tri-State Share	24.00%
Electric Plant in Service	$ 391,698
Accumulated Depreciation	251,323
Construction Work In Progress	$ 653
MBPP - Laramie River Station
Jointly owned facilities
Tri-State Share	27.13%
Electric Plant in Service	$ 500,485
Accumulated Depreciation	318,715
Construction Work In Progress	$ 3,096
MBPP - Laramie River Station | Subsequent Event
Jointly owned facilities
Tri-State Share		28.50%
Additional undivided ownership interest		1.37%
Additional megawatts of generation | MW		23
Class A Members
Jointly owned facilities
Number of members | memberSystem	42
Class B Members
Jointly owned facilities
Number of members | memberSystem	0
Non-Utility Members
Jointly owned facilities
Number of members | memberSystem	3

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ACCOUNTING FOR RATE REGULATION (Details) - USD ($) $ in Thousands	1 Months Ended	6 Months Ended
	Oct. 31, 2017	Jun. 30, 2021	Dec. 31, 2020
Regulatory assets and liabilities
Regulatory assets		$ 688,747	$ 710,268
Regulatory liabilities		183,907	224,953
Net regulatory asset		504,840	485,315
Interest rate swaps, realized gain
Regulatory assets and liabilities
Regulatory liabilities		3,037	3,293
Proceeds from settlement of interest rate swaps	$ 4,600
Deferred non-member electric sales
Regulatory assets and liabilities
Regulatory liabilities		22,927	63,717
Deferred membership withdrawal income
Regulatory assets and liabilities
Regulatory liabilities		$ 157,943	157,943
First Mortgage Obligations, Series 2017A , Tranche 1, 3.34%, due through 2029
Regulatory assets and liabilities
Term of issuance		12 years
Deferred income tax expense
Regulatory assets and liabilities
Regulatory assets		$ 19,641	19,641
Deferred prepaid lease expense | Springerville Unit 3 Lease
Regulatory assets and liabilities
Regulatory assets		80,278	81,424
Annual amortization expense		$ 2,300
Amortization period		47 years
Goodwill | TCP
Regulatory assets and liabilities
Regulatory assets		$ 44,872	46,296
Annual amortization expense		$ 2,800
Amortization period		25 years
Goodwill | Colowyo Coal
Regulatory assets and liabilities
Regulatory assets		$ 35,645	36,161
Annual amortization expense		$ 1,000
Amortization period		44 years
Deferred debt prepayment transaction costs
Regulatory assets and liabilities
Regulatory assets		$ 127,988	132,302
Annual amortization expense		$ 8,600
Amortization period		21 years 4 months 24 days
Deferred impairment loss | Unrecovered Plants
Regulatory assets and liabilities
Regulatory assets		$ 293,841	305,625
Deferred impairment loss | Nucla Generating Station
Regulatory assets and liabilities
Amortization period		3 years 3 months 18 days
Deferred impairment loss | Holcomb Expansion
Regulatory assets and liabilities
Annual amortization expense		$ 11,300
Deferred impairment loss | Holcomb Expansion
Regulatory assets and liabilities
Regulatory assets		86,482	$ 88,819
Annual amortization expense		$ 4,700
Amortization period		20 years

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INVESTMENTS IN OTHER ASSOCIATIONS (Details) - USD ($)	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Investment in other associations
Investment in other associations	$ 164,223,000		$ 162,975,000
Impairment during the period	0	$ 0
Basin Electric Power Cooperative
Investment in other associations
Investment in other associations	118,295,000		118,295,000
National Rural Utilities Cooperative Finance Corporation - patronage capital
Investment in other associations
Investment in other associations	11,933,000		11,933,000
National Rural Utilities Cooperative Finance Corporation - capital term certificates
Investment in other associations
Investment in other associations	15,149,000		15,221,000
CoBank, ACB
Investment in other associations
Investment in other associations	12,707,000		11,141,000
Other
Investment in other associations
Investment in other associations	$ 6,139,000		$ 6,385,000

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CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020	Jun. 30, 2020	Dec. 31, 2019
Cash, cash equivalents, restricted cash and investments
Cash and cash equivalents	$ 114,494	$ 127,187
Restricted cash and investments - current	343	205
Restricted cash and investments - noncurrent	4,366	4,682
Cash, cash equivalents and restricted cash and investments	$ 119,203	$ 132,074	$ 345,741	$ 113,768

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CONTRACT ASSETS AND CONTRACT LIABILITIES (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Dec. 31, 2020
Accounts receivable
Accounts receivable—Utility Members	$ 110,126	$ 96,637
Other accounts receivable - trade	25,513	20,570
Contract liabilities
Contract liabilities (unearned revenue)	5,598	6,025
Other accounts receivable - trade
Accounts receivable
Other accounts receivable - trade	24,026	15,016
Other accounts receivable - trade | Non-member electric sales
Accounts receivable
Other accounts receivable - trade	7,423	5,231
Other accounts receivable - trade | Other
Accounts receivable
Other accounts receivable - trade	16,603	9,785
Other accounts receivable, non-trade
Accounts receivable
Other accounts receivable - trade	1,487	$ 5,554
Other operating revenue
Contract liabilities
Contract liabilities recognized	$ 700

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OTHER DEFERRED CHARGES (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Deferred Costs [Abstract]
Preliminary surveys and investigations	$ 12,188	$ 12,886
Advances to operating agents of jointly owned facilities	6,507	2,071
Operating lease right-of-use assets	7,688	7,985
Other	14,840	10,704
Total other deferred charges	$ 41,223	$ 33,646

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LONG-TERM DEBT - Additional Information (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2021 USD ($) $ / shares	Dec. 31, 2020 USD ($)
Debt
Long-term debt	$ 3,138,826	$ 3,200,181
Number of unsecured debt instruments | $ / shares	1
Unsecured notes	$ 15,800
Minimum
Debt
Equity to capitalization ratio (ECR) requirement	18.00%
Debt service ratio (DSR) requirement	1.10
Springerville certificates, Series B, 7.14%, due through 2033
Debt
Debt service ratio (DSR) requirement	1.02
2018 Revolving Credit Agreement
Debt
Maximum borrowing capacity	$ 650,000
Available borrowing capacity	570,000
2018 Revolving Credit Agreement | Commercial Paper
Debt
Available borrowing capacity	420,000
Swingline
Debt
Maximum borrowing capacity	100,000
Letter of Credit
Debt
Maximum borrowing capacity	75,000
Commercial Paper
Debt
Maximum borrowing capacity	$ 500,000

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LONG-TERM DEBT - Components (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Long-term debt, components
Total debt	$ 3,234,768	$ 3,308,715
Less debt issuance costs	(24,341)	(25,590)
Less debt discounts	(9,530)	(9,659)
Plus debt premiums	13,647	14,302
Total debt adjusted for debt issuance costs, discounts and premiums	3,214,544	3,287,768
Less current maturities	(75,718)	(87,587)
Long-term debt	$ 3,138,826	$ 3,200,181

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SHORT-TERM BORROWINGS (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Dec. 31, 2020
Short-term borrowings
Maturities of commercial paper issuances, not to exceed	397 days
Short-term borrowings	$ 79,968	$ 0
2018 Revolving Credit Agreement
Short-term borrowings
Available borrowing capacity	$ 570,000
Commercial Paper
Short-term borrowings
Weighted average interest rate	0.18%	0.00%
Short-term borrowings	$ 79,968	$ 0
Commercial Paper | 2018 Revolving Credit Agreement
Short-term borrowings
Available borrowing capacity	420,000
Maximum | Commercial Paper
Short-term borrowings
Maximum amount per commercial paper sublimit	$ 500,000

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ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS (Details) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Dec. 31, 2019 USD ($) item	Dec. 31, 2020 USD ($)
Aggregate carrying amounts of asset retirement obligations
Obligations at beginning of period		$ 138,089
Liabilities incurred		0
Liabilities settled		(135)
Accretion expense		1,411
Change in cash flow estimate		(54,324)
Total obligations at end of period	$ 85,041	85,041
Less current obligations at end of period	(6,679)	(6,679)		$ (11,044)
Long-term obligations at end of period	78,362	$ 78,362
Colowyo Mine
Asset Retirement And Environmental Reclamation Obligations
Number of mine pits in final reclamation | item			1
Aggregate carrying amounts of asset retirement obligations
Additional environmental reclamation obligation liability	$ 50,000
New Horizon Mine
Aggregate carrying amounts of asset retirement obligations
Additional environmental reclamation obligation liability			$ (22,400)

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OTHER DEFERRED CREDITS AND OTHER LIABILITIES (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Dec. 31, 2020
Deferred credits and other liabilities
Transmission easements	$ 19,531	$ 19,983
Operating lease liabilities - noncurrent	1,689	1,590
Contract liabilities (unearned revenue) - noncurrent	3,520	3,702
Customer deposits	8,900	7,712
Financial liabilities - reclamation	11,931	12,081
Deposits associated with generator interconnection requests	17,130	0
Other	13,650	9,532
Other	76,351	54,600
Transmission Right of Way Easements
Deferred credits and other liabilities
Total due for easement right of way	29,400
Transmission Right of Way Easements | Other Deferred Credits and Other Liabilities
Deferred credits and other liabilities
Transmission easements	$ 19,500	$ 20,000

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EMPLOYEE BENEFIT PLANS - Postretirement Benefits Other Than Pensions, Obligations (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2021 USD ($) plan
Medical Plans
Postretirement medical benefit and postemployment medical benefit obligations
Total postretirement and postemployment medical obligations at end of period	$ 10,538
Postretirement Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
Postretirement medical benefit obligation at beginning of period	9,985
Service cost	301
Interest cost	129
Benefit payments (net of contributions by participants)	(296)
Total postretirement and postemployment medical obligations at end of period	$ 10,119
Threshold percentage, unrecognized amount of actuarial gains and losses as a percentage of projected benefit obligation	10.00%
Postemployment Medical Benefit Plans
Postretirement medical benefit and postemployment medical benefit obligations
Total postretirement and postemployment medical obligations at end of period	$ 419
Non-bargaining unit employees | Medical Plans
POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Number of plans | plan	3
Non-bargaining unit employees | Medical 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) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Net unrecognized actuarial gains and losses
Amortization of prior service cost	$ 219	$ 177	$ 731	$ 1,110
Postretirement Medical Benefit Plans
Net unrecognized actuarial gains and losses
Accumulated other comprehensive loss at beginning of period			(841)
Amortization of prior service cost			(39)
Accumulated other comprehensive loss at end of period	$ (880)		$ (880)

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EMPLOYEE BENEFIT PLANS - NRECA Executive Benefit Restoration Plan, Obligations (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2021 USD ($)
Defined benefit plans, Plan Assets
Fair value of plan assets at beginning of period	$ 6,955
Employer contributions	806
Fair value of plan assets at end of period	7,822
Net liability recognized	991
NRECA Executive Benefit Restoration Plan
Defined Benefit Plans
Postretirement medical benefit obligation at beginning of period	7,379
Service cost	204
Interest cost	109
Actuarial loss	1,121
Total postretirement and postemployment medical obligations at end of period	$ 8,813
Defined benefit plans, Plan Assets
Threshold percentage, unrecognized amount of actuarial gains and losses as a percentage of projected benefit obligation	10.00%
Executive Benefit Restoration Plan
Defined Benefit Plans
Actuarial loss	$ (61)

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EMPLOYEE BENEFIT PLANS - NRECA Executive Benefit Restoration Plan, Actuarial Gains and Losses (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Net unrecognized actuarial gains and losses
Amortization of prior service cost	$ 219	$ 177	$ 731	$ 1,110
Amortization of actuarial loss			171
Curtailment and settlement			141
NRECA Executive Benefit Restoration Plan
Net unrecognized actuarial gains and losses
Accumulated other comprehensive loss at beginning of period			(4,873)
Amortization of prior service cost			459
Unrecognized actuarial loss			(1,121)
Accumulated other comprehensive loss at end of period	$ (5,223)		$ (5,223)

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REVENUE - Member Electric Sales (Details)	6 Months Ended
	Jun. 30, 2021 utilityMember demandRate billingCompany
Disaggregation of Revenue [Line Items]
Number of billing components of Class A rate schedule for electric power sales to Members | billingCompany	3
Number of demand rates | demandRate	2
Member Contracts Extending Through 2050
Disaggregation of Revenue [Line Items]
Number of contracts | utilityMember	42

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REVENUE - Revenue Reflected in Statement of Operations (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2021 USD ($) non-utilityMember	Jun. 30, 2020 USD ($)
Disaggregation of revenue
Recognition of deferred revenue			$ 40,790	$ 0
Other	$ 15,712	$ 10,034	30,712	20,924
Total non-member electric sales and other operating revenue	326,302	313,656	$ 652,274	633,122
Number of non-utility members from whom other operating revenue is received | non-utilityMember			2
Non-member electric sales
Disaggregation of revenue
Revenue from contract with customer	36,145	16,625	$ 74,319	32,438
Recognition of deferred revenue	19,956	0	40,790	0
Non-member electric sales | Long-term contracts
Disaggregation of revenue
Revenue from contract with customer	10,093	11,251	18,799	23,395
Non-member electric sales | Short-term contracts
Disaggregation of revenue
Revenue from contract with customer	6,096	5,374	14,730	9,043
Other
Disaggregation of revenue
Other	15,712	10,034	30,712	20,924
Total non-member electric sales and other operating revenue
Disaggregation of revenue
Total non-member electric sales and other operating revenue	$ 51,857	$ 26,659	$ 105,031	$ 53,362

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INCOME TAXES (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Income Tax Disclosure [Abstract]
Income tax expense (benefit)	$ 110	$ (121)	$ 219	$ (330)

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LEASES - Leasing Arrangements as Lessee (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2021 USD ($) lease	Jun. 30, 2020 USD ($)
Leases [Abstract]
Operating lease expense | $	$ 0.9	$ 0.7	$ 1.9	$ 1.6
Number of financing leases | lease			0

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LEASES - Lease Components (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Leases [Abstract]
Operating lease right-of-use assets	$ 9,237	$ 9,223
Less: Accumulated amortization	(1,549)	(1,238)
Net operating lease right-of-use assets	7,688	7,985
Operating lease liabilities - current	(464)	(526)
Operating lease liabilities - noncurrent	(1,689)	(1,590)
Total operating lease liabilities	$ (2,153)	$ (2,116)
Weighted average remaining lease term (years)	7 years 8 months 12 days	7 years 7 months 6 days
Weighted average discount rate	3.75%	3.84%
Operating lease right-of-use asset, Statement of Financial Position line item	Other	Other
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:LiabilitiesCurrent	us-gaap:LiabilitiesCurrent
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:DeferredLongTermLiabilityCharges	us-gaap:DeferredLongTermLiabilityCharges

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LEASES - Future Minimum Lease Commitments (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Future expected minimum lease commitments under operating leases
Year 1	$ 550
Year 2	415
Year 3	374
Year 4	247
Year 5	91
Thereafter	650
Total lease payments	2,327
Less imputed interest	(174)
Total	$ 2,153	$ 2,116

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LEASES - Leasing Arrangements as Lessor (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Leases [Abstract]
Lease revenue	$ 1.7	$ 1.6	$ 3.5	$ 3.2

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FAIR VALUE (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Fair value:
Cash and cash equivalents	$ 105,900	$ 94,600
Cost
Fair value:
Marketable securities	513	491
Total long-term debt	3,234,768	3,308,715
Cost | EBT Trust Investments
Fair value:
Marketable securities	7,822	6,955
Estimated Fair Value
Fair value:
Marketable securities	556	478
Total long-term debt	3,825,737	3,908,497
Estimated Fair Value | EBT Trust Investments
Fair value:
Marketable securities	$ 7,743	$ 6,955

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VARIABLE INTEREST ENTITIES - Consolidated Entities (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Consolidated Variable Interest Entities
Net electric plant	$ 3,345,763		$ 3,345,763		$ 3,352,706
Noncontrolling interest	115,569		115,569		114,851
Long-term debt	3,138,826		3,138,826		3,200,181
Accrued interest	25,892		25,892		27,520
Interest	35,088	$ 36,392	70,229	$ 73,298
Springerville Partnership | Reportable Legal Entities
Consolidated Variable Interest Entities
Net electric plant	749,204		749,204		758,273
Noncontrolling interest	115,571		115,571		114,852
Long-term debt	300,789		300,789		342,355
Accrued interest	8,721		8,721		$ 9,942
Depreciation, amortization and depletion	4,535	4,535	9,069	9,069
Interest	$ 4,956	$ 5,651	$ 10,141	$ 11,511
Springerville Partnership | 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 | Springerville Partnership
Consolidated Variable Interest Entities
Ownership interest held by parent	100.00%		100.00%

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LEGAL (Details)	6 Months Ended
	Jun. 30, 2021	Apr. 30, 2022	Apr. 30, 2021
Other legal
Rate reduction due to settlement			2.00%
Subsequent Event
Other legal
Rate reduction due to settlement		4.00%
Members | Maximum
Other legal
Annual allowance for self-supply of a member's electric power requirements	5.00%