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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

___________________________________

FORM 10-Q

___________________________________

(Mark One)


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

For the quarterly period ended March 31, 2026


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

For the transition period from _____ to _____

Commission file number 333-295074

___________________________________

BASIN ELECTRIC POWER COOPERATIVE

(Exact name of registrant as specified in its charter)

___________________________________


North Dakota		45-0277395
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1717 East Interstate Avenue
Bismarck, North Dakota 58503
(Address of Principal Executive Offices and Zip Code)

	(701) 223 0441
(Registrant’s telephone number, including area code)

	Not Applicable
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act: None

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 x No o

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 x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated

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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 o No x

Indicate the number of shares outstanding of each of the registrant’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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BASIN ELECTRIC POWER COOPERATIVE

FORM 10-Q FOR THE QUARTER ENDED MARCH 31, 2026

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		Page

FORWARD-LOOKING STATEMENTS		ii
CERTAIN DEFINITIONS		iv

PART I FINANCIAL INFORMATION

ITEM 1.	FINANCIAL STATEMENTS	1
	CONSOLIDATED BALANCE SHEETS (Unaudited)	2
	CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited)	4
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited)	5
	CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (Unaudited)	6
	CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited)	7
	CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)	8
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	40
ITEM 4.	CONTROLS AND PROCEDURES	40

PART II OTHER INFORMATION		41

ITEM 1.	LEGAL PROCEEDINGS	41
ITEM 1A.	RISK FACTORS	41
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	53
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	53
ITEM 4.	MINE SAFETY DISCLOSURES	53
ITEM 5.	OTHER INFORMATION	54
ITEM 6.	EXHIBITS	54

SIGNATURES		55

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FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this “report”) contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are forward-looking and as such are not historical facts. These forward-looking statements include statements relating to our anticipated financial performance and business prospects or statements preceded by, followed by or that include the words “believe,” “will,” “so we can,” “when,” “anticipate,” “intend,” “estimate,” “forecast,” “expect,” “project,” “should,” “could,” “may,” “plan,” “seeks,” and similar expressions. Although we believe that in making the statements contained in this report our expectations are based on reasonable assumptions, we can give no assurance that these expectations will prove to be correct or that we will achieve the financial results, savings or other benefits anticipated in the forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other important factors, some of which may be beyond our control, that could cause our actual results, performance or achievements or industry results, to differ materially from any future results, performance or achievements expressed or implied by these forward-looking statements. These risks, uncertainties and other important factors, including those disclosed under “RISK FACTORS” in Part II, Item 1A of this report, include, without limitation:

◦unanticipated variation in demand for electric capacity or energy or load forecasts resulting from changes in population and economic growth (and declines), consumer consumption and energy conservation efforts, including the impact on power supply plans;

◦the impact of traditional load growth and potential large loads, including data centers, in our members’ service territories and any decisions regarding the development of additional generation resources to meet the additional demand;

◦changes in the market price of commodities, including natural gas, energy, crude oil, diesel and nitrogen-based fertilizer products, which may result from inflation, tariffs, trade policies, or geopolitical events or instability;

◦legislative and regulatory compliance standards and the cost and other burdens of complying with any applicable standards, including mandatory reliability standards, and potential penalties for non‑compliance;

◦new, amended, or existing laws, regulations, or administrative orders, including those related to environmental matters, carbon dioxide and other greenhouse gas emissions, water and coal combustion byproducts, and the costs of complying with these laws, regulations, and administrative orders;

◦costs of additional generation or transmission facilities to meet the needs of our members or changes in the anticipated retirement dates of existing generation or transmission facilities;

◦success or failure to consummate strategic transactions, including acquisition or divestiture activities, upon which we base financial or operational forecasts;

◦the outcome or consequences of strategic alternatives that we have implemented or are evaluating, or may in the future, evaluate in connection with our subsidiary, Dakota Gasification Company (“Dakota Gas”), including asset sales and asset impairments;

◦changes in customer preferences for energy produced from cleaner generation sources;

◦continued efficient operation of our generation facilities by us;

◦the ability of our member systems to perform their obligations to us;

◦the pricing and availability of an adequate and economical supply of fuel, water and other materials, including due to the potential impact of geopolitical tensions on supply chains;

◦our ability to hedge power, fuel and capacity to provide margin visibility and mitigate market volatility;

◦changes in utility regulation and the allocation of costs within regional transmission organizations, including the Southwest Power Pool (“SPP”) and Midcontinent Independent System Operator (“MISO”);

◦pressures exerted by increasing levels of indebtedness caused by significant capital expenditures;

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◦unanticipated changes in capital expenditures, operating expenses and liquidity needs;

◦our access to capital, the cost to access capital, and the results of our financing and refinancing efforts, including availability of funds in the capital markets;

◦the availability of funding under any federal loan or grant programs for which we qualify and are awarded and our ability to meet the applicable loan or grant conditions and requirements;

◦general economic, credit and capital market conditions;

◦supply chain challenges, including as a result of trade policies, tariffs, or other international trade restrictions and geopolitical tensions;

◦failure of our information technology or operating technology;

◦the direct or indirect effect on our business resulting from cyber or physical attacks on us, our members or third-party service providers, vendors or contractors;

◦commercial banking and financial market conditions;

◦hazards customary to the electric industry and the possibility that we may not have adequate insurance to cover losses resulting from these hazards;

◦litigation or legal and administrative proceedings and settlements;

◦the effectiveness of our risk management policies and risk strategies, including hedging, with respect to commodity prices, interest rates and counterparty credit and non-performance risks;

◦the credit quality or inability of various counterparties to meet their financial obligations to us, including failure to perform under agreements;

◦unanticipated changes in interest rates or rates of inflation;

◦acts of sabotage, wars or terrorist activities, including cyber or physical attacks on our assets or assets on which we rely;

◦catastrophic events such as wildfires, earthquakes, floods, droughts, tornadoes, mechanical failures, explosions, pandemic health events, or similar occurrences;

◦changes in technology available to and utilized by us or our competitors;

◦significant changes in critical accounting policies material to us;

◦significant changes in our relationship with our employees, including the availability of qualified personnel; and

◦weather conditions and other natural phenomena.

For more information on these and other factors, see “RISK FACTORS” in Part II, Item 1A of this report. In light of these risks, uncertainties and assumptions, we caution you not to place undue reliance on any forward-looking statements. The forward-looking statements included in this report are made only as of the date of this report and we do not undertake any obligation to update or revise publicly any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law.

Where You Can Find More Information

We announce material information to the public through a variety of means, including filings with the U.S. Securities and Exchange Commission (“SEC”), press releases and our website at www.basinelectric.com. We use these channels to communicate with our Members, investors and the public about our business and other matters. Therefore, we encourage investors, the media and others interested in Basin Electric to review the information we make public in these locations, as such information could be deemed to be material information.

iii

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CERTAIN DEFINITIONS

Except where otherwise noted, or the context otherwise requires, the following capitalized terms, abbreviations, and acronyms have the meanings set forth below:


Abbreviations or Acronyms						Definitions
AI						Artificial intelligence
ASC						FASB Accounting Standards Codification
ASU						FASB Accounting Standards Update
Basin Cooperative Services						Basin Cooperative Services, a wholly owned subsidiary of Basin Electric that operates on a not-for-profit basis. Basin Cooperative Services provides certain nonutility property management services to us
Basin Electric, we, our, us, the Company and similar terms						Basin Electric Power Cooperative and, in the case of GAAP financial statements, our consolidated subsidiaries
Board						The Board of Directors of Basin Electric
CCR Rule						Coal Combustion Residuals Rule
CFC						National Rural Utilities Cooperative Finance Corporation
Class A Members						Class A Members consist of ten wholesale G&T cooperatives, eight distribution cooperatives and one wholesale municipal provider that have entered into long-term wholesale power contracts with us
Class B Members						Class B Members consist of any municipality or association of municipalities operating within an area served by a Class A Member and which is a member of, and contracts for its electric capacity or energy from, that Class A Member, and which is not eligible for Class C Membership
Class C Members						Class C Members consist of distribution cooperatives and public power districts that are members of a Class A Member and contract for a portion of their electric power and energy from the Class A Member
Class D Members						Class D Members consist of electric cooperatives, municipalities, or associations of municipalities which purchase power directly from us on a basis other than as a Class A, Class B, or Class C Member
Clean Air Act						A U.S. federal law that regulates air emissions from stationary and mobile sources to protect public health and the environment
Clean Water Act						A U.S. federal law that governs water pollution, aiming to ensure clean surface waters by regulating discharges into navigable waters
CO2						Carbon dioxide
Code						Internal Revenue Code of 1986, as amended
Corn Belt						Corn Belt Power Cooperative, a Class A Member
Coteau						The Coteau Properties Company, a subsidiary of North American Coal Corporation
Coteau Lignite Sales Agreement						Dakota Coal purchases lignite coal from Coteau on a cost-plus basis pursuant to this sales agreement with Coteau
D.C. Circuit						United States Court of Appeals for the D.C. Circuit
Dakota Coal						Dakota Coal Company, a wholly owned subsidiary of Basin Electric that operates on a for-profit basis
Dakota Gas						Dakota Gasification Company, a wholly owned subsidiary of Basin Electric that operates on a for-profit basis
DC						Direct Current
DCS						Dakota Carbon Services LLC
DEF						Diesel exhaust fluid
DFS						Dry Fork Generation Station
DOE						United States Department of Energy
DTC						The Depository Trust Company
East River						East River Electric Power Cooperative, Inc., a Class A Member

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EDAM						Extended Day‑Ahead Market, is a forward wholesale electricity market being developed and operated by the California Independent System Operator
EPA						United States Environmental Protection Agency
ERISA						Employee Retirement Income Security Act of 1974
ERISA Plan						Plan subject to Title I of ERISA or Section 4975 of the Code
Exchange Act						Securities Exchange Act of 1934, as amended
FASB						Financial Accounting Standards Board
FATCA						Foreign Account Tax Compliance Act
Federal Power Act						Federal Power Act of 1920, as amended, and the rules and regulations adopted by FERC thereunder
FERC						Federal Energy Regulatory Commission
FIP						Federal Implementation Plan
Fitch						Fitch Ratings Inc.
Freedom Mine						A large lignite coal mine near Beulah, ND, operated by The Coteau Properties Company
G&T						Generation and transmission
GAAP						Accounting principles generally accepted in the U.S.
GHG						Greenhouse gas
Indenture						Amended and Restated Indenture, dated as of May 5, 2015, between Basin Electric and U.S. Bank Trust Company, National Association, as trustee, as amended and supplemented
IRS						United States Internal Revenue Service
kV						Kilovolt
kWh						Kilowatt-hour
LMP						Locational marginal pricing in an energy market
LRS						Laramie River Station
MBPP						Missouri Basin Power Project
McKenzie						McKenzie Electric Cooperative, Inc., a Class C Member
Members						Our electric distribution member systems, consisting of Class A Members, Class B Members, Class C Members, and Class D Members
MFI Ratio						Margins for Interest Ratio
Minnesota Valley						Minnesota Valley Electric Cooperative, a Class A Member
MIP						Member Investment Program
MISO						Midcontinent Independent System Operator, Inc.
MMbtu/day						Million British Thermal Units per day
MMcf/day						Million Cubic Feet per day
Montana Limestone						Montana Limestone Company, a wholly owned subsidiary of Dakota Coal
Moody’s						Moody’s Investors Services, Inc.
MRO						Midwestern Reliability Organization
MVAR						Megavolt-amps reactive
MW						Megawatt
MWh						Megawatt-hour
NAAQS						National Ambient Air Quality Standards
Nemadji River Generation						Nemadji River Generation LLC, previous owner of a 30% undivided interest in NTEC
NEO						Named Executive Officers
NERC						North American Electric Reliability Corporation
New ERA						RUS Empowering Rural America Program
Northern Border						Northern Border Pipeline Company
NOX						Nitrogen oxide

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NTEC						Nemadji Trail Energy Center, a proposed 600-megawatt natural gas-fired combined-cycle electric generation facility that was previously planned to be constructed in Wisconsin
PCAOB						Public Company Accounting Oversight Board (United States)
Pioneer Generation Station Phase IV						Pioneer Generation Station Unit 4, Unit 5 and Units 31-36
PRECorp						Powder River Energy Corporation, a Class C Member
PRM						Planning reserve margin
PSCo						Public Service Company of Colorado
PURPA						Public Utility Regulatory Policies Act of 1978, as amended
RE Act						Rural Electrification Act of 1936
RMR						Rocky Mountain region
RMSC						Risk Management Steering Committee of Basin Electric
RTO						Regional transmission organization
RUS						Rural Utilities Service, which provides funding for the development of rural utilities infrastructure such as water, waste management, power and telecommunications under the U.S. Department of Agriculture
S&P						S&P Global Ratings, a division of S&P Global Inc.
SEC						United States Securities and Exchange Commission
Section 45Q						Section 45Q of the Code, which provides a federal tax credit for carbon oxide (CO₂ and CO) capture and sequestration
Securities Act						Securities Act of 1933, as amended
SNG						Synthetic Natural Gas
SO2						Sulfur Dioxide
SPP						Southwest Power Pool, Inc.
SVPL						Souris Valley Pipeline Limited
Synfuels Plant						Great Plains Synfuels Plant
Tri-State						Tri-State Generation & Transmission Association, Inc., a Class A Member
UGP						Upper Great Plains
Upper Missouri						Upper Missouri G & T Electric Cooperative, Inc., doing business as Upper Missouri Power Cooperative, a Class A Member
U.S.						United States of America
WAPA						Western Area Power Administration
WECC						Western Electricity Coordinating Council, a non-profit corporation that exists to assure a reliable Bulk Electric System in the geographic area known as the Western Interconnection
WEIM						Western Energy Imbalance Market, real‑time wholesale electricity market in the western United States operated by the California Independent System Operator
Western Fuels						Western Fuels Association, a non-profit Wyoming corporation founded by us and Tri-State
WMPA						Wyoming Municipal Power Agency, a Class A Member
WPP						Western Power Pool
Wright-Hennepin						Wright-Hennepin Cooperative Electric Association, a Class A Member
Wyoming Lime						Wyoming Lime Producers, a division of Dakota Coal

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Part I - Financial Information

ITEM 1. FINANCIAL STATEMENTS

BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(unaudited)

Assets


	March 31, 2026		December 31, 2025
	(In thousands)
Property, plant and equipment:
Plant in service	$	10,249,993	$	10,252,773
Construction work in progress	929,635		778,763
Less: accumulated provision for depreciation and amortization	(4,422,530)		(4,375,917)
Net property, plant and equipment	6,757,098		6,655,619

Other assets and investments:
Mine related assets	164,030		166,561
Investments in associated companies	36,760		37,024
Restricted and designated investments	60,107		61,362
Other investments	141,213		138,624
Special funds	69,885		69,564
Total other assets and investments	471,995		473,135

Current assets:
Cash and cash equivalents	622,221		685,570
Restricted and designated cash and cash equivalents	303,190		301,923
Short-term investments	—		630
Receivables – Members	223,807		202,408
Receivables, net	125,203		117,228
Inventories	380,396		358,812
Prepayments and other current assets	117,901		118,837
Total current assets	1,772,718		1,785,408

Deferred charges and other:
Regulatory assets	303,826		311,373
Other noncurrent assets	177,015		172,122
Total deferred charges and other	480,841		483,495

Total Assets	$	9,482,652	$	9,397,657

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

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BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS, Continued

(unaudited)

Capitalization and Liabilities


	March 31, 2026		December 31, 2025
	(In thousands)
Capitalization:
Equity:
Memberships	$	22	$	22
Patronage capital	1,584,817		1,523,238
Retained earnings of subsidiaries	157,776		142,776
Other equity	293,040		294,252
Accumulated other comprehensive income	7,113		13,463
	2,042,768		1,973,751
Noncontrolling interest	3,027		2,676
Total equity	2,045,795		1,976,427

Long-term debt	4,937,383		4,949,264
Finance lease obligations	3,459		3,532

Total capitalization	6,986,637		6,929,223

Commitments and contingencies (Note 15)

Current liabilities:
Long-term debt and finance leases due within one year	176,900		177,134
Accounts payable	319,472		421,715
Notes payable – Members	176,988		159,495
Notes payable	475,000		475,000
Other current liabilities	302,690		196,460
Total current liabilities	1,451,050		1,429,804

Deferred credits and other:
Regulatory liabilities	331,776		336,305
Deferred income tax liability	92,872		90,922
Other noncurrent liabilities	620,317		611,403
Total deferred credits and other	1,044,965		1,038,630

Total Capitalization and Liabilities	$	9,482,652	$	9,397,657

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

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BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited)


	Three Months Ended March 31,
	2026		2025
	(In thousands)
Operating revenue:
Sales - Members (related party)	$	600,778	$	555,678
Other operating revenues (includes related party of $84,244 and $67,703, respectively)	240,425		222,934
Total operating revenues	841,203		778,612

Operating expenses:
Electric fuel and purchased power (includes related party of $57,967 and $45,005, respectively)	335,299		310,658
Electric operations and maintenance (includes related party of $(2,317) and $(1,651), respectively	181,712		177,243
Cost of products sold (includes related party of $20,187 and $16,802, respectively)	131,746		123,734
Nonelectric selling, general and administrative (includes related party of $8,407 and $7,547, respectively)	24,835		24,635
Depreciation, depletion and amortization	65,043		66,123
Total operating expenses	738,635		702,393

Operating margin	102,568		76,219

Other income:
Investment income	9,191		11,648
Other and tax credits	44,533		34,551
Total other income	53,724		46,199

Interest and other charges:
Interest expense	82,463		72,851
Interest charged during construction	(8,838)		(9,272)
Total interest and other charges	73,625		63,579

Margin before income taxes	82,667		58,839
Income tax expense	1,100		4,821
Net margin and earnings including noncontrolling interest	81,567		54,018
Net margin and earnings attributable to noncontrolling interest	(6,200)		(6,316)
Net margin and earnings attributable to Basin Electric	$	75,367	$	47,702

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

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BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited)


	Three Months Ended March 31,
	2026		2025
	(In thousands)
Net margin and earnings including noncontrolling interest	$	81,567	$	54,018

Other comprehensive loss:
Adjustment to post employment liability (net of tax of $(1) and $0, respectively)	(112)		(168)
Unrealized gain on securities (net of tax of $5 and $49, respectively)	14		179
Reclassification of net realized loss on securities (net of tax of $0 and $1, respectively)	—		4
Unrealized loss on cash flow hedges (net of tax of $(1,828) and $(312), respectively)	(6,875)		(1,174)
Reclassification of net realized loss (gain) on cash flow hedges (net of tax of $165 and $(101), respectively)	623		(380)
Total other comprehensive loss	(6,350)		(1,539)

Comprehensive income including noncontrolling interest	75,217		52,479
Comprehensive income attributable to noncontrolling interest	(6,090)		(6,147)
Comprehensive income attributable to Basin Electric	$	69,127	$	46,332

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

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BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(unaudited)


	Memberships		Patronage Capital		Retained Earnings of Subsidiaries		Other Equity		Accumulated Other Comprehensive Income		Noncontrolling Interest		Total
	(In thousands)
Balance, December 31, 2025	$	22	$	1,523,238	$	142,776	$	294,252	$	13,463	$	2,676	$	1,976,427
Comprehensive income (loss)	—		60,367		15,000		—		(6,240)		—		69,127
Transfers to other equity	—		1,212		—		(1,212)		—		—		—
Comprehensive income (loss) attributable to noncontrolling interest	—		—		—		—		(110)		6,200		6,090
Dividends paid to noncontrolling interest	—		—		—		—		—		(5,849)		(5,849)
Balance, March 31, 2026	$	22	$	1,584,817	$	157,776	$	293,040	$	7,113	$	3,027	$	2,045,795

Balance, December 31, 2024	$	22	$	1,476,557	$	125,713	$	285,113	$	4,806	$	2,711	$	1,894,922
Comprehensive income (loss)	—		42,186		5,516		-		(1,370)		—		46,332
Transfers to other equity	—		(9,139)		—		9,139		—		—		—
Comprehensive income (loss) attributable to noncontrolling interest	—		—		—		—		(169)		6,316		6,147
Dividends paid to noncontrolling interest	—		—		—		—		—		(6,097)		(6,097)
Balance, March 31, 2025	$	22	$	1,509,604	$	131,229	$	294,252	$	3,267	$	2,930	$	1,941,304

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

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BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)


	Three Months Ended March 31,
	2026		2025
	(In thousands)
Operating activities:
Net margin and earnings attributable to Basin Electric	$	75,367	$	47,702
Adjustments to reconcile net margin and earnings to net cash provided by operating activities:
Depreciation, amortization and accretion	79,392		75,033
Deferred income taxes	32		1,096
Changes in regulatory assets and liabilities	(809)		4,055
Unrealized loss on investments	4,653		2,898
Patronage capital allocated	(4,894)		(2,934)
Income attributable to noncontrolling interest	6,200		6,316
Recognition of initial payment for tax credits	(5,518)		(2,616)
Changes in other operating elements:
Receivables	(29,412)		(27,126)
Inventories	(21,540)		(21,016)
Prepayments and other current assets	2,088		676
Accounts payable	(22,900)		11,801
Other current liabilities	102,988		87,728
Changes in collateral	(26,640)		3,838
Other operating activities, net	4,692		27,041
Net cash provided by operating activities	163,699		214,492
Investing activities:
Capital expenditures	(227,798)		(106,172)
Proceeds from sales of property	1,502		316
Purchase of investments	(2,071)		(29,655)
Sale of investments	5,541		32,065
Changes in other investments, net	(1,999)		(1,026)
Net cash used in investing activities	(224,825)		(104,472)
Financing activities:
Principal payments of long-term debt	(13,208)		(13,161)
Payment of debt issuance costs	(250)		—
Changes in notes payable – Members, net	18,492		32,009
Dividends paid to noncontrolling interest	(5,849)		(6,097)
Other	(141)		(189)
Net cash (used in) provided by financing activities	(956)		12,562
Net (decrease) increase in cash and cash equivalents and restricted and designated cash and cash equivalents	(62,082)		122,582
Cash and cash equivalents and restricted and designated cash and cash equivalents, beginning of period	987,493		693,910
Cash and cash equivalents and restricted and designated cash and cash equivalents, end of period	$	925,411	$	816,492


Supplemental cash flow information:
Cash paid for interest	$	36,984	$	35,292
Cash paid for income taxes	$	83	$	51
Supplemental disclosure of noncash investing and financing activities:
Accrued acquisition of property, plant and equipment	$	66,926	$	63,252
Operating lease right-of-use assets	$	9,986	$	22,306

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

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BASIN ELECTRIC POWER COOPERATIVE AND SUBSIDIARIES

CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1.ORGANIZATION

Basin Electric Power Cooperative (Basin Electric) is an electric generation and transmission cooperative corporation, organized and existing under the laws of the State of North Dakota. It serves member electric service needs in a nine-state region of North Dakota, South Dakota, Montana, Wyoming, New Mexico, Colorado, Nebraska, Minnesota and Iowa. Basin Electric’s power supply resources are composed of its own generating facilities and contractual power purchase arrangements. Basin Electric owns and operates transmission assets, some of which are a part of regional transmission organizations.

The rates charged to its members for electric service are established by Basin Electric’s Board of Directors with changes in rates subject to acceptance by the United States Department of Agriculture Rural Utilities Service (RUS).

Basin Electric has three wholly owned for-profit subsidiaries, Dakota Gasification Company (Dakota Gas), Dakota Coal Company (Dakota Coal), and Nemadji River Generation (NRG). Basin Electric also has one wholly owned not-for-profit subsidiary, Basin Cooperative Services (BCS). Dakota Gas has a wholly owned for-profit subsidiary, Souris Valley Pipeline Limited (SVPL). Dakota Coal has a wholly owned for-profit subsidiary, Montana Limestone Company (MLC). Dakota Gas owns and operates the Great Plains Synfuels Plant (Synfuels Plant) which converts lignite coal into pipeline-quality synthetic gas and produces a number of other products including anhydrous ammonia, urea, diesel exhaust fluid (DEF), carbon dioxide (CO2), tar oil and chemical products. The Synfuels Plant is located adjacent to Basin Electric’s Antelope Valley Station (AVS) electric generating plant. These plants share certain facilities, and coal and water supplies. Dakota Gas supplies various Basin Electric gas generating stations and AVS with synthetic gas. SVPL owns and operates a CO2 pipeline in Saskatchewan, Canada. Dakota Coal purchases lignite coal from the Freedom Mine, a coal mine in North Dakota that is owned and operated by The Coteau Properties Company (Coteau), a wholly owned subsidiary of The North American Coal Corporation (NACoal). NACoal is a wholly owned subsidiary of NACCO Industries, Inc. (NACCO). Coteau is a variable interest entity (VIE) of Dakota Coal. Pursuant to the coal purchase agreement, Dakota Coal is obligated to provide financing for and has certain rights with respect to the operation of the coal mine. The lignite coal is used in Basin Electric’s Leland Olds Station (LOS), AVS, and Dakota Gas’s Synfuels Plant. Dakota Coal coordinates procurement and rail delivery of Powder River Basin coal to the Laramie River Station (LRS) and the Dry Fork Station (DFS). Dakota Coal also owns a lime plant that sells lime to AVS, the Laramie River Station (LRS) and others. MLC operates a limestone quarry and owns and operates a fine grind plant, both in Montana, and sells limestone to Dakota Coal’s lime plant, LOS and others. BCS provides certain nonutility property management services to Basin Electric. Basin Electric is a 42.27% owner of the Missouri Basin Power Project (MBPP) and acts as the operating agent for the 1,700 megawatt LRS generating plant in Wyoming, associated transmission facilities and the Grayrocks Dam and Reservoir. Basin Electric’s ownership in MBPP is accounted for using proportionate consolidation consistent with accounting for jointly owned utility property. NRG was a 30 percent owner in the Nemadji Trail Energy Center (NTEC) project, which was a proposed 600 megawatt combined cycle generating plant in Wisconsin. In January 2026, NRG exited the NTEC project and the NRG subsidiary is expected to be fully dissolved by the end of 2026.

Dakota Carbon Services LLC (DCS) owns and operates carbon capture assets in North Dakota and contracts for transportation and sequestration of CO2. DCS was formed by DGC with a tax equity partner to monetize tax credits available under Section 45Q of the United States Internal Revenue Code for the capture and sequestration of CO2 (45Q transaction).

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2.BASIS OF PRESENTATION

PRINCIPLES OF CONSOLIDATION–The consolidated financial statements include the accounts of Basin Electric, its wholly owned subsidiaries and its VIE’s, Coteau and DCS. DCS is considered a VIE for which Dakota Gas is the primary beneficiary. All intercompany investments, debt, and receivable and payable accounts have been eliminated in consolidation. Charges from BCS, Dakota Gas, Dakota Coal, MLC and Coteau to Basin Electric and charges from Basin Electric to BCS, Dakota Gas, Dakota Coal, MLC and Coteau are not eliminated as Basin Electric includes the results of these activities in the determination of rates charged to its members (Note 16).

N-7 LLC (N-7) is a Delaware limited liability company formed by OCI Iowa, Inc. (OCI) and Dakota Gas on May 18, 2018. N-7 was formed to market OCI’s, Dakota Gas’s and other companies’ fertilizer and DEF production. N-7 is considered a VIE of Dakota Gas for which Dakota Gas is not the primary beneficiary and, therefore, Dakota Gas is not required to consolidate N-7. However, Dakota Gas has the ability to exercise significant influence over N-7. Therefore, Dakota Gas’s share of N-7 net income is recorded in the consolidated financial statements using the equity method of accounting. The investment in N-7 is included in other investments on the consolidated balance sheets and Dakota Gas’ share of N-7 net income is presented in other and tax credits income in the consolidated statements of operations.

In 2024, Dakota Gas and OCI agreed to dissolve N-7 with final dissolution to be completed in 2026. Basin Electric does not anticipate this to have a material impact on the consolidated financial statements and disclosures.

USE OF ESTIMATES–The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period. Estimates are used for items such as present value of lease assets and lease liabilities, plant depreciable lives, actuarially determined benefit costs, valuation of derivatives, asset retirement obligations, present value of expected tax credits, cash flows used in asset impairment evaluations and income tax expense or benefits. Ultimate results could differ from those estimates.

INTERIM FINANCIAL INFORMATION–Basin Electric’s consolidated interim financial statements are unaudited, and reflect all adjustments management considers necessary (consisting of normal recurring accruals) for a fair presentation. The Financial Statements included herein have been prepared pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (SEC). Certain information and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations; however, we believe that the condensed disclosures provided are adequate to make the information presented not misleading. Basin Electric’s operating results are affected by various factors including sales to members which may vary with weather conditions, the availability and market for sales of surplus power, actions of the Basin Electric board of directors in their role as regulator, general business conditions, the demand for non-utility products and services produced by Dakota Gas, Dakota Coal and Basin Electric’s other subsidiary companies and availability of substitute products in the market, and operating costs which vary based on plant outages, labor conditions and other costs of production. Accordingly, Basin Electric’s operating results for the three-month periods ended March 31, 2026 and 2025 are not necessarily an appropriate base from which to project annual results.

The consolidated interim financial statements should be read in conjunction with the audited consolidated financial statements and notes included in Basin Electric’s final prospectus filed with the SEC pursuant to Rule 424(b) under the Securities Act of 1933, as amended, on May 6, 2026 (the Prospectus). There have been no changes to Basin Electric’s significant accounting policies described in the Prospectus that have had a material impact on Basin Electric’s consolidated interim financial statements and related notes.

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3.NEW ACCOUNTING PRONOUNCEMENTS

RECENTLY ISSUED ACCOUNTING STANDARD UPDATES (ASU) NOT YET ADOPTED

ASU No. 2024-03, Income Statement-Reporting Comprehensive Income-Expense Disaggregation Disclosures: Disaggregation of Income Statement Expenses – In November 2024, the FASB issued new guidance to improve disclosures about a public business entity’s expenses that will require additional detail for certain categories of income statement expenses. The new guidance will be effective for Basin Electric for annual reporting periods beginning after December 15, 2026, and interim reporting periods beginning after December 15, 2027. Early adoption is permitted and the new guidance is to be applied either on a prospective or retrospective basis. Management is currently evaluating the impact of adoption of this new guidance on the financial statements and disclosures.

ASU No. 2025-06, Intangibles-Goodwill and Other-Internal-Use Software: Targeted Improvements to the Accounting for Internal-Use Software – In September 2025, the FASB issued new guidance to modernize existing older guidance regarding capitalization and recognition to reflect the software development approaches currently being utilized. The new guidance will be effective for Basin Electric for annual reporting periods beginning after December 15, 2027, and interim reporting periods within those annual reporting periods. Early adoption is permitted and the new guidance is to be applied using one of the three prescribed approaches. Management is currently evaluating the impact of adoption of this new guidance on the financial statements and disclosures.

ASU No. 2025-09, Derivatives and Hedging: Hedge Accounting Improvements – In November 2025, the FASB issued new guidance in an effort to better reflect an entity's risk management activities in the financial statements. The update makes targeted improvements by addressing five specific matters that arose from the implementation of previous ASU 2017-12, Derivatives and Hedging: Targeted Improvements for Accounting for Hedging Activities and the effects of LIBOR cessation. The new guidance will be effective for Basin Electric for annual reporting periods beginning after December 15, 2026, and interim reporting periods within those annual reporting periods. Early adoption is permitted and the new guidance is to be applied on a prospective basis, although an entity may elect to adopt the guidance for hedging relationships that exist as of the date of adoption. Management is currently evaluating the impact of adoption of this new guidance on the financial statements and disclosures.

ASU No. 2025-10, Government Grants: Accounting for Government Grants Received by Business Entities – In December 2025, the FASB issued new guidance to improve GAAP by establishing authoritative guidance on the accounting for government grants received by business entities. Previously, GAAP did not provide specific guidance about the recognition, measurement, and presentation of a grant received by a business entity from a government, and due to this absence of specific guidance, Basin Electric like many other business entities, utilized the guidance contained in IAS 20, Accounting for Government Grants and Disclosure of Government Assistance. The new guidance will be effective for Basin Electric for annual reporting periods beginning after December 15, 2028, and interim reporting periods within those annual reporting periods. Early adoption is permitted and the new guidance is to be applied using one of the three prescribed approaches. Management is currently evaluating the impact of adoption of this new guidance on the financial statements and disclosures.

4.RESTRICTED AND DESIGNATED CASH AND INVESTMENTS

Cash, cash equivalents, and restricted and designated cash and cash equivalents reported within the

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consolidated balance sheets and included in the consolidated statement of cash flows are as follows:


	March 31, 2026		December 31, 2025
	(In thousands)
Cash and cash equivalents	$	622,221	$	685,570
Restricted and designated cash and equivalents:
MBPP operating funds	31,190		29,923
Deferred revenue	272,000		272,000
	303,190		301,923
Total cash, cash equivalents and restricted and designated cash and equivalents included in the consolidated statements of cash flows	$	925,411	$	987,493

Restricted and designated investments reported within the consolidated balance sheets are as follows:


	March 31, 2026		December 31, 2025
	(In thousands)
Restricted and designated investments:
Funds held in trust for an asset retirement obligation by Bank of Montreal as trustee for SVPL	5,487		5,244
Asset retirement obligations	54,620		56,118
	$	60,107	$	61,362

Restricted cash and investments include funds held by a financial institution, as trustee. Designated cash and investments includes amounts designated by the Basin Electric Board of Directors.

5.SELECTED BALANCE SHEET INFORMATION

INVENTORIES–Inventories were as follows:


	March 31, 2026		December 31, 2025
	(In thousands)
Materials and supplies	$	259,968	$	245,857
Coal and fuel oil	61,232		62,238
Urea	20,891		18,786
Ammonia	14,655		9,233
Ammonium sulfate	7,952		5,081
Lime and limestone	7,886		8,484
Natural gas held in storage	1,688		2,055
Other	6,124		7,078
	$	380,396	$	358,812

COLLATERAL-Certain derivative instruments and certain agreements of Basin Electric and Dakota Gas contain contract provisions that require collateral to be posted if the credit ratings of Basin Electric fall below certain levels or if the counterparty exposure to Basin Electric or Dakota Gas exceeds a certain level.

Collateral posted (received) is related to derivative assets and liabilities and agreements that contain

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credit-related contingent features and is in the consolidated balance sheets as follows:


	March 31, 2026		December 31, 2025
	(In thousands)
Other investments	$	51,215	$	47,575
Prepayments and other current assets	26,350		3,350
Taxes and other current liabilities	(5,434)		(1,954)
	$	72,131	$	48,971

6.INVESTMENTS

Investments in equity securities and available-for-sale debt securities are included in mine related assets, restricted and designated investments and other investments on the consolidated balance sheets. The cost, unrealized holding gains and losses, and fair value of equity and debt securities that do not have an allowance for credit losses were as follows as of March 31, 2026:


			Gross Unrealized Holding				Fair Value
	Cost		Gains		Losses
	(In thousands)
Available-for-sale debt securities:
Corporate and government bonds	$	1,958	$	44	$	—	$	2,002
Equity securities:
Equities and equity funds	43,347		79,899		—		123,246
Bond market funds	79,293		—		(6,239)		73,054
	122,640		79,899		(6,239)		196,300
Other	208		—		—		208
	$	124,806	$	79,943	$	(6,239)	$	198,510

The cost, unrealized holding gains and losses, and fair value of equity and debt securities that do not have an allowance for credit losses were as follows as of December 31, 2025:


			Gross Unrealized Holding				Fair Value
	Cost		Gains		Losses
	(In thousands)
Available-for-sale debt securities:
Corporate and government bonds	$	1,947	$	24	$	—	$	1,971
Equity securities:
Equities and equity funds	42,147		86,512		—		128,659
Bond market funds	78,577		—		(5,573)		73,004
	120,724		86,512		(5,573)		201,663
Other	88		—		—		88
	$	122,759	$	86,536	$	(5,573)	$	203,722

For the three months ended March 31, 2026, there were no sales proceeds on debt securities classified as available-for-sale. For the three months ended March 31, 2025, sales proceeds on debt securities classified as available-for-sale were $17.3 million. The cost of securities sold is based on the specific identification method. The realized losses for the three months ended March 31, 2025 were immaterial.

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The fair value of available-for-sale debt securities by contracted maturity date as of March 31, 2026 was as follows:


	March 31, 2026
	(In thousands)
Due through one year	$	461
Due after one year through five years	729
Due after five years	812
	$	2,002

Held-to-maturity debt securities have contracted maturity dates of one year or less and are included in cash and cash equivalents, restricted and designated cash and cash equivalents and short-term investments on the consolidated balance sheets. The amortized cost of held-to-maturity debt securities as of March 31, 2026 and December 31, 2025, was as follows:


	March 31, 2026		December 31, 2025
	(In thousands)
Corporate commercial paper	$	17,650	$	38,030
Money market funds	689,108		745,170
Treasuries	209,292		199,300
	$	916,050	$	982,500

Included in other investments on the consolidated balance sheets is the cash surrender value of life insurance policies of $1.7 million and $1.6 million, as of March 31, 2026 and December 31, 2025, respectively.

The MBPP provides financing to Western Fuels Association (Western Fuels) and Western Fuels-Wyoming, Inc. (WFW), a wholly owned subsidiary of Western Fuels, for mine development costs associated with coal deliveries to LRS. Basin Electric provides financing to Western Fuels and WFW for mine development costs associated with coal deliveries to DFS.

Notes receivable from WFW of $20.3 million and $20.8 million as of March 31, 2026 and December 31, 2025, respectively, are included in other investments, investments in associated companies and receivables, net on the consolidated balance sheets. Maturities range from July 2026 through May 2043, and the weighted average interest rate is 5.53 percent. The estimated fair value of these notes receivable as of March 31, 2026 and December 31, 2025 was $20.4 million and $21.0 million, respectively, based on the future cash flows discounted using the yield on a treasury note with a similar maturity.

7.DERIVATIVE FINANCIAL INSTRUMENTS

Normal operations expose Basin Electric to risks associated with changes in the market price of certain commodities. Basin Electric entered into derivative financial instruments for the purpose of mitigating the risks associated with market price volatility of natural gas, tar oil, electricity and diesel. Any changes in cash flows from the underlying purchases and sales that are indexed to certain prices are offset by corresponding changes in the cash flows from the derivatives. As directed by a Basin Electric Board of Director’s policy (Board Policy) to monitor risk and establish an internal control framework, Basin Electric maintains a Risk Management Steering Committee (RMSC) that is governed by a Commodity Risk Management Manual (Manual). The Board Policy prohibits speculation and the Manual has been adopted by the RMSC. In offsetting market risk, Basin Electric is exposed to other forms of incremental risk such as credit or liquidity risk.

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The following table presents the outstanding hedged forecasted transactions as of March 31, 2026:

Hedged Transaction

Term

Contracted
Monthly Volumes
of Forecasted
Transactions

Price

Natural gas purchases

Through December 2033

20% to 62%

$2.79 - $6.51 per dekatherm

Tar oil sales

Through December 2027

23% to 90%

$52.00 - $93.80 per barrel

Electricity purchases

Through December 2027

24% to 90%

$30.50 - $58.60 per MWh

Diesel purchases

Through January 2029

9% to 80%

$2.05 - $2.44 per gallon

Basin Electric is also exposed to interest rate risk. To mitigate this risk, Basin Electric entered into various interest rate swaps to reduce the impact of changes in interest rates on certain variable rate long-term bonds and projected future bond issuances. The total notional amount of outstanding swap agreements as of March 31, 2026, was $325.0 million with due dates ranging from 2032 through 2058 at a weighted average interest rate of 5.10 percent.

The fair value and classification of the asset and liability portion of the derivative instruments in the consolidated balance sheets is as follows:


	March 31, 2026				December 31, 2025
Balance Sheet Location	Fair Value of Asset Derivatives		Fair Value of Liability Derivatives		Fair Value of Asset Derivatives		Fair Value of Liability Derivatives
	(In thousands)
Derivatives designated as cash flow hedges:
Commodity derivatives:
Prepayments and other current assets	$	5,031	$	—	$	5,312	$	—
Other investments	1,858		—		1,684		—
Other current liabilities	—		(8,104)		—		(1,319)
Other noncurrent liabilities	—		(1,693)		—		(671)
Total derivatives designated as cash flow hedges	6,889		(9,797)		6,996		(1,990)

Derivatives not designated as cash flow hedges:
Commodity derivatives:
Prepayments and other current assets	12,367		—		34,673		—
Other investments	—		—		1,211		—
Other current liabilities	—		(10,895)		—		(14,763)
Other noncurrent liabilities	—		(13,072)		—		(14,687)
Interest rate derivatives:
Other noncurrent liabilities	—		(19,689)		—		(22,031)
Total derivatives not designated as cash flow hedges	12,367		(43,656)		35,884		(51,481)
	$	19,256	$	(53,453)	$	42,880	$	(53,471)

Under ASC 980, Basin Electric’s Board of Directors defers changes in the fair value of certain derivative instruments as regulatory assets or liabilities. Current settlements of derivatives, including interest rate swaps and commodity derivatives, resulted in (credits) charges to the consolidated statements of operations for the three months ended March 31, 2026 and 2025 of $(14.3) million and $8.3 million, respectively, which are reclassified from regulatory assets and liabilities.

The change in fair value of derivatives deferred as a regulatory item for the three months ended March 31, 2026 and the year ended December 31, 2025 resulted in net deferred (gains) losses of $(9.9) million and $21.7 million, respectively.

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For derivative instruments that are designated and qualify as a cash flow hedge under ASC 815, the gain or loss on the derivative instrument is reported as a component of other comprehensive income (loss) and reclassified into net earnings in the same period or periods during which the hedged transaction affects net margin and earnings and is presented in the same line item on the consolidated statements of operations as the net earnings effect of the hedged item.

The following table summarizes Dakota Gas and Dakota Coal gains and losses and financial statement classification of the derivatives designated as cash flow hedges as of March 31, 2026. This does not reflect the expected gains or losses arising from the underlying physical transactions; therefore it is not indicative of the economic gross profit or loss realized when the underlying physical and financial transactions were settled.


	Location of Loss Recognized in Net (Gain) Loss on Cash Flow Hedging Relationships
	March 31, 2026
	Other Operating Revenues		Cost of Products Sold
	(In thousands)
Total amounts of income and expense line items presented on the consolidated statements of operations in which the effects of cash flow hedges are recorded	$	240,425	$	131,746
Loss on cash flow hedges:
Commodity derivatives:
Amount reclassified from accumulated other comprehensive income into net margins and earnings	$	(760)	$	(28)

The following table summarizes Dakota Gas and Dakota Coal gains and losses and financial statement classification of the derivatives designated as cash flow hedges as of March 31, 2025. This does not reflect the expected gains or losses arising from the underlying physical transactions; therefore it is not indicative of the economic gross profit or loss realized when the underlying physical and financial transactions were settled.


	Location of Gain (Loss) Recognized in Net (Gain) Loss on Cash Flow Hedging Relationships
	March 31, 2025
	Other Operating Revenues		Cost of Products Sold
	(In thousands)
Total amounts of income and expense line items presented on the consolidated statements of operations in which the effects of cash flow hedges are recorded	$	222,934	$	123,734
Gain (loss) on cash flow hedges:
Commodity derivatives:
Amount reclassified from accumulated other comprehensive income into net margins and earnings	$	554	$	(73)

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The following table summarizes Dakota Gas and Dakota Coal gains and losses and financial statement classification of the derivatives designated as cash flow hedges for the three months ended March 31, 2026 and 2025.


	March 31, 2026		March 31, 2025
	(In thousands)
Decrease in fair value of commodity derivatives	$	(8,703)	$	(1,486)
Recognition of losses (gains) in earnings due to settlements on commodity derivatives	788		(481)
Total other comprehensive loss from hedging	$	(7,915)	$	(1,967)

Based on March 31, 2026 prices, a $3.1 million loss would be realized, reported in pre-tax earnings and reclassified from accumulated other comprehensive income during the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

There are certain commodity derivative financial instruments that do not meet the criteria for hedge accounting under ASC 815 when using the critical terms match effectiveness assessment. For those derivatives, gains or losses are recorded in the consolidated statements of operations. The following table summarizes the impact of commodity derivatives that do not meet the criteria. This does not reflect the expected gains or losses arising from the underlying physical transactions; therefore it is not indicative of the economic gross profit or loss realized when the underlying physical and financial transactions were settled.


	March 31, 2026		March 31, 2025
Location of Gain on Derivatives Recognized in Net Margin and Earnings	Recognized Gain		Recognized Gain
	(In thousands)
Derivatives not designated as cash flow hedges:
Commodity derivatives:
Other operating revenues	$	19	$	86
Total	$	19	86

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8.REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities were as follows at:


	Remaining Recovery Period	March 31, 2026		December 31, 2025
		(In thousands)
Regulatory assets:
Deferred income taxes	Over Plant lives	$	164,726	$	160,754
Refinancing fees	Up to 24 years	78,579		80,122
Unrealized loss on interest rate swaps	Up to 6 years	20,263		21,066
Unrealized loss on commodity derivatives	Up to 8 years	19,190		28,239
Other	Up to 49 years	21,068		21,192
		303,826		311,373
Regulatory liabilities:
Deferred revenue		(272,000)		(272,000)
Unrealized gain on equity investments		(16,436)		(18,489)
Post-retirement medical gain		(21,044)		(21,044)
Other		(22,296)		(24,772)
		(331,776)		(336,305)
Net regulatory liabilities		$	(27,950)	$	(24,932)

If all or a separable portion of Basin Electric’s operations no longer are subject to the provisions of ASC 980, a write-off of net related regulatory assets (liabilities) would be required, unless some form of transition recovery (refund) continues through rates established and collected for Basin Electric’s remaining regulated operations. In addition, Basin Electric would be required to determine any impairment to the carrying costs of deregulated plant and inventory assets.

9.ACCUMULATED OTHER COMPREHENSIVE INCOME

The following table includes the changes in the balances of the components of accumulated other comprehensive income on the consolidated balance sheets:


	Post Employment Benefit Plans		Unrealized Gain on Securities		Unrealized Gain (Loss) on Cash Flow Hedges		Total
	(In thousands)
Balance, December 31, 2025	$	9,491	$	16	$	3,956	$	13,463
Other comprehensive income (loss)	(112)		14		(6,252)		(6,350)
Balance, March 31, 2026	$	9,379	$	30	$	(2,296)	$	7,113

Balance, December 31, 2024	$	5,311	$	22	$	(527)	$	4,806
Other comprehensive income (loss)	(168)		183		(1,554)		(1,539)
Balance, March 31, 2025	$	5,143	$	205	$	(2,081)	$	3,267

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10.LONG-TERM DEBT AND OTHER FINANCING

Outstanding long-term debt was as follows at:


	Due Date	Weighted Average Interest Rate at March 31, 2026	March 31, 2026		December 31, 2025
			(In thousands)
Basin Electric Power Cooperative
First Mortgage Bonds
2006 Series	June 2041	6.13%	$	200,000	$	200,000
2017 Series	April 2047	4.75%	500,000		500,000
2025 Series	Oct. 2055	5.85%	700,000		700,000
			1,400,000		1,400,000
First Mortgage Obligations
2005 Series	Dec. 2028-May 2030	5.85%	90,000		90,000
2007 Series	Sep. 2042	5.75%	214,711		216,854
2008 Series	Dec. 2028-Dec. 2038	5.92%	413,389		413,389
2009 Series	Oct. 2027-April 2040	5.47%	132,222		132,222
2011 Series	Oct. 2031-Oct. 2049	4.53%	208,080		208,080
2012 Series	Nov. 2044	4.07%	73,949		73,949
2015 Series	June 2027-June 2044	4.50%	1,353,420		1,353,420
2016 CoBank Note	April 2046	4.48%	66,667		68,333
2016 CFC Note	April 2046	3.74%	50,420		51,050
2022 Series	Feb. 2042-Feb. 2062	3.00%	276,810		276,810
2024 CoBank Note	Nov. 2034-May 2035	6.14%	200,000		200,000
2024 Series	Feb. 2029-Feb. 2054	6.22%	344,033		350,525
2007 and 2008 Notes	June 2027-Dec. 2028	5.09%	4,750		4,750
2023 Note	Oct. 2043	5.56%	72,000		72,000
2025 RUS Loan	June 2033	4.33%	538		538
			3,500,989		3,511,920

Equipment Notes	Dec. 2035-Apr. 2036	5.00%	21,446		21,617
2019 Tax-Exempt Bonds	July 2039	3.63%	150,000		150,000
			171,446		171,617
Dakota Coal
Equipment notes	May 2026-July 2036	4.92%	64,345		66,462
Other		Various	12,583		11,806
			76,928		78,268
			5,149,363		5,161,805
Less:
Current portion			(175,854)		(176,019)
Unamortized debt issue costs			(35,059)		(35,447)
Discount payable			(1,067)		(1,075)
Long-term debt, net of current portion			$	4,937,383	$	4,949,264

In October 2025, in connection with the issuance and sale in a private offering of the First Mortgage Bonds, 2025 Series, Basin Electric entered into an exchange and registration rights agreement with the

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representatives of the initial purchasers of the First Mortgage Bonds. Pursuant to such agreement, Basin Electric filed a Registration Statement on Form S-4 with the SEC on April 15, 2026, which was declared effective on May 6, 2026, with respect to an offer to exchange these First Mortgage Bonds for substantially similar First Mortgage Bonds of Basin Electric that are registered under the Securities Act. On June 5, 2026, Basin Electric completed an exchange offer of these First Mortgage Bonds for like principal amounts registered under the Securities Act.

The estimated fair value of debt at March 31, 2026 and December 31, 2025 was $5.0 billion and $5.1 billion, respectively, based on cash flows discounted at interest rates for similar issues or at the current rates offered to Basin Electric for debt of comparable maturities.

NOTES PAYABLE–Basin Electric and Dakota Gas have outstanding revolving credit facilities which are included in Notes payable on the consolidated balance sheets as follows:


Facility	Expiration Date	Facility Limit		Outstanding Amounts as of March 31, 2026
		(In thousands)
Commercial Paper/Revolving Credit Agreement (a)	March 2031	$	100,000	$	100,000
Revolving Credit Agreement (a)	May 2030	1,250,000		-
2025 Term Loan	October 2026	375,000		375,000
Total notes payable		$	1,725,000	$	475,000

_______________

(a)The taxable and tax-exempt commercial paper programs are supported by revolving credit agreements with various banks. Balances reflect commercial paper amounts outstanding. There were no amounts outstanding under the revolving credit agreements.

As of March 31, 2026 and December 31, 2025, the effective interest rate of the outstanding advances was 4.60 percent and 4.74 percent, respectively.

MEMBER INVESTMENT PROGRAM–Basin Electric holds notes related to funds invested by the members under a member investment program. These funds are used by Basin Electric to reduce short-term borrowings. The members receive investment earnings based on market rates, adjusted for administrative costs. The notes held as part of this program were as follows at:


	March 31, 2026		December 31, 2025
	(In thousands)
Long-term debt, net of current portion	$	1,000	$	—
Notes payable – Members	176,988		159,495
	$	177,988	$	159,495

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11.REVENUE

The following tables disaggregate revenue by major source for the periods presented. The tables also include a reconciliation of the disaggregated revenue by reportable segments. For more information on Basin Electric’s business segments, see Note 14.


	Three Months Ended March 31, 2026
	Electric Utility		Gasification		Coal and Limestone Operations		Elimination of Intersegment		Total
	(In thousands)
Sales of electricity to members	$	600,778	$	—	$	—	$	—	$	600,778
Sales of electricity to non-members	68,804		—		—		—		68,804
Synthetic natural gas	—		42,056		—		—		42,056
Fertilizer and DEF products	—		55,900		—		—		55,900
Other byproducts	—		16,895		—		—		16,895
Lignite coal	—		—		79,062		(30,966)		48,096
Miscellaneous	2,007		344		7,065		—		9,416
Revenue from contracts with customers	671,589		115,195		86,127		(30,966)		841,945
Other revenue	—		(742)		—		—		(742)
Total operating revenue	$	671,589	$	114,453	$	86,127	$	(30,966)	$	841,203


	Three Months Ended March 31, 2025
	Electric Utility		Gasification		Coal and Limestone Operations		Elimination of Intersegment		Total
	(In thousands)
Sales of electricity to members	$	555,678	$	—	$	—	$	—	$	555,678
Sales of electricity to non-members	59,317		—		—		—		59,317
Synthetic natural gas	—		39,888		—		—		39,888
Fertilizer and DEF products	—		51,411		—		—		51,411
Other byproducts	—		18,689		—		—		18,689
Lignite coal	—		—		70,974		(28,604)		42,370
Miscellaneous	2,577		329		6,853		—		9,759
Revenue from contracts with customers	617,572		110,317		77,827		(28,604)		777,112
Other revenue	861		639		—		—		1,500
Total operating revenue	$	618,433	$	110,956	$	77,827	$	(28,604)	$	778,612

OTHER REVENUE–Other revenue includes derivative revenue from hedging activities for synthetic natural gas, tar oil, and electricity sales which is accounted for under ASC 815.

CONTRACT BALANCES–At times, Basin Electric and its subsidiaries will receive payment in advance of performing an obligation under a contract. Unearned revenue, a contract liability, is recognized when this occurs. At March 31, 2026 and December 31, 2025, the unearned revenue balance (included in other current liabilities on the consolidated balance sheets) was $70.1 million and $7.6 million, respectively. There were no contract assets at March 31, 2026 and December 31, 2025. The balance in receivables, net on the consolidated balance sheets represent the unconditional right to consideration from customers.

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12.EMPLOYEE BENEFIT PLANS

POSTRETIREMENT BENEFITS–Eligible employees of Basin Electric, Dakota Gas, and MLC who are retiring may elect to continue medical and dental benefits by paying premiums to continue participating in the current employee plan. Coteau also maintains medical care and life insurance plans which provide benefits to eligible retired employees.

Components of net periodic postretirement benefit expense (income) for the three months ended March 31, 2026 and 2025 were as follows:


	Basin Electric and Subsidiaries				Coteau
	2026		2025		2026		2025
	(In thousands)
Service cost	$	319	$	292	$	3	$	5
Interest cost	258		233		13		16
Amortization of prior service cost	58		58		—		—
Amortization of net actuarial gain	(412)		(459)		(110)		(169)
Net periodic expense (income)	$	223	$	124	$	(94)	$	(148)

Basin Electric, Dakota Gas, and MLC made contributions (withdrawals) of $768,000 and $(163,000) to (from) the postretirement benefit plans during the three months ended March 31, 2026 and 2025, respectively.

DEFINED BENEFIT PLANS

NRECA RS PLAN–Pension benefits for Basin Electric and Dakota Gas employees participating in the pension plan are provided through participation in the National Rural Electric Cooperative Association (NRECA) Retirement Security Plan (RS Plan) which is a defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the Internal Revenue code. It is a multiemployer plan under GAAP.

Pension costs charged to expense for the three months ended March 31, 2026 and 2025 were $9.6 million and $9.5 million, respectively.

BCS AND COTEAU PLANS–BCS’s former United Mine Workers of America employees are covered under a defined benefit plan which is funded by BCS. Substantially all of Coteau’s salaried employees hired prior to January 1, 2000, participate in the Coteau Pension Plan (the Plan), a noncontributory defined benefit plan sponsored by NACoal. In October 2025, Coteau terminated the Plan and settled all future obligations by transferring the remaining benefit obligations to a third-party insurance company.

Components of net periodic pension expense (income) for the three months ended March 31, 2026 and 2025 were as follows:


	BCS				Coteau
	2026		2025		2026		2025
	(In thousands)
Interest cost	$	32	$	31	$	—	$	904
Expected return on assets	(34)		(35)		—		(1,027)
Amortization of net actuarial loss	12		16		—		—
Settlements	—		—		45		—
Net periodic expense (income)	$	10	$	12	$	45	$	(123)

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BCS did not make any contributions to the defined benefit plan during the three months ended March 31, 2026. BCS and Coteau did not make any contributions to the defined benefit plans for the three months ended March 31, 2025.

13.ASSETS AND LIABILITIES MEASURED AT FAIR VALUE

Level 1 inputs utilize observable market data in active markets for identical assets or liabilities. Level 2 inputs consist of observable market data, other than that included in Level 1, that is either directly or indirectly observable. Level 3 inputs consist of unobservable market data which are 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. Basin Electric’s 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.

On March 31, 2026 and December 31, 2025, Basin Electric had government obligations, equity securities, bond market funds and corporate bonds included in restricted and designated investments, mine related assets and other investments, recorded at a fair value, using quoted prices in active markets for identical assets as the fair value measurement (Level 1).

Basin Electric recorded derivative financial instruments including commodity contracts and interest rate swaps using significant other observable inputs as the fair value measurement (Level 2). The fair value for commodity contracts is determined by comparing the difference between the net present value of the cash flows for the commodity contracts at their initial price and the current market price. The initial price is quoted in the commodity contract and the current market price is corroborated by observable market data. The fair value for interest rate swap contracts is determined by comparing the difference between the net present value of the cash flows for the swaps at their initial fixed rate and the current market interest rate. The initial fixed rate is quoted in the swap agreement and the current market interest rate is corroborated by observable market data.

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The following table summarizes assets and liabilities measured at fair value on a recurring basis as of March 31, 2026, aggregated by the level in the fair value hierarchy within which those measurements fall:


	Fair Value		Fair Value Measurements Using
			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In thousands)
Assets:
Investments:
Equities and equity funds	$	123,246	$	123,246	$	—	$	—
Corporate and government bonds	2,002		2,002		—		—
Bond market funds	73,054		73,054		—		—
	198,302		198,302		—		—
Commodity derivatives	19,256		—		19,256		—
	$	217,558	$	198,302	$	19,256	$	—

Liabilities:
Interest rate swaps	$	19,689	$	—	$	19,689	$	—
Commodity derivatives	33,764		—		33,764		—
	$	53,453	$	—	$	53,453	$	—

The following table summarizes assets and liabilities measured at fair value on a recurring basis as of December 31, 2025, aggregated by the level in the fair value hierarchy within which those measurements fall:


	Fair Value		Fair Value Measurements Using
			Quoted Prices in Active Markets for Identical Assets and Liabilities (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
	(In thousands)
Assets:
Investments:
Equities and equity funds	$	128,659	$	128,659	$	—	$	—
Corporate and government bonds	1,971		1,971		—		—
Bond market funds	73,004		73,004		—		—
	203,634		203,634		—		—
Commodity derivatives	42,880		—		42,880		—
	$	246,514	$	203,634	$	42,880	$	—

Liabilities:
Interest rate swaps	$	22,031	$	—	$	22,031	$	—
Commodity derivatives	31,440		—		31,440		—
	$	53,471	$	—	$	53,471	$	—

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14.SEGMENT REPORTING

Basin Electric’s reportable segments include the Electric Utility, Gasification, and Coal and Limestone Operations. Certain activities that support the reportable segments, ancillary projects, or operating segments that do not meet the quantitative threshold for a reportable segment are presented as Other. The operating segments are based on Basin Electric’s method of internal reporting that the Chief Operating Decision Maker (CODM) reviews to make decisions on overall resource allocation and to assess performance. The CODM is Basin Electric’s Chief Executive Officer and General Manager. The CODM reviews actual financial information and forecasted financial information at an operating segment level and primarily uses segment net margin and earnings for making decisions on resource allocation and assessing performance. The CODM uses segment net income in assessing financial performance on a monthly basis, reviewing and approving annual operating budgets and long-term forecasts, allocating capital or financial resources to our segments and in making strategic decisions.

The Electric Utility reportable segment provides wholesale electric service and other ancillary services to Basin Electric’s members throughout its service territory with its own electrical generation and transmission assets and various contractual arrangements.

The Gasification reportable segment includes Dakota Gasification Company (DGC). DGC operates a gasification facility that converts lignite coal into synthetic natural gas and other products including fertilizers, diesel exhaust fluid, carbon dioxide, and other oil and chemical products.

The Coal and Limestone Operations reportable segment purchases coal and coordinates deliveries of coal to Basin Electric’s Electric Utility generation facilities and Gasification operations. It also produces lime and limestone that is used for emissions control at the generation facilities.

Other consists of Basin Cooperative Services, Nemadji River Generation, and certain tax adjustments and other activity not associated with the reportable segments. Basin Cooperative Services provides certain nonutility property management services to Basin Electric. Nemadji River Generation owned an undivided interest in a proposed electric generation facility. In January 2026, Nemadji River Generation exited the project and the NRG subsidiary is expected to be fully dissolved by the end of 2026.

Substantially all of Basin Electric’s assets and revenues are located in the United States. Revenues and assets outside the United States were not material for the periods presented.

Major Customer – For the three months ended March 31, 2026 and 2025, revenues from a single customer, Upper Missouri, represented approximately 30.6 percent and 30.7 percent respectively, of Basin Electric’s consolidated revenues, all of which were attributable to the Electric Utility reportable segment. No other customer contributed 10 percent or more of consolidated revenues for the periods.

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Information on Basin Electric’s segments for the three months ended March 31, 2026 and 2025 was as follows:


	Three Months Ended March 31, 2026
	Electric Utility		Gasification		Coal and Limestone Operations		Total Reportable Segments
	(In thousands)
Operating revenue:
External	$	671,589	$	114,453	$	55,161	$	841,203
Intersegment	—		—		30,966		30,966
	671,589		114,453		86,127		872,169
Elimination of intersegment revenue							(30,966)
Total operating revenue							$	841,203
Less:
Electric fuel and purchased power	335,299		—		—
Electric operations and maintenance	181,712		—		—
Cost of products sold:
External	—		78,525		53,221
Intersegment	—		30,966		—
Nonelectric selling, general and administrative	—		23,740		2,150
Depreciation, depletion and amortization	49,697		10,346		5,000
Other (income) expense	(17,105)		(39,684)		3,065
Interest and other charges:
External	66,527		4,000		3,098
Intersegment	(3,792)		—		—
Income tax (benefit) expense	(1,112)		3,822		3,565
Net margin and earnings attributable to noncontrolling interest	—		—		6,200
Segment net margin and earnings	60,363		2,738		9,828		72,929
Elimination of intercompany gain							(3,792)
Other net earnings							6,230
Net margin and earnings attributable to Basin Electric							$	75,367

Segment capital expenditures (a)	$	221,105	$	1,858	$	4,835	$	227,798
Other capital expenditures							—
Total consolidated capital expenditures							$	227,798

_______________

(a)Does not include accruals for property, plant and equipment as disclosed in the supplemental cash flow information to the consolidated statements of cash flows.

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	Three Months Ended March 31, 2025
	Electric Utility		Gasification		Coal and Limestone Operations		Total Reportable Segments
	(In thousands)
Operating revenue:
External	$	618,433	$	110,956	$	49,223	$	778,612
Intersegment	—		—		28,604		28,604
	618,433		110,956		77,827		807,216
Elimination of intersegment revenue							(28,604)
Total operating revenue							$	778,612
Less:
Electric fuel and purchased power	310,658		—		—
Electric operations and maintenance	177,243		—		—
Cost of products sold:
External	—		72,186		51,548
Intersegment	—		28,604		—
Nonelectric selling, general and administrative	—		22,240		2,395
Depreciation, depletion and amortization	51,505		10,019		4,599
Other (income) expense	(16,781)		(31,111)		1,693
Interest and other charges:
External	51,535		8,688		3,356
Intersegment	2,376		—		—
Income tax (benefit) expense	(275)		2,706		2,404
Net margin and earnings attributable to noncontrolling interest	—		—		6,316
Segment net margin and earnings (loss)	42,172		(2,376)		5,516		45,312
Elimination of intercompany loss							2,376
Other net earnings							14
Net margin and earnings attributable to Basin Electric							$	47,702

Segment capital expenditures (a)	$	99,693	$	4,479	$	1,651	$	105,823
Other capital expenditures							349
Total consolidated capital expenditures							$	106,172

_______________

(a)Does not include accruals for property, plant and equipment as disclosed in the supplemental cash flow information to the consolidated statements of cash flows.

Information on Basin Electric’s segments as of March 31, 2026 and December 31, 2025 was as follows:


	March 31, 2026
	Electric Utility		Gasification		Coal and Limestone Operations		Total Reportable Segments
	(In thousands)
Segment total assets	$	9,027,074	$	1,106,862	$	571,572	$	10,705,508
Other assets							35,171
Elimination of intersegment assets							(1,258,027)
Total consolidated assets							$	9,482,652

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	December 31, 2025
	Electric Utility		Gasification		Coal and Limestone Operations		Total Reportable Segments
	(In thousands)
Segment total assets	$	9,014,439	$	1,053,066	$	568,599	$	10,636,104
Other assets							35,504
Elimination of intersegment assets							(1,273,951)
Total consolidated assets							$	9,397,657

15.COMMITMENTS AND CONTINGENCIES

LEGAL

We are involved in claims, legal proceedings, investigations, and regulatory matters arising in the normal course of business. We regularly analyze relevant information and, as necessary, estimate and record accrued liabilities for legal, regulatory enforcement and other matters in which a loss or range of loss is probable of occurring and can be reasonably estimated. We believe the effect on our consolidated operating results, financial position and cash flows, if any, for the disposition of all matters pending as of March 31, 2026, other than those discussed below, will not be material.

LITIGATION–On November 7, 2019, McKenzie Electric Cooperative, Inc. (McKenzie), a Class C Member of Basin Electric and a member of Class A Member Upper Missouri G&T Electric Cooperative, Inc. (Upper Missouri), filed a lawsuit in North Dakota State Court against both Basin Electric and Upper Missouri. The complaint brought multiple claims against Basin Electric, some of which have since been dismissed. McKenzie’s remaining claims against Basin Electric are: (1) breach of the wholesale power contract (WPC) between Basin Electric and Upper Missouri (either as an alleged three-tier contract among Basin Electric, Upper Missouri and McKenzie, or with McKenzie being a third-party beneficiary to the WPC) by including losses associated with Dakota Gas in rates; and (2) declaratory judgment that the WPC permits McKenzie to terminate its contract with Upper Missouri prior to the expiration of the contract. Summary judgment motions were argued in April 2025 and are currently pending before the court. In September 2025, the parties reached a non-binding settlement in principle, through which the parties agreed to a settlement of all claims and allegations related to the matter. The settlement in principle which has since been modified and agreed to in a formal settlement agreement, is contingent upon certain corporate and regulatory approvals, as applicable to certain of the parties. In the absence of those approvals and a stipulated dismissal, the Court in North Dakota has indicated that it plans to move forward with setting a trial date and ruling on pending motions until the parties inform the Court that the settlement has been finalized. At this time, while a loss is reasonably possible, Basin Electric does not believe that the amount of loss can be reasonably estimated pending finalization of a definitive settlement agreement and therefore has not currently made any accrual for this matter.

FERC PROCEEDINGS–Effective November 1, 2019, Basin Electric ceased qualifying for an exemption from FERC’s jurisdiction under the Federal Power Act. As part of its new compliance requirements, Basin Electric submitted its WPCs and Rate Schedule A to FERC for approval. FERC accepted Basin Electric’s WPCs and 2020 Rate Schedule A subject to hearing and settlement proceedings effective September 15, 2020, and dismissed Basin Electric’s 2019 Rate Schedule A as moot. FERC subsequently accepted and consolidated Basin Electric’s 2021 Rate Schedule A with the ongoing hearing and settlement proceedings effective January 1, 2021. The FERC presiding judge held a hearing on the WPCs and 2020 and 2021 Rate Schedules A from August 28, 2023, to October 27, 2023, and from February 5, 2024, through February 7, 2024. The FERC presiding judge issued his initial decision on June 11, 2024, addressing arguments raised by Class A Member Tri-State Generation and Transmission Association, Inc. (Tri-State), Class C Members McKenzie, Minnesota Valley Electric Cooperative (MVEC), and Wright-Hennepin Cooperative Electric Association (Wright-Hennepin), and the Sierra Club. In particular, the Sierra Club argued that Basin Electric should not be allowed to recover costs in its rates relating to certain of its coal generation assets; McKenzie argued that Basin Electric should not be allowed to recover costs in its rates relating to Dakota Gas; and Tri-State, MVEC, and

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Wright-Hennepin argued that Basin Electric’s calculation of rates for depreciation expense and transmission service are not just and reasonable. The Initial Decision remains pending before FERC on exceptions. FERC has not indicated when it intends to act on the initial decision. In addition, FERC action remains pending on Basin Electric’s 2022, 2023, 2024, and 2025 Rate Schedules A.

On July 16, 2025, Basin Electric received financing under the Rural Electrification Act of 1936. Basin Electric subsequently filed a motion at FERC to dismiss the active rate proceedings involving the WPCs and Rate Schedules A on the basis that, pursuant to Federal Power Act (FPA) Section 201(f), Basin Electric is no longer a public utility subject to FERC rate regulation and also filed notices of cancellation of its rate schedules, tariffs, and other agreements. On September 12, 2025, FERC issued an order accepting the notices of cancellation, finding that, due to Basin Electric’s change of jurisdictional status, it is no longer required to maintain tariff records with FERC. FERC denied rehearing and issued an order addressing the rehearing arguments. The cancellation order has since been appealed by Tri-State to the D.C. Circuit Court of Appeals and remains pending with the appellate court. MVEC has subsequently voluntarily dismissed its objections in this proceeding and withdrawn as a participant in the matter. In September 2025, Basin Electric and McKenzie reached a settlement in principle, through which McKenzie agreed to withdraw its objections to Basin Electric’s rates in the FERC proceedings and withdraw from any other FERC proceedings and/or appeals in which it had intervened against Basin Electric to the greatest extent possible. The settlement in principle is contingent upon execution of a mutually acceptable settlement agreement and corporate and regulatory approvals, as applicable to each party. See also “Litigation” above. On June 5, 2026, FERC denied the motion to dismiss on the basis that it “must ensure that jurisdictional rates charged to customers were just and reasonable.” Basin Electric considered these FERC proceedings and currently has not made an accrual.

RUS FINANCING–On June 10, 2025, McKenzie filed with FERC a complaint against Basin Electric. The complaint requests that FERC find that Basin Electric is not authorized to obtain financing under the Rural Electrification Act of 1936 and that FERC retain jurisdiction over Basin Electric notwithstanding Basin Electric receiving such financing. Basin Electric contested the allegations of the complaint, and further contested McKenzie’s right to the relief requested under the Federal Power Act. On May 21, 2026, FERC issued an order denying the complaint, finding that McKenzie had not demonstrated that Basin Electric's actions were in violation of either Section 204 of the Federal Power Act or its blanket authorization to obtain financing. It is possible that a party to the complaint proceeding may seek rehearing by June 21, 2026.

NORTHWEST RURAL PUBLIC POWER DISTRICT–On March 25, 2024, Northwest Rural Public Power District (NRPPD) filed with FERC a complaint against Basin Electric and Tri-State. The complaint requested that FERC find that NRPPD is permitted to withdraw its membership in Tri-State, terminate its wholesale electric service contract (WESC) with Tri-State, and that its withdrawal and termination is permissible under the wholesale power contract between Basin Electric and Tri-State. In December 2024, FERC issued its order denying the complaint, but finding that NRPPD’s withdrawal from Tri-State and termination of its WESC is not a breach of the wholesale power contract between Basin Electric and Tri-State. FERC denied rehearing and issued an order addressing the rehearing arguments. Basin Electric filed an appeal of the FERC order with the D.C. Circuit Court of Appeals and the matter remains pending with the appellate court. In April 2026, Basin Electric and NRPPD reached a settlement in principle, through which NRPPD will dismiss its pending appeal at the D.C. Circuit and the underlying FERC complaint. The settlement in principle is contingent on execution of a mutually acceptable settlement agreement and regulatory approval, as applicable to each party. Basin Electric considered this matter and currently has not made an accrual.

Additionally, NRPPD has filed a complaint against Basin Electric in federal district court in Nebraska. In its amended complaint, NRPPD seeks a declaratory judgment that Basin Electric and Tri-State are bound by the December 2024 FERC Order that NRPPD’s withdrawal as a member of Tri-State, and therefore as a Class C Member of Basin Electric, is not a breach of the wholesale power contract for the Eastern Interconnection between Basin Electric and Tri-State. NRPPD further claims that it is a third-party beneficiary of the wholesale power contract between Basin Electric and Tri-State, and that Basin Electric has breached its obligations to Tri-State under the wholesale power contract by failing to provide NRPPD with an exit fee. Additional claims were added against Basin Electric for tortious interference with contract,

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tortious interference with a business relationship, and tortious interference with a prospective business relationship. Basin Electric contests the allegations of the complaint and has filed a motion to dismiss, which remains pending with the court. In April 2026, Basin Electric and NRPPD reached a settlement in principle, through which NRPPD will dismiss the pending complaint. The settlement in principle is contingent on execution of a mutually acceptable settlement agreement and regulatory approval, as applicable to each party. Basin Electric considered this complaint and currently has not made an accrual.

OTHER

DEBT GUARANTEE–Basin Electric guarantees, on an unsecured basis, a certain debt obligation of Dakota Coal totaling $21.4 million as of March 31, 2026. In the event Dakota Coal defaults under this obligation, Basin Electric would be required to make payments under its guarantee.

16.RELATED PARTY TRANSACTIONS

Basin Electric provides wholesale electricity sales and other services to its members. Basin Electric had accounts receivable from its members related to member wholesale power agreements of $223.8 million and $202.4 million as of March 31, 2026 and December 31, 2025, respectively.

Other receivables include $2.8 million and $2.3 million as of March 31, 2026 and December 31, 2025, respectively, for amounts Basin Electric, as operating agent, and its subsidiaries, have billed to MBPP. Included in special funds on the consolidated balance sheets is Basin Electric’s advance to MBPP of approximately $17.0 million as of both March 31, 2026 and December 31, 2025.

CONTRACTUAL COMMITMENTS–Basin Electric provides and receives power, various materials, supplies and services to and from affiliates which are under the following agreements:

•POWER SUPPLY–Basin Electric provides all electric capacity, energy and transmission service needed to meet Dakota Gas’ Synfuels Plant requirements under an agreement that extends through 2050.

•SCREENED COAL–Dakota Gas’ Synfuels Plant provides screened coal to Basin Electric under an agreement that extends through 2037.

•COAL SUPPLY–Dakota Coal provides all coal requirements of Dakota Gas’ Synfuels Plant and Basin Electric’s AVS and LOS. This agreement extends through 2037.

•ADMINISTRATIVE SERVICES–Basin Electric provides various administrative and financial services to Dakota Gas, Dakota Coal, MLC and BCS.

•LIME SALES–Dakota Coal provides lime to Basin Electric’s AVS and LRS. The agreement with AVS extends through 2030.

•LIMESTONE SALES–Dakota Coal provides limestone to Basin Electric’s LOS under an agreement that extends through 2040.

•WATER SUPPLY–Basin Electric provides water supply facilities for use by Dakota Gas’ Synfuels Plant.

•SALE OF NATURAL GAS–Dakota Gas sells natural gas to Basin Electric for operation of utility gas generating plants and AVS (includes pipeline related costs).

•USE OF TRANSMISSION ASSETS–Basin Electric uses certain Dakota Gas transmission assets for a fee under an agreement that extends through 2047.

•SALE OF FERTILIZERS, UREA AND DEF-Dakota Gas sells fertilizers, urea and DEF to Basin Electric and MBPP for operation of power generation units.

•PROJECT SERVICES–Basin Electric provides the use of operational assets to Dakota Gas’ Synfuels Plant.

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•OTHER-Dakota Coal provides the maintenance of railroad facilities to Dakota Gas' Synfuels Plant and Basin Electric under an agreement that extends through 2040.

Related party amounts that were not eliminated in consolidation in accordance with ASC 980 were billed as follows for the three months ended March 31, 2026 and 2025:


	March 31, 2026		March 31, 2025
	(In thousands)
Sales of goods and services to:
Dakota Gas
Power supply	$	19,343	$	15,892
Administrative services	7,879		6,917
Water supply	700		643
Project and other services	136		267
Dakota Coal
Administrative services	537		630
Total	$	28,595	$	24,349

Goods and services provided by:
Dakota Gas
Screened coal	$	17,251	$	18,426
Natural gas	9,674		2,638
Transmission and other misc. services	264		257
Fertilizers, urea and DEF	1,331		984
Dakota Coal
Coal supply	31,042		23,941
Lime	4,074		4,214
Limestone	429		441
Other	9		—
Total	$	64,074	$	50,901

Various other intercompany management, administrative and financial services were performed, which were not significant.

17.SUBSEQUENT EVENTS

On May 29, 2026, Basin Electric entered into an Equity Purchase Agreement with a third party to sell the CO2 pipeline that runs from Dakota Gas to Canada. The agreement also provides for the sale of the stock of SVPL because the Canadian portion of the CO2 pipeline is owned by SVPL. Basin Electric expects to receive proceeds of approximately $90.0 million upon closing. The sale is expected to be completed by the end of 2026, subject to customary closing conditions. Dakota Gas will remain involved in the pipeline operations until the expiration of its current Canadian contracts at the end of 2027, after which Dakota Gas expects to redirect CO2 to its carbon sequestration project.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of Basin Electric’s financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and related notes that appear elsewhere in this report and our audited consolidated financial statements and the related notes and the discussion under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations” for the year ended December 31, 2025, included in our final prospectus filed with the SEC pursuant to Rule 424(b) under the Securities Act on May 6, 2026 (the “Prospectus”). In addition to historical consolidated financial information, the following discussion contains forward-looking statements based upon current expectations that involve risks and uncertainties. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of various factors, including those set forth under “Risk Factors” and “Forward-Looking Statements” included elsewhere in this report.

Executive Overview

We are a not-for-profit G&T cooperative corporation based in Bismarck, North Dakota, principally engaged in the business of providing wholesale electric services to our members through long-term wholesale power contracts. These electric services generally represent the capacity and energy requirements of our members beyond that available to them from other sources, primarily WAPA, which provides hydroelectric power and transmission services to our members.

We have three operating segments: Electric Utility, Gasification, and Coal and Limestone Operations. The Electric Utility segment provides wholesale electric service and other ancillary services to our members throughout their respective service territories with our own electrical generation and transmission assets and various contractual arrangements. The Gasification segment includes Dakota Gas, which operates a gasification facility that converts lignite coal into synthetic natural gas and other products, including fertilizers, DEF, carbon dioxide, and other oil and chemical products. The Coal and Limestone Operations segment includes Dakota Coal, which purchases coal and coordinates deliveries of coal to the Electric Utility generation facilities and Gasification operations and produces lime and limestone that is used for emissions control at the generation facilities.

For the three months ended March 31, 2026, we sold 10.7 million MWhs of electricity, of which 82% was sold to our Class A Members. Our consolidated net margin and earnings was $75.4 million in the three months ended March 31, 2026, compared to $47.7 million for the three months ended March 31, 2025. Our results for the three months ended March 31, 2026, were primarily impacted by the following factors:

Total operating revenue increased $62.6 million, or 8.0%.

◦Operating revenue at our Electric Utility operating segment increased primarily due to a rate increase on electricity sales to our members effective January 1, 2026, and increased electricity sales to non-members.

◦Operating revenue at our Gasification operating segment increased mainly due to higher fertilizer, DEF, and synthetic natural gas revenue. Fertilizer and synthetic natural gas sales prices were higher and DEF volumes sold increased.

◦Operating revenue at our Coal and Limestone Operations operating segment increased largely due to higher lignite coal sales resulting from higher average sales prices.

Total operating expenses increased $36.2 million, or 5.2%.

◦Electric fuel and purchased power and Electric operations and maintenance increased largely due to increased fuel, general and administrative, and production expenses. Fuel expenses were higher as a result of higher natural gas generation and prices and higher coal expense. General and administrative expenses increased due to employee-related and software expenses and production expenses were impacted by higher contracted services, property taxes and materials.

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◦Cost of products sold increased primarily due increased prices for electricity, natural gas purchases, and coal.

Other income increased $7.5 million primarily due to monetization of tax credits related to the capture and sequestration of CO2 through Dakota Gas' investment in Dakota Carbon Services LLC.

Interest and other charges increased $10.0 million mainly due to an increase in net interest expense primarily due to higher debt balances resulting from additional capital expenditures in electric utility property.

Key Factors Affecting Results

In addition to commodity prices, changes in rates and weather conditions, other factors have been important to our results of operations and financial condition and may significantly impact our outlook in future periods. Some of these factors include: changes in member load growth; major capital expenditures; commodities and asset management; changes in regional transmission organizations; changes in our membership; our rate structure; the rate covenant in our Indenture; our net margin and patronage capital; the future of Dakota Gas; our tax status; environmental regulations; our large load commercial program; and available financing from RUS. For information regarding these and other factors affecting our results, see “Key Factors Affecting Results” in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of the Prospectus.

Results of Operations

Provided below is a summary and discussion of our operating results on a consolidated basis for the three months ended March 31, 2026 and 2025, followed by a discussion of the operating results of each of our operating segments for the three months ended March 31, 2026 compared to 2025.

Consolidated Summary

The following table summarizes our consolidated net margin and earnings for the three months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
(In thousands)	2026		2025		% Change
Electric Utility	$	60,363	$	42,172	43.1	%
Gasification	2,738		(2,376)		215.2	%
Coal and Limestone Operations	9,828		5,516		78.2	%
Other (a)	2,438		2,390		2.0	%
Net margin and earnings attributable to Basin Electric	$	75,367	$	47,702	58.0	%

_____________

(a)Includes intersegment eliminations.

Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025

•Electric Utility net margin increased primarily due to increased revenue from member sales largely due to higher average rates effective January 1, 2026, and higher electricity sales to non-members partially offset by increased fuel, operations and maintenance expenses and interest and other charges.

•Gasification net earnings increased primarily due to higher monetization of tax credits related to the capture and sequestration of CO2, lower interest and other charges, and higher fertilizer and DEF revenues, partially offset by higher operating expenses related to increased cost of products sold.

•Coal and Limestone Operations net earnings increased primarily due to higher average sales prices of lignite coal.

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Electric Utility Results

Our operating revenue from Electric Utility operations is derived from electricity sales to our members and to non-members (including Dakota Gas). Our revenues from our sales to our members are a function of the volume of those sales and our rates, particularly our rate to our Class A Members. For a discussion of certain factors affecting demand for power from our members and sales to non-members, see “Electric Utility Results” in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of the Prospectus.

The following table summarizes the performance and certain operating statistics of the Electric Utility segment the three months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
(In thousands)	2026		2025		% Change
Operating revenue:
Sales of electricity to members	$	600,778	$	555,678	8.1	%
Sales of electricity to non-members	68,804		60,178		14.3	%
Other	2,007		2,577		(22.1)	%
Total operating revenue	671,589		618,433		8.6	%

Fuel and purchased power	335,299		310,658		7.9	%
Operations and maintenance	181,712		177,243		2.5	%
Depreciation and amortization	49,697		51,505		(3.5)	%
Total operating expenses	566,708		539,406		5.1	%

Operating margin	104,881		79,027		32.7	%

Other income	17,105		16,781		1.9	%
Interest and other charges	62,735		53,911		16.4	%
Income tax benefit	(1,112)		(275)		304.4	%
Net margin	$	60,363	$	42,172	43.1	%

Electricity energy sales (in thousand MWh):
Member sales	8,778		9,106		(3.6)	%
Non-member sales	1,918		1,446		32.6	%
Total electricity energy sales	10,696		10,552		1.4	%

Peak billing demand (in MW)	5,071		5,150		(1.5)	%
Average rate per MWh:
Member sales	$	68.44	$	61.02	12.2	%
Non-member sales	$	35.87	$	41.62	(13.8)	%

Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025

Electric Utility net margin increased $18.2 million as a result of:

Operating revenue increased $53.2 million mainly due to:

•Sales of electricity to members increased $45.1 million primarily due to higher average member rates effective January 1, 2026 partially offset by lower energy volumes sold resulting from lower weather-related demand.

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•Sales of electricity to non-members increased $8.6 million primarily due to increased energy sold partially offset by lower prices. Energy sold increased 472,000 MWhs mainly due to lower member sales.

Fuel and purchased power increased by $24.6 million mainly due to increased fuel expense of $34.5 million due to higher natural gas expense resulting from higher generation from natural gas facilities somewhat due to new gas generation coming online in mid-2025 and higher prices. Coal expense was higher due to increased coal prices. Partially offsetting the increase was a decrease in purchased power of $9.9 million due to lower volumes purchased.

Operations and maintenance increased $4.5 million mainly due to:

•Increased general and administrative expenses of $3.6 million mainly due to higher employee-related expenses and software costs.

•Increased production expenses of $3.5 million primarily due to higher contracted services, property taxes and material costs associated with new gas generation coming online in mid-2025.

•Maintenance expense decreased $3.7 million mainly due to absence of maintenance work performed at Leland Olds Station in 2025.

Interest and other charges increased $8.8 million mainly due to an increase in net interest expense primarily due to higher debt balances.

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Gasification Results

Gasification operating revenue is mainly derived from the sale of synthetic natural gas, carbon dioxide, anhydrous ammonia, urea, DEF and various other products produced by Dakota Gas.

The following table summarizes the performance and certain operating statistics of the Gasification segment for the three months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
(In thousands)	2026		2025		% Change
Operating revenue:
Synthetic natural gas	$	41,784	$	40,710	2.6	%
Fertilizers and diesel exhaust fluid	55,900		51,411		8.7	%
Other byproducts and miscellaneous	16,769		18,835		(11.0)	%
Total operating revenue	114,453		110,956		3.2	%

Cost of products sold	109,491		100,790		8.6	%
Selling, general and administrative	23,740		22,240		6.7	%
Depreciation and amortization	10,346		10,019		3.3	%
Total operating expenses	143,577		133,049		7.9	%

Operating deficit	(29,124)		(22,093)		31.8	%

Other income	39,684		31,111		27.6	%
Interest and other charges	4,000		8,688		(54.0)	%
Income tax expense	3,822		2,706		41.2	%
Net earnings (loss)	$	2,738	$	(2,376)	215.2	%

Sales volumes:
Synthetic natural gas (dekatherms in millions)	7.0		10.1		(30.7)	%
Fertilizer products (tons in thousands)	83.1		83.8		(0.8)	%
Diesel exhaust fluid (gallons in millions)	13.5		11.1		21.6	%

Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025

Gasification net earnings increased $5.1 million as a result of:

Operating revenue increased $3.5 million mainly due to:

•Synthetic natural gas revenue increased by $1.1 million primarily as a result of higher natural gas prices, substantially offset by lower volumes sold. Realized prices of $5.95 per dekatherm were 48 percent higher.

•Fertilizer and DEF revenue increased $4.5 million. Fertilizer sales revenue increased $2.2 million due to higher prices, partially offset by a decrease in volumes sold. DEF revenue increased $2.3 million largely due to higher volumes sold.

Cost of products sold increased by $8.7 million primarily due to higher electricity prices and higher natural gas purchases, labor and benefits, contracted services, and coal expense, partially offset by lower chemicals expense.

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Selling, general and administrative increased by $1.5 million largely due to higher general and administrative expenses, partially offset by lower freight.

Depreciation and amortization increased by $327,000 mainly due to investments in infrastructure enhancement projects to improve the availability of the Synfuels Plant.

Other income was $8.6 million higher largely due to increased benefits from the monetization of tax credits related to the capture and sequestration of CO2 through Dakota Gas’s investment in Dakota Carbon Services LLC resulting from higher CO2 volumes sequestered.

Interest and other charges decreased $4.7 million primarily due to lower interest expense as a result of lower debt balances due to certain third-party debt being paid off in December 2025.

Income tax expense was higher primarily due to higher income before income taxes.

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Coal and Limestone Operations Results

Coal and Limestone Operations revenue is mainly derived from the sale by Dakota Coal of lignite coal for use at our generating facilities and for coal gasification at Dakota Gas. In addition, Dakota Coal operates a limestone quarry and sells lime and limestone to Basin Electric and other third parties.

The following table summarizes performance and certain operating statistics of the Coal and Limestone Operations segment for the three months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
(In thousands)	2026		2025		% Change
Operating revenue	$	86,127	$	77,827	10.7	%

Cost of products sold	53,221		51,548		3.2	%
Selling, general and administrative	2,150		2,395		(10.2)	%
Depreciation, depletion and amortization	5,000		4,599		8.7	%
Total operating expenses	60,371		58,542		3.1	%

Operating margin	25,756		19,285		33.6	%

Other income (expense)	(3,065)		(1,693)		81.0	%
Interest and other charges	3,098		3,356		(7.7)	%
Income tax expense	3,565		2,404		48.3	%
Earnings including noncontrolling interest	16,028		11,832		35.5	%
Earnings attributable to noncontrolling interest	(6,200)		(6,316)		(1.8)	%
Net earnings	$	9,828	$	5,516	78.2	%

Sales volumes:
Lignite coal (tons in millions)	3.2		3.3		(3.0)	%

Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025

Coal and Limestone Operations net earnings increased $4.3 million as a result of:

Operating revenue increased $8.3 million mainly due to higher lignite coal sales of $8.1 million resulting from higher average sales prices.

Cost of products sold increased $1.7 million primarily due to higher costs in lignite coal mining operations.

Selling, general and administrative decreased $245,000 primarily due to lower freight expenses related to lower lime sales.

Depreciation and amortization increased $401,000 mainly due to investments in mining equipment.

Other income (expense) increased $1.4 million due to unrealized losses on investments.

Interest and other charges decreased $258,000 related to lower debt balances.

Income tax expense was $1.2 million higher largely due to higher income before taxes.

Earnings attributable to noncontrolling interest was comparable to 2025.

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Other Results

Other consists of the operations of Basin Cooperative Services, certain tax adjustments, intersegment eliminations, and other activity not associated with the Electric Utility, Gasification, and Coal and Limestone Operations segments. Basin Cooperative Services provides certain nonutility property management services to Basin Electric.

Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025

The change in other is primarily related to the intersegment elimination of the decreased loss at the Gasification segment. See “—Gasification Results” above for further detail on the decreased loss.

Liquidity and Capital Resources

General

Our liquidity is provided through a combination of cash generated from operations (including the operations of our subsidiaries), the MIP, the net proceeds of our financings and available commitments under existing credit facilities. While we fund operational costs with cash generated from our operations and our subsidiaries’ operations, we also issue commercial paper and periodically access our existing credit facilities to manage our liquidity. We also utilize the credit facilities to fund capital expenditures on an interim basis, which we intend to repay with the proceeds of the issuance of long-term debt secured under our Indenture.

Capital Resources

We had cash, restricted and designated cash and short-term investments of $925.4 million as of March 31, 2026. This is inclusive of cash and investments of $272.0 million designated for regulatory revenue deferrals as of March 31, 2026.

Our liquidity is supported by two revolving credit facilities. We have a $1.25 billion unsecured syndicated revolving credit agreement. As of March 31, 2026, we had issued a letter of credit in the amount of $250,000 with no amounts outstanding under this facility and no outstanding taxable commercial paper.

We also have a tax-exempt commercial paper program supported by a $100.0 million credit facility with National Rural Utilities Cooperative Finance Corporation (“CFC”). As of March 31, 2026, $100.0 million of the CFC facility was used to support commercial paper issuances.

We have a MIP available to all Class A and Class C Members. As of March 31, 2026, our obligations under the MIP totaled $178.0 million.

The following table summarizes amounts outstanding under our lines of credit to our subsidiaries:


	Facility Limit		Outstanding Amounts as of March 31, 2026
(In thousands)
Dakota Gas	$	500,000	$	90,000
Dakota Coal	250,000		160,220
Basin Cooperative Services	3,000		—
Nemadji River Generation (a)	300,000		27,599
Total	$	1,053,000	$	277,819

_____________

(a)Nemadji River Generation, our wholly owned subsidiary, was formerly the owner of a 30% undivided interest in NTEC. In January 2026, Nemadji River Generation exited NTEC effective December 31, 2025 and the subsidiary is expected to be fully dissolved by the end of 2026.

Dakota Coal. In addition to our revolving credit facility, Dakota Coal issued a promissory note to us that it used for the expenditures associated with a truck dump and unit train load-out facility. As of March 31, 2026,

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$13.9 million was outstanding under this note. Also, Dakota Coal issued two notes to us that it used for the expenditures associated with development of coal reserves. As of March 31, 2026, $7.6 million was outstanding under these notes.

Cash Flows

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


	For the Three Months Ended March 31,
(In thousands)	2026		2025		% Change
Net cash provided by (used in)
Operating activities	$	163,699	$	214,492	(23.7)	%
Investing activities	(224,825)		(104,472)		115.2	%
Financing activities	(956)		12,562		(107.6)	%
Net (decrease) increase in cash and cash equivalents and restricted and designated cash and cash equivalents	(62,082)		122,582		(150.6)	%
Cash and cash equivalents and restricted and designated cash and cash equivalents, beginning of period	987,493		693,910		42.3	%
Cash and cash equivalents and restricted and designated cash and cash equivalents, end of period	$	925,411	$	816,492	13.3	%

Three Months Ended March 31, 2026, Compared to Three Months Ended March 31, 2025

Operating activities. Net cash provided by operating activities decreased $50.8 million, primarily driven by increased collateral posted and the timing of payment of accounts payable; partially offset by higher net margin and earnings driven by the rate increase effective January 1, 2026.

Investing activities. Net cash used in investing activities increased $120.4 million largely due to $121.6 million in incremental capital expenditures in 2026 mainly resulting from expenditures associated with the Bison Generating Station capital project.

Financing activities. Net cash (used in) provided by financing activities decreased $13.5 million primarily due to the decreased investment from our Members under the member investment program.

Projected Capital Expenditures

For additional information on our projected capital expenditures, see “Project Capital Expenditures” in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of the Prospectus.

Electric Utility

We annually forecast expenditures required for additional electric generation and transmission facilities and capital for enhancement of existing facilities. We review these projections periodically to update our calculations to reflect changes in our future plans, construction costs, market factors and other items affecting our forecasts. Our actual capital expenditures could vary significantly from these projections because of, among other things, unforeseen construction, changes in resource requirements, changes in actual or forecasted load growth, labor market uncertainty, weather or other issues. Our long-range capital plan details actual and projected construction requirements and system upgrades of approximately $7.1 billion for the years 2026 through 2030.

Gasification

Construction and equipment requirements of Dakota Gas are projected to result in capital expenditures of approximately $146 million over the period of 2026 through 2030.

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Coal and Limestone Operations

Mine development and equipment requirements of Dakota Coal are projected to result in capital expenditures of approximately $262 million for the years 2026 through 2030.

Material Cash Requirements

Our material cash requirements relate primarily to operating expenses, capital expenditures and debt service. There were no material changes to our contractual and other obligations from those reported within Management's Discussion and Analysis of Financial Condition and Results of Operations of the Prospectus.

Credit Rating Triggers

Basin Electric Power Cooperative’s senior secured debt and commercial paper have been assigned credit ratings by independent credit rating agencies. The current ratings are as follows:.

Senior Secured

Commercial Paper

Outlook

S&P

Negative

Moody's

P-2

Stable

Fitch

F1+

Stable

These credit ratings are based on rating criteria developed by each rating agency and reflect their respective assessments of Basin Electric’s creditworthiness. Each rating agency applies its own methodologies, and the significance of a particular rating may differ among rating agencies. Credit ratings are not recommendations to purchase, sell, or hold securities, and do not address market price, liquidity, or the suitability of any security for a particular investor. Credit ratings may be revised or withdrawn at any time by the respective rating agencies.

Critical Accounting Estimates

Our consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period. Estimates are used for items such as present value of lease assets and lease liabilities, plant depreciable lives, actuarially determined benefit costs, valuation of derivatives, asset retirement obligations, present value of expected tax credits, and income tax expense or benefits. Ultimate results could differ from those estimates. We refer to accounting estimates of this type as critical accounting policies and estimates.

Our significant accounting policies are discussed in Note 2 to our consolidated financial statements included in the Prospectus. There have been no significant changes to these policies for the three months ended March 31, 2026.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have not been any material changes to market risks during the three months ended March 31, 2026, from those reported in the Prospectus.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of March 31, 2026, 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 Exchange Act. Based on this evaluation, our principal executive officer and principal financial officer concluded that, as of such date, our disclosure controls and procedures were effective at a reasonable assurance level.

Changes in Internal Controls

There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended March 31, 2026, that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

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Part II - Other Information

ITEM 1. LEGAL PROCEEDINGS

Information required by this Item is contained in the Legal section within Note 15, ”Commitments and Contingencies" to the consolidated financial statements in Part I, Item 1.

ITEM 1A. RISK FACTORS

Basin Electric's business, financial condition or results of operations are subject to various risks and uncertainties, including those described below. You should consider carefully the risks and uncertainties described below, together with all of the other information in this report, including the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our consolidated financial statements and related notes. Our business, financial condition and results of operations could also be harmed by risks and uncertainties that are not presently known to us or that we currently believe are not material. If any of these risks actually occur, our business, financial condition or results of operations could suffer. Unless otherwise indicated, references in this section to our business being harmed will include harm to our business, reputation, results of operations, financial condition, and prospects. In such event, the market price of our debt securities could decline. The risks discussed below also include forward-looking statements and our actual results may differ substantially from those discussed in these forward-looking statements. See “FORWARD-LOOKING STATEMENTS” in this report.

Financial Risks

Our results of operations and financial condition are largely dependent upon our Class A Members, and two Class A Members individually account for more than 10% of our total Class A Member revenue.

Our results of operations and financial condition depend on our Class A Members to satisfy their obligations to us in accordance with our wholesale power contracts with them. Electric sales to our Class A Members provided approximately 89.7% and 90.5% of our electric sales revenue for the three months ended March 31, 2026 and the year ended December 31, 2025, respectively. Upper Missouri Power Cooperative (“Upper Missouri”) accounted for 42.8% and 42.7% and East River Electric Power Cooperative (“East River”) accounted for 12.8% and 12.8%, of our total Class A Member revenue for the three months ended March 31, 2026 and the year ended December 31, 2025, respectively. If one or more of our Class A Members were to default in the performance of its obligations to us under their wholesale power contract, our results of operations or cash flows could be adversely affected.

Most of our wholesale power contracts with our Class A Members extend through 2075; however, our wholesale power contracts with Tri-State, Minnesota Valley, Wright-Hennepin and WMPA only extend through 2050. These members represented in the aggregate approximately 8.8% and 10.1% of Class A Member sales for the three months ended March 31, 2026 and the year ended December 31, 2025, respectively. There cannot be any assurance that our wholesale power contracts with these Class A Members will be extended or replaced prior to the expiration of these contracts.

Financial difficulties, such as those resulting from challenges in passing through its costs to its customers, could affect a member’s ability to perform its obligations under its wholesale power contract with us. Such challenges could arise from the failure of the member’s board of directors to establish rates and charges sufficient to recover the member’s costs, including power costs owed to us. If our cost of power were to become uncompetitive, large industrial customers of our Class A Members could seek to self-generate their power requirements or customers of the members could seek to cause our members to become subject to state rate regulation. Certain of our members, such as those located in Wyoming, are already subject to rate regulation by state regulatory authorities. New or additional state-level rate regulation of a member could potentially affect its ability to recover costs and meet its obligations to us. We cannot predict if or when any such state-level rate regulation will be implemented in the future in other states within our service territory or what the impact of future state-level rate regulation may be. To date, however, such state-level rate regulation has not prevented affected members from being able to recover their costs.

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We have a substantial amount of indebtedness and expect to incur significant future capital expenditures. Constraints on our access to, or increases in our cost of, capital could adversely affect our results of operations and financial condition.

Our substantial existing indebtedness and the significant capital expenditures planned through 2030 to construct, acquire, and make capital improvements to our generation and transmission facilities will require our continued access to the capital markets. As of March 31, 2026, we had total debt outstanding of approximately $5.8 billion. In the years 2026 through 2030, we forecast that we will invest approximately $7.5 billion in capital expenditures for the development and construction of new generation and transmission resources to serve existing and projected load growth and upgrades to our existing facilities. The scope and timing of these investments are subject to numerous uncertainties, including the forecasted electric demand of our members; the availability and cost of available power purchase options; our membership in regional transmission organizations and their applicable tariffs and policies; federal funding; and regulatory approvals and changes in law. For additional information, see the discussion under the caption "Projected Capital Expenditures" in "MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.”

We expect to incur significant indebtedness to fund this capital expenditure program. Failure to obtain financing may adversely affect our results of operations, liquidity and financial condition, and may result in development uncertainties for our generation and transmission business. Although we plan on exploring additional financing of projects from RUS, our ability to receive any such financing could be impacted by the terms set by RUS and, because RUS funding availability is dependent on Congressional appropriation, competition for RUS loans from other electric cooperatives may exceed available funds. In addition, a significant increase in our indebtedness is likely to increase the cost of electric service we provide to our Class A Members due to increasing interest expense as well as our objective to maintain “A” category credit ratings. If demand for electricity from our Class A Members is materially less than projected, we might not generate sufficient revenue to meet the MFI Ratio requirements in the Indenture or to service our indebtedness. If this occurs, we may be required to raise our rates, revise our plans for capital expenditures or restructure our long-term commitments. These actions may adversely affect our operations, and we may be unable to generate sufficient additional revenue to pay our obligations.

We also rely on access to short-term and long-term capital to meet our liquidity needs not funded by operating cash flows. Our access to capital, or cost of, could be adversely affected by various factors, and some market disruptions could constrain, at least temporarily, our ability to maintain sufficient liquidity and access capital on favorable terms, or at all. These factors and disruptions include:

•our credit ratings being downgraded;

•financial markets view of our relationship with our members, including the outcome of litigation or regulatory proceedings;

•challenges or delays related to rate changes for our Class A Members; and

•some of the wholesale power contracts with our Class A Members only extending through 2050.

Broader economic and market conditions that may affect our access to, or cost of, capital include:

•geopolitical instability, economic downturns or market uncertainty;

•market pressures, including tightening of lending standards by commercial banks and other credit providers;

•changes in prevailing interest rates due to changes in U.S. Treasury rates or credit spreads; and

•conditions in the energy industry and the generation and transmission cooperative sector.

Even if we maintain access to the capital markets, capital may only be available on terms and conditions we consider unfavorable, including higher interest rates or more restrictive covenants and conditions to borrowing or events of defaults. If our ability to access capital becomes constrained, our ability to finance capital

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expenditures could be limited, our interest costs could increase, and our results of operations and financial condition could be adversely affected.

The financial performance of our subsidiary, Dakota Gas, has a significant impact on our financial results and its future is uncertain. We continue to explore strategic alternatives and some of the alternatives could result in substantial costs or may result in an asset impairment.

Our consolidated financial results are significantly affected by the performance of Dakota Gas. The Gasification operating segment accounted for 13.6% and 16.0% of our consolidated revenue for the three months ended March 31, 2026, and the year ended December 31, 2025, respectively. As of March 31, 2026, none of our equity represented retained earnings of Dakota Gas. The Gasification segment reported net income (loss) of $2.7 million, ($34.8) million, and ($31.3) million for the three months ended March 31, 2026, and the years ended December 31, 2025 and 2024, respectively. Historically, we have benefited from synergies with Dakota Gas, including economies of scale resulting from a shared coal supply that lowers our fuel cost and various shared services. Additionally, because Dakota Gas produces and sells natural gas and we purchase natural gas for electric generation, its natural gas sales offset part of the risk associated with our natural gas purchases, creating a natural hedge. Dakota Gas’s financial performance remains exposed to significant commodity price volatility, and operating losses and negative cash flows could continue if commodity prices remain low.

We continue to evaluate various strategic options, including a potential sale of the equity or assets of Dakota Gas, in whole or in part. Dakota Gas’s principal assets include the Synfuels Plant and geologic sequestration project at the Synfuels Plant. There is no assurance that any transaction will occur. A sale or other strategic action could result in the loss of existing synergies with Dakota Gas. Decommissioning or repurposing the Synfuels Plant could require substantial costs including site reclamation, employee severances and the loss of our above-described synergies with Dakota Gas.

The nature and extent of risks associated with the future of Dakota Gas and its assets cannot be fully predicted and events relating to the Synfuels Plant may affect us in ways that we cannot currently anticipate. Although the value of the coal gasification assets of the Synfuels Plant has been written off, we could incur additional impairment charges related to our remaining non-coal gasification assets investments in Dakota Gas. If an impairment occurs, we expect that we would seek regulatory accounting treatment from RUS to amortize the resulting regulatory asset over a future period. Failure to receive such regulatory accounting treatment could materially adversely affect our results of operations, financial condition and cash flows. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Key Factors Affecting Results—Future of Dakota Gas.”

Any one or a combination of risks associated with Dakota Gas may have a material adverse effect on our results of operations, financial condition and cash flows.

Changes in commodity prices, including natural gas, coal, purchased power, and fertilizers and other products produced by Dakota Gas, could adversely affect our cost of electric service and Dakota Gas revenue.

We purchase power and fuel from other suppliers exposing us to market prices of various commodities that could increase our operating expenses. In 2025, natural gas units comprised approximately 20.0% of our maximum winter generating capacity. With the addition of Bison Generating Station, we forecast that in 2031 this amount will increase to approximately 35.0%. Historically, Dakota Gas has provided a natural hedge for us against price fluctuations of natural gas. However, as we add additional natural gas generation, we expect to burn more natural gas annually than what Dakota Gas produces and the value of this natural hedge may decrease. There can be significant volatility in market prices for fuel, power and other energy-related commodities, both in general and across geographies, because of broader supply chain challenges, geopolitical events or conflicts, and commodity availability constraints. Natural gas supplies may also be unavailable due to increased demand during periods of exceptionally cold weather and are also subject to disruption due to natural disasters and similar events or infrastructure failure. Further, purchasing electric power in the market exposes us, and consequently our members, to market price risk because electric power prices can fluctuate substantially over short periods of time. Increases in power and fuel prices related to natural gas or coal could

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significantly increase the cost of electric service we provide to our Class A Members and affect their ability to perform their contractual obligations to us.

Although our hedging activities help reduce some market price risk, Dakota Gas remains exposed to volatile commodity prices which could result in future losses. Additionally, Dakota Gas’s products also are exposed to market risks other than pricing, particularly in the agricultural sector. Economic conditions in the agricultural sector directly influence demand for fertilizers, such as anhydrous ammonia, ammonium sulfate and urea, exposing Dakota Gas’s revenues to downturns in this sector. Further, most market price risks related to products other than natural gas and tar oil cannot be hedged because no efficient derivative market exists for these commodities. As a result, changes in natural gas, fertilizer, and other commodity prices could adversely affect our results of operations and financial condition.

Market or regulatory pressures may cause us to retire our coal-fired generating facilities earlier than the units’ depreciable lives, which could result in substantial additional costs.

As of March 31, 2026, our coal-fired electric generation facilities totaled approximately $2.0 billion of our net assets. We own, lease and operate coal-fired generating facilities with 3,665 MW of capacity as of December 31, 2025. Early retirement of these facilities could lead to substantial expenses, including accelerated depreciation, increased purchased power and capacity costs, or significant capital investments to replace lost capacity or repurpose existing facilities. Early retirement of these facilities could also create stranded assets unless we obtain regulatory accounting treatment approval from RUS to establish a regulatory asset to recover related costs over time. Without such approval, we could face substantial impairments to our members’ patronage capital and other equities. Even with regulatory accounting treatment, amortization of these costs may require rate increases that could reduce the competitiveness of our service.

Early retirement would also accelerate reclamation and mine-related obligations, increasing both the timing and total amount of these costs. In addition, we could incur severance obligations for employees at the facilities and associated mines, as well as significant termination charges under take-or-pay transportation contracts.

Our costs for future capital expenditures may be adversely affected by unanticipated higher levels of inflation, increasing labor costs and shortages, implementation of tariffs, and other supply chain disruptions.

Our ability to meet our Class A Members’ electric power requirements and complete our capital projects is dependent on maintaining an efficient supply chain and controlling our costs, including labor, material and financing costs. We are experiencing longer lead-times on the procurement and delivery of some materials and equipment, which have been impacted by domestic and global supply chain disruptions. Additionally, inflation has contributed to lingering high prices for materials and equipment and increases in labor costs to retain sufficient labor resources. Imposed and proposed tariffs could significantly increase the prices and delivery lead times on materials and equipment critical to completing our capital projects.

We are exposed to the credit and liquidity risk of and with counterparties beyond our Class A Members.

In addition to our Class A Members, we are exposed to the risk that contractual counterparties will default in the performance of their obligations to us. We regularly analyze and monitor the default risks of counterparties and other credit issues related to our material contracts. Based on our review, we may require counterparties to post credit support. Still, defaults may occur. Defaults may take the form of failure to physically deliver purchased goods or supplies, such as power or natural gas. If a default occurs, we may be forced to enter into alternate contractual arrangements at prices that may be less favorable than those in the original contracts. If a defaulting counterparty is in poor financial condition, we may not be able to recover damages for breach of contract.

Dakota Gas also has exposure to the credit risk of its counterparties. Several byproducts produced at the Synfuels Plant have a small number of potential purchasers. Evaluation of these purchasers’ respective credit quality is impaired by the limited availability of independent financial information and analysis for these entities. A contractual counterparty may fail to perform its obligations to Dakota Gas, which could adversely affect our consolidated results of operations, financial condition or cash flows.

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Additionally, certain of our financial agreements and commercial contracts include collateral and termination triggers that may be active if credit metrics fall below specified levels and may require posting of collateral (in the form of letters of credit, surety bonds or cash) or termination of the agreements, which could adversely affect our results of operations, financial condition, or cash flows, as well as our ability to enter into future financial agreements and commercial contracts.

The use of hedging arrangements may not work as planned or fully protect us and could result in financial losses and requirements to post collateral.

We typically enter into hedging arrangements, including contracts to purchase or sell commodities at future dates and at fixed prices, in order to manage our commodity price risks. These activities, although intended to mitigate price volatility, expose us to risks related to commodity price movements and other risks. When we purchase or sell commodities forward, we may be required to post significant amounts of cash collateral or other credit support to our counterparties if forward prices move unfavorably to our position. Further, if forward price curves move unfavorably to our position the values of financial contracts may deteriorate and could result in adverse effects to our results of operations, financial condition, or cash flows. We also employ risk management techniques to hedge against interest rate volatility. However, significant and sustained volatility in market interest rates could still materially increase our financing costs and adversely affect our results of operations, cash flows and liquidity.

We maintain internal policies and procedures intended to govern hedging activities, including limits on positions and a prohibition on speculative trading. While these policies and procedures are designed to prevent hedging arrangements in excess of desired limits or unauthorized hedging transactions, they may not detect all violations, particularly in instances involving intentional misconduct or deception. Any failure of our risk-management controls or processes could result in unintended positions, financial losses, or other adverse effects on our results of operations, financial condition, or cash flows.

The scope or amount of our insurance coverage may be insufficient.

We maintain a comprehensive insurance and self-insurance program to provide coverage for various types of risks, including severe weather or other natural disasters, wildfires, property damage, war, terrorism, cyber incidents, liability claims against us, or a combination of other significant unforeseen events that could affect our operations. However, insurance coverage may not continue to be available or may not be available at rates or on terms similar to those presently available to us. Our ability to obtain insurance and the terms of any available insurance coverage could be adversely affected by the financial condition of insurers, industry losses, the impacts of actual or perceived climate-related events, as well as international, national, state, local or business-specific events. There may be some instances in which we are not fully insured against all significant losses. A loss for which we are not fully insured could have an adverse effect on our business, results of operations, financial condition and prospects. If the amount of insurance is insufficient or otherwise unavailable, the costs of uninsured losses, our results of operations, financial condition or cash flows could be adversely affected.

Operating Risks

Factors outside our control could disrupt our power supply plans.

We are focused on reliably and economically meeting our members’ requirements for electric power. We continually evaluate and refine our power supply strategy to achieve this objective in a manner that balances the forecasted cost of power to our members, our ability to provide reliable service and our impact on the environment. Based on our strategy, we develop and construct new generation and transmission facilities and enter into long-term and short-term power purchase agreements. In developing and implementing our strategy, we are guided by our forecasts of future market conditions and our assessment of the likelihood of the occurrence of various contingencies. Some of these contingencies include:

•Future market prices for natural gas and electricity;

•Current and future transmission constraints and changes in the location of load impacting the ability to deliver electricity to desired locations; and

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•Trends in the rate of installation of renewable energy resources, such as wind-powered generation facilities and energy storage, in the service territories of our members and neighboring regions.

As with any forecast, our ability to accurately predict or anticipate future events becomes less reliable the farther into the future the forecast extends. We must make assumptions to develop our plans for the future. These assumptions include economic forecasts, cost estimates, construction schedules, power demand forecasts, reliability and reserve margin requirements, the appropriate generation mix to meet demand and potential changes to the regulatory environment. Should our assumptions be inaccurate, or be superseded by subsequent events, or unexpected contingencies occur, our plans may not be effective in achieving the intended results, which could adversely affect our results of operations, financial condition or cash flows, our ability to meet electricity demand, or the way we conduct our business.

Our ability to successfully develop and execute our power supply strategy for our members is complicated by the need to serve load in both the Eastern Interconnection and the Western Interconnection of the United States and the need to balance our members’ requirements in several transmission systems. For example, a surplus of generating capacity located in MISO may not easily be used to meet additional load in SPP. A surplus of transmission capacity may also exist in one system, while transmission constraints requiring significant investment may exist in another system. Consequently, even if our power supply portfolio includes the right mix of resources, those resources may not be optimally located for efficient use as the grid continually evolves.

Failure of our facilities to operate as we plan could have an adverse effect on our results of operations or financial condition.

The operation of our generation or transmission facilities involves risks, including the breakdown or failure of power generation equipment, transmission lines, pipes or other equipment or processes and performance below expected levels of output or efficiency. The occurrence of any such events could result in:

•Loss of market sale opportunities;

•Significant expenditures to repair or replace the affected facilities or related infrastructure;

•Failure to maintain the integrity or reliability of our transmission system; or

•Increases in purchased power.

In the Eastern energy markets of SPP and MISO, failure of our facilities to operate as planned could also result in:

•Loss of capacity accreditation, requiring the purchase of additional market capacity and potentially resulting in deficiency payments under applicable market rules;

•Increase in market pricing, if the unit in outage is the marginal unit or affects the pricing of the marginal unit;

•Increase in market pricing if a transmission outage or changes in load or generation resources drives an increase in congestion costs; or

•Financial implications of not providing MWhs to the market, if a unit has committed MWhs in the day-ahead market and cannot provide that energy in real time.

In Western markets of the Western Electricity Coordinating Council (“WECC”), failure of our facilities to operate as planned could result in:

•The need to operate alternative facilities for an extended period of time, likely at a greater cost;

•A default on a contractual obligation to deliver power; or

•The purchase of potentially more costly replacement energy and capacity power in the market.

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In addition, the failure of our generation, transmission or other facilities to perform as planned may cause health, safety or environmental problems. Our ability to safely and reliably operate, maintain and construct our facilities is subject to numerous risks, many of which are beyond our control, including:

•The failure to take timely or adequate action to mitigate identified unsafe conditions, resulting in a catastrophic event; or

•Operator or other human error.

If one or more of these events materialized, our results of operations, financial condition, or cash flows could be adversely affected.

We are subject to construction risks for additional projects we are undertaking to meet projected load growth.

In 2026 through 2030, we expect to spend approximately $7.5 billion on additional capital expenditures on a consolidated basis. Our capital plan includes construction of new generation resources and a number of new transmission lines and facilities. See “MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Liquidity and Capital Resources—Projected Capital Expenditures” for a description of our capital plan for additional electric generation and transmission facilities and capital for enhancement of existing facilities.

Our development and construction of new generation and transmission resources is subject to construction risk. We will also be subject to construction risks for capital projects to comply with current or future environmental standards. Many factors could lead to cost increases, cost overruns, and schedule delays for any of these projects, including:

•challenges related to the failure of contractors, subcontractors, or vendors to perform their obligations;

•timing and issuance of necessary permits, licenses, or approvals (including required certificates from regulatory agencies) and any related litigation or stakeholder opposition;

•unforeseen engineering problems or scope changes;

•performance under construction and equipment agreements and contract disputes;

•environmental litigation; and

•environmental, cultural, geological, and weather conditions.

The Company is progressing planned wind turbine repowering projects within its generation fleet in North and South Dakota. Certain projects have experienced delays in permitting approvals due to certain review requirements. These delays may shift anticipated construction timelines and the timing of related capital expenditures, and could increase project costs or reduce expected economic benefits. If such impacts occur, we could incur impairment charges or other adverse financial effects associated with these assets. In such circumstances, we would expect to seek regulatory accounting treatment from RUS or other applicable regulators to defer and amortize such costs over a future period. Failure to obtain such regulatory accounting treatment could adversely affect our results of operations, financial condition, and cash flows.

Construction‑related inflation, labor availability, supply chain disruptions, and tariff impacts may also contribute to project cost or schedule risk as discussed elsewhere in this “RISK FACTORS” section. Failure to complete any construction project on schedule and on budget for any reason could have an adverse effect on our results of operations.

Our members’ requirements are impacted by matters outside our control, including the power requirements in the Bakken shale formation and the operation of data centers.

In addition to the structure and nature of our power supply resources, our members’ requirements for power can significantly impact our results of operations, financial condition and cash flows. We currently forecast that our members’ peak demand requirements supplied by us will increase at an average annual compound rate of

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2.5% for the period from 2026 through 2031, exclusive of large loads. Our forecasts of our members’ requirements and their actual future requirements may vary significantly. If we overestimate the growth in our members’ requirements, there is no assurance that the price of surplus capacity or energy from surplus power supply resources will be economical or could be sold without a loss. In addition, costs related to any new facilities constructed to meet the anticipated load growth could increase some of these members’ cost of electric service more than anticipated and could affect their ability to perform their contractual obligations to us. If we underestimate the growth in our members’ requirements, we may be required to purchase capacity or energy at a cost substantially above the cost we would have incurred to obtain the power or generate the energy from facilities we own.

Several factors could influence the actual rate of growth of our members’ requirements, including:

•The power requirements of our members serving commercial and industrial loads, including the Bakken shale formation and the operation of data centers to meet the increased demand for artificial intelligence (“AI”) resources as described below;

•Agricultural commodity price fluctuations and possible diseases that cause disruption in the food supply chain;

•Volatile pricing in the crypto currency markets that results in loads being curtailed or ramped up unexpectedly;

•The impact of extended periods of unusual or extreme weather on power requirements;

•Changes in trends “behind the meter,” such as growth in the use of distributed solar generation equipment and energy storage that reduce energy purchases from our members and thus us;

•Implementation of energy conservation and demand response programs that reduce peak demand; and

•Macroeconomic conditions in the members’ service territories, including population or economic changes.

Currently, one of the largest factors affecting the rate of growth of our members’ power requirements is economic activity related to oil and natural gas production in the Bakken shale formation in western North Dakota and eastern Montana. While the rate of growth of power requirements associated with oil production in the Bakken has moderated in recent years, growth still continues. Many factors impact oil and natural gas production in this region. One factor is the volatility of crude oil and natural gas prices. A significant decline in the price of crude oil and natural gas could impact the development of this region. Therefore, the estimates as to the production volumes in the region could be too high and, as a result, our members’ requirements for power could be impacted.

Due to the depth of the oil and natural gas, production from this formation requires fracking to separate the oil from the rock formation. To the extent that production of oil and natural gas by hydraulic fracking becomes more regulated by state or federal governments, production could be restricted or become more expensive, thereby impacting our Class A Members’ load growth. Over the past decade, there has been an increase in the number of regulations and restrictions on the production of oil and natural gas through hydraulic fracking, including several states banning the practice entirely. Currently, the majority of the oil and natural gas recovered in our Class A Members’ service territories are recovered utilizing hydraulic fracking. While we do not currently anticipate any regulations, restrictions or bans on fracking in the areas in which we operate, any regulation, restriction or ban by federal, state or local governments on fracking in those areas could adversely affect our results of operations, financial condition or cash flows and the way we operate our business.

Substantially large loads considered for development in the service territories of our Class A Members could significantly impact our Class A Members’ requirements for power and our results of operations.

We are projected to experience significant load growth over the next several years resulting from traditional load growth and the development of several large commercial projects, including AI resources, data centers and cryptocurrency mining. Our members have received requests to commit to provide thousands of megawatts of baseload energy to new large loads. Both the number and size of these large load requests that are being

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considered for development and construction in the service territories of our members are increasing and expected to further increase substantially with the growth of AI and other factors, thereby potentially materially increasing the aggregate power requirements of our members. The volume of these large load requests and uncertainty related to these requests create risks.

To the extent that any of our members serve large data centers, serving this additional load growth may put pressure on our existing generation and transmission infrastructure and will require significant investments to meet the anticipated load growth and they will be subject to increased counterparty risk to customers that may consume a disproportionate percentage of their sales. Changes in technology could impact the development and continued resource needs of data centers and any significant decrease in those needs could affect the counterparty’s willingness or ability to pay for large amounts of electricity. Cryptocurrency data mining centers’ energy demands are particularly unpredictable as they may be affected by federal or state regulatory actions and are highly incentivized to operate in regions with relatively low energy prices and are able to shut down and relocate relatively easily. The potential volatility in energy demands from our Class A Members from these operations can exacerbate the challenges in determining our long-term power supply requirements and potentially adversely impact our financial results.

To meet the obligation to serve these large loads, insulate our existing membership from rate pressure associated with new generation and transmission requirements, increased fuel costs, and higher Locational Marginal Pricing (“LMP”), and to protect our balance sheet from stranded asset risk, we adopted a Large Load Commercial Program in 2025. Under this program, new loads meeting the requirements to be considered a “large load” will be billed under a rate structure that includes a market pass-through component and will be required to contribute a substantial portion of the capital required to build or acquire the assets necessary to serve their load. There is no guarantee that this program will fully insulate us from the risks associated with these large loads.

We cannot predict whether the large loads under consideration and for which we are planning will ever commence operations, the size and duration of the power requirements of those that do become operational, and whether they will seek to be served by a power supplier other than our members. For these and other reasons, there can be no assurance that these developments will not have an adverse effect on our business, results of operations, financial condition or cash flows.

If we are unable to obtain an adequate supply of fuel, our ability to operate our facilities could be limited.

We obtain our natural gas and coal from multiple suppliers. Any disruptions in our fuel supplies, could result in us having insufficient levels of fuel supplies. Natural gas and coal markets have experienced supply chain and availability constraints in recent years. Natural gas supplies may be limited during periods of seasonal demands and are also subject to disruption due to natural disasters and similar events or infrastructure failures. Any failure to maintain access to or an adequate inventory of fuel supplies could require us to operate other generating plants at a higher cost or require us to purchase higher-cost energy from other sources and, as a result, have an adverse effect on our results of operations, financial performance, or cash flows.

Our service reliability could be affected by problems at other utilities or by the increase in intermittent sources of power.

We are a transmission-owning member of SPP, a regional transmission organization. Some of our Class A Members also are transmission-owning members of SPP. In addition, some of our Class A Members service areas are within MISO and the WECC. SPP coordinates, controls and monitors the bulk electric system and wholesale power market in the central United States on behalf of a diverse group of utilities and transmission companies in fourteen states. Our transmission facilities are directly interconnected with the transmission facilities of neighboring utilities and are thus part of the larger bulk electric transmission system. Generation and transmission assets are the cornerstone of bulk electric system reliability. Accordingly, problems or outages at other utilities may increase costs, interrupt service to our members, or reduce service reliability. In addition, the increasing contribution of intermittent sources of power, such as wind and solar, may place significant strain on the entire bulk electric system, particularly if investment, operations, and maintenance of firm dispatchable generation units (e.g., coal or natural gas-fired generation facilities) sources are uneconomic. Greater curtailment or cycling of firm dispatchable generation may increase the wear-and-tear on these facilities and consequently increases the potential for breakdown of the facilities. If we suffer a service interruption, or the

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bulk electric system generally has reduced service reliability, our results of operations, financial condition, cash flows, or reputation may be adversely affected.

Wildfires and other catastrophic events could adversely affect our financial condition and results of operations.

We are exposed to the risk of wildfires and other catastrophic events that could result in substantial losses, operational disruptions, and significant financial impacts. We own over 2,500 miles of transmission lines as of December 31, 2025, including transmission lines that cross through certain wildfire-prone areas, such as forest areas and grasslands. Climate-related factors may worsen hot and dry summer conditions, which could increase the likelihood and magnitude of damages caused by fires burning or allegedly originating from our equipment. If a wildfire alleged to have involved our transmission facilities, or alleged to have resulted from our or our contractors’ operating or maintenance practices, were to occur, we could be exposed to claims for property damage, costs of fire-fighting, evacuation, and clean-up activities, personal injury or loss of life, environmental pollution and other costs, for which liability could be substantial and in excess of our insurance coverage. We may also be subject to credit ratings downgrades, unfavorable media coverage, fines and penalties, or other negative consequences which may impact our financial condition and future plans. Any such liability could adversely affect us and our results of operations, financial condition, or cash flows.

In addition to wildfires, our operations may be affected by other catastrophic events, including tornadoes, floods, droughts, mechanical failures, and intentional acts such as terrorism. The frequency and severity of these events are unpredictable and may increase as a result of climate‑related factors. Such events may damage critical infrastructure, disrupt our ability to generate or transmit electricity, impair fuel delivery and supply chains, or reduce our members’ electricity requirements for an extended period. Restoration of damaged facilities may require substantial capital expenditures for repairs, replacements, or modifications. Any resulting operational disruptions or financial impacts could be significant and could adversely affect our results of operations, financial condition, or cash flows.

We are subject to operational and market risks associated with participation in RTOs, including SPP and MISO.

Our operations within RTOs, including SPP and MISO, expose us to a variety of operational, regulatory, and market risks that could adversely affect our financial condition and results of operations. Both SPP and MISO have recently revised their planning reserve margin (“PRM”) requirements in response to increasing reliability concerns. In 2025, MISO reduced its PRM target from 9.0% to 7.9% for the 2025/2026 planning year, yet still experienced a 43% drop in surplus capacity compared to the prior year. This tightening of capacity positions, combined with the retirement of dispatchable generation and delays in new resource development, has led to significantly higher prices for capacity that we must purchase or have available. Similarly, SPP has approved and implemented an increase in its PRM from 15% to 16% for the summer season beginning in 2026, and has implemented a 36% PRM for the winter season starting in 2026/2027. These changes reflect the growing risk of winter reliability events, as recent studies show that the majority of annual loss-of-load risk is now concentrated in the winter months. As of May 2026, we have transitioned portions of our western load and generation into organized market participation, including SPP’s Western market, WEIM, and EDAM. This includes participation in balancing authority operations within SPP, Black Hills Power and the Public Service Company of Colorado (“PSCo”) balancing authorities. We also plan to further transition portions of our operations into additional organized wholesale markets during 2027, which could expose us to additional operational, regulatory, or market risks. These evolving market and reliability requirements may increase our cost of compliance, could limit our ability to take planned outages, and may require additional investment in capacity resources. Moreover, the variability of renewable generation, fuel supply constraints, and extreme weather events further complicate our ability to meet these requirements reliably. Failure to effectively manage these risks could adversely affect our results of operations, financial condition, or cash flows.

Failure to maintain a skilled workforce could adversely affect our operations.

Together with our subsidiaries, we require skilled executive officers as well as professional and technical employees to operate and maintain our generation, transmission and other facilities, such as the Synfuels Plant. Competition for qualified employees and broader labor shortages have made it more difficult to attract

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necessary personnel. Our failure to attract and retain the appropriate workforce talent required for the most efficient operation of our facilities and business could limit our ability to maximize our enterprise value.

A significant portion of our employees is covered by collective bargaining agreements with expiration dates ranging from 2026 through 2028. Failure to reach satisfactory agreements with these labor unions, or any resulting strikes, work stoppages, or other labor disruptions, could adversely impact our operations, financial condition, or results of operations. The terms of future collective bargaining agreements may also increase labor costs or limit our operational flexibility.

Legal and Regulatory Risks

We are involved in disputes and legal proceedings that, if determined unfavorably to us, could have an adverse effect on our results of operations, financial condition, or cash flows.

We are involved in several disputes and legal proceedings that, if determined unfavorably to us, could have a material adverse effect upon our business. See “LEGAL PROCEEDINGS.” Any such disputes or legal proceedings, whether with or without merit, could be expensive and time consuming, could divert the attention of our management and, if resolved adversely to us, could harm our reputation and increase our costs or reduce our revenues, all of which could have a material adverse effect on our financial results. Further, any adverse result to us with respect to our current disputes or legal proceedings could result in more litigation, further exacerbating the adverse consequences noted above.

Our business is the focus of extensive existing and proposed statutory and regulatory restrictions intended to limit the impact of our operations on the environment. These restrictions will impact our operations in ways we cannot fully predict and could have an adverse effect on our financial results.

We are required to comply with numerous federal, state and local laws relating to the protection of the environment. These laws include restrictions on air emissions, water discharges and the use, management and disposal of hazardous and solid wastes. We expect to spend substantial amounts on capital expenditures to comply with environmental laws, including for the installation, maintenance and operation of pollution control equipment, monitoring systems and other related equipment and facilities to comply with these laws.

Our ability to plan for and meet applicable environmental requirements is challenged due to new legislation, rulemaking, executive orders, and judicial interpretations with respect to environmental laws. The outcomes and effects of the United States Environmental Protection Agency’s (“EPA”) and other agencies’ rulemakings, and of litigation, executive orders, and other governmental actions, cannot be predicted. Environmental regulations and orders sometimes are appealed or otherwise litigated in the courts for several years. Sometimes regulations or orders are vacated or stayed. Implementation of these contested laws, regulations, or proposals can be delayed. In addition, there may be attempts to repeal or amend final regulations that have survived legal challenges and become effective. These modifications then may restart the cycle of legal challenges to the new laws.

Our compliance with existing and proposed environmental laws is further complicated by the scope of our operations. We operate generation facilities in four different states. EPA and state environmental agencies often implement environmental laws and regulations in a manner designed to meet compliance targets within a particular state. As a result, existing and future environmental laws may cause us to undertake relatively higher cost measures to comply with laws in one state jurisdiction than those that would be applicable or acceptable in another state. The differential in cost between these compliance measures could be substantial, including as a result of substantial additional capital expenditures to install new pollution control facilities or the permanent closure of one or more units of one or more existing coal-fired or gas-fired generation facilities.

The lack of certainty regarding potential future environmental requirements exists even though we must make decisions in the near term to plan for compliance with our assessment of likely future requirements. For example, capital expenditures in pollution control equipment for a given facility to achieve compliance must incorporate our assessment of the impact of all other known or anticipated environmental laws with respect to the operation of the same facility. The resulting costs to comply with all applicable environmental requirements, as they may change from time to time, may have an adverse effect on our results of operations, financial

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condition and cash flows. For additional information regarding certain environmental regulations to which our business is subject, see “BUSINESS—Environmental Regulation.” in the Prospectus.

Other Risks

Cybersecurity incidents or failures of our information systems could disrupt our operations, compromise sensitive information, and adversely affect our financial condition and reputation.

We operate in a highly regulated industry requiring the continued operation of advanced information systems, operational technology (“OT”), and network infrastructure. We rely on private and third-party communication infrastructure and computing information systems, and other technology, including hosted servers and internet, to support a variety of business processes and activities. We use information systems to process financial information and operational data for internal reporting purposes and to comply with regulatory financial reporting, legal, tax, and operational requirements. Deliberate or unintentional cyber incidents could directly or indirectly impact our owned and co-owned generation and transmission assets and OT systems. An incident involving our information technology or OT systems could also impact our ability to complete critical business or operational functions and inhibit our ability to effectively maintain certain financial reporting internal controls. In addition to our OT systems, our business and facilities may be impacted by physical or cyber attacks on the business or facilities of others. Any of these types of events could adversely affect our results of operations, financial performance, or cash flows.

In addition, such incidents could result in unauthorized disclosure of material confidential information, including personally identifiable information or sensitive business information. These events could also impair our ability to raise capital by contributing to financial instability and reduced economic activity. To reduce the likelihood and severity of a cyber incident, we employ procedural and technical controls to help protect and preserve the confidentiality, integrity and availability of data and systems. Despite these protections, a major cyber incident could result in significant business disruptions, compromised or improper disclosure of data, safety risks and significant expense to repair security breaches or replace damaged systems, and could lead to litigation, regulatory action, including penalties or fines, and adverse effects to our results of operations, financial condition and reputation. As cybercriminals become more sophisticated, the cost of proactive defensive measures may increase. We are also subject to mandatory and enforceable North American Electric Reliability Corporation (“NERC”) reliability standards to protect against security risks to the reliable operation of the bulk power system. The consequences of failure to comply with these standards can result in fines and other penalties.

We may be subject to physical attacks, threats, or other interference.

As operators of energy infrastructure, we face a heightened risk of physical attacks, or threats of such attacks, on our electric systems. Our generation and transmission assets and systems are geographically dispersed and are often in rural or sparsely populated areas which make it difficult to adequately detect, defend from, and respond to such attacks and effectively deter and prevent such attacks. Recent physical attacks on us and other electric utilities in the U.S. and the coverage of such attacks by the media may have increased this risk and the risk of copycat attacks. If a significant physical attack occurred, it could disrupt our operations, damage our property, pose health and safety risks, have an adverse impact on our revenues, cause us to incur response costs, and result in other financial losses. It could also cause us to be subject to increased regulation or litigation, and cause damage to our reputation, any of which could have an adverse effect on our business and results of operations.

New technologies and improvements in existing technologies related to the generation, storage and use of electricity may materially change the operation of our business in ways we cannot predict.

Technological developments are affecting many aspects of the business of providing electric services. These developments include the improvement in the efficiency of electricity generation from non-conventional sources, the reduction of energy usage and the development of improved modes of energy storage. In recent years, the technologies for wind and solar-powered generation facilities have become more efficient and less expensive. Continued advances in these technologies may reduce the cost of power generated to a level that is competitive with conventional technologies, such as coal-fired or natural gas-fired generation facilities. In addition, new technologies related to fuel cells and other energy storage could significantly impact the overall

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demand for electricity, especially when coupled with distributed generation. While we cannot predict the exact nature of how these technological changes will affect our financial results, this trend could adversely affect our members’ demand for electricity, the dispatch of our facilities and, ultimately, our results of operations, financial condition, or cash flows. This adverse effect could be further exacerbated if state or federal governments require (or enhance existing requirements) that a specified percentage of the electricity we sell comes from renewable resources if such renewable technologies are not commercially viable compared to conventional technologies.

Accidents involving Dakota Gas products could cause severe damage to people or property.

As a producer and seller of synthetic natural gas and other byproducts and coproducts of the coal gasification process, including phenol, anhydrous ammonia, ammonium sulfate, carbon dioxide, crude cresylic acid, krypton and xenon gases, liquid nitrogen, naphtha, tar oil, urea and diesel exhaust fluid (“DEF”), Dakota Gas’s operations and the producing and handling of these chemical substances involves significant risks and hazards. Accidents involving chemical substances could result in fires, explosions, pollution or other serious circumstances, which could cause severe damage or injury to persons (employees or otherwise), property or the environment, as well as disrupt our business. Any damage to persons, equipment or property or other disruption to Dakota Gas’s ability to produce or distribute its products could adversely impact our cash flows, results of operations and financial condition and result in significant additional costs to replace or repair our assets.

We could be subject to litigation and recapture of tax credits if carbon oxides we have sequestered are released into the atmosphere.

In February 2024, Dakota Gas concurrently placed into service a geologic sequestration project at the Synfuels Plant and entered into a variety of contractual agreements with an investor to monetize tax credits related to the geologic sequestration of carbon oxides under Section 45Q (“Section 45Q”) of the Internal Revenue Code of 1986, as amended (the “Code”). The tax credits are available for up to twelve years from the time the project reached commercial operation. A variety of factors could result in Dakota Gas not receiving the anticipated benefits of the transaction. A change in the Code or the Internal Revenue Service’s interpretation of tax laws could adversely affect or eliminate the benefit of Section 45Q. As part of the transaction with the investor, Dakota Gas has an obligation to manage the carbon sequestration process and is responsible for the ongoing monitoring of sequestered carbon oxides. We provide a guaranty for Dakota Gas’s payment obligations to the investor. If Dakota Gas or any of its contractors failed to perform their respective obligations, Dakota Gas could be liable to the investor for substantial amounts, including for costs incurred to third parties as a result of the failure. For example, the Internal Revenue Service could disallow claimed tax credits for failure to properly sequester the carbon oxides. Any such failure and any resulting payment obligations on our part could adversely affect our results of operations, financial condition, or cash flows.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Not applicable.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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 is included in Exhibit 95 to this report.

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ITEM 5. OTHER INFORMATION

During the three months ended March 31, 2026, none of our directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) informed us of the adoption or termination of a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," each as defined in Item 408 of Regulation S-K.

ITEM 6. EXHIBITS


Exhibit No.						Description of Exhibit
3.1						Restated Articles of Incorporation of Basin Electric Power Cooperative (incorporated by reference to Exhibit 3 .1 to the registrant's Registration Statement on Form S-4 (Registration No. 333-295074), filed with the SEC on April 15, 2026).

3.2						Amended and Restated Bylaws of Basin Electric Power Cooperative (incorporated by reference to Exhibit 3 .2 to the registrant's Registration Statement on Form S-4 (Registration No. 333-295074), filed with the SEC on April 15, 2026).

10.1						Amended and Restated Executive Deferred Compensation Plan effective January 1, 2026 (incorporated by reference to Exhibit 10 .7 to the registrant's Registration Statement on Form S-4 (Registration No. 333-295074), filed with the SEC on April 15, 2026).

31.1						Rule 13a-14(a)/15d-14(a) Certification of Principal Executive Officer .

31.2						Rule 13a-14(a)/15d-14(a) Certification of Principal Financial Officer .

32.1						Certification of Principal Executive Officer p ursuant to 18 U.S.C. 1350, as a dopted p ursuant to Section 906 of the Sarbanes-Oxley Act of 2002 .

32.2						Certification of Principal Financial Officer p ursuant to 18 U.S.C. 1350, as a dopted p ursuant to Section 906 of the Sarbanes-Oxley Act of 2002 .

95						Mine Safety Disclosure Exhibit.

101						The following information from the registrant's Form 10-Q for the quarter ended March 31, 2026, formatted in Inline XBRL: (i) Consolidated Balance Sheets (unaudited); (ii) Consolidated Statements of Operations (unaudited); (iii) Consolidated Statements of Comprehensive Income (unaudited); (iv) Consolidated Statements of Changes in Equity (unaudited); (v) Consolidated Statements of Cash Flows (unaudited); and (vi) the Condensed Notes to the Consolidated Financial Statements (unaudited).
104						Cover Page Interactive Data File, formatted in Inline XBRL (contained in Exhibit 101).

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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.


			BASIN ELECTRIC POWER COOPERATIVE

Date: June 18, 2026			/s/ Todd Brickhouse
			Name: Todd Brickhouse
			Title: Chief Executive Officer and General Manager (Principal Executive Officer)

Date: June 18, 2026			/s/ Christopher A. Johnson
			Name: Christopher A. Johnson
			Title: Senior Vice President and Chief Financial Officer (Principal Financial Officer)

BASIN ELECTRIC POWER COOPERATIVE 10-Q