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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended September 30, 2025

☐ 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 001-31303

Black Hills Corporation

Incorporated in South Dakota IRS Identification Number 46-0458824

7001 Mount Rushmore Road

Rapid City, South Dakota 57702

Registrant’s telephone number (605) 721-1700

Former name, former address, and former fiscal year if changed since last report

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 ☒ No ☐

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 during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files). Yes ☒ No ☐

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

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

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock as of the latest practicable date.


Class	Outstanding at November 4, 2025
Common stock, $1.00 par value	75,473,390	shares

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TABLE OF CONTENTS


		Page
Glossary of Terms and Abbreviations		3
Forward-Looking Information		7

PART I. FINANCIAL INFORMATION		8

Item 1.	Financial Statements - unaudited	8
	Consolidated Statements of Income	8
	Consolidated Statements of Comprehensive Income	9
	Consolidated Balance Sheets	10
	Consolidated Statements of Cash Flows	12
	Consolidated Statements of Equity	13
	Condensed Notes to Consolidated Financial Statements	15
	Note 1. Management’s Statement	15
	Note 2. Regulatory Matters	16
	Note 3. Commitments, Contingencies and Guarantees	17
	Note 4. Revenue	18
	Note 5. Financing	19
	Note 6. Earnings Per Share	21
	Note 7. Risk Management and Derivatives	21
	Note 8. Fair Value Measurements	24
	Note 9. Other Comprehensive Income	26
	Note 10. Employee Benefit Plans	27
	Note 11. Income Taxes	28
	Note 12. Business Segment Information	28
	Note 13. Selected Balance Sheet Information	31
	Note 14. Pending Business Combination	32
	Note 15. Subsequent Events	32

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
	Executive Summary	33
	Recent Developments	33
	Results of Operations	34
	Consolidated Summary and Overview	35
	Non-GAAP Financial Measure	36
	Electric Utilities	37
	Gas Utilities	40
	Corporate and Other	42
	Consolidated Interest Expense, Other Income and Income Tax Expense	42
	Liquidity and Capital Resources	43
	Cash Flow Activities	44
	Capital Resources	45
	Credit Ratings	45
	Capital Requirements	46
	Critical Accounting Estimates	46
	New Accounting Pronouncements	46

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 4.	Controls and Procedures	46

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	47
Item 1A.	Risk Factors	47
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	54
Item 4.	Mine Safety Disclosures	54
Item 5.	Other Information	54
Item 6.	Exhibits	54

Signatures		55

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GLOSSARY OF TERMS AND ABBREVIATIONS

The following terms and abbreviations appear in the text of this report and have the definitions described below:


AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
Arkansas Gas	Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).
ASU	Accounting Standards Update as issued by the FASB
ATM	At-the-market equity offering program
Availability	The availability factor of a power plant is the percentage of the time that it is available to provide energy.
BHC	Black Hills Corporation; the Company
Black-box Settlement	Settlement with a utility's commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.
Black Hills Colorado IPP	Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Electric Generation	Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities.
Black Hills Electric Parent Holdings	Black Hills Electric Utility Holdings, LLC., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Energy	The name used to conduct the business of our Utilities
Black Hills Energy Renewable Resources (BHERR)	Black Hills Energy Renewable Resources, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy Services	Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Non-regulated Holdings	Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings	Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming	Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Blockchain Interruptible Service (BCIS) Tariff	A WPSC-approved tariff applicable to prospective new Wyoming Electric blockchain customers. The tariff allows customers to negotiate rates and terms and conditions for interruptible electric utility service of 10 MW or greater that would be interconnected with Wyoming Electric’s system. Agreements under the BCIS tariff must be filed with the WPSC prior to the first customer billing, be at least 2 years in duration and include specific pricing for all electricity purchased (with pricing terms subject to renegotiation every three years). BCIS customers shall not participate in the PCA to the extent of service received under the tariff.
Busch Ranch I	A 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.
Busch Ranch II	A 59.4 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to provide wind energy to Colorado Electric through a PPA expiring in November 2044.
CEPR	Clean Energy Plan Rider, which is a 1.5% surcharge to fund Colorado Electric's recovery of renewable energy projects under the Clean Energy Plan. In conjunction with the implementation of the CEPR in January 2025, the RESA surcharge was reduced from 2.0% to 1.5%.
Choice Gas Program	Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.
Chief Operating Decision Maker (CODM)	Chief Executive Officer
CIAC	Contribution in aid of construction

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Clean Energy Plan	2030 Ready Plan that establishes a roadmap and preferred resource portfolio for Colorado Electric to achieve the State of Colorado’s requirement calling upon electric utilities to reduce greenhouse gas emissions by a minimum of 80% from 2005 levels by 2030. The recommended resource portfolio proposes the addition of 350 MW of clean energy resources to Colorado Electric's system. Colorado legislation allows electric utilities to own up to 50% of the renewable generation assets added to comply with the Clean Energy Plan.
Colorado Electric	Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Parent Holdings, providing electric services to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas	Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Consolidated Indebtedness to Capitalization Ratio	Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day	A cooling degree day is equivalent to each degree that the average of the high and the low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
CP Program	Commercial Paper Program
CPCN	Certificate of Public Convenience and Necessity
CPUC	Colorado Public Utilities Commission
CT	Combustion Turbine
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Emergency PSPS	Emergency Public Safety Power Shutoff is a safety measure to prevent the electric system from becoming a potential source of ignition during extreme weather conditions/events. It entails selectively and intentionally turning off power to a portion of a service area when high-fire-risk weather and fuel conditions occur.
FASB	Financial Accounting Standards Board
FCC	Federal Communications Commission
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings Inc.
GAAP	Accounting principles generally accepted in the United States of America
GSRS	Gas System Reliability Surcharge is a monthly charge that recovers Kansas Gas's costs associated with pipeline safety and government-mandated projects.
Heating Degree Day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
HomeServe	We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
HSR Act	Hart-Scott-Rodino Antitrust Improvements Act of 1976
Integrated Generation	Non-regulated power generation and mining businesses (Black Hills Electric Generation and WRDC) that are vertically integrated within our Electric Utilities segment.
Iowa Gas	Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP	Independent Power Producer
IRA	Inflation Reduction Act of 2022
IRS	United States Internal Revenue Service
IUC	Iowa Utilities Commission
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).
KCC	Kansas Corporation Commission

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Lange II	A dual fuel (natural gas and diesel oil) electric generation project in Rapid City, South Dakota with an estimated total capacity of 99 MW. This facility will be owned and operated by South Dakota Electric and will be located adjacent to the Lange CT generation facility. This project is expected to begin construction in third quarter of 2025 and in service during the second half of 2026. The addition of these resources will replace generation facilities planned for retirement and support updated planning reserve margin requirements.
Large Power Contract Service (LPCS) Tariff	Innovative tariff solution developed in collaboration with Microsoft and approved by the WPSC in 2016. The LPSC is applicable to Wyoming Electric retail customers with new loads of 13 MW or greater who agree to Black Hills Energy-dispatched, customer-owned generation, on-site for the purpose of providing backup service for the customer’s load and maintaining reliability. If the parties agree through negotiations to electric service through this tariff, a Large Power Service Agreement will be executed. The associated service agreement provides qualifying customers with market-based energy rates and access to renewable energy resources that is not served from utility-owned generation (i.e. minimal capital model for Wyoming Electric). Customers shall not participate in the PCA or TCAM to the extent of service received under the tariff.
Merger Sub	River Merger Sub Inc., a Delaware corporation and direct, wholly owned subsidiary of BHC
MMBtu	Million British thermal units
Moody's	Moody's Ratings
MPSC	Montana Public Service Commission
MW	Megawatts
MWh	Megawatt-hours
N/A	Not applicable
Nebraska Gas	Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
NorthWestern	NorthWestern Energy Group, Inc., a Delaware corporation
NPSC	Nebraska Public Service Commission
NYSE	New York Stock Exchange
OBBBA	One Big Beautiful Bill Act enacted on July 4, 2025, which is a legislative package designed to permanently extend certain expiring provisions of the TCJA and deliver additional tax relief for individuals and businesses. The OBBBA introduced changes to federal energy policies by rolling back several clean energy provisions and codified restrictions related to prohibited foreign entities, termination and restrictions on clean energy PTCs, extension and modification of clean fuel production. The OBBBA does not repeal tax credit transferability provisions enacted under the IRA, but restricts credit transfers to prohibited foreign entities.
OCI	Other Comprehensive Income
PCA	Power Cost Adjustment is an annual adjustment mechanism that allows Wyoming Electric to pass a portion of prudently-incurred delivered power costs, including fuel, purchased capacity and energy, and transmission costs, through to customers.
PPA	Power Purchase Agreement
PTC	Production Tax Credit
Pueblo Airport Generation	Pueblo Airport Generating Station located in Pueblo, Colorado includes 440 MW of combined cycle gas-fired power generation plants jointly owned by Colorado Electric (240 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP operates this facility. The plants commenced operation on January 1, 2012.
Ready Wyoming	A 260-mile, multi-phase transmission expansion project in Wyoming. This transmission project is expected to serve the growing needs of customers by enhancing resiliency of Wyoming Electric’s overall electric system and expanding access to power markets and renewable resources. The project is expected to help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region.
RESA	Renewable Energy Standard Adjustment is an incremental retail rate limited to 1.5% for Colorado Electric customers that provides funding for renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard.
Revolving Credit Facility	Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended on May 31, 2024, and will terminate on May 31, 2030. This facility includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment.
RNG	Renewable natural gas

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SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Service Guard Comfort Plan	Appliance protection plan that provides home appliance repair services through on-going monthly service agreements to residential utility customers.
S&P	S&P Global Ratings, a division of S&P Global Inc.
South Dakota Electric	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
TCAM	Transmission Cost Adjustment Mechanism is a WPSC-approved tariff based on a formulaic approach that determines the recovery of Wyoming Electric's transmission costs.
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017, which reduced the U.S. federal corporate tax rate from 35% to 21%. As such, we remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017.
Tech Services	Non-regulated product lines delivered by our Utilities that 1) provide electrical system construction services to large industrial customers of our Electric Utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.
Utilities	Black Hills' Electric and Gas Utilities
Wind Capacity Factor	Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential.
Winter Storm Uri	February 2021 winter weather event that caused extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a coal mine which is a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities at our Gillette Energy Complex (doing business as Black Hills Energy).
Wygen I	A mine-mouth, coal-fired generating facility with a total capacity of 90 MW located at our Gillette Energy Complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wygen III	A mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 116 MW located at our Gillette Energy Complex. South Dakota Electric owns 52% of the power plant, MDU owns 25%, and the City of Gillette owns the remaining 23%.
Wyoming Electric	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas	Black Hills Wyoming Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

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FORWARD-LOOKING INFORMATION

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the SEC. Forward-looking statements are all statements other than statements of historical fact, including without limitation those statements that are identified by the words “anticipates,” “estimates,” “expects,” “intends,” “plans,” “predicts” and similar expressions, and include statements concerning plans, objectives, goals, strategies, future events or performance, and underlying assumptions and other statements that are other than statements of historical facts. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation, the risk factors described in Item 1A of Part I of our 2024 Annual Report on Form 10-K, Part II, Item 1A of this Quarterly Report on Form 10-Q, and other reports that we file with the SEC from time to time, and the following:

•

Our ability to obtain adequate cost recovery for our utility operations through regulatory proceedings and favorable rulings on periodic applications to recover costs for capital additions, plant retirements and decommissioning, fuel, transmission, purchased power and other operating costs, and the timing in which new rates would go into effect;

•

Our ability to complete our capital program in a cost-effective and timely manner;

•

Our ability to execute on our strategy;

•

Our ability to successfully execute our financing plans;

•

The effects of changing interest rates;

•

Our ability to achieve our greenhouse gas emissions intensity reduction goals;

•

The impact of future governmental regulation;

•

Our ability to overcome the impacts of supply chain disruptions on availability and cost of materials;

•

The effects of inflation, tariffs and volatile energy prices;

•

Our ability to obtain sufficient insurance coverage at reasonable costs and whether such coverage will protect us against significant losses;

•

The expected timing and likelihood of completion and our ability to realize the anticipated benefits of the proposed merger with NorthWestern, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed acquisition that could reduce anticipated benefits or give rise to the termination of the merger; and

•

Other factors discussed from time to time in our filings with the SEC.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time-to-time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward-looking statements, whether as a result of new information, future events or otherwise.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME


(unaudited)	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
	(in millions, except per share amounts)
Revenue	$	430.2		$	401.6		$	1,674.5		$	1,530.6

Operating expenses:
Fuel, purchased power and cost of natural gas sold		112.0			94.5			595.7			518.2
Operations and maintenance		150.8			145.6			452.2			420.8
Depreciation and amortization		71.5			69.3			210.5			201.8
Taxes other than income taxes		17.2			16.4			50.0			50.0
Total operating expenses		351.5			325.8			1,308.4			1,190.8

Operating income		78.7			75.8			366.1			339.8

Other income (expense):
Interest expense incurred net of amounts capitalized		(50.6	)		(50.6	)		(152.2	)		(144.8	)
Interest income		1.2			5.4			2.6			12.9
Other income (expense), net		0.6			(1.3	)		1.1			(1.7	)
Total other (expense)		(48.8	)		(46.5	)		(148.5	)		(133.6	)

Income before income taxes		29.9			29.3			217.6			206.2
Income tax (expense)		(4.0	)		(2.9	)		(26.5	)		(23.6	)
Net income		25.9			26.4			191.1			182.6
Net income attributable to non-controlling interest		(1.0	)		(2.0	)		(4.5	)		(7.6	)
Net income available for common stock	$	24.9		$	24.4		$	186.6		$	175.0

Earnings per share of common stock:
Earnings per share, Basic	$	0.34		$	0.35		$	2.58		$	2.53
Earnings per share, Diluted	$	0.34		$	0.35		$	2.58		$	2.52

Weighted average common shares outstanding:
Basic		72.8			70.5			72.3			69.2
Diluted		72.9			70.6			72.4			69.3

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


(unaudited)	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
	(in millions)
Net income	$	25.9		$	26.4		$	191.1		$	182.6

Other comprehensive income (loss), net of tax;
Reclassification adjustments of benefit plan liability - net loss (net of tax of $0.0, $0.0, $0.0 and $0.0, respectively)		—			—			0.1			0.1
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(0.2), $(0.2), $(0.5), and $(0.5), respectively)		0.5			0.6			1.6			1.7
Net unrealized gains (losses) on commodity derivatives (net of tax of $0.4, $0.0, $0.4, and $0.0, respectively)		(1.3	)		0.1			(1.5	)		(0.1	)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $0.0, $0.0, $(0.1), and $(0.7), respectively)		—			—			0.4			2.5
Other comprehensive income (loss), net of tax		(0.8	)		0.7			0.6			4.2

Comprehensive income		25.1			27.1			191.7			186.8
Less: comprehensive income attributable to non-controlling interest		(1.0	)		(2.0	)		(4.5	)		(7.6	)
Comprehensive income available for common stock	$	24.1		$	25.1		$	187.2		$	179.2

See Note 9 for additional disclosures.

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS


(unaudited)	As of
	September 30, 2025			December 31, 2024
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	21.1		$	16.1
Restricted cash and equivalents		8.0			7.3
Accounts receivable, net		251.4			351.2
Materials, supplies and fuel		173.0			153.9
Income tax receivable, net		21.0			19.8
Regulatory assets, current		138.2			154.8
Other current assets		54.9			39.2
Total current assets		667.6			742.3

Property, plant and equipment		10,104.2			9,566.5
Less: accumulated depreciation		(2,076.5	)		(1,936.6	)
Total property, plant and equipment, net		8,027.7			7,629.9

Other assets:
Goodwill		1,299.5			1,299.5
Intangible assets, net		6.7			7.6
Regulatory assets, non-current		253.0			272.9
Other assets, non-current		74.5			70.4
Total other assets, non-current		1,633.7			1,650.4

TOTAL ASSETS	$	10,329.0		$	10,022.6

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

(Continued)


(unaudited)	As of
	September 30, 2025			December 31, 2024
	(in millions)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	219.1		$	229.1
Accrued liabilities		292.4			302.2
Derivative liabilities, current		5.2			4.2
Regulatory liabilities, current		91.9			94.1
Notes payable		126.0			133.8
Total current liabilities		734.6			763.4

Long-term debt, net of current maturities		4,252.8			4,250.2

Deferred credits and other liabilities:
Deferred income tax liabilities, net		679.6			625.1
Regulatory liabilities, non-current		484.7			474.6
Benefit plan liabilities		120.9			122.9
Other deferred credits and other liabilities		205.5			201.2
Total deferred credits and other liabilities		1,490.7			1,423.8

Commitments, contingencies and guarantees (Note 3)

Equity:
Stockholder's equity -
Common stock $1 par value; 100,000,000 shares authorized; issued 75,520,225 and 71,676,756 shares, respectively		75.5			71.7
Additional paid-in capital		2,415.0			2,193.4
Retained earnings		1,289.0			1,249.1
Treasury stock, at cost - 46,443 and 56,608 shares, respectively		(2.7	)		(3.3	)
Accumulated other comprehensive (loss)		(8.8	)		(9.4	)
Total stockholders' equity		3,768.0			3,501.5
Non-controlling interest		82.9			83.7
Total equity		3,850.9			3,585.2

TOTAL LIABILITIES AND TOTAL EQUITY	$	10,329.0		$	10,022.6

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS


(unaudited)	Nine Months Ended September 30,
	2025			2024
Operating activities:	(in millions)
Net income	$	191.1		$	182.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		210.5			201.8
Deferred financing cost amortization		7.2			8.2
Stock compensation		8.0			8.2
Deferred income taxes		40.6			39.6
Employee benefit plans		8.9			8.9
Other adjustments, net		2.8			(1.8	)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel		(19.0	)		10.9
Accounts receivable and other current assets		90.8			123.9
Accounts payable and other current liabilities		(70.4	)		(61.8	)
Regulatory assets		47.1			61.6
Other operating activities, net		(12.3	)		(16.0	)
Net cash provided by operating activities		505.3			566.1

Investing activities:
Property, plant and equipment additions		(550.2	)		(530.5	)
Other investing activities		(6.2	)		(1.5	)
Net cash (used in) investing activities		(556.4	)		(532.0	)

Financing activities:
Dividends paid on common stock		(146.8	)		(135.8	)
Common stock issued		219.2			181.6
Net borrowings (payments) of Revolving Credit Facility and CP Program		(7.8	)		17.5
Long-term debt - issuance		—			450.0
Long-term debt - repayments		—			(600.0	)
Distributions to non-controlling interests		(5.2	)		(12.5	)
Other financing activities		(2.6	)		(8.3	)
Net cash provided by (used in) financing activities		56.8			(107.5	)

Net change in cash, restricted cash and cash equivalents		5.7			(73.4	)

Cash, restricted cash, and cash equivalents beginning of period		23.4			93.0
Cash, restricted cash, and cash equivalents end of period	$	29.1		$	19.6

Supplemental cash flow information:
Cash (paid) received during the period:
Interest (net of amounts capitalized)	$	(145.4	)	$	(122.5	)
Income taxes, net of transferred tax credits (Note 11)		12.9			14.6
Non-cash investing and financing activities:
Accrued property, plant, and equipment purchases at September 30,		121.7			64.0

The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY


(unaudited)	Common Stock				Treasury Stock
	Shares		Value		Shares			Value			Additional Paid in Capital			Retained Earnings			AOCI			Non-controlling Interest			Total
	(in millions except share amounts)
December 31, 2024		71,676,756	$	71.7		56,608		$	(3.3	)	$	2,193.4		$	1,249.1		$	(9.4	)	$	83.7		$	3,585.2
Net income		—		—		—			—			—			134.3			—			2.1			136.4
Other comprehensive income, net of tax		—		—		—			—			—			—			1.0			—			1.0
Dividends on common stock ($0.676 per share)		—		—		—			—			—			(48.6	)		—			—			(48.6	)
Share-based compensation		103,995		0.1		(22,488	)		1.3			(0.1	)		—			—			—			1.3
Issuance of common stock		763,481		0.7		—			—			45.4			—			—			—			46.1
Issuance costs		—		—		—			—			(0.5	)		—			—			—			(0.5	)
Distributions to non-controlling interest		—		—		—			—			—			—			—			(3.8	)		(3.8	)
March 31, 2025		72,544,232	$	72.5		34,120		$	(2.0	)	$	2,238.2		$	1,334.8		$	(8.4	)	$	82.0		$	3,717.1
Net income		—		—		—			—			—			27.5			—			1.3			28.8
Other comprehensive income, net of tax		—		—		—			—			—			—			0.4			—			0.4
Dividends on common stock ($0.676 per share)		—		—		—			—			—			(49.0	)		—			—			(49.0	)
Share-based compensation		19,159		0.1		13,827			(0.8	)		3.4			—			—			—			2.7
Issuance of common stock		339,285		0.3		—			—			19.4			—			—			—			19.7
Issuance costs		—		—		—			—			(0.3	)		—			—			—			(0.3	)
June 30, 2025		72,902,676	$	72.9		47,947		$	(2.8	)	$	2,260.7		$	1,313.3		$	(8.0	)	$	83.3		$	3,719.4
Net income		—		—		—			—			—			24.9			—			1.0			25.9
Other comprehensive (loss), net of tax		—		—		—			—			—			—			(0.8	)		—			(0.8	)
Dividends on common stock ($0.676 per share)		—		—		—			—			—			(49.2	)		—			—			(49.2	)
Share-based compensation		10		—		(1,504	)		0.1			2.7			—			—			—			2.8
Issuance of common stock		2,617,539		2.6		—			—			153.0			—			—			—			155.6
Issuance costs		—		—		—			—			(1.4	)		—			—			—			(1.4	)
Distributions to non-controlling interest		—		—		—			—			—			—			—			(1.4	)		(1.4	)
September 30, 2025		75,520,225	$	75.5		46,443		$	(2.7	)	$	2,415.0		$	1,289.0		$	(8.8	)	$	82.9		$	3,850.9

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(unaudited)	Common Stock				Treasury Stock
	Shares		Value		Shares		Value			Additional Paid in Capital			Retained Earnings			AOCI			Non-controlling Interest			Total
	(in millions except share amounts)
December 31, 2023		68,265,042	$	68.3		68,073	$	(4.1	)	$	2,007.7		$	1,158.2		$	(14.8	)	$	90.5		$	3,305.8
Net income		—		—		—		—			—			127.9			—			3.7			131.6
Other comprehensive income, net of tax		—		—		—		—			—			—			2.5			—			2.5
Dividends on common stock ($0.65 per share)		—		—		—		—			—			(44.4	)		—			—			(44.4	)
Share-based compensation		104,181		0.1		14,270		(0.6	)		1.9			—			—			—			1.4
Issuance of common stock		600,355		0.6		—		—			30.9			—			—			—			31.5
Issuance costs		—		—		—		—			(0.3	)		—			—			—			(0.3	)
Distributions to non-controlling interest		—		—		—		—			—			—			—			(5.6	)		(5.6	)
March 31, 2024		68,969,578	$	69.0		82,343	$	(4.7	)	$	2,040.2		$	1,241.7		$	(12.3	)	$	88.6		$	3,422.5
Net income		—		—		—		—			—			22.8			—			1.9			24.7
Other comprehensive income, net of tax		—		—		—		—			—			—			1.0			—			1.0
Dividends on common stock ($0.65 per share)		—		—		—		—			—			(44.9	)		—			—			(44.9	)
Share-based compensation		9,623		—		817		(0.2	)		2.9			—			—			—			2.7
Issuance of common stock		768,019		0.7		—		—			41.5			—			—			—			42.2
Issuance costs		—		—		—		—			(0.4	)		—			—			—			(0.4	)
Distributions to non-controlling interest		—		—		—		—			—			—			—			(4.4	)		(4.4	)
June 30, 2024		69,747,220	$	69.7		83,160	$	(4.9	)	$	2,084.2		$	1,219.6		$	(11.3	)	$	86.1		$	3,443.4
Net income		—		—		—		—			—			24.4			—			2.0			26.4
Other comprehensive income, net of tax		—		—		—		—			—			—			0.7			—			0.7
Dividends on common stock ($0.65 per share)		—		—		—		—			—			(46.5	)		—			—			(46.5	)
Share-based compensation		10		—		18,311		(1.0	)		3.1			—			—			—			2.1
Issuance of common stock		1,929,516		2.0							107.7			—			—			—			109.7
Issuance costs		—		—		—		—			(1.1	)		—			—			—			(1.1	)
Distributions to non-controlling interest		—		—		—		—			—			—			—			(2.5	)		(2.5	)
September 30, 2024		71,676,746	$	71.7		101,471	$	(5.9	)	$	2,193.9		$	1,197.5		$	(10.6	)	$	85.6		$	3,532.2

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BLACK HILLS CORPORATION

Condensed Notes to Consolidated Financial Statements

(unaudited)

(Reference is made to Notes to Consolidated Financial Statements

included in the Company’s 2024 Annual Report on Form 10-K)

(1)

Management’s Statement

The unaudited Consolidated Financial Statements included herein have been prepared by Black Hills Corporation (together with our subsidiaries the “Company”, “us”, “we”, or “our”), pursuant to the rules and regulations of the SEC. Certain information and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted pursuant to such rules and regulations; however, we believe that the footnotes adequately disclose the information presented. These Consolidated Financial Statements should be read in conjunction with the consolidated financial statements and the notes included in our 2024 Annual Report on Form 10-K.

Use of Estimates and Basis of Presentation

The information furnished in the accompanying Consolidated Financial Statements reflects certain estimates required and all adjustments, including accruals, which are, in the opinion of management, necessary for a fair presentation of the September 30, 2025, December 31, 2024, and September 30, 2024, financial information. Certain lines of business in which we operate are highly seasonal and our interim results of operations are not necessarily indicative of the results of operations to be expected for an entire year.

Recently Issued Accounting Standards

Improvements to Income Tax Disclosures, ASU 2023-09

In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which expands public entities’ annual disclosures by requiring disclosure of tax rate reconciliation amounts and percentages for specific categories, income taxes paid disaggregated by federal and state taxes, and income tax expense disaggregated by federal and state taxes jurisdiction. The ASU is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2025. We are evaluating the disclosure impact of ASU 2023-09; however, the standard is not expected to have an impact on our financial condition, results of operations and/or cash flows.

Disaggregation of Income Statement Expenses, ASU 2024-03

In November 2024, the FASB issued ASU 2024-03, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures, and in January 2025, the FASB issued ASU 2025-01, Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures: Clarifying the Effective Date. ASU 2024-03 requires public entities to disclose, in the notes to financial statements, certain costs and expenses, such as purchases of inventory, employee compensation, and costs related to depreciation and amortization. ASU 2024-03, as clarified by ASU 2025-01, is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2027, and subsequent interim periods, with early adoption permitted. We are evaluating the disclosure impact of ASU 2024-03; however, the standard is not expected to have an impact on our financial condition, results of operations and/or cash flows.

Targeted Improvements to the Accounting for Internal-Use Software, ASU 2025-06

In September 2025, the FASB issued ASU 2025-06, Targeted Improvements to the Accounting for Internal-Use Software, which amends the accounting guidance for internal-use software under ASC 350-40. The amendments are intended to modernize the recognition and capitalization framework to better reflect current software development practices, particularly agile methodologies. ASU 2025-06 is effective for fiscal years beginning after December 15, 2027, including interim periods within those fiscal years. Early adoption is permitted. We are currently evaluating the impact of ASU 2025-06 on our consolidated financial statements and related disclosures.

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(2)

Regulatory Matters

We had the following regulatory assets and liabilities:


	As of			As of
	September 30, 2025			December 31, 2024
	(in millions)
Regulatory assets
Winter Storm Uri	$	62.1		$	109.5
Deferred energy and fuel cost adjustments		76.1			62.8
Deferred gas cost adjustments		7.5			14.5
Gas price derivatives		4.9			2.9
Deferred taxes on AFUDC		9.5			8.0
Employee benefit plans and related deferred taxes		85.7			89.0
Environmental		11.5			10.7
Loss on reacquired debt		14.5			15.7
Deferred taxes on flow through accounting		93.1			87.7
Decommissioning costs		2.4			2.4
Other regulatory assets		23.9			24.5
Total regulatory assets		391.2			427.7
Less current regulatory assets		(138.2	)		(154.8	)
Regulatory assets, non-current	$	253.0		$	272.9

Regulatory liabilities
Deferred energy and gas costs	$	61.1		$	67.8
Employee benefit plan costs and related deferred taxes		35.0			36.7
Cost of removal		212.0			197.0
Excess deferred income taxes		232.4			238.5
Colorado renewable energy (a)		30.7			24.1
Other regulatory liabilities		5.4			4.6
Total regulatory liabilities		576.6			568.7
Less current regulatory liabilities		(91.9	)		(94.1	)
Regulatory liabilities, non-current	$	484.7		$	474.6

(a)

Represents Colorado Electric's RESA and CEPR mechanisms, which allow for recovery/repayment of costs, but not a rate of return.

Regulatory Activity

Colorado Electric

On June 14, 2024, Colorado Electric filed a rate review with the CPUC seeking recovery of infrastructure investments in its 3,200-mile electric distribution and 600-mile electric transmission systems. On March 17, 2025, Colorado Electric received an order from the CPUC for a general rate increase which was expected to generate approximately $17.0 million of new annual revenue based on a weighted average cost of capital of 6.9% with a capital structure in a range of 47% to 49% equity and 51% to 53% debt, and a return on equity in a range of 9.3% to 9.5%. The new rates were effective March 22, 2025. On April 7, 2025, Colorado Electric filed a request with the CPUC for rehearing, re-argument or reconsideration ("RRR"). On May 6, 2025, Colorado Electric received a final decision from the CPUC related to its RRR request, increasing new annual revenue from approximately $17.0 million to approximately $17.5 million.

Iowa Gas

On May 1, 2024, Iowa Gas filed a rate review with the IUC seeking recovery of infrastructure investments in its 5,000-mile natural gas pipeline system. In the fourth quarter of 2024, Iowa Gas received final approval from the IUC for a settlement agreement for a general rate increase. The approved Black-box Settlement is expected to generate $15.0 million of new annual revenue based on a weighted average cost of capital of 7.2%. New rates were enacted on January 1, 2025, which replaced interim rates.

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Kansas Gas

On February 3, 2025, Kansas Gas filed a rate review with the KCC seeking recovery of infrastructure investments in its 4,765-mile natural gas pipeline system and increased operations and maintenance costs driven by inflation and operational needs to serve customers. On July 24, 2025, Kansas Gas received final approval from the KCC for a settlement agreement for a general rate increase. The approved Black-box Settlement is expected to generate $10.8 million in new annual revenue and will shift $4.4 million of GSRS rider revenue to base rates. New rates were enacted on August 1, 2025. The settlement also includes approval for Kansas Gas to file an abbreviated case in first quarter of 2026 that includes the addition of capital placed in service through December 31, 2025.

Nebraska Gas

On May 1, 2025, Nebraska Gas filed a rate review with the NPSC seeking recovery of infrastructure investments in its 12,900-mile natural gas pipeline system and increased operations and maintenance costs driven by inflation and operational needs to serve customers. On October 7, 2025, Nebraska Gas reached a settlement with all intervenors for a general rate increase which is subject to NPSC approval. The settlement is expected to generate $23.9 million in new annual revenue with a capital structure of 51% equity and 49% debt and a return on equity of 9.85%. The settlement also includes renewal of Nebraska Gas' SSIR for five years and the development of a two-year pilot program for a weather normalization adjustment rider. If approved, new rates will be effective on January 1, 2026, and will replace interim rates which were effective in August 2025.

Approval of the settlement agreement from the NPSC is expected by mid-December 2025.

(3)

Commitments, Contingencies and Guarantees

There have been no significant changes to commitments, contingencies and guarantees from those previously disclosed in Note 3 of our Notes to the Consolidated Financial Statements in our 2024 Annual Report on Form 10-K except as described below.

Transfers of Renewable Tax Credits

In January 2025, we entered into an agreement with a third party to sell our 2024 generated PTCs. In the agreement, we provided indemnifications associated with the proceeds for PTCs transferred to the third party in the event of an adverse change or interpretation of tax law, including whether the related tax credits meet the qualification requirements. We believe the likelihood of having to make any material cash payments under these indemnifications is remote. See Note 11 for additional information.

Manufactured Gas Plant

In 2008, we acquired liabilities for a former manufactured gas plant site in Iowa, which was previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, which was used to help offset remediation costs. Our insurance recovery asset was valued at $1.5 million as of September 30, 2025, and was recorded in Other current assets on our Consolidated Balance Sheets. We recovered our insurance recovery asset in October 2025.

As of December 31, 2024, we had an Accrued liability of $9.7 million on our Consolidated Balance Sheets for the remaining remediation of the manufactured gas plant site in Iowa. During the nine months ended September 30, 2025, we completed substantially all remaining remediation work. As of September 30, 2025, $11.5 million of cumulative remediation costs, which are net of our $1.5 million insurance recovery asset, were recorded to a Regulatory asset on our Consolidated Balance Sheets. Iowa Gas intends to seek recovery of this $11.5 million regulatory asset during a future rate review.

Deborah Ferrari et al. v. Colorado Electric, Case No. 2024CV31889 (District Court for the City and County of Denver, Colorado)

Colorado Electric is currently involved in a legal matter related to an auto accident that could result in a liability. While we have determined that liability is probable, we believe Colorado Electric has meritorious defenses regarding the damages claimed and are vigorously defending its position. As such, the outcome of this matter remains uncertain.

At this time, we are unable to estimate the possible range of liability due to the complexity of the issues involved and the status of the proceedings. Accordingly, to date, we have not recorded an accrual in the financial statements. We will continue to monitor the matter and will accrue a liability if and when it becomes reasonably estimable.

At the time of the accident, the Company maintained an insurance policy designed to provide coverage for certain legal and regulatory exposures. In the event we incur a liability related to this legal matter, we will seek recovery under this insurance policy.

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GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (District Court for the City and County of Denver, Colorado)

On April 13, 2022, a jury awarded $41 million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a 2.3 million-acre concession award in Costa Rica which was acquired by a BHC subsidiary in 2003. GTR retained rights to receive a royalty interest on any hydrocarbon production from the concession upon the occurrence of contingent events. GTR contended that BHC and its subsidiaries failed to adequately pursue the opportunity and failed to transfer the concession to GTR. We appealed this verdict to the Colorado Court of Appeals. On October 19, 2023, the Appellate Court reversed and remanded the case with directions limiting any retrial to the narrow issue of whether there was improper interference with the prospective conveyance of the concession. The retrial occurred and on May 12, 2025, the jury returned a verdict in favor of BHC and its subsidiaries on all counts, thus resolving any claims without material impact on our financial position, results or operations and cash flows.

(4)

Revenue

The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the three and nine months ended September 30, 2025, and 2024. Sales tax and other similar taxes are excluded from revenues.


Three Months Ended September 30, 2025	Electric Utilities		Gas Utilities		Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	201.3	$	128.6	$	—		$	329.9
Transportation		—		43.6		(0.1	)		43.5
Wholesale		5.5		—		—			5.5
Market - off-system sales		16.3		—		—			16.3
Transmission		11.1		0.1		—			11.2
Other revenues		14.6		10.2		(3.8	)		21.0
Revenue from contracts with customers	$	248.8	$	182.5	$	(3.9	)	$	427.4
Alternative revenue and other		0.9		1.9		—			2.8
Total revenues	$	249.7	$	184.4	$	(3.9	)	$	430.2

Timing of revenue recognition:
Services transferred at a point in time	$	8.8	$	—	$	—		$	8.8
Services transferred over time		240.0		182.5		(3.9	)		418.6
Revenue from contracts with customers	$	248.8	$	182.5	$	(3.9	)	$	427.4


Three Months Ended September 30, 2024	Electric Utilities		Gas Utilities		Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	186.3	$	117.5	$	—		$	303.8
Transportation		—		43.2		—			43.2
Wholesale		6.1		—		—			6.1
Market - off-system sales		10.7		—		—			10.7
Transmission		13.6		—		—			13.6
Other revenues		14.9		10.8		(4.5	)		21.2
Revenue from contracts with customers	$	231.6	$	171.5	$	(4.5	)	$	398.6
Alternative revenue and other		0.9		2.1		—			3.0
Total revenues	$	232.5	$	173.6	$	(4.5	)	$	401.6

Timing of revenue recognition:
Services transferred at a point in time	$	9.3	$	—	$	—		$	9.3
Services transferred over time		222.3		171.5		(4.5	)		389.3
Revenue from contracts with customers	$	231.6	$	171.5	$	(4.5	)	$	398.6

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Nine Months Ended September 30, 2025	Electric Utilities		Gas Utilities		Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	570.6	$	797.0	$	—		$	1,367.6
Transportation		—		143.4		(0.3	)		143.1
Wholesale		16.9		—		—			16.9
Market - off-system sales		38.3		0.1		—			38.4
Transmission		33.3		0.3		—			33.6
Other revenues		43.9		31.5		(11.4	)		64.0
Revenue from contracts with customers	$	703.0	$	972.3	$	(11.7	)	$	1,663.6
Alternative revenue and other		3.3		7.6		—			10.9
Total revenues	$	706.3	$	979.9	$	(11.7	)	$	1,674.5

Timing of revenue recognition:
Services transferred at a point in time	$	25.9	$	—	$	—		$	25.9
Services transferred over time		677.1		972.3		(11.7	)		1,637.7
Revenue from contracts with customers	$	703.0	$	972.3	$	(11.7	)	$	1,663.6


Nine Months Ended September 30, 2024	Electric Utilities		Gas Utilities		Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	529.4	$	707.8	$	—		$	1,237.2
Transportation		—		130.9		—			130.9
Wholesale		21.1		—		—			21.1
Market - off-system sales		22.8		—		—			22.8
Transmission		39.1		0.4		—			39.5
Other revenues		43.3		31.6		(13.4	)		61.5
Revenue from contracts with customers	$	655.7	$	870.7	$	(13.4	)	$	1,513.0
Alternative revenue and other		4.1		13.5		—			17.6
Total revenues	$	659.8	$	884.2	$	(13.4	)	$	1,530.6

Timing of revenue recognition:
Services transferred at a point in time	$	25.9	$	—	$	—		$	25.9
Services transferred over time		629.8		870.7		(13.4	)		1,487.1
Revenue from contracts with customers	$	655.7	$	870.7	$	(13.4	)	$	1,513.0

(5)

Financing

Short-term Debt

Revolving Credit Facility and CP Program

On June 6, 2025, with approval from our lenders, we utilized one of our two available one-year extension options under the amended and restated Revolving Credit Facility, thereby extending its maturity date to May 31, 2030.

Our Revolving Credit Facility and CP Program, which are classified as Notes payable on the Consolidated Balance Sheets, had the following borrowings, outstanding letters of credit, and available capacity as of:


	September 30, 2025			December 31, 2024
	(dollars in millions)
Amount outstanding	$	126.0		$	133.8
Letters of credit (a)		3.1			3.5
Available capacity		620.9			612.7
Weighted average interest rates		4.26	%		4.74	%

(a)

Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit Facility.

Table of Contents

Revolving Credit Facility and CP Program borrowing activity was as follows:


	Nine Months Ended September 30,
	2025			2024
	(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)	$	263.6		$	25.8
Average amount outstanding (based on daily outstanding balances)		115.9			0.6
Weighted average interest rates		4.55	%		5.15	%

Long-term Debt

On October 2, 2025, we completed a public debt offering of $450 million, 4.55% senior unsecured notes due January 31, 2031. Proceeds from the offering, which were reduced by $4.0 million of deferred financing costs, will be used to repay all $300 million principal amount outstanding of our 3.95% senior unsecured notes at or before their January 15, 2026, maturity date and for other general corporate purposes.

Financial Covenants

Revolving Credit Facility

We were in compliance with all of our Revolving Credit Facility covenants as of September 30, 2025. We are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed 0.65 to 1.00. Subject to applicable cure periods, a violation of this covenant would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. As of September 30, 2025, our Consolidated Indebtedness to Capitalization Ratio was 0.54 to 1.00.

Wyoming Electric

Wyoming Electric was in compliance with all covenants within its financing agreements as of September 30, 2025. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of September 30, 2025, Wyoming Electric's debt to capitalization ratio was 0.50 to 1.00.

Equity

ATM

On May 8, 2025, we entered into a First Amendment to our Equity Distribution Sales Agreement (the “First Amendment”). The First Amendment, among other things, provides for the continuation of the ATM, which allows us to sell shares of common stock under the Company's shelf registration statement (Registration No. 333-272739), and resets the size of the ATM to $400 million. The First Amendment aggregate gross sales price limitation of $400 million supersedes and replaces the aggregate gross sales price limitation provided in our Equity Distribution Sales Agreement. Except as modified by the First Amendment, our Equity Distribution Sales Agreement remains in full force and effect.

ATM activity was as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
June 16, 2023 ATM Program	(in millions, except Average price per share amounts)
Proceeds, (net of issuance costs of $0.0, $(1.1), $(0.5), and $(1.8), respectively)	$	—	$	108.6	$	45.7	$	181.6
Number of shares issued		—		1.9		0.8		3.3

May 8, 2025 ATM Program
Proceeds, (net of issuance costs of $(1.3), $0.0, $(1.5), and $0.0, respectively)	$	154.3	$	—	$	173.9	$	—
Number of shares issued		2.6		—		2.9		—

Total activity under both ATM Programs
Proceeds, (net of issuance costs of $(1.3), $(1.1), $(2.0), and $(1.8), respectively)	$	154.3	$	108.6	$	219.6	$	181.6
Number of shares issued		2.6		1.9		3.7		3.3
Average price per share	$	59.47	$	56.84	$	59.56	$	55.63

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Earnings Per Share

A reconciliation of share amounts used to compute earnings per share in the accompanying Consolidated Statements of Income was as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(in millions, except per share amounts)
Net income available for common stock	$	24.9	$	24.4	$	186.6	$	175.0

Weighted average shares - basic		72.8		70.5		72.3		69.2
Dilutive effect of equity compensation		0.1		0.1		0.1		0.1
Weighted average shares - diluted	$	72.9	$	70.6	$	72.4	$	69.3

Net income available for common stock, per share - Diluted	$	0.34	$	0.35	$	2.58	$	2.52

Anti-dilutive shares excluded from the diluted earnings per share computation were not material for the three and nine months ended September 30, 2025, and 2024.

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Risk Management and Derivatives

Market and Credit Risk Disclosures

Our activities in the energy industry expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.

Market Risk

Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed but not limited to, the following market risks:

•

Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, geopolitical events, pandemics, market speculation, imposition of new tariffs, recession, inflation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and

•

Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility.

Credit Risk

Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.

We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit, and other security agreements.

We perform periodic credit evaluations of our customers and adjust credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses, and any specific customer collection issue that is identified.

Derivatives and Hedging Activity

Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income, and Consolidated Statements of Comprehensive Income are detailed below and in Note 8.

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The operations of our Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, over-the-counter swaps, and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.

For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions, are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income.

Through Black Hills Energy Services, our non-regulated natural gas commodity supplier, we buy, sell, and deliver natural gas in Nebraska and Wyoming at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales through December 2027. A portion of our over-the-counter swaps have been designated as cash flow hedges to mitigate the commodity price risk associated with deliveries under fixed price forward contracts to deliver gas to our Choice Gas Program customers. The gain or loss on these designated derivatives is reported in AOCI in the accompanying Consolidated Balance Sheets and reclassified into earnings in the same period that the underlying hedged item is recognized in earnings. Effectiveness of our hedging position is evaluated at least quarterly.

The contract or notional amounts and terms of the electric and natural gas derivative commodity instruments held at our Utilities are composed of both long and short positions. We had the following net long and (short) positions as of:


	September 30, 2025			December 31, 2024
	Notional Amounts (MMBtus)		Maximum Term (months) (a)	Notional Amounts (MMBtus)		Maximum Term (months) (a)
Natural gas futures purchased		1,760,000	6		660,000	3
Natural gas options purchased, net		7,670,000	6		2,780,000	3
Natural gas basis swaps purchased		1,760,000	6		1,080,000	3
Natural gas over-the-counter swaps, net (b)		4,810,000	26		3,480,000	20
Natural gas physical contracts, net (c)		24,513,400	6		20,276,230	10

(a)

Term reflects the maximum forward period hedged.

(b)

As of September 30, 2025, 2,805,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.

(c)

Volumes exclude contracts that qualify for the normal purchases and normal sales exception under GAAP.

We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At September 30, 2025, the Company posted $0.8 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets.

Derivatives by Balance Sheet Classification

The following table presents the fair value and balance sheet classification of our derivative instruments as of:


	Balance Sheet Location	September 30, 2025			December 31, 2024
		(in millions)
Derivatives designated as hedges:
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	$	(2.0	)	$	(0.7	)
Total derivatives designated as hedges		$	(2.0	)	$	(0.7	)

Derivatives not designated as hedges:
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	$	(3.2	)	$	(3.5	)
Total derivatives not designated as hedges		$	(3.2	)	$	(3.5	)

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Derivatives Designated as Hedge Instruments

The impact of cash flow hedges on our Consolidated Statements of Comprehensive Income and Consolidated Statements of Income are presented below for the three and nine months ended September 30, 2025, and 2024. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.


	Three Months Ended September 30,						Three Months Ended September 30,
	2025			2024			2025			2024
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in OCI					Income Statement Location	Amount of Gain/(Loss) Reclassified from AOCI into Income
	(in millions)						(in millions)
Interest rate swaps	$	0.7		$	0.8	Interest expense	$	(0.7	)	$	(0.8	)
Commodity derivatives		(1.6	)		0.1	Fuel, purchased power, and cost of natural gas sold		(0.1	)		—
Total	$	(0.9	)	$	0.9		$	(0.8	)	$	(0.8	)


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in OCI					Income Statement Location	Amount of Gain/(Loss) Reclassified from AOCI into Income
	(in millions)						(in millions)
Interest rate swaps	$	2.1		$	2.2	Interest expense	$	(2.1	)	$	(2.2	)
Commodity derivatives		(1.3	)		3.1	Fuel, purchased power, and cost of natural gas sold		(0.5	)		(3.2	)
Total	$	0.8		$	5.3		$	(2.6	)	$	(5.4	)

As of September 30, 2025, $4.5 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

Derivatives Not Designated as Hedge Instruments

The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the three and nine months ended September 30, 2025, and 2024. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.


		Three Months Ended September 30,
		2025			2024
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
		(in millions)
Commodity derivatives	Fuel, purchased power, and cost of natural gas sold	$	(0.6	)	$	(0.3	)
		$	(0.6	)	$	(0.3	)


		Nine Months Ended September 30,
		2025		2024
Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) on Derivatives Recognized in Income	Amount of Gain/(Loss) on Derivatives Recognized in Income
		(in millions)
Commodity derivatives	Fuel, purchased power, and cost of natural gas sold	$	—	$	0.4
		$	—	$	0.4

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As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset accounts related to these financial instruments were $4.9 million and $2.9 million as of September 30, 2025 and December 31, 2024, respectively.

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Fair Value Measurements

We use the following fair value hierarchy for determining inputs for our financial instruments. Our assets and liabilities for financial instruments are classified and disclosed in one of the following fair value categories:

Level 1 — Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. Level 1 instruments primarily consist of highly liquid and actively traded financial instruments with quoted pricing information on an ongoing basis.

Level 2 — Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets other than quoted prices in Level 1, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived principally from, or corroborated by, observable market data by correlation or other means.

Level 3 — Pricing inputs are generally less observable from objective sources. These inputs reflect management’s best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement within the fair value hierarchy levels. We record transfers, if necessary, between levels at the end of the reporting period for all of our financial instruments.

Transfers into Level 3, if any, occur when significant inputs used to value the derivative instruments become less observable, such as a significant decrease in the frequency and volume in which the instrument is traded, negatively impacting the availability of observable pricing inputs. Transfers out of Level 3, if any, occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery date of a transaction becomes shorter, positively impacting the availability of observable pricing inputs.

Recurring Fair Value Measurements

Derivatives

The commodity contracts for our Utilities segments are valued using the market approach and include forward strip pricing at liquid delivery points, exchange-traded futures, options, basis swaps, and over-the-counter swaps and options (Level 2) for wholesale electric energy and natural gas contracts. For exchange-traded futures, options, and basis swap assets and liabilities, fair value was derived using broker quotes validated by the exchange settlement pricing for the applicable contract. For over-the-counter instruments, the fair value is obtained by utilizing a nationally recognized service that obtains observable inputs to compute the fair value, which we validate by comparing our valuation with the counterparty. The fair value of these swaps includes a credit valuation adjustment based on the credit spreads of the counterparties when we are in an unrealized gain position or on our own credit spread when we are in an unrealized loss position. For additional information, see Note 1 of our Notes to the Consolidated Financial Statements in our 2024 Annual Report on Form 10-K.

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The following tables set forth, by level within the fair value hierarchy, our gross assets and gross liabilities and related offsetting as permitted by GAAP that were accounted for at fair value on a recurring basis for derivative instruments.


	As of September 30, 2025
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)			Total
	(in millions)
Assets:
Commodity derivatives - Gas Utilities	$	—	$	5.2	$	—	$	(5.2	)	$	—
Total	$	—	$	5.2	$	—	$	(5.2	)	$	—

Liabilities:
Commodity derivatives - Gas Utilities	$	—	$	8.0	$	—	$	(2.8	)	$	5.2
Total	$	—	$	8.0	$	—	$	(2.8	)	$	5.2

(a)

As of September 30, 2025, $5.2 million of our commodity derivative assets and $2.8 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.


	As of December 31, 2024
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)			Total
	(in millions)
Assets:
Commodity derivatives - Gas Utilities	$	—	$	2.2	$	—	$	(2.2	)	$	—
Total	$	—	$	2.2	$	—	$	(2.2	)	$	—

Liabilities:
Commodity derivatives - Gas Utilities	$	—	$	4.8	$	—	$	(0.6	)	$	4.2
Total	$	—	$	4.8	$	—	$	(0.6	)	$	4.2

(a)

As of December 31, 2024, $2.2 million of our commodity derivative assets and $0.6 million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

Pension and Postretirement Plan Assets

Fair value measurements also apply to the valuation of our pension and postretirement plan assets. Current accounting guidance requires employers to annually disclose information about the fair value measurements of their assets of a defined benefit pension or other postretirement plan. The fair value of these assets is presented in Note 13 to the Consolidated Financial Statements included in our 2024 Annual Report on Form 10-K.

Other Fair Value Measures

The carrying amount of cash and cash equivalents, restricted cash and equivalents, and short-term borrowings approximates fair value due to their liquid or short-term nature. Cash, cash equivalents, and restricted cash are classified in Level 1 in the fair value hierarchy. Notes payable consist of commercial paper borrowings and are not traded on an exchange; therefore, they are classified as Level 2 in the fair value hierarchy.

The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the Consolidated Balance Sheets as of:


	September 30, 2025				December 31, 2024
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Long-term debt, including current maturities (a)	$	4,252.8	$	4,180.9	$	4,250.2	$	4,059.1

(a)

Long-term debt is valued based on observable inputs available either directly or indirectly for similar liabilities in active markets and therefore is classified in Level 2 in the fair value hierarchy. Carrying amount of long-term debt is net of deferred financing costs.

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Other Comprehensive Income

We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts designated as cash flow hedges, and the amortization of components of our defined benefit plans. Deferred gains (losses) for our commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses) related to our interest rate swaps are recognized in earnings as they are amortized.

The following table details reclassifications out of AOCI and into Net income. The amounts in parentheses below indicate decreases to Net income in the Consolidated Statements of Income for the period, net of tax:


		Amount Reclassified from AOCI
		Three Months Ended September 30,						Nine Months Ended September 30,
	Location on the Consolidated Statements of Income	2025			2024			2025			2024
		(in millions)
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(0.7	)	$	(0.8	)	$	(2.1	)	$	(2.2	)
Commodity contracts	Fuel, purchased power, and cost of natural gas sold		(0.1	)		—			(0.5	)		(3.2	)
		$	(0.8	)	$	(0.8	)	$	(2.6	)	$	(5.4	)
Income tax	Income tax (expense) benefit		0.2			0.2			0.6			1.2
Total reclassification adjustments related to cash flow hedges, net of tax		$	(0.6	)	$	(0.6	)	$	(2.0	)	$	(4.2	)

Amortization of components of defined benefit plans:
Actuarial (loss)	Operations and maintenance		—			—			(0.1	)		(0.1	)
Total reclassification adjustments related to defined benefit plans, net of tax		$	—		$	—		$	(0.1	)	$	(0.1	)
Total reclassifications		$	(0.6	)	$	(0.6	)	$	(2.1	)	$	(4.3	)

Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows:


	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
	(in millions)
As of December 31, 2024	$	(3.8	)	$	(0.3	)	$	(5.3	)	$	(9.4	)
Other comprehensive income (loss) before reclassifications		—			(1.5	)		—			(1.5	)
Amounts reclassified from AOCI		1.6			0.4			0.1			2.1
As of September 30, 2025	$	(2.2	)	$	(1.4	)	$	(5.2	)	$	(8.8	)


	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
	(in millions)
As of December 31, 2023	$	(6.1	)	$	(2.5	)	$	(6.2	)	$	(14.8	)
Other comprehensive income (loss) before reclassifications		—			(0.1	)		—			(0.1	)
Amounts reclassified from AOCI		1.7			2.5			0.1			4.3
As of September 30, 2024	$	(4.4	)	$	(0.1	)	$	(6.1	)	$	(10.6	)

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Employee Benefit Plans

Components of Net Periodic Expense

The components of net periodic expense were as follows:


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
Three Months Ended September 30,	2025			2024			2025		2024		2025			2024
	(in millions)
Service cost	$	0.4		$	0.6		$	1.2	$	1.3	$	0.4		$	0.4
Interest cost		4.0			4.1			0.3		0.4		0.6			0.6
Expected return on plan assets		(4.2	)		(4.5	)		—		—		(0.1	)		(0.1	)
Net amortization of prior service costs		—			—			—		—		0.1			0.1
Recognized net actuarial loss		0.5			0.5			—		—		—			—
Net periodic expense	$	0.7		$	0.7		$	1.5	$	1.7	$	1.0		$	1.0


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
Nine Months Ended September 30,	2025			2024			2025		2024		2025			2024
	(in millions)
Service cost	$	1.3		$	1.7		$	2.8	$	2.9	$	1.1		$	1.2
Interest cost		12.0			12.3			1.1		1.1		1.8			1.8
Expected return on plan assets		(12.7	)		(13.4	)		—		—		(0.2	)		(0.2	)
Net amortization of prior service costs		(0.1	)		(0.1	)		—		—		0.2			0.1
Recognized net actuarial loss		1.6			1.5			—		—		—			—
Net periodic expense	$	2.1		$	2.0		$	3.9	$	4.0	$	2.9		$	2.9

Plan Contributions

Contributions made in the first nine months of 2025 and additional contributions anticipated for the remainder of 2025 are as follows:


	Contributions Made		Additional Contributions
	Nine Months Ended September 30, 2025		Anticipated for 2025
	(in millions)
Defined Benefit Pension Plan	$	1.8	$	—
Non-pension Defined Benefit Postretirement Healthcare Plan		3.5		1.2
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans		2.1		0.7

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Income Taxes

Transfers of Production Tax Credits

In August 2022, President Biden signed H.R. 5376 into law, commonly known as the IRA of 2022, or IRA. The IRA contains a tax credit transferability provision that allows us to transfer (e.g. sell) PTCs produced after December 31, 2022, to third parties. In January 2025, under this transferability provision, we entered into an agreement with a third party to sell $17.0 million of our 2024 generated PTCs.

We expect to continue to explore the ability to efficiently monetize our tax credits through third party transferability agreements.

One Big Beautiful Bill Act

On July 4, 2025, President Trump signed H.R. 1, commonly referred to as the OBBBA, a legislative package designed to permanently extend certain expiring provisions of the TCJA and deliver additional tax relief for individuals and businesses. The OBBBA introduced changes to federal energy policies by rolling back several clean energy provisions and codified restrictions related to prohibited foreign entities, termination and restrictions on clean energy PTCs, and extension and modification of clean fuel production. The OBBBA does not repeal tax credit transferability provisions enacted under the IRA and continues to permit the execution of our transferability agreements as originally agreed upon, but restricts credit transfers to prohibited foreign entities.

Additionally, on August 15, 2025, the IRS issued Notice 2025-42, which provides guidance on the beginning of construction requirements for applicable wind and solar. These requirements are critical for determining eligibility for energy-related tax credits, particularly considering the OBBBA’s modifications to clean energy incentives. Projects must meet specific criteria—such as physical work of a significant nature—to be considered as having begun construction. This determination affects whether a project qualifies under pre-OBBBA or post-OBBBA credit regimes, which may differ in value, availability, or restrictions.

We do not anticipate material impacts to our pre-OBBBA in-service clean energy generation facilities as a result of the OBBBA. Further, we do not anticipate impacts to the execution of Colorado Electric’s Clean Energy Plan. However, we continue to monitor IRS guidance and legislative developments to ensure compliance and optimize the timing and structure of future clean energy investments.

Income Tax (Expense) and Effective Tax Rates

Three Months Ended September 30, 2025, Compared to the Three Months Ended September 30, 2024

Income tax (expense) for the three months ended September 30, 2025, was $(4.0) million compared to $(2.9) million reported for the same period in 2024. For the three months ended September 30, 2025, the effective tax rate was 13.5% compared to 10.0% for the same period in 2024. The higher effective tax rate was primarily driven by non-deductibility of certain NorthWestern merger-related costs. See Note 14 below for further discussion of the proposed merger with NorthWestern.

Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024

Income tax (expense) for the nine months ended September 30, 2025, was $(26.5) million compared to $(23.6) million reported for the same period in 2024. For the nine months ended September 30, 2025, the effective tax rate was 12.2%, which was comparable to 11.4% for the same period in 2024.

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Business Segment Information

We are a holding company that, through our subsidiaries, conducts our operations through the following reportable segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our reportable segments are presented as Corporate and Other.

Our operating segments, which are equivalent to our reportable segments, are based on our method of internal reporting, which is generally segregated by differences in products and services. All of our operations and assets are located within the United States.

Our Electric Utilities segment includes the operating results of the regulated electric utility operations of Colorado Electric, South Dakota Electric, and Wyoming Electric, which supply regulated electric utility services to areas in Colorado, Montana, South Dakota, and Wyoming. We also own and operate non-regulated power generation and mining businesses that are vertically integrated with our Electric Utilities.

Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming.

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Corporate and Other consists of certain unallocated expenses for administrative activities that support our operating segments. Corporate and Other also includes business development activities that are not part of our operating segments and inter-segment eliminations.

Our Chief Executive Officer, who is considered to be our CODM, reviews financial information presented on an operating segment basis for purposes of making decisions, allocating resources, and assessing financial performance. Our CODM assesses the performance of our operating segments and decides how to allocate resources based on operating income. Our CODM reviews capital expenditures by operating segment rather than any individual or total asset amount.

Segment information was as follows:


	Consolidating Income Statement
Three Months Ended September 30, 2025	Electric Utilities		Gas Utilities		Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	247.3	$	182.9	$	—		$	430.2
Inter-segment		2.4		1.5		(3.9	)		—
Total revenue		249.7		184.4		(3.9	)		430.2

Fuel, purchased power and cost of natural gas sold		69.8		42.3		(0.1	)		112.0
Operations and maintenance (a) -
Direct		36.1		38.9		0.7			75.7
Allocated		33.7		41.4		—			75.1
Depreciation and amortization		38.3		33.2		—			71.5
Taxes other than income taxes		9.4		7.8		—			17.2
Operating income (loss)	$	62.4	$	20.8	$	(4.5	)	$	78.7

Interest expense, net									(49.4	)
Other income (expense), net									0.6
Income tax (expense)									(4.0	)
Net income									25.9
Net income attributable to non-controlling interest									(1.0	)
Net income available for common stock								$	24.9


	Consolidating Income Statement
Three Months Ended September 30, 2024	Electric Utilities		Gas Utilities		Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	229.6	$	172.0	$	—		$	401.6
Inter-segment		2.9		1.6		(4.5	)		—
Total revenue		232.5		173.6		(4.5	)		401.6

Fuel, purchased power and cost of natural gas sold		54.9		39.7		(0.1	)		94.5
Operations and maintenance (a) -
Direct		32.4		41.3		(4.3	)		69.4
Allocated		32.7		43.5		—			76.2
Depreciation and amortization		38.0		31.3		—			69.3
Taxes other than income taxes		9.4		6.9		0.1			16.4
Operating income	$	65.1	$	10.9	$	(0.2	)	$	75.8

Interest expense, net									(45.2	)
Other income (expense), net									(1.3	)
Income tax (expense)									(2.9	)
Net income									26.4
Net income attributable to non-controlling interest									(2.0	)
Net income available for common stock								$	24.4

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	Consolidating Income Statement
Nine Months Ended September 30, 2025	Electric Utilities		Gas Utilities		Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	699.1	$	975.4	$	—		$	1,674.5
Inter-segment		7.2		4.5		(11.7	)		—
Total revenue		706.3		979.9		(11.7	)		1,674.5

Fuel, purchased power and cost of natural gas sold		192.2		403.7		(0.2	)		595.7
Operations and maintenance (a) -
Direct		107.9		121.9		(4.1	)		225.7
Allocated		99.9		126.6		—			226.5
Depreciation and amortization		113.0		97.6		(0.1	)		210.5
Taxes other than income taxes		27.6		22.4		—			50.0
Operating income (loss)	$	165.7	$	207.7	$	(7.3	)	$	366.1

Interest expense, net									(149.6	)
Other income (expense), net									1.1
Income tax (expense)									(26.5	)
Net income									191.1
Net income attributable to non-controlling interest									(4.5	)
Net income available for common stock								$	186.6


	Consolidating Income Statement
Nine Months Ended September 30, 2024	Electric Utilities		Gas Utilities		Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	651.0	$	879.6	$	—		$	1,530.6
Inter-segment		8.8		4.6		(13.4	)		—
Total revenue		659.8		884.2		(13.4	)		1,530.6

Fuel, purchased power and cost of natural gas sold		155.7		362.9		(0.4	)		518.2
Operations and maintenance (a) -
Direct		97.1		117.5		(12.3	)		202.3
Allocated		93.4		125.1		—			218.5
Depreciation and amortization		108.9		92.8		0.1			201.8
Taxes other than income taxes		28.7		21.3		—			50.0
Operating income (loss)	$	176.0	$	164.6	$	(0.8	)	$	339.8

Interest expense, net									(131.9	)
Other income (expense), net									(1.7	)
Income tax (expense)									(23.6	)
Net income									182.6
Net income attributable to non-controlling interest									(7.6	)
Net income available for common stock								$	175.0

(a)

Direct and Allocated Operations and maintenance expenses for our operating segments are regularly provided to the CODM. Direct Operations and maintenance expense represents the costs incurred directly by our operating segments. Allocated Operations and maintenance expense represent costs incurred by BHSC for various direct and indirect support services provided to our operating segments. Pursuant to the BHSC Cost Allocation Manual, indirect cost allocations are determined in accordance with the Public Utility Holding Company Act of 2005.

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Capital Expenditures (a) for the nine months ended September 30,	2025		2024
	(in millions)
Electric Utilities	$	334.0	$	246.8
Gas Utilities		267.6		308.2
Corporate and Other		6.9		10.8
Total capital expenditures	$	608.5	$	565.8

(a)

Includes accruals for property, plant, and equipment as disclosed in supplemental cash flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements. Capital expenditures are presented net of CIACs in the Consolidated Statements of Cash Flows.

(13)

Selected Balance Sheet Information

Accounts Receivable and Allowance for Credit Losses

Following is a summary of Accounts receivable, net included in the accompanying Consolidated Balance Sheets as of:


	September 30, 2025			December 31, 2024
	(in millions)
Billed Accounts Receivable	$	173.7		$	201.5
Unbilled Revenue		79.8			151.8
Less: Allowance for Credit Losses		(2.1	)		(2.1	)
Account Receivable, net	$	251.4		$	351.2

Changes to allowance for credit losses for the nine months ended September 30, 2025 and 2024, respectively, were as follows:


	Balance at Beginning of Year		Additions Charged to Costs and Expenses		Recoveries and Other Additions		Write-offs and Other Deductions			Balance at September 30,
	(in millions)
2025	$	2.1	$	5.8	$	2.4	$	(8.2	)	$	2.1
2024	$	2.2	$	4.0	$	2.8	$	(7.6	)	$	1.4

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies, and fuel on the accompanying Consolidated Balance Sheets as of:


	September 30, 2025		December 31, 2024
	(in millions)
Materials and supplies	$	114.1	$	106.1
Fuel - Electric Utilities		6.7		7.5
Natural gas in storage		52.2		40.3
Total materials, supplies, and fuel	$	173.0	$	153.9

Accrued Liabilities

The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of:


	September 30, 2025		December 31, 2024
	(in millions)
Accrued employee compensation, benefits, and withholdings	$	84.1	$	85.5
Accrued property taxes		53.7		54.7
Customer deposits and prepayments		62.6		55.6
Accrued interest		56.0		56.4
Other (none of which is individually significant)		36.0		50.0
Total accrued liabilities	$	292.4	$	302.2

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(14)

Pending Business Combination

On August 18, 2025, we entered into an Agreement and Plan of Merger (the “Merger Agreement”), with NorthWestern and Merger Sub. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern (the “Merger”), with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills Corporation, which will assume a new corporate name as the resulting parent company of the combined corporate group. At the effective time of the Merger (the “Effective Time”), each share of common stock of NorthWestern, par value $0.01 per share, issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of our common stock, par value $1.00 per share (or cash-in-lieu of fractional shares thereof), in each case upon and subject to the terms and conditions of the Merger Agreement.

The Merger Agreement, which was unanimously approved on August 18, 2025, by both the board of directors of Black Hills Corporation and the board of directors of NorthWestern, provides for a tax-free, all-stock business combination of Black Hills Corporation and NorthWestern upon the terms and subject to the conditions set forth therein. Such conditions include, among other things, clearance under the HSR Act, consent of the FCC, approval from each company's shareholders, and regulatory approvals, including approval from the SDPUC, NPSC and MPSC, as well as the FERC.

To date, regulatory efforts by Black Hills Corporation and NorthWestern include the following actions:

•

On October 20, 2025, we filed a joint application for approval with the MPSC. We expect a decision from the MPSC in the second half of 2026.

•

On October 27, 2025, we filed joint applications for approval with the NPSC and SDPUC, respectively. We expect decisions from the NPSC and SDPUC in the second quarter of 2026.

We anticipate the transaction closing in the second half of 2026, subject to the satisfaction of certain closing conditions including receipt of certain regulatory approvals as mentioned above.

(15)

Subsequent Events

Except as described in Notes 2, 3, 5 and 14, there have been no events subsequent to September 30, 2025, which would require recognition in the Consolidated Financial Statements or disclosures.

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

The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in our 2024 Annual Report on Form 10-K.

Executive Summary

We are a customer-focused energy solutions provider with a mission of Improving Life with Energy for more than 1.35 million customers and 800+ communities we serve. Our aspiration is to be the trusted energy partner across our growing eight-state footprint, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota, and Wyoming. Our strategy is centered on four priorities: People & Culture—build a team that wins together, Operational Excellence—relentlessly deliver on our commitment to serve our customers, Transformation—be a simple and connected company and Growth—grow to be a dominant long-term energy provider.

We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. We conduct our utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. We consider ourselves a domestic electric and natural gas utility company.

We have provided energy and served customers for 141 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. By being responsive and service focused, we can help our customers and communities thrive while meeting rapidly changing customer expectations.

Recent Developments

Pending Merger with NorthWestern

On August 18, 2025, we entered into the Merger Agreement with NorthWestern and Merger Sub. See Note 14 of the Condensed Notes to Consolidated Financial Statements for further discussion about the pending Merger.

One Big Beautiful Bill Act

See Note 11 of the Condensed Notes to Consolidated Financial Statements for discussion surrounding the OBBBA.

Trade Tariffs

Trade tariffs have been enacted over the last several months through presidential executive orders affecting products exported by several U.S. trading partners, and retaliatory tariffs have been imposed by some of these trading partners. While some tariffs scheduled to take effect were temporarily suspended, broad tariffs remain in effect with the possibility of additional tariffs being imposed. We are currently unable to predict the impact that recently imposed and possible future tariffs may have on our business. Trade tariffs have not had a material impact on our operations or financial performance to date. We are closely monitoring the impacts of trade tariffs and the potential effect they may have on our financial position, results of operations, or cash flows.

Business Segment Recent Developments

Electric Utilities

•

See Note 2 of the Condensed Notes to Consolidated Financial Statements for recent rate review activity for Colorado Electric.

•

On March 6, 2025, the state of Wyoming enacted comprehensive wildfire mitigation legislation (HB0192), effective July 1, 2025. The legislation provides material liability protections for a utility that complies with its commission-approved wildfire mitigation plan. The legislation provides a utility a presumption of meeting an appropriate level of operating care for compliance with an approved wildfire mitigation plan. We plan to file our wildfire mitigation plan with the WPSC in the fourth quarter of 2025.

•

In 2024, we published our formal WMP, which is an overview of our three-layered approach to manage wildfire risks driven by asset-based risk assessments that include asset programs, integrity programs and operational response. On June 30, 2025, we established our Emergency PSPS program across all three of our electric utilities to promote customer safety and mitigate wildfire risk. In establishing the Emergency PSPS program, we engaged with wildfire experts and key stakeholders including customers, community and local agencies, regulators and community leaders.

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•

In the first half of 2025, Wyoming Electric set four new all-time peak loads, including an all-time peak of 379 MW on June 20, 2025. Prior to 2025, the previous all-time peak was 314 MW set on January 11, 2024.

•

In 2024, Colorado Electric received CPUC approval for the addition of 350 MW of new renewable generation resources in support of its Clean Energy Plan, which included a 50-MW utility-owned battery storage project, a 200-MW solar PPA and a 100-MW utility-owned solar project. On October 8, 2025, Colorado Electric filed a settlement with the CPUC for its request for a CPCN for the 50-MW battery storage project and anticipates a decision by year-end. On October 29, 2025, the CPUC recommended continuing negotiations on the 200-MW solar PPA but recommended no further action on the 100-MW utility-owned solar project.

•

On March 28, 2025, South Dakota Electric filed a CPCN with the WPSC for the Lange II project, which was approved in June 2025. The new facility began construction in the third quarter of 2025 and is anticipated to be in service in the second half of 2026.

•

During the third quarter of 2025, Wyoming Electric continued construction of its approximately 260-mile, $350 million Ready Wyoming electric transmission expansion project. The project is on track and expected to be completed and in service by year-end 2025.

Gas Utilities

•

See Note 2 of the Condensed Notes to Consolidated Financial Statements for recent rate review activity for Iowa Gas, Kansas Gas and Nebraska Gas.

Corporate and Other

•

See Note 5 of the Condensed Notes to Consolidated Financial Statements for information regarding our corporate Revolving Credit Facility, October 2, 2025, debt offering and ATM program activity.

•

During the second quarter of 2025, we published our 2024 Corporate Sustainability Report, highlighting our environmental, social and governance impacts and our progress on major projects and climate goals.

•

On January 17, 2025, Fitch affirmed BHC's long-term issuer rating at BBB+ with a negative outlook. Following the affirmation, the parties jointly withdrew the rating. See Liquidity and Capital Resources section below for additional information on our credit ratings.

Results of Operations

Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and nine months ended September 30, 2025, and 2024, and our financial condition as of September 30, 2025, and December 31, 2024, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.

All amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in amounts may result due to rounding.

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Consolidated Summary and Overview


	Three Months Ended September 30,									Nine Months Ended September 30,
	2025			2024			2025 vs 2024 Variance			2025			2024			2025 vs 2024 Variance
	(in millions, except per share amounts)
Operating income (loss):
Electric Utilities	$	62.4		$	65.1		$	(2.7	)	$	165.7		$	176.0		$	(10.3	)
Gas Utilities		20.8			10.9			9.9			207.7			164.6			43.1
Corporate and Other (a)		(4.5	)		(0.2	)		(4.3	)		(7.3	)		(0.8	)		(6.5	)
Operating income		78.7			75.8			2.9			366.1			339.8			26.3

Interest expense, net		(49.4	)		(45.2	)		(4.2	)		(149.6	)		(131.9	)		(17.7	)
Other income (expense), net		0.6			(1.3	)		1.9			1.1			(1.7	)		2.8
Income tax (expense)		(4.0	)		(2.9	)		(1.1	)		(26.5	)		(23.6	)		(2.9	)
Net income		25.9			26.4			(0.5	)		191.1			182.6			8.5
Net income attributable to non-controlling interest		(1.0	)		(2.0	)		1.0			(4.5	)		(7.6	)		3.1
Net income available for common stock	$	24.9		$	24.4		$	0.5		$	186.6		$	175.0		$	11.6

Weighted average common shares outstanding, Diluted		72.9			70.6			2.3			72.4			69.3			3.1
Total earnings per share of common stock, Diluted	$	0.34		$	0.35		$	(0.01	)	$	2.58		$	2.52		$	0.06

(a)

Includes inter-segment eliminations.

Three Months Ended September 30, 2025, Compared to the Three Months Ended September 30, 2024

•

Electric Utilities' operating income decreased $2.7 million primarily due to milder weather and higher operating expenses partially offset by new rates and rider recovery;

•

Gas Utilities' operating income increased $9.9 million primarily due to new rates and rider recovery driven by the Arkansas Gas, Kansas Gas, and Nebraska Gas rate reviews and lower operating expenses partially offset by the unfavorable margin impacts of wet summer weather on Nebraska irrigation loads;

•

Corporate and Other operating loss increased $4.3 million primarily due to NorthWestern merger-related costs partially offset by an unallocated favorable true-up of operating expenses; and

•

Interest expense, net, increased $4.2 million primarily due to higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances partially offset by higher AFUDC debt driven by construction work-in-progress balances related to the Lange II and Ready Wyoming projects.

Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024:

•

Electric Utilities’ operating income decreased $10.3 million primarily due to higher operating expenses, unplanned generation outages, lower transmission services revenues and unfavorable weather partially offset by new rates and rider recovery;

•

Gas Utilities’ operating income increased $43.1 million primarily due to new rates and rider recovery driven by the Arkansas Gas, Iowa Gas, Kansas Gas, and Nebraska Gas rate reviews and favorable weather partially offset by higher operating expenses;

•

Corporate and Other operating loss increased $6.5 million primarily due to NorthWestern merger-related costs;

•

Interest expense, net, increased $17.7 million due to higher interest rates on long-term debt, higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances partially offset by higher AFUDC debt driven by construction work-in-progress balances related to the Lange II and Ready Wyoming projects;

•

Other income, net, increased $2.8 million primarily due to higher AFUDC equity driven by construction work-in-progress balances related to the Lange II and Ready Wyoming projects;

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•

Income tax expense increased $2.9 million primarily due to higher pre-tax income; and

•

Net income attributable to non-controlling interest decreased $3.1 million due to lower net income from Black Hills Colorado IPP primarily driven by current year unplanned generation outages.

Segment Operating Results

A discussion of operating results from our business segments follows. Unless otherwise indicated, segment information does not include inter-segment eliminations.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in accordance with GAAP and a “non-GAAP financial measure", Electric and Gas Utility margin. Generally, a non-GAAP financial measure is a numerical measure of a company’s financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. We define Electric and Gas Utility margin as operating revenue less cost of fuel, purchased power and cost of natural gas sold. Electric and Gas Utility margin is a non-GAAP financial measure due to the exclusion of operation and maintenance expenses determined to be directly attributable to revenue-producing activities, depreciation and amortization expenses, and taxes other than income taxes from the measure.

We believe that Gas and Electric Utility margin provides a useful basis for evaluating our segment operating results since our Utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the customer in current rates. As a result, management uses Gas and Electric Utility margin internally when assessing the financial performance of our operating segments as this measure excludes the majority of revenue fluctuations caused by changes in these costs of energy. Similarly, the presentation of Gas and Electric Utility margin is intended to supplement investors’ understanding of operating performance.

Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin measures. The following table includes a reconciliation of Electric and Gas Utility margin to Gross margin, the most directly comparable GAAP measure:


	Electric Utilities												Gas Utilities
	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024			2025			2024			2025			2024
	(in millions)
Revenue	$	249.7		$	232.5		$	706.3		$	659.8		$	184.4		$	173.6		$	979.9		$	884.2
Fuel, purchased power and cost of natural gas sold		(69.8	)		(54.9	)		(192.2	)		(155.7	)		(42.3	)		(39.7	)		(403.7	)		(362.9	)
Operations and maintenance (a)		(44.4	)		(38.0	)		(130.1	)		(116.5	)		(42.0	)		(44.3	)		(129.0	)		(129.5	)
Depreciation and amortization		(38.3	)		(38.0	)		(113.0	)		(108.9	)		(33.2	)		(31.3	)		(97.6	)		(92.8	)
Taxes other than income taxes		(9.4	)		(9.4	)		(27.6	)		(28.7	)		(7.8	)		(6.9	)		(22.4	)		(21.3	)
Gross margin (GAAP)	$	87.8		$	92.2		$	243.4		$	250.0		$	59.1		$	51.4		$	327.2		$	277.7
Operations and maintenance (a)		44.4			38.0			130.1			116.5			42.0			44.3			129.0			129.5
Depreciation and amortization		38.3			38.0			113.0			108.9			33.2			31.3			97.6			92.8
Taxes other than income taxes		9.4			9.4			27.6			28.7			7.8			6.9			22.4			21.3
Electric and Gas Utility margin (non-GAAP)	$	179.9		$	177.6		$	514.1		$	504.1		$	142.1		$	133.9		$	576.2		$	521.3

(a)

Operations and maintenance expenses which are deemed to be directly attributable to revenue-producing activities include plant operations and maintenance expenses at our electric generation facilities, operations and maintenance expenses at our WRDC coal mine, and electric and gas transmission and distribution expenses. These amounts are included in the table above to calculate gross margin in accordance with GAAP. These amounts excluded operations and maintenance expenses not directly attributable to revenue-producing activities of $25.4 million, $27.1 million, $77.7 million, and $74.0 million for the three and nine months ended September 30, 2025, and 2024, respectively, for the Electric Utilities and $38.3 million, $40.5 million, $119.5 million, and $113.2 million for the three and nine months ended September 30, 2025, and 2024, respectively, for the Gas Utilities.

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Electric Utilities

Operating results for the Electric Utilities were as follows:


	Three Months Ended September 30,							Nine Months Ended September 30,
	2025		2024		2025 vs 2024 Variance			2025		2024		2025 vs 2024 Variance
	(in millions)
Revenue	$	249.7	$	232.5	$	17.2		$	706.3	$	659.8	$	46.5
Fuel and purchased power		69.8		54.9		14.9			192.2		155.7		36.5
Electric Utility margin (non-GAAP) (a)		179.9		177.6		2.3			514.1		504.1		10.0

Operations and maintenance		69.8		65.1		4.7			207.8		190.5		17.3
Depreciation and amortization		38.3		38.0		0.3			113.0		108.9		4.1
Taxes other than income taxes		9.4		9.4		-			27.6		28.7		(1.1	)
		117.5		112.5		5.0			348.4		328.1		20.3

Operating income	$	62.4	$	65.1	$	(2.7	)	$	165.7	$	176.0	$	(10.3	)

(a)

See Non-GAAP Financial Measures section above for reconciliation to Gross margin, the most directly comparable GAAP measure.

Three Months Ended September 30, 2025, Compared to the Three Months Ended September 30, 2024:

•

Electric Utility margin increased as a result of the following:


	(in millions)
New rates and rider recovery	$	6.8
Prior year unplanned outages		1.4
Weather		(2.6	)
Retail customer usage		(1.1	)
Transmission services		(1.1	)
Other		(1.1	)
	$	2.3

•

Operations and maintenance expense increased primarily due to higher outside services expenses and higher generation expenses.

•

Depreciation and amortization was comparable to the same period in the prior year.

•

Taxes other than income taxes was comparable to the same period in the prior year.

Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024:

•

Electric Utility margin increased as a result of the following:


	(in millions)
New rates and rider recovery	$	15.5
Retail customer growth and usage		2.1
Current year and prior year unplanned outages		1.8
Transmission services		(3.9	)
Weather		(2.2	)
Off-system excess energy sales		(0.8	)
Other		(2.5	)
	$	10.0

•

Operations and maintenance expense increased primarily due to $5.7 million of higher outside services expenses, $4.8 million of higher expenses related to unplanned generation outages, $2.5 million of higher generation expenses, $2.1 million of higher insurance expense and $1.9 million of higher employee related expenses.

•

Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.

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•

Taxes other than income taxes was comparable to the same period in the prior year.

Operating Statistics


	Revenue								Quantities Sold
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
By Customer Class	2025		2024		2025		2024		2025		2024		2025		2024
	(in millions)								(in GWh)
Retail Revenue -
Residential	$	68.8	$	66.1	$	189.3	$	179.4		393.5		411.1		1,120.9		1,123.4
Commercial		74.6		70.7		210.3		199.9		561.6		571.9		1,578.5		1,590.6
Industrial (a)		49.8		41.6		147.3		126.8		639.1		531.5		1,912.8		1,643.4
Municipal		4.6		4.4		13.4		12.8		41.4		41.4		110.1		111.7
Other Retail		3.5		3.5		10.3		10.5		—		—		—		—
Subtotal Retail Revenue - Electric		201.3		186.3		570.6		529.4		1,635.6		1,555.9		4,722.3		4,469.1
Wholesale		5.5		6.1		16.9		21.1		110.5		124.4		366.7		459.2
Market - off-system sales		16.3		10.7		38.3		22.8		267.0		227.0		660.6		506.8
Transmission		11.1		13.6		33.3		39.1		—		—		—		—
Other (b)		15.5		15.8		47.2		47.4		—		—		—		—
Total Revenue and Quantities Sold	$	249.7	$	232.5	$	706.3	$	659.8	$	2,013.1	$	1,907.3		5,749.6		5,435.1
Other Uses, Losses, or Generation, net (c)										112.9		110.7		332.4		237.5
Total Energy										2,126.0		2,018.0		6,082.0		5,672.6

(a)

The increase in industrial revenues and quantities sold for the three and nine months ended September 30, 2025, compared to the same periods in 2024, was primarily driven by Wyoming Electric LPCS Tariff and BCIS Tariff customers.

(b)

Includes Integrated Generation, inter-segment rent, and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.

(c)

Includes company uses and line losses.


	Revenue								Quantities Sold
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
By Business Unit	2025		2024		2025		2024		2025		2024		2025		2024
	(in millions)								(in GWh)
Colorado Electric	$	79.6	$	74.9	$	218.3	$	208.7		621.3		675.4		1,677.7		1,816.8
South Dakota Electric		90.6		86.0		255.5		242.5		711.8		669.8		2,032.7		1,882.3
Wyoming Electric		68.6		60.3		200.0		176.7		659.9		537.1		1,970.9		1,661.8
Integrated Generation		10.9		11.3		32.5		31.9		20.1		25.0		68.3		74.2
Total Revenue and Quantities Sold	$	249.7	$	232.5	$	706.3	$	659.8		2,013.1		1,907.3		5,749.6		5,435.1

Table of Contents


	Three Months Ended September 30,				Nine Months Ended September 30,
Quantities Generated and Purchased by Fuel Type	2025		2024		2025		2024
	(in GWh)
Generated:
Coal (a)		556.8		645.7		1,614.1		1,804.5
Natural Gas and Oil		718.7		714.4		1,816.1		1,689.3
Wind		115.7		141.8		426.5		477.5
Total Generated		1,391.2		1,501.9		3,856.7		3,971.3
Purchased:
Coal, Natural Gas, Oil, and Other Market Purchases		458.9		223.5		1,305.4		863.0
Wind and Solar		275.9		292.6		919.9		838.3
Total Purchased (b)		734.8		516.1		2,225.3		1,701.3

Total Generated and Purchased		2,126.0		2,018.0		6,082.0		5,672.6

(a)

The decrease in coal generation for the three and nine months ended September 30, 2025, compared to the same period in 2024 is primarily due to unplanned outages at Wygen III.

(b)

The increase in total purchases for the three and nine months ended September 30, 2025, compared to the same periods in 2024, was primarily driven by increased demand from Wyoming Electric LPCS Tariff and BCIS Tariff customers and unplanned outages at Wygen III as discussed in (a) above.


	Three Months Ended September 30,				Nine Months Ended September 30,
Quantities Generated and Purchased by Business Unit	2025		2024		2025		2024
	(in GWh)
Generated:
Colorado Electric		228.1		275.3		595.5		659.9
South Dakota Electric (a)		453.8		549.1		1,377.6		1,503.5
Wyoming Electric		236.9		227.9		676.3		630.9
Integrated Generation		472.4		449.6		1,207.3		1,177.0
Total Generated		1,391.2		1,501.9		3,856.7		3,971.3
Purchased:
Colorado Electric		72.8		67.2		269.5		330.1
South Dakota Electric (a)		294.7		161.8		738.6		425.4
Wyoming Electric (b)		357.7		269.0		1,173.5		894.5
Integrated Generation		9.6		18.1		43.7		51.3
Total Purchased		734.8		516.1		2,225.3		1,701.3

Total Generated and Purchased		2,126.0		2,018.0		6,082.0		5,672.6

(a)

The shift in South Dakota Electric's generated and purchased GWh for the three and nine months ended September 30, 2025, compared to the same period in 2024 is primarily driven by unplanned outages at Wygen III.

(b)

As discussed in footnote (b) in the Quantities Generated and Purchased by Fuel Type table above, the increase in Wyoming Electric's purchases is primarily driven by increased demand from LPCS Tariff and BCIS Tariff customers.

Table of Contents


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Degree Days	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal
Heating Degree Days:
Colorado Electric	34	(15)%	19	(57)%	3,390	8%	3,050	(8)%
South Dakota Electric	86	(41)%	48	(71)%	4,432	---	4,080	(12)%
Wyoming Electric	157	---	109	(35)%	4,382	2%	4,135	(8)%
Combined (a)	77	(24)%	47	(58)%	3,952	3%	3,624	(10)%

Cooling Degree Days:
Colorado Electric	770	(13)%	904	5%	1,005	(14)%	1,247	10%
South Dakota Electric	598	10%	789	57%	760	15%	903	48%
Wyoming Electric	277	(31)%	368	(6)%	337	(30)%	486	6%
Combined (a)	610	(8)%	756	17%	785	(8)%	975	19%

(a)

Degree days are calculated based on a weighted average of total customers by state.


	Three Months Ended September 30,		Nine Months Ended September 30,
Contracted generating facilities Availability(a) by fuel type	2025	2024	2025	2024
Coal	77.3%	90.7%	80.6%	87.3%
Natural gas and diesel oil	97.9%	98.0%	94.2%	95.4%
Wind	82.8%	92.3%	82.6%	91.6%
Total Availability (b)	89.9%	95.1%	88.7%	92.5%

Wind Capacity Factor (a)	26.1%	32.0%	32.4%	36.2%

(a)

Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.

(b)

2025 included unplanned outages at Wygen III, Pueblo Airport Generation #4-5 and Busch Ranch I and II. 2024 included unplanned outages at Wygen I and Pueblo Airport Generation #4-5.

Gas Utilities

Operating results for the Gas Utilities were as follows:


	Three Months Ended September 30,							Nine Months Ended September 30,
	2025		2024		2025 vs 2024 Variance			2025		2024		2025 vs 2024 Variance
	(in millions)
Revenue	$	184.4	$	173.6	$	10.8		$	979.9	$	884.2	$	95.7
Cost of natural gas sold		42.3		39.7		2.6			403.7		362.9		40.8
Gas Utility margin (non-GAAP) (a)		142.1		133.9		8.2			576.2		521.3		54.9

Operations and maintenance		80.3		84.8		(4.5	)		248.5		242.6		5.9
Depreciation and amortization		33.2		31.3		1.9			97.6		92.8		4.8
Taxes other than income taxes		7.8		6.9		0.9			22.4		21.3		1.1
		121.3		123.0		(1.7	)		368.5		356.7		11.8

Operating income	$	20.8	$	10.9	$	9.9		$	207.7	$	164.6	$	43.1

(a)

See Non-GAAP Financial Measures section above for reconciliation to Gross margin, the most directly comparable GAAP measure.

Table of Contents

Three Months Ended September 30, 2025, Compared to the Three Months Ended September 30, 2024:

•

Gas Utility margin increased as a result of the following:


	(in millions)
New rates and rider recovery	$	12.5
Weather		(3.7	)
Other	$	(0.6	)
	$	8.2

•

Operations and maintenance expense decreased primarily due to lower employee related expenses.

•

Depreciation and amortization was comparable to the same period in the prior year.

•

Taxes other than income taxes was comparable to the same period in the prior year.

Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024:

•

Gas Utility margin increased as a result of the following:


	(in millions)
New rates and rider recovery	$	46.4
Weather		8.4
Transport and transmission		3.3
Retail customer growth		3.2
Retail customer usage		(6.1	)
Other		(0.3	)
	$	54.9

•

Operations and maintenance expense increased primarily due to $3.8 million of higher insurance expense and $1.2 million of higher bad debt expense driven by increased revenues and lower prior year write-offs.

•

Depreciation and amortization increased primarily due to higher asset base driven by capital expenditures.

•

Taxes other than income taxes was comparable to the same period in the prior year.

Operating Statistics


	Revenue								Quantities Sold and Transported
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
By Customer Class	2025		2024		2025		2024		2025		2024		2025		2024
	(in millions)								(Dth in millions)
Retail Revenue -
Residential	$	86.0	$	76.2	$	543.4	$	476.5		3.6		3.5		41.5		38.2
Commercial		30.0		27.2		206.3		183.9		2.5		2.4		20.5		19.3
Industrial		8.2		7.6		21.3		18.5		2.0		2.4		4.4		5.1
Other Retail (a)		4.4		6.5		26.0		28.9		—		—		—		—
Subtotal Retail Revenue - Gas		128.6		117.5		797.0		707.8		8.1		8.3		66.4		62.6
Transportation		43.6		43.2		143.4		130.9		36.2		35.8		122.8		117.0
Other (b)		12.2		12.9		39.5		45.5		—		—		—		—
Total Revenue and Quantities Sold	$	184.4	$	173.6	$	979.9	$	884.2		44.3		44.1		189.2		179.6

(a)

Includes Black Hills Energy Services revenue under the Choice Gas Program.

(b)

Includes inter-segment rent and non-regulated services under the Service Guard Comfort Plan, Tech Services, and HomeServe.

Table of Contents


	Revenue								Quantities Sold and Transported
	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended September 30,				Nine Months Ended September 30,
By Business Unit	2025		2024		2025		2024		2025		2024		2025		2024
	(in millions)								(Dth in millions)
Arkansas Gas	$	31.0	$	25.4	$	196.5	$	167.2		4.9		4.5		23.4		21.5
Colorado Gas		27.9		31.5		182.7		191.5		3.5		3.3		21.9		21.3
Iowa Gas		21.7		21.0		138.6		110.4		6.1		5.8		28.1		26.4
Kansas Gas		23.7		19.6		114.9		90.8		8.6		8.5		27.9		26.1
Nebraska Gas		57.2		54.2		245.4		218.9		15.6		16.5		61.7		58.1
Wyoming Gas		22.9		21.9		101.8		105.4		5.6		5.5		26.2		26.2
Total Revenue and Quantities Sold	$	184.4	$	173.6	$	979.9	$	884.2		44.3		44.1		189.2		179.6


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	1	(92)%	9	(40)%	2,151	(3)%	1,925	(18)%
Colorado Gas	99	(7)%	80	(29)%	3,758	---	3,613	(5)%
Iowa Gas	75	2%	45	(47)%	4,003	(1)%	3,450	(19)%
Kansas Gas (a)	18	(20)%	19	(26)%	3,001	7%	2,576	(11)%
Nebraska Gas	41	(23)%	22	(65)%	3,633	---	3,281	(12)%
Wyoming Gas	153	(22)%	132	(37)%	4,586	---	4,384	(6)%
Combined (b)	71	(11)%	50	(43)%	3,811	(1)%	3,502	(11)%

(a)

Arkansas Gas and Kansas Gas have weather normalization mechanisms that mitigate the weather impact on revenue.

(b)

The combined heating degree days are calculated based on a weighted average of total customers by state excluding Kansas Gas due to its weather normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November through April.

Corporate and Other

Corporate and Other operating results, including inter-segment eliminations, were as follows:


	Three Months Ended September 30,									Nine Months Ended September 30,
	2025			2024			2025 vs 2024 Variance			2025			2024			2025 vs 2024 Variance
	(in millions)
Operating income (loss)	$	(4.5	)	$	(0.2	)	$	(4.3	)	$	(7.3	)	$	(0.8	)	$	(6.5	)

Three Months Ended September 30, 2025, Compared to the Three Months Ended September 30, 2024:

•

Operating loss increased primarily due to $8.4 million of NorthWestern merger-related costs partially offset by an unallocated favorable true-up of operating expenses.

Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024:

•

Operating loss increased primarily due to $8.4 million of NorthWestern merger-related costs.

Consolidated Interest Expense, Other Income and Income Tax Expense


	Three Months Ended September 30,									Nine Months Ended September 30,
	2025			2024			2025 vs 2024 Variance			2025			2024			2025 vs 2024 Variance
	(in millions)
Interest expense, net	$	(49.4	)	$	(45.2	)	$	(4.2	)	$	(149.6	)	$	(131.9	)	$	(17.7	)
Other income (expense), net		0.6			(1.3	)		1.9			1.1			(1.7	)		2.8
Income tax (expense)		(4.0	)		(2.9	)		(1.1	)		(26.5	)		(23.6	)		(2.9	)

Table of Contents

Three Months Ended September 30, 2025, Compared to the Three Months Ended September 30, 2024:

•

Interest expense, net, increased due to higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances partially offset by higher AFUDC debt driven by construction work-in-progress balances related to the Lange II and Ready Wyoming projects.

•

Other income (expense), net, was comparable to the same period in the prior year.

•

Income tax (expense) was comparable to the same period in the prior year. For the three months ended September 30, 2025, the effective tax rate was 13.5%, compared to 10.0% for the same period in 2024. The higher effective tax rate was primarily driven by non-deductibility of certain NorthWestern merger-related expenses.

Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024:

•

Interest expense, net, increased due to higher interest rates on long-term debt, higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances partially offset by higher AFUDC debt driven by construction work-in-progress balances related to the Lange II and Ready Wyoming projects.

•

Other income, net, increased primarily due to higher AFUDC equity driven by construction work-in-progress balances related to the Lange II and Ready Wyoming projects;

•

Income tax (expense) was comparable to the same period in the prior year. For the nine months ended September 30, 2025, the effective tax rate was 12.2%, which was comparable to 11.4% for the same period in 2024.

Liquidity and Capital Resources

The following table provides an informational summary of our liquidity and capital structure as of:


	September 30, 2025			December 31, 2024
	(dollars in millions)
Cash and cash equivalents	$	21.1		$	16.1
Available capacity under Revolving Credit Facility and CP Program (a)		620.9			612.7
Available liquidity	$	642.0		$	628.8

Capital structure
Short-term debt	$	126.0		$	133.8
Long-term debt (b)		4,252.8			4,250.2
Total debt		4,378.8			4,384.0
Total stockholders' equity (excludes non-controlling interest)		3,768.0			3,501.5
Total capitalization	$	8,146.8		$	7,885.5

Debt to capitalization		53.7	%		55.6	%
Long-term debt to total debt		97.1	%		96.9	%

(a)

Available capacity under Revolving Credit Facility and CP Program represents $750 million of total borrowing capacity less outstanding borrowings and letters of credit. See Note 5 of the Notes to Consolidated Financial Statements for more information.

(b)

On October 2, 2025, we completed a public debt offering of $450 million, 4.55% senior unsecured notes due January 31, 2031. Net proceeds from the offering will be used to repay our $300 million, 3.95% senior unsecured notes at or before their January 2026 maturity and for other general corporate purposes.

Future Financing Plans

We plan to fund our capital plan and strategic objectives by using cash generated from operating activities and various financing alternatives, which could include our Revolving Credit Facility, our CP Program, and the issuance of common stock under our ATM or in a secondary offering. We plan to repay our $300 million, 3.95%, senior unsecured notes due January 2026, at or before the maturity date.

Table of Contents

CASH FLOW ACTIVITIES

The following tables summarize our cash flows for the nine months ended September 30, 2025:

Operating Activities:


	Nine Months Ended September 30,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Net income	$	191.1		$	182.6		$	8.5
Non-cash adjustments to Net income		278.0			264.9			13.1
Total earnings	$	469.1		$	447.5		$	21.6
Changes in certain operating assets and liabilities:
Materials, supplies and fuel, Accounts receivable and other current assets		71.8			134.8			(63.0	)
Accounts payable and other current liabilities		(70.4	)		(61.8	)		(8.6	)
Regulatory assets		47.1			61.6			(14.5	)
Net inflow (outflow) from changes in certain operating assets and liabilities	$	48.5		$	134.6		$	(86.1	)
Other operating activities		(12.3	)		(16.0	)		3.7
Net cash provided by operating activities	$	505.3		$	566.1		$	(60.8	)

Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024

•

Total earnings (net income plus non-cash adjustments) were $21.6 million higher for the nine months ended September 30, 2025, compared to the same period in the prior year primarily as a result of increased Electric and Gas Utility margins due to new rates and rider recovery partially offset by higher operating expenses, NorthWestern merger-related costs and higher financing costs.

•

Net inflows from changes in certain operating assets and liabilities were $86.1 million lower, primarily attributable to:

Cash inflows decreased by approximately $63.0 million as a result of changes in accounts receivable and other current assets primarily driven by fluctuations in commodity prices;

Cash outflows increased by approximately $8.6 million as a result of increases in accounts payable and other current liabilities primarily driven by fluctuations in commodity prices, remediation costs for our manufactured gas plant site in Iowa and changes in other working capital requirements; and

Cash inflows decreased by approximately $14.5 million as a result of changes in our regulatory assets and liabilities primarily due to lower recoveries of our Winter Storm Uri regulatory asset as recovery is now complete in several of our jurisdictions.

•

Cash outflows decreased $3.7 million from other operating activities primarily due to lower costs from cloud computing arrangements.

Investing Activities:


	Nine Months Ended September 30,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Capital expenditures	$	(550.2	)	$	(530.5	)	$	(19.7	)
Other investing activities		(6.2	)		(1.5	)		(4.7	)
Net cash (used in) investing activities	$	(556.4	)	$	(532.0	)	$	(24.4	)

Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024

•

Cash outflows from capital expenditures (which are net of contributions in aid of construction) increased $19.7 million primarily as a result of the Ready Wyoming and Lange II projects and prior year receipts related to contributions in aid of construction for data center projects in Wyoming partially offset by prior year expenditures from Black Hills Energy Renewable Resources' acquisition of an RNG production facility at a landfill in Dubuque, Iowa; and

Table of Contents

•

Cash outflows increased by $4.7 million for other investing activities primarily due to higher AFUDC debt driven construction work-in-progress balances related to the Lange II and Ready Wyoming projects.

Financing Activities:


	Nine Months Ended September 30,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Dividends paid on common stock	$	(146.8	)	$	(135.8	)	$	(11.0	)
Common stock issued		219.2			181.6			37.6
Short-term and long-term debt borrowings (repayments), net		(7.8	)		(132.5	)		124.7
Distributions to non-controlling interests		(5.2	)		(12.5	)		7.3
Other financing activities		(2.6	)		(8.3	)		5.7
Net cash provided by (used in) financing activities	$	56.8		$	(107.5	)	$	164.3

Nine Months Ended September 30, 2025, Compared to the Nine Months Ended September 30, 2024

•

Dividends paid on common stock increased $11.0 million due to the increased dividend rate per share and increased number of common shares outstanding;

•

Cash inflows increased $37.6 million due to increased issuances of common stock;

•

Net cash outflows decreased $124.7 million primarily as a result of net repayment activity under our CP Program and the prior year repayment of $600 million, 1.04% senior unsecured notes on their August 2024 maturity date partially offset by prior year proceeds from the May 2024, debt offering of $450 million, 6.00% senior unsecured notes;

•

Distributions to non-controlling interests decreased $7.3 million due to lower net income from Black Hills Colorado IPP primarily driven by unplanned generation outages; and

•

Cash outflows decreased $5.7 million from other financing activities primarily due to prior year financing costs from the May 2024 debt offering.

CAPITAL RESOURCES

See Note 5 of the Condensed Notes to Consolidated Financial Statements for recent financing updates and financial covenants information.

CREDIT RATINGS

The following table represents the credit ratings and outlook and risk profile of BHC as of the date of this report:


Rating Agency	Senior Unsecured Rating	Outlook
S&P (a)	BBB+	Stable
Moody's (b)	Baa2	Stable

(a)

On August 19, 2025, S&P affirmed our BBB+ rating and maintained a Stable outlook.

(b)

On August 19, 2025, Moody's affirmed our Baa2 rating and maintained a Stable outlook.

The following table represents the credit rating of South Dakota Electric as of the date of this report:


Rating Agency	Senior Secured Rating
S&P	A

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CAPITAL REQUIREMENTS

Capital Expenditures


	Actual (a)		Forecasted (b)
Capital Expenditures by Segment (minor differences may result due to rounding)	Nine Months Ended September 30, 2025		2025 (c)		2026		2027		2028		2029
	(in millions)
Electric Utilities	$	334	$	550	$	432	$	383	$	615	$	435
Gas Utilities		268		431		386		412		447		447
Corporate and Other		7		21		41		27		27		27
	$	609	$	1,002	$	859	$	822	$	1,089	$	909

(a)

Includes accruals for property, plant and equipment as disclosed in supplemental cash flow information in the Consolidated Statements of Cash Flows in the Consolidated Financial Statements. Capital expenditures are presented net of CIACs in the Consolidated Statements of Cash Flows.

(b)

Projects are being evaluated by our segments for timing, cost, and other factors.

(c)

Includes actual capital expenditures for the nine months ended September 30, 2025.

Common Stock Dividends

Dividends paid on our common stock totaled $146.8 million for the nine months ended September 30, 2025, or $0.676 per share. On October 28, 2025, our board of directors declared a quarterly dividend of $0.676 per share payable December 1, 2025, equivalent to an annual dividend of $2.704 per share. The amount of any future cash dividends to be declared and paid, if any, will depend upon, among other things, our financial condition, funds from operations, the level of our capital expenditures, restrictions under our Revolving Credit Facility, and our future business prospects.

Critical Accounting Estimates

A summary of our critical accounting estimates is included in our 2024 Annual Report on Form 10-K. There were no material changes made as of September 30, 2025.

New Accounting Pronouncements

See Note 1 of the Condensed Notes to Consolidated Financial Statements for a description of recent accounting pronouncements, if any, and our expectation of their impact on our results of operations and financial condition.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no material changes to our quantitative and qualitative disclosures about market risk previously disclosed in Item 7A of our 2024 Annual Report on Form 10-K.

ITEM 4. CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of September 30, 2025. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at September 30, 2025.

Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, 2025, there have been no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely, to materially affect our internal control over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

For information regarding legal proceedings, see Note 3 of the Condensed Notes to Consolidated Financial Statements and Note 3 in Item 8 of our 2024 Annual Report on Form 10-K.

ITEM 1A. RISK FACTORS

There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2024 Annual Report on Form 10-K except as described below.

Risks Related to the Merger

The ability of Black Hills and NorthWestern to complete the Merger is subject to various closing conditions, including the receipt of approval of Black Hills and NorthWestern shareholders and the receipt of consents and approvals from various governmental authorities, which may impose conditions that could adversely affect Black Hills or NorthWestern or cause the Merger to be abandoned. Failure to complete the Merger, or significant delays in completing the Merger, could negatively affect the trading price of Black Hills common stock or other securities and the future business and financial results of Black Hills.

To complete the Merger, Black Hills and NorthWestern shareholders must vote to approve a number of proposals related to the Merger and the Merger Agreement. Further, the Merger is subject to the satisfaction or waiver of certain closing conditions, including, (1) the effectiveness of a registration statement on Form S-4 to be filed in connection with the Merger; (2) subject to certain conditions, the receipt of certain regulatory approvals, including expiration or termination of the applicable waiting period under the HSR Act, and approval from the FERC and certain state regulatory commissions, in each case on such terms and conditions that would not result in a material adverse effect on the combined company; (3) the absence of any court order or regulatory injunction prohibiting completion of the Merger; (4) the authorization for listing of shares of Black Hills Common Stock to be issued in connection with the Merger on the NYSE or other mutually-agreed stock exchange; (5) subject to specified materiality standards, the accuracy of the representations and warranties of each party; (6) compliance by each party in all material respects with its covenants under the Merger Agreement; (7) the absence of a material adverse effect on each party; and (8) receipt by each party of an opinion relating to the anticipated tax-free treatment of the Merger. If the foregoing conditions are not satisfied or waived, one or both of Black Hills or NorthWestern would not be required to complete the Merger.

Black Hills and NorthWestern have not yet obtained shareholder approval or the regulatory consents and approvals required to complete the Merger. Governmental or regulatory agencies could seek to block or challenge the Merger or could impose restrictions they deem necessary or desirable in the public interest as a condition to approving the Merger. Black Hills and NorthWestern will be unable to complete the Merger until the waiting period under the HSR Act has expired or been terminated and the required governmental approvals have been received. Regulatory authorities may impose certain requirements or obligations as conditions for their approval. The Merger Agreement may require Black Hills and/or NorthWestern to accept conditions from these regulators that could adversely impact the combined company. If the required governmental approvals are not received, or they are not received on terms that satisfy the conditions set forth in the Merger Agreement, then neither Black Hills nor NorthWestern will be obligated to complete the Merger.

There can be no assurance that a challenge to the Merger on antitrust grounds will not be made or, if such a challenge is made, of the result of such challenge.

Additionally, even after the statutory waiting period under the antitrust laws and even after completion of the Merger, governmental authorities could seek to block or challenge the Merger as they deem necessary or desirable in the public interest. In addition, in some jurisdictions, a private party could initiate an action under the antitrust laws challenging or seeking to enjoin the Merger, before or after they are completed. Black Hills or NorthWestern may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.

The special meetings at which the Black Hills shareholders and the NorthWestern shareholders will vote on the transactions contemplated by the Merger Agreement may take place before all regulatory approvals have been obtained and, in cases where they have not been obtained, before the terms of any conditions to obtain such regulatory approvals that may be imposed are known. As a result, if shareholder approval of the transactions contemplated by the Merger Agreement is obtained at such meetings, Black Hills and NorthWestern may make decisions after the meetings to waive a condition or approve certain actions required to obtain the necessary approvals without seeking further shareholder approval. Such actions could have an adverse effect on the combined company.

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If Black Hills and NorthWestern are unable to complete the Merger, or there is a significant delay in completing the Merger, Black Hills would be subject to a number of risks, including the following:

•

Black Hills would not realize the anticipated benefits of the Merger, including, among other things, increased operating efficiencies and future cost savings;

•

the attention of management of Black Hills may have been diverted to the Merger rather than to its own operations and the pursuit of other opportunities that could have been beneficial to Black Hills;

•

the potential loss of key personnel during the pendency of the Merger as employees may experience uncertainty about their future roles with the combined company;

•

Black Hills will have been subject to certain restrictions on the conduct of its business, which may prevent Black Hills from making certain acquisitions or dispositions or pursuing certain business opportunities while the Merger is pending;

•

the trading price of Black Hills common stock or other securities may decline to the extent that the current market prices reflect a market assumption that the Merger will be completed; and

•

the parties may be liable for damages to one another, or have to pay a termination fee, under the Merger Agreement.

Black Hills can provide no assurance that the various closing conditions will be satisfied and that the required governmental approvals and other approvals will be obtained, or that any required conditions will not materially adversely affect the combined company following the Merger. In addition, Black Hills can provide no assurance that these conditions will not result in the abandonment or delay of the Merger. The occurrence of these events individually or in combination could have a material adverse effect on Black Hills’ results of operations and the trading price of Black Hills common stock or other securities.

The Merger Agreement contains provisions that limit Black Hills’ ability to pursue alternatives to the Merger, could discourage a potential acquirer of Black Hills from making a favorable alternative transaction proposal and, in certain circumstances, could require Black Hills to pay a termination fee to NorthWestern.

Under the Merger Agreement, Black Hills and NorthWestern have agreed, subject to certain exceptions with respect to unsolicited proposals, not to directly or indirectly solicit competing acquisition proposals or to enter into discussions concerning, or provide confidential information in connection with, any unsolicited alternative acquisition proposals. Additionally, the Black Hills board of directors and the NorthWestern board of directors are each required to recommend the approval of the applicable transaction-related proposals to its respective shareholders, subject to certain exceptions. Prior to the approval of the transaction-related proposals by their respective shareholders, the Black Hills board of directors or the NorthWestern board of directors may change its recommendation in response to an unsolicited proposal for an alternative transaction, if such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that the proposal constitutes or would reasonably be expected to lead to a “Superior NorthWestern Proposal” or “Superior Black Hills Proposal”, as applicable (as such terms are defined in the Merger Agreement), and that failure to take such action would be inconsistent with their fiduciary duties under applicable law to the applicable company and its shareholders under applicable law, subject to complying with certain procedures set forth in the Merger Agreement. Prior to the approval of the transaction-related proposals by their respective shareholders, the Black Hills board of directors and the NorthWestern board of directors may also change its recommendation upon the occurrence of a “NorthWestern Intervening Event” or “Black Hills Intervening Event”, as applicable (as such terms are defined in the Merger Agreement), and such board of directors determines in good faith after consultation with its outside legal counsel and financial advisor that failing to change its recommendation would be inconsistent with its fiduciary duties under applicable law, subject to complying with certain procedures set forth in the Merger Agreement. The Merger Agreement is subject to a “force-the-vote” provision, which means neither Black Hills nor NorthWestern would have an independent right to terminate the Merger Agreement to accept a superior proposal. These provisions could discourage a third party that may have an interest in acquiring all or a significant part of Black Hills from considering or proposing that acquisition, even if such third party were prepared to pay consideration with a higher market value than the market value proposed to be received or realized in the merger, or might result in a potential acquirer proposing to pay a lower price than it would otherwise have proposed to pay. As a result of these restrictions, Black Hills may not be able to enter into an agreement with respect to a more favorable alternative transaction, or may be able to do so only by incurring potentially significant liability to NorthWestern.

The Merger Agreement contains certain customary termination rights for each of Black Hills and NorthWestern; provided, that, either party would be required to pay to the other a termination fee equal to $100 million upon termination of the Merger Agreement in certain circumstances involving (i) a change in recommendation by such party’s board of directors (including, in certain circumstances, the failure of such party to publicly reaffirm its recommendation upon request) or (ii) a party entering into a definitive agreement in respect of a competing transaction within twelve months of termination of the Merger Agreement in certain circumstances involving a potential competing acquisition proposal.

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Uncertainties associated with the Merger may cause a loss of management personnel and other key employees of Black Hills and NorthWestern, which could adversely affect the future business and operations of the combined company following the Merger.

Each of Black Hills and NorthWestern depends on the experience and industry knowledge of its officers and other key employees to execute its business plans. The success of the combined company after the Merger will depend in part on its ability to retain key management personnel and other key employees. Current and prospective employees of Black Hills and NorthWestern may experience uncertainty about their roles within the combined company following the Merger or other concerns regarding the timing and completion of the Merger or the operations of the combined company following the Merger, any of which may have an adverse effect on the ability of Black Hills and NorthWestern to retain or attract key management and other key personnel. If Black Hills or NorthWestern is unable to retain personnel, including Black Hills’ or NorthWestern’s key management, who are critical to the future operations of the companies, Black Hills and NorthWestern could face disruptions in their operations, loss of existing customers, loss of key information, expertise or know-how and unanticipated additional recruitment and training costs. In addition, the loss of key Black Hills and NorthWestern personnel could diminish the anticipated benefits of the Merger. No assurance can be given that the combined company, following the Merger, will be able to retain or attract key management personnel and other key employees of Black Hills and NorthWestern to the same extent that Black Hills and NorthWestern have previously been able to retain or attract their own employees.

The business relationships of Black Hills and NorthWestern may be subject to disruption due to uncertainty associated with the Merger, which could have a material effect on the business, financial condition, cash flows and results of operations of Black Hills or NorthWestern pending the combined company and following the Merger.

Parties with which Black Hills or NorthWestern do business may experience uncertainty associated with the Merger, including with respect to current or future business relationships with Black Hills or NorthWestern following the Merger. Black Hills’ and NorthWestern’s business relationships may be subject to disruption as customers, distributors, suppliers, vendors, landlords, joint venture participants and other third parties with whom they do business may attempt to delay or defer entering into new business relationships, negotiate changes in existing business relationships or consider entering into business relationships with parties other than Black Hills or NorthWestern following the Merger. These disruptions could have a material and adverse effect on the business, financial condition, cash flows and results of operations, of Black Hills or NorthWestern, regardless of whether the Merger is completed, as well as a material and adverse effect on the combined company’s ability to realize the expected cost savings and other benefits of the Merger. The risk, and adverse effects, of any disruption could be exacerbated by a delay in completion of the Merger or termination of the Merger Agreement.

Black Hills is subject to risk of the Merger having an adverse impact on its credit rating, both while the Merger is pending and following completion of the Merger.

Black Hills cannot be assured that its credit ratings will not be lowered as a result of the Merger or for any other reason, including the failure to consummate the Merger. Any reduction in Black Hills’ credit ratings, or the criteria used by rating agencies to determine such ratings, could adversely affect its ability to complete the Merger, its access to capital, its cost of capital and its other operating costs, and its ability to refinance or repay Black Hills’ existing debt and complete new financings, which could have a material adverse effect on Black Hills’ business, financial condition, results of operations or the trading price of its common stock or other securities.

The market prices of Black Hills common stock and other securities may be subject to fluctuation while the Merger is pending and after the Merger is completed.

The market price of Black Hills common stock and other securities may fluctuate significantly while the Merger is pending, or after it is completed, and any adverse developments related to the Merger or otherwise could result in holders of Black Hills common stock or other securities losing some or all of the value of their investment. In addition, if the stock market experiences significant price and volume fluctuations, such fluctuations could be exacerbated by the pendency of the Merger, which could adversely affect the market for, or liquidity of, Black Hills common stock or other securities, regardless of Black Hills’ or the combined company’s actual operating performance.

Because the Merger Agreement contemplates that Black Hills will issue shares of Black Hills common stock to NorthWestern’s shareholders based upon a fixed exchange ratio, developments with respect to NorthWestern and its shares of common stock may affect Black Hills common stock irrespective of their relevance to standalone Black Hills and even though Black Hills may have no control over, or knowledge of, such developments. As a result, the market price of Black Hills common stock during the pendency of the Merger may not accurately reflect the value of Black Hills absent the Merger.

Black Hills is subject to contractual restrictions in the Merger Agreement that may hinder its operations while the Merger is pending. The corollary restrictions applicable to NorthWestern may not prevent NorthWestern from taking actions that are adverse to Black Hills or its shareholders.

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The Merger Agreement includes certain customary restrictions with respect to the operation of Black Hills’ and NorthWestern’s respective businesses between the date of the Merger Agreement and the consummation of the Merger. These restrictions may prevent Black Hills from pursuing otherwise attractive business opportunities and making other changes to its business prior to completion of the Merger or termination of the Merger Agreement.

Despite these mutual restrictions, Black Hills and NorthWestern will continue to operate their businesses independently of one another during the pendency of the Merger. The restrictions in the Merger Agreement, which are subject to numerous exceptions, may not be adequate to prevent NorthWestern from taking actions that are adverse to Black Hills or its shareholders.

Black Hills will incur significant transaction and other costs in connection with the Merger.

Black Hills has incurred and expects to incur additional significant costs associated with the Merger, including transaction fees and costs of combining the operations of the two companies. Additional unanticipated costs also may be incurred in the integration of the businesses of Black Hills and NorthWestern. Any net benefit from any anticipated elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not be achieved in the near term or at all. Transaction costs could have a material adverse impact on the results of operations of Black Hills, and the failure to achieve the anticipated benefits and efficiencies from the Merger, or the incurrence of additional expenses, could have a material adverse impact on the results of operations of the combined company and its ability to pay dividends after closing. In turn, the current or future market value of Black Hills common stock or other securities could be adversely impacted.

The Merger may not be accretive to Black Hills’ or NorthWestern’s earnings and may cause dilution to Black Hills’ or NorthWestern’s earnings per share, which may negatively affect the current or future market price of Black Hills common stock or other securities.

Expectations that the Merger will be accretive to earnings per share on a standalone basis are based on preliminary estimates any of which may prove to be incorrect or may change materially. Black Hills and NorthWestern may encounter additional transaction and integration-related costs other than those they currently anticipate, may fail to realize all of the benefits anticipated in the Merger or may be subject to other factors that affect preliminary estimates or the ability of either company to realize operational efficiencies. Any of these factors could cause a decrease in Black Hills’ and NorthWestern’s earnings per share, or negatively affect the current or future market price of Black Hills common stock or other securities.

Black Hills and/or NorthWestern may be subject to litigation challenging the Merger while it is pending, and an unfavorable judgment or ruling in any such lawsuits could prevent or delay the consummation of the Merger and/or result in substantial costs.

Lawsuits in connection with the Merger while it is pending may be filed against Black Hills, NorthWestern, any parties to the Merger Agreement and/or their respective directors and officers, which could prevent or delay the consummation of the Merger and/or result in additional costs to us. The ultimate resolution of any such lawsuit cannot be predicted with certainty, and an adverse ruling in any such lawsuit may cause the Merger to be delayed or not to be completed and/or result in additional costs to Black Hills and NorthWestern, which could cause Black Hills and NorthWestern not to realize some or all of the anticipated benefits of the Merger. The defense or settlement of any lawsuit that remains unresolved at the time the Merger is consummated may adversely affect the combined company’s business, financial condition, results of operations and cash flows. Black Hills cannot currently predict the outcome of or reasonably estimate the possible loss or range of loss from any such lawsuit.

Risks Relating to the Combined Company Following Completion of the Merger

Failure to successfully combine the businesses of Black Hills and NorthWestern in the expected time frame or at all may adversely affect the future results of the combined company, and, consequently, the value of the Black Hills common stock after the Merger.

The success of the Merger will depend, in part, on the ability of the combined company to realize in a timely fashion the anticipated benefits and efficiencies from combining the businesses of Black Hills and NorthWestern. The process of integration may reveal that benefits and efficiencies are less than anticipated and may result in additional expenses, all of which could reduce the anticipated benefits of the Merger.

Achieving the anticipated benefits of the Merger is subject to a number of uncertainties, including:

•

whether U.S. federal and state public utility, antitrust and other regulatory authorities whose approval is required to complete the Merger impose conditions on the Merger, which may have an adverse effect on the combined company, including its ability to achieve the anticipated benefits of the Merger;

•

the ability of the two companies to combine certain of their operations or take advantage of expected growth opportunities;

•

general market and economic conditions;

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•

general competitive factors in the marketplace; and

•

higher than expected costs required to achieve the anticipated benefits of the Merger.

Failure to achieve the anticipated benefits and efficiencies from the Merger, or the occurrence of additional expenses, could have a material adverse impact on the results of operations of the combined company and its ability to pay dividends after closing. In turn, the market value of the combined company’s common stock could be adversely impacted.

Black Hills shareholders will have a reduced ownership and voting interest after the Merger and will exercise less influence over management.

It is currently anticipated that Black Hills shareholders and NorthWestern shareholders will hold approximately 56 percent and 44 percent, respectively, of the combined company’s common stock then-issued and outstanding after the completion of the Merger. Consequently, Black Hills shareholders, as a group, will have reduced ownership and voting power in the combined company compared to their current ownership and voting power in Black Hills. As a result of the reduced ownership percentages, current Black Hills shareholders will have less influence on the management and policies of the combined company than they had with Black Hills. Further, provisions of the Merger Agreement will result in individuals designated by NorthWestern, and not previously subject to a vote of Black Hills shareholders, holding five out of eleven positions on the Black Hills board of directors and there will be changes to the Black Hills Management.

The market price of Black Hills common stock after the completion of the Merger may be affected by factors different from those that historically have affected or currently affect Black Hills common stock.

Upon completion of the Merger, NorthWestern shareholders who receive Merger consideration will become holders of Black Hills common stock, which will trade on the NYSE or other mutually-agreeable exchange under a new name and ticker to be announced. Black Hills’ business differs from that of NorthWestern and certain adjustments may be made to the combined company as a result of the Merger. The financial position of the combined company after completion of the Merger may differ from Black Hills’ financial position before the completion of the Merger, and the results of operations and/or cash flows of Black Hills after the completion of the Merger may be affected by factors different from those currently affecting the financial position or results of operations and/or cash flows of Black Hills and NorthWestern, respectively. Accordingly, the market price of Black Hills common stock after the completion of the Merger may be affected by factors different from those currently affecting the market prices of Black Hills common stock and NorthWestern common stock, respectively, in the absence of the Merger. In addition, general fluctuations in stock markets could adversely affect the market for, or liquidity of, Black Hills common stock, regardless of the combined company’s actual operating performance.

Each of Black Hills and NorthWestern may have liabilities that are not known to the other party.

Each of Black Hills and NorthWestern may have liabilities that the other party failed, or was unable, to discover in the course of performing its respective due diligence investigations. Black Hills and NorthWestern may learn additional information about the other party that materially adversely affects it, such as unknown or contingent liabilities and liabilities related to compliance with applicable laws. As a result of these factors, the combined company may incur additional costs and expenses and may be forced to later write-down or write-off assets, restructure operations or incur impairment or other charges that could result in the combined company reporting losses. Even if Black Hills’ and NorthWestern’s respective due diligence has identified certain risks, unexpected risks may arise and previously known risks may materialize in a manner not consistent with its expectations. If any of these risks materialize, this could adversely affect the combined company’s financial condition and results of operations and could contribute to negative market perceptions about, or price movements of, the combined company’s common stock following the Merger.

Each of NorthWestern and Black Hills and their respective subsidiaries has substantial amounts of indebtedness. Consequently, the combined company will have substantial indebtedness following the Merger. As a result, the rating of the combined company’s indebtedness could be downgraded, and it may be difficult for the combined company to pay or refinance its debts or take other actions, and the combined company may need to divert its cash flow from operations to debt service payments.

The combined company’s debt service obligations could have an adverse impact on its earnings and cash flows for as long as the indebtedness is outstanding.

The combined company’s indebtedness could also have important consequences for holders of Black Hills common stock. For example, it could:

•

make it more difficult for the combined company to pay or refinance its debts as they become due during adverse economic and industry conditions because any decrease in revenues could cause the combined company to not have sufficient cash flows from operations to make its scheduled debt payments;

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require a substantial portion of the combined company’s cash flows from operations to be used for debt service payments, thereby reducing the availability of its cash flow to fund working capital, capital expenditures, acquisitions, dividend payments and other general corporate purposes;

•

result in a downgrade in the rating of the combined company’s indebtedness, which could limit its ability to borrow additional funds or increase the interest rates applicable to its indebtedness;

•

increasing the risk of default on debt obligations of the combined company;

•

limiting the flexibility of the combined company in planning for or reacting to changes in its business and the industry in which it operates;

•

increasing the exposure of the combined company to a rise in interest rates, which would generate greater interest expense or the costs of obtaining applicable interest rate fluctuation hedges; or

•

require that additional or more stringent terms, conditions or covenants be placed on Black Hills.

There can be no assurance that the combined company will be able to repay or refinance such borrowings and obligations. In addition, the Merger will result in NorthWestern becoming a wholly owned subsidiary of Black Hills. The combined company may decide to incur additional indebtedness at subsidiaries of Black Hills, which could have an effect on outstanding securities, including because such subsidiary indebtedness is “structurally senior” to the indebtedness of its parent company with respect to the assets of such subsidiary.

The future results of the combined company following the Merger will suffer if the combined company does not effectively manage its expanded operations.

Following the Merger, the size, geographic footprint and complexity of the combined company will increase significantly compared to the business of each of Black Hills and NorthWestern. The combined company’s future success will depend, in part, upon its ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and geographies and associated increased costs and complexity. The combined company may also face increased scrutiny from, and/or additional regulatory requirements of, governmental authorities as a result of the significant increase in the size, geographic footprint and complexity of its business. There can be no assurances that the combined company will be successful or that it will realize the expected operating efficiencies, cost savings or other benefits currently anticipated from the Merger.

There is no guarantee regarding dividends following the Merger.

Although each of Black Hills and NorthWestern has returned capital to its respective shareholders in the past, including through cash dividends on their respective shares of common stock, the board of directors of the combined company may determine not to declare dividends or use other means to return capital to its shareholders in the future or may reduce the amount, proportion or rate of capital returned to its shareholders through dividends or other means in the future. Decisions on whether, when, by what means and in what amounts to return capital to its shareholders will remain in the discretion of the board of directors of the combined company (as reconstituted following the Merger). Any dividend payment or share repurchase amounts will be determined by the board of directors of the combined company from time to time, and it is possible that the board of directors of the combined company may increase or decrease the amount of dividends paid or shares repurchased in the future, or determine not to declare dividends and/or repurchase shares in the future, at any time and for any reason. Black Hills expects that any such decisions will depend on the combined company’s financial condition, results of operations, cash balances, cash requirements, future prospects, the outlook for commodity prices and other considerations that the board of directors of the combined company deems relevant, including, but not limited to:

•

whether the combined company has enough discretionary cash flow to return capital to its shareholders due to its cash requirements, capital spending plans, cash flows or financial position;

•

the combined company’s desire to maintain or improve the credit ratings on its debt; and

•

applicable restrictions under South Dakota law. Shareholders should be aware that they have no contractual or other legal right to dividends that have not been declared.

The combined company is expected to record a significant amount of goodwill as a result of the Merger, and such goodwill could become impaired in the future.

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Accounting standards in the United States require that one party to the Merger be identified as the acquirer. In accordance with these standards, the Merger will be accounted for as an acquisition of NorthWestern’s common stock by Black Hills and will follow the acquisition method of accounting for business combinations. NorthWestern assets and liabilities will be consolidated with those of Black Hills on the combined company’s financial statements. The excess of the consideration transferred over the fair values of NorthWestern’s assets and liabilities will be recorded as goodwill.

Black Hills will be required to assess goodwill for impairment at least annually. To the extent goodwill becomes impaired, Black Hills may be required to incur material charges relating to such impairment. Such a potential impairment charge could have a material impact on Black Hills’ future operating results and statements of financial position which may, in turn, have a material adverse effect on the trading price or liquidity of Black Hills securities.

Black Hills’ ability to utilize its and/or NorthWestern’s historic net operating loss carryforwards and certain other tax attributes may be limited.

As of December 31, 2024, NorthWestern had U.S. federal net operating loss carryforwards (“NOLs”) of approximately $486.6 million, which do not expire. As of December 31, 2024, Black Hills had NOLs of approximately $547.2 million, which also do not expire. However, the NOLs of each of NorthWestern and Black Hills can only be used to offset 80% of U.S. federal taxable income. Black Hills’ ability to utilize these NOLs and other tax attributes to reduce future taxable income following the closing of the Merger depends on many factors, including its future income, which cannot be assured, and which will be determined after the Merger on a consolidated basis with that of NorthWestern. It is possible that the amount of NOLs and other tax attributes that Black Hills is able to utilize in any tax period ending after the closing of the Merger may be less than the amount that Black Hills and NorthWestern together (or either of them separately) would have been able to use had the Merger not taken place.

Additionally, Section 382 of the Code (“Section 382”) and Section 383 of the Code generally impose an annual limitation on the amount of NOLs and certain other tax attributes that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more shareholders (or groups of shareholders) who are each deemed to own at least 5% of such corporation’s stock increase their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change occurs with respect to Black Hills and/or NorthWestern, utilization of Black Hills and/or NorthWestern’s NOLs would be subject to an annual limitation under Section 382, generally determined by multiplying (1) the fair market value of its stock at the time of the ownership change by (2) the long-term tax-exempt rate published by the IRS for the month in which the ownership change occurs, subject to certain adjustments. Any unused annual limitation may be carried over to later years.

The completion of the Merger may cause Black Hills and/or NorthWestern to undergo an ownership change under Section 382, which would trigger a limitation (calculated as described above) on Black Hills’ ability to utilize its and/or NorthWestern’s historic NOLs and other tax attributes.

Future sales or issuances of Black Hills common stock could have a negative impact on the Black Hills common stock price.

Under the terms of the Merger Agreement, NorthWestern shareholders will receive a fixed exchange ratio of 0.98 shares of Black Hills common stock for each share of NorthWestern common stock they own at the close of the Merger. Based on the 61,393,380 shares of NorthWestern common stock outstanding as of July 25, 2025, Northwestern shareholders would receive approximately 60,165,512 shares of Black Hills common stock upon the closing of the Merger. The treatment of outstanding equity awards of each of Black Hills and NorthWestern will vary depending on the type of award, its terms and conditions, and determinations made or to be made by each company or its board of directors, but additional shares, or cash in respect of share equivalents, would be issued to settle equity awards, and such shares are not reflected in the share totals included in the preceding sentence. The Black Hills common stock that NorthWestern shareholders will receive upon the exchange of NorthWestern common stock for the Merger consideration or in settlement of outstanding equity awards generally may be sold immediately in the public market. It is possible that some former NorthWestern shareholders may seek to sell some or all of the shares of Black Hills common stock they receive as Merger consideration, and the Merger Agreement contains no restriction on the ability of former NorthWestern shareholders to sell such shares of Black Hills common stock following completion of the Merger. Other Black Hills shareholders may also seek to sell shares of Black Hills common stock held by them following completion of the Merger. These sales or other dispositions of a significant number of shares of Black Hills common stock (or the perception that such sales or other dispositions may occur), coupled with the increase in the outstanding number of shares of Black Hills common stock as a result of the Merger (as well as any increase resulting from future issuances of Black Hills common stock), may affect the market for Black Hills common stock in an adverse manner and may cause the price of Black Hills common stock to fall.

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

The following table contains monthly information about our acquisitions of equity securities for the three months ended September 30, 2025:


Period	Total Number of Shares Purchased (a)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
July 1, 2025 - July 31, 2025		1	$	56.79		—		—
August 1, 2025 - August 31, 2025		127		59.17		—		—
September 1, 2025 - September 30, 2025		1		59.83		—		—
Total		129	$	59.16		—		—

(a)

Shares were acquired under the share withholding provisions of the Amended and Restated 2015 Omnibus Incentive Plan for payment of taxes associated with the vesting of various equity compensation plans.

ITEM 4. MINE SAFETY DISCLOSURES

Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act is included in Exhibit 95.

ITEM 5. OTHER INFORMATION

None of our directors or officers adopted, modified, or terminated a Rule 10b5-1 trading arrangement or a non-Rule 10b5-1 trading arrangement during the three months ended September 30, 2025.

ITEM 6. EXHIBITS

Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated.


Exhibit Number	Description
2.1	Agreement and Plan of Merger, dated as of August 18, 2025, by and among Black Hills Corporation, NorthWestern Energy Group, Inc. and River Merger Sub, Inc. (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed on August 19, 2025).
3.2	Amended and Restated Bylaws of the Registrant dated August 18, 2025.
4.1	Fourteenth Supplemental Indenture dated as of October 2, 2025 between Black Hills Corporation and Computershare Trust Company, N.A. (as current successor to LaSalle Bank National Association), as trustee (filed as Exhibit 4.1 to the Registrant's Form 8-K filed on October 2, 2025).
10.1	Chief Executive Officer Agreement, dated as of August 18, 2025, between Black Hills Corporation and Brian B. Bird (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on August 19, 2025).
10.2	Transition Agreement, dated August 18, 2025, by and between Black Hills Corporation and Linden R. Evans (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on August 19, 2025).
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes - Oxley Act of 2002.
95*	Mine Safety and Health Administration Safety Data.
101.INS*	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	Inline XBRL Taxonomy Extension Schema with Embedded Linkbase Documents
104*	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

Table of Contents

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.

BLACK HILLS CORPORATION


		/s/ Linden R. Evans
		Linden R. Evans, President and
		Chief Executive Officer

		/s/ Kimberly F. Nooney
		Kimberly F. Nooney, Senior Vice President and
		Chief Financial Officer

Dated:	November 6, 2025