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☒
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended
June 30,
2025
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.
The following terms and abbreviations appear in the text of this report and have the definitions described below:
AFUDC
Allowance for Funds Used During Construction
AOCI
Accumulated Other Comprehensive Income (Loss)
Arkansas Gas
Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).
ASU
Accounting Standards Update as issued by the FASB
ATM
At-the-market equity offering program
Availability
The availability factor of a power plant is the percentage of the time that it is available to provide energy.
BHC
Black Hills Corporation; the Company
Black-box Settlement
Settlement with a utility's commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.
Black Hills Colorado IPP
Black Hills Colorado IPP, LLC a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Electric Generation
Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing wholesale electric capacity and energy primarily to our affiliate utilities.
Black Hills Electric Parent Holdings
Black Hills Electric Utility Holdings, LLC., a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Energy
The name used to conduct the business of our Utilities
Black Hills Energy Renewable Resources (BHERR)
Black Hills Energy Renewable Resources, LLC, a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings
Black Hills Energy Services
Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas commodity supply for the Choice Gas Programs (doing business as Black Hills Energy).
Black Hills Non-regulated Holdings
Black Hills Non-regulated Holdings, LLC, a direct, wholly-owned subsidiary of Black Hills Corporation
Black Hills Utility Holdings
Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing business as Black Hills Energy)
Black Hills Wyoming
Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Generation
Blockchain Interruptible Service (BCIS) Tariff
A WPSC-approved tariff applicable to prospective new Wyoming Electric blockchain customers. The tariff allows customers to negotiate rates and terms and conditions for interruptible electric utility service of 10 MW or greater that would be interconnected with Wyoming Electric’s system. Agreements under the BCIS tariff must be filed with the WPSC prior to the first customer billing, be at least 2 years in duration and include specific pricing for all electricity purchased (with pricing terms subject to renegotiation every three years). BCIS customers shall not participate in the PCA to the extent of service received under the tariff.
Busch Ranch I
A 29 MW wind farm near Pueblo, Colorado, jointly owned by Colorado Electric and Black Hills Electric Generation. Colorado Electric and Black Hills Electric Generation each have a 50% ownership interest in the wind farm. Black Hills Electric Generation provides its share of energy from the wind farm to Colorado Electric through a PPA, which expires in October 2037.
Busch Ranch II
A 59.4 MW wind farm near Pueblo, Colorado owned by Black Hills Electric Generation to provide wind energy to Colorado Electric through a PPA expiring in November 2044.
CEPR
Clean Energy Plan Rider, which is a 1.5% surcharge to fund Colorado Electric's recovery of renewable energy projects under the Clean Energy Plan. In conjunction with the implementation of the CEPR in January 2025, the RESA surcharge was reduced from 2.0% to 1.5%.
Choice Gas Program
Regulator-approved programs in Wyoming and Nebraska that allow certain utility customers to select their natural gas commodity supplier, providing for the unbundling of the commodity service from the distribution delivery service.
2030 Ready Plan that establishes a roadmap and preferred resource portfolio for Colorado Electric to achieve the State of Colorado’s requirement calling upon electric utilities to reduce greenhouse gas emissions by a minimum of 80% from 2005 levels by 2030. The recommended resource portfolio proposes the addition of 350 MW of clean energy resources to Colorado Electric's system. Colorado legislation allows electric utilities to own up to 50% of the renewable generation assets added to comply with the Clean Energy Plan.
Colorado Electric
Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Electric Parent Holdings, providing electric services to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas
Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Consolidated Indebtedness to Capitalization Ratio
Any indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day
A cooling degree day is equivalent to each degree that the average of the high and the low temperatures for a day is above 65 degrees. The warmer the climate, the greater the number of cooling degree days. Cooling degree days are used in the utility industry to measure the relative warmth of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
CP Program
Commercial Paper Program
CPCN
Certificate of Public Convenience and Necessity
CPUC
Colorado Public Utilities Commission
CT
Combustion Turbine
Dth
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu)
Emergency PSPS
Emergency Public Safety Power Shutoff is a safety measure to prevent the
electric system from becoming a potential source of ignition during extreme weather conditions/events. It entails selectively and intentionally turning off power to a portion of a service area when high-fire-risk weather and fuel conditions occur.
FASB
Financial Accounting Standards Board
Fitch
Fitch Ratings Inc.
GAAP
Accounting principles generally accepted in the United States of America
GSRS
Gas System Reliability Surcharge is a monthly charge that recovers Kansas Gas's costs associated with pipeline safety and government-mandated projects.
Heating Degree Day
A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
HomeServe
We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
Integrated Generation
Non-regulated power generation and mining businesses (Black Hills Electric Generation and WRDC) that are vertically integrated within our Electric Utilities segment.
Iowa Gas
Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP
Independent Power Producer
IRA
Inflation Reduction Act of 2022
IRS
United States Internal Revenue Service
IUC
Iowa Utilities Commission
Kansas Gas
Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).
A dual fuel (natural gas and diesel oil) electric generation project in Rapid City, South Dakota with an estimated total capacity of 99 MW. This facility will be owned and operated by South Dakota Electric and will be located adjacent to the Lange CT generation facility. This project is expected to begin construction in third quarter of 2025 and in service during the the second half of 2026. The addition of these resources will replace generation facilities planned for retirement and support updated planning reserve margin requirements.
Large Power Contract Service (LPCS) Tariff
Innovative tariff solution developed in collaboration with Microsoft and approved by the WPSC in 2016. The LPSC is applicable to Wyoming Electric retail customers with new loads of 13 MW or greater who agree to Black Hills Energy-dispatched, customer-owned generation, on-site for the purpose of providing backup service for the customer’s load and maintaining reliability. If the parties agree through negotiations to electric service through this tariff, a Large Power Service Agreement will be executed. The associated service agreement provides qualifying customers with market-based energy rates and access to renewable energy resources that is not served from utility-owned generation (i.e. minimal capital model for Wyoming Electric). Customers shall not participate in the PCA or TCAM to the extent of service received under the tariff.
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
OBBBA
One Big Beautiful Bill Act enacted on July 4, 2025, which is a legislative package designed to permanently extend certain expiring provisions of the TCJA and deliver additional tax relief for individuals and businesses. The OBBBA introduced changes to federal energy policies by rolling back several clean energy provisions and codified restrictions related to prohibited foreign entities, termination and restrictions on clean energy PTCs, extension and modification of clean fuel production. The OBBBA does not repeal tax credit transferability provisions enacted under the IRA, but restricts credit transfers to prohibited foreign entities.
OCI
Other Comprehensive Income
PPA
Power Purchase Agreement
PTC
Production Tax Credit
Pueblo Airport Generation
Pueblo Airport Generating Station located in Pueblo, Colorado includes 440 MW of combined cycle gas-fired power generation plants jointly owned by Colorado Electric (240 MW) and Black Hills Colorado IPP (200 MW). Black Hills Colorado IPP operates this facility. The plants commenced operation on January 1, 2012.
Ready Wyoming
A 260-mile, multi-phase transmission expansion project in Wyoming. This transmission project is expected to serve the growing needs of customers by enhancing resiliency of Wyoming Electric’s overall electric system and expanding access to power markets and renewable resources. The project is expected to help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region.
RESA
Renewable Energy Standard Adjustment is an incremental retail rate limited to 1.5% for Colorado Electric customers that provides funding for renewable energy projects and programs to comply with Colorado’s Renewable Energy Standard.
Revolving Credit Facility
Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended on May 31, 2024, and will terminate on May 31, 2030. This facility includes an accordion feature that allows us to increase total commitments up to $1.0 billion with the consent of the administrative agent, the issuing agents and each bank increasing or providing a new commitment.
RNG
Renewable natural gas
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).
Transmission Cost Adjustment Mechanism is a WPSC-approved tariff based on a formulaic approach that determines the recovery of Wyoming Electric's transmission costs.
TCJA
Tax Cuts and Jobs Act enacted on December 22, 2017, which reduced the U.S. federal corporate tax rate from 35% to 21%. As such, we remeasured our deferred income taxes at the 21% federal tax rate as of December 31, 2017.
Tech Services
Non-regulated product lines delivered by our Utilities that 1) provide electrical system construction services to large industrial customers of our Electric Utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.
Utilities
Black Hills' Electric and Gas Utilities
Wind Capacity Factor
Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential.
Winter Storm Uri
February 2021 winter weather event that caused extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.
WPSC
Wyoming Public Service Commission
WRDC
Wyodak Resources Development Corp., a coal mine which is a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities at our Gillette Energy Complex (doing business as Black Hills Energy).
Wygen I
A mine-mouth, coal-fired generating facility with a total capacity of 90 MW located at our Gillette Energy Complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wygen III
A mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 116 MW located at our Gillette Energy Complex. South Dakota Electric owns 52% of the power plant, MDU owns 25%, and the City of Gillette owns the remaining 23%.
Wyoming Electric
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas
Black Hills Wyoming Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).
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.
Reclassification adjustments of benefit plan liability - net loss
(net of tax of $
0.0
, $
0.0
, $
0.0
and $
0.0
, respectively)
—
—
0.1
0.1
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(
0.2
), $(
0.2
), $(
0.3
), and $(
0.3
), respectively)
0.6
0.6
1.1
1.1
Net unrealized gains (losses) on commodity derivatives
(net of tax of $
0.1
, $
0.0
, $
0.1
, and $
0.0
, respectively)
(
0.3
)
—
(
0.2
)
(
0.2
)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $
0.0
, $(
0.1
), $(
0.2
), and $(
0.8
), respectively)
0.1
0.4
0.4
2.5
Other comprehensive income, net of tax
0.4
1.0
1.4
3.5
Comprehensive income
29.2
25.7
166.6
159.7
Less: comprehensive income attributable to non-controlling interest
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)
Manage
ment’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 June 30, 2025, December 31, 2024, and June 30, 2024
, financial information. Certain lines of business in which we operate are highly seasonal and our interim results of operations are not necessarily indicative of the results of operations to be expected for an entire year.
Recently Issued Accounting Standards
Improvements to Income Tax Disclosures, ASU 2023-09
In December 2023, the FASB issued ASU 2023-09,
Improvements to Income Tax Disclosures
, which expands public entities’ annual disclosures by requiring disclosure of tax rate reconciliation amounts and percentages for specific categories, income taxes paid disaggregated by federal and state taxes, and income tax expense disaggregated by federal and state taxes jurisdiction. The ASU is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2025. We are evaluating the disclosure impact of ASU 2023-09; however, the standard is not expected to have an impact on our financial condition, results of operations and/or cash flows.
Disaggregation of Income Statement Expenses, ASU 2024-03
In November 2024, the FASB issued ASU 2024-03,
Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures
, and in January 2025, the FASB issued ASU 2025-01,
Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures: Clarifying the Effective Date
. ASU 2024-03 requires public entities to disclose, in the notes to financial statements, certain costs and expenses, such as purchases of inventory, employee compensation, and costs related to depreciation and amortization. ASU 2024-03, as clarified by ASU 2025-01, is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2027, and subsequent interim periods, with early adoption permitted. We are evaluating the disclosure impact of ASU 2024-03; however, the standard is not expected to have an impact on our financial condition, results of operations and/or cash flows.
We had the following regulatory assets and liabilities:
As of
As of
June 30, 2025
December 31, 2024
(in millions)
Regulatory assets
Winter Storm Uri
$
64.9
$
109.5
Deferred energy and fuel cost adjustments
70.6
62.8
Deferred gas cost adjustments
3.0
14.5
Gas price derivatives
1.0
2.9
Deferred taxes on AFUDC
9.0
8.0
Employee benefit plans and related deferred taxes
86.7
89.0
Environmental
11.5
10.7
Loss on reacquired debt
14.9
15.7
Deferred taxes on flow through accounting
92.8
87.7
Decommissioning costs
2.4
2.4
Other regulatory assets
23.1
24.5
Total regulatory assets
379.9
427.7
Less current regulatory assets
(
132.1
)
(
154.8
)
Regulatory assets, non-current
$
247.8
$
272.9
Regulatory liabilities
Deferred energy and gas costs
$
67.5
$
67.8
Employee benefit plan costs and related deferred taxes
35.5
36.7
Cost of removal
206.6
197.0
Excess deferred income taxes
234.1
238.5
Colorado renewable energy
(a)
28.9
24.1
Other regulatory liabilities
4.1
4.6
Total regulatory liabilities
576.7
568.7
Less current regulatory liabilities
(
96.6
)
(
94.1
)
Regulatory liabilities, non-current
$
480.1
$
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 infrastructure investments in its
3,200
-mile electric distribution and
600
-mile electric transmission systems. On March 17, 2025, Colorado Electric received an order from the CPUC for a general rate increase which was expected to generate approximately $
17.0
million of new annual revenue based on a weighted average cost of capital of
6.9
% with a capital structure in a range of
47
% to
49
% equity and
51
% to
53
% debt, and a return on equity in a range of
9.3
% to
9.5
%. The new rates were effective March 22, 2025.
On April 7, 2025, Colorado Electric filed a request with the CPUC for rehearing, re-argument or reconsideration (RRR). On May 6, 2025, Colorado Electric received a final decision from the CPUC related to its RRR request, increasing new annual revenue from approximately $
17.0
million to approximately $
17.5
million.
Iowa Gas
On May 1, 2024, Iowa Gas filed a rate review with the IUC seeking recovery of infrastructure investments in its
5,000
-mile natural gas pipeline system. In the fourth quarter of 2024, Iowa Gas received final approval from the IUC for a settlement agreement for a general rate increase. The approved Black-box Settlement is expected to generate $
15.0
million of new annual revenue based on a weighted average cost of capital of
7.2
%. New rates were enacted on January 1, 2025, which replaced interim rates.
On February 3, 2025, Kansas Gas filed a rate review with the KCC seeking recovery of infrastructure investments in its
4,765
-mile natural gas pipeline system and increased operations and maintenance costs driven by inflation and operational needs to serve customers. On July 24, 2025, Kansas Gas received final approval from the KCC for a settlement agreement for a general rate increase. The approved Black-box Settlement is expected to generate $
10.8
million in new annual revenue and will shift $
4.4
million of GSRS rider revenue to base rates. New rates will be effective on August 1, 2025. The settlement also includes approval for Kansas Gas to file an abbreviated case in first quarter of 2026 that includes the addition of capital placed in service through December 31, 2025.
Nebraska Gas
On May 1, 2025, Nebraska Gas filed a rate review with the NPSC seeking recovery of infrastructure investments in its
12,900
-mile natural gas pipeline system
and increased operations and maintenance costs driven by inflation and operational needs to serve customers
. 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
and Nebraska Gas plans to implement interim rates, subject to adjustment or refund, effective in August 2025
. New rates are expected to be effective in the first quarter of 2026.
(3)
Comm
itments, Contingencies and Guarantees
There have been no significant changes to commitments, contingencies and guarantees from those previously disclosed in Note 3 of our Notes to the Consolidated Financial Statements in our 2024 Annual Report on Form 10-K except as described below.
Transfers of Renewable Tax Credits
In January 2025, we entered into an agreement with a third party to sell our 2024 generated PTCs. In the agreement, we provided indemnifications associated with the proceeds for PTCs transferred to the third party in the event of an adverse change or interpretation of tax law, including whether the related tax credits meet the qualification requirements. We believe the likelihood of having to make any material cash payments under these indemnifications is remote. See
Note 11
for additional information.
Manufactured Gas Plant
In 2008, we acquired liabilities for a former manufactured gas plant site in Iowa, which was previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $
1.5
million recorded in Other current assets on our Consolidated Balance Sheets, which will be used to help offset remediation costs. As of December 31, 2024, we had an Accrued liability of $
9.7
million on our Consolidated Balance Sheets for the remaining remediation of the manufactured gas plant site in Iowa. During the six months ended June 30, 2025, we completed substantially all remaining remediation work. As of June 30, 2025, $
11.5
million of cumulative remediation costs, which are net of our $
1.5
million insurance recovery asset, were recorded to a Regulatory asset on our Consolidated Balance Sheets which Iowa Gas intends to seek recovery of during a future rate review. We expect to recover our $
1.5
million insurance recovery asset by year-end 2025.
GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (District Court for the City and County of Denver, Colorado)
On April 13, 2022, a jury awarded $
41
million for claims made by GT Resources, LLC (“GTR”) against BHC and two of its subsidiaries (Black Hills Exploration and Production, Inc. and Black Hills Gas Resources, Inc.), which ceased oil and natural gas operations in 2018 as part of BHC’s decision to exit the exploration and production business. The claims involved a dispute over a
2.3
million-acre concession award in Costa Rica which was acquired by a BHC subsidiary in 2003. GTR retained rights to receive a royalty interest on any hydrocarbon production from the concession upon the occurrence of contingent events. GTR contended that BHC and its subsidiaries failed to adequately pursue the opportunity and failed to transfer the concession to GTR. We appealed this verdict to the Colorado Court of Appeals. On October 19, 2023, the Appellate Court reversed and remanded the case with directions limiting any retrial to the narrow issue of whether there was improper interference with the prospective conveyance of the concession. The retrial occurred and on May 12, 2025, the jury returned a verdict in favor of BHC and its subsidiaries on all counts, thus resolving any claims without material impact on our financial position, results or operations and cash flows.
The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by customer type and timing of revenue recognition for each of the reportable segments for the
three and six months ended June 30, 2025, and 2024. Sales tax and other similar taxes are excluded from revenues.
On June 6, 2025, with approval from our lenders, we utilized
one
of our
two
available
one-year
extension options under the amended and restated Revolving Credit Facility, thereby extending its maturity date to May 31, 2030.
Our Revolving Credit Facility and CP Program, which are classified as Notes payable on the Consolidated Balance Sheets, had the following borrowings, outstanding letters of credit, and available capacity as of:
June 30, 2025
December 31, 2024
(dollars in millions)
Amount outstanding
$
123.7
$
133.8
Letters of credit
(a)
3.5
3.5
Available capacity
622.8
612.7
Weighted average interest rates
4.58
%
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:
Six Months Ended June 30,
2025
2024
(dollars in millions)
Maximum amount outstanding (based on daily outstanding balances)
$
157.8
$
—
Average amount outstanding (based on daily outstanding balances)
80.4
—
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 June 30, 2025
. We are required to maintain a Consolidated Indebtedness to Capitalization Ratio not to exceed
0.65
to 1.00. Subject to applicable cure periods, a violation of this covenant would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding. As of
June 30, 2025, our Consolidated Indebtedness to Capitalization Ratio was
0.55
to 1.00.
Wyoming Electric was in compliance with all covenants within its financing agreements as of June 30, 2025
. Wyoming Electric is required to maintain a debt to capitalization ratio of no more than
0.60
to 1.00. As of
June 30, 2025
, Wyoming Electric's debt to capitalization ratio was
0.51
to 1.00.
Equity
ATM
On May 8, 2025, we entered into a First Amendment to our Equity Distribution Sales Agreement (the “First Amendment”). The First Amendment, among other things, provides for the continuation of the ATM, which allows us to sell shares of common stock under the Company's shelf registration statement (Registration No. 333-272739), and resets the size of the ATM to $
400
million. The First Amendment aggregate gross sales price limitation of $
400
million supersedes and replaces the aggregate gross sales price limitation provided in our Equity Distribution Sales Agreement. Except as modified by the First Amendment, our Equity Distribution Sales Agreement remains in full force and effect.
ATM activity was as follows:
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025
2024
June 16, 2023 ATM Program
(in millions, except Average price per share amounts)
Proceeds, (net of issuance costs of $
0.0
, $(
0.4
), $(
0.5
), and $(
0.7
), respectively)
$
—
$
41.8
$
45.7
$
73.0
Number of shares issued
—
0.8
0.8
1.4
May 8, 2025 ATM Program
Proceeds, (net of issuance costs of $(
0.2
), $
0.0
, $(
0.2
), and $
0.0
, respectively)
$
19.6
$
—
$
19.6
$
—
Number of shares issued
0.3
—
0.3
—
Total activity under both ATM Programs
Proceeds, (net of issuance costs of $(
0.2
), $(
0.4
), $(
0.7
), and $(
0.7
), respectively)
$
19.6
$
41.8
$
65.3
$
73.0
Number of shares issued
0.3
0.8
1.1
1.4
Average price per share
$
58.28
$
55.02
$
59.78
$
53.92
(6)
Earning
s 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 June 30,
Six Months Ended June 30,
2025
2024
2025
2024
(in millions, except per share amounts)
Net income available for common stock
$
27.5
$
22.8
$
161.7
$
150.6
Weighted average shares - basic
72.4
69.0
72.0
68.6
Dilutive effect of equity compensation
—
—
0.1
0.1
Weighted average shares - diluted
$
72.4
$
69.0
$
72.1
$
68.7
Net income available for common stock, per share - Diluted
$
0.38
$
0.33
$
2.24
$
2.19
Anti-dilutive shares excluded from the diluted earnings per share computation were not material for the three and six months ended June 30, 2025, and 2024.
Our activities in the energy industry expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk.
Market Risk
Market risk is the potential loss that may occur as a result of an adverse change in market price, rate or supply. We are exposed but not limited to, the following market risks:
•
Commodity price risk associated with our retail natural gas and wholesale electric power marketing activities and our fuel procurement for several of our gas-fired generation assets, which include market fluctuations due to unpredictable factors such as weather, geopolitical events, pandemics, market speculation, imposition of new tariffs, recession, inflation, pipeline constraints, and other factors that may impact natural gas and electric supply and demand; and
•
Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital markets volatility.
Credit Risk
Credit risk is the risk of financial loss resulting from non-performance of contractual obligations by a counterparty.
We attempt to mitigate our credit exposure by conducting business primarily with high credit quality entities, setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through parental guarantees, cash collateral requirements, letters of credit, and other security agreements.
We perform periodic credit evaluations of our customers and adjust credit limits based upon payment history and the customers’ current creditworthiness, as determined by review of their current credit information. We maintain a provision for estimated credit losses based upon historical experience, changes in current market conditions, expected losses, and any specific customer collection issue that is identified.
Derivatives and Hedging Activity
Our derivative and hedging activities included in the accompanying Consolidated Balance Sheets, Consolidated Statements of Income, and Consolidated Statements of Comprehensive Income are detailed below and in
Note 8
.
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 July 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:
June 30, 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
1,160,000
9
2,780,000
3
Natural gas basis swaps purchased
—
N/A
1,080,000
3
Natural gas over-the-counter swaps, net
(b)
5,590,000
29
3,480,000
20
Natural gas physical contracts, net
(c)
6,077,280
9
20,276,230
10
(a)
Term reflects the maximum forward period hedged.
(b)
As of
June 30, 2025
,
3,040,000
MMBtus of natural gas over-the-counter swaps purchases were designated as cash flow hedges.
(c)
Volumes exclude contracts that qualify for the normal purchases and normal sales exception under GAAP.
We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At June 30, 2025, the Company posted
$
0.1
million related
to such provisions, which is included in Other current assets on the Consolidated Balance Sheets.
Derivatives by Balance Sheet Classification
The following table presents the fair value and balance sheet classification of our derivative instruments as of:
Balance Sheet Location
June 30,
2025
December 31,
2024
(in millions)
Derivatives designated as hedges:
Asset derivative instruments:
Noncurrent commodity derivatives
Other assets, non-current
$
0.1
$
—
Liability derivative instruments:
Current commodity derivatives
Derivative liabilities, current
(
0.5
)
(
0.7
)
Total derivatives designated as hedges
$
(
0.4
)
$
(
0.7
)
Derivatives not designated as hedges:
Asset derivative instruments:
Noncurrent commodity derivatives
Other assets, non-current
$
0.2
$
—
Liability derivative instruments:
Current commodity derivatives
Derivative liabilities, current
(
1.2
)
(
3.5
)
Total derivatives not designated as hedges
$
(
1.0
)
$
(
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 and six months ended June 30, 2025, and 2024. Note that this presentation does not reflect the gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
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
(
0.3
)
0.6
Fuel, purchased power, and cost of natural gas sold
(
0.1
)
(
0.6
)
Total
$
0.5
$
1.3
$
(
0.9
)
$
(
1.3
)
Six Months Ended
June 30,
Six Months Ended
June 30,
2025
2024
2025
2024
Derivatives in Cash Flow Hedging Relationships
Amount of Gain/(Loss) Recognized in OCI
Income Statement Location
Amount of Gain/(Loss) Reclassified from AOCI into Income
(in millions)
(in millions)
Interest rate swaps
$
1.4
$
1.4
Interest expense
$
(
1.4
)
$
(
1.4
)
Commodity derivatives
0.3
3.0
Fuel, purchased power, and cost of natural gas sold
(
0.6
)
(
3.2
)
Total
$
1.7
$
4.4
$
(
2.0
)
$
(
4.6
)
As of
June 30, 2025,
$
3.0
million o
f net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.
Derivatives Not Designated as Hedge Instruments
The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated Statements of Income for the three and six months ended June 30, 2025, and 2024. Note that this presentation does not reflect the expected gains or losses arising from the underlying physical transactions; therefore, it is not indicative of the economic profit or loss we realized when the underlying physical and financial transactions were settled.
Three Months Ended June 30,
2025
2024
Derivatives Not Designated as Hedging Instruments
Location of Gain/(Loss) on Derivatives Recognized in Income
Amount of Gain/(Loss) on Derivatives Recognized in Income
(in millions)
Commodity derivatives
Fuel, purchased power, and cost of natural gas sold
$
(
0.5
)
$
0.1
$
(
0.5
)
$
0.1
Six Months Ended June 30,
2025
2024
Derivatives Not Designated as Hedging Instruments
Location of Gain/(Loss) on Derivatives Recognized in Income
Amount of Gain/(Loss) on Derivatives Recognized in Income
(in millions)
Commodity derivatives
Fuel, purchased power, and cost of natural gas sold
$
0.6
$
0.7
$
0.6
$
0.7
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 $
1.0
million and $
2.9
million as of
June 30, 2025 and December 31, 2024
, 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 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 June 30, 2025
Level 1
Level 2
Level 3
Cash Collateral and Counterparty Netting
(a)
Total
(in millions)
Assets:
Commodity derivatives - Gas Utilities
$
—
$
1.3
$
—
$
(
1.0
)
$
0.3
Total
$
—
$
1.3
$
—
$
(
1.0
)
$
0.3
Liabilities:
Commodity derivatives - Gas Utilities
$
—
$
1.9
$
—
$
(
0.2
)
$
1.7
Total
$
—
$
1.9
$
—
$
(
0.2
)
$
1.7
(a)
As of June 30, 2025
, $
1.0
million of our commodity derivative assets and $
0.2
million of our commodity derivative liabilities, as well as related gross collateral amounts, were subject to master netting agreements.
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:
June 30, 2025
December 31, 2024
Carrying Amount
Fair Value
Carrying Amount
Fair Value
(in millions)
Long-term debt, including current maturities
(a)
$
4,252.4
$
4,101.2
$
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.
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 June 30,
Six Months Ended June 30,
Location on the Consolidated Statements of Income
2025
2024
2025
2024
(in millions)
Gains and (losses) on cash flow hedges:
Interest rate swaps
Interest expense
$
(
0.8
)
$
(
0.7
)
$
(
1.4
)
$
(
1.4
)
Commodity contracts
Fuel, purchased power, and cost of natural gas sold
(
0.1
)
(
0.6
)
(
0.6
)
(
3.2
)
$
(
0.9
)
$
(
1.3
)
$
(
2.0
)
$
(
4.6
)
Income tax
Income tax expense
0.2
0.3
0.5
1.0
Total reclassification adjustments related to cash flow hedges, net of tax
$
(
0.7
)
$
(
1.0
)
$
(
1.5
)
$
(
3.6
)
Amortization of components of defined benefit plans:
Actuarial (loss)
Operations and maintenance
—
—
(
0.1
)
(
0.1
)
Total reclassification adjustments related to defined benefit plans, net of tax
$
—
$
—
$
(
0.1
)
$
(
0.1
)
Total reclassifications
$
(
0.7
)
$
(
1.0
)
$
(
1.6
)
$
(
3.7
)
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
—
(
0.2
)
—
(
0.2
)
Amounts reclassified from AOCI
1.1
0.4
0.1
1.6
As of June 30, 2025
$
(
2.7
)
$
(
0.1
)
$
(
5.2
)
$
(
8.0
)
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
In August 2022, President Biden signed H.R. 5376 into law, commonly known as the IRA of 2022, or IRA. The IRA contains a tax credit transferability provision that allows us to transfer (e.g. sell) PTCs produced after December 31, 2022, to third parties. In January 2025, under this transferability provision, we entered into an agreement with a third party to sell $
17.0
million of our 2024 generated PTCs.
We expect to continue to explore the ability to efficiently monetize our tax credits through third party transferability agreements.
One Big Beautiful Bill Act
On July 4, 2025, President Trump signed H.R. 1, commonly referred to as the OBBBA, a legislative package designed to permanently extend certain expiring provisions of the TCJA and deliver additional tax relief for individuals and businesses. The OBBBA introduced changes to federal energy policies by rolling back several clean energy provisions and codified restrictions related to prohibited foreign entities, termination and restrictions on clean energy PTCs, and extension and modification of clean fuel production. The OBBBA does not repeal tax credit transferability provisions enacted under the IRA and continues to permit the execution of our transferability agreements as originally agreed upon, but restricts credit transfers to prohibited foreign entities. Additionally, on July 7, 2025, President Trump issued Executive Order 14315, which relates to the implementation of such changes to energy tax credits. Further clarity is expected from the Secretaries of the Treasury and the Interior as it relates to their findings and actions taken under Executive Order 14315 within 45 days. We are currently evaluating the provisions of the OBBBA and Executive Order 14315 on our consolidated financial statements but we do not anticipate impacts to our clean energy generation facilities already in service or the execution of Colorado Electric's Clean Energy Plan.
Income Tax (Expense) and Effective Tax Rates
Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024
Income tax (expense) for the three months ended June 30, 2025, was
$(
4.4
)
million compared to
$(
3.7
)
million reported for the same period in 2024. For the three months ended June 30, 2025, the effective tax rate was
13.3
%
, which was comparable to
13.0
%
for the same period in 2024.
Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024
Income tax (expense) for the six months ended June 30, 2025, was
$(
22.5
)
million compared to
$(
20.6
)
million reported for the same period in 2024. For the six months ended June 30, 2025, the effective tax rate was
12.0
%
, which was comparable to
11.7
%
for the same period in 2024
.
(12)
Business Segme
nt 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 June 30, 2025
Electric Utilities
Gas Utilities
Corporate
and Other
Total
(in millions)
Revenue -
External Customers
$
217.5
$
221.5
$
—
$
439.0
Inter-segment
2.4
1.5
(
3.9
)
—
Total revenue
219.9
223.0
(
3.9
)
439.0
Fuel, purchased power and cost of natural gas sold
55.3
68.9
(
0.2
)
124.0
Operations and maintenance
(a)
-
Direct
36.1
38.9
(
1.7
)
73.3
Allocated
33.1
41.2
—
74.3
Depreciation and amortization
37.5
32.3
—
69.8
Taxes other than income taxes
8.9
6.2
—
15.1
Operating income (loss)
$
49.0
$
35.5
$
(
2.0
)
$
82.5
Interest expense, net
(
48.9
)
Other income (expense), net
(
0.4
)
Income tax (expense)
(
4.4
)
Net income
28.8
Net income attributable to non-controlling interest
(
1.3
)
Net income available for common stock
$
27.5
Consolidating Income Statement
Three Months Ended June 30, 2024
Electric Utilities
Gas Utilities
Corporate
and Other
Total
(in millions)
Revenue -
External Customers
$
202.1
$
200.5
$
—
$
402.6
Inter-segment
3.0
1.5
(
4.5
)
—
Total revenue
205.1
202.0
(
4.5
)
402.6
Fuel, purchased power and cost of natural gas sold
45.9
61.3
(
0.1
)
107.1
Operations and maintenance
(a)
-
Direct
37.4
38.2
(
5.7
)
69.9
Allocated
30.7
41.1
—
71.8
Depreciation and amortization
35.5
31.1
—
66.6
Taxes other than income taxes
9.3
7.3
—
16.6
Operating income
$
46.3
$
23.0
$
1.3
$
70.6
Interest expense, net
(
42.6
)
Other income (expense), net
0.4
Income tax (expense)
(
3.7
)
Net income
24.7
Net income attributable to non-controlling interest
Fuel, purchased power and cost of natural gas sold
122.5
361.4
(
0.1
)
483.8
Operations and maintenance
(a)
-
Direct
71.8
83.0
(
4.8
)
150.0
Allocated
66.2
85.1
—
151.3
Depreciation and amortization
74.6
64.4
—
139.0
Taxes other than income taxes
18.2
14.5
—
32.7
Operating income (loss)
$
103.3
$
187.0
$
(
2.9
)
$
287.4
Interest expense, net
(
100.3
)
Other income (expense), net
0.6
Income tax (expense)
(
22.5
)
Net income
165.2
Net income attributable to non-controlling interest
(
3.5
)
Net income available for common stock
$
161.7
Consolidating Income Statement
Six Months Ended June 30, 2024
Electric Utilities
Gas Utilities
Corporate
and Other
Total
(in millions)
Revenue -
External Customers
$
421.4
$
707.6
$
—
$
1,129.0
Inter-segment
5.9
3.0
(
8.9
)
—
Total revenue
427.3
710.6
(
8.9
)
1,129.0
Fuel, purchased power and cost of natural gas sold
100.8
323.2
(
0.3
)
423.7
Operations and maintenance
(a)
-
Direct
64.8
76.3
(
8.2
)
132.9
Allocated
60.7
81.6
—
142.3
Depreciation and amortization
70.8
61.5
0.2
132.5
Taxes other than income taxes
19.3
14.3
—
33.6
Operating income (loss)
$
110.9
$
153.7
$
(
0.6
)
$
264.0
Interest expense, net
(
86.7
)
Other income (expense), net
(
0.5
)
Income tax (expense)
(
20.6
)
Net income
156.2
Net income attributable to non-controlling interest
(
5.6
)
Net income available for common stock
$
150.6
(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 six months ended June 30,
2025
2024
(in millions)
Electric Utilities
$
211.8
$
185.6
Gas Utilities
153.8
190.4
Corporate and Other
4.3
4.8
Total capital expenditures
$
369.9
$
380.8
(a)
Includes accruals for property, plant, and equipment as disclosed in supplemental cash flow information in the
Consolidated Statements of Cash Flows
in the Consolidated Financial Statements. Capital expenditures are presented net of CIACs in the Consolidated Statements of Cash Flows.
(13)
Selected Balan
ce 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:
June 30, 2025
December 31, 2024
(in millions)
Billed Accounts Receivable
$
180.9
$
201.5
Unbilled Revenue
83.6
151.8
Less: Allowance for Credit Losses
(
3.7
)
(
2.1
)
Account Receivable, net
$
260.8
$
351.2
Changes to allowance for credit losses for the
six months ended June 30, 2025 and 2024, respectively, were as follows:
Balance at Beginning of Year
Additions Charged to Costs and Expenses
Recoveries and Other Additions
Write-offs and Other Deductions
Balance at June 30,
(in millions)
2025
$
2.1
$
4.4
$
1.6
$
(
4.4
)
$
3.7
2024
$
2.2
$
2.7
$
1.8
$
(
3.6
)
$
3.1
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:
June 30, 2025
December 31, 2024
(in millions)
Materials and supplies
$
113.4
$
106.1
Fuel - Electric Utilities
6.7
7.5
Natural gas in storage
25.1
40.3
Total materials, supplies, and fuel
$
145.2
$
153.9
Accrued Liabilities
The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance Sheets as of:
June 30, 2025
December 31, 2024
(in millions)
Accrued employee compensation, benefits, and withholdings
Except as described in Notes
2
and
11
, there have been no events subsequent to June 30, 2025
, which would require recognition in the Consolidated Financial Statements or disclosures.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussions should be read in conjunction with the Notes contained herein and Management's Discussion and Analysis of Financial Condition and Results of Operations appearing in our 2024 Annual Report on Form 10-K
Executive Summary
We are a customer-focused energy solutions provider with a mission of
Improving Life with Energy
for more than 1.35 million customers and 800+ communities we serve. Our aspiration is to be the trusted energy partner across our growing eight-state footprint, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota, and Wyoming. Our strategy is centered on four priorities:
People & Culture
—build a team that wins together,
Operational Excellence—
relentlessly deliver on our commitment to serve our customers,
Transformation
—be a simple and connected company and
Growth—
grow to be a dominant long-term energy provider.
We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other. We conduct our utility operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. We consider ourselves a domestic electric and natural gas utility company.
We have provided energy and served customers for 141 years, since the 1883 gold rush days in Deadwood, South Dakota. Throughout our history, the common thread that unites the past to the present is our commitment to serve our customers and communities. By being responsive and service focused, we can help our customers and communities thrive while meeting rapidly changing customer expectations.
Recent Developments
One Big Beautiful Bill Act
On July 4, 2025, the OBBBA was enacted and on July 7, 2025, President Trump issued Executive Order 14315. See
Note 11
of the Condensed Notes to Consolidated Financial Statements for further discussion surrounding the OBBBA and Executive Order 14315.
Trade Tariffs
Trade tariffs were recently enacted and proposed to be enacted through presidential executive orders affecting products exported by several U.S. trading partners. While some tariffs scheduled to take effect were temporarily suspended, broad tariffs remain in effect with the possibility of additional tariffs being imposed. We are currently unable to predict the impact that recently imposed and possible future tariffs may have on our business. Trade tariffs have not had a material impact on our operations or financial performance to date. We are closely monitoring the impacts of trade tariffs and the potential effect they may have on our financial position, results of operations, or cash flows.
Business Segment Recent Developments
Electric Utilities
•
See
Note 2
of the Condensed Notes to Consolidated Financial Statements for recent rate review activity for Colorado Electric.
•
On March 6, 2025, the state of Wyoming enacted comprehensive wildfire mitigation legislation (HB0192), effective July 1, 2025. The legislation provides material liability protections for a utility that complies with its commission-approved wildfire mitigation plan. The legislation provides a utility a presumption of meeting an appropriate level of operating care for compliance with an approved wildfire mitigation plan. We plan to file our wildfire mitigation plan with the WPSC in the second half of 2025.
•
In 2024, we published our first formal WMP, which is an overview of our three-layered approach to manage wildfire risks driven by asset-based risk assessments that include asset programs, integrity programs and operational response. On June 30, 2025, we established our Emergency PSPS program across all three of our electric utilities to promote customer safety and mitigate wildfire risk. In establishing the Emergency PSPS program, we engaged with wildfire experts and key stakeholders including customers, community and local agencies, regulators and community leaders.
•
In the first half of 2025, Wyoming Electric set four new all-time peak loads, including an all-time peak of 379 MW on June 20, 2025. Prior to 2025, the previous all-time peak was 314 MW set on January 11, 2024.
During the second quarter of 2025, Colorado Electric continued to advance 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. On June 12, 2025, Colorado Electric filed a CPCN for the battery storage project and expects a CPUC decision by year-end 2025. Negotiations with counterparties for the other two projects are ongoing, which will drive final cost and timing of projects.
•
On March 28, 2025, South Dakota Electric filed a request with the WPSC for the Lange II project, which was approved in June 2025. The new facility is scheduled to begin construction in the third quarter of 2025 and to be in service by the second half of 2026.
•
During the second quarter of 2025, Wyoming Electric continued construction of its approximately 260-mile, $350 million Ready Wyoming electric transmission expansion project. The project is on track to be completed and in service by year end 2025.
Gas Utilities
•
See
Note 2
of the Condensed Notes to Consolidated Financial Statements for recent rate review activity for Iowa Gas, Kansas Gas and Nebraska Gas.
Corporate and Other
•
See
Note 5
of the Condensed Notes to Consolidated Financial Statements for our corporate Revolving Credit Facility and ATM program activity.
•
During the second quarter of 2025, we published our 2024 Corporate Sustainability, highlighting our environmental, social and governance impacts and our progress on major projects and climate goals.
•
On January 17, 2025, Fitch affirmed BHC's long-term issuer rating at BBB+ with a negative outlook. Following the affirmation, the parties jointly withdrew the rating. See
Liquidity and Capital Resources
section below for additional information on our credit ratings.
Results of Operations
Certain lines of business in which we operate are highly seasonal, and revenue from, and certain expenses for, such operations may fluctuate significantly among quarterly periods. Demand for electricity and natural gas is sensitive to seasonal cooling, heating and industrial load requirements. In particular, the normal peak usage season for our Electric Utilities is June through August while the normal peak usage season for our Gas Utilities is November through March. Significant earnings variances can be expected between the Gas Utilities segment’s peak and off-peak seasons. Due to this seasonal nature, our results of operations for the three and six months ended June 30, 2025, and 2024, and our financial condition as of June 30, 2025, and December 31, 2024, are not necessarily indicative of the results of operations and financial condition to be expected as of or for any other period or for the entire year.
All amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in amounts may result due to rounding.
Net income attributable to non-controlling interest
(1.3
)
(1.9
)
0.6
(3.5
)
(5.6
)
2.1
Net income available for common stock
$
27.5
$
22.8
$
4.7
$
161.7
$
150.6
$
11.1
Weighted average common shares outstanding, Diluted
72.4
69.0
3.4
72.1
68.7
3.4
Total earnings per share of common stock, Diluted
$
0.38
$
0.33
$
0.05
$
2.24
$
2.19
$
0.05
(a)
Includes inter-segment eliminations.
Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024
The variance to the prior year included the following:
•
Electric Utilities' operating income increased $2.7 million primarily due to new rates and rider recovery partially offset by higher operating expenses;
•
Gas Utilities' operating income increased $12.5 million primarily due to new rates and rider recovery driven by the Arkansas Gas and Iowa Gas rate reviews and favorable weather;
•
Corporate and Other operating loss increased $3.3 million primarily due to a prior year gain on the sale of a Corporate asset and higher unallocated outside services expenses; and
•
Interest expense increased $6.3 million primarily due to higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances.
Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:
The variance to the prior year included the following:
•
Electric Utilities’ operating income decreased $7.6 million primarily due to higher operating expenses and current year unplanned generation outages partially offset by new rates and rider recovery;
•
Gas Utilities’ operating income increased $33.3 million primarily due to new rates and rider recovery driven by the Arkansas Gas, Iowa Gas and Colorado Gas rate reviews and favorable weather partially offset by higher operating expenses;
•
Corporate and Other operating loss increased $2.3 million primarily due to a prior year gain on the sale of a Corporate asset and higher unallocated outside services expenses;
•
Interest expense increased $13.6 million primarily due to higher CP Program borrowings and lower interest income on lower cash and cash equivalents balances; and
•
Net income attributable to non-controlling interest decreased $2.1 million due to lower net income from Black Hills Colorado IPP primarily driven by current year unplanned generation outages.
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 June 30,
Six Months Ended June 30,
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025
2024
2025
2024
2025
2024
(in millions)
Revenue
$
219.9
$
205.1
$
456.6
$
427.3
$
223.0
$
202.0
$
795.4
$
710.6
Fuel, purchased power and cost of natural gas sold
(55.3
)
(45.9
)
(122.5
)
(100.8
)
(68.9
)
(61.3
)
(361.4
)
(323.2
)
Operations and maintenance
(a)
(43.8
)
(42.5
)
(85.7
)
(78.5
)
(40.7
)
(42.3
)
(86.9
)
(85.1
)
Depreciation and amortization
(37.5
)
(35.5
)
(74.6
)
(70.8
)
(32.3
)
(31.1
)
(64.4
)
(61.5
)
Taxes other than income taxes
(8.9
)
(9.3
)
(18.2
)
(19.3
)
(6.2
)
(7.3
)
(14.5
)
(14.3
)
Gross margin (GAAP)
$
74.4
$
71.9
$
155.6
$
157.9
$
74.9
$
60.0
$
268.2
$
226.5
Operations and maintenance
(a)
43.8
42.5
85.7
78.5
40.7
42.3
86.9
85.1
Depreciation and amortization
37.5
35.5
74.6
70.8
32.3
31.1
64.4
61.5
Taxes other than income taxes
8.9
9.3
18.2
19.3
6.2
7.3
14.5
14.3
Electric and Gas Utility margin (non-GAAP)
$
164.6
$
159.2
$
334.1
$
326.5
$
154.1
$
140.7
$
434.0
$
387.4
(a)
Operations and maintenance expenses which are deemed to be directly attributable to revenue-producing activities include plant operations and maintenance expenses at our electric generation facilities, operations and maintenance expenses at our WRDC coal mine, and electric and gas transmission and distribution expenses. These amounts are included in the table above to calculate gross margin in accordance with GAAP. These amounts excluded operations and maintenance expenses not directly attributable to revenue-producing activities of $25.4 million, $25.6 million, 52.3 million, and $47.0 million for the three and six months ended June 30, 2025 and 2024, respectively, for the Electric Utilities and $39.4, $37.0, $81.2 million, and $72.8 million for the three and six months ended June 30, 2025 and 2024, respectively, for the Gas Utilities.
Operating results for the Electric Utilities were as follows:
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025 vs 2024 Variance
2025
2024
2025 vs 2024 Variance
(in millions)
Revenue
$
219.9
$
205.1
$
14.8
$
456.6
$
427.3
$
29.3
Fuel and purchased power
55.3
45.9
9.4
122.5
100.8
21.7
Electric Utility margin (non-GAAP)
(a)
164.6
159.2
5.4
334.1
326.5
7.6
Operations and maintenance
69.2
68.1
1.1
138.0
125.5
12.5
Depreciation and amortization
37.5
35.5
2.0
74.6
70.8
3.8
Taxes other than income taxes
8.9
9.3
(0.4
)
18.2
19.3
(1.1
)
115.6
112.9
2.7
230.8
215.6
15.2
Operating income
$
49.0
$
46.3
$
2.7
$
103.3
$
110.9
$
(7.6
)
(a)
See Non-GAAP Financial Measures section above for reconciliation to Gross margin, the most directly comparable GAAP measure.
Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024:
Electric Utility margin
increased as a result of the following:
(in millions)
New rates and rider recovery
$
5.0
Weather
(0.8
)
Other
1.2
$
5.4
Operations and maintenance expense
was comparable to the same period in the prior year.
Depreciation and amortization
increased primarily due to higher asset base driven by capital expenditures.
Taxes other than income taxes
was comparable to the same period in the prior year.
Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:
Electric Utility margin
increased as a result of the following:
(in millions)
New rates and rider recovery
$
6.8
Retail customer growth and usage
3.0
Weather
0.4
Off-system excess energy sales
(0.8
)
Other
(1.8
)
$
7.6
Operations and maintenance expense
increased primarily due to $5.3 million of expenses related to unplanned generation outages, $4.1 million of higher outside services expenses and $2.3 million of higher insurance expense.
Depreciation and amortization
increased primarily due to higher asset base driven by capital expenditures.
Taxes other than income taxes
was comparable to the same period in the prior year.
The increase in industrial revenues and quantities sold for the three and six months ended June 30, 2025, compared to the same periods in 2024, was primarily driven by Wyoming Electric LPCS Tariff and BCIS Tariff customers.
(b)
Includes Integrated Generation, inter-segment rent, and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.
(c)
Includes company uses and line losses.
Revenue
Quantities Sold
Three Months Ended June 30,
Six Months Ended June 30,
Three Months Ended June 30,
Six Months Ended June 30,
By Business Unit
2025
2024
2025
2024
2025
2024
2025
2024
(in millions)
(in GWh)
Colorado Electric
$
66.3
$
64.1
$
138.7
$
133.8
524.1
585.7
1,056.4
1,141.4
South Dakota Electric
78.0
75.9
164.9
156.5
638.9
591.4
1,320.9
1,212.5
Wyoming Electric
64.8
55.6
131.4
116.4
665.2
549.5
1,311.0
1,124.7
Integrated Generation
10.8
9.5
21.6
20.6
18.9
21.1
48.2
49.1
Total Revenue and Quantities Sold
$
219.9
$
205.1
$
456.6
$
427.3
1,847.1
1,747.7
3,736.5
3,527.7
Three Months Ended June 30,
Six Months Ended June 30,
Quantities Generated and Purchased by Fuel Type
2025
2024
2025
2024
(in GWh)
Generated:
Coal
(a)
457.4
478.1
1,057.3
1,158.8
Natural Gas and Oil
(b)
585.3
451.5
1,097.4
974.9
Wind
135.4
161.7
310.8
335.7
Total Generated
1,178.1
1,091.3
2,465.5
2,469.4
Purchased:
Coal, Natural Gas, Oil, and Other Market Purchases
470.8
350.6
846.5
639.5
Wind and Solar
323.6
330.9
644.0
545.7
Total Purchased
(c)
794.4
681.5
1,490.5
1,185.2
Total Generated and Purchased
1,972.5
1,772.8
3,956.0
3,654.6
(a)
The decrease in coal generation for the three and six months ended June 30, 2025, compared to the same period in 2024 is primarily due to unplanned outages at Wygen III.
(b)
The increase in natural gas and oil generation for the three and six months ended June 30, 2025, compared to the same periods in 2024, was primarily due to the timing and extent of unplanned outages at Pueblo Airport Generation #4-5.
(c)
The increase in total purchases for the three and six months ended June 30, 2025, compared to the same periods in 2024, was primarily driven by increased demand from Wyoming Electric LPCS Tariff and BCIS Tariff customers and unplanned outages at Wygen III as discussed in (a) above.
The shift in South Dakota Electric's generated and purchased GWh for the six months ended June 30, 2025, compared to the same period in 2024 is primarily driven by unplanned outages at Wygen III.
(b)
As discussed in footnote (c) in the Quantities Generated and Purchased by Fuel Type table above, the increase in Wyoming Electric's purchases is primarily driven by increased demand from LPCS Tariff and BCIS Tariff customers.
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025
2024
Degree Days
Actual
Variance from Normal
Actual
Variance from Normal
Actual
Variance from Normal
Actual
Variance from Normal
Heating Degree Days:
Colorado Electric
623
5%
524
(12)%
3,356
8%
3,031
(7)%
South Dakota Electric
908
(12)%
898
(15)%
4,346
1%
4,032
(10)%
Wyoming Electric
1,085
(5)%
1,040
(10)%
4,225
2%
4,026
(7)%
Combined
(a)
815
(5)%
757
(13)%
3,875
4%
3,577
(8)%
Cooling Degree Days:
Colorado Electric
235
(16)%
343
25%
235
(16)%
343
25%
South Dakota Electric
162
41%
114
8%
162
41%
114
8%
Wyoming Electric
60
(24)%
118
75%
60
(24)%
118
75%
Combined
(a)
174
(4)%
219
25%
174
(4)%
219
25%
(a)
Degree days are calculated based on a weighted average of total customers by state.
Three Months Ended June 30,
Six Months Ended June 30,
Contracted generating facilities Availability
(a)
by fuel type
2025
2024
2025
2024
Coal
79.4%
75.5%
82.7%
85.6%
Natural gas and diesel oil
93.2%
91.6%
92.4%
94.1%
Wind
78.6%
92.1%
82.4%
91.2%
Total Availability
(b)
87.2%
87.1%
88.1%
91.3%
Wind Capacity Factor
(a)
31.1%
36.9%
35.5%
38.4%
(a)
Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
(b)
2025 included unplanned outages at Wygen III, Pueblo Airport Generation #4-5 and Busch Ranch I and II. 2024 included unplanned outages at Wygen I and Pueblo Airport Generation #4-5.
Operating results for the Gas Utilities were as follows:
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025 vs 2024 Variance
2025
2024
2025 vs 2024 Variance
(in millions)
Revenue
$
223.0
$
202.0
$
21.0
$
795.4
$
710.6
$
84.8
Cost of natural gas sold
68.9
61.3
7.6
361.4
323.2
38.2
Gas Utility margin (non-GAAP)
(a)
154.1
140.7
13.4
434.0
387.4
46.6
Operations and maintenance
80.1
79.3
0.8
168.1
157.9
10.2
Depreciation and amortization
32.3
31.1
1.2
64.4
61.5
2.9
Taxes other than income taxes
6.2
7.3
(1.1
)
14.5
14.3
0.2
118.6
117.7
0.9
247.0
233.7
13.3
Operating income
$
35.5
$
23.0
$
12.5
$
187.0
$
153.7
$
33.3
(a)
See Non-GAAP Financial Measures section above for reconciliation to Gross margin, the most directly comparable GAAP measure.
Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024:
Gas Utility margin
increased as a result of the following:
(in millions)
New rates and rider recovery
$
9.9
Weather
3.3
Mark-to-market on non-utility natural gas commodity contracts
(0.6
)
Other
0.8
$
13.4
Operations and maintenance expense
was comparable to the same period in the prior year.
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.
Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:
Gas Utility margin
increased as a result of the following:
(in millions)
New rates and rider recovery
$
36.7
Weather
12.0
Other
(2.1
)
$
46.6
Operations and maintenance expense
increased primarily due to $4.4 million of higher employee related expenses, $3.6 million of higher insurance expense, and $1.5 million of higher bad debt expense driven by increased revenues and lower prior year write-offs.
Depreciation and amortization
increased primarily due to higher asset base driven by capital expenditures.
Taxes other than income taxes
was comparable to the same period in the prior year.
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.
Revenue
Quantities Sold and Transported
Three Months Ended June 30,
Six Months Ended June 30,
Three Months Ended June 30,
Six Months Ended June 30,
By Business Unit
2025
2024
2025
2024
2025
2024
2025
2024
(in millions)
(Dth in millions)
Arkansas Gas
$
40.7
$
31.2
$
165.5
$
141.8
5.3
5.0
18.5
17.0
Colorado Gas
39.0
42.3
154.8
160.0
5.2
5.1
18.4
18.0
Iowa Gas
30.1
27.6
116.9
89.4
6.9
7.1
22.1
20.6
Kansas Gas
25.1
20.9
91.2
71.2
7.6
7.9
19.3
17.6
Nebraska Gas
57.9
50.4
188.1
164.7
16.4
14.5
46.1
41.6
Wyoming Gas
30.2
29.6
78.9
83.5
7.4
7.5
20.6
20.7
Total Revenue and Quantities Sold
$
223.0
$
202.0
$
795.4
$
710.6
48.8
47.1
145.0
135.5
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025
2024
Heating Degree Days
Actual
Variance from Normal
Actual
Variance from Normal
Actual
Variance from Normal
Actual
Variance from Normal
Arkansas Gas
(a)
193
(33)%
144
(54)%
2,150
(2)%
1,916
(17)%
Colorado Gas
822
(5)%
790
(9)%
3,659
---
3,533
(5)%
Iowa Gas
640
(5)%
507
(27)%
3,928
(1)%
3,405
(18)%
Kansas Gas
(a)
367
(9)%
266
(37)%
2,983
7%
2,557
(11)%
Nebraska Gas
553
(9)%
457
(26)%
3,592
---
3,259
(12)%
Wyoming Gas
1,110
(7)%
1,096
(9)%
4,433
1%
4,252
(5)%
Combined
(b)
658
(8)%
587
(20)%
3,740
---
3,452
(10)%
(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 operating results, including inter-segment eliminations, were as follows:
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025 vs 2024 Variance
2025
2024
2025 vs 2024 Variance
(in millions)
Operating income (loss)
$
(2.0
)
$
1.3
$
(3.3
)
$
(2.9
)
$
(0.6
)
$
(2.3
)
Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024:
Operating loss increased primarily due to a prior year gain on the sale of a Corporate asset and higher unallocated outside services expenses.
Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:
Operating loss increased primarily due to a prior year gain on the sale of a Corporate asset and higher unallocated outside services expenses.
Consolidated Interest Expense, Other Income and Income Tax Expense
Three Months Ended June 30,
Six Months Ended June 30,
2025
2024
2025 vs 2024 Variance
2025
2024
2025 vs 2024 Variance
(in millions)
Interest expense, net
$
(48.9
)
$
(42.6
)
$
(6.3
)
$
(100.3
)
$
(86.7
)
$
(13.6
)
Other income (expense), net
(0.4
)
0.4
(0.8
)
0.6
(0.5
)
1.1
Income tax (expense)
(4.4
)
(3.7
)
(0.7
)
(22.5
)
(20.6
)
(1.9
)
Three Months Ended June 30, 2025, Compared to the Three Months Ended June 30, 2024:
Interest expense, net
increased primarily due to higher interest rates on long-term debt, higher CP Program borrowings 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 June 30, 2025, the effective tax rate was 13.3%, which was comparable to 13.0% for the same period in 2024.
Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024:
Interest expense, net
increased primarily due to higher interest rates on long-term debt, higher CP Program borrowings 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 six months ended June 30, 2025, the effective tax rate was 12.0%, which was comparable to 11.7% for the same period in 2024.
The following table provides an informational summary of our liquidity and capital structure as of:
June 30, 2025
December 31, 2024
(dollars in millions)
Cash and cash equivalents
$
8.1
$
16.1
Available capacity under Revolving Credit Facility and CP Program
(a)
622.8
612.7
Available liquidity
$
630.9
$
628.8
Capital structure
Short-term debt
(b)
$
423.7
$
133.8
Long-term debt
3,952.4
4,250.2
Total debt
4,376.1
4,384.0
Total stockholders' equity (excludes non-controlling interest)
3,636.1
3,501.5
Total capitalization
$
8,012.2
$
7,885.5
Debt to capitalization
54.6
%
55.6
%
Long-term debt to total debt
90.3
%
96.9
%
(a)
Available capacity under Revolving Credit Facility and CP Program represents $750 million of total borrowing capacity less outstanding borrowings and letters of credit. See
Note 5
of the Notes to Consolidated Financial Statements for more information.
(b)
Short-term debt includes our $300 million, 3.95% senior unsecured notes due January 2026.
Future Financing Plans
We plan to fund our capital plan and strategic objectives by using cash generated from operating activities and various financing alternatives, which could include our Revolving Credit Facility, our CP Program, and the issuance of common stock under our ATM or in a secondary offering. We plan to re-finance our $300 million, 3.95%, senior unsecured notes due January 2026, at or before maturity date.
C
ASH FLOW ACTIVITIES
The following tables summarize our cash flows for the six months ended June 30, 2025:
Operating Activities:
Six Months Ended June 30,
2025
2024
2025 vs 2024 Variance
(in millions)
Net income
$
165.2
$
156.2
$
9.0
Non-cash adjustments to Net income
195.0
181.6
13.4
Total earnings
$
360.2
$
337.8
$
22.4
Changes in certain operating assets and liabilities:
Materials, supplies and fuel, Accounts receivable and other current assets
93.2
146.1
(52.9
)
Accounts payable and other current liabilities
(93.3
)
(77.4
)
(15.9
)
Regulatory assets
57.9
69.8
(11.9
)
Net inflow (outflow) from changes in certain operating assets and liabilities
$
57.8
$
138.5
$
(80.7
)
Other operating activities
(1.6
)
(12.3
)
10.7
Net cash provided by operating activities
$
416.4
$
464.0
$
(47.6
)
Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024
Net cash provided by operating activities was $47.6 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 $22.4 million higher for the six months ended June 30, 2025, compared to the same period in the prior year primarily as a result of increased Electric and Gas Utility margins due to new rates and rider recovery partially offset by higher operating expenses and higher financing costs.
Net inflows from changes in certain operating assets and liabilities were $80.7 million lower, primarily attributable to:
o
Cash inflows decreased by approximately $52.9 million as a result of changes in accounts receivable and other current assets primarily driven by fluctuations in commodity prices;
o
Cash outflows increased by approximately $15.9 million as a result of increases in accounts payable and other current liabilities primarily driven by fluctuations in commodity prices, remediation costs for our manufactured gas plant site in Iowa and changes in other working capital requirements; and
o
Cash inflows decreased by approximately $11.9 million as a result of changes in our regulatory assets and liabilities primarily due to lower recoveries of our Winter Storm Uri regulatory asset as recovery is now complete in several of our jurisdictions.
•
Cash outflows decreased $10.7 million from other operating activities primarily due to lower costs from cloud computing arrangements.
Investing Activities:
Six Months Ended June 30,
2025
2024
2025 vs 2024 Variance
(in millions)
Capital expenditures
$
(371.8
)
$
(342.4
)
$
(29.4
)
Other investing activities
(4.4
)
1.7
(6.1
)
Net cash (used in) investing activities
$
(376.2
)
$
(340.7
)
$
(35.5
)
Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024
Net cash used in investing activities was $35.5 million higher than the same period in 2024. The variance to the prior year was primarily attributable to:
•
Cash outflows from capital expenditures (which are net of contributions in aid of construction) increased $29.4 million primarily as a result of the Ready Wyoming and Lange II projects and prior year receipts related to contributions in aid of construction for data center projects in Wyoming; and
•
Cash outflows increased by $6.1 million for other investing activities primarily due to higher AFUDC debt driven by higher construction work-in-progress balances and prior year proceeds from the sale of a Corporate asset.
Financing Activities:
Six Months Ended June 30,
2025
2024
2025 vs 2024 Variance
(in millions)
Dividends paid on common stock
$
(97.6
)
$
(89.3
)
$
(8.3
)
Common stock issued
65.0
73.0
(8.0
)
Short-term and long-term debt borrowings (repayments), net
(10.1
)
450.0
(460.1
)
Distributions to non-controlling interests
(3.8
)
(10.0
)
6.2
Other financing activities
(1.3
)
(8.3
)
7.0
Net cash provided by (used in) financing activities
$
(47.8
)
$
415.4
$
(463.2
)
Six Months Ended June 30, 2025, Compared to the Six Months Ended June 30, 2024
Net cash used in financing activities was $463.2 million higher than the same period in 2024. The variance to the prior year was primarily attributable to:
•
Dividends paid on common stock increased $8.3 million due to the increased dividend rate per share and increased number of common shares outstanding;
•
Cash inflows decreased $8.0 million due to lower issuances of common stock;
•
Net cash outflows increased $460.1 million as a result of net repayment activity under our Revolving Credit Facility and CP Program and prior year proceeds from the May 16, 2024, debt offering;
Distributions to non-controlling interests decreased $6.2 million due to lower net income from Black Hills Colorado IPP primarily driven by unplanned generation outages; and
•
Cash outflows decreased $7.0 million from other financing activities primarily due to prior year financing costs from the May 2024 debt offering.
C
APITAL RESOURCES
See
Note 5
of the Condensed Notes to Consolidated Financial Statements for recent financing updates and financial covenants information.
C
REDIT 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.
C
APITAL REQUIREMENTS
Capital Expenditures
Actual
(a)
Forecasted
(b)
Capital Expenditures by Segment
(minor differences may result due to rounding)
Six Months Ended
June 30, 2025
2025
(c)
2026
2027
2028
2029
(in millions)
Electric Utilities
$
212
$
550
$
432
$
383
$
615
$
435
Gas Utilities
154
431
386
412
447
447
Corporate and Other
4
21
41
27
27
27
$
370
$
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 six months ended June 30, 2025.
Common Stock Dividends
Dividends paid on our common stock totaled $97.6 million for the six months ended June 30, 2025, or $0.676 per share. On July 22, 2025, our board of directors declared a quarterly dividend of $0.676 per share payable September 2, 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.
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 June 30, 2025.
New Accounting Pronouncements
See
Note 1
of the Condensed Notes to Consolidated Financial Statements for a description of recent accounting pronouncements, if any, and our expectation of their impact on our results of operations and financial condition.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There have been no material changes to our quantitative and qualitative disclosures about market risk previously disclosed in Item 7A of our 2024 Annual Report on Form 10-K.
ITEM 4. CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) as of June 30, 2025. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective at June 30, 2025.
Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Changes in Internal Control over Financial Reporting
During the quarter ended June 30, 2025, there have been no changes in our internal controls over financial reporting that have materially affected, or are reasonably likely, to materially affect our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding legal proceedings, see
Note 3
of the Condensed Notes to Consolidated Financial Statements and Note 3 in Item 8 of our 2024 Annual Report on Form 10-K.
ITEM 1A. RISK FACTORS
There are no material changes to the risk factors previously disclosed in Item 1A of Part I in our 2024 Annual Report on Form 10-K.
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 June 30, 2025:
Period
Total Number of Shares Purchased
(a)
Average Price Paid per Share
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
April 1, 2025 - April 30, 2025
1
$
60.83
—
—
May 1, 2025 - May 31, 2025
745
61.50
—
—
June 1, 2025 - June 30, 2025
1
58.44
—
—
Total
747
$
61.49
—
—
(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.
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
June 30, 2025.
ITEM 6. EXHIBITS
Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior filing, as indicated.
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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.
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