tris-20240331

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 March 31, 2024


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

For the transition period from to

Commission File No. 333-212006

TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

(Exact name of registrant as specified in its charter)


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

(303) 452-6111

(Registrant’s telephone number, including area code)

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

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

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

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

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

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

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


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

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

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TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.

INDEX TO QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED MARCH 31, 2024


		Page Number
PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Financial Position	1
	Consolidated Statements of Operations (Unaudited)	2
	Consolidated Statements of Comprehensive Income (Unaudited)	3
	Consolidated Statements of Equity (Unaudited)	4
	Consolidated Statements of Cash Flows (Unaudited)	5
	Notes to Unaudited Consolidated Financial Statements	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	33
SIGNATURES

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GLOSSARY

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


Abbreviations or Acronyms						Definition
2022 Revolving Credit Agreement						Amended and Restated Credit Agreement, dated as of April 25, 2022, between us and CFC, as administrative agent
ASC						Accounting Standards Codification
ASU						Accounting Standards Update
Basin						Basin Electric Power Cooperative
Board						Board of Directors
CFC						National Rural Utilities Cooperative Finance Corporation
CoBank						CoBank, ACB
Colowyo Coal						Colowyo Coal Company L.P., a subsidiary of ours
COPUC						Colorado Public Utilities Commission
D.C. Circuit Court of Appeals						United States Court of Appeals for the District of Columbia Circuit
DSR						Debt Service Ratio (as defined in our Master Indenture)
ECR						Equity to Capitalization Ratio (as defined in our Master Indenture)
EPA						Environmental Protection Agency
FERC						Federal Energy Regulatory Commission
Fitch						Fitch Ratings Inc.
FPA						Federal Power Act, as amended
GAAP						accounting principles generally accepted in the United States
kWh						kilowatt hour
LPEA						La Plata Electric Association, Inc.
Master Indenture						Master First Mortgage Indenture, Deed of Trust and Security Agreement, dated effective as of December 15, 1999, between us and U.S. Bank Trust Company, National Association, as successor trustee
MBPP						Missouri Basin Power Project
Members						our Utility Members and Non-Utility Members
MPEI						Mountain Parks Electric, Inc.
Moody’s						Moody’s Investors Services, Inc.
MW						megawatt
MWh						megawatt hour
Non-Utility Members						our non-utility members
NRPPD						Northwest Rural Public Power District
New ERA Program						U.S. Department of Agriculture's Empowering Rural America Program
OATT						Open Access Transmission Tariff
Phase I 2023 ERP						Phase I of our 2023 Electric Resource Plan filed with the COPUC
S&P						S & P Global Ratings
Salt River Project						Salt River Project Agricultural Improvement and Power District
SEC						Securities and Exchange Commission
Springerville Partnership						Springerville Unit 3 Partnership LP, a subsidiary of ours
Springerville Unit 3						Springerville Generating Station Unit 3
Term SOFR						the implied rate on the future movement in the Secured Overnight Financing Rate (or "SOFR") over a future reference period
Tri-State, We, Our, Us, the Association						Tri-State Generation and Transmission Association, Inc.
United Power						United Power, Inc.
Utility Members						our electric distribution member systems, consisting of both Class A members and Class B members

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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, member withdraws 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.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Financial Position

(dollars in thousands)


	March 31, 2024		December 31, 2023
ASSETS	(Unaudited)
Property, plant and equipment
Electric plant
In service	$	5,759,052	$	5,722,679
Construction work in progress	159,604		163,954
Total electric plant	5,918,656		5,886,633
Less allowances for depreciation and amortization	(2,761,762)		(2,739,924)
Net electric plant	3,156,894		3,146,709
Other plant	950,834		952,318
Less allowances for depreciation, amortization and depletion	(720,332)		(711,896)
Net other plant	230,502		240,422
Total property, plant and equipment	3,387,396		3,387,131
Other assets and investments
Investments in other associations	185,724		187,684
Investments in and advances to coal mines	1,537		1,619
Restricted cash and investments	188		3,408
Other noncurrent assets	15,361		15,264
Total other assets and investments	202,810		207,975
Current assets
Cash and cash equivalents	110,400		106,005
Restricted cash and investments	20,357		605
Deposits and advances	77,913		37,455
Accounts receivable—Utility Members	94,392		101,394
Other accounts receivable	16,118		23,123

Coal inventory	57,958		54,979
Materials and supplies	108,452		106,893
Total current assets	485,590		430,454
Deferred charges
Regulatory assets	911,418		919,483
Prepayment—NRECA Retirement Security Plan	4,029		5,372
Other	44,952		36,121
Total deferred charges	960,399		960,976
Total assets	$	5,036,195	$	4,986,536
EQUITY AND LIABILITIES
Capitalization
Patronage capital equity	$	969,553	$	984,581
Accumulated other comprehensive loss	(949)		(839)
Noncontrolling interest	126,945		134,269
Total equity	1,095,549		1,118,011
Long-term debt	2,741,491		2,896,506
Total capitalization	3,837,040		4,014,517
Current liabilities
Utility Member advances	12,952		14,333
Accounts payable	136,313		123,674
Short-term borrowings	272,962		184,305
Accrued expenses	33,774		39,268
Current asset retirement obligations	19,783		21,635
Accrued interest	43,469		24,549
Accrued property taxes	26,169		31,986
Current maturities of long-term debt	341,159		223,523
Total current liabilities	886,581		663,273
Deferred credits and other liabilities
Regulatory liabilities	2,199		2,317
Deferred income tax liability	15,223		15,223
Asset retirement and environmental reclamation obligations	201,912		195,566
Other	81,610		84,125
Total deferred credits and other liabilities	300,944		297,231
Accumulated postretirement benefit and postemployment obligations	11,630		11,515
Total equity and liabilities	$	5,036,195	$	4,986,536

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

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Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Operations (Unaudited)

(dollars in thousands)


	Three Months Ended March 31,
	2024		2023
Operating revenues
Utility Member electric sales	$	295,826	$	292,176
Non-member electric sales	35,619		41,950
Rate stabilization	—		11,757
Provision for rate refunds	—		310
Other	20,104		17,858
	351,549		364,051

Operating expenses
Purchased power	93,070		100,825
Fuel	76,340		81,930
Production	42,126		43,552
Transmission	47,558		49,028
General and administrative	21,733		18,498
Depreciation, amortization and depletion	44,624		42,381
Coal mining	1,078		1,639
Other	2,950		6,295
	329,479		344,148

Operating margins	22,070		19,903

Other income
Interest	1,499		1,330
Capital credits from cooperatives	1,281		1,952

Other income	5,320		1,555
	8,100		4,837

Interest expense
Interest	44,326		40,764
Interest charged during construction	(1,832)		(983)
	42,494		39,781

Income tax expense	—		22

Net margins including noncontrolling interest	(12,324)		(15,063)
Net margin attributable to noncontrolling interest	(2,704)		(2,394)
Net margins attributable to the Association	$	(15,028)	$	(17,457)

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

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Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Comprehensive Income (Loss) (Unaudited)

(dollars in thousands)


	Three Months Ended March 31,
	2024		2023
Net margins including noncontrolling interest	$	(12,324)	$	(15,063)
Other comprehensive loss:
Unrealized gain on securities available for sale	10		61



Amortization of prior service credit on postretirement benefit obligation included in net margin	(409)		(409)




Amortization of prior service cost on executive benefit restoration obligation included in net margin	289		289
Other comprehensive loss	(110)		(59)

Comprehensive loss including noncontrolling interest	(12,434)		(15,122)
Net comprehensive income attributable to noncontrolling interest	(2,704)		(2,394)

Comprehensive loss attributable to the Association	$	(15,138)	$	(17,516)

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

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Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Equity (Unaudited)

(dollars in thousands)


	Three Months Ended March 31,
	2024		2023
Patronage capital equity at beginning of period	$	984,581	$	984,865

Net margins attributable to the Association	(15,028)		(17,457)

Patronage capital equity at end of period	969,553		967,408

Accumulated other comprehensive loss at beginning of period	(839)		(468)
Unrealized gain on securities available for sale	10		61

Reclassification adjustment of prior service credit on postretirement benefit obligation included in net margin	(409)		(409)


Reclassification adjustment for prior service cost on executive benefit restoration obligation included in net margin	289		289




Accumulated other comprehensive loss at end of period	(949)		(527)

Noncontrolling interest at beginning of period	134,269		126,180

Net comprehensive income attributable to noncontrolling interest	2,704		2,394
Equity distribution to noncontrolling interest	(10,028)		(949)
Noncontrolling interest at end of period	126,945		127,625
Total equity at end of period	$	1,095,549	$	1,094,506

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

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Tri-State Generation and Transmission Association, Inc.

Consolidated Statements of Cash Flows (Unaudited)

(dollars in thousands)


	Three Months Ended March 31,
	2024		2023
Operating activities
Net margins including noncontrolling interest	$	(12,324)	$	(15,063)
Adjustments to reconcile net margins to net cash provided by operating activities:
Depreciation, amortization and depletion	44,624		42,381

Amortization of NRECA Retirement Security Plan prepayment	1,343		1,343
Amortization of debt issuance costs	620		551



Deposits associated with generator interconnection requests	1,880		1,840
Rate stabilization revenue	—		(11,757)
Capital credit allocations from cooperatives and income from coal mines under refund distributions	2,042		1,348
Changes in operating assets and liabilities:
Accounts receivable	14,008		30,174
Coal inventory	(2,979)		764
Materials and supplies	(1,559)		(9,677)
Accounts payable and accrued expenses	(13,748)		(15,914)
Accrued interest	18,920		17,647
Accrued property taxes	(5,817)		(4,520)

Other	(11,396)		8,413
Net cash provided by operating activities	35,614		47,530

Investing activities
Purchases of plant	(47,993)		(33,945)
Sale of nonutility assets	3,061		—
Changes in deferred charges	(3,398)		(11,931)

Net cash used in investing activities	(48,330)		(45,876)

Financing activities
Changes in Member advances	(1,381)		(613)
Payments of long-term debt	(37,755)		(53,507)
Proceeds from issuance of long-term debt	—		100,000
Debt issuance costs	(8)		(515)
Change in short-term borrowings, net	88,556		(25,647)
Retirement of patronage capital	(5,214)		(5,446)
Equity distribution to noncontrolling interest	(10,028)		(949)
Other	(527)		(482)
Net cash provided by financing activities	33,643		12,841

Net increase in cash, cash equivalents and restricted cash and investments	20,927		14,495
Cash, cash equivalents and restricted cash and investments – beginning	110,018		110,682
Cash, cash equivalents and restricted cash and investments – ending	$	130,945	$	125,177

Supplemental cash flow information:
Cash paid for interest	$	24,656	$	22,519
Cash paid for income taxes	$	—	$	—

Supplemental disclosure of noncash investing and financing activities:
Change in plant expenditures included in accounts payable	$	(439)	$	(1,334)

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

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Tri-State Generation and Transmission Association, Inc.

Notes to Unaudited Consolidated Financial Statements

For the Three Months Ended March 31, 2024 and 2023

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, 2023 filed with the SEC. In the opinion of management, all adjustments, consisting of normal recurring accruals considered necessary for a fair presentation, have been included. Our consolidated financial position as of March 31, 2024, results of operations for the three months ended March 31, 2024 and 2023, and cash flows for the three months ended March 31, 2024 and 2023 are not necessarily indicative of the results that may be expected for an entire year or any other period.

Basis of Consolidation

We are a taxable wholesale electric power generation and transmission cooperative operating on a not-for-profit basis serving large portions of Colorado, Nebraska, New Mexico and Wyoming. We were incorporated under the laws of the State of Colorado in 1952. We have three classes of membership: Class A - utility full requirements members, Class B - utility partial requirements members, and non-utility members. As of March 31, 2024, we had forty-two electric distribution member systems who are Class A members to which we provided electric power pursuant to long-term wholesale electric service contracts. We currently have no Class B members. We have three non-utility members (“Non-Utility Members”). Our Class A members and any Class B members are collectively referred to as our “Utility Members.” Our Class A members, any Class B members, and Non-Utility Members are collectively referred to as our “Members.” Our rates are subject to regulation by the Federal Energy Regulatory Commission (“FERC”). On December 23, 2019, our stated rate to our Class A members was filed at FERC and was accepted by FERC on March 20, 2020. On August 2, 2021, FERC approved our settlement agreement related to our stated rate to our Class A members.

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 intercompany balances and transactions in consolidation.

Jointly Owned Facilities

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

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Our share in each jointly owned facility is as follows as of March 31, 2024 (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	%	$	392,510	$	360,890	$	—
MBPP - Laramie River Station	28.50	%	535,241		348,326		6,319
Total			$	927,751	$	709,216	$	6,319

Accounting Pronouncement - Not Yet Adopted

In December 2023, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update (“ASU”) 2023-09 – Income Taxes (Topic 740): Improvements to Income Tax Disclosures. The purpose of ASU 2023-09 is to enhance the transparency and decision usefulness of income tax disclosures by providing additional information related to the following:

(1) Rate reconciliation: ASU 2023-09 requires a tabular rate reconciliation using both percentages and dollar amounts of the reported income tax expense (or benefit) from continuing operations to the product of income (or loss) from continuing operating before income taxes and the applicable statutory federal income tax rate of the county of domicile using specific categories. The following specific categories are required to be disclosed in the rate reconciliation; state and local income tax (qualitative disclosure required for states that make up over 50% of this category), foreign tax effect, effect of changes in tax laws or rates enacted in the current period, effect of cross-border tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, changes in unrecognized tax benefits, and any other item that meets the 5 percent threshold.

(2) Income taxes paid: ASU 2023-09 requires all reporting entities to disclose the year-to-date amount of income taxes paid (net of refunds received) disaggregated by federal, state, and foreign jurisdictions. It also requires additional disaggregation of income taxes paid to an individual jurisdiction equal to or greater than 5 percent of total income taxes paid (net of refunds). Entities are required to disclose pre-tax income (or loss) from continuing operations disaggregated by domestic and foreign along with income tax expense (or benefit) disaggregated by federal, state, and foreign components.

ASU 2023-09 is effective for public business entities for annual periods beginning after December 15, 2024, with early adoption and retrospective or prospective application permitted. We have evaluated the impact of ASU 2023-09 and believe that the adoption of this update will not have a material impact on our consolidated financial statement disclosures.

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.

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


	March 31, 2024		December 31, 2023
Regulatory assets
Deferred income tax expense (1)	$	15,223	$	15,223
Deferred prepaid lease expense – Springerville Unit 3 Lease (2)	73,979		74,551
Acquisition costs – J.M. Shafer (3)	37,037		37,749
Acquisition costs – Colowyo Coal (4)	32,803		33,062
Deferred debt prepayment transaction costs (5)	104,260		106,417
Deferred Holcomb expansion impairment loss (6)	73,626		74,795
New Horizon Mine environmental obligation (7)	44,869		44,869
Unrecovered plant (8)	529,621		532,817
Total regulatory assets	911,418		919,483

Regulatory liabilities
Interest rate swap - realized gain (9) and other	1,736		1,854

Membership withdrawal (10)	463		463
Total regulatory liabilities	2,199		2,317
Net regulatory asset	$	909,219	$	917,166

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

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

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

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

(5)Represents transaction costs that we incurred related to the prepayment of our long-term debt in 2014. These costs are being amortized to depreciation, amortization and depletion expense in the amount of $8.6 million annually over the 21.4-year period ending in 2036 and recovered from our Utility Members through rates.

(6)Represents deferral of the impairment loss related to development costs, including costs for the option to purchase development rights for the expansion of the Holcomb Generating Station. The regulatory asset for the deferred impairment loss is being amortized to depreciation, amortization and depletion expense in the amount of $4.7 million annually over the 20-year period ending in 2039 and recovered from our Utility Members through rates.

(7)Represents $44.9 million of New Horizon Mine environmental obligation expense that was recognized as a regulatory item in 2023. The regulatory asset for the deferred environmental obligation expense will be amortized to expense in the amount of $1.8 million annually over 25 years.

(8)Represents deferral of the impairment losses and other closure costs related to the early retirement of the Escalante, Rifle and Craig Generating Station Units 2 and 3. The deferred impairment loss for Escalante Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $12.2 million annually over the 25-year period ending in December 2045, which was the depreciable life of the Escalante Generating Station, and recovered from our Utility Members through rates. The annual amortization approximates the former annual Escalante Generating Station depreciation for the remaining life of the asset. The deferred impairment loss for Rifle Generating Station is being amortized to depreciation, amortization and depletion expense in the amount of $0.6 million annually through December 2028, which was the depreciable life of the Rifle Generating Station, and recovered from our Utility Members in rates. We recognized the early retirement of Craig Generating Station Units 2 and 3 and concluded the impairment of incurred costs is probable of recovery through future rates. We recognized an impairment loss of $261.6 million and deferred the loss in accordance with accounting for rate regulation. The deferred impairment loss will be amortized to depreciation, amortization and depletion expense beginning in October 2028 through 2039 for Craig Generating Station Unit 2 and

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January 2030 through 2043 for Craig Generating Station Unit 3. These amortization periods are the depreciable lives of Craig Generating Station Unit 2 and 3. The annual amortization is expected to approximate the former annual Craig Generation Station Unit 2 and 3 depreciation for the remaining life of the asset.

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

(10) Represents the remaining balance of the deferred recognition of other operating revenues related to the withdrawal of former Utility Members from membership in us. The deferred membership withdrawal income will be refunded to Utility Members through reduced rates when recognized in operating revenues in future periods with the oldest vintage year used first.

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):


	March 31, 2024		December 31, 2023
Basin Electric Power Cooperative	$	135,652	$	135,652
National Rural Utilities Cooperative Finance Corporation - patronage capital	12,451		12,451
National Rural Utilities Cooperative Finance Corporation - capital term certificates	15,054		15,054
CoBank, ACB	16,946		18,809
Other	5,621		5,718
Investments in other associations	$	185,724	$	187,684

Our investments in other associations are considered equity securities without readily determinable fair values, and as such are measured at cost minus impairment. We have evaluated these investments for indicators of impairment. There were no impairments of these investments recognized during the three months ended March 31, 2024 or during 2023.

NOTE 4 – CASH, CASH EQUIVALENTS AND RESTRICTED CASH AND INVESTMENTS

We consider highly liquid investments with an original maturity of three months or less to be cash equivalents. The fair value of cash equivalents approximates their carrying values due to their short-term maturity.

Restricted cash and investments represent funds designated by our Board for specific uses and funds restricted by contract or other legal reasons. A portion of the funds are amounts that have been restricted by contract that are expected to be settled within one year. These funds are therefore classified as current on our consolidated statements of financial position. The other 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):


	March 31, 2024		December 31, 2023
Cash and cash equivalents	$	110,400	$	106,005
Restricted cash and investments - current	20,357		605
Restricted cash and investments - noncurrent	188		3,408
Cash, cash equivalents and restricted cash and investments	$	130,945	$	110,018

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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 three months ended March 31, 2024, we recognized $0.3 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):


	March 31, 2024		December 31, 2023
Accounts receivable - Utility Members	$	94,392	$	101,394

Other accounts receivable - trade:
Non-member electric sales	4,092		9,657
Other	9,531		11,077
Total other accounts receivable - trade	13,623		20,734
Other accounts receivable - nontrade	2,495		2,389
Total other accounts receivable	$	16,118	$	23,123

Contract liabilities (unearned revenue)	$	3,894	$	4,159

NOTE 6 – OTHER DEFERRED CHARGES

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


	March 31, 2024		December 31, 2023
Preliminary surveys and investigations	$	13,514	$	12,845
Advances to operating agents of jointly owned facilities	6,148		2,750
Operating lease right-of-use assets	6,216		6,477
Other	19,074		14,049
Total other deferred charges	$	44,952	$	36,121

We make expenditures for preliminary surveys and investigations for the purpose of determining the feasibility of contemplated generation and transmission projects. If construction results, the preliminary survey and investigation expenditures will be reclassified to electric plant - construction work in progress. If the work is abandoned, the related preliminary survey and investigation expenditures will be charged to the appropriate operating expense account or the expense could be deferred as a regulatory asset to be recovered from our Utility Members through rates subject to approval by our Board and FERC.

We make advance payments to the operating agents of jointly owned facilities to fund our share of costs expected to be incurred under each project including MBPP – Laramie River Station, and Yampa Project – Craig Generating Station Units 1 and 2. We also make advance payments to the operating agent of Springerville Unit 3.

A right-of-use asset represents a lessee’s right to control the use of the underlying asset for the lease term. Right-of-use assets are included in other deferred charges and presented net of accumulated amortization. See Note 14 – Leases.

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NOTE 7 – LONG-TERM DEBT

We have $2.7 billion of long-term debt which consists of mortgage notes payable, pollution control revenue bonds and the Springerville certificates. The mortgage notes payable and pollution control revenue bonds are secured on a parity basis by a Master First Mortgage Indenture, Deed of Trust and Security Agreement (“Master Indenture”). Substantially all our assets, rents, revenues and margins are pledged as collateral. The Springerville certificates are secured by the assets of Springerville Unit 3. All long-term debt contains certain restrictive financial covenants, including a debt service ratio ("DSR") requirement on an annual basis and an equity to capitalization ratio ("ECR") requirement of at least 18 percent at the end of each fiscal year. Other than long-term debt for the Springerville certificates that has a DSR requirement of at least 1.02 on an annual basis, all other long-term debt contains a DSR requirement of at least 1.10 on an annual basis. A DSR below 1.025 under the Master Indenture would require us to transfer all cash to a special fund managed by the trustee of the Master Indenture.

We have a secured revolving credit facility with National Rural Utilities Cooperative Finance Corporation (“CFC”), as lead arranger and administrative agent, in the amount of $520 million (“2022 Revolving Credit Agreement”) that expires on April 25, 2027 and includes a swingline sublimit of $125 million, a letter of credit sublimit of $75 million, and a commercial

paper back-up sublimit of $500 million. As of March 31, 2024, we had $247.1 million in availability (including $227 million under the commercial paper back-up sublimit) under the 2022 Revolving Credit Agreement.

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


	March 31, 2024		December 31, 2023
Total debt	$	3,099,679	$	3,137,534
Less debt issuance costs	(19,111)		(19,723)
Less debt discounts	(8,605)		(8,678)
Plus debt premiums	10,687		10,896
Total debt adjusted for debt issuance costs, discounts and premiums	3,082,650		3,120,029
Less current maturities	(341,159)		(223,523)
Long-term debt	$	2,741,491	$	2,896,506

NOTE 8 – SHORT-TERM BORROWINGS

We have a commercial paper program under which we issue unsecured commercial paper in aggregate amounts not exceeding the commercial paper back-up sublimit under our 2022 Revolving Credit Agreement, which is the lesser of $500 million or the amount available under our 2022 Revolving Credit Agreement. The commercial paper issuances are used to provide an additional financing source for our short-term liquidity needs. The maturities of the commercial paper issuances vary but may not exceed 397 days from the date of issue. The commercial paper notes are classified as current and are included in current liabilities as short-term borrowings on our consolidated statements of financial position.

Short-term borrowings consisted of the following (dollars in thousands):


	March 31, 2024			December 31, 2023
Commercial paper outstanding, net of discounts	$	272,862		$	184,205
Short-term borrowings - other	$	100		$	100
Weighted average interest rate	5.49		%	5.62		%

As of March 31, 2024, we had $273 million commercial paper outstanding and $227 million of the commercial paper back-up sublimit remained available under the 2022 Revolving Credit Agreement. See Note 7 – Long-Term Debt.

NOTE 9 – ASSET RETIREMENT AND ENVIRONMENTAL RECLAMATION OBLIGATIONS

We account for current obligations associated with the future retirement of tangible long-lived assets and environmental reclamation in accordance with the accounting guidance relating to asset retirement and environmental obligations. This guidance requires that legal obligations associated with the retirement of long-lived assets be recognized at fair value at the time the liability is incurred and capitalized as part of the related long-lived asset. Over time, the liability is adjusted to its present value by recognizing accretion expense and the capitalized cost of the long-lived asset is depreciated in a manner consistent with the depreciation of the underlying physical asset. In the absence of quoted market prices, we determine

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fair value by using present value techniques in which estimates of future cash flows associated with retirement activities are discounted using a credit adjusted risk-free rate and market risk premium. Upon settlement of an asset retirement obligation, we will apply payment against the estimated liability and incur a gain or loss if the actual retirement costs differ from the estimated recorded liability.

Environmental reclamation costs are accrued based on management’s best estimate at the end of each period of the costs expected to be incurred. Such cost estimates may include ongoing care, maintenance and monitoring costs. Changes in reclamation estimates are reflected in earnings in the period an estimate is revised.

Coal mines: We have asset retirement obligations for the final reclamation costs and environmental obligations for post-reclamation monitoring related to the Colowyo Mine and the New Horizon Mine. The New Horizon Mine is currently in post-reclamation monitoring. Two pits at the Colowyo Mine are in final reclamation with the other pit still being actively mined.

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

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


	Three Months Ended March 31, 2024
Obligations at beginning of period	$	217,201
Liabilities incurred	3,456
Liabilities settled	(752)
Accretion expense	1,790

Total obligations at end of period	$	221,695
Less current obligations at end of period	(19,783)
Long-term obligations at end of period	$	201,912

The New Horizon Mine environmental remediation liability is $67.3 million as of March 31, 2024. Of this amount, $36.8 million is recorded on a discounted basis, using a discount rate of 3.25 percent, with total estimated undiscounted future cash outflows of $57.9 million. Environmental obligation expense is included in other operating expenses on our consolidated statements of operations. In the fourth quarter of 2023, we reversed the $44.9 million of environmental obligation expense that was recorded in 2022 as a regulatory item to be amortized to expense over 25 years and recovered from our Utility Members through rates. We continue to evaluate the New Horizon Mine and Colowyo Mine post reclamation obligations and will make adjustments to these obligations as needed.

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

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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):


	March 31, 2024		December 31, 2023
Transmission easements	$	17,949	$	17,862
OATT deposits	29,707		27,872
Financial liabilities - reclamation	13,128		16,895
Customer deposits	12,079		12,091
Contract liabilities (unearned revenue) - noncurrent	2,998		3,125
Operating lease liabilities - noncurrent	1,312		1,396
Other	4,437		4,884
Total other deferred credits and other liabilities	$	81,610	$	84,125

In 2015, we renewed transmission right-of-way easements on tribal nation lands where certain of our electric transmission lines are located. $26.8 million will be paid by us for these easements from 2024 through the individual easement terms ending between 2036 and 2040. The present values for the remaining easement payments were $17.9 million as of March 31, 2024 and December 31, 2023 which are recorded as other deferred credits and other liabilities.

OATT deposits represent refundable transmission customer deposits related to interconnection and transmission requests from third parties. An OATT deposit is refundable should the interconnection or transmission request not move forward.

Financial liabilities - reclamation represent financial obligations that we have for our share of reclamation costs at jointly owned facilities in which we have undivided interests in.

A lease liability represents a lessee’s obligation to make lease payments over the lease term. The long-term portion of our lease liabilities are included in other deferred credits and other liabilities and the current portion of our lease liabilities are included in current liabilities. See Note 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.

NOTE 11 – EMPLOYEE BENEFIT PLANS

Postretirement Benefits Other Than Pensions

We sponsor three medical plans for all non-bargaining unit employees under the age of 65. Two of the plans provide postretirement medical benefits to full-time non-bargaining unit employees and retirees who receive benefits under those plans, who have attained age 55, and who elect to participate. All three of these non-bargaining unit medical plans offer post employment medical benefits to employees on long-term disability. The plans were unfunded as of March 31, 2024, are contributory (with retiree premium contributions equivalent to employee premiums, adjusted annually) and contain other cost-sharing features such as deductibles. As of June 30, 2021, the plans ceased to provide postretirement medical benefits for employees who retire after June 30, 2021.

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


	Three Months Ended March 31, 2024
Postretirement medical benefit obligation at beginning of period	$	924

Interest cost	14
Benefit payments (net of contributions by participants)	(90)


Postretirement medical benefit obligation at end of period	$	848
Postemployment medical benefit obligation at end of period	243
Total postretirement and postemployment medical obligations at end of period	$	1,091

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

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

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


	Three Months Ended March 31, 2024
Amounts included in accumulated other comprehensive income at beginning of period	$	1,114
Amortization of prior service credit into other income	(409)



Amounts included in accumulated other comprehensive income at end of period	$	705

Defined Benefit Plans

We participate in the NRECA Pension Restoration Plan and the NRECA Executive Benefit Restoration Plan, both of which are intended to provide a supplemental benefit to the defined benefit plan for an eligible group of highly compensated employees. Eligible employees include the Chief Executive Officer and any other employees that become eligible. All our executive employees with a hire date prior to May 1, 2021 participate in one of the following pension restoration plans: the NRECA Pension Restoration Plan or the NRECA Executive Benefit Restoration Plan. Eligibility is determined annually and is based on January 1 base salary that exceeds the limits of the defined benefit plan. Employees hired May 1, 2021 or later are not eligible for either plan.

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


	Three Months Ended March 31, 2024
Executive benefit restoration obligation at beginning of period	$	10,158
Service cost	81
Interest cost	110




Executive benefit restoration at end of period	$	10,349
Fair value of plan assets at beginning of period	$	10,298


Actual return on plan assets	64
Fair value of plan assets at end of period	$	10,362
Net liability recognized at end of period	$	(13)

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

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

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


	Three Months Ended March 31, 2024
Accumulated other comprehensive loss at beginning of period	$	(1,639)

Amortization of prior service cost into other income	289



Accumulated other comprehensive loss at end of period	$	(1,350)

NOTE 12 – REVENUE

Revenue from Contracts with Customers

Our revenues are derived primarily from the sale of wholesale electric service to our Utility Members pursuant to long-term wholesale electric service contracts. Our contracts with our Utility Members extend through 2050.

Member electric sales

Revenues from wholesale electric power sales to our Utility Members are primarily from our Class A rate schedule filed with FERC. Our Class A rate schedule for electric power sales to our Utility Members consist of three billing components: an energy rate and two demand rates. Our Class A rate schedule is variable and is approved by our Board and FERC. Energy and demand have the same pattern of transfer to our Utility Members and are both measurements of the electric power provided to our Utility Members. Therefore, the provision of electric power to our Utility Members is one performance obligation. Prior to our Utility Members’ requirement for electric power, we do not have a contractual right to consideration as we are not obligated to provide electric power until the Utility Member requires each incremental unit of electric power. We transfer control of the electric power to our Utility Members over time and our Utility Members simultaneously receive and consume the benefits of the electric power. Progress toward completion of our performance obligation is measured using the output method, meter readings are taken at the end of each month for billing purposes, energy and demand are determined after the meter readings and Utility Members are invoiced based on the meter reading. Payments from our Utility Members are received

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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 March 31,
	2024		2023
Non-member electric sales:
Long-term contracts	$	21,376	$	11,215
Short-term contracts	14,243		30,735
Rate stabilization	—		11,757
Provision for rate refunds	—		310
Coal sales	1,643		1,079
Other	18,461		16,779
Total non-member electric sales and other operating revenue	$	55,723	$	71,875

Non-member electric sales

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

Coal sales

Coal sales revenue results from the sale of coal from the Colowyo Mine to third parties. We have an obligation to deliver coal and progress of completion toward our performance obligation is measured using the output method. Our performance obligation is completed as coal is delivered. We recognize coal sales revenue in other operating revenue on our consolidated statements of operations.

Other operating revenue

Other operating revenue consists primarily of wheeling and transmission revenue. Other operating revenue also includes revenue we receive from our Non-Utility Members. Wheeling revenue is earned when we charge other energy companies for transmitting electricity over our transmission lines (payments are received in accordance with the contract terms which is within 20 days of the date the invoice is received). Transmission revenue is from Southwest Power Pool’s scheduling of transmission across our transmission assets in the Eastern Interconnection because of our membership in it (Southwest Power Pool collects the revenue from the customer and pays us for the scheduling, system control, dispatch transmission service, and the annual transmission revenue requirement). Each of these services or goods are provided over time and progress toward completion of our performance obligations are measured using the output method.

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. We adopted the normalization method January 1, 2020 pursuant to FERC regulation. Our subsidiaries not subject to FERC regulation continued to use a flow-through method for recognizing deferred income taxes whereby changes in deferred tax assets or liabilities result in the establishment of a regulatory asset or liability, as approved by our Board. A regulatory asset or liability associated with deferred income taxes generally represents the future increase or decrease in income taxes payables that will be settled or received through future rate revenues.

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Under ASC 740-270, we calculate an estimate of the provision for income taxes during interim reporting periods by applying an estimate of the annual effective tax rate for the full fiscal year to income or loss (pretax income or loss excluding unusual or infrequently occurring discrete items) for the reporting period, after regulatory affect. Our consolidated statements of operations included no income tax expense or benefit for the three months ended March 31, 2024 and an income tax expense of $22 thousand for the comparable period in 2023.

On August 16, 2022, the Inflation Reduction Act of 2022 (the "IRA") was enacted into law. The IRA enacted many provisions intended to mitigate climate change by providing various sources of funding and tax credit incentives for investments designed to reduce greenhouse gas emissions. These provisions do not impact our current consolidated financial statements but could affect future financial statements due to the impact of such investments. These provisions are subject to regulations and other guidance to be released by the U.S. Department of the Treasury, the U.S. Department of Agriculture and other governmental agencies over time. We are monitoring developments and evaluating opportunities to utilize these incentives. In March 2024, we received an Invitation to Proceed from the U.S. Department of Agriculture to complete the New Empowering Rural America ("New ERA") Program Application. The New ERA Program implements the $9.7 billion funded in the IRA.

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 accrued expenses and the long-term portion of lease liabilities is included in other deferred credits and other liabilities on our consolidated statements of financial position.

We have elected to apply the short-term lease exception for contracts that have a lease term of twelve months or less and do not include an option to purchase the underlying asset. Therefore, we do not recognize a right-of-use asset or lease liability for such contracts. We recognize short-term lease payments as expense on a straight-line basis over the lease term. Variable lease payments that do not depend on an index or rate are recognized as expense.

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 $0.6 million for both the three months ended March 31, 2024 and 2023. Rent expense is included in various categories of operating expenses on our consolidated statements of operations based on the type and purpose of the lease. As of March 31, 2024, there were no arrangements accounted for as finance leases.

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


	March 31, 2024			December 31, 2023
Operating leases
Operating lease right-of-use assets	$	9,061		$	9,072
Less: Accumulated amortization	(2,845)			(2,595)
Net operating lease right-of-use assets	$	6,216		$	6,477

Operating lease liabilities - current	$	(344)		$	(371)
Operating lease liabilities - noncurrent	(1,312)			(1,396)
Total operating lease liabilities	$	(1,656)		$	(1,767)

Operating leases
Weighted average remaining lease term (years)	7.5			7.0
Weighted average discount rate	4.76		%	4.68		%

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

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Year 1	$	408
Year 2	209
Year 3	206
Year 4	509
Year 5	139
Thereafter	465
Total lease payments	$	1,936
Less imputed interest	(280)
Total	$	1,656

Leasing Arrangements as Lessor

We have lease agreements as lessor for certain operational assets. The revenue from these lease agreements of $0.9 million for both the three months ended March 31, 2024 and 2023 are included in other operating revenue on our consolidated statements of operations.

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

NOTE 15 – FAIR VALUE

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability between market participants in the principal or in the most advantageous market when no principal market exists. The fair value measurement accounting guidance emphasizes that fair value is a market-based measurement, not an entity-specific measurement. Therefore, a fair value measurement should be determined based on the assumptions that market participants would use in pricing the asset or liability (market participants are assumed to be independent, knowledgeable, able and willing to transact an exchange and not under duress). In considering market participant assumptions in fair value measurements, a three-tier fair value hierarchy for measuring fair value was established which prioritizes the inputs used in measuring fair value as follows:

Level 1 inputs are based upon quoted prices for identical instruments traded in active (exchange-traded) markets. Valuations are obtained from readily available pricing sources for market transactions (observable market data) involving identical assets or liabilities.

Level 2 inputs are based upon quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active and model-based valuation techniques (such as option pricing models, discounted cash flow models) for which all significant assumptions are observable in the market.

Level 3 inputs consist of unobservable market data which is typically based on an entity’s own assumptions of what a market participant would use in pricing an asset or liability as there is little, if any, related market activity.

In instances where the determination of the fair value measurement is based on inputs from different levels of the fair value hierarchy, the level in the fair value hierarchy within which the entire fair value measurement falls is based on the lowest level input that is significant to the fair value measurement in its entirety. The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. Additionally, we use fair value to determine the inception value of our asset retirement obligations. The inputs used to determine such fair value are primarily based upon costs incurred historically for similar work, as well as estimates from independent third parties for costs that would be incurred to restore leased property to the contractually stipulated condition, and would generally be classified in Level 3.

Executive Benefit Restoration Plan Trust

We have an irrevocable trust with an independent third party to fund the NRECA Executive Benefit Restoration Plan. The trust is funded quarterly to the prior year obligation as determined by the NRECA actuary. The trust consists of investments in equity and debt securities and are measured at fair value on a recurring basis. Changes in the fair value of investments in equity securities are recognized in earnings and changes in fair value of investments in debt securities classified as available-for-sale are recognized in other comprehensive income until realized. The estimated fair value of the investments is

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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):


	March 31, 2024				December 31, 2023
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	10,870	$	10,361	$	10,821	$	10,298

Marketable Securities

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


	March 31, 2024				December 31, 2023
	Cost		Estimated Fair Value		Cost		Estimated Fair Value
Marketable securities	$	576	$	559	$	576	$	530

Cash Equivalents

We invest portions of our cash and cash equivalents in commercial paper, money market funds, and other highly liquid investments. The fair value of these investments approximates our cost basis in the investments. In aggregate, the fair value was $81.0 million as of March 31, 2024 and $83.0 million as of December 31, 2023.

Debt

The fair values of long-term debt, excluding amounts reclassified from short-term debt, were estimated using discounted cash flow analyses based on our current incremental borrowing rates for similar types of borrowing arrangements. These valuation assumptions utilize observable inputs based on market data obtained from independent sources and are therefore considered Level 2 inputs (quoted prices for similar assets, liabilities (adjusted) and market corroborated inputs). The principal amounts and fair values of our debt are as follows (dollars in thousands):


	March 31, 2024				December 31, 2023
	Principal Amount		Estimated Fair Value		Principal Amount		Estimated Fair Value
Total long-term debt	$	3,099,679	$	2,849,518	$	3,137,534	$	2,909,301

NOTE 16 – VARIABLE INTEREST ENTITIES

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

Consolidated Variable Interest Entity

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

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


	March 31, 2024		December 31, 2023
Net electric plant	$	699,325	$	703,859
Noncontrolling interest	126,945		134,269
Long-term debt	173,237		206,027
Accrued interest	1,999		5,968

Our consolidated statements of operations include the following Springerville Partnership expenses for the three months ended March 31, 2024 and 2023 (dollars in thousands):


	Three Months Ended March 31,
	2024		2023
Depreciation, amortization and depletion	$	4,534	$	4,534
Interest	3,033		3,667

The revenue associated with the Springerville Partnership lease has been eliminated in consolidation. Income, losses and cash flows of the Springerville Partnership are allocated to the general and limited partners based on their equity ownership percentages. The net income or loss attributable to the 49 percent non-controlling equity interest in the Springerville Partnership is reflected on our consolidated statements of operations.

NOTE 17 – LEGAL

Other than as disclosed below, we do not expect any litigation or proceeding pending or threatened against us to have a potential material effect on our financial condition, results of operations or cash flows.

CTP Proceeding: Pursuant to our Bylaws, a Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no Member shall be permitted to withdraw until it has met all its contractual obligations to us. On September 1, 2021, we filed with FERC a modified contract termination payment methodology tariff as Rate Schedule 281 that provides a process should a Utility Member elect to withdraw from membership in us and terminate its wholesale electric service contract. The tariff process includes requirements for a two-year notice and the payment to us of a contract termination payment. On October 29, 2021, FERC accepted our modified contract termination payment methodology, effective November 1, 2021, subject to refund. FERC set the matter for hearing and instituted a concurrent Federal Power Act ("FPA") section 206 proceeding to determine the justness and reasonableness of our modified methodology.

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

On December 19, 2023, FERC issued an order adopting a modified balance sheet approach for the contract termination payment methodology ("FERC December 19 Order"). On January 18, 2024, we, United Power, and others filed requests for rehearing with FERC of the FERC December 19 Order. Our request for rehearing included FERC's rejection of our lost revenue approach and also certain clarifications. On February 20, 2024, FERC issued a notice stating the parties' requests for rehearing were denied by operation of law, but FERC stated it will address the merits of the requests in a subsequent order. On March 28, 2024, we filed a petition for review of the FERC December 19 Order with the United States Court of Appeals for the Tenth Circuit ("10th Circuit Court of Appeals"), 24-9516. On April 8, 2024, United Power filed a petition for review of the FERC December 19 Order with the United States Court of Appeals for the District of Columbia Circuit ("DC Circuit Court of Appeals"), 24-1081. United Power, Mountain Parks Electric, Inc., NRPPD, and La Plata Electric Association, Inc. ("LPEA") have filed notices of interventions in our petition for review with the 10th Circuit Court of Appeals. On April 30, 2024, FERC filed a motion with the 10th Circuit Court of Appeals to hold the petition for review in abeyance until 75 days after FERC issues a further order on rehearing regarding the FERC December 19 Order. On May 2, 2024, FERC filed with the DC Circuit Court of Appeals a motion to transfer United Power's petition for review filed in the DC Circuit Court of Appeals to the 10th Circuit Court of Appeals.

On January 25, 2024, we filed a revised Rate Schedule 281 with FERC with the contract termination methodology based upon the FERC December 19 Order. On March 29, 2024, FERC issued an order accepting our revised Rate Schedule 281, subject to further compliance filing, and established hearing and settlement judge procedures related to our sleeving

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administrative fee methodology set forth in our revised Rate Schedule 281. On April 12, 2024, we submitted a further revised Rate Schedule 281 as directed by FERC's March 2024 order. FERC has not issued an order on our April 2024 revised Rate Schedule 281 so our January 2024 Rate Schedule 281 is currently on-file with FERC.

On May 1, 2024, United Power withdrew from membership in us and terminated its wholesale electric service contract with us pursuant to the Rate Schedule 281 on-file with FERC and a Membership Withdrawal Agreement. United Power’s contract termination payment amount was $709 million. United Power paid us an exit fee in cash of $627 million, after a regulatory liabilities credit and United Power relinquishing its right to any patronage capital in us resulting in a discounted patronage capital credit of $82 million. Such amounts remain subject to true-up in accordance with Rate Schedule 281 and United Power's Membership Withdrawal Agreement. As provided in the Membership Withdrawal Agreement, United Power's exit fee is also subject to true-up in the event Rate Schedule 281 and the amount paid by United Power are modified pursuant to a subsequent final and non-appealable FERC order, including resolution of the petitions for review filed by us and United Power. It is not possible to predict the outcome of this matter or whether we will be required to refund any amounts to United Power or if United Power will be required to pay us any additional amounts.

LPEA's La Plata County District Court Complaint. On November 10, 2023, LPEA filed a complaint with the La Plata County District Court, 2023CV30148, against us. The complaint alleges, among other things, that we have breached our Bylaws and our wholesale electric service contract with LPEA by failing to provide equitable terms and conditions for LPEA to withdraw from us and by violating the implied covenant of good faith and fair dealing. LPEA seeks a declaratory order that we have materially breached our Bylaws and our wholesale electric service contract and that LPEA is relieved from any further obligation to perform under those agreements, or in the alternative, damages from us for such alleged breach. On January 10, 2024, we filed a motion to dismiss stating that LPEA's claims are barred by federal preemption and the statute of limitations. The motion to dismiss is fully briefed and waiting for a court's ruling. It is not possible to predict the outcome of this matter, whether the litigation will be dismissed or whether we will incur any liability in connection with this matter, and in the event of liability, if any, the amount or type of damages, equitable relief or other legal relief that could be awarded or granted.

Basin Complaint: On January 12, 2024, Basin filed a complaint with the U.S. District Court District of North Dakota Eastern Division, 3:24-cv-00008-PDW-ARS, against us alleging that our filing of our Rate Schedule 281 with FERC on September 1, 2021 constitutes a breach of our Amended and Restated Wholesale Power Contract for the Eastern Interconnection with Basin ("Basin Eastern WPC"). The complaint provides that Basin will seek a preliminary and permanent injunction, along with specific performance, that would restrict us from allowing a Utility Member in the Eastern Interconnection from terminating its wholesale electric service contract with us early. On February 1, 2024, Basin filed with the court a motion for preliminary injunction that would enjoin us from disposing of our assets in the Eastern Interconnection in violation of our Basin Eastern WPC. Basin's preliminary injunction sought to preclude us from allowing a Utility Member in the Eastern Interconnection from terminating its wholesale electric service contract with us prior to the end of 2050. On February 15, 2024, we filed a response to Basin's motion. We disputed much of the merit of Basin's motion, but did not oppose the court granting a limited preliminary injunction. On February 28, 2024, NRPPD filed a motion to intervene in the case that was granted by the court. On March 6, 2024, NRPPD filed a response to Basin's motion seeking for the court to deny Basin’s motion for preliminary injunction. On April 24, 2024, the court denied Basin's motion for preliminary injunction. On May 2, 2024, Basin filed a notice with the court that it had voluntarily dismissed its complaint without prejudice.

NRPPD Compliant: On March 25, 2024, NRPPD filed a FPA section 206 proceeding with FERC, Docket No. EL24-93, against us and Basin seeking FERC to exercise primary jurisdiction over the interpretation of the FERC December 19 Order and the Basin Eastern WPC. In particular, NRPPD requests that FERC hold that NRPPD’s withdrawal from us is permissible under the Basin Eastern WPC and that NRPPD’s contract termination payment calculation is the appropriate contract termination payment. NRPPD further seeks refunds from us because Basin has allegedly overcharged us and thus NRPPD for sales of power and energy under the Basin Eastern WPC for Basin’s financial losses caused by Basin’s Urea facility. On March 28, 2024, Basin filed an answer opposing NRPPD’s request for fast-track processing and a motion for an extension of time to respond to NRPPD’s complaint. On April 5, 2024, FERC granted Basin’s request and entered a notice of extension of time with answers due May 8, 2024.

Energy Sales - Soft-Cap: In August 2020, we made certain energy sales to third parties in excess of the soft-cap price for short-term, spot market sales of $1,000 per megawatt hour established by the Western Electricity Coordinating Council. On October 7, 2020, we filed a report with FERC justifying the sales above the soft-cap and we did not recognize the revenue for the energy sales in excess of the soft-cap, EL21-65-000. Based upon additional guidance from FERC, we filed a supplemental report on July 19, 2021. On May 20, 2022, FERC issued an order directing us to refund only certain amounts of the energy

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sales revenue in excess of the soft-cap. Based upon the FERC order, in the second quarter of 2022, we recognized approximately $2.9 million in excess of the soft-cap and refunded $0.4 million to a third party. On July 22, 2022, the California Public Utilities Commission filed a petition for review with the DC Circuit Court of Appeals of FERC’s May 20, 2022 order, 22-1169. On August 18, 2022, we filed a motion to intervene with the DC Circuit Court of Appeals and an order granting our motion was issued on September 6, 2022. On January 24, 2023, the parties to the proceeding filed a motion with the court to consolidate this proceeding with other related proceedings with the DC Circuit Court of Appeals and proposed a procedural schedule with final briefings due in October 2023. On March 6, 2023, the DC Circuit Court of Appeals granted the motion to consolidate the proceedings. On October 31, 2023, the final briefs were filed in this consolidated proceeding. It is not possible to predict the outcome of this matter or whether we will be required to refund any additional amounts to third parties.

NOTE 18 – SUBSEQUENT EVENTS

In May 2024, the conditions for the effectiveness of a tolling agreement with a third party were satisfied that gives the third party the exclusive right to receive all capacity and electric energy through the operation of both units at our Knutson Generating Station. This arrangement began on May 1, 2024 and continues to December 31, 2027. This arrangement has been determined to be a lease, with us as lessor and the third party as lessee, as the third party has the right to direct the use of Knutson Generating Station by receiving all of the economic benefits of the facility, controls the fuel source provided to the facility and controls the dispatching of the electric energy from the facility.

In March 2024, we executed an asset purchase agreement to purchase the 145 MW Axial Basin Solar project being developed in northwestern Colorado located near the Colowyo Mine. In April 2024, we closed on the acquisition of Axial Basin Solar project, terminated the power purchase contract for this project and issued a notice to proceed with construction to the contractor. In April 2024, we executed an asset purchase agreement to purchase the 110 MW Dolores Canyon Solar project being developed in southwestern Colorado. We expect to close on the acquisition of Dolores Canyon Solar project in the second quarter of 2024. We are currently evaluating the impact of these agreements on our consolidated financial statements.

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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 currently owned entirely by our forty-four 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-one 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-seven of our Utility Members are not-for-profit, electric distribution cooperative associations. Four Utility Members are public power districts, which are political subdivisions of the State of Nebraska. We became regulated as a public utility under Part II of the FPA on September 3, 2019 when we admitted a Non-Utility Member, MIECO, Inc. (a non-governmental/non-electric cooperative entity), as a new Member/owner.

We supply and transmit our Utility Members’ electric power requirements through a portfolio of resources, including generation and transmission facilities, long term purchase contracts and short-term energy purchases. We own, lease, have undivided percentage interests in, or long-term purchase contracts with respect to various generating facilities. Our diverse generation portfolio provides us with maximum available power of 4,323 MWs, of which approximately 1,366 MWs comes from renewables.

We sold 4.6 million MWhs for the three months ended March 31, 2024, of which 90.2 percent was to Utility Members. Total revenue from electric sales was $331.4 million for the three months ended March 31, 2024 of which 89.3 percent was from Utility Member sales. Our results for the three months ended March 31, 2024 were primarily impacted by mild weather conditions as well as lower market power prices.

•Non-member electric sales decreased $6.3 million, or 15.1 percent, primarily due to lower short-term market sales (in MWhs) and lower average prices.

•Rate stabilization was $11.8 million lower during the first quarter of 2024 compared to the same period in 2023 as we didn't recognize any of the remaining previously deferred membership withdrawal income during the three months ended March 31, 2024 compared to $11.8 million during the same period in 2023 as part of our rate stabilization measures.

•Purchased power expense decreased $7.8 million, or 7.7 percent, primarily due to lower average prices of power.

•Fuel expense decreased $5.6 million, or 6.8 percent, primarily due to lower market prices which allowed us, particularly in the energy imbalance markets, to purchase energy below our production costs.

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 41 Utility Members extend through 2050. We had a wholesale electric service contract with United Power that extended through 2050 (which constituted approximately 19.7 percent of our revenue from Utility Member sales for the three months ended March 31, 2024). United Power withdrew from membership in us on May 1, 2024 and its wholesale electric service contract was terminated. 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 March 31, 2024 and removing any projects related to United Power, 20 Utility Members have enrolled in this program with capacity totaling approximately 96 MWs of which 89 MWs are in operation.

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We have presented to our Utility Members and received feedback on alternatives for an increased amount of self-supply in addition to the 5 percent self-supply provision of our wholesale electric services contracts. The alternative that emerged through our collaboration with our Utility Members is known as the Bring Your Own Resource Program, which is designed to provide our Utility Members with the flexibility to build, own or contract for power supply projects. Under the Bring Your Own Resource Program, Utility Members interested in participating in the program will propose projects that they will own or control and that do not exceed 40 percent of their 2022 peak load during our peak period and which projects will not have an adverse impact on our reliability, overall system costs or compliance with environmental objectives. We are developing a tariff describing the parameters of the Bring Your Own Resource Program that is expected to be filed with FERC in the second quarter of 2024. If the tariff is accepted by FERC, the Bring Your Own Resource Program cycle for the first proposal, evaluation and implementation steps is expected to begin in the third quarter of 2024 and conclude in the first quarter of 2025. For a Utility Member to participate in the Bring Your Own Resource Program, a Utility Member will enter into an agreement with us for us to purchase the output of the Bring Your Own Resource Program project and that output will be deemed to serve the Utility Member’s load.

Member Withdrawals and Relationship with Members

Pursuant to our Bylaws, a Member may only withdraw from membership in us upon compliance with such equitable terms and conditions as our Board may prescribe provided, however, that no Member shall be permitted to withdraw until it has met all its contractual obligations to us. In September 2021, we filed with FERC a modified contract termination payment methodology tariff as Rate Schedule 281 that provides a process should a Utility Member elect to withdraw from membership in us and terminate its wholesale electric service contract. The tariff process includes requirements for a two-year notice and the payment to us of a contract termination payment. In October 2021, FERC accepted our modified contract termination payment methodology, effective November 1, 2021, subject to refund. FERC set the matter for hearing and instituted a concurrent FPA section 206 proceeding to determine the justness and reasonableness of our modified methodology.

In December 2023, FERC issued an order adopting a modified balance sheet approach for the contract termination payment methodology. In January 2024, we filed a revised Rate Schedule 281 with FERC with the contract termination methodology based upon FERC's order. The revised Rate Schedule 281 based upon FERC's adopted balance sheet approach uses our FERC financials and distinguishes between Utility Members served on the Western and Eastern Interconnection. In March 2024, FERC issued an order accepting our revised Rate Schedule 281, subject to further compliance filing, and established hearing and settlement judge procedures related to our sleeving administrative fee methodology set forth in our revised Rate Schedule 281. In April 2024, we submitted a further revised Rate Schedule 281 as directed by FERC's March 2024 order. FERC has not issued an order on our April 2024 revised Rate Schedule 281 so our January 2024 Rate Schedule 281 is currently on-file with FERC. For further information on the methodology see “Item 1 – BUSINESS – MEMBERS - Contract Termination Payment and Relationship with Members” in our annual report on Form 10-K for the year ended December 31, 2023. See also Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for further information.

On April 29, 2022, both United Power and NRPPD provided us notices to withdraw from membership in us, with a May 1, 2024 withdrawal effective date. In January 2023, MPEI provided us a notice to withdraw from membership in us, with a February 1, 2025 withdrawal effective date. In March 2024, LPEA provided us a notice to withdraw from membership in us, with an April 1, 2026 withdrawal effective date.

On May 1, 2024, United Power withdrew from membership in us and terminated its wholesale electric service contract with us pursuant to the Rate Schedule 281 on-file with FERC and a Membership Withdrawal Agreement. United Power’s contract termination payment amount was $709 million. United Power paid us an exit fee in cash of $627 million, after a regulatory liabilities credit and United Power relinquishing its right to any patronage capital in us resulting in a discounted patronage capital credit of $82 million. Such amounts remain subject to true up in accordance with Rate Schedule 281 and United Power's Membership Withdrawal Agreement. On May 8, 2024, we also sold to United Power certain assets for $75 million that were primarily used to serve United Power's load after our receipt of approval from FERC on May 1, 2024.

NRPPD did not comply with the Rate Schedule 281 on-file with FERC and made no contract termination payment to us. NRPPD’s wholesale electric service contract with us remains in effect and NRPPD remains a Class A member of us. NRPPD’s April 29, 2022 notice of intent to withdraw is deemed null and void. Contrary to FERC’s March 2024 order on our revised Rate Schedule 281 compliance filing, NRPPD has asserted there is no FERC-accepted Rate Schedule 281 on file with FERC and no contract termination payment is payable by NRPPD as the parties await further orders from FERC. NRPPD is disputing our position that their wholesale electric service contract with us remains in effect and NRPPD remains a Class A member of us.

MPEI’s and LPEA’s estimated contract termination payments based upon our April 2024 revised Rate Schedule 281 are $77.9 million and $209.6 million, respectively, prior to any reduction for discounted patronage capital or regulatory

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liabilities credit, if applicable. These estimated contract termination payments do not include their respective pro rata share of our power purchase obligations in the Western Interconnection and potential adjustments related to the prior withdrawal of United Power. MPEI and LPEA comprised 8.7 percent of our Utility Member revenue and 7.3 percent of our operating revenue for the three months ended March 31, 2024.

The contract termination payments for United Power, MPEI, and LPEA are subject to review and modification through proceedings currently pending with FERC and petitions for review filed in the federal courts. See Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for further information.

Although there is no certainty that MPEI and LPEA will pay their respective contract termination payment required upon withdrawal and withdraw as they have asserted, if these Utility Members pay and withdraw, it will reduce our Utility Members' electric sales revenue and the amount of energy sold to our Utility Members. We expect the receipt of the contract termination payments from United Power, MPEI, and LPEA to assist in mitigating the impacts of decreased Utility Members electric sales revenue. We expect to defer some or all of the contract termination payments received as a regulatory liability and recognize as revenue in future period or periods to offset the revenue otherwise recoverable from Utility Members.

In addition, as part of mitigating the impacts, we expect our non-member electric sales revenue and the amount of energy sold to non-members to increase significantly. In anticipation of Utility Member withdrawals, we have entered into with third parties multiple power sales contracts for up to 260 MWs and a tolling agreement for our two 70 MW units at the Knutson Generating Station for the sale of excess capacity and energy, with certain transactions that started on May 1, 2024. Our Phase I 2023 ERP also assumed United Power and MPEI will withdraw resulting in a decreased need for additional resources and costs as we transition to a cleaner energy portfolio and reduce our greenhouse gas emissions. However, there is no certainty that our mitigation steps or the contract termination payments will mitigate the full amount of the loss of Utility Member electric sales revenue. See also “Item 1 – BUSINESS – MEMBERS - Contract Termination Payment and Relationship with Members” and "RISK FACTORS - Members and Regulatory Risks" in our annual report on Form 10-K for the year ended December 31, 2023.

In November 2023, LPEA filed a complaint for declaratory judgement and damages against us alleging, among other things, that we have breached our Bylaws and our wholesale electric service contract with LPEA. In January 2024, we filed a motion to dismiss stating that LPEA's claims are barred by federal preemption and the statute of limitations. See Note 17 to the Unaudited Consolidated Financial Statements in Item 1 for further information.

Responsible Energy Plan and Colorado Electric Resource Plan and New Era Program

Responsible Energy Plan

In January 2020, we released our energy transition plan known as our Responsible Energy Plan. With our Responsible Energy Plan, we are implementing a clean energy transition while being responsible to our employees, Members, communities, and environment. The plan was developed with input from our Board, our Utility Members and external stakeholders. Our plan is dynamic and will change as Utility Members' needs change, new technologies become available and market conditions evolve. We and our Utility Members have made great strides implementing the plan. 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 2025, 50 percent of the electricity our Utility Members use is expected to come from clean energy.

•more local renewables for Utility Members through contract flexibility.

•promoting participation in a regional transmission organization.

•expanding electric vehicle infrastructure and beneficial electrification.

For further information regarding our Responsible Energy Plan, see “Item 1 – BUSINESS — MEMBERS – Responsible Energy Plan” in our annual report on Form 10-K for the year ended December 31, 2023.

Colorado Electric Resource Plan

In December 2023, we filed our Phase I 2023 ERP with the COPUC, which contained our preferred plan and submitted a filing in April 2024 affirming the preferred plan. Our preferred plan is the IRA scenario, which brings online 1,540 MWs of new resources during the resource acquisition period of 2026-2031, if we are awarded federal funding to support generation additions and provide stranded asset relief under the New ERA Program funding opportunity. Our preferred plan

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enables us to take advantage of direct pay of federal tax benefits for renewable and storage resources by increasing our owned resources. Our preferred plan retires Craig Station Unit 3 by January 1, 2028 and, if we receive New ERA Program funding and reach agreements with the applicable parties, our preferred plan retires Springerville Unit 3 by September 15, 2031. These shifts in our generation portfolio included in our preferred plan over the coming years are expected to result in an 89 percent greenhouse gas emissions reduction for our wholesale electricity sales in Colorado in 2030, with respect to a verified 2005 baseline. This emissions reduction exceeds the emissions reduction target of 80 percent in 2030 identified in our January 2022 settlement agreement related to Phase I of our 2020 Electric Resource Plan. For further information, see “Item 1 – BUSINESS — POWER SUPPLY RESOURCES – Resource Planning” in our annual report on Form 10-K for the year ended December 31, 2023.

New ERA Program

In September 2023, we submitted a Letter of Interest to apply for a funding award of low-cost loans and grants through the New ERA Program. The details of the portfolio proposed in our Letter of Interest are a result of resource and financial modeling performed in connection with our preferred IRA scenario as part of our Phase I 2023 ERP. Our Letter of Interest expands and further supports our implementation of Responsible Energy Plan. In March 2024, we received an Invitation to Proceed from the U.S. Department of Agriculture to complete the New ERA Program Application. The New ERA Program implements the $9.7 billion funded in the Inflation Reduction Act of 2022.

Other Recent Developments

In March 2024, we executed an asset purchase agreement to purchase the 145 MW Axial Basin Solar project being developed in northwestern Colorado located near the Colowyo Mine. Concurrent with execution of the purchase agreement, we also executed an engineering, procurement and construction contract with an affiliate of the developer of the project. In April 2024, we closed on the acquisition of Axial Basin Solar project, terminated the power purchase contract for this project, and issued a notice to proceed with construction to the contractor.

In April 2024, we executed an asset purchase agreement to purchase the 110 MW Dolores Canyon Solar project being developed in southwestern Colorado. Concurrent with execution of the purchase agreement, we also executed an engineering, procurement and construction contract with an affiliate of the developer of the project. We expect to close on the acquisition of Dolores Canyon Solar project in the second quarter of 2024. Upon closing, we also expect to terminate the power purchase contract for this project and issue a notice to proceed with construction to the contractor. Both projects are expected to achieve commercial operation in 2025. We also expect to take advantage of direct pay of federal tax benefits as provided in the Inflation Reduction Act of 2022 for both projects.

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 March 31, 2024, 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, 2023.

Factors Affecting Results

Master Indenture

As of March 31, 2024, 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. As of December 31, 2023, our DSR was 1.20 and our ECR was 24.0 percent. 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

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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 or waiver 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 Members. On a periodic basis, our Board will determine whether to retire any patronage capital, and in what amounts, to our Members. As of March 31, 2024, we have retired approximately $523.6 million of patronage capital to our Members.

Pursuant to our Board Policy for Financial Goals and Capital Credits, we have historically 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. Our Board Policy for Financial Goals and Capital Credits, approved in 2023 in connection with our Board’s approval of a revised Class A rate schedule that uses a formula rate, includes three financial ratio goals for which we will set rates based upon an annual budget and true-up from the actual results of the previous fiscal year. The three financial goals are: (i) a minimum DSR of at least 1.15, (ii) a minimum ECR of at least 20 percent, and (iii) a minimum net margin attributable to us in each fiscal year of at least $20 million. Our Board approved rates to our Utility Members to achieve a DSR and ECR in excess of the requirements under our Master Indenture, including a DSR of approximately 1.34 largely driven by a minimum net margin attributable to us of at least $20 million for 2024. Based on our 2024 budget, we have forecasted the recognition of deferred membership withdrawal income during 2024.

Rates and Regulation

On September 3, 2019, we became FERC jurisdictional for our Utility Members' 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. On August 2, 2021, FERC approved our settlement agreement related to our Utility Members' stated rate that provides for us to implement a two-stage, graduated reduction in the charges making up our A-40 rate of two percent starting from March 1, 2021 until the first anniversary and four percent reduction (additional two percent reduction from then current rates) on March 1, 2022 until the date a new Class A wholesale rate schedule goes into effect. For further information, see “Item 1 – BUSINESS — RATE REGULATION” in our annual report on Form 10-K for the year ended December 31, 2023.

Our electric sales revenues are derived from wholesale electric service sales to our Utility Members and non-member purchasers. Revenues from wholesale electric power sales to our non-member purchasers is primarily 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 that is a stated rate. Our current 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 Members' 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.

As part of the settlement agreement for our Utility Members' stated rate, we agreed to file a new Class A rate schedule with FERC before September 1, 2023. We established a rate design committee to oversee the development of the new rate. In June 2023, we filed with FERC the new Class A rate schedule (A-41) that uses a formula rate and requested for the new rate to take effect on January 1, 2024 and included a 6.3 percent rate increase. In March 2024, FERC rejected our Class A formula rate resulting in our Class A rate schedule (A-40) remaining in effect. FERC's rejection related to unbundling of rate components for ancillary services on our bills to our Utility Members and allocation of costs across the Eastern and Western Interconnection. FERC's reject was not related to our ability to recover costs, including our rate increase. We expect to file a revised Class A rate schedule that uses a formula rate with FERC in the second quarter of 2024.

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.

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

Results of Operations

General

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

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

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

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

•the general growth in population; and

•economic conditions.

Impacts of Supply Chain and Inflation

Our ability to meet our Utility Members' electric power requirements and complete our capital projects are dependent on maintaining an efficient supply chain. The procurement and delivery of materials and equipment have been impacted by the current domestic and global supply chain disruptions. We are experiencing shortages of critical items and longer lead-times on the procurement of certain materials and equipment. Supply chain disruptions and inflation have contributed to higher prices for materials and equipment. We continue to monitor potential impacts to our operations and estimated capital expenditures and timing of projects related to inflationary pressures and supply chain disruptions.

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023

Operating Revenues

Our operating revenues are primarily derived from electric power sales to our Utility Members and non-member purchasers. Other operating revenue consists primarily of wheeling, transmission, and coal sales. Other operating revenue also

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includes revenue we receive from certain of our Non-Utility Members. The following is a comparison of our operating revenues and energy sales in MWh by type of purchaser for the three months ended March 31, 2024 and 2023 (dollars in thousands):


	Three Months Ended March 31,				Period-to-period Change
	2024		2023		Amount		Percent
Operating revenues
Utility Member electric sales	$	295,826	$	292,176	$	3,650	1.2	%
Non-member electric sales	35,619		41,950		(6,331)		(15.1)	%
Rate stabilization	—		11,757		(11,757)		(100.0)	%
Provision for rate refunds	—		310		(310)		(100.0)	%
Other	20,104		17,858		2,246		12.6	%
Total operating revenues	$	351,549	$	364,051	$	(12,502)	(3.4)	%

Energy sales (in MWh):
Utility Member electric sales	4,172,191		4,095,442		76,749		1.9	%
Non-member electric sales	452,773		410,994		41,779		10.2	%
	4,624,964		4,506,436		118,528		2.6	%

•Non-member electric sales revenue decreased primarily due to lower short-term market sales and lower average prices. Short-term market sales decreased 94,941 MWhs, or 28.9 percent, to 233,843 MWhs for the three months ended March 31, 2024 compared to 328,784 MWhs for the same period in 2023, and average short-term market prices decreased 34.8 percent for the three months ended March 31, 2024 compared to the same period in 2023. Long-term sales increased 136,720 MWhs, or 166.3 percent, to 218,930 MWhs for the three months ended March 31, 2024 compared to 82,210 MWhs for the same period in 2023. While long-term sales in MWhs increased primarily due to new power sales contracts, average prices decreased 28.4 percent for the three months ended March 31, 2024 compared to the same period in 2023.

•Rate stabilization represents recognition of income from the withdrawal of former Utility Members from membership in us that was previously deferred in accordance with accounting requirements related to regulated operations. We didn't recognize any of the remaining $463,000 of previously deferred membership withdrawal income during the three months ended March 31, 2024 compared to $11.8 million during the same period in 2023 as part of our rate stabilization measures.

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 March 31, 2024 and 2023 (dollars in thousands):


	Three Months Ended March 31,				Period-to-period Change
	2024		2023		Amount		Percent
Operating expenses
Purchased power	$	93,070	$	100,825	$	(7,755)	(7.7)	%
Fuel	76,340		81,930		(5,590)		(6.8)	%
Production	42,126		43,552		(1,426)		(3.3)	%
Transmission	47,558		49,028		(1,470)		(3.0)	%
General and administrative	21,733		18,498		3,235		17.5	%
Depreciation, amortization and depletion	44,624		42,381		2,243		5.3	%
Coal mining	1,078		1,639		(561)		(34.2)	%
Other	2,950		6,295		(3,345)		(53.1)	%
Total operating expenses	$	329,479	$	344,148	$	(14,669)	(4.3)	%

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•Purchased power expense decreased primarily due to lower average power prices of 24.6 percent during the three months ended March 31, 2024 compared to the same period in 2023, partially offset by an increase of 496,365 MWhs purchased during the three months ended March 31, 2024 compared to the same period in 2023.

•Fuel expense decreased primarily due to a decrease of 304,363 MWhs in generation by our coal-fired generating facilities and a decrease of 97,165 MWhs in generation by our natural gas-fired generating facilities, partially offset by a higher average rate for natural gas of 6.0 percent during the three months ended March 31, 2024 compared to the same period in 2023.

•General and administrative expense increased primarily due to higher depreciation expense related to depreciation that began in 2024 related to capitalized software costs and an overall increase in expenses related to general and administration labor and benefits, partially offset by lower outside professional services during the three months ended March 31, 2024 compared to the same period in 2023.

Financial Condition as of March 31, 2024 Compared to December 31, 2023

The principal changes in our financial condition from December 31, 2023 to March 31, 2024 were due to increases and decreases in the following:

Assets

•Restricted cash and investments-current increased $19.8 million to $20.4 million as of March 31, 2024 compared to $0.6 million as of December 31, 2023. The increase was primarily due to $16.8 million that was deposited with our Master Indenture trustee in March 2024 in advance of our April 1, 2024 debt service payments for the First Mortgage Obligations, Series 2014B and Moffat County Pollution Control Bonds. In accordance with our Master Indenture, we are required to fund the account one day prior to debt service payments.

•Deposits and advances increased $40.4 million to $77.9 million as of March 31, 2024 compared to $37.5 million as of December 31, 2023. The increase was primarily due to migrating and upgrading software solutions to hosted solutions and 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

•Short-term borrowings increased $88.7 million to $273.0 million as of March 31, 2024 compared to $184.3 million as of December 31, 2023. The increase was due to commercial paper activity related to working capital needs and capital expenditures.

•Accrued interest increase $19.0 million, or 77.1 percent, to $43.5 million as of March 31, 2024 compared to $24.5 million as of December 31, 2023. The increase was primarily due to accrual for interest due in future periods of $43.7 million partially offset by interest payments of $24.7 million.

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 March 31, 2024, we had $110.4 million in cash and cash equivalents. Our committed credit arrangement as of March 31, 2024 is as follows (dollars in thousands):


	Authorized Amount			Available March 31, 2024
2022 Revolving Credit Agreement	$	520,000	(1)	$	247,138	(2)

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

(2)The portion of this facility that was unavailable at March 31, 2024 was $273 million which was dedicated to support outstanding commercial paper.

We have a secured 2022 Revolving Credit Agreement with aggregate commitments of $520 million. The 2022 Revolving Credit Agreement includes a swingline sublimit of $125 million, a letter of credit sublimit of $75 million, and a commercial paper back-up sublimit of $500 million, of which $125 million of the swingline sublimit, $75 million of the letter of credit sublimit, and $227 million of the commercial paper back-up sublimit remained available as of March 31, 2024.

The 2022 Revolving Credit Agreement is secured under our Master Indenture and has a maturity date of April 25, 2027, unless extended as provided therein. Funds advanced under the 2022 Revolving Credit Agreement bear interest either at adjusted Term SOFR rates or alternative base rates, at our option. The adjusted Term SOFR rate is the Term SOFR rate for the term of the advance plus a margin (1.250 percent as of March 31, 2024) based on our credit ratings. Base rate loans bear interest

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at the alternate base rate plus a margin (0.250 percent as of March 31, 2024) based on our credit ratings. The alternate base rate is the highest of (a) the federal funds rate plus ½ of 1.00 percent, (b) the prime rate, and (c) the adjusted Term SOFR rate plus 1.00 percent.

The 2022 Revolving Credit Agreement contains customary representations, warranties, covenants, events of default and acceleration, including financial DSR and ECR requirements in line with the covenants contained in our Master Indenture. A violation of these covenants would result in the inability to borrow under the facility.

Under our commercial paper program, our Board authorized us to issue commercial paper in amounts that do not exceed the commercial paper back-up sublimit under our 2022 Revolving Credit Agreement, which was $500 million as of March 31, 2024, thereby providing 100 percent dedicated support for any commercial paper outstanding. As of March 31, 2024, we had $273 commercial paper outstanding and $227 million available on the commercial paper back-up sublimit. See Note 7 to the Unaudited Consolidated Financial Statements in Item 1 for further information.

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

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

Cash Flow

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

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023

Operating activities. Net cash provided by operating activities was $47.9 million for the three months ended March 31, 2024 compared to $124.4 million for the same period in 2023, a decrease in net cash provided by operating activities of $76.5 million. The decrease in net cash provided by operating activities was impacted by the timing of cash collected from Member accounts receivable, payment of trade payables and accrued expenses and prepayments of annual insurance.

Investing activities. Net cash used in investing activities was $48.3 million for the three months ended March 31, 2024 compared to $175.1 million for the same period in 2023, a decrease in net cash used in investing activities of $126.8 million. The decrease in net cash used in investing activities was impacted by additional investments in utility plant and timing of payments we made to operating agents of jointly owned facilities to fund our share of costs to be incurred under each project.

Financing activities. Net cash provided by financing activities was $33.6 million for the three months ended March 31, 2024 compared to $50.0 million for the same period in 2023, a decrease in net cash provided by financing activities of $16.4 million. The decrease in net cash provided by financing activities was primarily due to an increase in short-term borrowings for the three months ended March 31, 2024 compared to the same period in 2023 to fund working capital needs and capital expenditures.

Capital Expenditures

We forecast our capital expenditures annually as part of our long-term planning. We regularly review these projections to update our calculations to reflect changes in our future plans, facility closures, facility costs, market factors and other items affecting our forecasts. After taking into account our our preferred IRA scenario as part of our Phase I 2023 ERP, in the years 2024 through 2028, we forecast that we may invest approximately $2.60 billion in new facilities and upgrades to our existing facilities. Our investment forecast for new facilities and upgrades to existing facilities by capital expenditure category is as follows (dollars in thousands):

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	2024		2025		2026		2027		2028		Total
Generation	$	207,167	$	604,395	$	227,450	$	257,847	$	356,066	$	1,652,925
Transmission	144,837		197,608		133,438		158,825		147,384		782,092
General Plant	52,071		27,708		31,654		28,211		28,046		167,690
Total Capital Expenditures	$	404,075	$	829,711	$	392,542	$	444,883	$	531,496	$	2,602,707

Our actual capital expenditures depend on a variety of factors, including assumptions related to our Responsible Energy Plan and our Phase I 2023 ERP, receipt of New ERA Program funding and other federal programs, Utility Member load growth or Utility Member withdraws, Bring Your Own Resource Program, availability of necessary permits, regulatory changes, environmental requirements, construction delays and costs, supply chain issues, inflation, and ability to access capital in credit markets. Thus, actual capital expenditures may vary significantly from our projections.

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

Changing Environmental Regulations

We are subject to 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. Following are updates on recent developments that may impact us:

Air Quality

Mercury and other Hazardous Air Pollutants. In April 2024, the EPA announced final revisions to the National Emission Standards for Hazardous Air Pollutants for coal- and oil-fired electric utility steam generating units pursuant to EPA’s risk and technology review as required by Section 112 of the Clean Air Act. EPA finalized a more stringent emission limit for particulate matter, as a surrogate for non-mercury metals, and requirements for installations of particulate matter continuous emissions monitoring systems. We will continue to ensure compliance with the applicable particulate matter emission limit and will begin to assess options related to continuous emission monitoring equipment for particulate matter.

Greenhouse Gas Regulation. In April 2024, the EPA announced a final rule regarding emission guidelines for carbon dioxide from certain existing electric generating units under Section 111(d) of the Clean Air Act and certain new electric generating units under Section 111(b) of the Clean Air Act. EPA finalized a matrix of emission requirements that depend on a given unit’s fuel type, generating capacity, capacity factor, and years of continued operation. Due to applicability thresholds and previously announced retirement dates of our generating facilities, this particular rule does not, or likely will not, affect most of our generating facilities. However, if not overturned, the rule will drive important decision-making about future operation of and investment in Laramie River Generating Station.

Colorado Greenhouse Gas Fees. In February 2024, the Colorado Air Quality Control Commission adopted state regulatory revisions enabling the Colorado Department of Public Health and Environment to collect fees from certain greenhouse gas-emitting sources. Such fees will begin to be assessed in 2024. Due to the methodology applied, the 2024 invoice for these fees is estimated to exceed $600,000, with substantial increases in future years above $1,000,000 annually for several years.

Other Environmental Matters

Coal Ash Regulation. In April 2024, the EPA announced a final rule regarding groundwater monitoring, corrective action, closure, and post-closure care requirements for all coal combustion residuals management units under the Resource Conservation and Recovery Act. We are analyzing the final rule for possible effects on our operations.

For further discussion regarding potential effects on our business from environmental regulations, see "Item 1 – BUSINESS — ENVIRONMENTAL REGULATION" and "Item 1 – RISK FACTORS" in our annual report on Form 10-K for the year ended December 31, 2023.

Rating Triggers

Our current senior secured ratings are “Baa1 (stable outlook)” by Moody’s, “BBB (negative outlook)” by S&P, and “BBB+ (negative outlook)” by Fitch. Our current short-term ratings are “A-2” by S&P and “F1” by Fitch.

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Our 2022 Revolving Credit Agreement includes a pricing grid related to the Term SOFR spread, commitment fee and letter of credit fees due under the facility. A downgrade of our senior secured ratings could result in an increase in each of these pricing components. We do not believe that any such increase would have a material adverse effect on our financial condition or our future results of operations. However, a downgrade of our senior secured ratings could impact the costs associated with incurring additional debt and could make accessing the debt markets on favorable terms more difficult.

We currently have contracts and other obligations that require adequate assurance of performance. These include organized markets contracts, power contracts, natural gas supply contracts and financial risk management contracts. Some of the contracts are directly tied to us maintaining investment grade credit ratings by S&P and Moody’s. We may enter into additional contracts which may contain adequate assurance requirements. If we are required to provide adequate assurances, it may impact our liquidity and the amount of adequate assurance required will be dependent on our credit ratings.

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, 2023.

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 were no changes that occurred during the first quarter ended March 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. In 2024, due to migrating and upgrading software solutions to hosted solutions later in 2024, we expect changes to our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 4. Mine Safety Disclosures

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

Item 6. Exhibits


Exhibit Number						Description of Exhibit
31.1						Rule 13a-14(a)/15d-14(a) Certification, by Duane Highley (Principal Executive Officer).
31.2						Rule 13a-14(a)/15d-14(a) Certification, by Todd E. Telesz (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 Todd E. Telesz (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: May 9, 2024	By:	/s/ Duane Highley
		Duane Highley
		Chief Executive Officer


Date: May 9, 2024		/s/ Todd E. Telesz
		Todd E. Telesz
		Senior Vice President/Chief Financial Officer (Principal Financial Officer)