10-Q

Large Accelerated Filer

Accelerated Filer

Non-accelerated Filer

Smaller Reporting Company

Emerging Growth Company

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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 March 31, 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 May 5, 2025
Common stock, $1.00 par value	72,509,377	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	14
	Note 1. Management’s Statement	14
	Note 2. Regulatory Matters	15
	Note 3. Commitments, Contingencies and Guarantees	16
	Note 4. Revenue	16
	Note 5. Financing	18
	Note 6. Earnings Per Share	19
	Note 7. Risk Management and Derivatives	19
	Note 8. Fair Value Measurements	22
	Note 9. Other Comprehensive Income	24
	Note 10. Employee Benefit Plans	25
	Note 11. Income Taxes	25
	Note 12. Business Segment Information	26
	Note 13. Selected Balance Sheet Information	28
	Note 14. Subsequent Events	28

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
	Executive Summary	29
	Recent Developments	29
	Results of Operations	30
	Consolidated Summary and Overview	30
	Non-GAAP Financial Measure	31
	Electric Utilities	32
	Gas Utilities	35
	Corporate and Other	36
	Consolidated Interest Expense, Other Income and Income Tax Expense	36
	Liquidity and Capital Resources	37
	Cash Flow Activities	38
	Capital Resources	39
	Credit Ratings	39
	Capital Requirements	40
	Critical Accounting Estimates	40
	New Accounting Pronouncements	40

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.	Controls and Procedures	40

PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	41
Item 1A.	Risk Factors	41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 4.	Mine Safety Disclosures	41
Item 5.	Other Information	41
Item 6.	Exhibits	41

Signatures		42

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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
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
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).

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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)
FASB	Financial Accounting Standards Board
Fitch	Fitch Ratings Inc.
GAAP	Accounting principles generally accepted in the United States of America
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.
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
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
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 be completed by the second half of 2026. The fast-start, dispatchable generation will be comprised of six reciprocating internal combustion engines, with technology to support strong system resiliency, including crucial black start capability to respond quickly to electric load changes. The addition of these resources will replace aging gas-fired and diesel resources planned for retirement in 2027 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.

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MMBtu	Million British thermal units
Moody's	Moody's Investors Service, Inc.
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).
NPSC	Nebraska Public Service Commission
OCI	Other Comprehensive Income
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, 2029. 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
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.
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 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%.

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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; 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 March 31,
	2025			2024
	(in millions, except per share amounts)
Revenue	$	805.2		$	726.4

Operating expenses:
Fuel, purchased power and cost of natural gas sold		359.7			316.6
Operations and maintenance		153.7			133.6
Depreciation and amortization		69.2			65.9
Taxes other than income taxes		17.6			17.0
Total operating expenses		600.2			533.1

Operating income		205.0			193.3

Other income (expense):
Interest expense incurred net of amounts capitalized		(51.7	)		(46.0	)
Interest income		0.4			2.0
Other income (expense), net		0.8			(0.8	)
Total other (expense)		(50.5	)		(44.8	)

Income before income taxes		154.5			148.5
Income tax (expense)		(18.1	)		(16.9	)
Net income		136.4			131.6
Net income attributable to non-controlling interest		(2.1	)		(3.7	)
Net income available for common stock	$	134.3		$	127.9

Earnings per share of common stock:
Earnings per share, Basic	$	1.87		$	1.88
Earnings per share, Diluted	$	1.87		$	1.87

Weighted average common shares outstanding:
Basic		71.6			68.2
Diluted		71.8			68.3

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 March 31,
	2025			2024
	(in millions)
Net income	$	136.4		$	131.6

Other comprehensive income (loss), net of tax;
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) and $(0.1), respectively)		0.6			0.6
Net unrealized gains (losses) on commodity derivatives (net of tax of $0.0 and $0.0, respectively)		0.1			(0.1	)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $(0.1) and $(0.6), respectively)		0.3			2.0
Other comprehensive income, net of tax		1.0			2.5

Comprehensive income		137.4			134.1
Less: comprehensive income attributable to non-controlling interest		(2.1	)		(3.7	)
Comprehensive income available for common stock	$	135.3		$	130.4

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
	March 31, 2025			December 31, 2024
	(in millions)
ASSETS
Current assets:
Cash and cash equivalents	$	6.6		$	16.1
Restricted cash and equivalents		7.5			7.3
Accounts receivable, net		377.9			351.2
Materials, supplies and fuel		128.1			153.9
Derivative assets, current		0.1			-
Income tax receivable, net		19.7			19.8
Regulatory assets, current		129.3			154.8
Other current assets		38.9			39.2
Total current assets		708.1			742.3

Property, plant and equipment		9,714.6			9,566.5
Less: accumulated depreciation		(1,992.6	)		(1,936.6	)
Total property, plant and equipment, net		7,722.0			7,629.9

Other assets:
Goodwill		1,299.5			1,299.5
Intangible assets, net		7.3			7.6
Regulatory assets, non-current		252.3			272.9
Other assets, non-current		72.0			70.4
Total other assets, non-current		1,631.1			1,650.4

TOTAL ASSETS	$	10,061.2		$	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
	March 31, 2025			December 31, 2024
	(in millions)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	216.8		$	229.1
Accrued liabilities		253.2			302.2
Derivative liabilities, current		—			4.2
Regulatory liabilities, current		99.0			94.1
Notes payable		59.9			133.8
Current maturities of long-term debt		300.0			—
Total current liabilities		928.9			763.4

Long-term debt, net of current maturities		3,951.6			4,250.2

Deferred credits and other liabilities:
Deferred income tax liabilities, net		666.5			625.1
Regulatory liabilities, non-current		475.2			474.6
Benefit plan liabilities		122.3			122.9
Other deferred credits and other liabilities		199.6			201.2
Total deferred credits and other liabilities		1,463.6			1,423.8

Commitments, contingencies and guarantees (Note 3)

Equity:
Stockholder's equity -
Common stock $1 par value; 100,000,000 shares authorized; issued 72,544,232 and 71,676,756 shares, respectively		72.5			71.7
Additional paid-in capital		2,238.2			2,193.4
Retained earnings		1,334.8			1,249.1
Treasury stock, at cost - 34,120 and 56,608 shares, respectively		(2.0	)		(3.3	)
Accumulated other comprehensive income (loss)		(8.4	)		(9.4	)
Total stockholders' equity		3,635.1			3,501.5
Non-controlling interest		82.0			83.7
Total equity		3,717.1			3,585.2

TOTAL LIABILITIES AND TOTAL EQUITY	$	10,061.2		$	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)	Three Months Ended March 31,
	2025			2024
Operating activities:	(in millions)
Net income	$	136.4		$	131.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		69.2			65.9
Deferred financing cost amortization		2.4			2.7
Stock compensation		2.6			2.4
Deferred income taxes		33.2			16.7
Employee benefit plans		2.2			3.0
Other adjustments, net		3.3			(0.3	)
Changes in certain operating assets and liabilities:
Materials, supplies and fuel		25.3			30.4
Accounts receivable and other current assets		(42.6	)		(11.3	)
Accounts payable and other current liabilities		(56.0	)		(59.6	)
Regulatory assets		52.6			54.8
Other operating activities, net		(0.8	)		(2.9	)
Net cash provided by operating activities		227.8			233.4

Investing activities:
Property, plant and equipment additions		(152.9	)		(176.2	)
Other investing activities		(2.3	)		(0.7	)
Net cash (used in) investing activities		(155.2	)		(176.9	)

Financing activities:
Dividends paid on common stock		(48.6	)		(44.4	)
Common stock issued		45.6			31.2
Net borrowings (payments) of Revolving Credit Facility and CP Program		(73.9	)		—
Distributions to non-controlling interests		(3.8	)		(5.6	)
Other financing activities		(1.2	)		(1.0	)
Net cash (used in) financing activities		(81.9	)		(19.8	)

Net change in cash, restricted cash and cash equivalents		(9.3	)		36.7

Cash, restricted cash, and cash equivalents beginning of period		23.4			93.0
Cash, restricted cash, and cash equivalents end of period	$	14.1		$	129.7

Supplemental cash flow information:
Cash (paid) received during the period:
Interest (net of amounts capitalized)	$	(48.8	)	$	(33.6	)
Income taxes, net of transferred tax credits (Note 11)		15.2			-
Non-cash investing and financing activities:
Accrued property, plant, and equipment purchases at March 31,		86.8			37.7

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


(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

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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 March 31, 2025, December 31, 2024, and March 31, 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, with early adoption permitted. We are currently evaluating the impact of ASU 2023-09 on our consolidated financial statement disclosures.

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 currently evaluating the impact of these standards on our consolidated financial statement disclosures.

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(2)

Regulatory Matters

We had the following regulatory assets and liabilities:


	As of			As of
	March 31, 2025			December 31, 2024
	(in millions)
Regulatory assets
Winter Storm Uri	$	72.1		$	109.5
Deferred energy and fuel cost adjustments		69.6			62.8
Deferred gas cost adjustments		3.1			14.5
Gas price derivatives		—			2.9
Deferred taxes on AFUDC		8.5			8.0
Employee benefit plans and related deferred taxes		87.8			89.0
Environmental		10.7			10.7
Loss on reacquired debt		15.3			15.7
Deferred taxes on flow through accounting		91.8			87.7
Decommissioning costs		2.4			2.4
Other regulatory assets		20.3			24.5
Total regulatory assets		381.6			427.7
Less current regulatory assets		(129.3	)		(154.8	)
Regulatory assets, non-current	$	252.3		$	272.9

Regulatory liabilities
Deferred energy and gas costs	$	70.5		$	67.8
Employee benefit plan costs and related deferred taxes		36.1			36.7
Cost of removal		200.4			197.0
Excess deferred income taxes		235.5			238.5
Colorado renewable energy (a)		27.0			24.1
Other regulatory liabilities		4.7			4.6
Total regulatory liabilities		574.2			568.7
Less current regulatory liabilities		(99.0	)		(94.1	)
Regulatory liabilities, non-current	$	475.2		$	474.6

(a)

Represents Colorado Electric's RESA and CEPR mechanisms, which allow for recovery/repayment of costs, but not a rate of return. Through these mechanisms, which are authorized by the CPUC, Colorado Electric is allowed to charge its retail customers an incremental rate limited to 1.5% per mechanism that provides funding for various renewable energy projects and programs to comply with requirements under the State of Colorado’s emissions reduction legislation. Project costs that are over-recovered through customer rates will be refunded to customers in future periods.

Regulatory Activity

Colorado Electric

On June 14, 2024, Colorado Electric filed a rate review with the CPUC seeking recovery of significant 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 is 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 to approximately $17.5 million.

Iowa Gas

On May 1, 2024, Iowa Gas filed a rate review with the IUC seeking recovery of significant infrastructure investments in its 5,000-mile natural gas pipeline system. On December 2, 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 significant infrastructure investments in its 4,765-mile natural gas pipeline system. The rate review requests $17.2 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 10.5%. The request seeks to implement new rates in the second half of 2025.

Nebraska Gas

On May 1, 2025, Nebraska Gas filed a rate review with the NPSC seeking recovery of significant infrastructure investments in its 12,900-mile natural gas pipeline system. The rate review requests $34.9 million in new annual revenue with a capital structure of 51% equity and 49% debt and a return on equity of 10.5%. Nebraska statute allows for implementation of interim rates 90 days after filing a rate review. New rates are expected to be effective in the first quarter of 2026.

(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.

(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 months ended March 31, 2025, and 2024. Sales tax and other similar taxes are excluded from revenues.


Three Months Ended March 31, 2025	Electric Utilities		Gas Utilities		Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	191.3	$	499.7	$	—		$	691.0
Transportation		—		57.7		(0.1	)		57.6
Wholesale		7.1		—		—			7.1
Market - off-system sales		11.3		—		—			11.3
Transmission		12.1		0.2		—			12.3
Other revenues		13.8		11.1		(3.8	)		21.1
Revenue from contracts with customers	$	235.6	$	568.7	$	(3.9	)	$	800.4
Alternative revenue and other		1.1		3.7		—			4.8
Total revenues	$	236.7	$	572.4	$	(3.9	)	$	805.2

Timing of revenue recognition:
Services transferred at a point in time	$	8.1	$	—	$	—		$	8.1
Services transferred over time		227.5		568.7		(3.9	)		792.3
Revenue from contracts with customers	$	235.6	$	568.7	$	(3.9	)	$	800.4

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Three Months Ended March 31, 2024	Electric Utilities		Gas Utilities		Inter-segment Eliminations			Total
Customer types:	(in millions)
Retail	$	179.6	$	437.4	$	—		$	617.0
Transportation		—		51.7		(0.1	)		51.6
Wholesale		8.5		—		—			8.5
Market - off-system sales		6.6		—		—			6.6
Transmission		12.7		0.3		—			13.0
Other revenues		14.0		10.9		(4.4	)		20.5
Revenue from contracts with customers	$	221.4	$	500.3	$	(4.5	)	$	717.2
Alternative revenue and other		0.8		8.4		—			9.2
Total revenues	$	222.2	$	508.7	$	(4.5	)	$	726.4

Timing of revenue recognition:
Services transferred at a point in time	$	8.7	$	—	$	—		$	8.7
Services transferred over time		212.7		500.3		(4.5	)		708.5
Revenue from contracts with customers	$	221.4	$	500.3	$	(4.5	)	$	717.2

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(5)

Financing

Short-term Debt

Revolving Credit Facility and CP Program

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:


	March 31, 2025			December 31, 2024
	(dollars in millions)
Amount outstanding	$	59.9		$	133.8
Letters of credit (a)		3.5			3.5
Available capacity		686.6			612.7
Weighted average interest rates		4.61	%		4.74	%

(a)

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

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


	Three Months Ended March 31,
	2025			2024
	(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)	$	157.8		$	—
Average amount outstanding (based on daily outstanding balances)		92.3			—
Weighted average interest rates		4.60	%	N/A

Financial Covenants

Revolving Credit Facility

We were in compliance with all of our Revolving Credit Facility covenants as of March 31, 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 March 31, 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 March 31, 2025. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of March 31, 2025, Wyoming Electric's debt to capitalization ratio was 0.51 to 1.00.

Equity

At-the-Market Equity Offering Program

ATM activity was as follows:


	Three Months Ended March 31,
	2025		2024
	(in millions, except Average price per share amounts)
Proceeds, (net of issuance costs of $(0.5) and $(0.3), respectively)	$	45.7	$	31.2
Number of shares issued		0.8		0.6
Average price per share	$	60.44	$	52.51

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(6)

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 March 31,
	2025		2024
	(in millions, except per share amounts)
Net income available for common stock	$	134.3	$	127.9

Weighted average shares - basic		71.6		68.2
Dilutive effect of equity compensation		0.2		0.1
Weighted average shares - diluted		71.8		68.3

Net income available for common stock, per share - Diluted	$	1.87	$	1.87

The following securities were excluded from the diluted earnings per share computation because of their anti-dilutive nature:


	Three Months Ended March 31,
	2025		2024
	(in millions of shares)
Equity compensation		—		0.1
Restricted stock		—		—
Anti-dilutive shares excluded from computation of earnings per share		—		0.1

(7)

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.

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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.

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 during time frames ranging from April 2025 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:


	March 31, 2025				December 31, 2024
	Notional Amounts (MMBtus)			Maximum Term (months) (a)	Notional Amounts (MMBtus)		Maximum Term (months) (a)
Natural gas futures purchased		-		N/A		660,000	3
Natural gas options purchased, net		-		N/A		2,780,000	3
Natural gas basis swaps purchased		-		N/A		1,080,000	3
Natural gas over-the-counter swaps, net (b)		2,350,000		32		3,480,000	20
Natural gas physical contracts, net (c)		(968,990	)	12		20,276,230	10

(a)

Term reflects the maximum forward period hedged.

(b)

As of March 31, 2025, 549,000 MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.

(c)

Volumes exclude derivative contracts that qualify for the normal purchases and normal sales exception permitted by 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 March 31, 2025, the Company posted $0.1 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets.

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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	March 31, 2025		December 31, 2024
		(in millions)
Derivatives designated as hedges:
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	$	—	$	(0.7	)
Total derivatives designated as hedges		$	—	$	(0.7	)

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets, current	$	0.1	$	—
Noncurrent commodity derivatives	Other assets, non-current		0.1		—
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities, current	$	—	$	(3.5	)
Total derivatives not designated as hedges		$	0.2	$	(3.5	)

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 months ended March 31, 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 March 31,					Three Months Ended March 31,
	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	$	0.8	$	0.7	Interest expense	$	(0.8	)	$	(0.7	)
Commodity derivatives		0.5		2.4	Fuel, purchased power, and cost of natural gas sold		(0.4	)		(2.6	)
Total	$	1.3	$	3.1		$	(1.2	)	$	(3.3	)

As of March 31, 2025, $2.7 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 months ended March 31, 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 March 31,
		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	$	1.1	$	0.6
		$	1.1	$	0.6

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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. There were no net unrealized gains or losses included in our Regulatory liability or asset accounts related to these financial instruments as of March 31, 2025. The net unrealized losses included in our Regulatory asset accounts related to these financial instruments were $2.9 million as of December 31, 2024.

(8)

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.

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 March 31, 2025
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)		Total
	(in millions)
Assets:
Commodity derivatives - Gas Utilities	$	—	$	0.2	$	—	$	—	$	0.2
Total	$	—	$	0.2	$	—	$	—	$	0.2

(a)

As of March 31, 2025, we had no commodity derivative or liabilities, or related gross collateral amounts, that were subject to master netting agreements.

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	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:


	March 31, 2025				December 31, 2024
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(in millions)
Long-term debt, including current maturities (a)	$	4,251.6	$	4,097.8	$	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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(9)

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 March 31,
	Location on the Consolidated Statements of Income	2025			2024
		(in millions)
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(0.8	)	$	(0.7	)
Commodity contracts	Fuel, purchased power, and cost of natural gas sold		(0.4	)		(2.6	)
		$	(1.2	)	$	(3.3	)
Income tax	Income tax expense		0.3			0.7
Total reclassification adjustments related to cash flow hedges, net of tax		$	(0.9	)	$	(2.6	)
Total reclassifications		$	(0.9	)	$	(2.6	)

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		—			0.1			—			0.1
Amounts reclassified from AOCI		0.6			0.3			—			0.9
As of March 31, 2025	$	(3.2	)	$	0.1		$	(5.3	)	$	(8.4	)


	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		0.6			2.0			—			2.6
As of March 31, 2024	$	(5.5	)	$	(0.6	)	$	(6.2	)	$	(12.3	)

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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 March 31,	2025			2024			2025		2024		2025			2024
	(in millions)
Service cost	$	0.4		$	0.6		$	0.2	$	1.0	$	0.4		$	0.4
Interest cost		4.0			4.1			0.3		0.3		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 (benefit)	$	0.7		$	0.7		$	0.5	$	1.3	$	1.0		$	1.0

Plan Contributions

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


	Contributions Made		Additional Contributions
	Three Months Ended March 31, 2025		Anticipated for 2025
	(in millions)
Defined Benefit Pension Plan	$	—	$	1.8
Non-pension Defined Benefit Postretirement Healthcare Plan		1.2		3.5
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans		0.7		2.1

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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.

Income Tax (Expense) and Effective Tax Rates

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024

Income tax (expense) for the three months ended March 31, 2025, was $(18.1) million compared to $(16.9) million reported for the same period in 2024. For the three months ended March 31, 2025, the effective tax rate was 11.7%, 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.

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 March 31, 2025	Electric Utilities		Gas Utilities		Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	234.3	$	570.9	$	—		$	805.2
Inter-segment		2.4		1.5		(3.9	)		—
Total revenue		236.7		572.4		(3.9	)		805.2

Fuel, purchased power and cost of natural gas sold		67.2		292.6		(0.1	)		359.7
Operations and maintenance (a) -
Direct		35.7		44.1		(3.0	)		76.8
Allocated		33.1		43.8		—			76.9
Depreciation and amortization		37.1		32.1		—			69.2
Taxes other than income taxes		9.3		8.3		—			17.6
Operating income (loss)	$	54.3	$	151.5	$	(0.8	)	$	205.0

Interest expense, net									(51.3	)
Other income (expense), net									0.8
Income tax (expense)									(18.1	)
Net income									136.4
Net income attributable to non-controlling interest									(2.1	)
Net income available for common stock								$	134.3

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	Consolidating Income Statement
Three Months Ended March 31, 2024	Electric Utilities		Gas Utilities		Corporate and Other			Total
	(in millions)
Revenue -
External Customers	$	219.3	$	507.1	$	—		$	726.4
Inter-segment		2.9		1.6		(4.5	)		—
Total revenue		222.2		508.7		(4.5	)		726.4

Fuel, purchased power and cost of natural gas sold		54.8		261.9		(0.1	)		316.6
Operations and maintenance (a) -
Direct		27.5		38.1		(2.5	)		63.1
Allocated		30.0		40.5		—			70.5
Depreciation and amortization		35.3		30.4		0.2			65.9
Taxes other than income taxes		10.0		7.0		—			17.0
Operating income (loss)	$	64.6	$	130.8	$	(2.1	)	$	193.3

Interest expense, net									(44.0	)
Other income (expense), net									(0.8	)
Income tax (expense)									(16.9	)
Net income									131.6
Net income attributable to non-controlling interest									(3.7	)
Net income available for common stock								$	127.9

(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.


Capital Expenditures (a) for the three months ended March 31,	2025		2024
	(in millions)
Electric Utilities	$	102.1	$	86.9
Gas Utilities		59.0		85.0
Corporate and Other		1.3		2.4
Total capital expenditures	$	162.4	$	174.3

(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.

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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:


	March 31, 2025			December 31, 2024
	(in millions)
Billed Accounts Receivable	$	263.6		$	201.5
Unbilled Revenue		119.2			151.8
Less: Allowance for Credit Losses		(4.9	)		(2.1	)
Account Receivable, net	$	377.9		$	351.2

Changes to allowance for credit losses for the three months ended March 31, 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 March 31,
	(in millions)
2025	$	2.1	$	3.4	$	0.9	$	(1.5	)	$	4.9
2024	$	2.2	$	2.0	$	1.1	$	(1.4	)	$	3.9

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:


	March 31, 2025		December 31, 2024
	(in millions)
Materials and supplies	$	108.9	$	106.1
Fuel - Electric Utilities		6.7		7.5
Natural gas in storage		12.5		40.3
Total materials, supplies, and fuel	$	128.1	$	153.9

Accrued Liabilities

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


	March 31, 2025		December 31, 2024
	(in millions)
Accrued employee compensation, benefits, and withholdings	$	58.6	$	85.5
Accrued property taxes		57.0		54.7
Customer deposits and prepayments		41.0		55.6
Accrued interest		55.7		56.4
Other (none of which is individually significant)		40.9		50.0
Total accrued liabilities	$	253.2	$	302.2

(14) Subsequent Events

Except as described in Note 2, there have been no events subsequent to March 31, 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 ourself 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

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 (HB192), 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 reasonableness and prudency for compliance with an approved wildfire mitigation plan.

•

On February 12, 2025, Wyoming Electric set a new all-time and winter peak load of 344 MW, surpassing the previous all-time and winter peak of 318 MW set on January 20, 2025. Prior to 2025, the previous all-time and winter peak was 314 MW set on January 11, 2024.

•

During the first quarter of 2025, Wyoming Electric continued construction of its approximately 260-mile, $350 million Ready Wyoming electric transmission expansion project, which is expected to be completed and in service by year-end 2025. Wyoming Electric has procured all required regulatory approvals and land rights-of-way and is constructing the project in multiple segments. The first 12-mile transmission line segment and two substations near Cheyenne, Wyoming, were completed and energized in 2024, adding approximately $40 million of rate base being recovered through the TCAM.

•

During the first quarter of 2025, South Dakota Electric continued its Lange II construction project, which is planned to be in-service by the second half of 2026. On March 28, 2025, South Dakota Electric filed a request with the WPSC for the Lange II project.

•

During the first quarter of 2025, Colorado Electric continued to pursue the addition of 350 MW of new renewable generation resources in support of its Clean Energy Plan. In 2024, the CPUC approved the addition of a 100-MW utility-owned solar project, 50-MW utility-owned battery storage project and a 200-MW solar PPA. Colorado Electric plans to file a CPCN for the battery storage project by mid-2025. Negotiations with counterparties for the other two projects are ongoing, which will drive final cost and timing of projects.

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.

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Corporate and Other

•

See Note 5 of the Condensed Notes to Consolidated Financial Statements for ATM program activity.

•

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 months ended March 31, 2025, and 2024, and our financial condition as of March 31, 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.

Consolidated Summary and Overview


	Three Months Ended March 31,
	2025			2024			2025 vs 2024 Variance
	(in millions, except per share amounts)
Operating income (loss):
Electric Utilities	$	54.3		$	64.6		$	(10.3	)
Gas Utilities		151.5			130.8			20.7
Corporate and Other (a)		(0.8	)		(2.1	)		1.3
Operating income		205.0			193.3			11.7

Interest expense, net		(51.3	)		(44.0	)		(7.3	)
Other income (expense), net		0.8			(0.8	)		1.6
Income tax (expense)		(18.1	)		(16.9	)		(1.2	)
Net income		136.4			131.6			4.8
Net income attributable to non-controlling interest		(2.1	)		(3.7	)		1.6
Net income available for common stock	$	134.3		$	127.9		$	6.4

Weighted average common shares outstanding, Diluted		71.8			68.3			3.5
Total earnings per share of common stock, Diluted	$	1.87		$	1.87		$	0.00

(a)

Includes inter-segment eliminations.

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024:

The variance to the prior year included the following:

•

Electric Utilities’ operating income decreased $10.3 million primarily due to higher operating expenses and current year unplanned generation outages;

•

Gas Utilities’ operating income increased $20.7 million primarily due to new rates and rider recovery driven by the Arkansas Gas and Colorado Gas rate reviews and favorable winter heating season weather partially offset by higher operating expenses;

•

Interest expense increased $7.3 million primarily due to higher interest rates and lower interest income on lower cash and cash equivalents balances; and

•

Net income attributable to non-controlling interest decreased $1.6 million due to lower net income from Black Hills Colorado IPP primarily driven by unplanned generation outages.

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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 March 31,
	2025			2024			2025			2024
	(in millions)
Revenue	$	236.7		$	222.2		$	572.4		$	508.7
Fuel, purchased power and cost of natural gas sold		(67.2	)		(54.8	)		(292.6	)		(261.9	)
Operations and maintenance (a)		(41.9	)		(36.0	)		(46.2	)		(42.8	)
Depreciation and amortization		(37.1	)		(35.3	)		(32.1	)		(30.4	)
Taxes other than income taxes		(9.3	)		(10.0	)		(8.3	)		(7.0	)
Gross margin (GAAP)	$	81.2		$	86.1		$	193.2		$	166.6
Operations and maintenance (a)		41.9			36.0			46.2			42.8
Depreciation and amortization		37.1			35.3			32.1			30.4
Taxes other than income taxes		9.3			10.0			8.3			7.0
Electric and Gas Utility margin (non-GAAP)	$	169.5		$	167.4		$	279.8		$	246.8

(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 $26.9 million and $21.5 million for the three months ended March 31, 2025 and 2024, respectively, for the Electric Utilities and $41.7 and $35.8 million for the three months ended 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 March 31,
	2025		2024		2025 vs 2024 Variance
	(in millions)
Revenue	$	236.7	$	222.2	$	14.5
Fuel and purchased power		67.2		54.8		12.4
Electric Utility margin (non-GAAP) (a)		169.5		167.4		2.1

Operations and maintenance		68.8		57.5		11.3
Depreciation and amortization		37.1		35.3		1.8
Taxes other than income taxes		9.3		10.0		(0.7	)
		115.2		102.8		12.4

Operating income	$	54.3	$	64.6	$	(10.3	)

(a)

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

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024:

Electric Utility margin increased as a result of the following:


	(in millions)
Retail customer growth and usage	$	2.6
New rates and rider recovery		1.4
Weather		1.2
Unplanned generation outages		(1.1	)
Off-system excess energy sales		(1.1	)
Other		(0.9	)
	$	2.1

Operations and maintenance expense increased primarily due to $2.8 million of expenses related to unplanned generation outages, $2.8 million of higher outside services expenses; $1.9 million of higher employee-related expenses and $1.3 million of higher insurance expense.

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.

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Operating Statistics


	Revenue				Quantities Sold
	Three Months Ended March 31,				Three Months Ended March 31,
	2025		2024		2025		2024
	(in millions)				(in GWh)
Retail Revenue -
Residential	$	66.4	$	62.5		406.4		388.8
Commercial		68.8		65.9		517.2		511.8
Industrial		48.2		43.5		609.8		553.6
Municipal		4.5		4.3		34.6		34.2
Other Retail		3.4		3.5		—		—
Subtotal Retail Revenue - Electric		191.3		179.7		1,568.0		1,488.4
Wholesale		7.1		8.5		147.8		176.0
Market - off-system sales		11.3		6.6		173.6		115.6
Transmission		12.1		12.6		—		—
Other (a)		14.9		14.8		—		—
Total Revenue and Quantities Sold	$	236.7	$	222.2		1,889.4		1,780.0
Other Uses, Losses, or Generation, net (b)						94.1		101.8
Total Energy						1,983.5		1,881.8

(a)

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

(b)

Includes company uses and line losses.


	Revenue				Quantities Sold
	Three Months Ended March 31,				Three Months Ended March 31,
	2025		2024		2025		2024
	(in millions)				(in GWh)
Colorado Electric	$	72.4	$	69.7		532.3		555.7
South Dakota Electric		86.9		80.6		682.0		621.1
Wyoming Electric		66.6		60.8		645.8		575.2
Integrated Generation		10.8		11.1		29.3		28.0
Total Revenue and Quantities Sold	$	236.7	$	222.2		1,889.4		1,780.0


	Three Months Ended March 31,
Quantities Generated and Purchased by Fuel Type	2025		2024
	(in GWh)
Generated:
Coal (a)		599.9		680.7
Natural Gas and Oil		512.1		523.4
Wind		175.4		174.0
Total Generated		1,287.4		1,378.1
Purchased:
Coal, Natural Gas, Oil, and Other Market Purchases (a)		375.7		288.9
Wind and Solar (b)		320.4		214.8
Total Purchased		696.1		503.7

Total Generated and Purchased		1,983.5		1,881.8

(a)

The shift between coal generation and coal, natural gas, oil and other market purchases for the three months ended March 31, 2025 compared to the same period in 2024 was primarily due to unplanned outages at Wygen III.

(b)

The increase in wind and solar GWh purchased for the three months ended March 31, 2025, compared to the same period in 2024 was primarily due to a new solar PPA. In 2022, Wyoming Electric entered into a new solar PPA with third party to purchase up to 150 MW of solar energy, upon construction of new renewable generation facility (owned by third party). The solar facility was placed in service in March 2024. The renewable energy from the PPA is used to serve our expanding partnerships with LPCS customers.

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	Three Months Ended March 31,
Quantities Generated and Purchased	2025		2024
	(in GWh)
Generated:
Colorado Electric		184.3		161.6
South Dakota Electric (a)		478.9		534.6
Wyoming Electric		219.3		215.2
Integrated Generation		404.9		466.7
Total Generated		1,287.4		1,378.1
Purchased:
Colorado Electric		90.2		90.2
South Dakota Electric (a)		211.3		100.6
Wyoming Electric (b)		376.1		295.7
Integrated Generation		18.5		17.2
Total Purchased		696.1		503.7

Total Generated and Purchased		1,983.5		1,881.8

(a)

The shift between South Dakota Electric's generated and purchased GWh for the three months ended March 31, 2025, compared to the same period in 2024 is primarily due to 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 its solar PPA from the facility that was placed in service in March 2024.


	Three Months Ended March 31,
	2025		2024
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal
Colorado Electric	2,733	9%	2,507	(6)%
South Dakota Electric	3,438	5%	3,134	(9)%
Wyoming Electric	3,140	5%	2,986	(5)%
Combined (a)	3,060	7%	2,820	(7)%

(a)

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


	Three Months Ended March 31,
Contracted generating facilities Availability(a) by fuel type	2025	2024
Coal (b)	86.3%	95.6%
Natural gas and diesel oil (b)	91.6%	96.7%
Wind (b)	86.3%	90.3%
Total Availability	89.3%	95.5%

Wind Capacity Factor (a)	40.0%	39.8%

(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.

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Gas Utilities

Operating results for the Gas Utilities were as follows:


	Three Months Ended March 31,
	2025		2024		2025 vs 2024 Variance
	(in millions)
Revenue	$	572.4	$	508.7	$	63.7
Cost of natural gas sold		292.6		261.9		30.7
Gas Utility margin (non-GAAP) (a)		279.8		246.8		33.0

Operations and maintenance		87.9		78.6		9.3
Depreciation and amortization		32.1		30.4		1.7
Taxes other than income taxes		8.3		7.0		1.3
		128.3		116.0		12.3

Operating income	$	151.5	$	130.8	$	20.7

(a)

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

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024:

Gas Utility margin increased as a result of the following:


	(in millions)
New rates and rider recovery	$	21.5
Weather		8.7
Transport and transmission		3.0
Mark-to-market on non-utility natural gas commodity contracts		0.6
Other		(0.8	)
	$	33.0

Operations and maintenance expense increased primarily due to $4.1 million of higher employee related expenses, $1.8 million of higher insurance expense, and $1.4 million of higher bad debt expense driven by increased revenues.

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.

Operating Statistics


	Revenue				Quantities Sold and Transported
	Three Months Ended March 31,				Three Months Ended March 31,
	2025		2024		2025		2024
	(in millions)				(Dth in millions)
Retail Revenue -
Residential	$	344.1	$	297.8		30.7		27.8
Commercial		134.3		118.5		14.0		13.0
Industrial		6.6		5.1		1.0		0.9
Other Retail (a)		14.7		16.0		—		—
Subtotal Retail Revenue - Gas		499.7		437.4		45.7		41.7
Transportation		57.7		51.7		50.4		46.7
Other (b)		15.0		19.6		—		—
Total Revenue and Quantities Sold	$	572.4	$	508.7		96.1		88.4

(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.

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	Revenue				Quantities Sold and Transported
	Three Months Ended March 31,				Three Months Ended March 31,
	2025		2024		2025		2024
	(in millions)				(Dth in millions)
Arkansas Gas	$	124.8	$	110.7		13.2		12.0
Colorado Gas		115.8		117.7		13.2		12.9
Iowa Gas		86.8		61.8		15.2		13.5
Kansas Gas		66.1		50.3		11.7		9.7
Nebraska Gas		130.2		114.3		29.6		27.1
Wyoming Gas		48.7		53.9		13.2		13.2
Total Revenue and Quantities Sold	$	572.4	$	508.7		96.1		88.4


	Three Months Ended March 31,
	2025		2024
Heating Degree Days	Actual	Variance from Normal	Actual	Variance from Normal
Arkansas Gas (a)	1,957	2%	1,772	(12)%
Colorado Gas	2,837	2%	2,743	(3)%
Iowa Gas	3,288	(1)%	2,898	(16)%
Kansas Gas (a)	2,616	10%	2,291	(7)%
Nebraska Gas	3,039	2%	2,802	(9)%
Wyoming Gas	3,323	3%	3,156	(3)%
Combined (b)	3,082	1%	2,865	(8)%

(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 March 31,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Operating income (loss)	$	(0.8	)	$	(2.1	)	$	1.3

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024:

Operating loss was comparable to the same period in the prior year.

Consolidated Interest Expense, Other Income and Income Tax Expense


	Three Months Ended March 31,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Interest expense, net	$	(51.3	)	$	(44.0	)	$	(7.3	)
Other income (expense), net		0.8			(0.8	)		1.6
Income tax (expense)		(18.1	)		(16.9	)		(1.2	)

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Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024:

Interest expense, net increased primarily due to higher interest rates and lower interest income on lower cash and cash equivalents balances.

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 March 31, 2025, the effective tax rate was 11.7%, 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:


	March 31, 2025			December 31, 2024
	(dollars in millions)
Cash and cash equivalents	$	6.6		$	16.1
Available capacity under Revolving Credit Facility and CP Program (a)		686.6			612.7
Available liquidity	$	693.2		$	628.8

Capital structure
Short-term debt	$	359.9		$	133.8
Long-term debt		3,951.6			4,250.2
Total debt		4,311.5			4,384.0
Total stockholders' equity (excludes non-controlling interest)		3,635.1			3,501.5
Total capitalization	$	7,946.6		$	7,885.5

Debt to capitalization		54.3	%		55.6	%
Long-term debt to total debt		91.7	%		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.

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 program or in an opportunistic block trade. In 2025, we plan to renew our Equity Distribution Sales Agreement, which allows us to sell shares of common stock, from time to time, through our ATM program utilizing our shelf registration statement. We also plan to re-finance our $300 million, 3.95%, senior unsecured notes due January 2026, at or before maturity date.

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CASH FLOW ACTIVITIES

The following tables summarize our cash flows for the three months ended March 31, 2025:

Operating Activities:


	Three Months Ended March 31,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Net income	$	136.4		$	131.6		$	4.8
Non-cash adjustments to Net income		112.9			90.4			22.5
Total earnings	$	249.3		$	222.0		$	27.3
Changes in certain operating assets and liabilities:
Materials, supplies and fuel, Accounts receivable and other current assets		(17.3	)		19.1			(36.4	)
Accounts payable and other current liabilities		(56.0	)		(59.6	)		3.6
Regulatory assets		52.6			54.8			(2.2	)
Net inflow (outflow) from changes in certain operating assets and liabilities	$	(20.7	)	$	14.3		$	(35.0	)
Other operating activities		(0.8	)		(2.9	)		2.1
Net cash provided by operating activities	$	227.8		$	233.4		$	(5.6	)

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024

Net cash provided by operating activities was $5.6 million lower than the same period in 2024. The variance to the prior year was primarily attributable to:

•

Total earnings (net income plus non-cash adjustments) were $27.3 million higher for the three months ended March 31, 2025, compared to the same period in the prior year primarily due the sale of our 2024 PTCs in January 2025.

•

Net outflows from changes in certain operating assets and liabilities were $35.0 million higher, primarily attributable to changes in materials, supplies, fuel, accounts receivable, and other current assets driven by fluctuations in commodity prices and weather conditions.

Investing Activities:


	Three Months Ended March 31,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Capital expenditures	$	(152.9	)	$	(176.2	)	$	23.3
Other investing activities		(2.3	)		(0.7	)		(1.6	)
Net cash (used in) investing activities	$	(155.2	)	$	(176.9	)	$	21.7

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024

Net cash used in investing activities was $21.7 million lower than the same period in 2024. The variance to the prior year was primarily attributable to lower capital expenditures which were primarily driven by timing of projects and the prior year Black Hills Energy Renewable Resources' acquisition of a RNG production facility at a landfill in Dubuque, Iowa.

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Financing Activities:


	Three Months Ended March 31,
	2025			2024			2025 vs 2024 Variance
	(in millions)
Dividends paid on common stock	$	(48.6	)	$	(44.4	)	$	(4.2	)
Common stock issued		45.6			31.2			14.4
Short-term and long-term debt borrowings (repayments), net		(73.9	)		-			(73.9	)
Distributions to non-controlling interests		(3.8	)		(5.6	)		1.8
Other financing activities		(1.2	)		(1.0	)		(0.2	)
Net cash (used in) financing activities	$	(81.9	)	$	(19.8	)	$	(62.1	)

Three Months Ended March 31, 2025, Compared to the Three Months Ended March 31, 2024

Net cash used in financing activities was $62.1 million higher than the same period in 2024. The variance to the prior year was primarily attributable to:

•

Cash outflows increased $73.9 million as a result of repayments of debt in excess of proceeds from debt offerings.

•

Cash inflows increased $14.4 million due to higher issuances of common stock; and

•

Cash outflows increased $4.2 million due to increased dividends paid on common stock.

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 May 9, 2024, S&P affirmed BBB+ rating and maintained a Stable outlook.

(b)

On March 5, 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

We have not had any triggering events (i.e. an acceleration of repayment of outstanding indebtedness, an increase in interest costs, or the posting of additional cash collateral) tied to our stock price and have not executed any transactions that require us to issue equity based on our credit ratings.

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CAPITAL REQUIREMENTS

Capital Expenditures


	Actual (a)		Forecasted (b)
Capital Expenditures by Segment (minor differences may result due to rounding)	Three Months Ended March 31, 2025		2025 (c)		2026		2027		2028		2029
	(in millions)
Electric Utilities	$	102	$	550	$	432	$	383	$	615	$	435
Gas Utilities		59		431		386		412		447		447
Corporate and Other		1		21		41		27		27		27
	$	162	$	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 three months ended March 31, 2025.

Common Stock Dividends

Dividends paid on our common stock totaled $48.6 million for the three months ended March 31, 2025, or $0.676 per share. On April 22, 2025, our board of directors declared a quarterly dividend of $0.676 per share payable June 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 March 31, 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 March 31, 2025. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, 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 March 31, 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 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.

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 March 31, 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
January 1, 2025 - January 31, 2025		1	$	58.56		—		—
February 1, 2025 - February 28, 2025		19,925		59.61		—		—
March 1, 2025 - March 31, 2025		1		61.16		—		—
Total		19,927	$	59.61		—		—

(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 March 31, 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
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)

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SIGNATURES

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

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:	May 8, 2025