Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2026
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File 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.
Large Accelerated Filer
x
Accelerated Filer
☐
Non-accelerated Filer
Smaller Reporting Company
Emerging Growth Company
If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes ☐ No ☒
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common stock of $1.00 par value
BKH
New York Stock Exchange
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 4, 2026
Common stock, $1.00 par value
76,128,592
shares
TABLE OF CONTENTS
Page
Glossary of Terms and Abbreviations
3
Forward-Looking Information
6
PART I. FINANCIAL INFORMATION
7
Item 1.
Financial Statements - unaudited
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
8
Consolidated Balance Sheets
9
Consolidated Statements of Cash Flows
11
Consolidated Statements of Equity
12
Condensed Notes to Consolidated Financial Statements
13
Note 1. Management’s Statement
Note 2. Regulatory Matters
14
Note 3. Commitments, Contingencies and Guarantees
15
Note 4. Revenue
16
Note 5. Financing
Note 6. Earnings Per Share
18
Note 7. Risk Management and Derivatives
Note 8. Fair Value Measurements
20
Note 9. Other Comprehensive Income
22
Note 10. Employee Benefit Plans
23
Note 11. Income Taxes
24
Note 12. Business Segment Information
Note 13. Selected Balance Sheet Information
26
Note 14. Pending Merger with NorthWestern
27
Note 15. Subsequent Events
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
28
Executive Summary
Recent Developments
Results of Operations
29
Consolidated Summary and Overview
Non-GAAP Financial Measure
30
Electric Utilities
31
Gas Utilities
34
Corporate and Other
35
Consolidated Interest Expense, Other Income and Income Tax Expense
Liquidity and Capital Resources
36
Cash Flow Activities
37
Capital Resources
38
Credit Ratings
Capital Requirements
39
Critical Accounting Estimates
New Accounting Pronouncements
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
Item 4.
Controls and Procedures
PART II. OTHER INFORMATION
Legal Proceedings
40
Item 1A.
Risk Factors
Unregistered Sales of Equity Securities and Use of Proceeds
Mine Safety Disclosures
Item 5.
Other Information
Item 6.
Exhibits
Signatures
41
2
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)
APSC
Arkansas Public Service Commission
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
BHC
Black Hills Corporation; the Company
BHSC
Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
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 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 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)
Blockchain Interruptible Service (BCIS) Tariff
A WPSC-approved tariff applicable to prospective new Wyoming Electric blockchain customers. The tariff allows customers to negotiate rates and terms and conditions for interruptible electric utility service of 10 MW or greater that would be interconnected with Wyoming Electric’s system. Agreements under the BCIS tariff must be filed with the WPSC prior to the first customer billing, be at least 2 years in duration and include specific pricing for all electricity purchased (with pricing terms subject to renegotiation every three years). BCIS customers shall not participate in the PCA to the extent of service received under the tariff.
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.
Colorado Electric
Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Parent Holdings, providing electric services to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas
Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Consolidated Indebtedness to Capitalization Ratio
Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day
A cooling degree day is equivalent to each degree that the average of the high and the low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
CP Program
Commercial Paper Program
CPUC
Colorado Public Utilities Commission
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
FASB
Financial Accounting Standards Board
FCC
Federal Communications Commission
FERC
Federal Energy Regulatory Commission
GAAP
Accounting principles generally accepted in the United States of America
GSRS
Gas System Reliability Surcharge is a monthly charge that recovers Kansas Gas's costs associated with pipeline safety and government-mandated projects.
GW
Gigawatts
GWh
Gigawatt Hours
Heating Degree Day
A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
HomeServe
We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
HSR Act
Hart-Scott-Rodino Antitrust Improvements Act of 1976
Integrated Generation
Non-regulated power generation and mining businesses (Black Hills Electric Generation and WRDC) that are vertically integrated within our Electric Utilities segment.
Iowa Gas
Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IRS
United States Internal Revenue Service
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 in service by the second half of 2026. The addition of these resources will replace generation facilities planned for retirement and support updated planning reserve margin requirements.
Large Power Contract Service (LPCS) Tariff
Wyoming Electric offers service under the LPCS tariff approved by the Wyoming Public Service Commission. The LPCS Tariff provides a cost-based rate structure for customers with very large electric loads, typically data centers or other high-demand facilities.This Tariff is designed to ensure that service to LPCS customers is fully self-supporting and does not shift costs to other customer classes.
Merger
Merger Sub merging with and into NorthWestern
Merger Agreement
The Agreement and Plan of Merger, dated August 18, 2025, by and among BHC, Merger Sub, and NorthWestern
Merger Sub
River Merger Sub Inc., a Delaware corporation and direct, wholly owned subsidiary of BHC
MMBtu
Million British thermal units
Moody's
Moody's Ratings
MPSC
Montana Public Service Commission
MW
Megawatts
MWh
Megawatt-hours
N/A
Not applicable
N/M
Not meaningful
4
Nebraska Gas
Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
NorthWestern
NorthWestern Energy Group, Inc., a Delaware corporation
NPSC
Nebraska Public Service Commission
OCI
Other Comprehensive Income
PPA
Power Purchase Agreement
PTC
Production Tax Credit
Ready Wyoming
A 260-mile, multi-phase transmission expansion project in Wyoming which was fully completed and placed in service in 2025. The project provides customers long-term price stability and greater flexibility as power markets develop in the western United States. This project is also expected to enable economic growth in Wyoming, expand access to renewable resources and facilitate additional renewable development across wind- and sun-rich resource areas.
Revolving Credit Facility
Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended on May 31, 2024, and will terminate on May 31, 2030. This facility includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment.
SDPUC
South Dakota Public Utilities Commission
SEC
United States Securities and Exchange Commission
Service Guard Comfort Plan
Appliance protection plan that provides home appliance repair services through ongoing 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).
SSIR
System Safety and Integrity Rider is a mechanism that allows us to recover the costs associated with certain pipeline safety and integrity investments, including the replacement of higher risk pipe, the improvement of the data management system, and the mitigation of other safety issues identified on our natural gas system.
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
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.
Wildfire Mitigation Plan (WMP)
Our three-layered approach to manage wildfire risks driven by asset-based risk assessments that include asset programs, integrity programs and operational response.
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%.
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).
5
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 2025 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:
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.
ITEM 1. FINANCIAL STATEMENTS
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(unaudited)
Three Months EndedMarch 31,
2026
2025
(in millions, except per share amounts)
Revenue
$
780.7
805.2
Operating expenses:
Fuel, purchased power and cost of natural gas sold
337.9
359.7
Operations and maintenance
148.0
153.7
Depreciation and amortization
74.8
69.2
Taxes other than income taxes
18.1
17.6
Total operating expenses
578.8
600.2
Operating income
201.9
205.0
Other income (expense):
Interest expense incurred net of amounts capitalized
(53.1
)
(51.7
Interest income
1.2
0.4
Other income, net
0.7
0.8
Total other (expense)
(51.2
(50.5
Income before income taxes
150.7
154.5
Income tax (expense)
(17.6
(18.1
Net income
133.1
136.4
Net income attributable to non-controlling interest
(2.1
Net income available for common stock
131.0
134.3
Earnings per share of common stock:
Earnings per share, Basic
1.74
1.87
Earnings per share, Diluted
1.73
Weighted average common shares outstanding:
Basic
75.4
71.6
Diluted
75.6
71.8
The accompanying Condensed Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)
Other comprehensive income (loss), net of tax;
Reclassification of benefit plan liability
0.1
-
Derivative instruments designated as cash flow hedges:
Reclassification of settled/amortized interest rate swaps
0.6
Unrealized gain on commodity derivatives
0.2
Reclassification of settled commodity derivatives
1.3
0.3
Other comprehensive income (loss), net of tax
2.2
1.0
Comprehensive income
135.3
137.4
Less: comprehensive income attributable to non-controlling interest
Comprehensive income available for common stock
133.2
See Note 9 for additional disclosures.
CONSOLIDATED BALANCE SHEETS
As of
March 31, 2026
December 31, 2025
ASSETS
Current assets:
Cash and cash equivalents
23.6
182.8
Restricted cash and equivalents
7.8
7.6
Accounts receivable, net
383.4
389.0
Materials, supplies and fuel
146.8
172.4
Income tax receivable, net
22.6
23.3
Regulatory assets, current
122.6
139.7
Other current assets
81.4
81.1
Total current assets
788.2
995.9
Property, plant and equipment
10,556.4
10,344.9
Less: accumulated depreciation
(2,162.6
(2,110.7
Total property, plant and equipment, net
8,393.8
8,234.2
Other assets:
Goodwill
1,299.5
Intangible assets, net
5.8
6.4
Regulatory assets, non-current
251.7
255.0
Other assets, non-current
81.0
78.8
Total other assets, non-current
1,638.0
1,639.7
TOTAL ASSETS
10,820.0
10,869.8
(Continued)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
210.8
311.7
Accrued liabilities
260.2
322.6
Derivative liabilities, current
1.8
Regulatory liabilities, current
85.9
99.9
Notes payable
252.2
—
Current maturities of long-term debt
410.0
Total current liabilities
1,220.9
740.0
Long-term debt, net of current maturities
3,992.5
4,701.1
Deferred credits and other liabilities:
Deferred income tax liabilities, net
736.6
697.9
Regulatory liabilities, non-current
490.2
488.3
Benefit plan liabilities
121.2
123.4
Other deferred credits and other liabilities
231.7
213.4
Total deferred credits and other liabilities
1,579.7
1,523.0
Commitments, contingencies and guarantees (Note 3)
Equity:
Stockholder's equity -
Common stock $1 par value; 100,000,000 shares authorized; issued 76,174,264 and 75,520,234 shares, respectively
76.2
75.5
Additional paid-in capital
2,459.4
2,417.5
Retained earnings
1,420.8
1,342.9
Treasury stock, at cost - 57,505 and 43,167 shares, respectively
(3.7
(2.6
Accumulated other comprehensive (loss)
(7.5
(9.7
Total stockholders' equity
3,945.2
3,823.6
Non-controlling interest
81.7
82.1
Total equity
4,026.9
3,905.7
TOTAL LIABILITIES AND TOTAL EQUITY
10
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended March 31,
Operating activities:
Adjustments to reconcile net income to net cash provided by operating activities:
Deferred financing cost amortization
2.5
2.4
Stock compensation
3.2
2.6
Deferred income taxes
31.8
33.2
Employee benefit plans
1.6
Other adjustments
1.4
3.3
Changes in certain operating assets and liabilities:
24.5
25.3
Accounts receivable and other current assets
20.5
(42.6
Accounts payable and other current liabilities
(119.3
(56.0
Regulatory assets
5.4
52.6
Other operating activities, net
(3.3
(0.8
Net cash provided by operating activities
176.2
227.8
Investing activities:
Property, plant and equipment additions
(267.4
(152.9
Other investing activities
(2.3
Net cash (used in) investing activities
(270.0
(155.2
Financing activities:
Dividends paid on common stock
(48.6
Common stock issued
40.7
45.6
Net borrowings (payments) of Revolving Credit Facility and CP Program
(73.9
Long-term debt - repayments
(300.0
Distributions to non-controlling interests
(2.5
(3.8
Other financing activities
(1.2
Net cash (used in) financing activities
(65.2
(81.9
Net change in cash, restricted cash and cash equivalents
(159.0
(9.3
Cash, restricted cash, and cash equivalents beginning of period
190.4
23.4
Cash, restricted cash, and cash equivalents end of period
31.4
14.1
Supplemental cash flow information:
Cash (paid) received during the period:
Interest (net of amounts capitalized)
(51.1
(48.8
Income taxes, net of transferred tax credits (Note 11)
14.8
15.2
Non-cash investing and financing activities:
Accrued property, plant, and equipment purchases at March 31,
87.7
86.8
CONSOLIDATED STATEMENTS OF EQUITY
Common Stock
Treasury Stock
Shares
Value
Additional Paid in Capital
Retained Earnings
Non-controlling Interest
Total
(in millions except share amounts)
75,520,234
43,167
2.1
Other comprehensive income, net of tax
Dividends on common stock ($0.703 per share)
Share-based compensation
93,064
14,338
(1.1
Issuance of common stock
560,966
40.6
41.2
Issuance costs
(0.5
Distributions to non-controlling interest
76,174,264
57,505
December 31, 2024
71,676,756
71.7
56,608
2,193.4
1,249.1
(9.4
83.7
3,585.2
Dividends on common stock ($0.676 per share)
103,995
(22,488
(0.1
763,481
45.4
46.1
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
(Reference is made to Notes to Consolidated Financial Statements
included in the Company’s 2025 Annual Report on Form 10-K)
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 2025 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, 2026, December 31, 2025, and March 31, 2025, 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
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.
Targeted Improvements to the Accounting for Internal-Use Software, ASU 2025-06
In September 2025, the FASB issued ASU 2025-06, Targeted Improvements to the Accounting for Internal-Use Software, which amends the accounting guidance for internal-use software under ASC 350-40. The amendments are intended to modernize the recognition and capitalization framework to better reflect current software development practices, particularly agile methodologies. ASU 2025-06 is effective for fiscal years beginning after December 15, 2027, including interim periods within those fiscal years. Early adoption is permitted. We are currently evaluating the impact of ASU 2025-06 on our consolidated financial statements and related disclosures.
We had the following regulatory assets and liabilities:
24.0
50.7
Deferred energy and fuel cost adjustments
90.7
83.3
Deferred gas cost adjustments
8.6
10.2
Gas price derivatives
4.6
Deferred taxes on AFUDC
11.0
10.6
Employee benefit plans and related deferred taxes
86.6
87.4
Environmental
13.1
Loss on reacquired debt
13.7
Deferred taxes on flow through accounting
97.4
94.8
Other regulatory assets
29.2
25.9
Total regulatory assets
374.3
394.7
Less current regulatory assets
(122.6
(139.7
Regulatory liabilities
14.4
12.3
31.2
51.5
Employee benefit plan costs and related deferred taxes
35.9
36.2
Cost of removal
220.6
216.5
Excess deferred income taxes
227.2
230.3
Colorado renewable energy
36.3
Other regulatory liabilities
10.5
8.2
Total regulatory liabilities
576.1
588.2
Less current regulatory liabilities
(85.9
(99.9
Recent Rate Review Activity
On December 5, 2025, Arkansas Gas filed a rate review with the APSC seeking recovery of infrastructure investments in its natural gas pipeline system. The rate review requested $29.4 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 fourth quarter of 2026.
On February 3, 2025, Kansas Gas filed a rate review with the KCC seeking recovery of infrastructure investments and increased operations and maintenance costs driven by inflation and operational needs to serve customers. On July 24, 2025, Kansas Gas received final approval from the KCC for a Black-box Settlement agreement for a general rate increase expected to generate $10.8 million in new annual revenue and shift $4.4 million of GSRS rider revenue to base rates. New rates were enacted on August 1, 2025. The settlement also included approval for Kansas Gas to file an abbreviated case in first quarter of 2026 that includes the addition of capital placed in service through December 31, 2025. On March 2, 2026, Kansas Gas filed the abbreviated case, which was limited in scope and requested increases in base rate revenues of $2.4 million with new rates effective in the second half of 2026.
On May 1, 2025, Nebraska Gas filed a rate review with the NPSC seeking recovery of infrastructure investments and increased operations and maintenance costs driven by inflation and operational needs to serve customers. On December 9, 2025, Nebraska Gas received final approval from the NPSC for a settlement agreement for a general rate increase. The settlement is expected to generate $23.9 million in new annual revenue with a capital structure of 51% equity and 49% debt and a return on equity of 9.85%. The settlement also includes renewal of Nebraska Gas' SSIR for five years and the development of a two-year pilot program for a weather normalization adjustment rider. New rates were enacted on January 1, 2026, which replaced interim rates effective in August 2025. Nebraska Gas customers are entitled to a $4.7 million refund due to the interim rate increase exceeding the final approved rate increase, which was retroactive to August 2025. These amounts are expected to be refunded to customers as a one-time bill credit during the second quarter of 2026.
On February 19, 2026, South Dakota Electric filed a rate review with the SDPUC seeking recovery of infrastructure investments and increased operations and maintenance costs driven by inflation and operational needs to serve customers since its last rate review in 2014. The rate review requested $50.6 million in new annual revenue with a capital structure of 53% equity and 47% debt and a return on equity of 10.5%. The request seeks interim rates to be effective 180 days after the filing, with new rates expected to be finalized in the first quarter of 2027.
On March 18, 2026, South Dakota Electric filed a rate review with the WPSC seeking recovery of infrastructure investments and increased operations and maintenance costs driven by inflation and operational needs to serve customers since its last rate review in 2014 The company is seeking an annual base rate increase to retail electric service rates of $5.1 million based on a similar capital structure and return on equity requested in South Dakota. New rates are expected to be finalized in the first quarter of 2027.
Deborah Ferrari et al. v. Colorado Electric, Case No. 2024CV31889 (District Court for the City and County of Denver, Colorado)
During the year ended December 31, 2025, Colorado Electric settled a legal matter involving an auto accident. As part of the settlement, Colorado Electric recognized a legal liability of $20 million, which was paid in the first quarter of 2026. In connection with this matter, Colorado Electric also recognized a loss recovery receivable of $20 million under its insurance coverage, which was received in the first quarter of 2026. We do not expect additional material losses related to this matter.
Generation Reservation Agreement with Prospective Data Center Customer
On April 22, 2026, Wyoming Electric entered into a generation reservation agreement with a prospective new customer seeking to construct a 1.8 GW data center under Wyoming Electric's LPCS Tariff. Under the agreement, the prospective customer will provide a refundable CIAC to Wyoming Electric to support milestone payments to suppliers to secure long lead-time generation equipment for potential company‑owned generation to serve the customer. To date, Wyoming Electric has received approximately $201 million in refundable CIAC payments from the prospective customer. Unless otherwise extended by the parties, this generation reservation agreement will terminate on June 30, 2026. This agreement is a bridge agreement to support long lead-time items while Wyoming Electric continues to negotiate definitive agreements with the prospective customer.
Power Purchase Agreement for Clean Energy Plan
On February 18, 2026, Colorado Electric executed a PPA with Honors Energy, LLC to purchase up to 200 MW of solar energy upon construction of a new renewable generation facility, which is expected to be completed by mid-2029. The agreement will expire 15 years after construction completion. The solar energy from this PPA will be used to support Colorado Electric's Clean Energy Plan.
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, 2026, and 2025. Sales tax and other similar taxes are excluded from revenues.
Three Months Ended March 31, 2026
Inter-segment Eliminations
Customer types:
Retail
197.0
458.7
655.7
Transportation
54.5
54.4
Wholesale
6.0
Market - off-system sales
10.9
Transmission
12.0
12.2
Other revenues
11.9
(3.9
22.8
Revenue from contracts with customers
240.7
525.3
(4.0
762.0
Alternative revenue and other
0.9
17.8
18.7
Total revenues
241.6
543.1
Timing of revenue recognition:
Services transferred at a point in time
8.8
Services transferred over time
231.9
753.2
Three Months Ended March 31, 2025
191.3
499.7
691.0
57.7
57.6
7.1
11.3
12.1
13.8
11.1
21.1
235.6
568.7
800.4
1.1
3.7
4.8
236.7
572.4
8.1
227.5
792.3
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:
(dollars in millions)
Amount outstanding
Letters of credit (a)
Available capacity
494.6
746.8
Weighted average interest rates
3.95
%
Revolving Credit Facility and CP Program borrowing activity was as follows:
Maximum amount outstanding (based on daily outstanding balances)
338.0
263.6
Average amount outstanding (based on daily outstanding balances)
182.6
87.1
3.88
4.55
Long-term Debt
On October 2, 2025, we completed a public debt offering of $450 million, 4.55% senior unsecured notes due January 31, 2031. Proceeds from the offering, which were reduced by $4.0 million of deferred financing costs, were used to repay all $300 million principal amount outstanding of our 3.95% senior unsecured notes at their January 15, 2026, maturity date and for other general corporate purposes.
Financial Covenants
We were in compliance with all of our Revolving Credit Facility covenants as of March 31, 2026. 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, 2026, our Consolidated Indebtedness to Capitalization Ratio was 0.54 to 1.00.
Wyoming Electric was in compliance with all covenants within its financing agreements as of March 31, 2026. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of March 31, 2026, Wyoming Electric's debt to capitalization ratio was 0.50 to 1.00.
Equity
ATM activity was as follows:
June 16, 2023 ATM Program
(in millions, except Average price per share amounts)
Proceeds, (net of issuance costs of $0.0 and $(0.5), respectively)
45.7
Number of shares issued
May 8, 2025 ATM Program
Proceeds, (net of issuance costs of $(0.4) and $0.0, respectively)
Total activity under both ATM Programs
Proceeds, (net of issuance costs of $(0.4) and $(0.5), respectively)
Average price per share
73.42
60.44
17
A reconciliation of share amounts used to compute earnings per share in the accompanying Consolidated Statements of Income was as follows:
Weighted average shares - basic
Dilutive effect of equity compensation
Weighted average shares - diluted
Net income available for common stock, per share - Diluted
Anti-dilutive shares excluded from the diluted earnings per share computation were not material for the three months ended March 31, 2026, and 2025.
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:
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.
We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit, and other security agreements.
We perform periodic credit evaluations of our customers and adjust credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses, and any specific customer collection issue that is identified.
Derivatives and Hedging Activity
Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income, and Consolidated Statements of Comprehensive Income are detailed below and in Note 8.
The operations of our Utilities, including natural gas sold by our Gas Utilities and natural gas used by our Electric Utilities’ generation plants or those plants under PPAs where our Electric Utilities must provide the generation fuel (tolling agreements), expose our utility customers to natural gas price volatility. Therefore, as allowed or required by state utility commissions, we have entered into commission approved hedging programs utilizing natural gas futures, options, over-the-counter swaps, and basis swaps to reduce our customers’ underlying exposure to these fluctuations. These transactions are considered derivatives, and in accordance with accounting standards for derivatives and hedging, mark-to-market adjustments are recorded as Derivative assets or Derivative liabilities on the accompanying Consolidated Balance Sheets, net of balance sheet offsetting as permitted by GAAP.
For our regulated Utilities’ hedging plans, unrealized and realized gains and losses, as well as option premiums and commissions on these transactions, are recorded as Regulatory assets or Regulatory liabilities in the accompanying Consolidated Balance Sheets in accordance with the state regulatory commission guidelines. When the related costs are recovered through our rates, the hedging activity is recognized in the Consolidated Statements of Income.
Through Black Hills Energy Services, our non-regulated natural gas commodity supplier, we buy, sell, and deliver natural gas in Nebraska and Wyoming at competitive prices by managing commodity price risk. As a result of these activities, this area of our business is exposed to risks associated with changes in the market price of natural gas. We manage our exposure to such risks using over-the-counter and exchange traded options and swaps with counterparties in anticipation of forecasted purchases and sales through September 2028. 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:
Notional Amounts (MMBtus)
Maximum Term (months) (a)
Natural gas futures purchased
620,000
Natural gas options purchased, net
2,750,000
Natural gas basis swaps purchased
1,040,000
Natural gas over-the-counter swaps, net (b)
2,610,000
3,430,000
Natural gas physical contracts, net (c)
(942,398
14,285,200
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, 2026, the Company had no amount related to such provisions, which would be included in Other current assets on the Consolidated Balance Sheets.
Derivatives by Balance Sheet Classification
The following table presents the fair value and balance sheet classification of our derivative instruments as of:
Balance Sheet Location
March 31,2026
December 31,2025
Derivatives designated as hedges:
Liability derivative instruments:
Current commodity derivatives
(0.7
(2.8
Total derivatives designated as hedges
Derivatives not designated as hedges:
(3.0
Total derivatives not designated as hedges
19
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, 2026, and 2025. 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.
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
Interest rate swaps
Interest expense
Commodity derivatives
2.0
0.5
Fuel, purchased power, and cost of natural gas sold
(1.7
(0.4
2.7
(2.4
As of March 31, 2026, $2.2 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, 2026, and 2025. 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.
Derivatives Not Designated as Hedging Instruments
Location of Gain/(Loss) on Derivatives Recognized in Income
Amount of Gain/(Loss) on Derivatives Recognized in Income
As discussed above, financial instruments used in our regulated Gas Utilities are not designated as cash flow hedges. However, there is no earnings impact because the unrealized gains and losses arising from the use of these financial instruments are recorded as Regulatory assets or Regulatory liabilities. The net unrealized losses included in our Regulatory asset accounts related to these financial instruments were $0.0 million and $4.6 million as of March 31, 2026, and December 31, 2025, respectively.
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 2025 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, 2026
Level 1
Level 2
Level 3
Cash Collateral and Counterparty Netting (a)
Assets:
Commodity derivatives - Gas Utilities
Liabilities:
As of December 31, 2025
21
Pension and Postretirement Plan Assets
The fair value of our pension and postretirement plan assets is presented in Note 13 to the Consolidated Financial Statements included in our 2025 Annual Report on Form 10-K.
Captive Insurance Cell Investments
We have investments in the Captive that may be used to pay insurance losses in the event of certain insured loss events. The Captive may hold investment assets in cash, cash equivalents, and equity and fixed income instruments. These investments are restricted for insured loss events. Additional information regarding the Captive is presented in Note 12 to the Consolidated Financial Statements included in our 2025 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:
Carrying Amount
Fair Value
Long-term debt, including current maturities (a)
4,402.5
4,264.7
4,639.0
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
Location on the Consolidated Statements of Income
Gains and (losses) on cash flow hedges:
Commodity contracts
Income tax
Income tax (expense) benefit
Total reclassification adjustments related to cash flow hedges, net of tax
(1.9
(0.9
Amortization of components of defined benefit plans:
Actuarial (loss)
Total reclassification adjustments related to defined benefit plans, net of tax
Total reclassifications
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
(1.6
(2.2
(5.9
Other comprehensive income (loss) before reclassifications
Amounts reclassified from AOCI
(1.0
(5.8
As of December 31, 2024
(0.3
(5.3
As of March 31, 2025
(3.2
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
Service cost
Interest cost
3.6
4.0
Expected return on plan assets
(4.2
Net amortization of prior service costs
Recognized net actuarial loss
Net periodic expense
Plan Contributions
Contributions made in the first three months of 2026 and additional contributions anticipated for the remainder of 2026 are as follows:
Contributions Made
Additional Contributions
Anticipated for 2026
Supplemental Non-qualified Defined Benefit and Defined Contribution Plans
Transfers of Production Tax Credits
In January 2025 and 2026, we entered into agreements with a third party to sell 2024 and 2025 generated PTCs for $16.0 million and $15.3 million, respectively. We expect to continue to explore monetization of our tax credits through third party transferability agreements.
Income Tax (Expense) and Effective Tax Rates
Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025
Income tax (expense) for the three months ended March 31, 2026, was $(17.6) million compared to $(18.1) million reported for the same period in 2025. For the three months ended March 31, 2026, the effective tax rate was 11.7%, which was comparable to 11.7% for the same period in 2025.
We are a holding company that, through our subsidiaries, conducts our operations through the following two 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 our captive insurance cell, 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, sets financial performance objectives and budgets and establishes separate targets based on operating income for our Electric Utilities segment as well as our Gas Utilities segment. Our CODM assesses segment financial performance, including quarterly and annual budget-to-actual and year-over-year variances in revenues and expenses, to inform operating decisions, capital investments and cost recovery strategies. Our CODM reviews capital expenditures by operating segment rather than any individual or total asset amount.
Segment information was as follows:
Consolidating Income Statement
Total Reportable Segments
Revenue -
External Customers
239.1
541.6
Inter-segment
1.5
Total revenue
784.7
66.8
271.2
Operations and maintenance (a) -
Direct
33.1
40.4
73.5
74.1
Allocated
32.0
41.9
73.9
34.2
9.2
8.9
Operating income (loss)
59.9
146.5
206.4
(4.5
Interest expense, net
(51.9
234.3
570.9
3.9
809.1
67.2
292.6
359.8
35.7
44.1
79.8
76.8
43.8
76.9
37.1
32.1
9.3
8.3
54.3
151.5
205.8
(51.3
25
Capital Expenditures (a) for the three months ended March 31,
189.5
102.1
68.4
59.0
1.9
Total capital expenditures
259.8
162.4
Accounts Receivable and Allowance for Credit Losses
Following is a summary of Accounts receivable, net included in the accompanying Consolidated Balance Sheets as of:
Billed Accounts Receivable
269.4
223.3
Unbilled Revenue
117.5
168.1
Less: Allowance for Credit Losses
(3.5
Account Receivable, net
Changes to allowance for credit losses for the three months ended March 31, 2026, and 2025, 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,
3.5
3.4
(1.5
4.9
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:
Materials and supplies
119.3
117.3
Fuel - Electric Utilities
Natural gas in storage
48.7
Total materials, supplies, and fuel
Accrued Liabilities
The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of:
Accrued employee compensation, benefits, and withholdings
60.3
92.8
Accrued property taxes
56.9
54.8
Customer deposits and prepayments
Accrued interest
56.7
57.2
Other (none of which is individually significant)
40.9
58.8
Total accrued liabilities
On August 18, 2025, we entered into an Agreement and Plan of Merger (the “Merger Agreement”), with NorthWestern and Merger Sub. The Merger Agreement provides for Merger Sub to merge with and into NorthWestern (the “Merger”), with NorthWestern continuing as the surviving entity and a direct wholly owned subsidiary of Black Hills Corporation, which will assume a new corporate name as the resulting parent company of the combined corporate group. At the effective time of the Merger (the “Effective Time”), each share of common stock of NorthWestern, par value $0.01 per share, issued and outstanding as of immediately prior to the Effective Time will be converted into the right to receive 0.98 validly issued, fully paid and non-assessable shares of our common stock, par value $1.00 per share (or cash-in-lieu of fractional shares thereof), in each case upon and subject to the terms and conditions of the Merger Agreement.
The Merger Agreement, which was unanimously approved on August 18, 2025, by both the board of directors of Black Hills Corporation and the board of directors of NorthWestern, provides for a tax-free, all-stock business combination of Black Hills Corporation and NorthWestern upon the terms and subject to the conditions set forth therein. Such conditions include, among other things, clearance under the HSR Act, consent of the FCC, approval from each company's shareholders, and regulatory approvals, including approval from the SDPUC, NPSC and MPSC, as well as the FERC. To date, the status of these matters is as follows:
We anticipate the transaction closing in the second half of 2026, subject to the satisfaction of certain closing conditions including receipt of certain regulatory approvals as mentioned above.
Except as described below, there have been no events subsequent to March 31, 2026, which would require recognition in the Consolidated Financial Statements or disclosures.
See Note 3 for information regarding Wyoming Electric's generation reservation agreement.
See Note 14 for information regarding the pending merger with NorthWestern.
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 2025 Annual Report on Form 10-K.
We are a customer-focused energy solutions provider with a mission of Improving Life with Energy for more than 1.37 million customers and 800+ communities we serve. Our aspiration is to be the trusted energy partner across our growing eight-state footprint, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota, and Wyoming. Our strategy is centered on four priorities: People & Culture—build a team that wins together, Operational Excellence—relentlessly deliver on our commitment to serve our customers, Transformation—be a simple and connected company and Growth—grow to be a dominant long-term energy provider.
We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. We conduct our utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. We consider ourselves a domestic electric and natural gas utility company.
We have provided energy and served customers for 142 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.
Pending Merger with NorthWestern
On August 18, 2025, we entered into the Merger Agreement with NorthWestern and Merger Sub. See Note 14 of the Condensed Notes to Consolidated Financial Statements for recent developments surrounding the pending Merger.
Business Segment Recent Developments
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, 2026, and 2025, and our financial condition as of March 31, 2026, and December 31, 2025, 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.
2026 vs 2025 Variance
Operating income (loss):
5.6
(5.0
Corporate and Other (a)
(3.1
(0.6
Weighted average common shares outstanding, Diluted
3.8
Total earnings per share of common stock, Diluted
(0.14
Three Months Ended March 31, 2026, Compared to the Three Months Ended March 31, 2025:
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:
(66.8
(67.2
(271.2
(292.6
Operations and maintenance (a)
(39.2
(41.9
(41.1
(46.2
(40.5
(37.1
(34.2
(32.1
(9.2
(8.9
(8.3
Gross margin (GAAP)
81.2
187.7
193.2
39.2
41.1
46.2
40.5
Electric and Gas Utility margin (non-GAAP)
174.8
169.5
271.9
279.8
Operating results for the Electric Utilities were as follows:
Fuel and purchased power
Electric Utility margin (non-GAAP) (a)
5.3
65.1
68.8
Total operating expenses (excluding Fuel and purchased power)
114.9
115.2
New rates and rider recovery
13.3
Residential and commercial customer usage
(3.6
Weather
Other
Operating Statistics
Quantities Sold
By Customer Class
(in GWh)
Retail Revenue -
Residential
63.1
66.4
358.9
406.4
Commercial
70.0
492.2
517.2
Industrial (a)
56.2
48.2
707.4
609.8
Municipal
4.3
4.5
31.1
34.6
Other Retail
Subtotal Retail Revenue - Electric
1,589.6
1,568.0
140.1
147.8
198.3
173.6
Other (b)
15.7
14.9
Total Revenue and Quantities Sold
1,928.0
1,889.4
Other Uses, Losses, or Generation, net (c)
103.2
94.1
Total Energy
2,031.2
1,983.5
By Business Unit
72.4
495.9
532.3
86.7
86.9
679.7
682.0
66.6
726.6
645.8
10.8
25.8
29.3
Quantities Generated and Purchased by Fuel Type
Generated:
Coal (a)
599.9
Natural Gas and Oil
441.7
512.1
Wind
186.8
175.4
Total Generated
1,118.7
1,287.4
Purchased:
Coal, Natural Gas, Oil, and Other Market Purchases
562.4
375.7
Wind and Solar
350.1
320.4
Total Purchased (b)
912.5
696.1
Total Generated and Purchased
32
Quantities Generated and Purchased by Business Unit
143.8
184.3
South Dakota Electric (a)
400.6
478.9
180.5
219.3
393.8
404.9
104.5
90.2
300.3
211.3
Wyoming Electric (b)
491.2
376.1
16.5
18.5
Total Purchased
Degree Days
Actual
Variance from Normal
Heating Degree Days:
2,001
(21)%
2,733
9%
2,567
(22)%
3,438
5%
2,325
(23)%
3,140
Combined (a)
2.263
3,060
7%
Cooling Degree Days:
---
33
Operating results for the Gas Utilities were as follows:
(29.3
Cost of natural gas sold
(21.4
Gas Utility margin (non-GAAP) (a)
(7.9
82.3
87.9
(5.6
Total operating expenses (excluding Cost of natural gas sold)
125.4
128.3
(2.9
(13.2
Retail customer usage
Mark-to-market on non-utility natural gas commodity contracts
Quantities Sold and Transported
(Dth in millions)
344.1
25.2
30.7
125.5
14.0
Industrial
6.9
6.6
Other Retail (a)
14.6
14.7
Subtotal Retail Revenue - Gas
38.3
50.4
29.9
15.0
84.5
96.1
122.1
124.8
11.5
13.2
115.8
93.8
60.6
66.1
11.7
130.9
130.2
26.2
29.6
45.5
Heating Degree Days
Arkansas Gas (a)
1,572
(16)%
1,957
2%
2,059
(27)%
2,837
2,994
(9)%
3,288
(1)%
Kansas Gas (a)
2,034
(15)%
2,616
10%
Nebraska Gas (a)
2,545
3,039
2,464
(24)%
3,323
3%
Combined (b)
2,513
(18)%
3,082
1%
Corporate and Other operating results, including inter-segment eliminations, were as follows:
The following table provides an informational summary of our liquidity and capital structure as of:
Available capacity under Revolving Credit Facility and CP Program (a)
Available liquidity
518.2
929.6
Capital structure
Short-term debt
662.2
Long-term debt
Total debt
4,654.7
Total stockholders' equity (excludes non-controlling interest)
Total capitalization
8,599.9
8,524.7
Debt to capitalization
54.1
55.1
Long-term debt to total debt
85.8
100.0
Future Financing Plans
We plan to fund our capital plan and strategic objectives by using cash generated from operating activities and various financing alternatives, which could include our Revolving Credit Facility, our CP Program, and the issuance of common stock under our ATM or in a secondary offering. Our current shelf registration statement expires in the second quarter of 2026 and we expect to file a new shelf registration statement to replace it. Additionally, we plan to re-finance our $400 million, 3.15%, senior unsecured notes due January 2027, at or before the maturity date.
CASH FLOW ACTIVITIES
The following tables summarize our cash flows for the three months ended March 31, 2026:
Operating Activities:
Non-cash adjustments to Net income
115.3
112.9
Total earnings
248.4
249.3
Materials, supplies and fuel, Accounts receivable and other current assets
45.0
(17.3
62.3
(63.3
(47.2
Net inflow (outflow) from changes in certain operating assets and liabilities
(68.9
(20.7
(48.2
Other operating activities
(51.6
Investing Activities:
Capital expenditures
(114.5
(114.8
Financing Activities:
(4.9
Short-term and long-term debt borrowings (repayments), net
(47.8
26.1
(1.3
Net cash provided by (used in) financing activities
16.7
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
The following table represents the credit rating of South Dakota Electric as of the date of this report:
Senior Secured Rating
A
CAPITAL REQUIREMENTS
Capital Expenditures
Actual (a)
Forecasted (b)
Capital Expenditures by Segment(minor differences may result due to rounding)
2027
2028
2029
2030
190
471
367
455
356
391
68
396
507
591
552
260
906
844
983
969
968
Common Stock Dividends
Dividends paid on our common stock totaled $53.1 million for the three months ended March 31, 2026, or $0.703 per share. On April 28, 2026, our board of directors declared a quarterly dividend of $0.703 per share payable June 1, 2026, equivalent to an annual dividend of $2.812 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.
A summary of our critical accounting estimates is included in our 2025 Annual Report on Form 10-K. There were no material changes made as of March 31, 2026.
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 2025 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, 2026. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at March 31, 2026.
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, 2026, 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.
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see Note 3 of the Condensed Notes to Consolidated Financial Statements and Note 3 in Item 8 of our 2025 Annual Report on Form 10-K.
ITEM 1A. RISK FACTORS
There have been no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2025 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, 2026:
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, 2026 - January 31, 2026
1
69.42
February 1, 2026 - February 28, 2026
32,951
72.16
March 1, 2026 - March 31, 2026
73.63
32,953
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, 2026.
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. Items constituting a board of director or management compensatory plan are designated by a cross (†).
Exhibit Number
Description
10.1*†
Form of Restricted Stock Unit Award Agreement (Non-Employee Director) effective for awards granted on or after May 1, 2026.
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)
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.
/s/ Linden R. Evans
Linden R. Evans, President and
/s/ Kimberly F. Nooney
Kimberly F. Nooney, Senior Vice President and
Chief Financial Officer
Dated:
May 7, 2026