2023
BLACK HILLS
CORPORATION
2023 Annual Report | Proxy Statement | Form 10-K
B
K
H
BLACK HILLS
CORPORATION
We are a customer focused, growth-oriented utility company with a tradition of
exemplary service and a vision to be the energy partner of choice. Based in Rapid
City, South Dakota, the company serves over 1.3 million electric and natural gas
utility customers in 824 communities in Arkansas, Colorado, Iowa, Kansas, Montana,
Nebraska, South Dakota and Wyoming. Employees partner to produce results that
improve life with energy.
Arkansas
186,200 utility customers
Kansas
119,400 utility customers
South Dakota
76,500 utility customers
100 communities served
67 communities served
Colorado
311,900 utility customers
119 communities served
617 megawatts of
owned power
generation capacity
Iowa
163,300 utility customers
133 communities served
Montana
44 utility customers
2 communities served
Nebraska
302,200 utility customers
319 communities served
29 communities served
150 megawatts of
owned power
generation capacity
Wyoming
179,100 utility customers
56 communities served
174 million tons of
coal reserves
627 megawatts of
owned power
generation capacity
Electric Utilities
Natural Gas Utilities
Power Generation
Wind Generation
Electric and Natural Gas Utilities
Company Headquarters
Mine
Renewable natural gas interconnection sites
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Dear shareholders,
At Black Hills Corporation, we provide essential energy to 1.34 million electric and natural gas
customers across eight states. Through a rapidly changing economic and business environment,
our team is dedicated to delivering the safe, reliable, and cost-effective service our customers and
communities depend upon every day.
During 2023, we delivered on our objectives of excellent operational performance and solid
financial results. We strengthened our financial position and advanced our regulatory, growth and
resiliency initiatives, setting the stage for future growth.
Reliable. Resilient. Ready.
Our mission of improving life with energy is accomplished every day as a dependable energy
provider within the communities we live and operate. In 2023, our team delivered more than 7,000
gigawatt hours of electricity and 95 million dekatherms of natural gas to our utility customers. Our
resilient team and infrastructure continued to advance our reputation for excellent service as we
continued to invest in the core needs for the safety and reliability of our systems and successfully
reduced third-party damages to our natural gas system by nearly 10%.
In addition, we continued to support customer and community growth and delivered innovative
solutions for both new and existing customers. This growing demand was reflected through our
tenth consecutive year of new all-time peaks at Wyoming Electric, representing an increase of
nearly 70% in peak demand over the last decade.
Our long-standing commitment to shareholders is also reflected in our 53 consecutive years of
annual dividend increases and 83 years of uninterrupted dividend payout. This track record of
sustainable growth through numerous economic cycles, global wars and uncertainties is one of the
longest in the electric and natural gas utility industry.
A firm foundation
Being ready for the needs of customers is the result of our customer-focused culture and is
supported by a solid financial foundation. We delivered on our commitment to strengthen our
financial position in 2023 as we improved our net debt to total capitalization ratio to 57.3% and
maintained our BBB+ equivalent credit ratings. Our financial progress in the face of a changing
economic environment was no easy feat, as we flexed the organization to achieve our objectives,
www.blackhillscorp.com
including conserving capital and managing expenses while executing on what was necessary to
deliver on our commitments for our customers and shareholders.
As we invested in the resiliency and modernization of our infrastructure for the core needs of our
customers, we continued to develop strategic growth projects. Looking forward, our $4.3 billion
capital plan for 2024 through 2028 is focused on critical needs for reliability, system integrity,
electric transmission and new renewable generation.
We commenced construction of our 260-mile Ready Wyoming electric transmission expansion
project to stabilize long-term costs for customers, enhance energy market access and capacity,
and interconnect our electric systems in Cheyenne and our jointly operated South Dakota and
Wyoming system.
During the year, we reached the final stages of our integrated resource plan for our jointly operated
South Dakota and Wyoming system. In 2023, we issued a request for proposals to add 100
megawatts of utility-owned renewable generation to our system by mid-2026.
We made great progress on our Clean Energy Plan to support Colorado’s decarbonization goals of
80% reduction in emissions by 2030 off a 2005 baseline. We issued a request for proposals to add
400 megawatts of renewable resources by 2029.
We also successfully served expanding data center and blockchain energy demand, a growing
and important piece of our business, and a benefit to our other customers and local communities
in Wyoming.
Looking to the horizon
Our strategic objectives, including Growth and Financial Performance, Operational Excellence,
Transformation and People and Culture provide clarity around our goal of growing long-term value
and serving our stakeholders effectively and efficiently. Our vision, mission and values embodied by
our unique team and culture are the foundation for our sustainable success and the driving force for
growing long-term value for our stakeholders.
www.blackhillscorp.com
Connecting the dots
Connecting our past success to a vibrant future is based in keeping our customers connected and
safe. During 2023, we once again delivered reliable service, with all three of our electric utilities in
the upper tier of reliability as reported by the Edison Electric Institute, with two of our utilities in the
top quartile of rankings for minimizing customer outage minutes.
We take pride in connecting to our stakeholders within our communities, cultivating relationships
and long-term business development. We work closely with our customers and communities,
developing innovative solutions such as our unique tariffs to serve data centers and large blockchain
customers, tailoring our service to their needs.
Our coworkers are also connected within our communities. We are proud to encourage and enable
our employees to volunteer and engage locally. Our company and employees support a wide range
of local nonprofit organizations with financial support, volunteer hours, serving on local community
boards and much more. We were also recognized for our employment of veterans, and we value the
benefits of their experience and leadership within our organization.
Our connections and interactions with utility regulators across our states are constructive and
supportive of the needs of our customers. Over the last year, we negotiated settlements in three
different rate reviews and continued to manage positive relationships with regulatory bodies
across our service footprint. Our culture of transparency and proactive communication builds
long-term trust and education about our goals, demonstrates the prudency of the decisions we are
making for our customers, and promotes fair and timely recovery of investments and costs required
to serve customers.
Growing long-term value
As we execute on our opportunities to sustainably grow long-term value for all our stakeholders, we
thank you for the confidence and trust you have placed in our company to continue improving lives
with energy.
Sincerely,
Steve Mills,
Chairman, Black Hills Corp. Board of Directors
Linn Evans,
President and CEO, Black Hills Corp.
www.blackhillscorp.com
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PROXY BLACK HILLS CORPORATION
Notice of 2024
Annual Meeting of Shareholders
and Proxy Statement
PROXY
(This page has been left blank intentionally.)
PROXY BLACK HILLS CORPORATION
NOTICE OF ANNUAL MEETING OF SHAREHOLDERS
WHEN:
Tuesday, April 23, 2024
9:30 a.m., local time
WHERE:
Horizon Point
Company’s Corporate Headquarters
7001 Mount Rushmore Road
Rapid City, South Dakota 57702
We are pleased to invite you to attend the annual meeting of shareholders of Black Hills Corporation.
In the event it is not possible to attend our annual meeting in person, we encourage you to listen to the meeting by calling in:
605-782-9484, Conference ID: 604 530 619#. The presentation for this meeting can be located at www.ir.blackhillscorp.com by
clicking on "Events and Presentations" in the "Investor Relations" section. The presentation will be posted on the website before
the call. Please note, if you attend by calling in, you will not be able to vote your shares or submit questions. Accordingly, it is
important that you vote your shares as instructed below.
Proposals:
Election of four directors in Class III: Linden R. Evans, Barry M. Granger, Tony A. Jensen, and Steven R. Mills.
Ratification of Deloitte & Touche LLP to serve as our independent registered public accounting firm for 2024.
Advisory vote to approve our executive compensation.
1.
2.
3.
4. Any other business that properly comes before the annual meeting.
Record Date:
The Board set March 4, 2024 as the record date for the meeting. This means that our shareholders as of the close of business
on that date are entitled to receive this notice of the meeting and vote at the meeting and any adjournments or postponements of
the meeting.
How to Vote:
Your vote is very important. You may vote your shares by telephone, by the Internet or by returning the enclosed proxy. If you
own shares of common stock other than the shares shown on the enclosed proxy, you will receive a proxy in a separate
envelope for each such holding. Please vote each proxy received. To make sure that your vote is counted if voting by mail, you
should allow enough time for the postal service to deliver your proxy before the meeting.
Sincerely,
/s/ AMY K. KOENIG
Amy K. Koenig
Vice President - Governance, Corporate Secretary and Deputy General Counsel
PROXY
PROXY SUMMARY
BLACK HILLS CORPORATION OVERVIEW
We are a customer-focused energy solution provider that invests in our communities’ safety, sustainability and growth with a
mission of Improving Life with Energy and a vision to be the Energy Partner of Choice. The Company’s core mission – and our
primary focus – is to provide safe, reliable and cost-effective electric and natural gas service to more than 1.3 million utility
customers in over 800 communities in eight states, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South
Dakota and Wyoming.
Items of Business to be Considered at the Annual Meeting
Proposal
1
2
3
Election of Directors
Ratification of Deloitte & Touche LLP to Serve as Independent
Registered Public Accounting Firm for 2024
Advisory Vote to Approve Executive Compensation
Board
Recommendation
FOR
each Director Nominee
FOR
FOR
Page
6
20
23
Director Nominees
BOARD OF DIRECTORS
Our Board of Directors ("Board") is committed to oversight that promotes the long-term interests of our shareholders and other
stakeholders. We believe this is best achieved with directors who bring a diverse and relevant set of skills, expertise,
experiences and perspectives. Our Board is nominating four individuals for election at this annual meeting. The following table
provides summary information about the nominees:
Name
Age
Director
Since
Independent
Committee
Membership
Other U.S. Public Boards
Linden R. Evans
Barry M. Granger
Tony A. Jensen
Steven R. Mills
61
64
61
68
2018
2020
2019
2011
NA
None
Compensation
None
Audit
None
Board Chair;
Governance
Amyris, Inc.
X
X
X
1
PROXYPROXY| PROXY SUMMARY
Director Skills and Demographics
Skills and Experience
Business Operations
Customer Service
Cybersecurity/Technology
ESG/Sustainability
Financial Acumen
Government/Regulatory
Health and Safety
Human Capital Management/Compensation
Legal/Governance/Compliance
Mergers and Acquisitions
Risk Management
Strategic Planning
Utility Industry
Board Tenure
Years
Age
Years Old
Gender
Female
Male
Race/Ethnicity
African American/Black
White/Caucasian
Evans Granger Jensen McAllister Mills Otto Prochazka Roberts Schober Taylor
X
X
X
X
X
X
X
X
X
X
5
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
3
4
4
12
7
X
X
X
X
X
X
X
X
X
3
X
X
X
X
X
X
X
12
X
X
X
X
X
X
X
7
X
X
X
X
X
X
8
61
64
61
59
68
64
58
71
68
60
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
OUR COMMITMENT TO SUSTAINABILITY
Our mission of Improving Life with Energy means we must be ready to make tomorrow even better than today. That is why we
are committed to creating a cleaner energy future which builds upon our responsibility to provide the safe, reliable and cost-
effective energy that improves our customers’ lives. By investing in the success of our employees, continually innovating,
thoughtfully utilizing resources and keeping people at the core of our decision-making, we are dedicated to the sustainability of
our Company, communities and planet.
Environmental, Social and Governance (ESG) Strategy and Oversight
We are continuously building upon our success of delivering cost-effective energy for customers and strong returns for
investors by seeking renewable energy growth opportunities, minimizing risk and responding to stakeholders’ evolving
expectations. ESG and sustainability are inherently connected throughout our business and our ESG management is
structured accordingly. Our Board oversees ESG, with management leadership from our CEO and executive steering
committee, our dedicated department and our cross functional sustainability working group.
Responsibly Reducing Greenhouse Gas Emissions
We have set challenging, yet realistic, goals for delivering cleaner energy. We've reduced our electric utilities' greenhouse gas
emissions intensity by one-third since 2005 and have a clear path to achieve our reduction goals of 40% by 2030 and 70% by
2
PROXYPROXYPROXY SUMMARY |
2040. In 2022, we increased our gas distribution utilities' emissions target to Net Zero by 2035. We expect to achieve our Net
Zero target through ongoing infrastructure investment, damage prevention and integration of low carbon fuels.
Electric Utilities Goals(1)(2)
40% by 2030
70% by 2040
Natural Gas Utilities
Goals(1)(3)
Net Zero by 2035
(1)
(2)
(3)
Our goals are compared to a 2005 baseline.
Electric Utilities goals include Scope 1 emissions from electric utility generating units and Scope 3 emissions from purchased
power for sales.
Natural Gas Utilities goals include all Scope 1 sources of methane emissions on our distribution system, including fugitive
emissions from pipeline mains and service lines, meters, transfer stations, system damages and system blow downs.
We are proud of our sustainability efforts and continue to pursue initiatives to enable the transition to a cleaner energy future,
including:
Since 2005, we have reduced GHG emissions intensity from our electric utilities by one-third. Additionally, our
Electric Utilities have reduced nitrogen oxide and sulfur dioxide emissions by more than 75% since 2005. Colorado
Electric has achieved a nearly 50% reduction in GHG emissions since 2005 and is on track to reach the State of
Colorado's 80% carbon reduction goal by 2030.
We completed a hydrogen blending feasibility study for our Cheyenne Prairie natural gas generation facility and are
now working on a feasibility analysis for a coal to hydrogen project.
We successfully filed and received approval for Green Forward, a voluntary renewable natural gas (RNG) attribute
and carbon offset program, expected to provide customers with a cost-effective path to offset up to 100% or more of
the emissions associated with their own natural gas footprint.
As we look to the future, our approximately 500 MW of planned battery storage, renewable generation and
additions, position us to achieve deeper carbon reductions that also deliver reliable and cost-effective energy to our
customers.
We will continue executing our strategy of investing in cost-effective renewables and new technologies to further reduce our
environmental impact across all states in which we operate, while continuing to deliver safe, reliable and cost effective energy
to customers.
For additional information on our commitment to sustainability, you can review the following 2022 ESG reports on our website
at www.blackhillsenergy.com/our-company/commitment-sustainability/sustainability-and-esg-reports:
2022 Corporate Sustainability Report
2022 Edison Electric Institute ESG Disclosure
2022 American Gas Association ESG Disclosure
2022 Natural Gas Sustainability Initiative Disclosure
2022 Sustainability Accounting Standards Board Disclosure
2022 Task Force on Climate Related Financial Disclosure Index
OUR COMMITMENT TO WILDFIRE SAFETY AND PREVENTION
We have a long history of delivering safe and reliable energy to our customers. For decades, we have employed a wide variety
of wildfire mitigation measures and initiatives to support the integrity of our energy delivery systems, while safeguarding our
facilities and the surrounding environment. These efforts are part of our comprehensive approach to mitigate not only wildfire
risk, but also a variety of extreme weather events, including ice storms and high winds. We are utilizing a three-pronged
approach to wildfire mitigation, which includes the following:
Asset programs like preventative inspection, repair, and maintenance practices, including vegetation
management, line patrol in the air and on the ground, and pole inspections and replacement.
Integrity programs and system investments aimed at improving reliability and reducing risk, undergrounding
electric distribution lines, and applying construction standards that reduce the likelihood of wildfire interactions with
facilities.
Operational response utilizing risk-driven decisions including system reconfigurations, daily work activities and
equipment operation (non-reclosing energized power lines), and fire weather forecasting tools to enhance
situational awareness and understanding of a potentially hazardous fire area.
3
PROXYPROXY| PROXY SUMMARY
We are committed to the ongoing development and implementation of risk reduction strategies for the betterment of the
environment and our customers, employees, and investors. For additional information on our commitment to wildfire safety
and prevention, please visit our website at www.blackhillsenergy.com/wildfire-safety.
EXECUTIVE COMPENSATION
We have an Executive Compensation Philosophy that establishes the framework our Compensation Committee applies in
structuring compensation for our executive officers ("Named Executive Officers" or "NEOs"). The components of our executive
pay program consist of a base salary, a short-term incentive plan, and long-term incentives. Our executive pay program aligns
the interest of our Named Executive Officers with our stakeholders by tying incentive pay to achievement of performance
metrics.
Variable
Linked to Share Value
80 %
60 %
Variable
Linked to Share Value
61 %
39 %
*Percentages may differ from above due to rounding.
The performance measures for our incentive compensation plans are discussed in greater detail on page 27 of the Proxy
Statement. We also require our executive officers to hold a significant amount of our common stock (between 3 and 6 times
the base salary) to further align their interests with the interest of our stakeholders.
Our compensation practices and policies demonstrate the alignment between executive compensation and the interests of our
stakeholders. Our shareholders share our confidence in our compensation philosophy as reflected by the support of
shareholders owning 98 percent of the shares who voted to approve our 2022 executive compensation at last year's annual
meeting.
4
PROXYPROXYPROXY SUMMARY |
The following table summarizes performance metrics and results for incentive plans that ended in 2023.
Pay Element
Performance Measure
2023 Results
Short-term Incentive: Payout of 153.67% of Target
70 Percent
EPS from ongoing operations, as adjusted, target set at
$3.75; threshold set at $3.49
$3.93 per share for
incentive plan purposes
Timeliness of Incident Reporting, target set at 91%;
threshold set at 90%
Average Proactive Safety Activities/Employee; target set
at 3; threshold set at 2
Total Case Incident Rate (TCIR); target set at 1.23;
threshold set at 1.39
Top Quartile PMVI Performance; target set at 1.44;
threshold set at 1.56
Hits Per Thousand (HPT), target set
at 2.05; threshold set at 2.20
Top Quartile System Average Interruption Duration Index
(SAIDI) Performance, target set at 65.7; threshold set at
72.8
Customer Interaction: Customer Effort; target set at 8.9;
threshold set at 8.8
Customer Interaction: Net Promoter Score; target set at
67; threshold set at 64
Customer Brand/Perception: JD Power Gas vs Industry;
target set at 50%; threshold set at 25%
Customer Brand/Perception: JD Power Electric vs
Industry; target set at +2 ranking; threshold set at +1
ranking
Percent of Diverse Candidate Slates; target set at 85%;
threshold set at 80%
Percent of Diverse Interview Panels; target set at 92%;
threshold set at 90%
93%
4
TCIR: 1.51
PMVI: 1.65
HPT: 2.05
SAIDI: 61.56
8.8
65.4
41%
0
90%
96%
Long-term Incentive (2021-2023 Plan): Payout of 16.21% of Target
Total Shareholder Return (TSR)
relative to our Performance Peer Group
measured over a three-year period; target set at 50th
Percentile; threshold set at 25th Percentile
Average EPS as Adjusted; target set at $4.09; threshold
set at $3.88
Average Cost to Serve; target set at 45.0%; threshold set
at 47.2%
TSR: 1.27%
16th Percentile Ranking in
Performance Peer Group
Average EPS: $3.882
Average Cost to Serve: 46.3%
7.5 Percent
7.5 Percent
5.0 Percent
2.5 Percent
7.5 Percent
60 Percent
20 Percent
20 Percent
5
PROXYPROXY| PROXY SUMMARY
2023 ACCOMPLISHMENTS AND PERFORMANCE
Black Hills Corporation delivered on our financial commitments during an inflationary macroeconomic environment.
Earnings per share for the year were $3.91, above our earnings guidance range of $3.65 to $3.85. We achieved our
financial targets, advanced our key strategic initiatives, executed our capital plan and delivered excellent operations
performance. Significant accomplishments for the year included:
Provided the safe and reliable service our communities and customers depend on and achieved several notable
operations performance metrics:
*
*
Achieved a safety performance preventable motor vehicle incident rate of 1.65 compared to a 2022 American
Gas Association report top quartile average of 1.72
Achieved 10 consecutive years of new peaks for Wyoming Electric, representing 127 MW, which is a 69%
increase
Completed financing activity to accomplish our long-term objective of investing to meet the needs of our customers,
including:
* Completed a public debt offering of $450 million, 6.15% senior unsecured notes due 2034
* Completed a public debt offering of $350 million, 5.95% senior unsecured notes due 2028
*
Issued a total of 2.0 million shares of new common stock for net proceeds of $118.7 million under our at-the-
market equity offering program
Improved our year-over-year net debt to capitalization ratio to 57.3% from 60.8%
*
* Grew our dividend for the 53rd consecutive year
Invested in our utility infrastructure and systems:
* Deployed $590 million in capital projects
* Commenced construction on our 260-mile Ready Wyoming Electric Transmission Expansion Project
*
Issued an RFP under our South Dakota Electric Integrated Resource Plan for 100 MW of build-transfer
renewable generation by mid-2026
Executed a number of regulatory accomplishments:
* Successfully completed rate review requests for Rocky Mountain Natural Gas and Wyoming Electric
* Reached constructive settlements for our rate reviews for Colorado Gas and Wyoming Gas
*
Received a Certificate of Public Convenience and Necessity for the Ready Wyoming Electric Transmission
Expansion Project
Continued our focus on sustainability, including:
*
*
Issued an updated sustainability report and updated EEI, AGA, SASB, NGSI, and TCFD disclosures
Issued an RFP under our Colorado Electric Clean Energy Plan for approximately 400 MW of renewable
resources by 2030
6
PROXYPROXYPROXY SUMMARY |
BLACK HILLS CORPORATION
7001 Mount Rushmore Road
Rapid City, South Dakota 57702
PROXY STATEMENT
A proxy in the accompanying form is solicited by the Board of Directors of Black Hills Corporation, a South Dakota
corporation, to be voted at the annual meeting of our shareholders to be held Tuesday, April 23, 2024, and at any
adjournment of the annual meeting.
The enclosed form of proxy, when executed and returned, will be voted as set forth in the proxy. Any shareholder
signing a proxy has the power to revoke the proxy in writing, addressed to our secretary, or in person at the meeting
at any time before the proxy is exercised.
This proxy statement and the accompanying form of proxy are to be first mailed on or about March 15, 2024. Our
2023 annual report to shareholders is being mailed to shareholders with this proxy statement.
VOTING RIGHTS AND PRINCIPAL HOLDERS
Only our shareholders of record at the close of business on March 4, 2024 are entitled to vote at the meeting. Our
outstanding voting stock as of the record date consisted of 68,289,533 shares of our common stock.
Each outstanding share of our common stock is entitled to one vote. Cumulative voting is permitted in the election of
directors in the same class.
1
PROXY| PROXY STATEMENT
TABLE OF CONTENTS
Commonly Asked Questions and Answers About the Annual Meeting Process
Proposal 1 - Election of Directors
Corporate Governance
Meetings and Committees of the Board
Director Compensation
Security Ownership of Management and Principal Shareholders
Proposal 2 - Ratification of Appointment of Independent Registered Public Accounting Firm
Fees Paid to the Independent Registered Public Accounting Firm
Audit Committee Report
Proposal 3 - Advisory Vote on Our Executive Compensation
Executive Compensation
Compensation Discussion and Analysis
Report of the Compensation Committee
Summary Compensation Table
Grants of Plan Based Awards in 2023
Outstanding Equity Awards at Fiscal Year-End 2023
Option Exercises and Stock Vested During 2023
Pension Benefits for 2023
Nonqualified Deferred Compensation for 2023
Potential Payments Upon Termination or Change in Control
Pay Ratio for 2023
Pay versus Performance
Transaction of Other Business
Shareholder Proposals for 2025 Annual Meeting
Shared Address Shareholders
Annual Report on Form 10-K
Notice Regarding Availability of Proxy Materials
Page
3
6
12
15
17
18
20
21
22
23
24
24
36
37
38
39
40
41
43
44
47
47
51
51
52
52
52
2
PROXYPROXY STATEMENT |
COMMONLY ASKED QUESTIONS AND ANSWERS ABOUT THE ANNUAL MEETING PROCESS
Who is soliciting my proxy?
The Board of Directors of Black Hills Corporation is soliciting your proxy.
Where and when is the annual meeting?
The annual meeting is at 9:30 a.m., local time, April 23, 2024 at Horizon Point, the Company’s corporate headquarters, 7001
Mount Rushmore Road, Rapid City, South Dakota.
Who can vote?
Holders of our common stock as of the close of business on the record date, March 4, 2024, can vote at our annual meeting.
Each share of our common stock has one vote for Proposals 2, and 3. Related to Proposal 1, Election of Directors, cumulative
voting is permitted in the election of directors in the same class.
How do I vote?
There are three ways to vote by proxy:
by calling the toll free telephone number on the enclosed proxy;
by going to the website identified on the enclosed proxy; or
by returning the enclosed proxy in the envelope provided.
You may be able to vote by telephone or over the Internet if your shares are held in the name of a bank or broker. If this is the
case, you will need to follow their instructions.
What constitutes a quorum?
Shareholders representing at least 50 percent of our common stock issued and outstanding as of the record date must be
present at the annual meeting, either in person or by proxy, for there to be a quorum. Abstentions and broker non-votes are
counted as present for establishing a quorum. A broker non-vote occurs when a broker or other nominee holding shares for a
beneficial owner does not vote on a particular proposal because the broker or nominee does not have discretionary voting
power and has not received instructions from the beneficial owner.
3
PROXY| PROXY STATEMENT
What am I voting on and what is the required vote for the proposals to be adopted?
The required vote and method of counting votes for the various business matters to be considered at the annual meeting are
described in the table below. If you sign and return your proxy card without indicating your vote, your shares will be voted in
accordance with the Board recommendations as set forth below.
Item of Business
Proposal 1:
Election of Directors
Board
Recommendation
FOR
election of each director
nominee
Voting Approval Standard
The four nominees with the most "FOR" votes are
elected to their respective classes.
Effect of
Abstention
No effect
Effect of Broker
Non-Vote
No effect
Proposal 2:
FOR
Ratification of
Appointment of
Independent Registered
Public Accounting Firm
Proposal 3:
Advisory Vote to
Approve Executive
Compensation
If a nominee receives more "WITHHOLD
AUTHORITY" votes than "FOR" votes, the
nominee must submit a resignation for
consideration by the Governance Committee and
final Board decision.
The votes cast "FOR" must exceed the votes cast
"AGAINST".
No effect
Not applicable;
broker may vote
shares without
instruction
FOR
The votes cast "FOR" must exceed the votes cast
"AGAINST".
No effect
No effect
This advisory vote is not binding on the Board, but
the Board will consider the vote results when
making future executive compensation decisions.
Is cumulative voting permitted for the election of directors?
In the election of directors, you may cumulate your vote. Cumulative voting allows you to allocate among the director
nominees in the same class, as you see fit, the total number of votes equal to the number of director positions to be filled
multiplied by the number of shares you hold. For example, if you own 100 shares of stock, and there are three directors to be
elected in a class at the annual meeting, you could allocate 300 “For” votes (three times 100) among as few or as many of the
three nominees to be voted on at the annual meeting as you choose.
If you choose to cumulate your votes, you will need to submit a proxy card or a ballot and make an explicit statement of your
intent to cumulate your votes, either by indicating in writing on the proxy card or by indicating in writing on your ballot when
voting at the annual meeting. If you hold shares beneficially in street name and wish to cumulate votes, you should contact
your broker, trustee or nominee.
4
PROXYPROXY STATEMENT |
How will my shares be voted if they are held in a broker’s name?
If you hold your shares through an account with a bank or broker, the bank or broker may vote your shares on some matters
even if you do not provide voting instructions. Brokerage firms have the authority under the New York Stock Exchange
("NYSE") rules to vote shares on certain matters (such as the ratification of auditors) when their customers do not provide
voting instructions. However, on most other matters when the brokerage firm has not received voting instructions from its
customers, the brokerage firm cannot vote the shares on that matter and a “broker non-vote” occurs. This means that
brokers may not vote your shares on the election of directors or the “say on pay” advisory vote if you have not given
your broker specific instructions as to how to vote. Please be sure to give specific voting instructions to your broker
so that your vote can be counted.
What should I do now?
You should vote your shares by telephone, over the Internet or by returning your signed and dated proxy card in the enclosed
envelope as soon as possible so that your shares will be represented at the annual meeting.
Who will count the vote?
Representatives of our transfer agent, Equiniti Trust Company, will count the votes and serve as judges of the election.
Who conducts the proxy solicitation and how much will it cost?
We are asking for your proxy for the annual meeting and will pay all the costs of asking for shareholder proxies. We have hired
Georgeson LLC to help us send out the proxy materials and ask for proxies. Georgeson LLC’s fee for these services is
anticipated to be $12,250 plus out-of-pocket expenses. We can ask for proxies through the mail, by telephone or in person.
We can use our directors, officers and employees to ask for proxies. These people do not receive additional compensation for
these services. We will reimburse brokers and other custodians, nominees and fiduciaries for their reasonable out-of-pocket
expenses for forwarding solicitation material to the beneficial owners of our common stock.
Can I revoke my proxy?
Yes. You can change your vote in one of four ways at any time before your proxy is used. First, you can enter a new vote by
telephone or Internet. Second, you can revoke your proxy by written notice. Third, you can send a later dated proxy changing
your vote. Fourth, you can attend the meeting and vote in person.
Who should I call with questions?
If you have questions about the annual meeting, you should call Amy K. Koenig, Vice President - Governance, Corporate
Secretary and Deputy General Counsel, at (605) 721-1700.
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PROPOSAL 1
ELECTION OF DIRECTORS
Our Board is nominating four individuals for election as directors at this annual meeting. All of the nominees are currently
serving as our directors. In accordance with our Bylaws and Article VI of our Articles of Incorporation, members of our Board
are elected to three classes of staggered terms consisting of three years each, and until their successors are duly elected and
qualified. At this annual meeting, four directors will be elected to Class III for a term of three years until our annual meeting in
2027.
Nominees for director at the annual meeting are Linden R. Evans, Barry M. Granger, Tony A. Jensen, and Steven R. Mills. Our
Bylaws require a minimum of nine directors. Currently, the Board has set the size of the Board at ten directors.
If, at the time of the annual meeting, any nominees are unable to stand for election, the Board may designate a substitute or
reduce the number of directors to no less than nine. In that case, shares represented by proxies may be voted for a substitute
director nominated by the Board. We do not expect that any nominee will be unavailable or unable to serve.
The Board and the Governance Committee believe that the combination of the various qualifications, skills and experiences of
the directors contribute to an effective and well-functioning Board, and that, individually and as a whole, the directors possess
the necessary qualifications to provide effective oversight of the business and quality advice to the Company’s management.
Included in each director’s biography below is an assessment of the specific qualifications, attributes, skills and experience
that have led to the conclusion that each individual should serve as a director in light of our current business and structure.
The Board recommends a vote FOR the election of the following nominees:
Director Nominee
Class
Year Term Expiring
Linden R. Evans
Barry M. Granger
Tony A. Jensen
Steven R. Mills
III
III
III
III
2027
2027
2027
2027
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PROXYPROXY STATEMENT |
DIRECTOR SKILLS AND EXPERIENCE
Linden R. Evans
Outside Directorships:
President and Chief Executive Officer of the
Company
None
Director since: 2018
Director Class: III, term expiring in 2027
Other U.S. Public Company
Directorships:
Age: 61
None
Summary:
Mr. Evans has been President and Chief Executive Officer of the Company since January 1, 2019. He previously served as
President and Chief Operating Officer from 2016 to 2018, and President and Chief Operating Officer – Utilities from 2004 to 2015.
He began his career with Black Hills Corporation in 2001 as Corporate Counsel. Prior to joining the Company, Mr. Evans was a
mining engineer and an attorney specializing in environmental and corporate legal matters.
Skills Relevant to BHC:
As CEO of Black Hills Corporation, Mr. Evans brings historic institutional knowledge of the Company and its operations that assist
the Board in its evaluation of the Company’s financial and operational risks and strategy.
Barry M. Granger
Standing Board Committees:
Managing Partner and Co-Founder of Vonbar
Investments LLC
Compensation Committee
Director since: 2020
Director Class: III, term expiring in 2027
Other U.S. Public Company
Directorships:
Age: 64
None
Summary:
Mr. Granger has over 40 years of experience in the chemical and industrial markets. He is the Managing Partner of Vonbar
Investments LLC. He held leadership roles at DuPont as Vice President of Government Marketing and Government Affairs and
Vice President and General Manager at Tyvek®. Early in his career, he served as the Executive Assistant to the Chairman and
CEO of DuPont. He has held a variety of leadership positions with increasing responsibilities in business, regulatory affairs,
operations, sales and marketing.
Skills Relevant to BHC:
Mr. Granger’s leadership roles in the areas of governmental affairs, business and operations offer the Board insight regarding
business strategy and leadership, oversight of operations, regulatory affairs, safety and people development.
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PROXY| PROXY STATEMENT
Tony A. Jensen
Standing Board Committees:
Retired Director, President and Chief Executive
Officer of Royal Gold, Inc.
Audit Committee
Director since: 2019
Director Class: III, term expiring in 2027
Other U.S. Public Company
Directorships:
Age: 61
None
Summary:
Mr. Jensen has over 35 years of experience in the international mining and mining finance industries. From 2003 until his
retirement in 2019, Mr. Jensen served in several leadership roles at Royal Gold, Inc., a public precious metals company, including
Director, President and Chief Executive Officer from 2006 to 2019, and Chief Operating Officer from 2003 to 2006. Prior to 2003,
he held roles with progressively more responsibility in engineering, finance, strategic growth, safety, environmental excellence,
and operational efficiency. Mr. Jensen also serves on the Boards of Antofagasta Minerals SA and Antofagasta plc where he
chairs the Audit and Risk Committee and is a member of the Projects Committee as well as the Governance and Nominations
Committee.
Skills Relevant to BHC:
As the former CEO of a publicly traded precious metals stream and royalty company, Mr. Jensen brings business, leadership,
governance, and financial expertise that assists the Board in evaluating the Company’s financial risks and strategy and capital
deployment.
Kathleen S. McAllister
Standing Board Committees:
Retired Director, President and Chief Executive
Officer of Transocean Partners LLC
Audit Committee
Director since: 2019
Director Class: I, term expiring in 2025
Age: 59
Other U.S. Public Company
Directorships:
Silverbow Resources, Inc. (since 2023)
TMC The Metals Company Inc. (since
2022)
Summary:
Ms. McAllister has over 30 years of experience in diverse leadership roles with global, capital intensive companies in the energy
value chain. She served as Director, President and Chief Executive Officer of Transocean Partners LLC, an international provider
of offshore contract drilling services from 2014 to 2016, and as Chief Financial Officer in 2016. She held the roles of Vice
President and Treasurer of Transocean Ltd. from 2011 to 2014. Prior to 2011, she served in roles with increasing responsibility in
finance, information technology, tax and treasury. Ms. McAllister is a National Association of Corporate Directors Board Fellow
and a Certified Public Accountant. She previously served on the board of Maersk Drilling from 2019 to 2021, where she chaired
the Audit and Risk Committee. She is a Board Member of Silverbow Resources, Inc. and TMC The Metals Company Inc., where
she chairs the Audit Committees. She also serves on the Board of Hoegh LNG Partners.
Skills Relevant to BHC:
As a former CEO, CFO and Treasurer of publicly traded companies, Ms. McAllister's broad business perspective, financial
acumen and experience in capital raising and allocation contributes to the Board's oversight of strategy and risk. Her experience
serving as a corporate director and audit and risk committee chair on other public company boards provides a valuable
perspective on the Board's role in management oversight and corporate governance.
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PROXYPROXY STATEMENT |
Steven R. Mills
Standing Board Committees:
Chairman of the Board
Retired Public Company Financial Executive
Governance Committee
Director since: 2011
Director Class: III, term expiring in 2027
Other U.S. Public Company
Directorships:
Age: 68
Amyris, Inc. (since 2018)
Summary:
Mr. Mills has more than 40 years of experience in the fields of accounting, corporate finance, strategic planning, risk
management, and mergers and acquisitions. He served as Chief Financial Officer of Amyris, Inc., a renewable products company,
from May 2002 to December 2003 Prior to joining Amyris, he had a 33-year career at Archer Daniels Midland Company, one of
the world’s largest agricultural processors and food ingredient providers. At Archer Daniels Midland, he held various senior
executive roles, including Chief Financial Officer, Controller, and responsibility for leading company strategic efforts globally. Mr.
Mills also serves on the boards of Arianna S.A., Illinois College and First Interstate Corporation (along with its wholly-owned
banking subsidiary, Hickory Point Bank & Trust).
Skills Relevant to BHC:
Mr. Mills brings to the Board executive leadership and financial experience as a former CFO of publicly traded companies and
strategic planning experience as both a former senior vice president of strategic planning and a senior executive vice president
performance and growth for a publicly traded company. These roles also position Mr. Mills to provide the Board perspectives on
mergers and acquisitions and capital deployment.
Robert P. Otto
Standing Board Committees:
Owner of Bob Otto Consulting LLC
Audit Committee
Director since: 2017
Director Class: I, term expiring in 2025
Other U.S. Public Company
Directorships:
Age: 64
None
Summary:
Since 2017, Mr. Otto has provided strategic planning and advisory services in cybersecurity and intelligence through his
company, Bob Otto Consulting LLC. With 34 years of U.S. Air Force service, he served as a general officer from 2008 to 2016,
culminating as lieutenant general and the Deputy Chief of Staff for Intelligence, Surveillance and Reconnaissance. He was
directly responsible for intelligence policy, planning, implementation, oversight, and leadership of a 27,000-person workforce.
Skills Relevant to BHC:
Mr. Otto’s experience in cybersecurity and intelligence through his lengthy career with the U.S. Air Force provides the Board
information technology and cybersecurity expertise. His leadership and oversight of a large workforce positions him to provide the
Board insights regarding human capital management.
9
PROXY| PROXY STATEMENT
Scott M. Prochazka
Standing Board Committees:
Former Board Member, President and Chief
Executive Officer of CenterPoint Energy
Compensation Committee
Director since: 2020
Director Nominee Class: II, term expiring in
2026
Other U.S. Public Company
Directorships:
Age: 58
Li-Cycle Holdings Corp. (since 2021)
Summary:
Mr. Prochazka served as Board Member, President and Chief Executive Officer of CenterPoint Energy, a public energy delivery
company with electric transmission and distribution, power generation and natural gas distribution operations, from 2014 until his
retirement in 2020. Prior to that he was Chief Operating Officer from 2012 to 2013, Senior Vice President of Electric Business
from 2011 to 2012, and Vice President of Gas Business Unit from 2009 to 2011. He held other management positions including
Vice President Customer Care and Support Services and Vice President Texas Gas Region. Before his time at CenterPoint
Energy, Mr. Prochazka held roles of increasing responsibility at Dow Chemical. Mr. Prochazka was a Board Member of Enable
Midstream Partners, LP from 2014 to 2020, and Chairman from 2015 to 2017. Mr. Prochazka was previously a Board Member of
Peridot Acquisition Corporation, from 2020 to 2021, where he served on the Audit and Compensation Committees, and Peridot
Acquisition Corp. II, from 2021 to 2023, where he served on the Audit and Compensation Committees. He currently serves on Li-
Cycle Holdings Corp. (successor to Peridot Acquisition Corp.) where he chairs the Audit Committee and serves on the
Nominating/Governance Committee and the Compensation Committee. He also serves on the Board of Saudi Electric Co.
Skills Relevant to BHC:
Mr. Prochazka’s executive experience as a former CEO of a publicly traded electric and gas utility company, with a market cap
more than four times that of Black Hills Corporation, and leadership experience as COO of both gas and electric utility divisions,
provides a valuable perspective regarding utility business operations, regulatory and governmental affairs, safety, capital
deployment and risk management.
Rebecca B. Roberts
Standing Board Committees:
Retired President of Chevron Pipe Line Company
Compensation Committee
Governance Committee (Chair)
Director since: 2011
Director Nominee Class: II, term expiring in
2026
Other U.S. Public Company
Directorships:
Age: 71
AbbVie, Inc. (since 2018)
MSA Safety, Inc. (since 2013)
Summary:
Ms. Roberts has over 35 years of experience in the energy industry, including managing pipelines in North America and global
pipeline projects, and managing a portfolio of power plants in the United States, Asia, and the Middle East. From 2006 until her
retirement in 2011, Ms. Roberts served as the President of Chevron Pipe Line Company, a pipeline company transporting crude
oil, refined petroleum products, liquefied petroleum gas, natural gas, and chemicals within the United States. From 2003 until
2006, she was the President of Chevron Global Power Generation. She was previously a Board Member of Enbridge, Inc., from
2015 to 2018. Ms. Roberts is a Board Member of Abbvie, Inc. and MSA Safety, Inc., where she serves as the Chair of the
Compensation Committee. As previously disclosed, Ms. Roberts, who will turn 72 prior to our 2025 annual meeting, is required to
resign effective at that meeting pursuant to our bylaws.
Skills Relevant to BHC:
Ms. Robert’s executive experience overseeing natural gas pipelines and power generation facilities positions her to assist the
Board as it evaluates the Company’s operational, health and safety risks. Her prior and ongoing experience on other public
company boards provides insight as to the Board’s role in oversight of management as well as corporate governance.
10
PROXYPROXY STATEMENT |
Mark A. Schober
Standing Board Committees:
Retired Senior Vice President and Chief Financial
Officer of ALLETE, Inc.
Audit Committee (Chair)
Governance Committee
Director since: 2015
Director Class: I, term expiring in 2025
Other U.S. Public Company
Directorships:
Age: 68
None
Summary:
Mr. Schober has more than 35 years of experience in the utility and energy industry. From 2006 until his retirement in 2014, Mr.
Schober served as the Senior Vice President and Chief Financial Officer of ALLETE, Inc., a public energy company. His extensive
industry experience in the upper Midwest provides expertise in the regulated business model and the unique challenges of the
geographic and regulatory environment in which we operate.
Skills Relevant to BHC:
Mr. Schober brings to the Board business and leadership experience as a former executive of a public company, regulated utility
experience as a former executive of a publicly traded Midwest based energy company, and financial expertise having served as a
CFO. He also provides insight to the Company regarding potential exposures and risks in these areas.
Teresa A. Taylor
Standing Board Committees:
Chief Executive Officer of Blue Valley Advisors, LLC
Compensation Committee (Chair)
Governance Committee
Director since: 2016
Director Nominee Class: II, term expiring in
2026
Other U.S. Public Company
Directorships:
Age: 60
T-Mobile USA, Inc. (since 2013)
Summary:
Ms. Taylor has over 30 years of experience in the technology, media, and telecom sectors. She has been the Chief Executive
Officer of Blue Valley Advisors, LLC, a consulting firm that she founded, since 2011. She was the Chief Operating Officer of
Qwest Communications, Inc., a telecommunications carrier, from 2009 to 2011, where she led the daily operations and a senior
management team responsible for 30,000 employees in field support, technical development, sales, marketing, customer support
and information technology systems. She is a Board Member of T-Mobile USA, Inc. She was previously a Board Member of First
Interstate BancSystem, Inc. from 2012 to 2020, Columbia Pipeline Group Inc. from 2015 to 2016, and NiSource, a public utility
company from 2012 to 2015.
Skills Relevant to BHC:
Ms. Taylor’s broad range of experience over her three decades-long career, including in the fields of human resources, customer
support, information technology systems, and business operations, add breadth and depth to the board. Her experience leading
large employee teams lends toward engagement with the Board in the areas of compensation practices and human capital
management. Ms. Taylor’s experience as a lead independent director of a publicly traded company provides further insight into
Board governance and oversight of management.
11
PROXY| PROXY STATEMENT
CORPORATE GOVERNANCE
Corporate Governance Guidelines
Our Board has adopted “Corporate Governance Guidelines of the Board,” which guide the operation of our Board and assist
the Board in fulfilling its obligations to shareholders and other constituencies. The guidelines lay the foundation for the Board’s
responsibilities, operations, leadership, organization and committee matters. The Governance Committee reviews the
guidelines annually, and the guidelines may be amended at any time, upon recommendation by the Governance Committee
and approval of the Board. These guidelines can be found in the “Corporate Governance” section of our website
(https://ir.blackhillscorp.com/corporate-governance/governance-documents).
Board Leadership Structure
On May 1, 2020, Steven R. Mills, an independent director, was appointed Chairman of the Board. As Chairman, Mr. Mills
leads our Board in the performance of its duties by working with the CEO to establish meeting agendas, facilitating board
meetings and executive sessions, and collaborating with the Board to annually evaluate the performance of the CEO.
As provided in our Corporate Governance Guidelines, the Board does not have a policy on whether or not the roles of
Chairman and CEO should be separate or combined. The Governance Committee annually reviews the appropriate leadership
structure for the Company and recommends a Chairman for Board approval. While our Bylaws and Corporate Governance
Guidelines do not require that our Chairman and CEO positions be held by separate individuals, the Board believes that
having separate positions and having an independent director serve as Chairman is the appropriate leadership structure for
the Company at this time because it allows our CEO to focus on business operations and our Chairman to focus on Board
governance.
Risk Oversight
Our Board oversees an enterprise risk management ("ERM") approach to risk management that supports our operational and
strategic objectives. It fulfills its oversight responsibilities through receipt of quarterly reports from management regarding
material risks involving strategic planning and execution, operations, physical and cybersecurity, environmental, social and
governance ("ESG"), financial, legal, safety, regulatory, and human resources risks. While our full Board retains responsibility
for risk oversight, it delegates oversight of certain risk considerations to its committees within each of their respective areas of
responsibility as defined in the charter for each committee.
Our management is responsible for day-to-day risk management and operates under our ERM program that addresses
enterprise risks. The ERM program includes practices to identify risks, assess the impact and likelihood of occurrence, and
develop action plans to prevent the occurrence or mitigate the impact of the risk. The ERM program includes regular reporting
to our senior management team, quarterly reporting to our Board, and monitoring and testing by the Risk Management,
Compliance and Internal Audit groups.
Sustainability Oversight
We are committed to creating a cleaner energy future that builds upon our responsibility to provide the safe, reliable and
economic energy that improves our customers' lives. The Board oversees management's execution of our sustainability
objectives and receives quarterly updates from management regarding sustainability matters. Under the oversight of the
Board, we published our 2022 Corporate Sustainability Report in the third quarter of 2023. In addition to announcing progress
toward our goal to reduce electric utility emission intensity 40% by 2030 and 70% by 2040, we provided key strategic updates
to our plans to achieve net zero emissions by 2035 for our natural gas distribution system. Also in the third quarter of 2023, we
issued updated Edison Electric Institute and American Gas Association ESG disclosures, Natural Gas Sustainability Initiative
(NGSI) disclosures, Sustainability Accounting Standards Board (SASB) disclosures, and Task Force on Climate Related
Financial Disclosure Index disclosures.
Cyber and Physical Security Oversight
Our Board retains oversight of cyber and physical security. Our Chief Information Officer provides the Board quarterly reports
that summarize material security risks and the measures that have been put in place to mitigate the associated risks. These
reports address a variety of topics including updates on strategic initiatives, industry trends, threat vulnerability assessments,
and efforts to prevent, detect and respond to internal and external critical threats.
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PROXYPROXY STATEMENT |
Human Capital Management Oversight
Primary responsibility for oversight of human capital management rests with our Compensation Committee. As part of its
oversight, the Committee reviews regular reports from management regarding diversity and inclusion, pay equity, strategic
workforce planning, talent retention, employee benefits programs, employee engagement, human rights, and company culture.
Succession Planning Oversight
Our Board is actively engaged in succession planning for our key executive positions to ensure a strong bench of future
leaders. To assist the Board, our CEO and our Human Resources team perform talent reviews and discuss succession
planning and leadership development. Semi-annually, their assessment of senior executive talent, including potential of such
talent to succeed our CEO or other executive officers, readiness for succession and development opportunities are presented
to our Board.
Director Nominees
The Governance Committee uses a variety of methods for identifying and evaluating nominees for director. The Governance
Committee regularly assesses the appropriate size of the Board and whether any vacancies on the Board are expected due to
retirement or otherwise. In the event vacancies are anticipated, or otherwise arise, the Governance Committee considers
various potential candidates for director. Board candidates are considered based upon various criteria, including diversity of
gender, race and ethnicity; business, administrative and professional skills or experiences; an understanding of relevant
industries, technologies and markets; financial literacy; independence status; the ability and willingness to contribute time and
special competence to Board activities; personal integrity and independent judgment; and a commitment to enhancing
shareholder value. The Governance Committee considers these and other factors as it deems appropriate, given the needs of
the Board. Our goal is a diverse, talented, and highly engaged Board, with members whose skills, background and experience
are complementary and, together, cover the spectrum of areas that impact our business currently and in the future. The
Governance Committee considers candidates for Board membership suggested by a variety of sources, including current or
past Board members, the use of third-party executive search firms, members of management, and shareholders. Any
shareholder may make recommendations for consideration by the Governance Committee for membership on the Board by
sending a written statement of the qualifications of the recommended individual to the Corporate Secretary. The Committee
evaluates all director candidates in the same manner using the same criteria regardless of who recommends them.
Shareholders who intend to nominate persons for election to the Board must provide timely written notice of the nomination in
accordance with Article I, Section 9 of our Bylaws. Generally, our Corporate Secretary must receive the written notice at our
executive offices at 7001 Mount Rushmore Road, P.O. Box 1400, Rapid City, South Dakota 57709, not less than 90 days nor
more than 120 days prior to the anniversary date of the immediately preceding annual meeting of shareholders. For the 2025
shareholder meeting, those dates are January 23, 2025 and December 24, 2024. The notice must include at a minimum the
information set forth in Article I, Section 9 of our Bylaws, including the shareholder’s identity, contingent ownership interests,
description of any agreement made with others acting in concert with respect to the nomination, specific information about the
nominee and certain representations by the nominee to us.
Board Independence
In accordance with NYSE rules, the Board through its Governance Committee, affirmatively determines the independence of
each director and director nominee in accordance with guidelines it has adopted, which include all elements of independence
set forth in the NYSE listing standards. These guidelines are contained in our Policy for Director Independence, which can be
found in the "Corporate Governance" section of our website (https://ir.blackhillscorp.com/corporate-governance/governance-
documents). Based on these standards, the Governance Committee determined that each of the following non-employee
directors is independent and has no relationship with us, except as a director and shareholder: Barry M. Granger, Tony A.
Jensen, Kathleen S. McAllister, Steven R. Mills, Robert P. Otto, Scott M. Prochazka, Rebecca B. Roberts, Mark A. Schober,
and Teresa A. Taylor. In addition, based upon these standards, the Governance Committee determined that Mr. Evans is not
independent because he is an officer of the Company.
Director Resignation Policies
The Corporate Governance Guidelines require members of the Board to submit a letter of resignation for consideration by the
Board in certain circumstances. The Corporate Governance Guidelines include a plurality plus voting policy. Pursuant to the
policy, any nominee for election as a director in an uncontested election who receives a greater number of votes “Withheld”
from his or her election than votes “For” his or her election will promptly tender his or her resignation as a director to the
Chairman of the Board following certification of the election results. Broker non-votes will not be deemed to be votes “For” or
“Withheld” from a director’s election for purposes of the policy. The Governance Committee (without the participation of the
affected director) will consider each resignation tendered under the policy and recommend to the Board whether to accept or
reject it. The Board will then take the appropriate action on each tendered resignation, taking into account the Governance
Committee’s recommendation. The Governance Committee in making its recommendation, and the Board in making its
decision, may consider any factors or other information that it considers appropriate, including the reasons why the
Governance Committee believes shareholders “Withheld” votes for election from such director and any other circumstances
13
PROXY| PROXY STATEMENT
surrounding the “Withheld” votes, any alternatives for curing the underlying cause of the “Withheld” votes, the qualifications of
the tendering director, his or her past and expected future contributions to us and the Board, and the overall composition of the
Board, including whether accepting the resignation would cause us to fail to meet any applicable SEC or NYSE requirements.
The Board will publicly disclose its decision and rationale by filing a Form 8-K with the SEC within 90 days after receipt of the
tendered resignation.
The Corporate Governance Guidelines also require members of the Board to tender a letter of resignation in the event of a
change in professional responsibilities that may directly or indirectly impact that Board member’s ability to fulfill directorship
obligations. The Board is not obligated to accept that resignation. The Governance Committee will review the affected
member’s service and qualifications and recommend to the Board the continued appropriateness of Board membership under
the circumstances.
Codes of Business Conduct and Ethics
The Code of Business Conduct and the Code of Ethics that apply to our Chief Executive Officer and Senior Financial Officers
can be found in the “Corporate Governance” section of our website (https://ir.blackhillscorp.com/corporate-
governance/governance-documents). We intend to disclose any amendments to, or waivers of, the Code of Ethics on our
website. Please note that none of the information contained on our website is incorporated by reference in this proxy
statement.
Certain Relationships and Related Party Transactions
We recognize related party transactions can present potential or actual conflicts of interest and create the appearance that
decisions are based on considerations other than the best interests of us and our shareholders. Accordingly, as a general
matter, it is our preference to avoid related party transactions. Nevertheless, we recognize that there are situations where
related party transactions may be in, or may not be inconsistent with, the best interests of us and our shareholders, including
but not limited to situations where we may obtain products or services of a nature, quantity or quality, or on other terms, that
are not readily available from alternative sources or when we provide products or services to related parties on an arm’s length
basis on terms comparable to those provided to unrelated third parties or on terms comparable to those provided to
employees generally.
Therefore, our Board has adopted a policy for the review of related party transactions. This policy requires directors and
officers to promptly report to our Vice President - Governance all proposed or existing transactions in which the Company and
they, or persons related to them, are parties or participants. Our Vice President - Governance presents those transactions to
our Governance Committee. Our Governance Committee reviews the material facts presented and either approves or
disapproves entry into the transaction. In reviewing the transaction, the Governance Committee considers the following
factors, among other factors it deems appropriate: (i) whether the transaction is on terms no less favorable than terms
generally available to an unaffiliated third party under the same or similar circumstances; (ii) the extent of the related party’s
interest in the transaction; and (iii) the impact on a director’s independence in the event the related party is a director, an
immediate family member of a director or an entity in which a director is a partner, shareholder or executive officer. There were
no reportable related party transactions in 2023.
Delinquent Section 16(a) Reports
Based solely upon a review of our records and reports on Forms 3, 4 and 5 filed with the SEC, we believe that during and with
respect to 2023, all persons subject to the reporting requirements of section 16(a) of the Securities and Exchange Act of 1934,
as amended, filed the required reports on a timely basis, except for a Form 4 for Mr. Keller related to an August 2023
transaction that was reported in December of 2023.
Communications with the Board
We value the views and input of our shareholders and believe that fostering productive dialogue with our shareholders
contributes to our long-term success. Shareholders and others interested in communicating directly with the Chairman, with
the independent directors as a group, or the Board may do so in writing to the Chairman, Black Hills Corporation, 7001 Mount
Rushmore Road, P.O. Box 1400, Rapid City, South Dakota 57709.
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PROXYPROXY STATEMENT |
MEETINGS AND COMMITTEES OF THE BOARD
THE BOARD
Our Board held eleven meetings during 2023. Each regularly scheduled meeting of the Board includes an executive session of
only independent directors. We encourage our directors to attend the annual shareholders’ meeting. During 2023, each current
director attended at least 75 percent of the combined total of Board meetings and Committee meetings on which the director
served. While not required under our policies, all directors attended the 2023 annual meeting of shareholders.
COMMITTEES OF THE BOARD
Our Board has three standing committees to facilitate and assist the Board in the execution of its responsibilities. Those
standing committees are the Audit Committee, the Compensation Committee and the Governance Committee. Each
committee operates under a charter, which is available on our website at https://ir.blackhillscorp.com/corporate-
governance/governance-documents and is also available in print to any shareholder who requests it. In addition, our Board
creates special committees from time to time for specific purposes. Members of the committees are designated by our Board
upon recommendation of the Governance Committee.
Audit Committee
9 Meetings in 2023
Assist the Board in fulfilling its oversight responsibility to our shareholders relating to the
quality and integrity of our accounting, auditing and financial reporting processes;
Primary Responsibilities
Members:
Oversee the integrity of our financial statements, financial reporting systems, internal
controls and disclosure controls regarding finance, accounting and legal compliance;
Mark A. Schober (Chair)
Tony A. Jensen
Kathleen S. McAllister
Robert P. Otto
Review areas of potential significant financial risk to us;
Review consolidated financial statements and disclosures;
Appoint an independent registered public accounting firm for ratification by our
shareholders;
Monitor the independence and performance of our independent registered public
accountants and internal auditing department;
Pre-approve all audit and non-audit services provided by our independent registered public
accountants;
Review the scope and results of the annual audit, including reports and recommendations of
our independent registered public accountants;
Review the internal audit plan results of internal audit work and our process for monitoring
compliance with our Code of Business Conduct and other policies and practices established to
ensure compliance with legal and regulatory requirements; and
Periodically meet, in private sessions, with our VP - Internal Audit, Chief Financial Officer,
Chief Compliance Officer, other management, and our independent registered public accounting
firm.
Independence:
100%
Committee Report:
Page 22 of this
Proxy Statement
In accordance with the rules of the NYSE, all of the members of the Audit Committee are
financially literate. In addition, the Board determined that Ms. McAllister and Messrs. Jensen and
Schober have the requisite attributes of an “audit committee financial expert” as provided in
regulations promulgated by the SEC, and that such attributes were acquired through relevant
education and/or experience.
15
PROXY| PROXY STATEMENT
Compensation
Committee
6 Meetings in 2023
Members:
Teresa A. Taylor (Chair)
Barry M. Granger
Scott M. Prochazka
Rebecca B. Roberts
Independence:
100%
Committee Report:
Page 36 of this
Proxy Statement
Primary Responsibilities
Discharge the Board's responsibilities related to executive and director compensation
philosophy, policies and programs;
Perform functions required of directors in the administration of all federal and state laws and
regulations pertaining to executive employment and compensation;
Consider and recommend for approval by the Board all executive compensation programs
including executive benefit programs and stock ownership plans;
Promote an executive compensation program that supports the overall objective of
enhancing shareholder value; and
Provide oversight of Company culture, diversity and inclusion, human rights, pay equity, and
employee engagement.
The Compensation Committee has authority under its charter to retain compensation
consultants and other advisors as the Committee may deem appropriate in its sole discretion.
The Committee engaged Meridian Compensation Partners, LLC (Meridian), an independent
consulting firm, to conduct an annual review of our 2023 total compensation program for
executive officers. The Committee reviewed the independence of Meridian and the individual
representatives of Meridian who served as consultants to the Committee, in accordance with the
SEC and NYSE requirements. The Compensation Committee concluded that Meridian was
independent and Meridian’s performance of services raised no conflict of interest. The
Committee’s conclusions were based in part on a report that Meridian provided to the
Committee intended to reveal any potential conflicts of interest and a schedule of the type and
amount of non-executive compensation services provided by Meridian to the Company. During
2023, the cost of these non-executive compensation services was less than $25,000.
Compensation Committee Interlocks. None of our executive officers serve as a member of a board of directors or
compensation committee of any entity that has one or more executive officers who serve on our Board or on our
Compensation Committee.
Governance Committee
3 Meetings in 2023
Members:
Rebecca B. Roberts
(Chair)
Steven R. Mills
Mark A. Schober
Teresa A. Taylor
Independence:
100%
Primary Responsibilities
Assess the size of the Board and qualifications for Board membership;
Identify and recommend prospective directors to the Board to fill vacancies;
Review and evaluate director nominations submitted by shareholders, including reviewing the
qualifications and independence of shareholder nominees;
Consider and recommend existing Board members to be renominated at our annual meeting
of shareholders;
Consider the resignation of an incumbent director who makes a principal occupation change
(including retirement) or who receives a greater number of votes "Withheld" than votes "For" in an
uncontested election of directors and recommend to the Board whether to accept or reject the
resignation;
Establish and review guidelines for corporate governance;
Recommend to the Board for approval committee membership and chairs of the committees;
Recommend to the Board for approval a Chairman or an independent director to serve as a
Lead Director;
Review the independence of each director and director nominee;
Administer an annual evaluation of the performance of the Board and each Committee and a
biennial evaluation of each individual director;
Ensure that the Board oversees the evaluation and succession planning of management;
Oversee the reporting framework the Company utilizes to track and monitor progress
associated with ESG activities; and
Oversee company political engagement.
16
PROXYPROXY STATEMENT |
DIRECTOR COMPENSATION
DIRECTOR FEES
Compensation to our non-employee directors consists of cash retainers for Board members, Committee members, the Board
Chairman and Committee Chairs.
In setting non-employee director compensation, the Compensation Committee recommends the form and amount of
compensation to the Board, which makes the final determination. In considering and recommending the compensation of non-
employee directors, the Compensation Committee considers such factors as it deems appropriate, including historical
compensation information, level of compensation necessary to attract and retain non-employee directors meeting our desired
qualifications and market data. We do not pay meeting fees. The Committee did not recommend a change to director
compensation for 2023. However, in January 2024 the Committee recommended and our Board approved increases to the
cash retainer, equity compensation, Chairman retainer, and Governance Chair retainer to maintain our board compensation
level near the median of our peers. The fee structure for director fees in 2023 and the fee structure that will take effect in May
2024, are as follows:
Board Retainer
Board Chairman
Committee Chair Retainer
Audit Committee
Compensation Committee
Governance Committee
Committee Member Retainer
Audit Committee
Compensation Committee
Governance Committee
Fees For Fiscal 2023
Cash
Restricted
Stock Units
95,000 $
100,000
120,000 $
$
Fees Effective
May 1, 2024
Restricted
Stock Units
135,000
Cash
105,000 $
120,000
15,000
12,500
10,000
10,000
7,500
7,500
$
$
$
$
$
$
15,000
12,500
12,500
10,000
7,500
7,500
$
$
$
$
$
$
$
$
DIRECTOR COMPENSATION FOR 2023 AND COMMON STOCK EQUIVALENTS OUTSTANDING AS OF DECEMBER 31,
2023(1)
Name(2)
Barry M. Granger
Tony A. Jensen
Kathleen A. McAllister
Steven R. Mills
Robert P. Otto
Scott M. Prochazka
Rebecca B. Roberts
Mark A. Schober
Teresa A. Taylor
Fees Earned or Paid
in Cash
$103,333
$104,167
$105,000
$202,500
$105,000
$102,500
$120,000
$127,500
$122,500
Stock Awards(3)
$120,000
$120,000
$120,000
$120,000
$120,000
$120,000
$120,000
$120,000
$120,000
Total
$223,333
$224,167
$225,000
$322,500
$225,000
$222,500
$240,000
$247,500
$242,500
Outstanding Equity
Awards at December
31, 2023(4)
5,770
5,755
7,508
23,706
10,758
4,017
23,166
15,014
11,321
(1) Our directors did not receive any stock option awards, non-equity incentive plan compensation, pension benefits or perquisites in 2023
and did not have any stock options outstanding at December 31, 2023.
(2) Mr. Evans, our President and CEO, is not included in this table because he is our employee and thus receives no compensation for his
services as director. Mr. Evans’ compensation received as an employee is shown in the Summary Compensation Table for our Named
Executive Officers.
(3) On May 1, 2023, each non-employee director received an annual equity award of restricted stock units equivalent to $120,000 that will
vest following our 2024 annual meeting. The grant date fair value of a restricted stock unit is the closing price of a share of our common
stock on the grant date.
Includes common stock equivalents, unvested restricted stock units and associated earned dividends (1,899 shares for each director that
will vest, if not deferred, at the 2024 annual meeting) and deferred stock units (1,753 shares for Ms. McAllister and Messrs. Granger,
Mills, and Schober who elected to defer their restricted stock awards until they separate from the board).
(4)
Dividend equivalents accrue on the common stock equivalents and restricted stock units.
17
PROXY| PROXY STATEMENT
DIRECTOR STOCK OWNERSHIP GUIDELINES
Each member of our Board is required to hold shares of common stock, common stock equivalents, or restricted stock units
equal to five times the annual cash Board retainer. Currently, all of our directors have met the stock ownership guideline
except for Messrs. Granger and Prochazka, who have been on the Board for less than four years.
SECURITY OWNERSHIP OF MANAGEMENT AND PRINCIPAL SHAREHOLDERS
The following table sets forth the beneficial ownership of our common stock as of February 23, 2024 for each director, each
executive officer named in the Summary Compensation Table, all of our current directors and executive officers as a group
and each person known by us to beneficially own more than five percent of our outstanding shares of common stock.
Beneficial ownership includes shares a director or executive officer has or shares the power to vote or transfer. There were no
stock options outstanding for any of our directors or executive officers as of February 23, 2024.
Except as otherwise indicated by footnote below, we believe that each individual named has sole investment and voting power
with respect to the shares of common stock indicated as beneficially owned by that individual.
Name of Beneficial Owner (1)
Outside Directors
Barry M. Granger
Tony A. Jensen
Kathleen S. McAllister
Steven R. Mills
Robert P. Otto
Scott M. Prochazka
Rebecca B. Roberts
Mark A. Schober
Teresa A. Taylor
Named Executive Officers
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
All current directors and executive officers as
a group (15 persons)
Shares of
Common Stock
Beneficially
Owned (2)
Outstanding
Equity Awards (3)
Total
Percentage
2,634
10,730
7,372
20,561
7,362
4,387
8,599
7,979
6,525
159,840
22,174
42,771
15,727
8,702
3,871
3,857
5,610
21,807
8,859
2,118
21,267
13,116
9,422
6,505
14,587
12,982
42,368
16,221
6,505
29,866
21,095
15,947
159,840
22,174
42,771
15,727
8,702
341,564
89,927
431,491
*
*
*
*
*
*
*
*
*
*
*
*
*
*
*
* Represents less than one percent of the common stock outstanding.
(1) Beneficial ownership means the sole or shared power to vote, or to direct the voting of, a security or investment power with respect to a
(2)
security.
Includes restricted stock held by the following executive officers for which they have voting power but not investment power: Mr. Evans -
29,229 shares; Ms. Nooney - 6,005 shares; Mr. Iverson - 6,412 shares; Ms. Jones - 3,994 shares; Mr. Keller - 3,206 shares and all
directors and executive officers as a group 84,825 shares. Includes 1,899 restricted stock units held by each director.
(3) Represents common stock equivalents allocated to the directors’ accounts prior to January 1, 2022 under our former directors’ stock-
based compensation plan, of which there are no voting rights, and deferred restricted stock units for directors who elected to defer their
equity compensation after January 1, 2022.
18
PROXYPROXY STATEMENT |
PRINCIPAL SHAREHOLDERS
Set forth in the table below is information about the number of shares held by persons we know to be the beneficial owners of
more than 5% of the issued and outstanding Common Stock:
Name and Address
BlackRock, Inc.(1)
50 Hudson Yards
New York, NY 10001
The Vanguard Group Inc.(3)
100 Vanguard Blvd.
Malvern, PA 19355
State Street Corporation(2)
State Street Financial Center
1 Congress Street, Suite 1
Boston, MA 02114-2016
Shares of
Common Stock
Beneficially
Owned
Percentage
10,122,756
14.9%
8,143,567
12.0%
3,665,284
5.4%
(1) Information is as of December 31, 2023, and is based on a Schedule 13G/A filed on January 25, 2024. BlackRock, Inc.
has sole voting power with respect to 9,984,516 shares and sole investment power with respect to 10,122,756 shares.
(2) Information is as of December 31, 2023, and is based on a Schedule 13G filed on January 25, 2024. State Street
Corporation has shared voting power with respect to 3,389,369 shares and shared investment power with respect to
3,656,584 shares.
(3) Information is as of December 31, 2023, and is based on a Schedule 13G/A filed on February 13, 2024. The Vanguard
Group Inc. has shared voting power with respect to 77,164 shares and sole investment power with respect to 8,002,478
shares.
19
PROXY| PROXY STATEMENT
PROPOSAL 2
RATIFICATION OF APPOINTMENT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
The firm of Deloitte & Touche LLP, independent registered public accountants, conducted the audit of Black Hills Corporation
and its subsidiaries for 2023. Representatives of Deloitte & Touche LLP will be present at our annual meeting and will have the
opportunity to make a statement, if they desire to do so, and to respond to appropriate questions.
Our Audit Committee has appointed Deloitte & Touche LLP to perform an audit of our consolidated financial statements and
those of our subsidiaries for 2024 and to render their reports. In determining whether to recommend to the full Board the
reappointment of Deloitte & Touche LLP as our independent auditor, the Audit Committee considered the following:
•
•
•
•
•
•
Technical expertise and knowledge of the Company’s business and industry
The quality and candor of communications with the Audit Committee
Deloitte & Touche LLP’s independence
Public Company Accounting Oversight Board inspection reports on the firm
Input from management on Deloitte & Touche LLP’s performance, objectivity and professional judgment
The appropriateness of fees for audit and non-audit services
The Board recommends ratification of the Audit Committee’s appointment of Deloitte & Touche LLP. The appointment of
Deloitte & Touche LLP as our independent registered public accounting firm for 2024 will be ratified if the votes cast “For”
exceed the votes cast “Against.” Abstentions will have no effect on such vote. If shareholder approval for the appointment of
Deloitte & Touche LLP is not obtained, the Audit Committee will reconsider the appointment.
The Board recommends a vote FOR ratification of the appointment of Deloitte & Touche LLP
to serve as our independent registered public accounting firm for 2024.
20
PROXYPROXY STATEMENT |
FEES PAID TO THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The following charts set forth the aggregate fees for services provided to us for the years ended December 31, 2023 and 2022
by our independent registered public accounting firm, Deloitte & Touche, the member firms of Deloitte & Touche and their
respective affiliates:
Audit Fees
Fees for professional services rendered for the audits of our financial statements, review of the interim financial statements
included in quarterly reports, opinions on the effectiveness of our internal control over financial reporting, and services that
generally only the independent auditor can reasonably provide, such as comfort letters, statutory audits, consents and
assistance with and review of documents filed with the SEC.
Audit-Related Fees
Fees for assurance and related services that are reasonably related to the performance of the audit or review of our financial
statements and are not reported under “Audit Fees.” These services include employee benefit plan audits.
Tax Compliance Fees
Fees for services related to federal and state tax compliance.
Tax Planning and Advisory Fees
Fees for planning and advisory services.
The services performed by D&T were pre-approved in accordance with the Audit Committee’s policy whereby the Audit
Committee pre-approves all audit and permissible non-audit services provided by the independent registered public
accountants. The Audit Committee will generally pre-approve a list of specific services and categories of services, including
audit, audit-related, tax and other services, for the upcoming or current year, subject to a specified cost level. Any service that
is not included in the approved list of services must be separately pre-approved by the Audit Committee.
21
PROXY| PROXY STATEMENT
AUDIT COMMITTEE REPORT
The Audit Committee assists the Board in fulfilling its oversight responsibilities to shareholders relating to the integrity of the
Company’s financial statements, the Company’s compliance with legal and regulatory requirements regarding financial reporting, the
independent auditors’ qualifications and independence, and the performance of the Company’s internal and independent auditors.
Management has the primary responsibility for the completeness and accuracy of the Company’s financial statements and
disclosures, the financial reporting process, and the effectiveness of the Company’s internal control over financial reporting.
Our independent auditors, Deloitte & Touche LLP, are responsible for auditing the Company’s consolidated financial statements and
expressing an opinion as to whether they are presented fairly, in all material respects, in conformity with accounting principles
generally accepted in the United States.
In fulfilling its oversight responsibilities for 2023, the Audit Committee, among other things:
•
•
•
•
•
•
•
•
•
•
•
Reviewed and discussed the audited financial information contained in the Annual Report on Form 10-K with management
and our independent auditors prior to public release.
Reviewed and discussed with our independent auditors their judgments as to the quality, not just the acceptability, of our
critical accounting principles and estimates and all other communications required to be discussed with the Audit
Committee under generally accepted auditing standards, including the matters required to be discussed by the applicable
requirements of the Public Company Accounting Oversight Board and the SEC.
Reviewed and discussed with management, our internal auditors and our independent auditors management’s report on
internal control over financial reporting, including the significance and status of control deficiencies identified by
management and the results of remediation efforts undertaken, to determine the effectiveness of internal control over
financial reporting at December 31, 2023.
Reviewed with our independent auditors their report on the Company’s internal control over financial reporting at
December 31, 2023, including the basis for their conclusions.
Reviewed and pre-approved all audit and non-audit services and fees provided to the Company by our independent
auditors and considered whether the provision of such non-audit services by our independent auditors is compatible with
maintaining their independence.
Discussed with our internal and independent auditors their audit plans, audit scope and identification of audit risks and
reviewed the results of internal audit examinations.
Reviewed and discussed the interim financial information contained in each quarterly earnings announcement and
Quarterly Report on Form 10-Q with management and our independent auditors prior to public release.
Received and reviewed periodic corporate compliance and financial risk reports, including credit and hedging activity.
Held private sessions with our independent auditors, Vice President - Internal Audit, Chief Financial Officer and Controller,
and Chief Compliance Officer.
Received the written disclosures and the letter from our independent auditors required by the applicable requirements of
the Public Company Accounting Oversight Board regarding the independent auditors’ communications with the Committee
concerning independence and discussed the independence of Deloitte & Touche LLP with them.
Concluded Deloitte & Touche LLP is independent based upon the above considerations.
Based upon the reviews and discussions referred to above, the Audit Committee recommended to the Board that our audited
consolidated financial statements be included in our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the
SEC. The Audit Committee also recommended and the Board reappointed Deloitte & Touche LLP as our independent registered
public accounting firm for 2024. Shareholders are being asked to ratify that selection at the 2024 Annual Meeting.
THE AUDIT COMMITTEE
Mark A. Schober, Chair
Tony A. Jensen
Kathleen S. McAllister
Robert P. Otto
22
PROXYPROXY STATEMENT |
PROPOSAL 3 ADVISORY VOTE ON OUR EXECUTIVE COMPENSATION
We are providing shareholders with an annual advisory, non-binding vote on the executive compensation of our Named
Executive Officers (commonly referred to as “say on pay”). Accordingly, shareholders will vote on approval of the following
resolution:
RESOLVED, that the shareholders approve, on an advisory basis, the compensation of our Named
Executive Officers as disclosed in the Compensation Discussion and Analysis section, the accompanying
compensation tables and the related narrative disclosure in this proxy statement.
This vote is non-binding. The Board and the Compensation Committee expect to consider the outcome of the vote when
considering future executive compensation decisions to the extent they can determine the cause or causes of any significant
negative voting results. At our 2023 annual meeting, shareholders owning 98 percent of the shares that were voted in this
matter approved our executive compensation.
As described at length in the Compensation Discussion and Analysis section of this proxy statement, we believe our executive
compensation program is reasonable, competitive and strongly focused on pay for performance. The compensation of our
Named Executive Officers varies depending upon the achievement of pre-established performance goals, both individual and
corporate. Our short-term incentive is tied to earnings per share, safety performance targets, system safety and reliability
targets, customer experience targets, and diversity targets that reward our executives when they deliver targeted results. Our
long-term incentive performance shares or units vest based upon the level of achievement of certain pre-established
performance goals over a three-year performance period as described in the Compensation Discussion and Analysis. Through
stock ownership guidelines, equity incentives and clawback provisions, we align the interests of our executives with those of
our shareholders and our long-term interests. Our executive compensation policies have enabled us to attract and retain
talented and experienced senior executives who can drive financial and strategic growth objectives that are intended to
enhance shareholder value. We believe that the 2023 compensation of our Named Executive Officers was appropriate and
aligned with our 2023 results and positions us for long-term growth.
Shareholders are encouraged to read the Compensation Discussion and Analysis, the accompanying compensation tables,
and the related narrative disclosures to better understand the compensation of our Named Executive Officers.
The advisory resolution to approve executive compensation is non-binding. However, our Board will consider shareholders to
have approved our executive compensation if the number of votes cast “For” the proposal exceeds the number of votes cast
“Against” the proposal. Abstentions and broker non-votes will have no effect on such vote.
The Board recommends a vote FOR the advisory vote on executive compensation.
23
PROXY| PROXY STATEMENT
EXECUTIVE COMPENSATION
COMPENSATION DISCUSSION AND ANALYSIS
INTRODUCTION
This Compensation Discussion and Analysis describes our overall executive compensation policies and practices and
specifically explains the compensation-related actions taken with respect to 2023 compensation for our Named Executive
Officers included in the Summary Compensation Table. The Compensation Committee of the Board (the "Committee" for
purposes of this Compensation Discussion and Analysis), is composed entirely of independent directors and is responsible for
approving and overseeing our executive compensation philosophy, policies and programs.
Our Named Executive Officers, based on 2023 positions and compensation levels, are:
Named Executive Officers
Title
Linden R. Evans
President and Chief Executive Officer
Kimberly F. Nooney
Sr. Vice President and Chief Financial Officer
Brian G. Iverson
Erik D. Keller
Marne M. Jones
Sr. Vice President, General Counsel and Chief Compliance Officer
Sr. Vice President - Chief Information Officer
Sr. Vice President - Utilities
Richard W. Kinzley (1)
Former Sr. Vice President and Chief Financial Officer
Reference
Evans, CEO
Nooney, CFO
Iverson, GC
Keller, CIO
Jones, SVP
Kinzley,
Former CFO
(1) Mr. Kinzley retired effective July 3, 2023.
KEY EXECUTIVE COMPENSATION OBJECTIVES
Overall, our goal is to target total direct compensation (the sum of base salary, short-term incentive at target and long-term
incentive at target) to be around the median of the appropriate market. Our executive compensation is designed to maintain an
appropriate and competitive balance between fixed and variable compensation components including short-and long-term
compensation, and cash and stock-based compensation. We believe that the performance basis for determining
compensation should differ by each reward component – base salary, short-term incentive and long-term incentive. Incentive
measures (short-term and long-term) should emphasize objective, quantitative operating measures. The performance
measures for our incentive compensation plans are discussed below.
24
PROXYPROXY STATEMENT |
BEST PRACTICES IN EXECUTIVE COMPENSATION
Our executive compensation program reflects the following best practices, which ensure effective compensation governance
and align the interests of our shareholders and executives.
What we do:
A significant portion of executive pay is at risk by granting
incentive awards that are based on continuing annual and
long-term metrics tied to performance.
Short-Term incentive plan awards are capped at 200% of
target.
Long-Term incentive plan awards are capped at 200% of
target number of shares granted.
Beginning with 2023 grants, non-vested equity awards are
not accelerated after a change in control unless the
executive is: (1) terminated without cause or good reason; or
(2) the award is not assumed or substituted by the successor
company
Executives and directors are subject to stock ownership
guidelines and retention requirements.
X No employment agreements with executives.
What we do not do:
X No change in control cash severance payments that exceed
three times base salary and target bonus.
X No excise tax gross-ups for executives.
X No hedging or pledging of Company stock.
X No excessive perquisites for executives.
2023 COMPENSATION PRACTICE CHANGES
The Compensation Committee engaged Meridian Compensation Partners, LLC (Meridian) to review our executive
compensation plans and practices. Based on this review and recommendations from Meridian and the Company's business
strategy, the Compensation Committee made the following changes to our executive compensation practices for 2023:
Prior Executive Compensation
Practice
Revised Executive Compensation
Practice
Rationale for Change
Short-Term Incentive Five performance measures and the
corresponding weighting:
Five goal categories and the
corresponding weighting:
70% EPS from ongoing operations,
as adjusted
70% EPS from ongoing operations, as
adjusted
7.5% System Average Interruption
Duration Index (SAIDI)
7.5% Hits Per Thousand (HPT)
7.5% Total Case Incident Rate
(TCIR)
7.5% Diversity Training
7.5% Safety Index metrics
7.5% System Safety and Reliability Index
metrics
7.5% Customer Experience Index metrics
7.5% Diversity Index metrics
Safety metrics reinforce a
culture of safety by
encouraging employee
attention to key proactive
safety actions and
outcome-based safety
results.
System Safety and
Reliability metrics
reinforce our commitment
to safe and reliable
operations and
environmental
stewardship.
Customer Experience
metrics measure the
quality of our customer
service through multiple
points of interaction.
Diversity metrics reinforce
our commitment to
advancing diversity in our
workforce.
Long-Term Incentive 60% Performance Share Units and
70% Performance Share Units and
A higher performance
40% Restricted Stock Awards
30% Restricted Stock Awards
based percentage drives
long-term
focus/behaviors/actions on
the performance
measures and aligns with
peer group practices.
25
PROXY| PROXY STATEMENT
Our executive compensation program reflects the following best practices, which ensure effective compensation governance
SETTING EXECUTIVE COMPENSATION
X No employment agreements with executives.
What we do not do:
Based upon our compensation philosophy, the Committee structures executive compensation to motivate our executives to
achieve specified business goals and to reward them for achieving such goals. The key steps the Committee follows in setting
executive compensation are to:
Analyze executive compensation market data to ensure market competitiveness
Review the components of executive compensation, including base salary, short-term incentive, long-term incentive,
retirement, and other benefits
Review total compensation and structure
Review executive officer performance, responsibilities, experience, and other factors cited above to determine individual
compensation levels
EXECUTIVE COMPENSATION PROGRAM DESIGN OBJECTIVES
Attract, retain, motivate,
and encourage the
development of highly
qualified executives
Provide competitive
compensation
Promote the
relationship between
pay and performance
Promote corporate
performance that is
linked to our
shareholders’ interests
Recognize and reward
individual performance
Market Compensation Analysis
The market for our executive talent is national in scope and is not focused on any one geographic location, area or region of
the country. As such, our executive compensation should be competitive with the national market for executives. It should also
reflect the executive’s responsibilities and duties and align with the compensation of executives at companies or business
units of comparable size and complexity. The Committee gathers market information for our executives from the electric and
gas utility industry and general industry.
The Committee selects and retains the services of an independent consulting firm to periodically:
7.5% Safety Index metrics
Provide information regarding practices and trends in compensation programs
Review and evaluate our compensation program as compared to compensation practices of other companies with
similar characteristics, including size, complexity, and type of business
Review and assist with the establishment of a peer group of companies
Provide a compensation analysis of the executive positions
The Committee used the services of Meridian to evaluate 2023 compensation. Meridian gathered data from nationally
recognized survey providers, as well as specific peer companies through public filings, which included:
i. Willis Towers Watson’s Compensation Data Bank (energy services and general industry); and
ii.
20 peer companies representing the utility and energy industry.
BEST PRACTICES IN EXECUTIVE COMPENSATION
and align the interests of our shareholders and executives.
What we do:
A significant portion of executive pay is at risk by granting
incentive awards that are based on continuing annual and
long-term metrics tied to performance.
target.
Short-Term incentive plan awards are capped at 200% of
X No change in control cash severance payments that exceed
three times base salary and target bonus.
Long-Term incentive plan awards are capped at 200% of
X No excise tax gross-ups for executives.
target number of shares granted.
Beginning with 2023 grants, non-vested equity awards are
X No hedging or pledging of Company stock.
not accelerated after a change in control unless the
executive is: (1) terminated without cause or good reason; or
(2) the award is not assumed or substituted by the successor
company
Executives and directors are subject to stock ownership
X No excessive perquisites for executives.
guidelines and retention requirements.
2023 COMPENSATION PRACTICE CHANGES
The Compensation Committee engaged Meridian Compensation Partners, LLC (Meridian) to review our executive
compensation plans and practices. Based on this review and recommendations from Meridian and the Company's business
strategy, the Compensation Committee made the following changes to our executive compensation practices for 2023:
Prior Executive Compensation
Revised Executive Compensation
Practice
Practice
Rationale for Change
Short-Term Incentive Five performance measures and the
Five goal categories and the
corresponding weighting:
corresponding weighting:
70% EPS from ongoing operations,
70% EPS from ongoing operations, as
as adjusted
adjusted
7.5% System Average Interruption
Duration Index (SAIDI)
7.5% Hits Per Thousand (HPT)
7.5% Total Case Incident Rate
(TCIR)
7.5% Diversity Training
7.5% System Safety and Reliability Index
operations and
metrics
7.5% Customer Experience Index metrics
metrics measure the
7.5% Diversity Index metrics
Safety metrics reinforce a
culture of safety by
encouraging employee
attention to key proactive
safety actions and
outcome-based safety
results.
System Safety and
Reliability metrics
reinforce our commitment
to safe and reliable
environmental
stewardship.
Customer Experience
quality of our customer
service through multiple
points of interaction.
Diversity metrics reinforce
our commitment to
advancing diversity in our
workforce.
A higher performance
based percentage drives
long-term
focus/behaviors/actions on
the performance
measures and aligns with
peer group practices.
Long-Term Incentive 60% Performance Share Units and
70% Performance Share Units and
40% Restricted Stock Awards
30% Restricted Stock Awards
26
PROXYPROXY STATEMENT |
The 20 peer companies ranged in annual revenue size from approximately $656 million to $8.1 billion, with the median at $2.4
billion. The Company’s 2023 revenue was $2.3 billion. The survey data was adjusted for our relative revenue size using
regression analysis. Our compensation peer companies included in the analysis for 2023 compensation decisions were:
ALLETE Inc.
Alliant Energy Corporation
IDACORP Inc.
MGE Energy Inc.
ONE Gas, Inc.
Pinnacle West Capital Corp.
Ameren Corporation
Atmos Energy Corp.
Avista Corp.
CMS Energy Corp.
Hawaiian Electric Ind., Inc.
New Jersey Resources Corp.
PNM Resources, Inc.
NiSource, Inc.
Portland General Electric Co.
Northwest Natural Holding Co.
South Jersey Industries, Inc. (1)
NorthWestern Corp.
OGE Energy Corp.
Spire, Inc.
(1) South Jersey Industries, Inc. is no longer an SEC registrant following completion of a merger in February 2023, and was therefore removed
from the peer group.
Meridian validated that the above Compensation Peer Group remains credible, includes size-appropriate peers, and reflects
the Company's industry, complexity and market for executive talent.
The salary surveys are one of several factors the Committee uses in setting appropriate compensation levels. Other factors
include Company performance, individual performance and experience, the level and nature of the executive’s responsibilities,
internal equity considerations and discussions with the CEO related to the other senior executive officers' performance and
contributions.
Components of Executive Compensation
The primary components of our executive compensation program consist of a base salary, a short-term incentive plan, and
long-term incentives. In addition, we provide retirement and other benefits. The Committee reviews all components of each
executive officer's compensation, including salary, short-term incentive, equity and other long-term incentive compensation
values granted, and the current and potential value of the executive officer's total Black Hills Corporation equity holdings.
The majority of the executives’ total compensation is granted as incentive compensation. Incentive compensation is intended
to motivate and encourage our executives to drive performance and achieve superior results for our shareholders and align
realized pay with stock performance. The Committee periodically reviews information provided by its compensation consultant
to inform its determination of the appropriate level and mix of total compensation. The Committee believes that a significant
portion of total target compensation should be comprised of variable compensation. In order to reward long-term growth while
still encouraging focus on short-term results, the Committee establishes incentive targets that emphasize long-term
compensation at a greater level than short-term compensation.
Base Salary. Base salaries for all executives are reviewed annually. The base salary of our executives is also adjusted at the
time of a promotion or material change in job responsibility, as appropriate. Evaluation of 2023 base salary adjustments
occurred in January 2023. The base salary component of each position was compared to the median of the market data
provided by the compensation consultant. The actual base salary of each officer was determined based on the executive’s
performance, the experience level of the officer, the current position in a market-based salary range, and internal pay
relationships.
Base Salary
2022
2023
Evans, CEO
Nooney, CFO (1)
Iverson, GC
Jones, SVP (2)
Keller, CIO
Kinzley, Former CFO
________
(1) Ms. Nooney was appointed CFO effective April 1, 2023.
(2) Ms. Jones was appointed Senior Vice President - Utilities effective June 12, 2023
860,000 $
375,000 $
416,000 $
340,000 $
354,000 $
472,000 $
900,000
440,000
433,000
398,000
368,000
472,000
$
$
$
$
$
$
Short-Term Incentive. Our Short-Term Incentive Plan is designed to recognize and reward the contributions of individual
executives as well as the contributions that group performance makes to overall corporate success. The 2023 short-term
incentive was based on the following metrics:
27
PROXY| PROXY STATEMENT
Metric
Weighting
Definition
2023 Short-Term Incentive Metrics
EPS from ongoing
operations, as
adjusted
Timeliness of Incident
Reporting
Average Proactive
Safety
Activities/Employee
Total Case Incident
Rate (TCIR)
Preventable Motor
Vehicle Incident Rate
(PMVI)
Gas Distribution
Damage Prevention
(HPT)
Electric Reliability
(SAIDI)
Customer Interaction:
Customer Effort
Customer Interaction:
Net Promoter Score
Customer
Brand/Perception: JD
Power Gas vs Industry
Customer
Brand/Perception: JD
Power Electric vs
Industry
Percent of Diverse
Candidate Slates
Percent of Diverse
Interview Panels
70.00%
Diluted earnings per share calculated in accordance with GAAP, adjusted for material, non-recurring events (such as
impairment charges, one-time tax events, external acquisition costs, changes to accounting rules, etc.)
1.875%
Reporting of injuries within 24 hours
1.875%
Includes reporting of near misses, safety suggestions, unsafe conditions, stop work authority, and pipeline near
misses
1.875%
Injuries per 200,000 hours worked
1.875%
Preventable motor vehicle incident rate
3.75%
Hits per thousand
3.75%
System average interruption duration index
2.50%
Third party survey of 25,000 customers regarding "How easy is BHE to do business with?"
2.50%
Third party survey of 25,000 customers regarding "How likely are you to recommend BHE?"
1.25%
Third party scoring of brand perception relative to other gas utilities
1.25%
Third party scoring of brand perception relative to other electric utilities
3.75%
A slate that includes at least 1 woman and/or racially/ethnically diverse candidate
3.75%
A panel that includes at least 1 woman and/or racially/ethnically diverse individual in the final interview
2023 Short-Term Incentive Goals
Incentive
EPS from ongoing operations, as adjusted
Timeliness of Incident Reporting
Average Proactive Safety Activities/Employee
Total Case Incident Rate (TCIR)
Preventable Motor Vehicle Incident Rate (PMVI)
Gas Distribution Damage (HPT)
Electric Reliability (SAIDI)
Customer Interaction: Customer Effort
Customer interaction: Net Promotor Score
Customer Brand/Perception: JD Power Gas vs Industry
Customer Brand/Perception: JD Power Electric vs Industry
Percent of Diverse Candidate Slates
Percent of Diverse Interview Panels
Payout percentage of target for each metric
Threshold
$3.488
90%
2
1.39
1.56
2.20
72.80
8.80
64.00
25%
+1 ranking
80%
90%
50%
Goals
Target
$3.750
91%
3
1.23
1.44
2.05
65.70
8.90
67.00
50%
+2 ranking
85%
92%
100%
Maximum
$4.013
92%
4
1.11
1.33
1.80
51.80
9.00
70.00
75%
+3 ranking
90%
94%
200%
The Committee believes that these performance measures meet the objectives of the plan, including:
Align the interests of the plan participants and the shareholders
Motivate employees to strive to achieve superior operating results
Provide an incentive reflective of core operating performance
Ensure “buy-in” from participants with easily understood metrics
Meet the performance objectives of the plan to achieve over time an average payout equal to market competitive
levels
The short-term incentive, after applicable tax withholding, is distributed to the officer in the form of cash. Target award levels
are established as a percentage of each participant’s base salary. A target award is typically set around the benchmark 50th
percentile short-term incentive target award for comparable positions. The actual payout, if any, will vary, based on attainment
of pre-established performance goals, between 0 and 200 percent of the individual executive’s short-term incentive target
award level.
28
PROXYPROXY STATEMENT |
The Committee approves the target level for each officer in January, which applies to performance in the upcoming plan year.
Target levels are derived in part from market data provided by the compensation consultant and in part by the Committee’s
judgment regarding internal equity, retention and an individual executive’s expected contribution to the achievement of our
strategic objectives. The target levels for our Named Executive Officers are shown below:
Evans, CEO
Nooney, CFO
Iverson, GC
Jones, SVP
Keller, CIO
Kinzley, Former CFO
Short-Term Incentive Target
2022
2023
% of Base
Salary
100%
45%
60%
45%
50%
70%
$ Amount
$
$
$
$
$
$
860,000
168,750
249,600
153,000
177,000
330,400
% of Base
Salary
100%
60%
70%
55%
50%
70%
$ Amount
$
$
$
$
$
$
900,000
264,000
303,100
218,900
184,000
330,400
The threshold, target and maximum payout levels for our Named Executive Officers under the 2023 Short-Term Incentive Plan
are shown in the Grants of Plan-Based Awards in 2023 table on page 38, under the heading “Estimated Future Payouts Under
Non-Equity Incentive Plan Awards.”
Early in the first quarter, the Committee evaluates actual performance in relation to the prior year’s targets and approves the
actual payment of awards related to the prior plan year. The Committee reserves the discretion to adjust any award, and will
review and take into account individual performance, level of contribution, and the accomplishment of specific project goals
that were initiated throughout the plan year. The Committee also reserves discretion with respect to any payout related to
safety goals if we experience an employee or contractor fatality during the plan period. For 2023, the Committee exercised its
discretion and approved a $0.022 increase to EPS from ongoing operations, as adjusted, resulting in $3.932 of EPS for
compensation purposes. The adjustment to EPS excluded certain project costs that were not anticipated when the original
metrics were set. Except for the Committee's discretionary increase, earnings per share from ongoing operations, as adjusted,
for incentive plan purposes were the same as earnings per share, diluted, reported externally to our investors.
On January 25, 2024, the Committee approved a payout of 153.67% percent of target under the 2023 Short-Term Incentive
Plan. The incentive plan payout was based on attainment of the following:
2023 Results Goal Payout % of Award
169.200%
200.00%
200.00%
0.00%
0.00%
100.00%
129.78%
50.00%
73.33%
82.00%
0.00%
200.00%
200.00%
$3.932
93%
4
1.51
1.65
2.05
61.56
8.80
65.40
41%
0.00
90%
96%
70.000%
1.875%
1.875%
1.875%
1.875%
3.750%
3.750%
2.500%
2.500%
1.250%
1.250%
3.750%
3.750%
100%
Payout
118.440%
3.750%
3.750%
0.000%
0.000%
3.750%
4.867%
1.250%
1.833%
1.025%
0.000%
7.500%
7.500%
153.67%
Incentive
EPS from ongoing operations, as adjusted
Timeliness of Incident Reporting
Average Proactive Safety Activities/Employee
Total Case Incident Rate (TCIR)
Preventable Motor Vehicle Incident Rate (PMVI)
Gas Distribution Damage (HPT)
Electric Reliability (SAIDI)
Customer Interaction: Customer Effort
Customer interaction: Net Promotor Score
Customer Brand/Perception: JD Power Gas vs Industry
Customer Brand/Perception: JD Power Electric vs Industry
Percent of Diverse Candidate Slates
Percent of Diverse Interview Panels
Total Payout
29
PROXY| PROXY STATEMENT
Payouts under the Short-Term Incentive Plan have varied over the last 10 years as shown in the graph below.
Actual awards made to each of our Named Executive Officers under the Short-Term Incentive Plan for 2023 are included in
the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table on page 37.
For the 2024 Short-Term Incentive Plan, we are maintaining our commitment to financial performance with EPS from ongoing
operations as adjusted, changing our outcome-based safety metric to replace TCIR and PMVI with the Days Away, Restricted
or Transferred Rate (DART), modifying our customer experience metrics to update our methodology for measuring customer
satisfaction and customer effort to leverage internal customer feedback tools instead of NPS and JD Power and continuing our
commitment to diversity by replacing diverse candidate slates and interview panels with a new metric intended to increase
diversity in leadership positions. Our metrics for customer experience, diversity, and system safety and reliability demonstrate
our continued efforts to improve our social and environmental ESG performance.
Long-Term Incentive. Our Long-Term Incentive Plan (LTIP) is designed to focus executive performance on sustained long-
term results that drive or are based on shareholder value creation. Long-term incentive compensation is intended to:
Promote achievement of corporate goals by linking the interests of participants to those of our shareholders
Provide participants with an incentive for excellence in individual performance
Promote teamwork among participants
Motivate, retain, and attract the services of participants who make significant contributions to our success by allowing
participants to share in such success
Meet the performance objectives of the plan to achieve an average payout equal to market competitive levels over
time
30
PROXYPROXY STATEMENT |
The Committee approved the metrics for the Performance plan portion of our Long-term incentive plans as follows:
Plan
Metrics
Definition
Performance Plan Metrics
2021-2023 Plan and 2022-
2024 Plan
60% TSR
Total shareholder return
20% EPS
20% Average
Cost to Serve
Diluted earnings per share calculated in accordance
with GAAP, adjusted for material, non-recurring events
(such as impairment charges, one-time tax events,
external acquisition costs, changes to accounting rules,
etc.)
Non-fuel operations and maintenance (O&M) expense
divided by Utility margin (a non-GAAP measure (1) which
represents revenue less cost of sales), adjusted for
material, non-recurring events (such as impairment
charges, external acquisition costs, changes to
accounting rules, etc.)
2023-2025 Plan
70% TSR
Total shareholder return
Diluted earnings per share calculated in accordance
with GAAP, adjusted for material, non-recurring events
(such as impairment charges, one-time tax events,
external acquisition costs, changes to accounting rules,
etc.)
Non-fuel operations and maintenance (O&M) expense
divided by Utility margin (a non-GAAP measure (1) which
represents revenue less cost of sales), adjusted for
material, non-recurring events (such as impairment
charges, external acquisition costs, changes to
accounting rules, etc.)
10% EPS
10% Average
Cost to Serve
10%
Emissions
Reduction
Rationale
Executive pay under a long-term,
capital accumulation program should
mirror performance in shareholder
return and directly aligns with
shareholders and reflects our
performance relative to peers
Aligns with long-term performance
growth
Drives growth goals while balancing
capital deployment with increasing
customer rates
Executive pay under a long-term,
capital accumulation program should
mirror performance in shareholder
return and directly aligns with
shareholders and reflects our
performance relative to peers
Aligns with long-term performance
growth
Drives growth goals while balancing
capital deployment with increasing
customer rates
Natural gas emissions reduction by 2035
Aligns with sustainability goals
________
(1) For further information regarding Utility margin, a non-GAAP measure, please see Item 7 - Management’s Discussion and Analysis of
Financial Condition and Results of Operations in our 2023 Annual Report on Form 10-K as filed with the U.S. Securities and Exchange
Commission on February 14, 2024.
The long-term incentive compensation component is composed of performance share units and restricted stock that vests
ratably over three years. The Committee chose these components because linking executive compensation to stock price
appreciation, total shareholder return, and other key financial and environmental metrics is an effective way to align the
interests of management with those of our shareholders. The split between performance share units and restricted stock for
each plan period is illustrated below:
31
PROXY| PROXY STATEMENT
The value of long-term incentives awarded is based primarily on competitive market-based data presented by the
compensation consultant to the Committee, the impact each position has on our shareholder return, executive performance,
and internal pay relationships. The actual amount realized may vary from the target award amounts. The Committee approved
the target long-term incentive compensation level for each officer in January 2023. The 2023 long-term incentive was adjusted
from 2022 levels for Mr. Evans to align more closely with market median and Ms. Nooney to align with her promotion to CFO.
NEO Long-Term Incentive Target Compensation
Evans, CEO
Nooney, CFO
Iverson, GC
Jones, SVP
Keller, CIO
Kinzley, Former CFO
2022
2023
2,300,000 $
250,000 $
600,000 $
250,000 $
300,000 $
625,000 $
2,700,000
600,000
600,000
250,000
300,000
—
$
$
$
$
$
$
Performance Share Units. Participants are awarded a target number of performance share units. The target number of
performance share units is determined by dividing the Committee approved target performance value for the participant by the
average closing price for the established number of trading days preceding the performance period.
Vesting of performance share units associated with TSR is based on our total shareholder return over designated performance
periods as measured against our Performance Peer Group. The Committee, with the guidance of its independent
compensation consultant, periodically conducts a review of our Performance Peer Group to which our performance should be
compared. Due to the extensive merger and acquisition activity in the industry and its contribution to relative performance
volatility, the Committee chose to continue to use the companies in the EEI Index as the Performance Peer Group for 2023.
A summary of the TSR performance criteria for the 2023-2025 performance share units is summarized in the table below:
Percentile Ranking for
Threshold Payout of 25% of
Target Shares
Percentile Ranking for
Target Payout of 100% of
Target Shares
Percentile Ranking for
Maximum Payout Level
Possible Payout Range of
Target
Performance Share Plans
25th percentile
50th percentile
90th percentile
0-200%
The 2023-2025 Performance plan, for the portion of the award that vests based on relative TSR, provides: (i) a threshold
payout if relative TSR performance is below threshold but our TSR is at least 35 percent for the performance period; and (ii)
the performance share plan payout is capped at 100 percent of target if TSR is negative. The additional provisions are
intended to reduce the impact of one peer company’s performance on the relative TSR, and also increase accountability and
expectations related to the Company’s performance.
Vesting of performance share units associated with Earnings Per Share, Average Cost to Serve, and Emissions Reduction
performance is determined based upon the Company's performance against established performance goals. The final value of
the performance shares is based upon the number of shares of common stock that are ultimately earned, based upon our
performance in relation to the performance criteria.
Threshold performance results in a payout of 25 percent of the target share award. Target performance results in a payout of
the target share award. Maximum performance results in a payout of 200 percent of the target share award.
The performance share units and dividend equivalents, if earned, are paid in common stock. Performance share units are pro-
rated for the period of service in the events of retirement, death or disability. Performance share units vest in full under certain
circumstances following a change in control. Performance awards are forfeited if an officer's employment is terminated for any
reason other than those previously stated.
Restricted Stock. Restricted stock awarded as long-term incentives vests one-third each year over a three-year period, and
automatically vests in its entirety upon death, disability or under certain termination circumstances following a change in
control. Dividends are paid on the restricted stock. Unvested restricted stock is forfeited if an officer’s employment is
terminated for any reason other than those previously stated.
Payouts under the Performance Share Plan have varied significantly over the last 10 years, as shown in the graph below.
Each performance period extends for three years. For the recently completed performance period, January 1, 2021 to
December 31, 2023, the payout was based on attainment of the following:
32
PROXYPROXY STATEMENT |
Metric
2021-2023 Results
Total Shareholder Return (TSR)
TSR relative to Performance Peer Group
Average EPS as Adjusted
Average Cost to Serve
Total Payout
1.27%
16th Percentile
$3.882
46.3%
Goal Payout
as a % of
Target
0.00%
25.37%
55.68%
% of Award
Payout
60%
0.00%
20%
20%
100%
5.07%
11.14%
16.21%
The 2024-2026 Performance plan portion of our Long-Term Incentive plan retains our current four metrics. The Compensation
Committee, with the guidance of its independent compensation consultant, adopted the Compensation Peer Group as the
Company's Performance Peer Group beginning with the 2024-2026 Performance plan. This change was made to better align
with our fuel mix as the companies in the EEI Index are electric-only utilities.
Board and Management Roles in Compensation Decisions
Role of Executive Officers in Compensation Decisions. In 2023, the Human Resources team, with the support of an
external compensation consultant, reviewed all compensation programs to ensure that the programs do not encourage
unnecessary risk-taking and instead encourage behaviors that support the values and operations of the Company. This review
determined that the compensation programs of the Company do not encourage excessive risk-taking or have an adverse
effect on the Company.
The CEO annually reviews the performance of each of our senior executive officers. Based upon these performance reviews
and market analysis conducted by compensation consultants, the CEO recommends the compensation for this group of
officers to the Committee.
Role of the Committee and Board in Setting Executive Compensantion. The Committee reviews and establishes the
Company’s financial targets and the CEO’s goals and objectives for the year. After the end of each year, the Committee
evaluates the CEO’s performance in light of established goals and objectives, with input from the other independent directors.
Based upon the Committee’s evaluation and recommendation, the independent directors of the Board set the CEO’s annual
compensation, including salary, short-term incentive, and long-term incentive compensation.
The Committee reviews the CEO’s recommended compensation for our senior executive officers. The Committee may
approve the CEO’s compensation recommendations for this group of officers or exercise its discretion by modifying any of the
recommended compensation and award levels in its review and approval process. The Committee is required to approve all
decisions regarding equity awards to our officers.
33
PROXY| PROXY STATEMENT
Summary
In total, the Committee believes that the 2023 compensation actions, decisions and outcomes strongly reflect and reinforce our
compensation philosophy and, in particular, emphasize the alignment between compensation and both performance and
shareholder interests. At our 2023 annual meeting, shareholders owning 98 percent of the shares that were voted on this
matter approved our executive compensation for 2022, which we consider highly supportive of our current compensation
philosophy. In connection with establishing the 2023 executive compensation program, the Board reviewed the results of the
say on pay vote, as well as market data and performance indicators.
Governance Best Practices
We have several governance programs in place to align our executive compensation with shareholder interests and to mitigate
risks in our plans. These programs include stock ownership guidelines, mandatory and supplemental clawback policies, and
the prohibition of hedging or pledging of Company stock.
STOCK OWNERSHIP GUIDELINES
The Committee has implemented stock ownership guidelines that apply to all officers based upon their level of responsibility.
We believe it is important for our officers to hold a significant amount of our common stock to further align their interests with
the interests of our shareholders. A “retention ratio” approach to stock ownership is incorporated into the guidelines. Officers
are required to retain 100 percent of all shares owned, including shares awarded through our incentive plans (net of share
withholding for taxes and, in the case of cashless stock option exercises, net of the exercise price and withholding for taxes)
until specific ownership goals are achieved.
The guidelines are shown below.
Position
CEO
CFO
Other Senior Officers
Stock Ownership Value as
Multiple of Base Salary
6X
3X
3X
At least annually, the Compensation Committee reviews common stock ownership to confirm the officers have met or are
progressing toward their stock ownership guidelines. Generally, an officer may not sell common stock unless he or she owns
common stock in excess of 110 percent of the applicable stock ownership guideline. With the exception of Mr. Keller and
Messes. Jones and Nooney, who have all been in their current roles less than four years, all of our Named Executive Officers
who are current officers have exceeded their stock ownership guidelines.
CLAWBACK OF EXECUTIVE COMPENSATION
We have adopted a Mandatory Compensation Recovery Policy that applies to all current and former Section 16 Officers. This
policy is consistent with the final rules adopted by the SEC and the NYSE. In the event of an accounting restatement to correct
an error that is (a) material to the previously issued financial statements or (b) would result in a material misstatement if the
error were corrected in the current period, the Company will seek to recover erroneously awarded incentive compensation
received by any current or former executive officer during the immediately preceding three years. This policy does not require
a finding of fault to trigger a recoupment, rather recovery may be triggered absent fraud or willful misconduct by the executive.
Erroneous compensation is the amount of compensation that is granted, earned or vested based upon attainment of a
financial reporting measure included in an accounting restatement, as described above, that would not have been received
had the financial statements in question been accurate. The Mandatory Compensation Recovery Policy is filed as an exhibit to
the 2023 Form 10-K.
The Company has also adopted a Supplemental Compensation Recovery Policy that also applies to our NEOs. Under this
Policy, our Board may seek to recover incentive compensation received by the executive in the event that such executive
officer willfully engaged in conduct which is reasonably likely to cause significant financial or reputational harm to the
Company.
UNLAWFUL INSIDER TRADING AND ANTI-HEDGING POLICY
Black Hills Corporation has adopted policies and procedures designed to prohibit unlawful insider trading, hedging
transactions and related practices. Specifically, Black Hills Corporation’s employees, officers and directors are prohibited from
trading in the Company’s securities while in possession of material, nonpublic information, from pledging its securities as
collateral, holding its securities in a margin account and entering into transactions that are designed to hedge or offset
decreases in the market value of the securities. Additionally, certain employees and officers are subject to routine and non-
34
PROXYPROXY STATEMENT |
routine blackout periods during which times trading in our securities is not permitted, as well as pre-clearance procedures to
ensure compliance with applicable internal policies.
Notwithstanding the prohibition against insider trading, the Policy aligns with the SEC rules that allow directors, officers and
employees to trade in Black Hills Corporation Securities while aware of material, nonpublic information, so long as the trades
occur pursuant to a binding contract, instruction or written trading program that complies with the requirements of Rule 10b5.
2023 BENEFITS
Retirement Benefits. We maintain a variety of employee benefit plans and programs in which our executive officers may
participate. We believe it is important to provide post-employment benefits to our executive officers and the benefits we
provide approximate retirement benefits paid by other employers to executives in similar positions. The Committee periodically
reviews the benefits provided, with assistance from its compensation consultant, to maintain a market-based benefits package.
Mr. Kinzley received a pension benefit payment in 2023.
Several years ago, we adopted a defined contribution plan design as our primary retirement plan and amended our Defined
Benefit Pension Plan (“Pension Plan”) for all eligible employees to incorporate a partial freeze in which the accrual of benefits
ceased for certain participants while other participants were allowed an election to continue to accrue benefits. None of our
Named Executive Officers met the age and service requirements to allow them to continue to accrue benefits under the
Pension Plan. Employees who no longer accrue benefits under the Pension Plan now receive Company Retirement
Contributions (“Retirement Contributions”) in the Retirement Savings Plan. The Retirement Contributions are an age and
service points-based calculation.
The 401(k) Retirement Savings Plan is offered to all our eligible employees and we provide matching contributions for certain
eligible participants. All of our Named Executive Officers are participants in the 401(k) Retirement Savings Plan and received
matching contributions in 2023. The matching contributions and the Retirement Contributions are included as “All Other
Compensation” in the Summary Compensation Table on page 37.
We also provide nonqualified plans to certain executives as approved by the Compensation Committee. The level of
retirement benefits provided by the Pension Plan and Nonqualified Plans for each of our Named Executive Officers is reflected
in the Pension Benefits for 2023 table on page 41. Our contributions to the Nonqualified Deferred Compensation Plan are
included in the All Other Compensation column of the Summary Compensation Table on page 37 and the aggregate
Nonqualified Deferred Compensation balance at December 31, 2023 is reported in the Nonqualified Deferred Compensation
for 2023 table on page 43. These retirement benefits are explained in more detail in the accompanying narrative to the tables.
Other Personal Benefits. We provide the personal use of a Company vehicle, executive health services, and limited
reimbursement of financial planning services as benefits to our executive officers. The specific amount attributable to these
benefits in 2023 is disclosed in the Summary Compensation Table on page 37. The Committee periodically reviews the other
personal benefits provided to our executive officers and believes the current benefits are reasonable and consistent with our
overall compensation program.
CHANGE IN CONTROL BENEFIT
Our Named Executive Officers may also receive severance benefits in the event of a qualifying termination in connection with
a change in control. We have no employment agreements with our Named Executive Officers. However, change in control
protections are common among our Compensation Peer Group and the Committee and our Board believes providing these
agreements to our corporate and select subsidiary officers protects our shareholder interests in the event of a change in
control by helping assure management focus and continuity.
In 2022, our Compensation Committee approved revised form of incentive award agreements that require a "double trigger"
before accelerated equity compensation will be paid to our Named Executive Officers. The double trigger provides benefits in
association with:
(1) a change in control, and
(2)
(i) a termination of employment other than by death, disability or by us for cause, or
(ii) a termination by the employee for good reason.
35
PROXY| PROXY STATEMENT
Our change in control agreements have expiration dates and our Board conducts a review of the change in control
agreements at each renewal period. Our current change in control agreements expire November 15, 2025. In general, our
change in control agreements provide a severance payment of up to 2.99 times average compensation for Mr. Evans, and up
to two times average compensation for the other Named Executive Officers. The change in control agreements do not provide
for excise tax gross-ups.
See the Potential Payments upon Termination or Change in Control table on page 44 and the accompanying narrative for
more information regarding our change in control agreements and estimated payments associated with a change in control.
TAX AND ACCOUNTING IMPLICATIONS
Section 162(m) of the U.S. Internal Revenue Code of 1986, as amended, places a limit of $1 million in compensation per year
on the amount public companies may deduct with respect to certain executive officers. The Committee continues to believe
that shareholder interests are best served if its discretion and flexibility in structuring and awarding compensation is not
restricted, even though some past and/or future compensation awards result in non-deductible compensation expenses to the
Company. The Committee's ability to continue to provide a competitive compensation package to attract, motivate and retain
the Company's most senior executives is considered critical to the Company's success and to advancing the interests of its
shareholders.
REPORT OF THE COMPENSATION COMMITTEE
The Compensation Committee has reviewed and discussed the Compensation Discussion and Analysis required by Item
402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee
recommended to our Board that the Compensation Discussion and Analysis be included in this proxy statement.
THE COMPENSATION COMMITTEE
Teresa A. Taylor, Chair
Barry M. Granger
Scott M. Prochazka
Rebecca B. Roberts
36
PROXYPROXY STATEMENT |
SUMMARY COMPENSATION TABLE
The following table sets forth the total compensation paid or earned by each of our Named Executive Officers for the years
ended December 31, 2023, 2022 and 2021. We have no employment agreements with our Named Executive Officers:
Name and
Principal Position
Linden R. Evans
President and Chief
Executive Officer
Kimberly F. Nooney (5)
Sr. Vice President and
Chief Financial Officer
Brian G. Iverson
Sr. Vice President, General Counsel and
Chief Compliance Officer
Marne M. Jones (5)
Sr. Vice President - Utilities
Erik D. Keller
Sr. Vice President - Chief Information Officer
Richard W. Kinzley (6)
Former Sr. Vice President and
Chief Financial Officer
Salary
Stock Awards(1)
Non-Equity
Incentive Plan
Compensation(2)
Changes in
Pension Value
and
Nonqualified
Deferred
Compensation
Earnings (3)
All
Other
Compensation(4)
893,333 $
854,167 $
819,167 $
429,167 $
2,729,666 $
2,394,776 $
2,238,529 $
606,568 $
1,372,785 $
610,559 $
708,252 $
395,700 $
430,167 $
413,333 $
397,667 $
388,333 $
365,667 $
351,667 $
338,333 $
236,000 $
469,000 $
454,000 $
606,568 $
624,682 $
510,213 $
252,767 $
303,274 $
312,337 $
260,251 $
— $
650,723 $
650,687 $
462,726 $
177,270 $
206,294 $
328,214 $
280,960 $
125,686 $
146,261 $
— $
234,669 $
274,770 $
35,493 $
— $
— $
13,765 $
10,405 $
— $
— $
4,968 $
— $
— $
— $
— $
— $
— $
607,725 $
627,046 $
674,960 $
144,083 $
163,506 $
164,183 $
170,934 $
123,906 $
117,496 $
109,753 $
146,667 $
277,783 $
268,377 $
282,323 $
Year
2023
2022
2021
2023
2023
2022
2021
2023
2023
2022
2021
2023
2022
2021
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Total
5,639,002
4,486,548
4,440,908
1,589,283
1,673,372
1,379,468
1,285,108
1,098,188
1,067,397
899,443
891,512
513,783
1,622,769
1,661,780
(1)
(2)
(3)
Stock Awards represent the grant date fair value related to restricted stock and performance share units that have been granted as a
component of long-term incentive compensation. The grant date fair value is computed in accordance with the provisions of accounting
standards for stock compensation. Assumptions used in the calculation of these amounts are included in Note 14 of the Notes to the
Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2023. The amounts shown for
the performance shares and performance share units represent the values that are based on the achievement of 100% of the target
performance. Assuming achievement of the maximum 200% of target performance, the value of the performance share units would be:
$4,018,777 for Mr. Evans, $893,040 for Ms. Nooney, $893,040 for Mr. Iverson, $372,162 for Ms. Jones, and $446,501 for Mr. Keller.
Non-Equity Incentive Plan Compensation represents amounts earned under the Short-Term Incentive Plan. The Compensation
Committee approved the payout of the 2023 awards on January 25, 2024 and the awards were paid on March 3, 2024.
Change in Pension Value and Nonqualified Deferred Compensation Earnings represents the net positive increase in actuarial value of
the Pension Plan and Pension Restoration Benefit (“PRB”) for the respective years. These benefits have been valued using the
assumptions disclosed in Note 13 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the
year ended December 31, 2023. Because these assumptions sometimes change between measurement dates, the change in value
reflects not only the change in value due to additional benefits earned during the period and the passage of time but also reflects the
change in value caused by changes in the underlying actuarial assumptions.
The Pension Plan and PRB were frozen effective January 1, 2010 for participants who did not satisfy the age 45 and 10 years of
service eligibility. Messrs. Evans, Kinzley and Iverson and Messes. Jones and Nooney did not meet the eligibility choice criteria and
their benefits were frozen.
Our Named Executive Officers receive employer contributions into a Nonqualified Deferred Compensation Plan (“NQDC”). The NQDC
employer contributions are reported in the All Other Compensation column. No Named Executive Officer received preferential or above-
market earnings on nonqualified deferred compensation. The change in value attributed to each Named Executive Officer from each
plan is shown in the table below:
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley
Year
2023
2022
2021
2023
2023
2022
2021
2023
2023
2022
2021
2023
2022
2021
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Defined
Benefit Plan
PRB
Total Change in
Pension Value
19,510 $
(76,130) $
(7,574) $
13,765 $
10,405 $
(40,857) $
(4,089) $
4,968 $
- $
- $
- $
(32,085) $
(91,619) $
(11,125) $
15,983 $
(63,285) $
(7,745) $
- $
- $
- $
- $
- $
- $
- $
- $
1,711 $
(5,842) $
(833) $
35,493
(139,415)
(15,319)
13,765
10,405
(40,857)
(4,089)
4,968
-
-
-
(30,374)
(97,461)
(11,958)
(4)
All Other Compensation includes amounts allocated under the 401(k) match, defined contributions, Company contributions to deferred
compensation plans, dividends received on restricted stock and unvested restricted stock units and other personal benefits. The Other
Personal Benefits column reflects the personal use of a Company vehicle, executive health, and financial planning services for each
37
PROXY| PROXY STATEMENT
NEO. All Other Compensation for Mr. Kinzley also includes a $105,000 lump sum payment that was made in lieu of a performance
share plan award for the 2023-2025 performance plan in recognition of his partial year of service in 2023.
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley
Year
2023
2023
2023
2023
2023
2023
401(k)
Match
Defined
Contributions
NQDC
Contributions
Dividends on
Restricted
Stock
Other
Personal
Benefits
Total Other
Compensation
$
$
$
$
$
$
13,800 $
17,100 $
17,044 $
17,100 $
19,800 $
19,512 $
29,700 $
26,400 $
26,456 $
26,400 $
19,800 $
24,086 $
476,817 $
76,231 $
90,220 $
63,682 $
47,705 $
112,685 $
66,365 $
10,388 $
15,720 $
6,350 $
12,308 $
5,288 $
21,043 $
13,964 $
14,066 $
10,374 $
17,883 $
116,212 $
607,725
144,083
163,506
123,906
117,496
277,783
(5) Messes. Nooney and Jones became NEOs in 2023.
(6) Mr. Kinzley retired from the Company effective July 3, 2023.
GRANTS OF PLAN BASED AWARDS IN 2023(1)
Estimated Future Payouts
Under Non-Equity Incentive Plan
Awards (2)
Estimated Future Payouts
Under Equity Incentive Plan
Awards (3)
Name
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley (6)
Date of
Compensation
Committee
Action
1/24/23
1/24/23
1/24/23
1/24/23
1/24/23
1/24/23
1/24/23
1/24/23
1/24/23
1/24/23
1/24/23
1/24/23
Grant
Date
1/24/23
2/9/23
1/24/23
2/9/23
1/24/23
2/9/23
1/24/23
2/9/23
1/24/23
2/9/23
1/24/23
2/9/23
Threshold
($)
$ 446,667
Target
($)
$ 893,333
Maximum
($)
$ 1,786,667
Threshold
(#)
Target
(#)
Maximum
(#)
6,609
26,434
52,868
$ 128,750
$ 257,500
$ 515,000
$ 150,558
$ 301,117
$ 602,233
$
98,797
$ 197,403
$ 394,806
$
91,417
$ 182,833
$ 365,667
$
82,600
$ 165,200
$ 330,400
1,469
5,874
11,748
1,469
5,874
11,748
612
2,448
4,896
734
2,937
5,874
—
—
—
Maximum
($)
All Other
Stock
Awards:
Number of
Shares of
Stock or
Units(4)
(#)
Threshold
(#)
Grant Date
Fair Value
of
Stock
Awards(5)
($)
11,395
$ 2,009,388
$ 720,278
$ 446,520
$ 160,048
2,532
$ 446,520
$ 160,048
2,532
$ 186,081
66,687
$
1,055
$ 223,250
80,024
$
1,266
$
$
—
—
—
(1)
(2)
(3)
(4)
No stock options were granted to our Named Executive Officers in 2023.
The columns under “Estimated Future Payouts Under Non-Equity Incentive Plan Awards” show the range of payouts for 2023
performance under our Short-Term Incentive Plan as described in the Compensation Discussion and Analysis under the section titled
“Short-Term Incentive” on page 27. If the performance criteria are met, payouts can range from 50 percent of target at the threshold
level to 200 percent of target at the maximum level. The non-equity incentive payment for 2023 performance, paid in 2024, has been
made based on achieving the criteria described in the Compensation Discussion and Analysis, at 153.67 percent of target, and is
shown in the Summary Compensation Table on page 37 in the column titled “Non-Equity Incentive Plan Compensation.”
The columns under “Estimated Future Payouts Under Equity Incentive Plan Awards” show the range of payouts (in shares of stock) for
the January 1, 2023 to December 31, 2025 performance period as described in the Compensation Discussion and Analysis under the
section titled “Long-Term Incentive” on page 30. If the performance criteria are met, payouts can range from 25 percent of target to 200
percent of target. If a participant retires, suffers a disability or dies during the performance period, the participant or the participant’s
estate is entitled to that portion of the number of performance shares as such participant would have been entitled to had he or she
remained employed through the end of the performance period, prorated for the number of months served. With the exception of
certain terminations following a change in control, performance shares and performance share units are forfeited if employment is
terminated for any other reason. During the performance period, dividends and other distributions paid with respect to the shares of
common stock accrue for the benefit of the participant and are paid out at the end of the performance period.
The column “All Other Stock Awards” reflects the number of shares of restricted stock granted on February 9, 2023 under our Amended
and Restated 2015 Omnibus Incentive Plan. The restricted stock vests one-third each year over a three-year period, and automatically
vests upon death or disability, with the exception of certain terminations following a change in control. Unvested restricted stock is
forfeited if employment is terminated for any other reason. Dividends are paid on the restricted stock and the dividends that were paid
in 2023 are included in the column titled “All Other Compensation” in the Summary Compensation Table on page 37.
38
PROXYPROXY STATEMENT |
(5)
(6)
The column “Grant Date Fair Value of Stock Awards” reflects the grant date fair value of each equity award computed in accordance
with the provisions of accounting standards for stock compensation. The grant date fair value for the performance share units was
$77.95 per share and was calculated on a weighted average basis considering the results of a Monte Carlo simulation model and the
market value of our common stock as of the beginning of the performance period. Assumptions used in the calculation are included in
Note 14 of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31,
2023. The grant date fair value for the restricted stock was $71.50 per share for the February 9, 2023 grant, which was the market
value of our common stock on the date of grant as reported on the NYSE.
In connection with his retirement, Mr. Kinzley did not receive any equity compensation awards for fiscal 2023; however, he did receive a
cash payment in lieu of these awards in recognition of his partial year of service. See footnote (4) to our Summary Compensation table.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END 2023(1)
Stock Awards
Number of Shares
or Units of Stock
That Have Not
Vested(2)
(#)
Market Value
of Shares or Units
of Stock
That Have Not
Vested
($)
Equity Incentive
Plan Awards:
Number of
Unearned Shares,
Units or Other
Rights
That Have Not
Vested(2)
(#)
Equity Incentive
Plan Awards:
Market or Payout
Value of Unearned
Shares, Units or
Other Rights
That Have Not
Vested
($)
26,546
4,155
6,288
2,540
3,158
—
1,432,157
224,162
339,238
137,033
170,374
—
39,573
7,417
9,144
3,761
4,577
3,307
2,134,963
400,147
493,319
202,906
246,929
178,413
Name
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley
(1)
(2)
There were no stock options outstanding at December 31, 2023 for our Named Executive Officers.
Vesting dates for restricted stock and performance share units are shown in the table below. The performance shares shown with a
vesting date of January 25, 2024, are the actual equivalent shares, including dividend equivalents, earned for the performance period
ended December 31, 2023. On January 25, 2024, the Compensation Committee confirmed that the performance criteria were met and
there would be a payout of 16.21 percent of target. The performance shares with a vesting date of January 23, 2025 and the
performance share units with a vesting date of January 23, 2026 are shown at a combination of threshold and target payout levels
based upon performance as of December 31, 2023.
39
PROXY| PROXY STATEMENT
Name
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley
Unvested Restricted Stock
Unvested and Unearned
Performance Shares
# of Shares
Vesting Date # of Shares
Vesting Date
5,950
4,600
4,601
3,798
3,798
3,799
623
500
500
844
844
844
1,356
1,200
1,200
844
844
844
485
500
500
351
352
352
692
600
600
422
422
422
02/11/24
02/11/24
02/11/25
02/09/24
02/09/25
02/09/26
02/11/24
02/11/24
02/11/25
02/09/24
02/09/25
02/09/26
02/11/24
02/11/24
02/11/25
02/09/24
02/09/25
02/09/26
02/11/24
02/11/24
02/11/25
02/09/24
02/09/25
02/09/26
02/11/24
02/11/24
02/11/25
02/09/24
02/09/25
02/09/26
3,233
8,730
01/25/24
01/23/25
27,610
01/23/26
336
947
01/25/24
01/23/25
6,134
01/23/26
735
2,275
6,134
01/25/24
01/23/25
01/23/26
261
947
01/25/24
01/23/25
2,553
01/23/26
374
1,137
3,066
01/25/24
01/23/25
01/23/26
937
2,370
01/25/24
01/23/25
OPTION EXERCISES AND STOCK VESTED DURING 2023(1)
Stock Awards(2)
Number of Shares
Acquired on
Vesting
(#)
Value Realized
on Vesting
($)
1,138,987
111,094
272,039
102,177
283,704
327,833
17,448 $
1,706 $
4,169 $
1,567 $
4,822 $
5,019 $
There were no stock options exercised during 2023.
Reflects restricted stock that vested in 2023 and performance shares earned for the January 1, 2020 to December 31, 2022
performance period. The performance share payout was approved by the Compensation Committee on January 25, 2023 and paid out
on February 14, 2023.
Name
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley
_______________
(1)
(2)
40
PROXYPROXY STATEMENT |
PENSION BENEFITS FOR 2023
Several years ago, we adopted a defined contribution plan design as our primary retirement plan and amended our Pension
Plan and Nonqualified Pension Plans for all eligible employees to incorporate a partial freeze in which the accrual of benefits
ceased for certain participants while other participants were allowed an election to continue to accrue benefits. Employees
eligible to elect continued participation were those employees who were at least 45 years old and had at least 10 years of
eligible service with us as of January 1, 2010. None of our Named Executive Officers met the age and service requirement
necessary to continue to accrue benefits under the Pension Plan. Rather, benefits under the Pension Plan were frozen for
Messrs. Evans, Kinzley and Iverson and Messes. Jones and Nooney. Mr. Keller joined the Company after the plans were
frozen and therefore does not participate in the plans. Mr. Kinzley received a pension benefit payment during the fiscal year
ended December 31, 2023.
The present value accumulated by each Named Executive Officer from each plan is shown in the table below:
Name
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley
Plan Name
Pension Plan
Pension Restoration Benefit
Pension Plan
Pension Restoration Benefit
Pension Plan
Pension Restoration Plan
Pension Plan
Pension Restoration Plan
Pension Plan
Pension Restoration Plan
Pension Plan
Pension Restoration Benefit
Number of Years of
Credited Service(1)
(#)
Present Value of
Accumulated
Benefit(2)
($)
Payments During
Last Fiscal Year
($)
8.58 $
8.58 $
13.50 $
N/A $
5.83 $
N/A $
8.00 $
N/A $
N/A $
N/A $
10.50 $
10.50 $
295,006 $
235,796 $
171,160 $
- $
157,035 $
- $
59,139 $
- $
- $
- $
- $
16,172 $
-
-
-
-
-
-
-
-
-
-
203,926
-
(1)
(2)
The number of years of credited service represents the number of years used in determining the benefit for each plan.
The present value of accumulated benefits was calculated assuming the participants will work until retirement, benefits commence at
age 62 and using the discount rate, mortality rate and assumed payment form assumptions consistent with those disclosed in Note 13
of the Notes to the Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2023.
41
PROXY| PROXY STATEMENT
DEFINED BENEFIT PENSION PLAN
Our Pension Plan is a qualified pension plan. As discussed above, several years ago we amended our Pension Plan to
incorporate a partial freeze in which the accrual of benefits ceased for certain participants while other participants were
allowed an election to continue to accrue benefits.
The Pension Plan provides benefits at retirement based on length of employment service and average compensation levels
during the highest five consecutive years of the last ten years of service. For purposes of the benefit calculation, earnings
include wages and other cash compensation received from us, including any bonus, commission, unused paid time off or
incentive compensation. It also includes any elective before-tax contributions made by the employee to a Company-sponsored
cafeteria plan or 401(k) plan. However, it does not include any expense reimbursements, taxable fringe benefits, moving
expenses or moving/relocation allowances, nonqualified deferred compensation, non-cash incentives, stock options and any
payments of long-term incentive compensation such as restricted stock or payments under performance share plans. The
Internal Revenue Code places maximum limitations on the amount of compensation that may be recognized when determining
benefits of qualified pension plans. In 2023, the maximum amount of compensation that could be recognized when
determining compensation was $330,000 (called “covered compensation”). Our employees do not contribute to the plan. The
amount of the annual contribution by us to the plan is based on an actuarial determination.
The benefit formula for the Named Executive Officers in the plan is the sum of (a) and (b) below:
(a) Credited Service after January 31, 2000
0.9% of average earnings (up to covered
compensation), multiplied by credited service
after January 31, 2000 minus the number of
years of credited service before January 31,
2000
Plus
1.3% of average earnings in excess of covered
compensation, multiplied by credited service after
January 31, 2000 minus the number of years of
credited service before January 31, 2000
Plus
(b) Credited Service before January 31, 2000
1.2% of average earnings (up to covered
compensation), multiplied by credited service
before January 31, 2000
Plus
1.6% of average earnings in excess of covered
compensation, multiplied by credited service
before January 31, 2000
Pension benefits are not reduced for social security benefits. The Internal Revenue Code places maximum limitations on
annual benefit amounts that can be paid under qualified pension plans. In 2023, the maximum benefit payable under qualified
pension plans was $265,000. Accrued benefits become 100 percent vested after an employee completes five years of service.
Normal retirement is defined as age 65 under the plan. However, a participant may retire and begin taking unreduced benefits
at age 62 with five years of service. Participants who have completed at least five years of credited service can retire and
receive defined benefit pension benefits as early as age 55. However, the retirement benefit will be reduced by five percent for
each year of retirement before age 62. All our Named Executive Officers who are eligible for pension benefits, with the
exception of Messes. Jones and Nooney, are currently age 55 or older and are entitled to early retirement benefits under this
provision.
PENSION RESTORATION BENEFIT
We also have a Pension Restoration Benefit. This is a nonqualified supplemental plan, in which benefits are not tax deductible
until paid. The plan is designed to provide the higher paid executive employee a retirement benefit which, when added to
social security benefits and the pension to be received under the Pension Plan, will approximate retirement benefits being paid
by other employers to their employees in similar executive positions. The employee’s pension from the qualified Pension Plan
is limited by the Internal Revenue Code. The 2023 pension limit was set at $265,000 annually and the compensation taken
into account in determining contributions and benefits could not exceed $330,000 and could not include nonqualified deferred
compensation. The amount of deferred compensation paid under nonqualified plans is not subject to these limits.
As a result of the change in the Pension Plan discussed above, the benefits for certain officers (including Messrs. Evans and
Kinzley) under the Nonqualified Pension Plans were significantly reduced because the nonqualified benefit calculations were
linked to the benefits earned in the Pension Plan. The Compensation Committee amended the Nonqualified Deferred
Compensation Plan to provide non-elective nonqualified restoration benefits to those affected officers who were not eligible to
continue accruing benefits under the Pension Plan and Nonqualified Pension Plans.
42
PROXYPROXY STATEMENT |
Pension Restoration Benefit. In the event that at the time of a participant’s retirement, the participant’s salary level exceeds
the qualified Pension Plan annual compensation limitation ($330,000 in 2023) or includes nonqualified deferred compensation,
then the participant will receive an additional benefit, called a “Pension Restoration Benefit,” which is measured by the
difference between (i) the monthly benefit that would have been provided to the participant under the Pension Plan as if there
were no annual compensation limitation and no exclusion on nonqualified deferred compensation, and (ii) the monthly benefit
to be provided to the participant under the Pension Plan. The Pension Restoration Benefit applies to Messrs. Evans and
Kinzley.
NONQUALIFIED DEFERRED COMPENSATION FOR 2023
We have a Nonqualified Deferred Compensation Plan for a select group of management or highly compensated employees.
Eligibility to participate in the plan is determined by the Compensation Committee and includes our Named Executive Officers.
A summary of the activity in the plan and the aggregate balance as of December 31, 2023 for our Named Executive Officers is
shown in the following table. Our Named Executive Officers received no withdrawals or distributions from the plan in 2023.
Name
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley
_______________
(1)
Executive
Contributions
Company
Contributions
in Last
Fiscal Year(1)
Aggregate
Earnings in
Last Fiscal
Year(2)
Aggregate
Balance
at Last Fiscal
Year End(3)
$
$
$
$
$
$
— $
— $
— $
— $
54,877 $
— $
476,817 $
76,231 $
90,220 $
63,682 $
47,705 $
112,685 $
926,737 $
91,506 $
103,392 $
41,561 $
35,121 $
233,229 $
6,436,107
559,709
1,183,756
305,035
333,465
2,817,496
Our contributions represent non-elective Supplemental Matching and Retirement Contributions and Supplemental Target Contributions
(defined in the paragraph below) and are included in the All Other Compensation column of the Summary Compensation Table. The
value attributed from each contribution type to each Named Executive Officer in 2023 is shown in the table below:
Name
Linden R. Evans
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley
Supplemental
Matching
Contribution
Supplemental
Retirement
Contribution
Supplemental
Target
Contribution
$
$
$
$
$
$
70,426 $
13,590 $
16,649 $
10,168 $
6,392 $
10,142 $
105,639 $
18,121 $
24,973 $
13,557 $
6,392 $
15,213 $
Total
Company
Contributions
476,817
76,231
90,220
63,682
47,705
112,685
300,752 $
44,520 $
48,598 $
39,957 $
34,921 $
87,330 $
(2)
Because amounts included in this column do not include above-market or preferential earnings, none of these amounts are included in
the “Change in Pension Value and Nonqualified Deferred Compensation Earnings” column of the Summary Compensation Table.
(3) Messrs. Evans’, Iverson’s, Keller's, Kinzley's and Messes. Nooney's and Jones' aggregate balances at December 31, 2023 include
$1,526,704, $291,104, $132,308, $516,084, $76,231 and $63,682, respectively, which are included in the Summary Compensation
Table as 2023, 2022 and 2021 compensation.
In April of 2022, the Compensation Committee eliminated the supplemental target contribution for all future participants in the plan. All
our Named Executive Officers were participants prior to this elimination and maintain entitlement to supplemental target contributions.
(4)
Eligible employees may elect to defer up to 50 percent of their base salary and up to 100 percent of their Short-Term Incentive
Plan award. In addition, the Nonqualified Deferred Compensation Plan was amended to provide certain officers whose
Pension Plan benefit and Nonqualified Pension Plan benefits were frozen with non-elective supplemental matching
contributions equal to 6 percent of eligible compensation in excess of the Internal Revenue Code limit plus matching
contributions, if any, lost under the 401(k) Retirement Savings Plan due to nondiscrimination test results and provides non-
elective supplemental age and service points-based contributions that cannot be made to the 401(k) Retirement Savings Plan
due to the Internal Revenue Code limit (“Supplemental Matching and Retirement Contributions”). It also provides supplemental
target contributions equal to a percentage of compensation that may differ by executive, based on the executive’s current age
and length of service with us, as determined by the plans’ actuary (“Supplemental Target Contributions”). Messrs. Evans,
Kinzley, Iverson, and Keller and Messes. Jones and Nooney received Supplemental Target Contributions of 20 percent, 17.5
percent, 8 percent, 8 percent, 8 percent, and 8 percent respectively.
The deferrals are deposited into hypothetical investment accounts where the participants may direct the investment of the
deferrals as allowed by the plan. The investment options are the same as those offered to all employees in the 401(k)
Retirement Savings Plan except for a fixed rate option, which was set at 5.10 percent in 2023. Investment earnings are
43
PROXY| PROXY STATEMENT
credited to the participants’ accounts. Upon retirement, we will distribute the account balance to the participant according to
the participant's distribution election. The participants may elect either a lump sum payment or annual or monthly installments
over a period of years designated by the participant, but not to exceed 10 years. As of January 1, 2024, Messrs. Evans and
Iverson and Messes. Jones and Nooney are 100 percent vested in the plan.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL
The following table describes the potential payments and benefits under our compensation and benefit plans and
arrangements to which our Named Executive Officers would be entitled upon termination of employment. Except for (i) certain
terminations following a change in control (“CIC”), as described below, (ii) pro-rata payout of incentive compensation and the
acceleration of vesting of equity awards upon retirement, death or disability, and (iii) certain pension and nonqualified deferred
compensation arrangements described under Pension Benefits for 2023 and Nonqualified Deferred Compensation for 2023
above, there are no agreements, arrangements or plans that entitle the Named Executive Officers to severance, perquisites,
or other enhanced benefits upon termination of their employment. Any agreements to provide other payments or benefits to a
terminating executive officer would be in the discretion of the Compensation Committee.
The amounts shown below assume that such termination was effective as of December 31, 2023, and thus includes estimates
of the amounts that would be paid out to our Named Executive Officers upon their termination. The table does not include
amounts such as base salary, short-term incentives and stock awards that the Named Executive Officers earned due to
employment through December 31, 2023 and distributions of vested benefits such as those described under Pension Benefits
for 2023 and Nonqualified Deferred Compensation for 2023. The table also does not include a value for outplacement services
because this would be a de minimis amount. The actual amounts to be paid can only be determined at the time of such
Named Executive Officer’s separation from us.
Linden R. Evans
Retirement
Death or disability
Involuntary termination
CIC (1)
Involuntary or good reason termination after CIC(2)
Kimberly F. Nooney
Retirement
Death or disability
Involuntary termination
CIC (1)
Involuntary or good reason termination after CIC(2)
Brian G. Iverson
Retirement
Death or disability
Involuntary termination
CIC (1)
Involuntary or good reason termination after CIC(2)
Marne M. Jones
Retirement
Death or disability
Involuntary termination
CIC (1)
Involuntary or good reason termination after CIC(2)
Erik D. Keller
Retirement
Death or disability
Involuntary termination
CIC (1)
Involuntary or good reason termination after CIC(2)
Richard W. Kinzley
Retirement (6)
Incremental
Retirement
Benefit
(present
value)(3)
Continuation
of Medical/
Welfare
Benefits
(present
value)(4)
Cash
Severance
Payment
Acceleration
of
Equity
Awards(5)
Total
Benefits
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
—
—
—
—
5,342,131
—
—
—
—
1,373,334
—
—
—
—
1,462,568
—
—
—
—
1,172,766
—
—
—
—
1,097,001
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
—
—
—
—
1,890,000
—
—
—
—
309,760
—
—
—
—
338,606
—
—
—
—
286,440
—
—
—
—
263,992
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
—
—
—
—
81,600
—
—
—
—
76,800
—
—
—
—
35,800
—
—
—
—
81,100
—
—
—
—
53,200
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
226,165
1,658,322
—
—
1,866,301
41,181
265,344
—
—
293,848
53,324
392,562
—
—
444,744
22,207
159,240
—
—
181,019
26,649
197,023
—
—
223,158
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
226,165
1,658,322
—
—
9,180,032
41,181
265,344
—
—
2,053,742
53,324
392,562
—
—
2,281,718
22,207
159,240
—
—
1,721,325
26,649
197,023
—
—
1,637,351
—
$
—
$
—
$
8,724
$
8,724
(1)
(2)
(3)
The amounts reflected for after a change in control (with no involuntary or good reason termination) contemplate the assumption or
replacement of the equity awards by the successor entity.
The amounts reflected for involuntary or good reason termination after a change in control include the benefits a Named Executive
Officer would receive in the event of a change followed by an involuntary or good reason termination.
Assumes that in the event of a change in control, Mr. Evans will receive an additional three years of credited and vesting service and
the other Named Executive Officers will receive an additional two years of credited and vesting service towards the benefit accrual
under their applicable retirement plans. For Messrs. Evans, Kinzley, and Iverson and Messes. Jones and Nooney this would be the
Retirement Contributions and Nonqualified Deferred Compensation contributions. The benefits will immediately vest and payments will
commence at the earliest eligible date unless the executive has elected a later date for the nonqualified plans. With the exception of
Messes. Jones and Nooney, our Named Executive Officers are age 55 or older and are already retirement eligible.
44
PROXYPROXY STATEMENT |
(5)
(4) Welfare benefits include medical coverage, dental coverage, life insurance, short-term disability coverage and long-term disability
coverage. The calculation assumes that the Named Executive Officer does not take employment with another employer following
termination, elects continued welfare benefits until age 55 or, if later, the end of the two year benefit continuation period (three years for
Mr. Evans) and elects retiree medical benefits thereafter. Retirement is assumed to occur at the earliest eligible date.
In the event of death or disability, the acceleration of equity awards represents the acceleration of unvested restricted stock and the
assumed payout of the pro-rata share of the performance shares for the January 1, 2022 to December 31, 2024 and January 1, 2023 to
December 31, 2025 performance periods. In the event of retirement, all unvested restricted stock is forfeited and the acceleration of
equity awards represents only the pro-rata share of the performance shares and performance share units. We assumed a 20.0 percent
payout of the performance shares for the January 1, 2022 to December 31, 2024 performance period and a 13.3 percent payout of
target for the January 1, 2023 to December 31, 2025 performance period based on assumed target achievement of performance
metrics for EPS and average cost to serve and, for relative total shareholder return, our Monte Carlo valuations at December 31, 2023.
In the event of a change in control without an involuntary or good reason termination after a change in control, the acceleration of equity
awards only occurs if the awards are not assumed or replaced by the successor entity.
In the event of a change in control or an involuntary or good reason termination after a change in control, the acceleration of equity
awards represents the acceleration of unvested restricted stock and performance share units calculated as if the performance period
ended on December 31, 2023 for the January 1, 2022 to December 31, 2024, and January 1, 2023 to December 31, 2025 performance
periods.
(6)
The valuation of the restricted stock and performance share units was based upon the closing price of our common stock on December
31, 2023.
The amounts for Mr. Kinzley reflect benefits he received in connection with his retirement effective July 3, 2023. As a result, no other
scenarios are presented for Mr. Kinzley. As disclosed in footnote (6) to our Summary Compensation Table, Mr. Kinzley also received a
cash payment in lieu of any equity compensation awards for fiscal 2023.
Payments Made Upon Termination. Regardless of the manner in which a Named Executive Officer’s employment
terminates, the Named Executive Officer or his/her beneficiaries may be entitled to receive amounts earned during his/her
term of employment. These include:
accrued salary and unused vacation pay;
amounts vested under the Pension Plan and Nonqualified Pension Plans;
amounts vested under the Nonqualified Deferred Compensation Plan; and
amounts vested under the 401(k) Retirement Savings Plan.
Payments Made Upon Retirement. In the event of retirement of a Named Executive Officer, in addition to the items identified
above, he/she will also receive the benefit of the following:
a pro-rata share of the performance shares for each outstanding performance period upon completion of the
performance period; and
a pro-rata share of the actual payout under the Short-Term Incentive Plan upon completion of the incentive period.
Payments Made Upon Death or Disability. In the event of death or disability of a Named Executive Officer, in addition to the
items identified above for payments made upon termination, he/she will also receive the benefit of the following:
accelerated vesting of restricted stock and restricted stock units;
a pro-rata share of the performance shares for each outstanding performance period upon completion of the
performance period; and
a pro-rata share of the actual payout under the Short-Term Incentive Plan upon completion of the incentive period.
Payments Made Upon a Change in Control. Our Named Executive Officers have change in control agreements that
terminate November 15, 2025. The renewal of the change in control agreements is at the discretion of the Compensation
Committee and the Board. The change in control agreements provide for certain payments and other benefits to be payable
upon a change in control and a subsequent termination of employment, either involuntary or for a good reason. In order to
receive any payments under the agreements, the Named Executive Officer must sign a waiver and release of claims that
includes a one-year non-competition clause and two-year non-solicitation and non-disparagement clauses.
A change in control is defined in the agreements as:
an acquisition of 30 percent or more of our common stock, except for certain defined acquisitions, such as acquisition by
employee benefit plans, us, any of our subsidiaries, or acquisition by an underwriter holding the securities in connection
with a public offering thereof; or
members of our incumbent Board cease to constitute at least a majority of the members of the Board, with the
incumbent Board being defined as those individuals consisting of the Board on October 1, 2022 and any other directors
elected subsequently whose election was approved by the incumbent Board; or
approval by our shareholders of:
- a merger, consolidation, or reorganization;
-
- an agreement for sale or other disposition of all or substantially all of our assets, with exceptions for
liquidation or dissolution; or
transactions which do not involve an effective change in control of voting securities or Board membership, and
transfers to subsidiaries or sale of subsidiaries; and
45
PROXY| PROXY STATEMENT
all regulatory approvals required to effect a change in control have been obtained and the transaction constituting the
change in control has been consummated.
In the change in control agreements, a good reason for termination that triggers payment of benefits includes:
a material reduction of the executive’s authority, duties or responsibilities;
a material reduction in the executive’s base salary or annual incentive target opportunity;
any material breach by us of any provisions of the change in control agreement;
requiring the executive to be based outside a 50-mile radius from his or her usual and normal place of work; or
our failure to obtain an agreement, satisfactory to the executive, from any successor company to assume and agree to
perform under the change in control agreement.
Upon a change in control, an employment contract with Mr. Evans will become effective for a three-year period and for a two-
year period for the other Named Executive Officers. During this time, the executive will receive annual compensation at least
equal to the highest rate in effect at any time during the one-year period preceding the change in control and will also receive
employment welfare benefits, pension benefits and supplemental retirement benefits on a basis no less favorable than those
received prior to the change in control. Annual compensation is defined to include amounts which are includable in the gross
income of the executive for federal income tax purposes, including base salary, targeted short-term incentive, targeted long-
term incentive grants and awards, and matching contributions or other benefits payable under the 401(k) Retirement Savings
Plan, but exclude restricted stock awards, performance units or stock options that become vested or exercisable pursuant to a
change in control.
If a Named Executive Officer’s employment is terminated prior to the end of the covered time by us for cause or disability, by
reason of the Named Executive Officer’s death, or by the Named Executive Officer without good reason, the Named Executive
Officer will receive all amounts of compensation earned or accrued through the termination date. If the Named Executive
Officer’s employment is terminated because of death or disability, the Named Executive Officer or their beneficiaries will also
receive a pro rata bonus equal to 100 percent of the target incentive for the portion of the year served.
If Mr. Evans’ employment is terminated during the employment term (other than by reason of death) (i) by us other than for
cause or disability, or (ii) by Mr. Evans for a good reason, then Mr. Evans is entitled to the following benefits:
all accrued compensation, a pro-rata short-term incentive bonus and accelerated vesting of restricted stock and
performance units valued at target as of the date of the change in control;
severance pay equal to 2.99 times Mr. Evans’ severance compensation defined as his base salary and short-term
incentive target on the date of the change in control;
continuation of employee welfare benefits for eighteen months following the termination date unless Mr. Evans becomes
covered under the health insurance coverage of a subsequent employer which does not contain any exclusion or
limitation with respect to any preexisting condition of Mr. Evans or his eligible dependents;
following the three-year period, Mr. Evans may elect to receive coverage under the employee welfare plans of the
successor entity at his then-current level of benefits (or reduced coverage at his election) by paying the premiums
charged to regular full-time employees for such coverage, and is eligible to continue receiving such coverage through
the date of his retirement;
three additional years of service and age will be credited to Mr. Evans’ retiree medical savings account and the account
balance will become fully vested and he is eligible to use the account balance to offset retiree medical premiums at the
later of age 55 or the end of the three year continuation period;
three years of additional credited service under the Pension Restoration Plan and Pension Plan; and
outplacement assistance services for up to six months.
If any other NEO’s employment is terminated during the employment term (other than by death) (i) by us other than for cause
or disability, or (ii) by the NEO for a good reason, then the NEO is entitled to the following benefits:
all accrued compensation, a pro-rata short-term incentive bonus and accelerated vesting of restricted stock and
performance units valued at target as of the date of the change in control;
severance pay equal to two times the NEO’s severance compensation defined as the NEO’s base salary and short-term
incentive target on the date of the change in control;
continuation of employee welfare benefits for eighteen months following the termination date unless the NEO becomes
covered under the health insurance coverage of a subsequent employer which does not contain any exclusion or
limitation with respect to any preexisting condition of the NEO or the NEO’s eligible dependents;
following the two-year period, the NEO may elect to receive coverage under the employee welfare plans of the
successor entity at their then-current level of benefits (or reduced coverage at the NEO’s election) by paying the
premiums charged to regular full-time employees for such coverage, and is eligible to continue receiving such coverage
through the date of their retirement;
two additional years of service and age will be credited to the NEO’s retiree medical savings account and the account
balance will become fully vested and the NEO is eligible to use the account balance to offset retiree medical premiums
at the later of age 55 or the end of the two year continuation period;
two years of additional credited service under the executives’ applicable retirement plans; and
outplacement assistance services for up to six months.
46
PROXYPROXY STATEMENT |
The change in control agreements do not contain a benefit to cover any excise tax imposed by Section 4999 of the Internal
Revenue Code of 1986.
PAY RATIO FOR 2023
We are providing the following information about the relationship of the annual total compensation of our employees and the
annual total compensation of Mr. Evans, our Chief Executive Officer, in 2023.
Based on the information below for the fiscal year 2023 and calculated in a manner consistent with Item 402(u) of Regulation
S-K, we reasonably estimate that the ratio of our CEO’s annual total compensation to the annual total compensation of our
median employee was 54:1.
Name
Linden R. Evans
Median Employee (1)
Year
2023
2023
$
$
Salary
Stock
Awards
Non-Equity
Incentive Plan
Compensation
Change in
Pension
Value(2)
All Other
Compensation(3)
Total
893,333 $
91,667 $
2,729,666 $
— $
1,372,785 $
6,453 $
35,493 $
— $
607,725 $ 5,639,002
5,891 $ 104,011
(1) We identified our median employee based on the year-to-date total cash compensation actually paid as of November 12, 2023 to all of
(2)
(3)
our employees, other than our CEO, who were employed on November 12, 2023.
See footnote (3) to our Summary Compensation Table for a description of how the values in the Change in Pension Value column are
calculated.
All Other Compensation includes 401(k) match, defined contributions, NQDC contributions, dividends on restricted stock and other
personal benefits for Mr. Evans and the 401(k) match for the median employee.
PAY VERSUS PERFORMANCE
In accordance with rules adopted by the Securities and Exchange Commission pursuant to the Dodd-Frank Wall Street
Reform and Consumer Protection Act of 2010, we provide the following disclosures regarding executive compensation for our
principal executive officer (“PEO”) and Non-PEO NEOs and Company performance for the fiscal years listed below. The
Compensation Committee did not consider the pay versus performance disclosure below in making its pay decisions for any of
the years shown.
Summary
Compensation
Table Total for
Linden R. Evans (1)
Compensation
Actually Paid to
Linden R. Evans (1)
(2) (3)
Average Summary
Compensation
Table Total for Non-
PEO NEOs (1)
Average
Compensation
Actually Paid to
Non-PEO NEOs
(1) (2) (3)
Total
Shareholder
Return
Peer Group
Total
Shareholder
Return (4)
Net income
(GAAP), in
millions
Value of initial Fixed $100
Investment Based on:
2023
2022
2021
$
$
$
5,639,002 $
1,951,347 $
1,186,100 $
631,015 $
79.38 $
91.30 $
276.0 $
4,486,548 $
4,506,289 $
1,208,492 $
1,224,584 $
99.15 $
101.15 $
270.8 $
4,440,908 $
5,151,457 $
1,318,764 $
1,453,664 $
96.19 $
117.12 $
251.3 $
4,221,114 $
3,055,790 $
1,565,573 $
1,003,991 $
80.92 $
98.84 $
242.8 $
Company-
Selected
Performance
Measure
EPS from
ongoing
operations, as
adjusted (non-
GAAP)
(5)
3.93
3.97
3.74
3.73
$
2020
______________
(1)
Linden R. Evans was our PEO for each year presented. The individuals comprising the Non-PEO NEOs for each year presented are
listed below:
2020
Richard W. Kinzley
Brian G. Iverson
Stuart A. Wevik
Scott A. Buchholz
2021
Richard W. Kinzley
Brian G. Iverson
Stuart A. Wevik
Erik D. Keller
2022
Richard W. Kinzley
Brian G. Iverson
Erik D. Keller
Jennifer C. Landis
2023
Kimberly F. Nooney
Brian G. Iverson
Marne M. Jones
Erik D. Keller
Richard W. Kinzley
The amounts shown for Compensation Actually Paid have been calculated in accordance with Item 402(v) of Regulation S-K and do
not reflect compensation actually earned, realized, or received by the Company's NEOs. These amounts reflect the Summary
Compensation Table Total with certain adjustments as described in footnote (3) below.
Compensation Actually Paid reflects the exclusions and inclusions of certain amounts for the PEO and the Non-PEO NEOs as set forth
below. Equity values are calculated in accordance with FASB ASC Topic 718. Amounts in the Exclusion of Stock Awards column are
the totals from the Stock Awards column set forth in the Summary Compensation Table. Amounts in the Exclusion of Change in
Pension Value column reflect the amounts attributable to the Change in Pension Value reported in the Summary Compensation Table.
Amounts in the Inclusion of Pension Service Cost are based on the service cost for services rendered during the listed year.
(2)
(3)
47
PROXY| PROXY STATEMENT
Year
Summary
Compensation
Table Total for
Linden R. Evans
Exclusion of
Change in Pension
Value for Linden R.
Evans
Exclusion of Stock
Awards for Linden
R. Evans
Inclusion of Pension
Service Cost for
Linden R. Evans
Inclusion of Equity
Values for Linden R.
Evans
Compensation
Actually Paid to
Linden R. Evans
2023
$
5,639,002 $
(35,493) $
(2,729,666 ) $
- $
(922,496) $
1,951,347
Average Summary
Compensation Table
Total for Non-PEO
NEOs
Average Exclusion
of Change in
Pension Value for
Non-PEO NEOs
Average Exclusion
of Stock Awards and
Option Awards for
Non-PEO NEOs
Average Inclusion of
Pension Service
Cost for Non-PEO
NEOs
Average Inclusion of
Equity Values for
Non-PEO NEOs
Average
Compensation
Actually Paid to
Non-PEO NEOs
$
1,186,100
$
(5,828) $
(353,835) $
-
$
(195,422) $
631,015
Year
2023
The amounts in the Inclusion of Equity Values in the tables above are derived from the amounts set forth in the following tables:
Year-End Fair
Value of Equity
Awards Granted
During Year That
Remained
Unvested as of
Last Day of Year
for Linden R.
Evans
Change in Fair
Value from Last
Day of Prior Year
to Last Day of
Year of Unvested
Equity Awards for
Linden R. Evans
Vesting-Date Fair
Value of Equity
Awards Granted
During Year that
Vested During
Year for Linden
R. Evans
Change in Fair
Value from Last
Day of Prior Year
to Vesting Date of
Unvested Equity
Awards that
Vested During
Year for Linden
R. Evans
Fair Value at Last
Day of Prior Year
of Equity Awards
Forfeited During
Year for Linden
R. Evans
Value of
Dividends or
Other Earnings
Paid on Stock or
Option Awards
Not Otherwise
Included for
Linden R. Evans
Total - Inclusion
of Equity Values
for Linden R.
Evans
$
1,578,054
$
(2,654,316) $
- $
153,766 $
- $
- $
(922,496)
Average Year-End
Fair Value of
Equity Awards
Granted During
Year That
Remained
Unvested as of
Last Day of Year
for Non-PEO
NEOs
Average Change
in Fair Value from
Last Day of Prior
Year to Last Day
of Year of
Unvested Equity
Awards for Non-
PEO NEOs
Average Vesting-
Date Fair Value of
Equity Awards
Granted During
Year that Vested
During Year for
Non-PEO NEOs
Average Change
in Fair Value from
Last Day of Prior
Year to Vesting
Date of Unvested
Equity Awards
that Vested
During Year for
Non-PEO NEOs
Average Fair
Value at Last Day
of Prior Year of
Equity Awards
Forfeited During
Year for Non-PEO
NEOs
Average Value of
Dividends or
Other Earnings
Paid on Stock or
Option Awards
Not Otherwise
Included for Non-
PEO NEOs
Total - Average
Inclusion of
Equity Values for
Non-PEO NEOs
$
204,554 $
(350,241) $
- $
12,605 $
(62,340) $
- $
(195,422)
Year
2023
Year
2023
(4)
The Peer Group TSR set forth in this table utilizes the Edison Electric Institute Index (“EEI Index”), which we also utilize in the stock
performance graph required by Item 201(e) of Regulation S-K included in our Annual Report for the year ended December 31, 2023.
The comparison assumes $100 was invested for the period starting December 31, 2019, through the end of the listed year in the
Company and in the EEI Index, respectively. All dollar values assume reinvestment of the pre-tax value of dividends paid by
companies, where applicable, included in the EEI Index. Historical stock performance is not necessarily indicative of future stock
performance.
(5) We determined EPS from ongoing operations, as adjusted (non-GAAP) to be the most important financial performance measure used
to link Company performance to Compensation Actually Paid to our PEO and Non-PEO NEOs in 2023. More information on EPS from
ongoing operations, as adjusted can be found in the Short-Term Incentive section of Compensation Discussion and Analysis. This
performance measure may not have been the most important financial performance measure for years 2022, 2021, and 2020 and we
may determine a different financial performance measure to be the most important financial performance measure in future years.
Relationship between Pay and Performance
The charts shown below present a graphical comparison of compensation actually paid to the PEO and the average
compensation actually paid to the other NEOs set forth in the Pay Versus Performance table above, as compared against the
following Company performance measures: (1) Total shareholder return (TSR); (2) Peer group TSR; (3) Net income; and (4)
EPS from ongoing operations, as adjusted. As presented, the first chart below compares the Company's TSR and peer group
TSR, assumes an initial investment of $100 on December 31, 2019, assumes all dividends were reinvested and depicts
performance at the end of each applicable year.
48
PROXYPROXY STATEMENT |
49
PROXY| PROXY STATEMENT
Financial Performance Measures
The following table presents the financial performance measures that the Company considers to have been the most important
in linking Compensation Actually Paid to our PEO and other NEOs for 2023 to Company performance. The measures in this
table are not ranked.
Most Important Performance Measures
EPS from ongoing operations, as adjusted (non-GAAP)
Net income
Total Shareholder Return
50
PROXYPROXY STATEMENT |
TRANSACTION OF OTHER BUSINESS
Our Board does not intend to present any business for action by our shareholders at the meeting except the matters referred
to in this proxy statement. If any other matters should be properly presented at the meeting, it is the intention of the persons
named in the accompanying form of proxy to vote thereon in accordance with the recommendations of our Board.
SHAREHOLDER PROPOSALS FOR 2025 ANNUAL MEETING
Shareholder proposals intended to be presented at our 2025 annual meeting of shareholders and considered for inclusion in
our proxy materials must be received by our Corporate Secretary in writing at our executive offices at 7001 Mount Rushmore
Road, P.O. Box 1400, Rapid City, South Dakota 57709, on or prior to November 15, 2024. Any proposal submitted must be in
compliance with Rule 14a-8 of Regulation 14A of the Securities and Exchange Commission.
Additionally, a shareholder may submit a proposal or director nominee for consideration at our 2025 annual meeting of
shareholders, but not for inclusion of the proposal or director nominee in our proxy materials, if the shareholder gives timely
written notice of such proposal in accordance with Article I, Section 9 of our Bylaws. In general, Article I, Section 9 provides
that, to be timely, a shareholder’s notice must be delivered to our Corporate Secretary in writing not less than 90 days nor
more than 120 days prior to the anniversary date of the immediately preceding annual meeting of shareholders.
Our 2025 annual meeting is scheduled for April 23, 2025. Ninety days prior to the first anniversary of this date will be January
23, 2025, and 120 days prior to the first anniversary of this date will be December 24, 2024. For business to be properly
requested by the shareholder to be brought before the 2025 annual meeting of shareholders, the shareholder must comply
with all of the requirements of Article I, Section 9 of our Bylaws, not just the timeliness requirements set forth above. In
addition to satisfying the foregoing requirements, to comply with the universal proxy rules, shareholders who intend to solicit
proxies in support of director nominees other than the Board's nominees must provide notice that sets forth the information
required by Rule 14a-19 under the exchange Act no later than February 24, 2025.
51
PROXY| PROXY STATEMENT
SHARED ADDRESS SHAREHOLDERS
In accordance with a notice sent to eligible shareholders who share a single address, we are sending only one annual report
and proxy statement to that address unless we receive instructions to the contrary from any shareholder at that address. This
practice, known as “householding,” is designed to reduce our printing and postage costs. However, if a shareholder of record
residing at such an address wishes to receive a separate annual report or proxy statement in the future, he or she may contact
Shareholder Relations at the below address.
Shareholder Relations
Black Hills Corporation
7001 Mount Rushmore Road
P.O. Box 1400
Rapid City, SD 57709
(605) 721-1700
Eligible shareholders of record receiving multiple copies of our annual report and proxy statement can request householding
by contacting us in the same manner. Shareholders who own shares through a bank, broker or other nominee can request
householding by contacting the nominee.
We hereby undertake to deliver promptly, upon written or oral request, a separate copy of the annual report to shareholders, or
proxy statement, as applicable, to our shareholders at a shared address to which a single copy of the document was delivered.
Please vote your shares by telephone, by the Internet or by promptly returning the accompanying form of proxy, whether or not
you expect to be present at the annual meeting.
ANNUAL REPORT ON FORM 10-K
A copy of our Annual Report on Form 10-K (excluding exhibits) for the year ended December 31, 2023, which is
required to be filed with the Securities and Exchange Commission, will be made available to shareholders to whom
this proxy statement is mailed, without charge, upon written or oral request to Shareholder Relations, Black Hills
Corporation, 7001 Mount Rushmore Road, P.O. Box 1400, Rapid City, SD 57709, Telephone Number: (605) 721-1700.
Our Annual Report on Form 10-K also may be accessed through our website at www.blackhillscorp.com.
IMPORTANT NOTICE REGARDING THE AVAILABILITY OF PROXY MATERIALS
FOR THE SHAREHOLDER MEETING TO BE HELD ON APRIL 23, 2024
Shareholders may view this proxy statement, our form of proxy and our 2023 Annual Report to Shareholders over the
Internet by accessing our website at www.blackhillscorp.com. Information on our website does not constitute a part
of this proxy statement.
By Order of the Board,
/s/ AMY K. KOENIG
Amy K. Koenig
Vice President - Governance, Corporate Secretary and Deputy
General Counsel
Dated: March 15, 2024
52
PROXYPROXY STATEMENT |
(This page has been left blank intentionally.)
67
10-K| FORM 10-K UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
Form 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2023
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
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol
Name of each exchange on which registered
Common stock of $1.00 par value
BKH
New York Stock Exchange
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
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 (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to
submit such files). Yes ☒ 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
Non-accelerated filer
☒
☐
Accelerated filer
Smaller reporting company
Emerging growth company
☐
☐
☐
If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with
any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its
internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting
firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant
included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based
compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the voting common equity held by non-affiliates of the registrant on the last business day of the registrant’s most
recently completed second fiscal quarter, June 30, 2023, was $4,016,297,084
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
Class
Outstanding at January 31, 2024
Common stock, $1.00 par value
68,196,551 shares
Documents Incorporated by Reference
Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2024 Annual Meeting
of Stockholders to be held on April 23, 2024, are incorporated by reference in Part III of this Form 10-K.
1
10-KFORM 10-K | TABLE OF CONTENTS
Page
GLOSSARY OF TERMS AND ABBREVIATIONS
WEBSITE ACCESS TO REPORTS
FORWARD-LOOKING INFORMATION
Part I
ITEM 1.
BUSINESS
History and Organization
Electric Utilities
Gas Utilities
Utility Regulation Characteristics
Environmental Matters
Human Capital Resources
RISK FACTORS
UNRESOLVED STAFF COMMENTS
CYBERSECURITY
PROPERTIES
LEGAL PROCEEDINGS
MINE SAFETY DISCLOSURES
ITEM 1A.
ITEM 1B.
ITEM 1C.
ITEM 2.
ITEM 3.
ITEM 4.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Part II
ITEM 5.
ITEM 6.
ITEM 7.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
RESERVED
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Executive Summary
Key Elements of our Business Strategy
Recent Developments
Results of Operations - Consolidated Summary and Overview
Non-GAAP Financial Measure
Electric Utilities
Gas Utilities
Corporate and Other
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and
Income Tax Benefit (Expense)
Liquidity and Capital Resources
Cash Flow Activities
Capital Resources
Credit Ratings
Capital Requirements
Critical Accounting Estimates
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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2
10-K| FORM 10-K
TABLE OF CONTENTS
Page
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
GLOSSARY OF TERMS AND ABBREVIATIONS
WEBSITE ACCESS TO REPORTS
FORWARD-LOOKING INFORMATION
Part I
ITEM 1.
BUSINESS
ITEM 1A.
ITEM 1B.
ITEM 1C.
ITEM 2.
ITEM 3.
ITEM 4.
Part II
ITEM 5.
ITEM 6.
ITEM 7.
History and Organization
Electric Utilities
Gas Utilities
Utility Regulation Characteristics
Environmental Matters
Human Capital Resources
RISK FACTORS
UNRESOLVED STAFF COMMENTS
CYBERSECURITY
PROPERTIES
LEGAL PROCEEDINGS
MINE SAFETY DISCLOSURES
RESERVED
RESULTS OF OPERATIONS
Executive Summary
Key Elements of our Business Strategy
Recent Developments
Non-GAAP Financial Measure
Electric Utilities
Gas Utilities
Corporate and Other
Income Tax Benefit (Expense)
Liquidity and Capital Resources
Cash Flow Activities
Capital Resources
Credit Ratings
Capital Requirements
Critical Accounting Estimates
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS
AND ISSUER PURCHASES OF EQUITY SECURITIES
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
Results of Operations - Consolidated Summary and Overview
Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
4
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Management’s Report on Internal Controls Over Financial Reporting
Reports of Independent Registered Public Accounting Firm
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
Consolidated Statements of Equity
Notes to Consolidated Financial Statements
Note 1. Business Description and Significant Accounting Policies
Note 2. Regulatory Matters
Note 3. Commitments, Contingencies and Guarantees
Note 4. Revenue
Note 5. Property, Plant and Equipment
Note 6. Jointly Owned Facilities
Note 7. Asset Retirement Obligations
Note 8. Financing
Note 9. Risk Management and Derivatives
Note 10. Fair Value Measurements
Note 11. Other Comprehensive Income
Note 12. Variable Interest Entity
Note 13. Employee Benefit Plans
Note 14. Share-based Compensation Plans
Note 15. Income Taxes
Note 16. Business Segment Information
Note 17. Subsequent Events
ITEM 9.
ITEM 9A.
ITEM 9B.
ITEM 9C.
Part III
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
Part IV
ITEM 15.
ITEM 16.
SIGNATURES
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
EXECUTIVE COMPENSATION
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR
INDEPENDENCE
PRINCIPAL ACCOUNTANT FEES AND SERVICES
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
FORM 10-K SUMMARY
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3
10-KFORM 10-K |
GLOSSARY OF TERMS AND ABBREVIATIONS
The following terms and abbreviations appear in the text of this report and have the definitions described below:
AC
AFUDC
AOCI
APSC
Arkansas Gas
ARO
ASC
ASU
ATM
Availability
BHC
BHSC
Alternating Current
Allowance for Funds Used During Construction
Accumulated Other Comprehensive Income (Loss)
Arkansas Public Service Commission
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).
Asset Retirement Obligation
Accounting Standards Codification
Accounting Standards Update as issued by the FASB
At-the-market equity offering program
The availability factor of a power plant is the percentage of the time that it is available to
provide energy.
Black Hills Corporation; the Company
Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills
Corporation (doing business as Black Hills Energy)
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 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 Power
Black Hills Utility Holdings
Black Hills Wyoming
Blockchain Interruptible Service
(BCIS) Tariff
Btu
Busch Ranch I
Busch Ranch II
4
Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing
business as Black Hills Energy). Also known as South Dakota Electric.
Black Hills Utility Holdings, Inc., a direct, wholly-owned subsidiary of Black Hills
Corporation (doing business as Black Hills Energy)
Black Hills Wyoming, LLC, a direct, wholly-owned subsidiary of Black Hills Electric
Generation
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.
British thermal unit
The 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.
The 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.
10-K| FORM 10-K The following terms and abbreviations appear in the text of this report and have the definitions described below:
GLOSSARY OF TERMS AND ABBREVIATIONS
Alternating Current
Allowance for Funds Used During Construction
Accumulated Other Comprehensive Income (Loss)
Arkansas Public Service Commission
Black Hills Energy).
Asset Retirement Obligation
Accounting Standards Codification
Accounting Standards Update as issued by the FASB
At-the-market equity offering program
provide energy.
Black Hills Corporation; the Company
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
Availability
The availability factor of a power plant is the percentage of the time that it is available to
Black Hills Colorado IPP
Black Hills Colorado IPP, LLC, a 50.1% owned subsidiary of Black Hills Electric Generation
Black Hills Service Company, LLC, a direct, wholly-owned subsidiary of Black Hills
Corporation (doing business as Black Hills Energy)
AC
AFUDC
AOCI
APSC
Arkansas Gas
ARO
ASC
ASU
ATM
BHC
BHSC
CACJA Adjustment
CFTC
Cheyenne Light
Cheyenne Prairie
Choice Gas Program
City of Gillette
Clean Energy Plan
Clean Air Clean Jobs Act Adjustment is an adjustment mechanism that allows Colorado
Electric to collect from customers the capital costs related to Pueblo Airport Generation CT
#6.
United States Commodity Futures Trading Commission
Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills
Corporation, providing electric service in the Cheyenne, Wyoming area (doing business as
Black Hills Energy). Also known as Wyoming Electric.
Cheyenne Prairie Generating Station located in Cheyenne, Wyoming serves the utility
customers of South Dakota Electric and Wyoming Electric. The facility includes one simple-
cycle, 40 MW combustion turbine that is wholly-owned by Wyoming Electric and one
combined-cycle, 100 MW unit that is jointly-owned by Wyoming Electric (42 MW) and
South Dakota Electric (58 MW).
Regulator-approved programs in Wyoming and Nebraska that allow certain utility
customers to select their natural gas commodity supplier, providing the unbundling of the
commodity service from the distribution delivery service.
Gillette, Wyoming
2030 Ready Plan that establishes a roadmap and preferred resource portfolio for Colorado
Electric to cost-effectively achieve the State of Colorado’s requirement calling upon electric
utilities to reduce GHG emissions by a minimum of 80% from 2005 levels by 2030. Based
on initial modeling, the preferred resource portfolio proposes the addition of approximately
400 MW of clean energy resources (100 MW of wind, 200-250 MW of solar and 50 MW of
battery storage) to Colorado Electric's system. The final mix of resources will be
determined by the results of a competitive solicitation that was issued in July 2023.
Colorado legislation allows electric utilities to own up to 50% of the renewable generation
assets added to comply with the Clean Energy Plan.
Black Hills Electric Generation
Black Hills Electric Generation, LLC, a direct, wholly-owned subsidiary of Black Hills Non-
CO2
Carbon dioxide
regulated Holdings, providing wholesale electric capacity and energy primarily to our
affiliate utilities.
Chief Operating Decision Maker
(CODM)
Chief Executive Officer
Black Hills Energy
The name used to conduct the business of our Utilities
Black Hills Energy Renewable
Black Hills Energy Renewable Resources, LLC, a direct, wholly-owned subsidiary of Black
Resources (BHERR)
Hills Non-regulated Holdings
Colorado Electric
Black Hills Energy Services
Black Hills Energy Services Company, an indirect, wholly-owned subsidiary of Black Hills
Colorado Gas
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
Common Use System
Blockchain Interruptible Service
A WPSC-approved tariff applicable to prospective new Wyoming Electric blockchain
Cooling Degree Day
Consolidated Indebtedness to
Capitalization Ratio
Corriedale
Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Electric
Parent Holdings, providing electric service to customers in Colorado (doing business as
Black Hills Energy).
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).
The Common Use System is a jointly operated transmission system we participate in with
Basin Electric Power Cooperative and Powder River Energy Corporation. The Common
Use System provides transmission service over these utilities' combined 230-kilovolt (kV)
and limited 69-kV transmission facilities within areas of southwestern South Dakota and
northeastern Wyoming.
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.
A cooling degree day is equivalent to each degree that the average of the high and low
temperature 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.
The 52.5 MW wind farm near Cheyenne, Wyoming, jointly owned by South Dakota Electric
(32.5 MW) and Wyoming Electric (20 MW), serving as the dedicated wind energy supply to
the Renewable Ready program, which is a voluntary renewable energy subscription
program for large commercial, industrial and governmental customers in South Dakota and
Wyoming.
CP Program
Commercial Paper Program
CPCN
CPUC
CSAPR
Certificate of Public Convenience and Necessity
Colorado Public Utilities Commission
The United States Environmental Protection Agency's Cross-State Air Pollution Rule
5
Black Hills Power
Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation (doing
business as Black Hills Energy). Also known as South Dakota Electric.
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
Corporation
Generation
(BCIS) Tariff
Btu
Busch Ranch I
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.
British thermal unit
The 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
The 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.
10-KFORM 10-K | CT
Cushion Gas
Cybersecurity incident
Cybersecurity threat
Combustion Turbine
The portion of natural gas necessary to force saleable gas from a storage field into the
transmission system and for system balancing, representing a permanent investment
necessary to use storage facilities and maintain reliability.
An unauthorized occurrence, or a series of related unauthorized occurrences, on or
conducted through a registrant’s information systems that jeopardizes the confidentiality,
integrity, or availability of a registrant’s information systems or any information residing
therein.
Any potential unauthorized occurrence on or conducted through a registrant’s information
systems that may result in adverse effects on the confidentiality, integrity or availability of a
registrant’s information systems or any information residing therein.
DC
Direct Current
Dividend Payout Ratio
Annual dividends paid on common stock divided by net income from continuing operations
available for common stock
DRSPP
DSM
Dth
EBITDA
ECA
Dividend Reinvestment and Stock Purchase Plan
Demand Side Management
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units
(MMBtu).
Earnings before interest, taxes, depreciation and amortization, a non-GAAP measure.
Energy Cost Adjustment is an adjustment that allows us to pass the prudently-incurred cost
of fuel and purchased energy through to customers.
Economy Energy
Purchased energy that costs less than that produced with the utilities’ owned generation.
EECR
EIA
EGU
Energy Efficiency Cost Recovery is an adjustment mechanism that allows us to recover
from customers the costs associated with providing energy efficiency programs.
Environmental Improvement Adjustment is an annual adjustment mechanism that allows us
to recover from customers eligible investments in, and expense related to, new
environmental measures.
Electric generating unit
Energy Assistance Benefit Charge Energy Assistance Benefit Charge is a Colorado statutory-created surcharge to provide
additional funding for bill assistance and weatherization for income-qualified customers.
We collect these funds and remit them to a Colorado non-profit organization that assists
low-income residents with utility bills, repairs, and energy efficiency upgrades.
Energy Transition
The global energy sector’s shift from fossil-based systems of energy production and
consumption, including oil, natural gas and coal to renewable energy sources like wind and
solar, as well as battery storage solutions.
EPA
ESG
EV
EWG
FASB
FERC
Fitch
GAAP
United States Environmental Protection Agency
Environmental, Social and Governance
Electric Vehicle
Exempt Wholesale Generator
Financial Accounting Standards Board
United States Department of Energy's Federal Energy Regulatory Commission
Fitch Ratings Inc.
Accounting principles generally accepted in the United States of America
Gas Price Risk Management Rider Gas Price Risk Management Rider is a mechanism that is similar to GCA but designed to
also provide a price floor and price ceiling.
GCA
GHG
Gillette Energy Complex
Gas Cost Adjustment is an adjustment that allows us to pass the prudently-incurred cost of
gas and certain services through to customers.
Greenhouse gases
The Gillette Energy Complex located in Gillette, Wyoming includes 793 MW of coal-fired
generating facilities (Neil Simpson II, Wygen I, Wygen II, Wygen III, Wyodak Plant) which
are supplied by WRDC and a 40 MW gas-fired generation facility (Neil Simpson CT). We
operate and own majority interests in five of the six facilities and own 20% of Wyodak
Plant.
6
10-K| FORM 10-K CT
Cushion Gas
Combustion Turbine
The portion of natural gas necessary to force saleable gas from a storage field into the
transmission system and for system balancing, representing a permanent investment
necessary to use storage facilities and maintain reliability.
Cybersecurity incident
An unauthorized occurrence, or a series of related unauthorized occurrences, on or
conducted through a registrant’s information systems that jeopardizes the confidentiality,
integrity, or availability of a registrant’s information systems or any information residing
Cybersecurity threat
Any potential unauthorized occurrence on or conducted through a registrant’s information
systems that may result in adverse effects on the confidentiality, integrity or availability of a
registrant’s information systems or any information residing therein.
therein.
Direct Current
Dividend Payout Ratio
Annual dividends paid on common stock divided by net income from continuing operations
Economy Energy
Purchased energy that costs less than that produced with the utilities’ owned generation.
available for common stock
Dividend Reinvestment and Stock Purchase Plan
Demand Side Management
Dekatherm. A unit of energy equal to 10 therms or one million British thermal units
(MMBtu).
Earnings before interest, taxes, depreciation and amortization, a non-GAAP measure.
Energy Cost Adjustment is an adjustment that allows us to pass the prudently-incurred cost
of fuel and purchased energy through to customers.
Energy Efficiency Cost Recovery is an adjustment mechanism that allows us to recover
from customers the costs associated with providing energy efficiency programs.
Environmental Improvement Adjustment is an annual adjustment mechanism that allows us
to recover from customers eligible investments in, and expense related to, new
environmental measures.
Electric generating unit
Energy Assistance Benefit Charge Energy Assistance Benefit Charge is a Colorado statutory-created surcharge to provide
additional funding for bill assistance and weatherization for income-qualified customers.
We collect these funds and remit them to a Colorado non-profit organization that assists
low-income residents with utility bills, repairs, and energy efficiency upgrades.
Energy Transition
The global energy sector’s shift from fossil-based systems of energy production and
consumption, including oil, natural gas and coal to renewable energy sources like wind and
United States Department of Energy's Federal Energy Regulatory Commission
Fitch Ratings Inc.
Accounting principles generally accepted in the United States of America
Gas Price Risk Management Rider Gas Price Risk Management Rider is a mechanism that is similar to GCA but designed to
solar, as well as battery storage solutions.
United States Environmental Protection Agency
Environmental, Social and Governance
Electric Vehicle
Exempt Wholesale Generator
Financial Accounting Standards Board
also provide a price floor and price ceiling.
gas and certain services through to customers.
Greenhouse gases
DC
DRSPP
DSM
Dth
EBITDA
ECA
EECR
EIA
EGU
EPA
ESG
EV
EWG
FASB
FERC
Fitch
GAAP
GCA
GHG
Global Settlement
GWh
Heating Degree Day
HomeServe
Information systems
Integrated Generation
Iowa Gas
IPP
IRA
IRC
IRP
IRS
ITC
Kansas Gas
kV
LIBOR
Mcf
Mcfd
MDU
MEAN
MMBtu
Moody’s
MSHA
MW
MWh
N/A
NAAQS
NAV
Gas Cost Adjustment is an adjustment that allows us to pass the prudently-incurred cost of
Nebraska Gas
Gillette Energy Complex
The Gillette Energy Complex located in Gillette, Wyoming includes 793 MW of coal-fired
generating facilities (Neil Simpson II, Wygen I, Wygen II, Wygen III, Wyodak Plant) which
are supplied by WRDC and a 40 MW gas-fired generation facility (Neil Simpson CT). We
operate and own majority interests in five of the six facilities and own 20% of Wyodak
Plant.
Neil Simpson II
NERC
NOX
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.
Gigawatt Hours
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.
We offer HomeServe products to our natural gas residential customers interested in
purchasing additional home repair service plans.
Electronic information resources, owned or used by the registrant, including physical or
virtual infrastructure controlled by such information resources, or components thereof,
organized for the collection, processing, maintenance, use, sharing, dissemination, or
disposition of the registrant’s information to maintain or support the registrant’s operations.
Non-regulated power generation and mining businesses (Black Hills Electric Generation
and WRDC) that are vertically integrated within our Electric Utilities segment.
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).
Independent Power Producer
Inflation Reduction Act of 2022
Internal Revenue Code
Integrated Resource Plan
United States Internal Revenue Service
Investment Tax Credit
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).
Kilovolt
London Interbank Offered Rate
Thousand cubic feet
Thousand cubic feet per day
Montana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc.
Municipal Energy Agency of Nebraska
Million British thermal units
Moody’s Investors Service, Inc.
United States Department of Labor’s Mine Safety and Health Administration
Megawatts
Megawatt-hours
Not Applicable
National Ambient Air Quality Standards
Net Asset Value
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).
A mine-mouth, coal-fired power plant owned and operated by South Dakota Electric with a
total capacity of 90 MW located at our Gillette Energy Complex.
North American Electric Reliability Corporation
Nitrogen oxide
7
10-KFORM 10-K | NOL
Net Operating Loss
Northern Iowa Windpower
Northern Iowa Windpower, LLC, a 87.1 MW wind farm located near Joice, Iowa, previously
owned by Black Hills Electric Generation. In March 2023, Black Hills Electric Generation
completed the sale of Northern Iowa Windpower assets to a third-party.
OCI
OPEB
OSHA
OSM
PacifiCorp
PCA
PCCA
Peak View
PHMSA
PPA
PSA
PTC
Pueblo Airport Generation
PUHCA 2005
Ready
Ready Wyoming
RESA
Revolving Credit Facility
RMNG
RNG
RTO
SDPUC
SEC
Other Comprehensive Income
Other Post-Employment Benefits
United States Department of Labor’s Occupational Safety & Health Administration
United States Department of the Interior’s Office of Surface Mining
PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an
affiliate of Berkshire Hathaway.
Power Cost Adjustment is an annual adjustment mechanism that allows us to pass a
portion of prudently-incurred delivered power costs, including fuel, purchased capacity and
energy, and transmission costs, through to customers.
Power Capacity Cost Adjustment is an annual adjustment that allows us to pass the
prudently-incurred purchased capacity costs, incremental to costs included in base rates,
through to customers.
The 60.8 MW wind farm owned by Colorado Electric.
United States Department of Transportation's Pipeline and Hazardous Materials Safety
Administration
Power Purchase Agreement
Power Sales Agreement
Production Tax Credit
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 owns and operates
this facility. The plants commenced operation on January 1, 2012.
Public Utility Holding Company Act of 2005
The Company’s branding platform which emphasizes that we will 1) prioritize our
customers; 2) act as a thoughtful, responsible leader; 3) listen first and lead with a focus on
relationships; and 4) be creative in our approach to solutions.
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.
Renewable Energy Standard Adjustment is an incremental retail rate limited to 2% for
Colorado Electric customers that provides funding for renewable energy projects and
programs to comply with Colorado’s Renewable Energy Standard.
Our $750 million credit facility used to fund working capital needs, letters of credit and other
corporate purposes, which was amended on May 9, 2023 and will terminate on July 19,
2026. 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.
Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility
Holdings, providing natural gas transmission and wholesale services in western Colorado
(doing business as Black Hills Energy).
Renewable natural gas
Regional Transmission Organization
South Dakota Public Utilities Commission
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.
SO2
Sulfur dioxide
8
10-K| FORM 10-K NOL
OCI
OPEB
OSHA
OSM
PCA
PCCA
Peak View
PHMSA
PPA
PSA
PTC
RESA
RMNG
RNG
RTO
SDPUC
SEC
SO2
PUHCA 2005
Ready
Ready Wyoming
Pueblo Airport Generation
Pueblo Airport Generating Station located in Pueblo, Colorado includes 440 MW of
Power Cost Adjustment is an annual adjustment mechanism that allows us to pass a
portion of prudently-incurred delivered power costs, including fuel, purchased capacity and
energy, and transmission costs, through to customers.
Power Capacity Cost Adjustment is an annual adjustment that allows us to pass the
prudently-incurred purchased capacity costs, incremental to costs included in base rates,
through to customers.
The 60.8 MW wind farm owned by Colorado Electric.
United States Department of Transportation's Pipeline and Hazardous Materials Safety
Administration
Power Purchase Agreement
Power Sales Agreement
Production Tax Credit
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 owns and operates
this facility. The plants commenced operation on January 1, 2012.
Public Utility Holding Company Act of 2005
The Company’s branding platform which emphasizes that we will 1) prioritize our
customers; 2) act as a thoughtful, responsible leader; 3) listen first and lead with a focus on
relationships; and 4) be creative in our approach to solutions.
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.
Renewable Energy Standard Adjustment is an incremental retail rate limited to 2% for
Colorado Electric customers that provides funding for renewable energy projects and
programs to comply with Colorado’s Renewable Energy Standard.
corporate purposes, which was amended on May 9, 2023 and will terminate on July 19,
2026. 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.
Rocky Mountain Natural Gas LLC, an indirect, wholly-owned subsidiary of Black Hills Utility
Holdings, providing natural gas transmission and wholesale services in western Colorado
(doing business as Black Hills Energy).
Renewable natural gas
Regional Transmission Organization
South Dakota Public Utilities Commission
United States Securities and Exchange Commission
monthly service agreements to residential utility customers.
Sulfur dioxide
Revolving Credit Facility
Our $750 million credit facility used to fund working capital needs, letters of credit and other
Service Guard Comfort Plan
Appliance protection plan that provides home appliance repair services through on-going
Northern Iowa Windpower
Northern Iowa Windpower, LLC, a 87.1 MW wind farm located near Joice, Iowa, previously
owned by Black Hills Electric Generation. In March 2023, Black Hills Electric Generation
completed the sale of Northern Iowa Windpower assets to a third-party.
Net Operating Loss
Other Comprehensive Income
Other Post-Employment Benefits
United States Department of Labor’s Occupational Safety & Health Administration
United States Department of the Interior’s Office of Surface Mining
PacifiCorp
PacifiCorp, a wholly owned subsidiary of MidAmerican Energy Holdings Company, itself an
affiliate of Berkshire Hathaway.
SOFR
S&P
South Dakota Electric
SPP
SSIR
Secured Overnight Financing Rate
S&P Global Ratings, a division of S&P Global Inc.
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).
Southwest Power Pool, a regional transmission organization (RTO) that oversees the bulk
electric grid and wholesale power market in the central United States.
System Safety and Integrity Rider is a mechanism that allows us to recover the costs
associated with certain pipeline safety and integrity investments, including the replacement
of higher risk pipe, the improvement of the data management system, and the mitigation of
other safety issues identified on our natural gas system.
System Peak Demand
Represents the highest point of retail customer usage for a single hour.
TCA
TCAM
TCJA
Tech Services
TEPR
TFA
Transmission Tie
TSA
Utilities
VEBA
VIE
WEIS
Wind Capacity Factor
Winter Storm Uri
Transmission Cost Adjustment is an annual adjustment mechanism that allows us to
recover from customers eligible transmission investments prior to the next rate review.
Transmission Cost Adjustment Mechanism is a WPSC-approved tariff based on a formulaic
approach that determines the recovery of Wyoming Electric's transmission costs.
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.
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.
Transportation Electrification Program Rider is a CPUC-approved mechanism associated
with Colorado Electric's EV program.
Transmission Facility Adjustment is an annual adjustment mechanism that allows us to
recover charges for qualifying new and modified transmission facilities from customers.
South Dakota Electric owns 35% of a AC-DC-AC transmission tie that interconnects the
Western and Eastern transmission grids, which are independently-operated transmission
grids serving the western and eastern United States, respectively. Basin Electric Power
Cooperative owns the remaining ownership percentage. This transmission tie allows us to
buy and sell energy in the Eastern grid without having to isolate and physically reconnect
load or generation between the two transmission grids, thus enhancing the reliability of our
system. It accommodates scheduling transactions in both directions simultaneously,
provides additional opportunities to sell excess generation or to make economic purchases
to serve our native load and contract obligations, and enables us to take advantage of
power price differentials between the two grids. The total transfer capacity of the tie is 400
MW, including 200 MW from West to East and 200 MW from East to West.
United States Department of Homeland Security's Transportation Security Administration
Black Hills’ Electric and Gas Utilities
Voluntary Employee Benefit Association
Variable Interest Entity
Western Energy Imbalance Service
Measures the amount of electricity a wind turbine produces in a given time period relative
to its maximum potential
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.
Working Capacity
Total gas storage capacity minus cushion gas
WPSC
WRDC
Wyoming Public Service Commission
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).
9
10-KFORM 10-K | Wygen I
Wygen II
Wygen III
Wyodak Plant
Wyoming Electric
Wyoming Gas
Wyoming Integrity Rider
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%.
A mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of
95 MW located at our Gillette Energy Complex.
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%.
The 402.3 MW mine-mouth, coal-fired generating facility located at our Gillette Energy
Complex, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). WRDC
supplies all of the fuel for the facility.
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).
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).
The Wyoming Integrity Rider (WIR) is a WPSC-approved tariff that allows Wyoming Gas to
recover costs from customers associated with ongoing infrastructure replacement, gas
meter and yard line replacement projects driven by federal regulation.
10
10-K| FORM 10-K
Wygen I
Wygen II
Wygen III
Wyodak Plant
Wyoming Electric
Wyoming Gas
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%.
A mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of
95 MW located at our Gillette Energy Complex.
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%.
The 402.3 MW mine-mouth, coal-fired generating facility located at our Gillette Energy
Complex, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). WRDC
supplies all of the fuel for the facility.
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).
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).
Wyoming Integrity Rider
The Wyoming Integrity Rider (WIR) is a WPSC-approved tariff that allows Wyoming Gas to
recover costs from customers associated with ongoing infrastructure replacement, gas
meter and yard line replacement projects driven by federal regulation.
WEBSITE ACCESS TO REPORTS
The reports we file with the SEC are available free of charge at our website www.blackhillscorp.com as soon as reasonably
practicable after they are filed. In addition, the charters of our Audit, Governance and Compensation Committees are located on
our website along with our Code of Business Conduct, Code of Ethics for our Chief Executive Officer and Senior Finance
Officers, Corporate Governance Guidelines of the Board of Directors and Policy for Director Independence. The information
contained on our website is not part of this document.
FORWARD-LOOKING INFORMATION
This Form 10-K contains 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. From time to time, the Company may publish or otherwise make available forward-
looking statements of this nature, including statements contained within Item 7 - Management’s Discussion & Analysis of
Financial Condition and Results of Operations.
Forward-looking statements involve risks and uncertainties, which could cause actual results or outcomes to differ materially
from those expressed. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the
Company to have a reasonable basis, including, without limitation, management’s examination of historical operating trends,
data contained in the Company’s records and other data available from third parties. Nonetheless, the Company’s expectations,
beliefs or projections may not be achieved or accomplished.
Any forward-looking statement contained in this document speaks only as of the date on which the statement is made and the
Company undertakes no obligation to update any forward-looking statement or statements to reflect events or circumstances
that occur after the date on which the statement is made or to reflect the occurrence of unanticipated events. New factors
emerge from time to time, such as adverse macroeconomic conditions, global pandemics or severe weather events, and it is not
possible for management to predict all of the factors, nor can it assess the effect of each factor on the Company’s business or
the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any
forward-looking statement. All forward-looking statements, whether written or oral and whether made by or on behalf of the
Company, are expressly qualified by the risk factors and cautionary statements in this Annual Report on Form 10-K, including
statements contained within Item 1A - Risk Factors.
11
10-KFORM 10-K |
PART I
ITEM 1. BUSINESS
History and Organization
Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,”
“us” or “our”), is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota (incorporated in
South Dakota in 1941).
We operate our business in the United States, reporting our operating results through our Electric Utilities and Gas Utilities
segments. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.
Our Electric Utilities segment generates, transmits and distributes electricity to approximately 222,000 electric utility customers in
Colorado, Montana, South Dakota and Wyoming. Our Electric Utilities own 1,394 MW of generation and 9,106 miles of electric
transmission and distribution lines.
Our Gas Utilities segment serves approximately 1,116,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas,
Nebraska, and Wyoming. Our Gas Utilities own and operate 4,663 miles of intrastate gas transmission pipelines and 42,514
miles of gas distribution mains and service lines, seven natural gas storage sites, more than 50,000 horsepower of compression
and 516 miles of gathering lines.
Electric Utilities
We conduct electric utility operations through our Colorado, South Dakota and Wyoming subsidiaries. Our Electric Utilities
generate, transmit and distribute electricity to our retail customers. Our electric generating facilities and power purchase
agreements provide for the supply of electricity principally to our retail customers. We also sell excess power to other utilities and
marketing companies, including our affiliates. Additionally, we provide non-regulated services to our retail customers under the
Service Guard Comfort Plan and Tech Services.
We also own and operate non-regulated power generation and mining assets that are vertically integrated into and primarily
support our Electric Utilities. All of these operations are located at our electric generating complexes and are physically
integrated into our Electric Utilities’ operations.
Retail Customers
Residential
Commercial
Industrial
Other
Total Electric Retail Customers at End of Year
Retail Customers
Colorado Electric
South Dakota Electric
Wyoming Electric
Total Electric Retail Customers at End of Year
2023
As of December 31,
2022
2021
190,776
30,491
84
989
222,340
188,921
30,404
82
1,024
220,431
2023
As of December 31,
2022
2021
100,907
76,479
44,954
222,340
100,573
75,169
44,689
220,431
186,852
30,326
81
1,010
218,269
99,709
74,509
44,051
218,269
Capacity and Demand. System Peak Demand for the Electric Utilities’ retail customers for each of the last three years are
listed below:
2023 (a)
Summer
411
378
312
Winter
297
289
301
System Peak Demand (in MW)
2022
2021
Summer
Winter
Summer
Winter
410
403
294
334
355
281
407
397
274
279
299
246
Coal, Natural Gas, Diesel Oil and Other Market Purchases
In 2023, Wyoming Electric set new summer and winter peak loads. See recent peak discussion in the Recent Developments section of
Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 in this Annual Report on Form 10-K for
additional information.
Colorado Electric
South Dakota Electric
Wyoming Electric
____________________
(a)
12
As of December 31, 2023, our Electric Utilities’ ownership interests in electric generating plants were as follows:
Owned
Ownership
Interest % (d)
Nameplate
In Service
Capacity (MW)
Date
Fuel
Type
Wind
Wind
Natural Gas
Natural Gas
Diesel Oil
Diesel Oil
Diesel Oil
Natural Gas
Wind
Coal
Coal
Coal
Natural Gas
Natural Gas
Diesel Oil
Natural Gas
Natural Gas
Wind
Coal
Coal
Wind
Wind
Location
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
Rocky Ford, Colorado
Cheyenne, Wyoming
Cheyenne, Wyoming
Gillette, Wyoming
Gillette, Wyoming
Gillette, Wyoming
Gillette, Wyoming
Rapid City, South Dakota
Rapid City, South Dakota
Cheyenne, Wyoming
Cheyenne, Wyoming
Cheyenne, Wyoming
Gillette, Wyoming
50%
100%
100%
100%
100%
100%
100%
58%
62%
52%
100%
20%
100%
100%
100%
100%
42%
100%
38%
100%
Gillette, Wyoming
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
76.5%
50.1% (e)
50%
100%
14.5
60.8
200.0
40.0
10.0
8.0
10.0
58.0
32.5
60.3
90.0
80.5
40.0
40.0
10.0
42.0
40.0
20.0
95.0
68.9
200.0
14.5
59.4
1,394.4
2012
2016
2011
2016
2001
1964
1964
2014
2020
2010
1995
1978
2000
2002
1965
2014
2014
2020
2008
2003
2012
2012
2019
Natural Gas/Diesel Oil Rapid City, South Dakota
100.0 1977-1979
Pueblo Airport Generation #4-5
Natural Gas
In 2013, Busch Ranch I was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American
Recovery and Reinvestment Act.
The PTCs for Peak View flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins.
This facility qualifies for PTCs at $28/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed
Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
In 2016, Black Hills Electric Generation sold a 49.9% non-controlling interest in Black Hills Colorado IPP to a third party. See Note 12 of
the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
Our Electric Utilities’ power supply by resource as a percent of the total power supply for our energy needs for the years ended
Unit
Colorado Electric:
Busch Ranch I (a)
Peak View (b) (c)
Pueblo Airport Generation #1-2
Pueblo Airport Generation CT #6
AIP Diesel
Diesel #1 and #3-5
Diesel #1-5
South Dakota Electric:
Cheyenne Prairie
Corriedale (c)
Wygen III
Neil Simpson II
Wyodak Plant
Neil Simpson CT
Lange CT
Ben French Diesel #1-5
Ben French CTs #1-4
Wyoming Electric:
Cheyenne Prairie
Cheyenne Prairie CT
Corriedale (c)
Wygen II
Integrated Generation:
Wygen I
Busch Ranch I (a)
Busch Ranch II (c)
Total MW Capacity
____________________
(a)
(b)
(c)
(d)
(e)
in service.
December 31 was as follows:
Power Supply
Coal
Natural Gas
Wind (a)
Total Generated (b)
Wind and Solar Purchases
Total Purchased
Total
____________________
2023
2022
2021
35.0%
26.4%
8.9%
70.3%
24.1%
5.6%
29.7%
35.1%
18.8%
11.4%
65.3%
29.6%
5.1%
34.7%
34.2%
24.4%
11.3%
69.9%
25.1%
5.0%
30.1%
100.0%
100.0%
100.0%
(a) Wind generation decreased due to the sale of Northern Iowa Windpower assets in March 2023.
(b)
The diesel oil-fueled generating units are generally used as supplemental peaking units. Power generated from these units, as a
percentage of total power supply, was 0.0% for each of the years presented.
10-K| FORM 10-K
PART I
ITEM 1. BUSINESS
History and Organization
South Dakota in 1941).
Black Hills Corporation, a South Dakota corporation (together with its subsidiaries, referred to herein as the “Company,” “we,”
“us” or “our”), is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota (incorporated in
We operate our business in the United States, reporting our operating results through our Electric Utilities and Gas Utilities
segments. Certain unallocated corporate expenses that support our operating segments are presented as Corporate and Other.
Our Electric Utilities segment generates, transmits and distributes electricity to approximately 222,000 electric utility customers in
Colorado, Montana, South Dakota and Wyoming. Our Electric Utilities own 1,394 MW of generation and 9,106 miles of electric
transmission and distribution lines.
Our Gas Utilities segment serves approximately 1,116,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas,
Nebraska, and Wyoming. Our Gas Utilities own and operate 4,663 miles of intrastate gas transmission pipelines and 42,514
miles of gas distribution mains and service lines, seven natural gas storage sites, more than 50,000 horsepower of compression
and 516 miles of gathering lines.
Electric Utilities
We conduct electric utility operations through our Colorado, South Dakota and Wyoming subsidiaries. Our Electric Utilities
generate, transmit and distribute electricity to our retail customers. Our electric generating facilities and power purchase
agreements provide for the supply of electricity principally to our retail customers. We also sell excess power to other utilities and
marketing companies, including our affiliates. Additionally, we provide non-regulated services to our retail customers under the
Service Guard Comfort Plan and Tech Services.
We also own and operate non-regulated power generation and mining assets that are vertically integrated into and primarily
support our Electric Utilities. All of these operations are located at our electric generating complexes and are physically
integrated into our Electric Utilities’ operations.
Total Electric Retail Customers at End of Year
As of December 31,
2023
2022
2021
As of December 31,
2023
2022
2021
188,921
30,404
82
1,024
220,431
100,573
75,169
44,689
220,431
186,852
30,326
81
1,010
218,269
99,709
74,509
44,051
218,269
190,776
30,491
84
989
222,340
100,907
76,479
44,954
222,340
2022
410
403
294
Total Electric Retail Customers at End of Year
Capacity and Demand. System Peak Demand for the Electric Utilities’ retail customers for each of the last three years are
System Peak Demand (in MW)
Summer
Winter
Summer
Winter
Summer
Winter
334
355
281
2021
407
397
274
279
299
246
2023 (a)
411
378
312
297
289
301
(a)
In 2023, Wyoming Electric set new summer and winter peak loads. See recent peak discussion in the Recent Developments section of
Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 in this Annual Report on Form 10-K for
Retail Customers
Residential
Commercial
Industrial
Other
Retail Customers
Colorado Electric
South Dakota Electric
Wyoming Electric
listed below:
Colorado Electric
South Dakota Electric
Wyoming Electric
____________________
additional information.
As of December 31, 2023, our Electric Utilities’ ownership interests in electric generating plants were as follows:
Ownership
Interest % (d)
Owned
Nameplate
Capacity (MW)
In Service
Date
Unit
Colorado Electric:
Busch Ranch I (a)
Peak View (b) (c)
Pueblo Airport Generation #1-2
Pueblo Airport Generation CT #6
AIP Diesel
Diesel #1 and #3-5
Diesel #1-5
South Dakota Electric:
Cheyenne Prairie
Corriedale (c)
Wygen III
Neil Simpson II
Wyodak Plant
Neil Simpson CT
Lange CT
Ben French Diesel #1-5
Ben French CTs #1-4
Wyoming Electric:
Cheyenne Prairie
Cheyenne Prairie CT
Corriedale (c)
Wygen II
Integrated Generation:
Wygen I
Pueblo Airport Generation #4-5
Busch Ranch I (a)
Busch Ranch II (c)
Total MW Capacity
____________________
(a)
Fuel
Type
Wind
Wind
Natural Gas
Natural Gas
Diesel Oil
Diesel Oil
Diesel Oil
Location
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
Rocky Ford, Colorado
Natural Gas
Wind
Coal
Coal
Coal
Natural Gas
Natural Gas
Diesel Oil
Cheyenne, Wyoming
Cheyenne, Wyoming
Gillette, Wyoming
Gillette, Wyoming
Gillette, Wyoming
Gillette, Wyoming
Rapid City, South Dakota
Rapid City, South Dakota
Natural Gas/Diesel Oil Rapid City, South Dakota
Natural Gas
Natural Gas
Wind
Coal
Coal
Natural Gas
Wind
Wind
Cheyenne, Wyoming
Cheyenne, Wyoming
Cheyenne, Wyoming
Gillette, Wyoming
Gillette, Wyoming
Pueblo, Colorado
Pueblo, Colorado
Pueblo, Colorado
76.5%
50.1% (e)
50%
100%
50%
100%
100%
100%
100%
100%
100%
58%
62%
52%
100%
20%
100%
100%
100%
100%
42%
100%
38%
100%
14.5
60.8
200.0
40.0
10.0
8.0
10.0
58.0
32.5
60.3
90.0
80.5
40.0
40.0
10.0
2012
2016
2011
2016
2001
1964
1964
2014
2020
2010
1995
1978
2000
2002
1965
100.0 1977-1979
42.0
40.0
20.0
95.0
68.9
200.0
14.5
59.4
1,394.4
2014
2014
2020
2008
2003
2012
2012
2019
In 2013, Busch Ranch I was awarded a one-time cash grant in lieu of ITCs under the Section 1603 program created under the American
Recovery and Reinvestment Act.
The PTCs for Peak View flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins.
This facility qualifies for PTCs at $28/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed
in service.
Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
In 2016, Black Hills Electric Generation sold a 49.9% non-controlling interest in Black Hills Colorado IPP to a third party. See Note 12 of
the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
(b)
(c)
(d)
(e)
Our Electric Utilities’ power supply by resource as a percent of the total power supply for our energy needs for the years ended
December 31 was as follows:
2023
Power Supply
Coal
Natural Gas
Wind (a)
Total Generated (b)
Coal, Natural Gas, Diesel Oil and Other Market Purchases
Wind and Solar Purchases
Total Purchased
Total
____________________
(a) Wind generation decreased due to the sale of Northern Iowa Windpower assets in March 2023.
(b)
35.0%
26.4%
8.9%
70.3%
24.1%
5.6%
29.7%
100.0%
2022
2021
35.1%
18.8%
11.4%
65.3%
29.6%
5.1%
34.7%
100.0%
34.2%
24.4%
11.3%
69.9%
25.1%
5.0%
30.1%
100.0%
The diesel oil-fueled generating units are generally used as supplemental peaking units. Power generated from these units, as a
percentage of total power supply, was 0.0% for each of the years presented.
13
10-KFORM 10-K |
Our Electric Utilities’ weighted average cost of fuel utilized to generate electricity and the average price paid for purchased power
(excluding contracted capacity) per MWh for the years ended December 31 were as follows:
Fuel and Purchased Power (dollars per MWh)
Coal
Natural Gas
Total Generated Weighted Average Fuel Cost
Coal, Natural Gas, Diesel Oil and Other Market Purchases
Wind and Solar Purchases
Total Purchased Power Weighted Average Cost
Total Weighted Average Fuel and Purchased Power Cost
2023
2022
2021
$
$
13.40 $
20.20
14.27
55.61
34.99
51.68
25.39 $
12.76 $
37.09
17.57
66.35
33.78
61.56
32.82 $
11.55
33.65
17.40
64.85
34.69
59.84
30.17
Purchased Power. We have executed various PPAs to support our Electric Utilities’ capacity and energy needs beyond our
regulated power plants’ generation, which include long-term related party agreements with our non-regulated power generation
businesses. See additional information in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K.
Coal Mining. We own and operate a single coal mine through our WRDC subsidiary which is reported within our Electric Utilities
segment. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine located immediately adjacent to our
Gillette Energy Complex in the Powder River Basin in northeastern Wyoming, where our five coal-fired power plants are located.
We produced approximately 3.7 million tons of coal in 2023.
The mine provides low-sulfur coal directly to these five power plants via a conveyor belt system, minimizing transportation costs.
The fuel can be delivered to our adjacent power plants at very cost competitive prices (i.e., $1.14 per MMBtu for year ended
December 31, 2023) when compared to alternatives. Nearly all of the mine’s production is sold to our on-site generation facilities
under long-term supply contracts.
As of December 31, 2023, we estimated our recoverable reserves to be approximately 179 million tons, based on a life-of-mine
engineering study utilizing currently available drilling data and geological information prepared by internal engineering analyses.
The recoverable reserve life is equal to approximately 48 years at the current production levels.
Transmission and Distribution. Through our Electric Utilities, we own electric transmission and distribution systems composed
of high voltage lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly operate an electric transmission
system, referred to as the Common Use System, with Basin Electric Power Cooperative and Powder River Energy Corporation.
Each participant in the Common Use System individually owns assets that are operated together for a single system. The
Common Use System also provides transmission service to our Transmission Tie. South Dakota Electric owns 35% of the
Transmission Tie. The Transmission Tie is further discussed in Note 6 of the Notes to Consolidated Financial Statements in this
Annual Report on Form 10-K.
At December 31, 2023, our Electric Utilities owned the electric transmission and distribution lines shown below:
Utility
Colorado Electric
South Dakota Electric (b)
Wyoming Electric
State
Colorado
South Dakota, Wyoming
Wyoming
Transmission (a)
(in Line Miles)
Distribution
(in Line Miles)
599
1,232
86
1,917
3,213
2,616
1,360
7,189
____________________
(a)
(b)
Electric transmission line miles include voltages of 69 kV and above.
South Dakota Electric transmission line miles include 43 miles within the Common Use System.
Material transmission services agreements are included in our disclosures in Note 3 of the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K.
Seasonal Variations of Business. Our Electric Utilities are seasonal businesses and weather patterns may impact their
operating results. Demand for electricity is sensitive to seasonal cooling, heating and industrial load requirements, as well as
market price. In particular, cooling demand is often greater in the summer and heating demand is often greater in the winter.
14
10-K| FORM 10-K
Our Electric Utilities’ weighted average cost of fuel utilized to generate electricity and the average price paid for purchased power
(excluding contracted capacity) per MWh for the years ended December 31 were as follows:
Fuel and Purchased Power (dollars per MWh)
Coal
Natural Gas
Total Generated Weighted Average Fuel Cost
Coal, Natural Gas, Diesel Oil and Other Market Purchases
Wind and Solar Purchases
Total Purchased Power Weighted Average Cost
Total Weighted Average Fuel and Purchased Power Cost
2023
2022
2021
13.40 $
12.76 $
$
$
20.20
14.27
55.61
34.99
51.68
37.09
17.57
66.35
33.78
61.56
25.39 $
32.82 $
11.55
33.65
17.40
64.85
34.69
59.84
30.17
Purchased Power. We have executed various PPAs to support our Electric Utilities’ capacity and energy needs beyond our
regulated power plants’ generation, which include long-term related party agreements with our non-regulated power generation
businesses. See additional information in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K.
Coal Mining. We own and operate a single coal mine through our WRDC subsidiary which is reported within our Electric Utilities
segment. We surface mine, process and sell low-sulfur sub-bituminous coal at our mine located immediately adjacent to our
Gillette Energy Complex in the Powder River Basin in northeastern Wyoming, where our five coal-fired power plants are located.
We produced approximately 3.7 million tons of coal in 2023.
The mine provides low-sulfur coal directly to these five power plants via a conveyor belt system, minimizing transportation costs.
The fuel can be delivered to our adjacent power plants at very cost competitive prices (i.e., $1.14 per MMBtu for year ended
December 31, 2023) when compared to alternatives. Nearly all of the mine’s production is sold to our on-site generation facilities
under long-term supply contracts.
As of December 31, 2023, we estimated our recoverable reserves to be approximately 179 million tons, based on a life-of-mine
engineering study utilizing currently available drilling data and geological information prepared by internal engineering analyses.
The recoverable reserve life is equal to approximately 48 years at the current production levels.
Transmission and Distribution. Through our Electric Utilities, we own electric transmission and distribution systems composed
of high voltage lines (greater than 69 kV) and low voltage lines (69 kV or less). We also jointly operate an electric transmission
system, referred to as the Common Use System, with Basin Electric Power Cooperative and Powder River Energy Corporation.
Each participant in the Common Use System individually owns assets that are operated together for a single system. The
Common Use System also provides transmission service to our Transmission Tie. South Dakota Electric owns 35% of the
Transmission Tie. The Transmission Tie is further discussed in Note 6 of the Notes to Consolidated Financial Statements in this
Annual Report on Form 10-K.
At December 31, 2023, our Electric Utilities owned the electric transmission and distribution lines shown below:
Utility
Colorado Electric
South Dakota Electric (b)
Wyoming Electric
____________________
State
Colorado
Wyoming
South Dakota, Wyoming
Transmission (a)
(in Line Miles)
Distribution
(in Line Miles)
599
1,232
86
1,917
3,213
2,616
1,360
7,189
(a)
(b)
Electric transmission line miles include voltages of 69 kV and above.
South Dakota Electric transmission line miles include 43 miles within the Common Use System.
Material transmission services agreements are included in our disclosures in Note 3 of the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K.
Seasonal Variations of Business. Our Electric Utilities are seasonal businesses and weather patterns may impact their
operating results. Demand for electricity is sensitive to seasonal cooling, heating and industrial load requirements, as well as
market price. In particular, cooling demand is often greater in the summer and heating demand is often greater in the winter.
Competition. We generally have limited competition for the retail generation and distribution of electricity in our service areas.
Various legislative or regulatory restructuring and competitive initiatives have been discussed in several of the states in which
our utilities operate. These initiatives would be aimed at increasing competition or providing for distributed generation. To date,
these initiatives have not had a material impact on our utilities. In Colorado, our electric utility is subject to rules which may
require competitive bidding for generation supply. Because of these rules, we face competition from other utilities and non-
affiliated IPPs for the right to supply electric energy and capacity for Colorado Electric when resource plans require additional
resources. Additionally, electrification initiatives in our service territories could increase demand for electricity and increase
customer growth.
The independent power industry consists of many strong and capable competitors, some of which may have more extensive
operations or greater financial resources than we possess. With respect to the merchant power sector, FERC has taken steps to
increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity to foster
competition within the wholesale electricity markets. Our non-regulated power generation businesses could face greater
competition if utilities are permitted to robustly invest in power generation assets. Conversely, state regulations requiring utilities
to competitively bid generation resources may provide opportunity for IPPs in some regions. To date, these initiatives have not
had a material impact on our non-regulated power generation businesses.
Our mining business strategy is to sell nearly all of our production to on-site generation facilities under long-term supply
contracts. Historically, any off-site sales have been to consumers within close proximity to WRDC. Coal competes with other
energy sources, such as natural gas, nuclear, wind, solar and hydropower. Costs and other factors relating to these alternative
fuels, such as safety, environmental and availability considerations affect the overall demand for coal as a fuel.
Operating Statistics. See a summary of key operating statistics in the Electric Utilities segment operating results within
Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on
Form 10-K.
Gas Utilities
We conduct natural gas utility operations through our Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming subsidiaries.
Our Gas Utilities transport and distribute natural gas through our distribution network to our retail customers. Additionally, we sell
contractual pipeline capacity and gas commodities to other utilities and marketing companies, including our affiliates, on an as-
available basis.
We also provide non-regulated services to our regulated customers. Black Hills Energy Services provides natural gas supply to
approximately 53,000 retail distribution customers under the Choice Gas Program in Nebraska and Wyoming. Additionally, we
provide services under the Service Guard Comfort Plan, Tech Services and HomeServe.
Retail Customers
Residential
Commercial
Industrial
Transportation
Total Natural Gas Retail Customers at End of Year
Retail Customers
Arkansas Gas
Colorado Gas
Iowa Gas
Kansas Gas
Nebraska Gas
Wyoming Gas
Total Natural Gas Retail Customers at End of Year
2023
As of December 31,
2022
2021
871,930
84,917
2,179
157,367
1,116,393
864,038
85,203
2,189
155,685
1,107,115
853,908
84,234
2,158
153,929
1,094,229
2023
As of December 31,
2022
2021
186,216
211,155
163,281
119,407
302,167
134,167
1,116,393
183,270
208,060
162,801
118,599
301,007
133,378
1,107,115
180,216
202,747
161,905
117,862
298,832
132,667
1,094,229
We procure natural gas for our distribution customers from a diverse mix of producers, processors and marketers and generally
use hedging, physical fixed-price purchases and market-based price purchases to achieve dollar-cost averaging within our
natural gas portfolio. The majority of our procured natural gas is transported in interstate pipelines under firm transportation
service agreements.
In addition to company-owned regulated underground natural gas storage assets in Arkansas, Colorado and Wyoming, we also
contract with third-party transportation providers for natural gas storage service to provide gas supply during the winter heating
season and to meet peak day customer demand for natural gas.
15
10-KFORM 10-K |
The following table summarizes certain information regarding our company-owned regulated underground gas storage facilities
as of December 31, 2023:
Arkansas Gas
Colorado Gas
Wyoming Gas
Total
Working Capacity
(Mcf)
Cushion Gas
(Mcf)
Total Capacity
(Mcf)
8,442,700
2,360,895
5,733,900
16,537,495
13,149,040
6,165,315
17,545,600
36,859,955
21,591,740
8,526,210
23,279,500
53,397,450
Maximum Daily
Withdrawal Capability
(Mcfd)
196,000
30,000
36,000
262,000
The following table summarizes certain information regarding our system infrastructure as of December 31, 2023:
Arkansas Gas
Colorado Gas
Iowa Gas
Kansas Gas
Nebraska Gas
Wyoming Gas
Total
Intrastate Gas
Transmission Pipelines
(in line miles)
Gas Distribution
Mains
(in line miles)
Gas Distribution
Service Lines
(in line miles)
875
694
173
339
1,315
1,267
4,663
5,197
7,188
2,890
3,026
8,611
3,625
30,537
1,380
1,861
2,765
1,400
2,845
1,726
11,977
Seasonal Variations of Business. Our Gas Utilities are seasonal businesses and weather patterns may impact their operating
results. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as market price. In
particular, demand is often greater in the winter months for heating. Natural gas is used primarily for residential and commercial
heating, and demand for this product can depend heavily upon weather throughout our service territories. As a result, a
significant amount of natural gas revenue is normally recognized in the heating season consisting of the first and fourth quarters.
Demand for natural gas can also be impacted by summer temperatures and precipitation, which can affect demand for irrigation.
Competition. We generally have limited competition for the retail distribution of natural gas in our service areas. Various
restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These
initiatives are aimed at increasing competition. Additionally, electrification initiatives in our service territories could negatively
impact demand for natural gas and decrease future growth. To date, these initiatives have not had a material impact on our
utilities. Although we face competition from independent marketers for the sale of natural gas to our industrial and commercial
customers, in instances where independent marketers displace us as the seller of natural gas, we still collect fees for
transporting the gas through our distribution network.
Operating statistics. See a summary of key operating statistics in the Gas Utilities segment operating results within
Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on
Form 10-K.
16
10-K| FORM 10-K The following table summarizes certain information regarding our company-owned regulated underground gas storage facilities
Utility Regulation Characteristics
as of December 31, 2023:
Maximum Daily
Our Utilities are subject to regulation by a number of federal, state and other organizations, including, but not limited to, the
following:
Working Capacity
Cushion Gas
Total Capacity
Withdrawal Capability
(Mcf)
(Mcf)
(Mcf)
(Mcfd)
Arkansas Gas
Colorado Gas
Wyoming Gas
Total
8,442,700
2,360,895
5,733,900
16,537,495
13,149,040
6,165,315
17,545,600
36,859,955
21,591,740
8,526,210
23,279,500
53,397,450
The following table summarizes certain information regarding our system infrastructure as of December 31, 2023:
Intrastate Gas
Transmission Pipelines
(in line miles)
Gas Distribution
Mains
(in line miles)
Gas Distribution
Service Lines
(in line miles)
Arkansas Gas
Colorado Gas
Iowa Gas
Kansas Gas
Nebraska Gas
Wyoming Gas
Total
875
694
173
339
1,315
1,267
4,663
5,197
7,188
2,890
3,026
8,611
3,625
30,537
196,000
30,000
36,000
262,000
1,380
1,861
2,765
1,400
2,845
1,726
11,977
Seasonal Variations of Business. Our Gas Utilities are seasonal businesses and weather patterns may impact their operating
results. Demand for natural gas is sensitive to seasonal heating and industrial load requirements, as well as market price. In
particular, demand is often greater in the winter months for heating. Natural gas is used primarily for residential and commercial
heating, and demand for this product can depend heavily upon weather throughout our service territories. As a result, a
significant amount of natural gas revenue is normally recognized in the heating season consisting of the first and fourth quarters.
Demand for natural gas can also be impacted by summer temperatures and precipitation, which can affect demand for irrigation.
Competition. We generally have limited competition for the retail distribution of natural gas in our service areas. Various
restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These
initiatives are aimed at increasing competition. Additionally, electrification initiatives in our service territories could negatively
impact demand for natural gas and decrease future growth. To date, these initiatives have not had a material impact on our
utilities. Although we face competition from independent marketers for the sale of natural gas to our industrial and commercial
customers, in instances where independent marketers displace us as the seller of natural gas, we still collect fees for
transporting the gas through our distribution network.
Operating statistics. See a summary of key operating statistics in the Gas Utilities segment operating results within
Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on
Form 10-K.
•
•
•
•
•
•
State public utility commissions, which have jurisdiction over services and facilities, rates and charges, accounting,
valuation of property, depreciation rates and various other matters;
the FERC, which oversees the acquisition and disposition of generation, transmission and other facilities,
transmission of electricity and natural gas in interstate commerce, proposals to build and operate interstate natural
gas pipelines and storage facilities, and wholesale purchases and sales of electric energy, among other things;
the NERC, which, through its regional entities, establishes and enforces mandatory reliability standards, subject to
approval by the FERC, to ensure the reliability of the U.S. electric transmission and generation system and to
prevent major system blackouts;
the EPA, which has the responsibility to maintain and enforce national standards under a variety of environmental
laws, in some cases delegating authority to state agencies. The EPA also works with industries and all levels of
government, including federal and state governments, in a wide variety of voluntary pollution prevention programs
and energy conservation efforts;
the TSA, which regulates certain activities related to the safety and security of natural gas pipelines. In May and July
2021 the TSA issued security directives that included several new cybersecurity requirements for critical pipeline
owners and operators; and
the PHMSA, which is responsible for administering the federal regulatory program to help ensure the safe
transportation of natural gas, petroleum and other hazardous materials by pipelines, including pipelines associated
with natural gas storage, and develops regulations and other approaches to risk management to help ensure safety
in design, construction, testing, operation, maintenance and emergency response of pipeline facilities.
Rates and Regulation
Our Utilities are subject to the jurisdiction of the public utility commissions in the states where they operate and the FERC for
certain assets and transactions. These commissions oversee services and facilities, rates and charges, accounting, valuation of
property, depreciation rates and various other matters. Rate decisions are influenced by many factors, including the cost of
providing service, capital expenditures, the prudence of costs we incur, views concerning appropriate rates of return, general
economic conditions and the political environment. Certain commissions also have jurisdiction over the issuance of debt or
securities and the creation of liens on property located in their states to secure bonds or other securities.
The regulatory provisions for recovering the costs of service vary by jurisdiction. Our Utilities have cost recovery mechanisms
that allow us to pass the prudently-incurred cost of natural gas, fuel and purchased power to customers. These mechanisms
allow the utility operating in that state to collect or refund the difference between the cost of commodities and certain services
embedded in our base rates and the actual cost of the commodities and certain services without filing a general rate review. In
addition, some jurisdictions allow us to recover certain costs or earn a return on capital investments placed in service between
base rate reviews through approved rider tariffs, such as energy efficiency plan costs and system safety and integrity
investments. These tariffs allow the utility a return on the investment.
17
10-KFORM 10-K | Electric Utilities
The following table provides regulatory information for each of our Electric Utilities:
Subsidiary
Jurisdiction
Authorized
Rate of
Return on
Equity
Authorized
Return on
Rate Base
Authorized
Capital
Structure
Debt/Equity
Authorized
Rate Base
(in millions)
Effective
Date
Additional Regulatory
Mechanisms
Percentage of
Power Marketing
Profit Shared
with Customers
Colorado Electric
CO
9.37%
7.43%
48%/52%
$653.7 (a)
1/2017
ECA, TCA, PCCA,
EECR/DSM, RESA, TEPR,
Energy Assistance Benefit
Charge
South Dakota Electric
Wyoming Electric (c)
CO
FERC
WY
SD
FERC
WY
9.37%
9.80%
9.90%
Global
Settlement
10.80%
9.75%
6.02%
6.45%
8.13%
7.76%
8.76%
7.48%
$57.9
(a)
$46.8
$543.9
1/2017 CACJA Adjustment Rider
9/2022 FERC Transmission Tariff
10/2014
10/2014
67%/33%
53%/47%
47%/53%
Global
Settlement
43%/57% $197.7 (b) 2/2009 FERC Transmission Tariff
PCA, EECR/DSM, Rate
3/2023
48%/52%
Base Recovery on
Acquisition Adjustment,
TCAM
ECA
ECA, TFA, EIA
$551.2 (a)
90%
N/A
N/A
65%
70%
N/A
N/A
FERC
9.90%
8.77%
44%/56%
(a)
1/2019 FERC Transmission Tariff
N/A
____________________
(a)
For both Wyoming Electric and Colorado Electric retail customers, transmission investments are recovered through retail rates rather than
FERC Transmission Tariffs. Transmission investments are recovered from wholesale transmission customers under the FERC Formula
Transmission rate. The rate base associated with FERC assets is not displayed separate from that collected through the state recovery
mechanisms, to avoid double counting. The rate base amounts for Colorado Electric and Wyoming Electric include rate base recovered
through base rates and the authorized regulatory mechanisms.
Includes $180.6 million in 2023 rate base for the 2023 Projected Common Use System formula rate that is updated annually and $17.1
million in rate base for the Transmission Tie that is based on the approved stated rate from 2005.
For additional information regarding recent rate review updates, see Note 2 of the Notes to Consolidated Financial Statements in this
Annual Report on Form 10-K.
(b)
(c)
The following table summarizes the mechanisms we have in place for each of our Electric Utilities:
Electric Utility Jurisdiction
Colorado Electric (a)
Colorado Electric (FERC) (a)
South Dakota Electric (SD) (b)
South Dakota Electric (WY) (c)
South Dakota Electric (FERC)
Wyoming Electric (a)
Wyoming Electric (FERC) (a)
____________________
(a)
Environmental
Cost
EECR/DSM
☑
Cost Recovery Mechanisms
Fuel
Cost
☑
Transmission
Expense
☑
Transmission
Capital
☑
☑
Purchased
Power
☑
RESA
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
For both Wyoming Electric and Colorado Electric retail customers, transmission investments are recovered through retail rates rather than
FERC Transmission Tariffs. Transmission investments are recovered from wholesale transmission customers under the FERC Formula
Transmission rate.
South Dakota Electric’s EIA and TFA tariffs were suspended for a six-year moratorium period effective July 1, 2017. On January 7, 2020,
South Dakota Electric received approval from the SDPUC to extend the 6-year moratorium period by an additional 3 years whereby these
recovery mechanisms will not be effective prior to July 1, 2026.
South Dakota Electric has WPSC authorization to accumulate certain energy efficiency costs in a regulatory asset with determination of
recovery to be made in the next rate review.
(b)
(c)
18
10-K| FORM 10-K Electric Utilities
The following table provides regulatory information for each of our Electric Utilities:
Subsidiary
Jurisdiction
Equity
Debt/Equity
(in millions)
Date
Mechanisms
Authorized
Rate of
Return on
Authorized
Return on
Rate Base
Authorized
Capital
Structure
Authorized
Rate Base
Effective
Additional Regulatory
Percentage of
Power Marketing
Profit Shared
with Customers
Colorado Electric
CO
9.37%
7.43%
48%/52%
$653.7 (a)
1/2017
ECA, TCA, PCCA,
90%
South Dakota Electric
Wyoming Electric (c)
CO
FERC
WY
SD
FERC
WY
9.37%
9.80%
9.90%
Global
Settlement
10.80%
9.75%
6.02%
6.45%
8.13%
7.76%
8.76%
7.48%
67%/33%
53%/47%
47%/53%
Global
Settlement
EECR/DSM, RESA, TEPR,
Energy Assistance Benefit
Charge
$57.9
1/2017 CACJA Adjustment Rider
(a)
9/2022 FERC Transmission Tariff
$46.8
$543.9
10/2014
10/2014
ECA
ECA, TFA, EIA
43%/57% $197.7 (b) 2/2009 FERC Transmission Tariff
48%/52%
$551.2 (a)
3/2023
PCA, EECR/DSM, Rate
Base Recovery on
Acquisition Adjustment,
TCAM
N/A
N/A
65%
70%
N/A
N/A
____________________
FERC
9.90%
8.77%
44%/56%
(a)
1/2019 FERC Transmission Tariff
N/A
(a)
For both Wyoming Electric and Colorado Electric retail customers, transmission investments are recovered through retail rates rather than
FERC Transmission Tariffs. Transmission investments are recovered from wholesale transmission customers under the FERC Formula
Transmission rate. The rate base associated with FERC assets is not displayed separate from that collected through the state recovery
mechanisms, to avoid double counting. The rate base amounts for Colorado Electric and Wyoming Electric include rate base recovered
through base rates and the authorized regulatory mechanisms.
(b)
(c)
Includes $180.6 million in 2023 rate base for the 2023 Projected Common Use System formula rate that is updated annually and $17.1
million in rate base for the Transmission Tie that is based on the approved stated rate from 2005.
For additional information regarding recent rate review updates, see Note 2 of the Notes to Consolidated Financial Statements in this
Annual Report on Form 10-K.
The following table summarizes the mechanisms we have in place for each of our Electric Utilities:
Environmental
Transmission
Cost
EECR/DSM
Expense
Transmission
Purchased
Capital
Power
Cost Recovery Mechanisms
RESA
☑
☑
☑
☑
☑
☑
☑
☑
Fuel
Cost
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
☑
Electric Utility Jurisdiction
Colorado Electric (a)
Colorado Electric (FERC) (a)
South Dakota Electric (SD) (b)
South Dakota Electric (WY) (c)
South Dakota Electric (FERC)
Wyoming Electric (a)
Wyoming Electric (FERC) (a)
____________________
Transmission rate.
(b)
South Dakota Electric’s EIA and TFA tariffs were suspended for a six-year moratorium period effective July 1, 2017. On January 7, 2020,
South Dakota Electric received approval from the SDPUC to extend the 6-year moratorium period by an additional 3 years whereby these
(c)
South Dakota Electric has WPSC authorization to accumulate certain energy efficiency costs in a regulatory asset with determination of
recovery mechanisms will not be effective prior to July 1, 2026.
recovery to be made in the next rate review.
Gas Utilities
The following table provides regulatory information for each of our Gas Utilities:
Subsidiary
Arkansas Gas (a)
Jurisdiction
AR
Authorized
Rate of Return
on Equity
9.60%
Authorized
Return on
Rate Base
6.20% (b)
Authorized
Capital
Structure
Debt/Equity
55%/45%
Authorized
Rate Base
(in millions)
$674.6 (c)
Effective
Date
Additional Regulatory Mechanisms
10/2022 GCA, Safety and Integrity Rider,
EECR, Weather Normalization
Adjustment, Billing Determinant
Adjustment
Colorado Gas (a)
CO
9.20%
6.56%
50%/50%
$303.2
1/2022 GCA, SSIR, DSM, Gas Price Risk
CO
9.50%-9.70%
6.93%
9.60%
6.75%
RMNG (a)
Iowa Gas
Kansas Gas
IA
KS
$209.3
Management Rider, Energy
Assistance Benefit Charge
7/2023 Liquids/Off-system/Market Center
Services Revenue Sharing
$300.9
1/2022 GCA, EECR, System Safety and
48%-50%/
50%-52%
50%/50%
Global
Settlement
Global
Settlement
Global
Settlement
Global
Settlement
Maintenance Adjustment Rider, Gas
Supply Optimization revenue sharing
1/2022 GCA, Weather Normalization Tariff,
Gas System Reliability Surcharge, Ad
Valorem Tax Surcharge, Cost of Bad
Debt Collected through GCA,
Pension Levelized Adjustment, Tax
Adjustment Rider, Gas Supply
Optimization revenue sharing
Nebraska Gas (d)
NE
9.50%
6.71%
50%/50%
$504.2 (e)
3/2021 GCA, Cost of Bad Debt Collected
through GCA, Infrastructure System
Replacement Cost Recovery
Surcharge, Choice Gas Program,
SSIR, Bad Debt expense recovered
through Choice Supplier Fee, Line
Locate Surcharge, HEAT Program
Wyoming Gas (a)(d)
WY
9.85%
7.33%
49%/51%
$450.8
1/2024 GCA, EECR, Rate Base Recovery on
Acquisition Adjustment, Wyoming
Integrity Rider, Choice Gas Program
____________________
(a)
Colorado Gas regulatory information presented above does not reflect the recent settlement agreement which is subject to CPUC
approval. For additional information regarding recent rate review updates, see Note 2 of the Notes to Consolidated Financial Statements
in this Annual Report on Form 10-K.
Arkansas Gas return on rate base is adjusted to remove certain liabilities from rate review capital structure for comparison with other
subsidiaries.
Arkansas Gas rate base is adjusted to include certain liabilities for comparison with other subsidiaries.
The Choice Gas Program mechanisms are applicable to only a portion of Nebraska Gas and Wyoming Gas customers.
Excludes amounts to serve non-jurisdictional and agriculture customers.
(b)
(c)
(d)
(e)
The following table summarizes the mechanisms we have in place for each of our Gas Utilities:
(a)
For both Wyoming Electric and Colorado Electric retail customers, transmission investments are recovered through retail rates rather than
FERC Transmission Tariffs. Transmission investments are recovered from wholesale transmission customers under the FERC Formula
Gas Utility Jurisdiction
EECR/DSM
☑
☑
Integrity
Additions
☑
☑
☑
☑
☑
☑
☑
☑
Cost Recovery Mechanisms
Weather
Normal
☑
Pension
Recovery
Bad Debt
Gas Cost (a)
☑
☑
Revenue
Decoupling
☑
☑
☑
☑
☑
☑
☑
☑
☑
Arkansas Gas
Colorado Gas
RMNG
Iowa Gas
Kansas Gas
Nebraska Gas
Wyoming Gas
____________________
(a)
All of our Gas Utilities, except where the Choice Gas Program is the only option, have GCAs that allow us to pass the prudently-incurred
cost of gas and certain services through to the customer between rate reviews.
Recent Tariff Filings
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current
regulatory activity.
19
10-KFORM 10-K |
FERC
The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of
electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction must
maintain tariffs and rate schedules on file with FERC that govern the rates, and terms and conditions for the provision of FERC-
jurisdictional wholesale power and transmission services. Public utilities are also subject to accounting, record-keeping and
reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and
their affiliates. Our electric utility subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.
Our Electric Utilities entities are authorized by FERC to make wholesale sales of electric capacity and energy at market-based
rates under tariffs on file with FERC. As a condition of their market-based rate authority, Electric Quarterly Reports are filed with
FERC. Our Electric Utilities own and operate FERC-jurisdictional interstate transmission facilities and provide open access
transmission service under tariffs on file with FERC. Our Electric Utilities are subject to routine audit by FERC with respect to
their compliance with FERC’s regulations.
PUHCA 2005 provides FERC authority with respect to the books and records of a utility holding company. As a utility holding
company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and also
a centralized service company subsidiary, BHSC, we are subject to FERC’s authority under PUHCA 2005.
PUHCA 2005 reiterated the definition and benefits of EWG status. Under PUHCA 2005, an EWG is an entity or generator
engaged, directly or indirectly through one or more affiliates, exclusively in the business of owning, operating or both owning and
operating all or part of one or more eligible facilities and selling electric energy at wholesale. Though EWGs are public utilities
within the definition set forth in the Federal Power Act and are subject to FERC regulation of rates and charges, they are exempt
from other FERC requirements. Through its subsidiaries, Black Hills Corporation is affiliated with two EWGs, Wygen I and
Pueblo Airport Generation (facilities #4-5). Both of these EWGs have been granted market-based rate authority.
NERC
The Energy Policy Act of 2005 included provisions to create an Electric Reliability Organization, which is required to promulgate
mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC certified NERC as the
Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect in 2007.
Entities that violate standards can be subject to fines and can also be assessed non-monetary penalties, depending upon the
nature and severity of the violation.
Pipeline Security
In May and July 2021, the TSA issued security directives in response to a ransomware attack on the Colonial Pipeline that
occurred earlier in 2021 that included several new cybersecurity requirements for critical pipeline owners and operators. Among
these requirements is the implementation of specific mitigation measures to protect against ransomware attacks and other
known threats to information and operational technology systems; development and implementation of a cybersecurity
contingency and recovery plan; and performance of a cybersecurity architecture design review. Compliance with these
measures has not had a material impact on our operations. We continue to evaluate the potential effect of these directives on
our operations and facilities and will continue to monitor for any clarifications or amendments to these directives.
Gas Pipeline and Storage Integrity and Safety
We are subject to regulation by PHMSA, which requires the following for certain gas distribution and transmission pipelines and
underground storage facilities: inspection and maintenance plans; integrity management programs, including the determination
of pipeline integrity risks and periodic assessments on certain pipeline segments; an operator qualification program, which
includes certain trainings; a public awareness program that provides certain information; and a control room management plan. If
we fail to comply with applicable statutes and the PHMSA Office of Pipeline Safety’s rules and related regulations and orders, we
could be subject to significant penalties and fines.
20
10-K| FORM 10-K FERC
Environmental Matters
We have clean energy goals to reduce GHG emissions that are based on prudent and proven solutions while minimizing cost
impacts to and ensuring safety of our customers. See more information in Key Elements of our Business Strategy within
Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on
Form 10-K.
We are subject to significant state and federal environmental regulations that encourage the use of clean energy technologies
and regulate emissions of GHGs. We have undertaken initiatives to meet current requirements and to prepare for anticipated
future regulations, reduce GHG emissions, and respond to state renewable and energy efficiency goals. Compliance with future
environmental regulations could result in substantial cost.
In July of 2019, the EPA adopted the Affordable Clean Energy rule, which requires states to develop plans by 2022 for GHG
reductions from coal-fired power plants. On May 23, 2023, the EPA proposed to repeal the Affordable Clean Energy rule and at
the same time issued a replacement rule to establish emissions limits for GHG emissions from existing coal-fired and oil/gas-
fired electric power generating boilers. The EPA also proposed GHG emission limits for existing stationary combustion turbines.
The proposed emissions limitations are based upon the application of carbon capture controls or the use of hydrogen fuel
beginning in 2030. The EPA is expected to issue a final rule in the first half of 2024. We will continue to monitor any related
guidelines and rulemakings issued by the EPA or state regulatory authorities.
In February 2022, the EPA proposed the Good Neighbor Rule Provisions, which are part of the CSAPR framework and is
intended to address ozone transport for the 2015 ozone NAAQS. The proposed rule included the state of Wyoming and imposed
a NOx emissions trading program on fossil fueled electricity generating plants within the state. The EPA’s consideration of
revised NOx emissions inventories and revised ozone modeling resulted in Wyoming’s exclusion from the final Good Neighbor
Rule published on June 5, 2023. In a subsequent action published on August 14, 2023, the EPA approved Wyoming’s State
Implementation Plan submission addressing interstate transport for the 2015 8-hour ozone NAAQS, and Wyoming sources will
not be subject to the CSAPR.
Environmental risk changes constantly with the implementation of new or modified regulations, changing stakeholder interests
and needs, and through the introduction of innovative work practices and technologies. We continually assess risk and develop
mitigation strategies to manage and ensure compliance across the enterprise successfully and responsibly. For additional
information on environmental matters, see Item 1A and Note 3 of the Notes to Consolidated Financial Statements in this Annual
Report on Form 10-K.
Human Capital Resources
Overview
We are committed to retaining, attracting and cultivating a talented, engaged and thriving team. By making our people and
culture a strategic priority, our employees are engaged and empowered to contribute to the success of our business.
The Federal Power Act gives FERC exclusive rate-making jurisdiction over wholesale sales of electricity and the transmission of
electricity in interstate commerce. Pursuant to the Federal Power Act, all public utilities subject to FERC’s jurisdiction must
maintain tariffs and rate schedules on file with FERC that govern the rates, and terms and conditions for the provision of FERC-
jurisdictional wholesale power and transmission services. Public utilities are also subject to accounting, record-keeping and
reporting requirements administered by FERC. FERC also places certain limitations on transactions between public utilities and
their affiliates. Our electric utility subsidiaries provide FERC-jurisdictional services subject to FERC’s oversight.
Our Electric Utilities entities are authorized by FERC to make wholesale sales of electric capacity and energy at market-based
rates under tariffs on file with FERC. As a condition of their market-based rate authority, Electric Quarterly Reports are filed with
FERC. Our Electric Utilities own and operate FERC-jurisdictional interstate transmission facilities and provide open access
transmission service under tariffs on file with FERC. Our Electric Utilities are subject to routine audit by FERC with respect to
their compliance with FERC’s regulations.
PUHCA 2005 provides FERC authority with respect to the books and records of a utility holding company. As a utility holding
company whose assets consist primarily of investments in our subsidiaries, including subsidiaries that are public utilities and also
a centralized service company subsidiary, BHSC, we are subject to FERC’s authority under PUHCA 2005.
PUHCA 2005 reiterated the definition and benefits of EWG status. Under PUHCA 2005, an EWG is an entity or generator
engaged, directly or indirectly through one or more affiliates, exclusively in the business of owning, operating or both owning and
operating all or part of one or more eligible facilities and selling electric energy at wholesale. Though EWGs are public utilities
within the definition set forth in the Federal Power Act and are subject to FERC regulation of rates and charges, they are exempt
from other FERC requirements. Through its subsidiaries, Black Hills Corporation is affiliated with two EWGs, Wygen I and
Pueblo Airport Generation (facilities #4-5). Both of these EWGs have been granted market-based rate authority.
The Energy Policy Act of 2005 included provisions to create an Electric Reliability Organization, which is required to promulgate
mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC certified NERC as the
Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect in 2007.
Entities that violate standards can be subject to fines and can also be assessed non-monetary penalties, depending upon the
NERC
nature and severity of the violation.
Pipeline Security
In May and July 2021, the TSA issued security directives in response to a ransomware attack on the Colonial Pipeline that
occurred earlier in 2021 that included several new cybersecurity requirements for critical pipeline owners and operators. Among
these requirements is the implementation of specific mitigation measures to protect against ransomware attacks and other
known threats to information and operational technology systems; development and implementation of a cybersecurity
contingency and recovery plan; and performance of a cybersecurity architecture design review. Compliance with these
measures has not had a material impact on our operations. We continue to evaluate the potential effect of these directives on
our operations and facilities and will continue to monitor for any clarifications or amendments to these directives.
Gas Pipeline and Storage Integrity and Safety
We are subject to regulation by PHMSA, which requires the following for certain gas distribution and transmission pipelines and
underground storage facilities: inspection and maintenance plans; integrity management programs, including the determination
of pipeline integrity risks and periodic assessments on certain pipeline segments; an operator qualification program, which
includes certain trainings; a public awareness program that provides certain information; and a control room management plan. If
we fail to comply with applicable statutes and the PHMSA Office of Pipeline Safety’s rules and related regulations and orders, we
could be subject to significant penalties and fines.
Our Team
Total employees
Women in executive leadership positions (a)
Gender diversity (women as a % of total employees)
Represented by a union
Military veterans
Ethnic diversity (non-white employees as a % of total)
As of December 31, 2023
2,874
29%
24%
25%
10%
15%
As of December 31, 2022
2,982
33%
25%
25%
11%
14%
For the year ended
December 31, 2023
293
27%
24%
12%
3%
For the year ended
December 31, 2022
487
30%
23%
13%
3%
Number of external hires
External hires gender diversity (as a % of total external hires)
External hires ethnic diversity (as a % of total external hires)
Turnover rate (b)
Retirement rate
____________________
(a)
(b)
Executive leadership positions are defined as positions with Vice President, Senior Vice President or Chief in their title.
Includes voluntary and involuntary separations but excludes internships.
21
10-KFORM 10-K |
Total Employees
Electric Utilities
Gas Utilities
Corporate and Other
Total
Number of Employees
As of December 31, 2023
425
1,198
1,251
2,874
At December 31, 2023, approximately 18% of our total employees and 20% of our Electric and Gas Utilities employees were
eligible for retirement (age 55 with at least 5 years of service).
Collective Bargaining Agreements
At December 31, 2023, certain employees of our Electric Utilities and Gas Utilities were covered by the collective bargaining
agreements as shown in the table below. We have not experienced any labor stoppages in decades.
Utility
Colorado Electric
South Dakota Electric
Wyoming Electric
Total Electric Utilities
Iowa Gas
Kansas Gas
Nebraska Gas
Nebraska Gas
Wyoming Gas
Wyoming Gas
Total Gas Utilities
Total
Diversity, Equity & Inclusion
Number of
Employees
108
122
29
259
129
15
92
134
16
80
466
725
Union Affiliation
IBEW Local 667
IBEW Local 1250
IBEW Local 111
Expiration Date of Collective
Bargaining Agreement
April 15, 2027
March 31, 2027
June 30, 2024
IBEW Local 204
Communications Workers of
America, AFL-CIO Local 6407
IBEW Local 244
CWA Local 7476
IBEW Local 111
CWA Local 7476
January 31, 2026
December 31, 2024
March 13, 2025
October 30, 2026
June 30, 2024
October 30, 2026
We believe the benefits of diversity, equity and inclusion can be powerful, and we are committed to building a workforce whose
diversity is representative of the communities we serve. Our recruiting strategies support our efforts to attract qualified
individuals with targeted efforts to reach underrepresented talent. Our internship program and our partnerships and participation
in outreach programs with local schools and colleges attract students to careers in the energy industry. Our commitment to
equitable and inclusive hiring practices, including diverse candidate slates and interview panels and pay equity reviews, further
supports our vision of retaining, attracting and cultivating an engaged and thriving team driven by improving life with energy. We
continuously evaluate our recruitment strategies to determine their effectiveness to attract and build a talented, diverse
workforce. Workforce diversity trends, which include new hires, promotions and turnover, are monitored at regular intervals
throughout the year.
Development and Retention
Developing and retaining talent is critical to our continued success. Our development and retention efforts include internal and
external skills training, career development programs, and competitive compensation. Our compensation programs are designed
to be strategically aligned, externally competitive, internally equitable, personally motivating, cost effective and legally compliant.
We monitor employee engagement through bi-annual engagement surveys and quarterly pulse surveys. Every leader is
responsible for creating and implementing an action plan based on their team’s engagement survey results. Our career
development programs include management onboarding, leadership development programs, mentoring programs, individual
development assessments, stretch opportunities, talent sharing and more. Internal training opportunities include corporate-wide
and specialized training opportunities for different job functions. Our Field Career Path Program (FCPP) promotes career growth
for our frontline customer-facing employees through established standards of knowledge, skills, abilities and performance.
22
10-K| FORM 10-K
Total Employees
Electric Utilities
Gas Utilities
Corporate and Other
Total
Number of Employees
As of December 31, 2023
425
1,198
1,251
2,874
Employee Safety and Wellness
Safety is one of our company values, a top priority in all we do and deeply embedded in our culture. Meetings of three or more
employees begin with a safety share, a practice which contributes to keeping safety top of mind. Since 2009, we have reduced
workplace injuries by more than 64% and continue to see long-term, sustained improvements in our safety practices and
performance.
Total Case Incident Rate (incidents per 200,000 hours worked)
Preventable Motor Vehicle Incident Rate (vehicle accidents per 1 million miles driven)
Proactive Safety Activities per Employee
% of injuries reported within 1 day
For the year ended
December 31, 2023
1.51
1.65
4
93.3%
At December 31, 2023, certain employees of our Electric Utilities and Gas Utilities were covered by the collective bargaining
agreements as shown in the table below. We have not experienced any labor stoppages in decades.
ITEM 1A. RISK FACTORS
The nature of our business subjects us to a number of uncertainties and risks. Risks that may adversely affect our business
operations, financial condition, results of operations or cash flows are described below. These risk factors, along with other risk
factors that we discuss in our periodic reports filed with the SEC should be considered for a better understanding of our
Company.
STRATEGIC RISK
Our continued success is dependent on execution of our business plan and growth strategy, including our capital
investment program.
Our continued success depends, in significant part, on our ability to execute our strategic business plans. Our strategy is
centered on four critical priorities: Growth—to grow strategically and achieve strong financial performance, Operational
Excellence—delivering safe, reliable and cost-effective energy to meet our customers’ needs, Transformation—be a simple and
connected company positioned for growth, and People & Culture—retain and attract a talented, engaged and thriving team. Our
current plans and strategy may be negatively impacted by disruptive forces and innovations in the marketplace, workforce
capabilities, changing political, business or regulatory conditions and technology advancements.
In addition, we have significant capital investment programs planned for the next five years that are key to our strategic business
plans. The successful execution of our capital investment program depends on, or could be affected by, a variety of factors that
include, but are not limited to: access to capital to fund projects, weather conditions, effective management of projects,
availability of qualified construction personnel including contractors, changes in commodity and other prices, impacts of supply
chain disruptions on availability and cost of materials, governmental approvals and permitting, regulatory cost recovery and
return on investment.
An inability to successfully and timely adapt to changing conditions and execute our strategic plans could materially affect our
financial operating results including earnings, cash flow and liquidity.
REGULATORY, LEGISLATIVE AND LEGAL RISKS
We may be subject to unfavorable or untimely federal and state regulatory outcomes.
Our regulated Utilities are subject to cost-of-service/rate-of-return regulation and earnings oversight from federal and eight state
utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our
customer rates are regulated based on an analysis of our costs and investments, as reviewed and approved in regulatory
proceedings. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on
invested capital, there can be no assurance that our various regulatory authorities will judge all of our costs to have been
prudently incurred or that the regulatory process in which rates are determined will result in full or timely recovery of our costs
with a reasonable return on invested capital. In addition, adverse rate decisions, including rate moratoriums, rate refunds, limits
on rate increases, lower allowed returns on investments or rate reductions, could be influenced by competitive, economic,
political, legislative, public perception and regulatory pressures and adversely impact earnings, cash flow and liquidity.
Each of our Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs, including costs
from certain severe weather events, or integrity capital investments) outside of a base rate review in order to stabilize customer
rates and reduce regulatory lag. If regulators decide to discontinue these tariff-based recovery mechanisms, it could negatively
impact earnings, cash flow and liquidity.
23
At December 31, 2023, approximately 18% of our total employees and 20% of our Electric and Gas Utilities employees were
eligible for retirement (age 55 with at least 5 years of service).
Collective Bargaining Agreements
Number of
Employees
Union Affiliation
IBEW Local 667
IBEW Local 1250
IBEW Local 111
Expiration Date of Collective
Bargaining Agreement
April 15, 2027
March 31, 2027
June 30, 2024
IBEW Local 204
Communications Workers of
America, AFL-CIO Local 6407
IBEW Local 244
CWA Local 7476
IBEW Local 111
CWA Local 7476
January 31, 2026
December 31, 2024
March 13, 2025
October 30, 2026
June 30, 2024
October 30, 2026
Utility
Colorado Electric
South Dakota Electric
Wyoming Electric
Total Electric Utilities
Iowa Gas
Kansas Gas
Nebraska Gas
Nebraska Gas
Wyoming Gas
Wyoming Gas
Total Gas Utilities
Total
Diversity, Equity & Inclusion
108
122
29
259
129
15
92
16
80
134
466
725
We believe the benefits of diversity, equity and inclusion can be powerful, and we are committed to building a workforce whose
diversity is representative of the communities we serve. Our recruiting strategies support our efforts to attract qualified
individuals with targeted efforts to reach underrepresented talent. Our internship program and our partnerships and participation
in outreach programs with local schools and colleges attract students to careers in the energy industry. Our commitment to
equitable and inclusive hiring practices, including diverse candidate slates and interview panels and pay equity reviews, further
supports our vision of retaining, attracting and cultivating an engaged and thriving team driven by improving life with energy. We
continuously evaluate our recruitment strategies to determine their effectiveness to attract and build a talented, diverse
workforce. Workforce diversity trends, which include new hires, promotions and turnover, are monitored at regular intervals
throughout the year.
Development and Retention
Developing and retaining talent is critical to our continued success. Our development and retention efforts include internal and
external skills training, career development programs, and competitive compensation. Our compensation programs are designed
to be strategically aligned, externally competitive, internally equitable, personally motivating, cost effective and legally compliant.
We monitor employee engagement through bi-annual engagement surveys and quarterly pulse surveys. Every leader is
responsible for creating and implementing an action plan based on their team’s engagement survey results. Our career
development programs include management onboarding, leadership development programs, mentoring programs, individual
development assessments, stretch opportunities, talent sharing and more. Internal training opportunities include corporate-wide
and specialized training opportunities for different job functions. Our Field Career Path Program (FCPP) promotes career growth
for our frontline customer-facing employees through established standards of knowledge, skills, abilities and performance.
10-KFORM 10-K |
Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws,
regulations or requirements including those associated with climate change.
Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and
future operations, including air emissions (i.e., SO2, NOx, volatile organic compounds, particulate matter and GHG), water
quality, wastewater discharges, solid waste and hazardous waste.
These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally
require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections and
other government approvals. Compliance with environmental laws and regulations may require significant expenditures,
including expenditures for cleanup costs and damages arising from contaminated properties. Failure or inability to comply with
evolving environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating
assets.
Our business segments may not be successful in recovering increased capital and operating costs incurred to comply with new
environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental
laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities.
There is significant uncertainty regarding if and when new climate legislation, regulations or administrative policies will be
adopted to reduce or limit GHG and the impact any such regulations would have on us. New or more stringent regulations or
other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the
installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional
emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the
closure or capacity reductions of coal-fired power generation facilities or conversion to alternative fuels, and potential increased
production from our combined cycle natural gas-fired generating units. Additional rules and regulations associated with fossil
fuels and GHG emissions could result in the impairment or retirement of some of our existing or future transmission, distribution,
generation and natural gas storage facilities or our coal mine. Further, these rules could create the need to purchase or build
clean-energy fuel sources to fulfill obligations to our customers. These actions could also result in increased operating costs
which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity. We
cannot definitively estimate the effect of GHG legislation or regulation on our earnings, cash flow and liquidity.
Legislative and regulatory requirements may result in compliance penalties.
Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Many agencies
employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, PHMSA, CFTC, EPA, OSHA, SEC, TSA
and MSHA may impose significant civil and criminal penalties to enforce compliance requirements relative to our business,
which could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.
Municipal governments may seek to limit or deny our franchise privileges.
Municipal governments within our utility service territories possess the power of condemnation and could establish a municipal
utility within a portion of our current service territories by limiting or denying franchise privileges for our operations and exercising
powers of condemnation over all or part of our utility assets within municipal boundaries. We regularly engage in negotiations on
renewals of franchise agreements with our municipal governments. We have from time to time faced challenges or ballot
initiatives on franchise renewals. To date, we have been successful in resolving or defending most of these challenges. Although
condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial
procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would
secure adequate recovery of our investment in assets subject to condemnation. We also cannot quantify the impact that such
action would have on the remainder of our business operations.
Changes in Federal tax law may significantly impact our business.
We are subject to taxation by the various taxing authorities at the federal, state and local levels where we operate. Sweeping
legislation or regulation could be enacted by any of these governmental authorities which may affect our tax burden. Changes
may include numerous provisions that affect businesses, including changes to corporate tax rates, business-related exclusions,
and deductions and credits. The outcome of regulatory proceedings regarding the extent to which a change in corporate tax rate
will affect our utility customers and the time period over which that change will occur could significantly impact future earnings
and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations,
decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other
tax-related assumptions may cause actual financial results to deviate from previous estimates.
24
10-K| FORM 10-K Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws,
regulations or requirements including those associated with climate change.
Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and
future operations, including air emissions (i.e., SO2, NOx, volatile organic compounds, particulate matter and GHG), water
quality, wastewater discharges, solid waste and hazardous waste.
These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally
require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections and
other government approvals. Compliance with environmental laws and regulations may require significant expenditures,
including expenditures for cleanup costs and damages arising from contaminated properties. Failure or inability to comply with
evolving environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating
assets.
Our business segments may not be successful in recovering increased capital and operating costs incurred to comply with new
environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental
laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities.
There is significant uncertainty regarding if and when new climate legislation, regulations or administrative policies will be
adopted to reduce or limit GHG and the impact any such regulations would have on us. New or more stringent regulations or
other energy efficiency requirements could require us to incur significant additional costs relating to, among other things, the
installation of additional emission control equipment, the acceleration of capital expenditures, the purchase of additional
emissions allowances or offsets, the acquisition or development of additional energy supply from renewable resources, the
closure or capacity reductions of coal-fired power generation facilities or conversion to alternative fuels, and potential increased
production from our combined cycle natural gas-fired generating units. Additional rules and regulations associated with fossil
fuels and GHG emissions could result in the impairment or retirement of some of our existing or future transmission, distribution,
generation and natural gas storage facilities or our coal mine. Further, these rules could create the need to purchase or build
clean-energy fuel sources to fulfill obligations to our customers. These actions could also result in increased operating costs
which could adversely impact customers and our financial operating results including earnings, cash flow and liquidity. We
cannot definitively estimate the effect of GHG legislation or regulation on our earnings, cash flow and liquidity.
Legislative and regulatory requirements may result in compliance penalties.
Business activities in the energy sector are heavily regulated, primarily by agencies of the federal government. Many agencies
employ mandatory civil penalty structures for regulatory violations. The FERC, NERC, PHMSA, CFTC, EPA, OSHA, SEC, TSA
and MSHA may impose significant civil and criminal penalties to enforce compliance requirements relative to our business,
which could have a material adverse effect on our financial operating results including earnings, cash flow and liquidity.
Municipal governments may seek to limit or deny our franchise privileges.
Municipal governments within our utility service territories possess the power of condemnation and could establish a municipal
utility within a portion of our current service territories by limiting or denying franchise privileges for our operations and exercising
powers of condemnation over all or part of our utility assets within municipal boundaries. We regularly engage in negotiations on
renewals of franchise agreements with our municipal governments. We have from time to time faced challenges or ballot
initiatives on franchise renewals. To date, we have been successful in resolving or defending most of these challenges. Although
condemnation is a process that is subject to constitutional protections requiring just and fair compensation, as with any judicial
procedure, the outcome is uncertain. If a municipality sought to pursue this course of action, we cannot assure that we would
secure adequate recovery of our investment in assets subject to condemnation. We also cannot quantify the impact that such
action would have on the remainder of our business operations.
Changes in Federal tax law may significantly impact our business.
We are subject to taxation by the various taxing authorities at the federal, state and local levels where we operate. Sweeping
legislation or regulation could be enacted by any of these governmental authorities which may affect our tax burden. Changes
may include numerous provisions that affect businesses, including changes to corporate tax rates, business-related exclusions,
and deductions and credits. The outcome of regulatory proceedings regarding the extent to which a change in corporate tax rate
will affect our utility customers and the time period over which that change will occur could significantly impact future earnings
and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations,
decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other
tax-related assumptions may cause actual financial results to deviate from previous estimates.
OPERATING RISKS
Failure to attract and retain an appropriately qualified workforce could have a negative impact on our operations and
long-term business strategy.
Recent trends, such as a competitive and tight labor market and an aging workforce may lead to higher costs and increased risk
of negative outcomes for safety, compliance, customer service, and operations. Our ability to transition and replace our
retirement-eligible utility employees is a risk; at December 31, 2023, approximately 18% of our employees were eligible for
retirement. Our ability to avoid or minimize work stoppages and labor disputes is also a risk with approximately 25% of our
employees represented by unions. Failure to hire and retain qualified employees, including the ability to transfer significant
internal historical knowledge and expertise to new employees, may adversely affect our ability to manage and operate our
business. If we are unable to successfully attract and retain an appropriately qualified workforce and maintain satisfactory
collective bargaining agreements, safety, service reliability, customer satisfaction and our results of operations could be
adversely affected. As part of our strategic business plans, we will need to attract and retain personnel who are qualified to
implement our strategy and may need to retrain or re-skill certain employees to support our long-term objectives.
Supply chain challenges could negatively impact our operations.
We rely on various suppliers in our supply chain for the materials necessary to execute on our capital investment program that is
key to our strategic business plans and to respond to a significant unplanned event such as a natural disaster. Our largest
customers also rely on our supply chain and delays in critical materials could impact their ability to operate and grow as planned.
Our supply chain, material costs, and capital investment program may be negatively impacted by:
•
•
Unanticipated price increases due to recent macroeconomic factors, such as inflation, including wage inflation, or
rising demand for raw materials associated with the Energy Transition; and
Supply restrictions beyond our control or the control of our suppliers such as disruption of the freight system (e.g.
labor union strikes), increased environmental threats from weather-related disasters, rising demand for raw
materials associated with the Energy Transition and/or geopolitical unrest (e.g. Russia-Ukraine and Middle East
conflicts).
An inability to successfully manage challenges in our supply chain network could materially affect our ability to execute our
business plan and growth strategy and our financial operating results including earnings, cash flow and liquidity.
Our financial performance depends on the successful operation of electric generating facilities, electric and natural gas
transmission and distribution systems, natural gas storage facilities and a coal mine.
The risks associated with managing these operations include:
•
•
•
•
•
•
•
Operating hazards. Operating hazards such as leaks, mechanical problems and accidents, including fires or
explosions, could impact employee and public safety, reliability and customer confidence;
Inherent dangers. Electricity and natural gas can be dangerous to employees and the general public. Failures of or
contact with power lines, natural gas pipelines or service facilities and equipment may result in fires, explosions,
property damage and personal injuries, including death. While we maintain liability and property insurance coverage,
such policies are subject to certain limits and deductibles. The occurrence of any of these events may not be fully
covered by our insurance;
Weather, natural conditions and disasters including impacts from climate change (discussed below);
Acts of sabotage, terrorism or other malicious physical attacks. Damage to our facilities due to deliberate acts could
lead to outages or other adverse effects;
Equipment and processes. Breakdown or failure of equipment or processes, unavailability or increased cost of
equipment, and performance below expected levels of output or efficiency could negatively impact our results of
operations;
Disrupted transmission and distribution. We depend on transmission and distribution facilities, including those
operated by unaffiliated parties, to deliver the electricity and natural gas that we sell to our retail and wholesale
customers. If transmission is interrupted physically, mechanically or with cyber means, our ability to sell or deliver
utility services and satisfy our contractual obligations may be hindered;
Natural gas supply for generation and distribution. Our regulated Utilities and non-regulated entities purchase
natural gas from a number of suppliers for our generating facilities and for distribution to our customers. Our results
of operations could be negatively impacted by the lack of availability and cost of natural gas, and disruptions in the
delivery of natural gas due to various factors, including but not limited to, transportation delays, labor relations,
weather, sabotage, cyber-attacks and environmental regulations;
25
10-KFORM 10-K | •
•
•
•
•
•
•
Replacement power. The cost of supplying or securing replacement power during scheduled and unscheduled
outages of generation facilities could negatively impact our results of operations;
Governmental permits. The inability to obtain required governmental permits and approvals along with the cost of
complying with or satisfying conditions imposed upon such approvals could negatively impact our ability to operate
and our results of operations;
Operational limitations. Operational limitations imposed by environmental and other regulatory requirements and
contractual agreements, including those that restrict the timing of generation plant scheduled outages, could
negatively impact our results of operations;
Increased costs. Increased capital and operating costs to comply with increasingly stringent laws and regulations,
unexpected engineering, environmental and geological problems, and unanticipated cost overruns could negatively
impact our results of operations;
Supply chain challenges (discussed above);
Workforce capabilities and labor relations (discussed above); and
Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to
operate our businesses.
Any of these risks described above could damage our reputation and public confidence. These risks could also cause us to incur
significant costs or be unable to deliver energy and/or operate below expected capacity levels, which in turn could reduce
revenues or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance, obtain
warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our
rights under contracts, warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased
expenses, liability or liquidated damage payments.
The nature of our business subjects us to climate-related risk, stemming from both physical risk and transition risk of
climate change, over varying time horizons.
Physical risks of climate change refer to risks to our facilities or operations that may result from changes in the physical climate,
such as changes to temperature and weather patterns. Our utility businesses are seasonal businesses and weather conditions
and patterns can have a material impact on our operating results. To the extent weather conditions are affected by climate
change, fluctuations in commodity prices and customers’ energy usage could be magnified. Climate change may lead to
increased intensity and frequency of storms, resulting in increased likelihood of fire, wind and extreme temperature events.
Severe weather events, such as snow and ice storms (e.g., Winter Storm Uri), fire, and strong winds could negatively impact our
operations, including our ability to provide energy safely, reliably and profitably and our ability to complete construction,
expansion or refurbishment of facilities as planned. Climate change may intensify these events or increase the frequency of their
occurrence. Over time, we may need to make additional investments to protect our facilities from physical risks of climate
change.
Transition risks of climate change include changes to the energy systems as a result of new technologies, changing customer
demand and/or expectations and voluntary GHG reduction goals, as well as local, state or federal regulatory requirements
(discussed above). Policies such as a carbon or methane tax could increase costs associated with fossil fuel usage, resulting in
higher operating costs including costs of energy generation, construction, and transportation. Risks of the transition to a low-
carbon economy could result in shrinking customer demand for fossil fuel-based energy sources. This could come from
increased use of behind the meter technology, such as residential solar and storage. Risk of investor pressure over climate risk
and/or ESG standards, activist campaigns against coal producers, employee preferences to work for companies with certain
sustainability goals and consumers preference for renewable energy could impact our reputation, ability to attract and retain an
appropriately trained workforce, and overall access to capital and/or adequate insurance policies.
26
10-K| FORM 10-K •
•
•
•
•
•
•
Governmental permits. The inability to obtain required governmental permits and approvals along with the cost of
complying with or satisfying conditions imposed upon such approvals could negatively impact our ability to operate
and our results of operations;
Operational limitations. Operational limitations imposed by environmental and other regulatory requirements and
contractual agreements, including those that restrict the timing of generation plant scheduled outages, could
negatively impact our results of operations;
Increased costs. Increased capital and operating costs to comply with increasingly stringent laws and regulations,
unexpected engineering, environmental and geological problems, and unanticipated cost overruns could negatively
impact our results of operations;
Supply chain challenges (discussed above);
Workforce capabilities and labor relations (discussed above); and
Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to
operate our businesses.
Any of these risks described above could damage our reputation and public confidence. These risks could also cause us to incur
significant costs or be unable to deliver energy and/or operate below expected capacity levels, which in turn could reduce
revenues or cause us to incur higher operating and maintenance costs and penalties. While we maintain insurance, obtain
warranties from vendors and obligate contractors to meet certain performance levels, the proceeds of such insurance and our
rights under contracts, warranties or performance guarantees may not be timely or adequate to cover lost revenues, increased
expenses, liability or liquidated damage payments.
The nature of our business subjects us to climate-related risk, stemming from both physical risk and transition risk of
climate change, over varying time horizons.
Physical risks of climate change refer to risks to our facilities or operations that may result from changes in the physical climate,
such as changes to temperature and weather patterns. Our utility businesses are seasonal businesses and weather conditions
and patterns can have a material impact on our operating results. To the extent weather conditions are affected by climate
change, fluctuations in commodity prices and customers’ energy usage could be magnified. Climate change may lead to
increased intensity and frequency of storms, resulting in increased likelihood of fire, wind and extreme temperature events.
Severe weather events, such as snow and ice storms (e.g., Winter Storm Uri), fire, and strong winds could negatively impact our
operations, including our ability to provide energy safely, reliably and profitably and our ability to complete construction,
expansion or refurbishment of facilities as planned. Climate change may intensify these events or increase the frequency of their
occurrence. Over time, we may need to make additional investments to protect our facilities from physical risks of climate
change.
Transition risks of climate change include changes to the energy systems as a result of new technologies, changing customer
demand and/or expectations and voluntary GHG reduction goals, as well as local, state or federal regulatory requirements
(discussed above). Policies such as a carbon or methane tax could increase costs associated with fossil fuel usage, resulting in
higher operating costs including costs of energy generation, construction, and transportation. Risks of the transition to a low-
carbon economy could result in shrinking customer demand for fossil fuel-based energy sources. This could come from
increased use of behind the meter technology, such as residential solar and storage. Risk of investor pressure over climate risk
and/or ESG standards, activist campaigns against coal producers, employee preferences to work for companies with certain
sustainability goals and consumers preference for renewable energy could impact our reputation, ability to attract and retain an
appropriately trained workforce, and overall access to capital and/or adequate insurance policies.
Replacement power. The cost of supplying or securing replacement power during scheduled and unscheduled
outages of generation facilities could negatively impact our results of operations;
Cybersecurity incidents, terrorism, or other malicious acts targeting our key technology systems could disrupt our
operations or lead to a loss or misuse of confidential and proprietary information.
To effectively operate our business, we rely upon a sophisticated electronic control system, information and operation
technology systems and network infrastructure to generate, distribute and deliver energy, and collect and retain sensitive
information including personal information about our customers and employees. Cybersecurity incidents, terrorism or other
malicious acts targeting electronic control systems could result in a full or partial disruption of our electric and/or natural gas
operations. Attacks targeting other key technology systems, including our third-party vendors’ information systems, could further
add to a full or partial disruption of our operations. The utility industry has been the target of several cyberattacks on operational
systems and has seen an increased volume and sophistication of cybersecurity incidents from international activist
organizations, other nation state actors and individuals. To date, we have not experienced a cybersecurity incident that has had
a material impact on our business or results of operations. Any disruption of our electric and/or natural gas operations could
result in a loss of service to customers and associated revenues, as well as significant expense to repair damages and remedy
security breaches. In addition, any theft, loss and/or fraudulent use of customer, shareowner, employee or proprietary data could
subject us to significant litigation, liability and costs, as well as adversely impact our reputation with customers and regulators,
among others. We maintain cyber risk insurance to mitigate a portion, but not all, of these risks and losses.
As discussed in Utility Regulation Characteristics above, in 2021 the TSA issued security directives that included several new
cybersecurity requirements for critical pipeline owners and operators. Such directives or other requirements may require
expenditure of significant additional resources to respond to cybersecurity incidents, to continue to modify or enhance protective
measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. Any failure to comply with
such government regulations or failure in our cybersecurity protective measures may result in enforcement actions that may
have a material adverse effect on our business, results of operations and financial condition. In addition, there is no certainty that
costs incurred related to securing against threats will be recovered through rates.
As discussed in Item 1C in this Annual Report on Form 10-K, we have instituted security measures and safeguards to protect
our operational systems and information technology assets against cybersecurity threats, including certain safeguards required
by NERC. Despite our implementation of security measures and safeguards, all of our technology systems may still be
vulnerable to disability, failures or unauthorized access.
Our operations are subject to various conditions that can result in fluctuations in customer usage, including customer
growth and general economic conditions in our service territories, weather conditions, and responses to price
increases and technological improvements.
Our results of operations and cash flows are affected by the demand for electricity and natural gas, which can vary greatly based
upon:
•
•
Fluctuations in customer growth and general economic conditions in our service territories. Customer growth and
energy use can be negatively impacted by population declines as well as adverse economic factors in our service
territories, including recession, inflation, workforce reductions, stagnant wage growth, changing levels of support
from state and local government for economic development, business closings, and reductions in the level of
business investment. Our Utilities are impacted by economic cycles and the competitiveness of the commercial and
industrial customers we serve. Any economic downturn, inflation, disruption of financial markets, or reduced
incentives by state government for economic development could adversely affect the financial condition of our
customers and demand for their products or services. These risks could directly influence the demand for electricity
and natural gas as well as the need for additional power generation and generating facilities. We could also be
exposed to greater risks of accounts receivable write-offs if customers are unable to pay their bills.
Weather conditions. Our Utilities are seasonal businesses and weather conditions and patterns can have a material
impact on our operating performance. Demand for electricity is typically greater in the summer and winter months
associated with cooling and heating, respectively. Demand for natural gas depends heavily upon winter-weather
patterns throughout our service territory and a significant amount of natural gas revenues are recognized in the first
and fourth quarters related to the heating season. Accordingly, our Utilities have historically generated lower
revenues, income and cash flows when weather conditions are cooler than normal in the summer and warmer than
normal in the winter. Demand for natural gas is also impacted by summer weather patterns that are cooler than
normal and provide higher than normal precipitation; both of which can reduce natural gas demand for irrigation.
Unusually mild summers and winters, therefore, could have an adverse effect on our financial operating results,
including earnings, cash flow and liquidity.
27
10-KFORM 10-K | •
Our customers' focus on energy conservation. Customer growth and usage may be impacted by the voluntary
reduction in consumption of electricity and natural gas by our customers in response to increases in prices and
energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas,
economic conditions (i.e., inflation, recession) impacting customers’ disposable income and the use of distributed
generation resources or other emerging technologies. Continued technological improvements may make customer
and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines,
solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own
generation, demand for energy from us could decline. Such developments could affect the price and/or delivery of
energy, require further improvements to our distribution systems to address changing load demands and could
make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the
end of their useful lives.
Each of these factors described above could materially affect demand for electricity and natural gas which would impact our
financial operating results including earnings, cash flow and liquidity.
If macroeconomic or other conditions adversely affect operations or require us to make changes to our strategic
business plan, we may be forced to record a non-cash goodwill impairment charge.
We had approximately $1.3 billion of goodwill on our consolidated balance sheets as of December 31, 2023. If we make
changes in our strategic business plan and growth strategy, or if macroeconomic or other conditions adversely affect operations
in any of our businesses, we may be required to record a non-cash impairment charge. Goodwill is tested for impairment
annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed
indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying
value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for
impairment requires us to make significant estimates about our future performance and cash flows, as well as other
assumptions. These estimates can be affected by numerous factors, including: future business operating performance, changes
in macroeconomic conditions including recession, inflation and interest rates, changes in our regulatory environment, industry-
specific market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in
key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could
affect the fair value of either or both of our operating segments, which may result in an impairment charge. See additional
information in “Critical Accounting Estimates” under Item 7, Management’s Discussion and Analysis of Financial Condition and
Results of Operations and Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
FINANCIAL RISKS
A sub-investment grade credit rating could impact our ability to access capital markets.
Our senior unsecured debt rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Negative
outlook) by Fitch. Reduction of our investment grade credit ratings could impair our ability to refinance or repay our existing debt
and complete new financings on reasonable terms. A credit rating downgrade, particularly to sub-investment grade, could also
result in counterparties requiring us to post additional collateral under existing or new contracts. In addition, a ratings downgrade
would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities,
potentially significantly increasing our cost of capital and other associated operating costs which may not be recoverable through
existing regulatory rate structures and contracts with customers.
We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures
or otherwise execute our operating strategy.
Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our
liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt, pay dividends and
fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of
debt and equity offerings and proceeds from asset sales. Our ability to access capital markets and the costs and terms of
available financing depend on many factors, including changes in our credit ratings, general macroeconomic conditions which
may drive changes in interest rates and cause volatility in our stock price, changes in the federal or state regulatory environment
affecting energy companies and volatility in commodity prices.
In addition, because we are a holding company and our utility assets are owned by our subsidiaries, if we are unable to
adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility
subsidiaries are adequately capitalized to provide safe and reliable service. Possible additional measures would be evaluated in
the context of then-prevailing market conditions, prudent financial management and any applicable regulatory requirements.
28
10-K| FORM 10-K •
Our customers' focus on energy conservation. Customer growth and usage may be impacted by the voluntary
Costs associated with our healthcare plans and other benefits could increase significantly.
reduction in consumption of electricity and natural gas by our customers in response to increases in prices and
energy efficiency programs, electrification initiatives that could negatively impact the demand for natural gas,
economic conditions (i.e., inflation, recession) impacting customers’ disposable income and the use of distributed
generation resources or other emerging technologies. Continued technological improvements may make customer
and third-party distributed generation and energy storage systems, including fuel cells, micro-turbines, wind turbines,
solar cells and batteries, more cost effective and feasible for our customers. If more customers utilize their own
generation, demand for energy from us could decline. Such developments could affect the price and/or delivery of
energy, require further improvements to our distribution systems to address changing load demands and could
make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the
end of their useful lives.
The costs of providing healthcare benefits to our employees and retirees have increased substantially in recent years. We
believe that our employee benefit costs, including costs related to healthcare plans for our employees and former employees,
will continue to rise. Significant regulatory developments have required, and likely will continue to require, changes to our current
employee benefit plans and supporting administrative processes. Our electric and natural gas utility rates are regulated on a
state-by-state basis by the relevant state regulatory authorities based on an analysis of our costs, as reviewed and approved in a
regulatory proceeding. Within our utility rates, we have generally recovered the cost of providing employee benefits. As benefit
costs continue to rise, however, there is no assurance that the utility commissions will allow recovery of these increased costs.
The rising employee benefit costs, or inadequate recovery of such costs, may adversely affect our financial operating results
including earnings, cash flow, and liquidity.
Each of these factors described above could materially affect demand for electricity and natural gas which would impact our
financial operating results including earnings, cash flow and liquidity.
We may be unable to obtain insurance coverage, and the coverage we currently have may not apply or may be
insufficient to cover a significant loss.
If macroeconomic or other conditions adversely affect operations or require us to make changes to our strategic
business plan, we may be forced to record a non-cash goodwill impairment charge.
We had approximately $1.3 billion of goodwill on our consolidated balance sheets as of December 31, 2023. If we make
changes in our strategic business plan and growth strategy, or if macroeconomic or other conditions adversely affect operations
in any of our businesses, we may be required to record a non-cash impairment charge. Goodwill is tested for impairment
annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed
indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying
value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for
impairment requires us to make significant estimates about our future performance and cash flows, as well as other
assumptions. These estimates can be affected by numerous factors, including: future business operating performance, changes
in macroeconomic conditions including recession, inflation and interest rates, changes in our regulatory environment, industry-
specific market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in
key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could
affect the fair value of either or both of our operating segments, which may result in an impairment charge. See additional
information in “Critical Accounting Estimates” under Item 7, Management’s Discussion and Analysis of Financial Condition and
Results of Operations and Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
FINANCIAL RISKS
A sub-investment grade credit rating could impact our ability to access capital markets.
Our senior unsecured debt rating is Baa2 (Stable outlook) by Moody’s; BBB+ (Stable outlook) by S&P; and BBB+ (Negative
outlook) by Fitch. Reduction of our investment grade credit ratings could impair our ability to refinance or repay our existing debt
and complete new financings on reasonable terms. A credit rating downgrade, particularly to sub-investment grade, could also
result in counterparties requiring us to post additional collateral under existing or new contracts. In addition, a ratings downgrade
would increase our interest expense under some of our existing debt obligations, including borrowings under our credit facilities,
potentially significantly increasing our cost of capital and other associated operating costs which may not be recoverable through
existing regulatory rate structures and contracts with customers.
We may be unable to obtain financing on reasonable terms needed to refinance debt, fund planned capital expenditures
or otherwise execute our operating strategy.
Our ability to execute our operating strategy is highly dependent upon our access to capital. Historically, we have addressed our
liquidity needs (including funds required to make scheduled principal and interest payments, refinance debt, pay dividends and
fund working capital and planned capital expenditures) with operating cash flow, borrowings under credit facilities, proceeds of
debt and equity offerings and proceeds from asset sales. Our ability to access capital markets and the costs and terms of
available financing depend on many factors, including changes in our credit ratings, general macroeconomic conditions which
may drive changes in interest rates and cause volatility in our stock price, changes in the federal or state regulatory environment
affecting energy companies and volatility in commodity prices.
In addition, because we are a holding company and our utility assets are owned by our subsidiaries, if we are unable to
adequately access the credit markets, we could be required to take additional measures designed to ensure that our utility
subsidiaries are adequately capitalized to provide safe and reliable service. Possible additional measures would be evaluated in
the context of then-prevailing market conditions, prudent financial management and any applicable regulatory requirements.
Our ability to obtain insurance, as well as the cost of such insurance, could be impacted by developments affecting the insurance
industry and the financial condition of insurers. Additionally, insurance providers could deny coverage or decline to extend
coverage under the same or similar terms that are presently available to us. A loss for which we are not adequately insured
could materially affect our financial results. The coverage we currently have in place may not apply to a particular loss, or it may
not be sufficient to cover all liabilities to which we may be subject, including liability and losses associated with wildfires, natural
gas and storage field explosions, cyber-security breaches, environmental hazards and natural disasters.
We have a holding company corporate structure with multiple subsidiaries. Corporate dividends and debt payments
are dependent upon cash distributions to the holding company from the subsidiaries.
As a holding company, our investments in our subsidiaries are our primary assets. Our operating cash flow and ability to service
our indebtedness depend on the operating cash flow of our subsidiaries and the payment of funds by them to us in the form of
dividends or advances. Our subsidiaries are separate legal entities that have no obligation to make any funds available for that
purpose, whether by dividends or otherwise. In addition, each subsidiary’s ability to pay dividends to us depends on any
applicable contractual or regulatory restrictions that may include requirements to maintain minimum levels of cash, working
capital, equity or debt service funds.
There is no assurance as to the amount, if any, of future dividends to the holding company because these subsidiaries depend
on future earnings, capital requirements and financial conditions to fund such dividends. See “Liquidity and Capital Resources”
within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note 8 of the
Notes to Consolidated Financial Statements of this Annual Report on Form 10-K for further information regarding these
restrictions and their impact on our liquidity.
Market performance or changes in key valuation assumptions could require us to make significant unplanned
contributions to our pension plan and other postretirement benefit plans.
Assumptions related to interest rates, expected return on investments, mortality and other key actuarial assumptions have a
significant impact on our funding requirements and the expense recognized related to our pension and other postretirement
benefit plans. An adverse change to key assumptions associated with our defined benefit retirement plans may require
significant unplanned contributions to the plans which could adversely affect our financial operating results including earnings,
cash flow and liquidity. See Note 13 of the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K for
further information
Our use of derivative financial instruments as hedges against commodity prices and financial market risks could result
in material financial losses.
We use various financial and physical derivatives, including futures, forwards, options and swaps, to manage commodity price
and interest rate risks. The timing of the recognition of gains or losses on these economic hedges in accordance with GAAP may
not consistently match up with the gains or losses on the commodities being hedged. For Black Hills Energy Services under the
Choice Gas Program, and in certain instances within our regulated Utilities where unrealized and realized gains and losses from
derivative instruments are not approved for regulatory accounting treatment, fluctuating commodity prices may cause
fluctuations in reported financial results due to mark-to-market accounting treatment.
To the extent that we hedge our commodity price and interest rate exposures, we forgo the benefits we would otherwise
experience if commodity prices or interest rates were to change in our favor. In addition, even though they are closely monitored
by management, our hedging activities can result in losses. Such losses could occur under various circumstances, including if a
counterparty does not perform its obligations under the hedge arrangement, the hedge is economically imperfect, commodity
prices or interest rates move unfavorably related to our physical or financial positions, or hedging policies and procedures are
not followed.
29
10-KFORM 10-K | Additionally, our exchange-traded futures contracts are subject to futures margin posting requirements. To the extent we are
unable to meet these requirements, this could have a significant impact on our business by reducing our ability to execute
derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral may
cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes or may require us
to increase our level of debt. Further, a requirement for our counterparties to post collateral could result in additional costs being
passed on to us, thereby decreasing our profitability.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
The utility industry has been the target of several cyberattacks on operational systems and has seen an increased volume and
sophistication of cybersecurity incidents from international activist organizations, other nation state actors and individuals. We
expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure
and other assets. To date, we have not experienced a cybersecurity incident that has had a material impact on our business or
results of operations.
Risk Management and Strategy
Our enterprise risk management program, which includes cybersecurity risks that are identified through our cybersecurity risk
management program, is designed to identify, report, and manage relevant material risks and opportunities.
Management of the identified risks is embedded into business processes and key decision making at every level of the
Company. Our enterprise risk management team works closely with our Chief Security Officer ("CSO") and IT risk management
team to evaluate and address material cybersecurity risks in alignment with our business strategy and operational needs.
We have a cybersecurity risk management program that is managed by a team of full-time cybersecurity professionals that
utilizes a variety of tools and techniques to identify and assess material cybersecurity threats, their potential impact and
opportunities for mitigation. The industry-standard security frameworks that we apply to our cyber environment include various
security and risk assessments, such as internal threat assessments and internal control self-assessments. Because we are
aware of the risks associated with third-party providers, we conduct third-party provider security assessments and benchmarking
before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards. These
assessments include evaluation of risk profiles through vendor questionnaires, review of System and Organization Controls
attestation reports and monitoring on an ongoing basis by our IT risk management team. This approach is designed to mitigate
risks related to data breaches or other security incidents originating from third-parties.
We regularly engage with third-party assessors and auditors as part of our ongoing cybersecurity risk assessment process to
leverage specialized knowledge and insights and to identify areas for continued focus, improvement, compliance and
effectiveness of mitigation. We also utilize government and industry-related security intelligence sources, and actively participate
in industry peer groups and public-private partnerships to assist in the identification of potential threats. We conduct ongoing
cybersecurity training and monthly email phishing drills for all employees.
We also have a cybersecurity incident response plan and procedures to manage cybersecurity incidents. These procedures
include steps to identify, classify, communicate, contain, eradicate, and recover from a cybersecurity incident. These procedures
also include notification to a cross-functional management team to assess incident materiality and an escalation process to
members of our senior management team and our Board of Directors.
Governance
Our Board of Directors is responsible for the oversight of risks from cybersecurity threats. Our Chief Information Officer provides
our Board of Directors quarterly reports that summarize material cybersecurity threats and the countermeasures taken to
mitigate the associated risks. These reports address a variety of topics including updates on strategic cyber initiatives, industry
trends, threat vulnerability assessments, and efforts to prevent, detect and respond to internal and external critical threats. From
time to time, our Board of Directors also engages third-party consultants to provide further education about cybersecurity risks.
Our cybersecurity risk management program, which is discussed above, is led by our CSO, who has 28 years of prior work
experience in various roles involving managing information security of large-scale global security operations, including
developing cybersecurity strategy and implementing effective information and cybersecurity programs. Our CSO maintains
industry certifications, including an ISC2 Certified Information Systems Security Professional certification.
30
10-K| FORM 10-K Additionally, our exchange-traded futures contracts are subject to futures margin posting requirements. To the extent we are
unable to meet these requirements, this could have a significant impact on our business by reducing our ability to execute
derivative transactions to reduce commodity price uncertainty and to protect cash flows. Requirements to post collateral may
cause significant liquidity issues by reducing our ability to use cash for investment or other corporate purposes or may require us
to increase our level of debt. Further, a requirement for our counterparties to post collateral could result in additional costs being
Through oversight of the cybersecurity risk management program, our CSO is continually informed about the status of the
program, including the effectiveness of the process and controls to monitor, prevent, detect, mitigate, and remediate
cybersecurity incidents. The CSO is also made aware of the latest developments in cybersecurity, including potential threats and
innovative risk management techniques. The CSO, in his capacity, regularly informs the Chief Information Officer and other
members of our senior management team of all aspects related to cybersecurity risks and incidents.
passed on to us, thereby decreasing our profitability.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
The utility industry has been the target of several cyberattacks on operational systems and has seen an increased volume and
sophistication of cybersecurity incidents from international activist organizations, other nation state actors and individuals. We
expect to continue to experience attempts to compromise our information technology and control systems, network infrastructure
and other assets. To date, we have not experienced a cybersecurity incident that has had a material impact on our business or
results of operations.
Risk Management and Strategy
Our enterprise risk management program, which includes cybersecurity risks that are identified through our cybersecurity risk
management program, is designed to identify, report, and manage relevant material risks and opportunities.
Management of the identified risks is embedded into business processes and key decision making at every level of the
Company. Our enterprise risk management team works closely with our Chief Security Officer ("CSO") and IT risk management
team to evaluate and address material cybersecurity risks in alignment with our business strategy and operational needs.
We have a cybersecurity risk management program that is managed by a team of full-time cybersecurity professionals that
utilizes a variety of tools and techniques to identify and assess material cybersecurity threats, their potential impact and
opportunities for mitigation. The industry-standard security frameworks that we apply to our cyber environment include various
security and risk assessments, such as internal threat assessments and internal control self-assessments. Because we are
aware of the risks associated with third-party providers, we conduct third-party provider security assessments and benchmarking
before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards. These
assessments include evaluation of risk profiles through vendor questionnaires, review of System and Organization Controls
attestation reports and monitoring on an ongoing basis by our IT risk management team. This approach is designed to mitigate
risks related to data breaches or other security incidents originating from third-parties.
We regularly engage with third-party assessors and auditors as part of our ongoing cybersecurity risk assessment process to
leverage specialized knowledge and insights and to identify areas for continued focus, improvement, compliance and
effectiveness of mitigation. We also utilize government and industry-related security intelligence sources, and actively participate
in industry peer groups and public-private partnerships to assist in the identification of potential threats. We conduct ongoing
cybersecurity training and monthly email phishing drills for all employees.
We also have a cybersecurity incident response plan and procedures to manage cybersecurity incidents. These procedures
include steps to identify, classify, communicate, contain, eradicate, and recover from a cybersecurity incident. These procedures
also include notification to a cross-functional management team to assess incident materiality and an escalation process to
members of our senior management team and our Board of Directors.
Governance
Our Board of Directors is responsible for the oversight of risks from cybersecurity threats. Our Chief Information Officer provides
our Board of Directors quarterly reports that summarize material cybersecurity threats and the countermeasures taken to
mitigate the associated risks. These reports address a variety of topics including updates on strategic cyber initiatives, industry
trends, threat vulnerability assessments, and efforts to prevent, detect and respond to internal and external critical threats. From
time to time, our Board of Directors also engages third-party consultants to provide further education about cybersecurity risks.
Our cybersecurity risk management program, which is discussed above, is led by our CSO, who has 28 years of prior work
experience in various roles involving managing information security of large-scale global security operations, including
developing cybersecurity strategy and implementing effective information and cybersecurity programs. Our CSO maintains
industry certifications, including an ISC2 Certified Information Systems Security Professional certification.
ITEM 2. PROPERTIES
See Item 1 for a description of our principal business properties.
In addition to the properties disclosed in the Item 1, we own or lease several facilities throughout our service territories including
a corporate headquarters building and various office, service center, storage, shop and warehouse space. Substantially all of the
tangible utility properties of South Dakota Electric and Wyoming Electric are subject to liens securing first mortgage bonds
issued by South Dakota Electric and Wyoming Electric, respectively.
ITEM 3. LEGAL PROCEEDINGS
Information regarding our legal proceedings is incorporated herein by reference to the “Legal Proceedings” sub-caption within
Item 8, Note 3, “Commitments, Contingencies and Guarantees”, of the Notes to Consolidated Financial Statements in this
Annual Report on Form 10-K.
ITEM 4. MINE SAFETY DISCLOSURES
Information concerning mine safety violations or other regulatory matters required by Sections 1503(a) of the Dodd-Frank Wall
Street Reform and Consumer Protection Act is included in Exhibit 95 of this Annual Report.
INFORMATION ABOUT OUR EXECUTIVE OFFICERS
Linden R. Evans, age 61, has been President and Chief Executive Officer since January 1, 2019, President and Chief
Operating Officer from 2016 through 2018, and President and Chief Operating Officer - Utilities from 2004 through 2015. Mr.
Evans served as the Vice President and General Manager of our former communication subsidiary in 2003 and 2004, and
Associate Counsel from 2001 to 2003. Mr. Evans has 22 years of experience with the Company.
Brian G. Iverson, age 61, has been Senior Vice President, General Counsel and Chief Compliance Officer since August 26,
2019. He served as Senior Vice President, General Counsel, Chief Compliance Officer and Corporate Secretary from February
1, 2019 to August 26, 2019, Senior Vice President, General Counsel and Chief Compliance Officer from 2016 to February 2019,
Senior Vice President - Regulatory and Governmental Affairs and Assistant General Counsel from 2014 to 2016, Vice President
and Treasurer from 2011 to 2014, Vice President - Electric Regulatory Services from 2008 to 2011 and as Corporate Counsel
from 2004 to 2008. Mr. Iverson has 20 years of experience with the Company.
Todd Jacobs, age 55, has been Senior Vice President Growth and Strategy since June 15, 2023. Mr. Jacobs spent seven years
in operations roles at the company, serving as the state leader for our Kansas and Arkansas utilities from 2014 to 2019 and then
as the segment leader of our natural gas utilities from 2019 to 2021. He led our strategic planning and growth efforts from 2021
to 2023 before moving into this newly expanded role in 2023, which includes growth, strategic planning, business development,
regulatory, government affairs, sustainability, communications and community affairs. He served in legal and corporate services
leadership roles with other investor-owned utilities before joining the company in 2014. Mr. Jacobs served on active duty for
seven years as a U.S. Army officer.
Marne M. Jones, age 50, has been Senior Vice President Utilities since June 15, 2023. She served as VP Electric Utilities from
2021 to 2023, Vice President Regulatory and Finance from 2018 to 2021 and Vice President Regulatory from 2016 to 2018. Ms.
Jones has a total of 22 years of experience with the Company and has advanced through roles of increasing responsibility in
finance, accounting, corporate services, regulatory and utility operations.
Erik D. Keller, age 60, joined the Company as Senior Vice President and Chief Information Officer on July 27, 2020. Prior to
joining the company, he was an Information Technology consultant to Ontic Inc., a global provider of parts and services for
legacy aerospace platforms, from January 2020 to July 2020, and Chief Information Officer for BBA Aviation, a global aviation
support and aftermarket services provider, from February 2012 to January 2020.
Kimberly F. Nooney, age 52, has been Senior Vice President and Chief Financial Officer since April 1, 2023. She served as
Vice President – Treasurer from 2015 to 2023, and also served as the Corporate Controller from 2018 to 2022. Ms. Nooney has
a total of 27 years of experience with the Company across numerous roles within accounting, internal audit, corporate
development, accounting systems, treasury and financial planning and analysis.
31
10-KFORM 10-K | PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of January 31, 2024, we had 3,244
common shareholders of record and 63,074 beneficial owners, representing all 50 states, the District of Columbia, Puerto Rico
and 5 foreign countries.
COMPARATIVE STOCK PERFORMANCE
The following performance graph compares the cumulative total stockholder return from Black Hills Corporation common stock,
as compared with the S&P 500 Index, S&P 500 Utilities index, and our Performance Peer Group for the past five years. The
graph assumes an initial investment of $100 on December 31, 2018, and assumes all dividends were reinvested. The
stockholder return shown below for the five-year historical period may not be indicative of future performance. The information in
this "Comparative Stock Performance" section shall not be deemed to be "soliciting material" or to be "filed" with the Securities
and Exchange Commission or subject to Regulation 14A or 14C, or to the liabilities of Section 18 of the Securities Exchange Act
of 1934.
Black Hills Corporation
S&P 500
S&P 500 Utilities
Performance Peer Group (a)
____________________
(a)
As of December 31,
$
2018
2019
2020
2021
2022
2023
100.00 $
100.00
100.00
100.00
128.59 $
131.49
126.35
125.79
104.05 $
155.68
126.96
124.33
123.69 $
200.37
149.39
145.61
127.49 $
164.08
151.73
147.29
102.08
207.21
140.99
134.47
Performance Peer Group represents the Edison Electric Institute Index, which was used in our 2023 Proxy Statement filed with the SEC
on March 15, 2023.
DIVIDENDS
For information concerning dividends, our dividend policy and factors that may limit our ability to pay dividends, see “Key
Elements of our Business Strategy” and “Liquidity and Capital Resources” under Item 7, Management’s Discussion and Analysis
of Financial Condition and Results of Operations in this Annual Report on Form 10-K.
UNREGISTERED SECURITIES ISSUED
There were no unregistered securities sold during 2023.
32
10-K| FORM 10-K
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS
See Item 12 in this Annual Report on Form 10-K for information regarding Securities Authorized for Issuance Under Equity
Compensation Plans.
Our common stock is traded on the New York Stock Exchange under the symbol BKH. As of January 31, 2024, we had 3,244
common shareholders of record and 63,074 beneficial owners, representing all 50 states, the District of Columbia, Puerto Rico
ISSUER PURCHASES OF EQUITY SECURITIES
and 5 foreign countries.
COMPARATIVE STOCK PERFORMANCE
The following performance graph compares the cumulative total stockholder return from Black Hills Corporation common stock,
as compared with the S&P 500 Index, S&P 500 Utilities index, and our Performance Peer Group for the past five years. The
graph assumes an initial investment of $100 on December 31, 2018, and assumes all dividends were reinvested. The
stockholder return shown below for the five-year historical period may not be indicative of future performance. The information in
this "Comparative Stock Performance" section shall not be deemed to be "soliciting material" or to be "filed" with the Securities
and Exchange Commission or subject to Regulation 14A or 14C, or to the liabilities of Section 18 of the Securities Exchange Act
of 1934.
Black Hills Corporation
$
100.00 $
128.59 $
104.05 $
123.69 $
127.49 $
2018
2019
2020
2021
2022
2023
100.00
100.00
100.00
131.49
126.35
125.79
155.68
126.96
124.33
200.37
149.39
145.61
164.08
151.73
147.29
102.08
207.21
140.99
134.47
As of December 31,
(a)
Performance Peer Group represents the Edison Electric Institute Index, which was used in our 2023 Proxy Statement filed with the SEC
S&P 500
S&P 500 Utilities
Performance Peer Group (a)
____________________
on March 15, 2023.
DIVIDENDS
For information concerning dividends, our dividend policy and factors that may limit our ability to pay dividends, see “Key
Elements of our Business Strategy” and “Liquidity and Capital Resources” under Item 7, Management’s Discussion and Analysis
of Financial Condition and Results of Operations in this Annual Report on Form 10-K.
UNREGISTERED SECURITIES ISSUED
There were no unregistered securities sold during 2023.
The following table contains monthly information about our acquisitions of equity securities for the three months ended
December 31, 2023:
Period
October 1, 2023 - October 31, 2023
November 1, 2023 - November 30, 2023
December 1, 2023 - December 31, 2023
Total
Total Number of
Shares
Purchased (a)
Average Price
Paid per
Share
47 $
991 $
7,018 $
8,056 $
48.44
51.52
54.62
54.20
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
—
—
—
—
—
—
—
—
____________________
(a)
Shares were acquired under the share withholding provisions of the Amended and Restated 2015 Omnibus Incentive Plan for payment of
taxes associated with the vesting of various equity compensation plans.
ITEM 6. (RESERVED)
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Executive Summary
We are a customer-focused energy solutions provider with a mission of Improving Life with Energy for more than 1.3 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 critical priorities: Growth—to grow strategically and achieve strong financial performance, Operational
Excellence—delivering safe, reliable and cost-effective energy to meet our customers’ needs, Transformation—be a simple and
connected company positioned for growth, and People & Culture—retain and attract a talented, engaged and thriving team.
We conduct our business operations through two operating segments: Electric Utilities and Gas Utilities. Certain unallocated
corporate expenses that support our operating segments are presented as Corporate and Other. We conduct our utility
operations under the name Black Hills Energy predominantly in rural areas of the Rocky Mountains and Midwestern states. We
consider ourself a domestic electric and natural gas utility company.
We have provided energy and served customers for 140 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.
33
10-KFORM 10-K |
Key Elements of our Business Strategy
Explore opportunities as an energy solutions provider. A key strategic initiative is to grow our business through innovative
energy solutions with new customers and partnerships. We see value creation by recruiting new customers and expanding
existing partnerships with data centers and blockchain opportunities; exploring energy markets such as RTOs; and expanding
our transmission capabilities, establishing a RNG program and expanding our RNG portfolio. A few recent examples of our
initiatives to grow our business as an energy solutions provider include:
•
•
•
•
Contracted Renewable Energy to Grow Data Center Partnerships: In 2022, Wyoming Electric entered into two new
PPAs with third parties to purchase up to 106 MW of wind energy and up to 150 MW of solar energy, upon
construction of new renewable generation facilities (owned by third parties). The new wind generation facility was
placed in service in December 2023 and the solar facility is expected to be completed in March 2024. The
renewable energy from these PPAs will be used to serve our expanding partnerships with data centers.
Developed BCIS Tariff to Facilitate Growth: We have supported enabling legislation in Wyoming for the growing
blockchain businesses while implementing our own BCIS Tariff to serve these customers. In June 2022, Wyoming
Electric completed its first agreement, with a new customer in Cheyenne, Wyoming, under this Tariff. This five-year
agreement provides delivery of up to 45 MW with an option to expand service up to 75 MW, which was exercised by
the customer in 2023. Energy is sourced through the electric energy market and delivered through our Electric
Utilities’ infrastructure. Under the agreement, the customer is responsible for costs of service, and the load is
interruptible to prioritize the needs of Wyoming Electric’s existing retail customers.
Established Green Forward: In 2022 and 2023, we filed regulatory applications to launch Green Forward, a
voluntary RNG and carbon offset program, to eligible residential and small business natural gas customers to offset
up to 100% or more of the emissions from their natural gas usage. Our teams continue to evaluate attractive RNG
investment opportunities across our agriculture-rich service territories and explore value generation with our natural
gas storage assets. We also continue to expand our RNG interconnections, with seven projects actively injecting
RNG into our natural gas system.
Expanded RNG Portfolio: In January 2024, Black Hills Energy Renewable Resources acquired a RNG production
facility at a landfill in Dubuque, Iowa. The facility currently injects RNG into the natural gas distribution system
serving Dubuque, which is owned and operated by Iowa Gas. This acquisition represents our entry into the
production of RNG as a nonregulated business while leveraging our expertise in owning and operating regulated
natural gas pipeline systems, including RNG interconnections. The RNG produced from the landfill facility captures
methane that would otherwise vent into the atmosphere. It is delivered under long-term contracts to a third party that
purchases the RNG and its related environmental attributes, in conformity with the EPA's Renewable Fuel Standard
Program.
Modernize and operate utility infrastructure to provide customers with safe, reliable, cost-effective electric and natural
gas service. Our utilities own and operate large electric and natural gas infrastructure systems with a geographic footprint that
spans nearly 1,600 miles. Our Electric Utilities own and operate 1,394 MW of generation capacity and 9,106 miles of
transmission and distribution lines and our Gas Utilities own and operate approximately 47,000 miles of natural gas transmission
and distribution pipelines.
A key strategic focus is to modernize and harden our utility infrastructure to meet customers’ and communities’ varied energy
needs, ensure the continued delivery of safe, reliable and cost-effective energy and reduce GHG emissions intensity. In addition,
we invest in the expansion, capacity and integrity of our systems to meet customer growth.
To meet our electric customers’ continued expectations of high levels of reliability, a key strength of the Company, our Electric
Utilities utilize an integrity program to ensure the timely repair and replacement of aging infrastructure. In alignment with this
program, in November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. The
260-mile, multi-phase transmission expansion project will provide customers long-term price stability and greater flexibility as
power markets develop in the Western States. Construction of the project commenced in late 2023 and is expected to take place
in multiple phases or segments through 2025 and will interconnect South Dakota Electric’s and Wyoming Electric’s transmission
systems.
Our Gas Utilities utilize a programmatic approach to system-wide pipeline replacement, particularly in high consequence areas.
Under the programmatic approach, obsolete, at-risk and vintage materials are replaced in a proactive and systematic time frame.
We have removed all cast- and wrought-iron from our natural gas transmission and distribution systems and continue to replace
aging infrastructure through programs that prioritize safety and reliability for our customers. Our Gas Utilities are authorized to
use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments, between
rate reviews, which allow timely recovery of costs incurred in repairing and replacing the gas delivery systems with a return on
the investment.
34
10-K| FORM 10-K Key Elements of our Business Strategy
Explore opportunities as an energy solutions provider. A key strategic initiative is to grow our business through innovative
energy solutions with new customers and partnerships. We see value creation by recruiting new customers and expanding
existing partnerships with data centers and blockchain opportunities; exploring energy markets such as RTOs; and expanding
our transmission capabilities, establishing a RNG program and expanding our RNG portfolio. A few recent examples of our
initiatives to grow our business as an energy solutions provider include:
•
•
•
•
Contracted Renewable Energy to Grow Data Center Partnerships: In 2022, Wyoming Electric entered into two new
PPAs with third parties to purchase up to 106 MW of wind energy and up to 150 MW of solar energy, upon
construction of new renewable generation facilities (owned by third parties). The new wind generation facility was
placed in service in December 2023 and the solar facility is expected to be completed in March 2024. The
renewable energy from these PPAs will be used to serve our expanding partnerships with data centers.
Developed BCIS Tariff to Facilitate Growth: We have supported enabling legislation in Wyoming for the growing
blockchain businesses while implementing our own BCIS Tariff to serve these customers. In June 2022, Wyoming
Electric completed its first agreement, with a new customer in Cheyenne, Wyoming, under this Tariff. This five-year
agreement provides delivery of up to 45 MW with an option to expand service up to 75 MW, which was exercised by
the customer in 2023. Energy is sourced through the electric energy market and delivered through our Electric
Utilities’ infrastructure. Under the agreement, the customer is responsible for costs of service, and the load is
interruptible to prioritize the needs of Wyoming Electric’s existing retail customers.
Established Green Forward: In 2022 and 2023, we filed regulatory applications to launch Green Forward, a
voluntary RNG and carbon offset program, to eligible residential and small business natural gas customers to offset
up to 100% or more of the emissions from their natural gas usage. Our teams continue to evaluate attractive RNG
investment opportunities across our agriculture-rich service territories and explore value generation with our natural
gas storage assets. We also continue to expand our RNG interconnections, with seven projects actively injecting
RNG into our natural gas system.
Expanded RNG Portfolio: In January 2024, Black Hills Energy Renewable Resources acquired a RNG production
facility at a landfill in Dubuque, Iowa. The facility currently injects RNG into the natural gas distribution system
serving Dubuque, which is owned and operated by Iowa Gas. This acquisition represents our entry into the
production of RNG as a nonregulated business while leveraging our expertise in owning and operating regulated
natural gas pipeline systems, including RNG interconnections. The RNG produced from the landfill facility captures
methane that would otherwise vent into the atmosphere. It is delivered under long-term contracts to a third party that
purchases the RNG and its related environmental attributes, in conformity with the EPA's Renewable Fuel Standard
Program.
Modernize and operate utility infrastructure to provide customers with safe, reliable, cost-effective electric and natural
gas service. Our utilities own and operate large electric and natural gas infrastructure systems with a geographic footprint that
spans nearly 1,600 miles. Our Electric Utilities own and operate 1,394 MW of generation capacity and 9,106 miles of
transmission and distribution lines and our Gas Utilities own and operate approximately 47,000 miles of natural gas transmission
and distribution pipelines.
A key strategic focus is to modernize and harden our utility infrastructure to meet customers’ and communities’ varied energy
needs, ensure the continued delivery of safe, reliable and cost-effective energy and reduce GHG emissions intensity. In addition,
we invest in the expansion, capacity and integrity of our systems to meet customer growth.
To meet our electric customers’ continued expectations of high levels of reliability, a key strength of the Company, our Electric
Utilities utilize an integrity program to ensure the timely repair and replacement of aging infrastructure. In alignment with this
program, in November 2021, Wyoming Electric announced its Ready Wyoming electric transmission expansion initiative. The
260-mile, multi-phase transmission expansion project will provide customers long-term price stability and greater flexibility as
power markets develop in the Western States. Construction of the project commenced in late 2023 and is expected to take place
in multiple phases or segments through 2025 and will interconnect South Dakota Electric’s and Wyoming Electric’s transmission
systems.
the investment.
Our Gas Utilities utilize a programmatic approach to system-wide pipeline replacement, particularly in high consequence areas.
Under the programmatic approach, obsolete, at-risk and vintage materials are replaced in a proactive and systematic time frame.
We have removed all cast- and wrought-iron from our natural gas transmission and distribution systems and continue to replace
aging infrastructure through programs that prioritize safety and reliability for our customers. Our Gas Utilities are authorized to
use system safety, integrity and replacement cost recovery mechanisms that provide for customer rate adjustments, between
rate reviews, which allow timely recovery of costs incurred in repairing and replacing the gas delivery systems with a return on
As of December 31, 2023, we estimate our five-year capital investment to be approximately $4.3 billion, with most of that
investment targeted toward upgrading existing utility infrastructure supporting customer and community growth needs, and
complying with safety requirements. Our actual 2023 and forecasted capital expenditures for the next five years from 2024
through 2028 are as follows (in millions). Minor differences may result due to rounding.
Capital Expenditures By Segment:
(in millions)
Electric Utilities
Gas Utilities
Corporate and Other
Strategic growth projects
Total
$
$
$
$
$
Actual (a)
2023
2024
2025
Forecasted (b)
2026
2027
2028
211 $
372 $
7 $
- $
590 $
409 $
407 $
24 $
- $
840 $
287 $
387 $
29 $
100 $
803 $
466 $
368 $
29 $
400 $
1,263 $
199 $
372 $
27 $
50 $
648 $
264
373
29
50
717
(a)
(b)
Includes accruals for property, plant and equipment as disclosed as supplemental cash flow information in the Consolidated Statements
of Cash Flows in the Consolidated Financial Statements in this Annual Report on Form 10-K. Capital expenditures are presented net of
contributions in aid of construction in the Consolidated Statements of Cash Flows.
Projects are being evaluated by our segments for timing, cost and other factors.
Efficiently plan, construct and operate power generation facilities to serve our Electric Utilities. We best serve customers
and communities when generation is vertically integrated into our Electric Utilities and we retain control of the fuel source. This
business model remains a core strength and strategy today as we invest in and operate efficient power generation resources to
supply cost-effective electricity to our customers. These generation assets can be rate-based or non-regulated assets within our
Electric Utilities segment. However, we believe that generation assets that are rate-based provide the most effective long-term
benefits to customers.
Our power production strategy focuses on low-cost construction and efficient operation of our generating facilities. Our low
power production costs result from a variety of factors including low fuel costs (operations located near energy hubs), efficiency
in converting fuel into energy and low per unit operating and maintenance costs. In addition, we operate our plants with high
levels of Availability as compared to industry benchmarks.
Rate-Based Generation: We continue to believe that customers are best served when the power generation facilities are owned
and rate-based by our Electric Utilities. Rate-based generation assets offer several advantages for customers and shareholders,
including:
•
•
•
•
When generating assets are included in the utility rate base and reviewed and approved by government authorities,
customer rates are more stable and predictable, and typically less expensive in the long run; especially when
compared to power otherwise purchased from the open market through wholesale contracts or PPAs that are
periodically re-priced to reflect current and varying market conditions;
Regulators participate in a planning process where long-term investments are designed to match long-term energy
demand;
The lower-risk profile of rate-based generation assets contributes to stronger credit ratings which, in turn, can benefit
both customers and investors by lowering the cost of capital; and
Investors are provided a long-term and stable return on their investment.
Integrated Generation: Our Electric Utilities segment also includes a power generation business that owns non-regulated
generating facilities that are contracted through long-term power purchase agreements with our electric utilities. Our power
generation business has an experienced staff with significant expertise in planning, building and operating power plants. This
team also provides shared services to our Electric Utilities’ generation facilities, resulting in efficient management of all of the
Company’s generation assets. Our power generation business competitively bids for energy and capacity through requests for
proposals by our Electric Utilities for energy resources necessary to serve customers. This business can bid competitively due to
construction expertise, fuel supply advantages and by co-locating new plants at our existing Electric Utilities’ energy complexes,
reducing infrastructure and operating costs. All power plants within this business are contracted to our Electric Utilities under
long-term contracts, located at our utility-generating complexes and physically integrated into our Electric Utilities’ operations.
35
10-KFORM 10-K |
Generation Fuel Supply: Our generating facilities are strategically located close to energy hubs that help reduce fuel supply
costs. Our Colorado and Wyoming gas-fired generating facilities are located close to major natural gas energy hubs that provide
trading liquidity and transparent pricing. Due to their location in the resource rich areas of Colorado and Wyoming, natural gas
supply to fuel our gas-fired generation can be sourced at competitive prices. Our coal-fired power plants, all located at the
Gillette Energy Complex in northeastern Wyoming, are supplied by our adjacent WRDC coal mine. WRDC provides
approximately 3.7 million tons of low-sulfur coal directly to these power plants via a conveyor belt system, minimizing
transportation costs. The fuel can be delivered to our adjacent power plants at very cost competitive prices (i.e., $1.14 per
MMBtu for year ended December 31, 2023) when compared to alternatives. Nearly all the mine’s production is sold to these on-
site generation facilities under long-term supply contracts. Approximately one-half of our production is sold under cost-plus
contracts with affiliates. A small portion of the mine’s production is sold to off-site industrial customers and delivered by truck.
Supporting the Energy Transition by proactively integrating alternative and renewable energy into our utility energy
supply while mitigating customer rate impacts. A critical component of our strategy involves sustainable operations and
supporting the Energy Transition. How we operate our company for the social good has never been more important. We are
committed to cleaner energy and a low carbon future, integrating the Energy Transition and more renewable energy into our
overall strategy and decision making. In addition, we are committed to a more sustainable future by better managing our impacts
to the planet, whether that is water usage, recycling, biodiversity, or other important measures.
In November 2020, we announced clean energy goals to reduce GHG emissions intensity for our Electric Utilities by 40% by
2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. Our goals are compared to a 2005
baseline. Electric Utility goals include Scope 1 emissions from electric utility generating units and Scope 3 emissions from
purchased power for sales. Our Gas Utilities goal initially included only Scope 1 emissions from distribution system main and
service lines. In August 2022, we announced a new "Net Zero by 2035" target for our Gas Utilities, which doubled the previous
target of a 50% reduction by 2035 and expanded the scope of the goal to all Scope 1 sources of methane emissions on our
distribution system. Net Zero will be achieved through pipeline material and main replacements, advanced leak detection, third-
party damage reduction, expanding the use of RNG and hydrogen, and utilizing carbon credit offsets.
Since 2005, we have reduced GHG emissions intensity from our Electric Utilities by one-third. We have plans in place today,
without reliance on future technologies, to achieve our corporate climate goals calling for a 40% reduction in greenhouse gas
emissions intensity from our electric utility operations by 2030 and 70% by 2040. Additionally, our Electric Utilities have reduced
nitrogen oxide and sulfur dioxide emissions by more than 75% since 2005. Colorado Electric has achieved a nearly 50%
reduction in GHG emissions since 2005 and is on track to reach the State of Colorado’s 80% carbon reduction goal by 2030. Our
goals are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. This
keeps our customers at the forefront of our decision-making, which is central to our values.
More of our customers, particularly our larger customers, are demanding cleaner sources of energy to meet their sustainability
goals. In addition, there is more interest from consumers, regulators and legislators to increase the use of renewable and other
alternative energy sources. Recent efforts to support this interest include:
•
•
In June 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. The IRP
outlines a range of options for the two electric utilities over a 20-year planning horizon to meet long-term forecasted
energy needs while strengthening reliability and resiliency of the grid. The analysis focused on the least-cost
resource needs to best meet customers’ future peak energy needs while maintaining system flexibility and achieving
the Company’s generation emissions reduction goals. The IRP’s preferred options for South Dakota Electric in the
near-term planning period through 2026 are the addition of 100 MW of renewable generation, the conversion of Neil
Simpson II to dual fuel (natural gas and coal) in 2025 and consideration of up to 20 MW of battery storage. In 2023,
South Dakota Electric issued a request for proposals for 100 MW of utility-owned renewable energy resources to be
in service in 2026. Negotiations are underway, with results to be presented to the SDPUC and included in a CPCN
filing with the WPSC during the first quarter of 2024.
In March 2023, the CPUC approved a unanimous settlement for Colorado Electric's Clean Energy Plan filed on May
25, 2022. The Clean Energy Plan supports Colorado Electric's voluntary election to reduce carbon emissions 80%
from 2005 levels by 2030. In July 2023, Colorado Electric issued a request for proposals for approximately 400 MW
of new renewable resources to be in service by 2029 to achieve objectives in its Clean Energy Plan. Colorado
Electric received a strong response to its request for proposal and provided a bids summary to the CPUC as part of
the approval process. A report with Colorado Electric's recommended resources is due to the CPUC in the second
quarter of 2024.
36
10-K| FORM 10-K Generation Fuel Supply: Our generating facilities are strategically located close to energy hubs that help reduce fuel supply
costs. Our Colorado and Wyoming gas-fired generating facilities are located close to major natural gas energy hubs that provide
trading liquidity and transparent pricing. Due to their location in the resource rich areas of Colorado and Wyoming, natural gas
supply to fuel our gas-fired generation can be sourced at competitive prices. Our coal-fired power plants, all located at the
Gillette Energy Complex in northeastern Wyoming, are supplied by our adjacent WRDC coal mine. WRDC provides
approximately 3.7 million tons of low-sulfur coal directly to these power plants via a conveyor belt system, minimizing
transportation costs. The fuel can be delivered to our adjacent power plants at very cost competitive prices (i.e., $1.14 per
MMBtu for year ended December 31, 2023) when compared to alternatives. Nearly all the mine’s production is sold to these on-
site generation facilities under long-term supply contracts. Approximately one-half of our production is sold under cost-plus
contracts with affiliates. A small portion of the mine’s production is sold to off-site industrial customers and delivered by truck.
Supporting the Energy Transition by proactively integrating alternative and renewable energy into our utility energy
supply while mitigating customer rate impacts. A critical component of our strategy involves sustainable operations and
supporting the Energy Transition. How we operate our company for the social good has never been more important. We are
committed to cleaner energy and a low carbon future, integrating the Energy Transition and more renewable energy into our
overall strategy and decision making. In addition, we are committed to a more sustainable future by better managing our impacts
to the planet, whether that is water usage, recycling, biodiversity, or other important measures.
In November 2020, we announced clean energy goals to reduce GHG emissions intensity for our Electric Utilities by 40% by
2030 and 70% by 2040 and achieve GHG reductions of 50% by 2035 for our Gas Utilities. Our goals are compared to a 2005
baseline. Electric Utility goals include Scope 1 emissions from electric utility generating units and Scope 3 emissions from
purchased power for sales. Our Gas Utilities goal initially included only Scope 1 emissions from distribution system main and
service lines. In August 2022, we announced a new "Net Zero by 2035" target for our Gas Utilities, which doubled the previous
target of a 50% reduction by 2035 and expanded the scope of the goal to all Scope 1 sources of methane emissions on our
distribution system. Net Zero will be achieved through pipeline material and main replacements, advanced leak detection, third-
party damage reduction, expanding the use of RNG and hydrogen, and utilizing carbon credit offsets.
Since 2005, we have reduced GHG emissions intensity from our Electric Utilities by one-third. We have plans in place today,
without reliance on future technologies, to achieve our corporate climate goals calling for a 40% reduction in greenhouse gas
emissions intensity from our electric utility operations by 2030 and 70% by 2040. Additionally, our Electric Utilities have reduced
nitrogen oxide and sulfur dioxide emissions by more than 75% since 2005. Colorado Electric has achieved a nearly 50%
reduction in GHG emissions since 2005 and is on track to reach the State of Colorado’s 80% carbon reduction goal by 2030. Our
goals are based on prudent and proven solutions to reduce our emissions while minimizing cost impacts to our customers. This
keeps our customers at the forefront of our decision-making, which is central to our values.
More of our customers, particularly our larger customers, are demanding cleaner sources of energy to meet their sustainability
goals. In addition, there is more interest from consumers, regulators and legislators to increase the use of renewable and other
alternative energy sources. Recent efforts to support this interest include:
•
•
In June 2021, South Dakota Electric and Wyoming Electric submitted an IRP to the SDPUC and WPSC. The IRP
outlines a range of options for the two electric utilities over a 20-year planning horizon to meet long-term forecasted
energy needs while strengthening reliability and resiliency of the grid. The analysis focused on the least-cost
resource needs to best meet customers’ future peak energy needs while maintaining system flexibility and achieving
the Company’s generation emissions reduction goals. The IRP’s preferred options for South Dakota Electric in the
near-term planning period through 2026 are the addition of 100 MW of renewable generation, the conversion of Neil
Simpson II to dual fuel (natural gas and coal) in 2025 and consideration of up to 20 MW of battery storage. In 2023,
South Dakota Electric issued a request for proposals for 100 MW of utility-owned renewable energy resources to be
in service in 2026. Negotiations are underway, with results to be presented to the SDPUC and included in a CPCN
filing with the WPSC during the first quarter of 2024.
In March 2023, the CPUC approved a unanimous settlement for Colorado Electric's Clean Energy Plan filed on May
25, 2022. The Clean Energy Plan supports Colorado Electric's voluntary election to reduce carbon emissions 80%
from 2005 levels by 2030. In July 2023, Colorado Electric issued a request for proposals for approximately 400 MW
of new renewable resources to be in service by 2029 to achieve objectives in its Clean Energy Plan. Colorado
Electric received a strong response to its request for proposal and provided a bids summary to the CPUC as part of
the approval process. A report with Colorado Electric's recommended resources is due to the CPUC in the second
quarter of 2024.
Many states have enacted, and others are considering, mandatory renewable energy standards, requiring utilities to meet certain
thresholds of renewable energy generation. In addition, some states have either enacted or are considering legislation setting
GHG emission reduction targets. Federal legislation for renewable energy standards and GHG emission reductions has been
considered and may be implemented in the future. Mandates for the use of renewable energy or the reduction of GHG emissions
will likely drive the need for significant investment in our Electric Utilities and Gas Utilities segments. These mandates will also
likely increase prices for electricity and/or natural gas for our utility customers. As a regulated utility, we are responsible for
providing safe, reliable and cost-effective sources of energy to our customers. Accordingly, we employ a customer-focused
strategy for complying with standards and regulations that balances our customers’ rate concerns with environmental
considerations and administrative and legislative mandates. We attempt to strike this balance by prudently and proactively
incorporating renewable energy into our resource supply, while seeking to minimize the magnitude and frequency of rate
increases for our utility customers.
Inflation Reduction Act
The IRA, signed into law by President Biden in August 2022, features $370 billion in spending and tax incentives on clean
energy provisions. Most notably, the IRA includes provisions that extend and expand the production and investment tax credits
for wind and solar; includes energy storage, EVs, RNG, and carbon capture and sequestration; and allows for the transferability
of clean energy tax credits on existing and qualifying new facilities. We see the IRA as generally supportive of our Energy
Transition strategy with the potential to drive increased value for our customers and shareholders. We are still evaluating the
impacts of the IRA provisions on our future capital projects.
Deliver a competitive total return to investors and maintain an investment grade credit rating. We are proud of our track
record of annual dividend increases for shareholders. 2023 represented our 53rd consecutive year of increasing dividends. In
January 2024, our Board of Directors declared a quarterly dividend of $0.65 per share, equivalent to an annual dividend of $2.60
per share. We intend to continue our record of annual dividend increases with a targeted dividend payout ratio of 55% to 65% of
net income.
We require access to the capital markets to fund our planned capital investments or acquire strategic assets that support prudent
and earnings-accretive business growth. We have demonstrated our ability to cost-effectively access the debt and equity
markets, while maintaining our investment-grade issuer credit rating.
Macroeconomic Trends
Recent Developments
We continue to monitor challenging macroeconomic trends including supply chain disruptions, rising interest rates, potential
recession and inflationary pressures on the prices of materials, outside services and employee costs. To date, we have
experienced moderate net impacts from these trends. However, if current macroeconomic conditions deteriorate in 2024,
adverse impacts to our businesses may be magnified.
Inflation has increased our operating expenses, which included higher employee-related expenses in 2023 compared to the prior
year.
We are proactively managing increased costs of materials and supply chain disruptions to achieve our forecasted capital
investment targets. To support our 2024 capital investment program, we have contracts in place with key suppliers and we have
contracted services for a significant portion of our largest forecasted projects. We continue to forecast multi-year key material
requirements with suppliers to enhance predictable material availability, challenge vendor price increases to ensure best value
and cost transparency and invest in our distribution network to ensure the safety and reliability of our system. We have also
evaluated each of our forecasted projects and will prioritize them depending on future constraints. Project delays may occur if
costs rise significantly or if materials are not available.
Rising interest rates have led to increased interest expense on recent debt issuances. These impacts were partially offset by
lower short-term, variable rate borrowings and higher interest income on our cash equivalents when compared to the prior year.
The deflationary trend in commodity prices throughout 2023 has partially offset macroeconomic headwinds from inflation and
higher interest rates. Lower commodity prices have led to lower customer bills, lower cost of fuel, purchased power and natural
gas sold, and improved cash flows from operations due to recoveries of deferred energy costs from customers (which were
elevated at the end of 2022 and subsequently collected in 2023).
More detailed discussion of the future uncertainties can be found in Item 1A - Risk Factors.
37
10-KFORM 10-K | Business Segment Highlights and Corporate Activity
Electric Utilities
•
•
•
•
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent rate
review activity for Wyoming Electric.
See Key Elements of our Business Strategy section above for discussion of recent developments related to Ready
Wyoming, Colorado Electric's Clean Energy Plan, and South Dakota Electric and Wyoming Electric's IRP.
On January 11, 2024, Wyoming Electric set a new winter peak load of 314 MW, surpassing the previous winter
peaks of 301 MW set on December 26, 2023, 299 MW set on October 31, 2023, and 281 MW set in December
2022.
On July 24, 2023, Wyoming Electric set a new all-time and summer peak load of 312 MW, surpassing the previous
peak of 294 MW set on July 21, 2022.
Gas Utilities
•
•
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent rate
review activity for Arkansas Gas, Colorado Gas, RMNG and Wyoming Gas.
See Key Elements of our Business Strategy section above for discussion of recent developments related to
BHERR's purchase of a RNG production facility in Iowa.
Corporate and Other
•
•
•
On September 15, 2023, we completed a public debt offering of $450 million, 6.15% 10-year senior unsecured notes
due May 15, 2034. Net proceeds from the offering were used to repay our $525 million principal amount outstanding
notes and for other general corporate purposes. See Note 8 of the Notes to Consolidated Financial Statements in
this Annual Report on Form 10-K for further information.
On June 16, 2023, we filed a new shelf registration statement with the SEC and entered into a new Equity
Distribution Sales Agreement. The new Equity Distribution Sales Agreement is similar to our prior agreement and
allows us to sell shares of common stock up to an aggregate of $400 million through our ATM program utilizing our
shelf registration statement. As of December 31, 2023, we have $329 million available to issue under this program.
See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further
information.
On March 7, 2023, we completed a public debt offering of $350 million, 5.95% 5-year senior unsecured notes due
March 15, 2028. The proceeds from the offering were used to repay notes outstanding under our commercial paper
program and for other general corporate purposes. See Note 8 of the Notes to Consolidated Financial Statements in
this Annual Report on Form 10-K for further information.
38
10-K| FORM 10-K •
•
•
•
•
•
•
•
•
2022.
Gas Utilities
Corporate and Other
On July 24, 2023, Wyoming Electric set a new all-time and summer peak load of 312 MW, surpassing the previous
peak of 294 MW set on July 21, 2022.
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent rate
review activity for Arkansas Gas, Colorado Gas, RMNG and Wyoming Gas.
See Key Elements of our Business Strategy section above for discussion of recent developments related to
BHERR's purchase of a RNG production facility in Iowa.
On September 15, 2023, we completed a public debt offering of $450 million, 6.15% 10-year senior unsecured notes
due May 15, 2034. Net proceeds from the offering were used to repay our $525 million principal amount outstanding
notes and for other general corporate purposes. See Note 8 of the Notes to Consolidated Financial Statements in
this Annual Report on Form 10-K for further information.
On June 16, 2023, we filed a new shelf registration statement with the SEC and entered into a new Equity
Distribution Sales Agreement. The new Equity Distribution Sales Agreement is similar to our prior agreement and
allows us to sell shares of common stock up to an aggregate of $400 million through our ATM program utilizing our
shelf registration statement. As of December 31, 2023, we have $329 million available to issue under this program.
See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further
information.
On March 7, 2023, we completed a public debt offering of $350 million, 5.95% 5-year senior unsecured notes due
March 15, 2028. The proceeds from the offering were used to repay notes outstanding under our commercial paper
program and for other general corporate purposes. See Note 8 of the Notes to Consolidated Financial Statements in
this Annual Report on Form 10-K for further information.
Business Segment Highlights and Corporate Activity
Electric Utilities
See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent rate
review activity for Wyoming Electric.
Results of Operations
Our discussion and analysis for the year ended December 31, 2023, compared to 2022 is included herein. For discussion and
analysis for the year ended December 31, 2022, compared to 2021, please refer to Item 7 of Part II, “Management’s Discussion
and Analysis of Financial Condition and Results of Operations” in our Annual Report on Form 10-K for the year ended December
31, 2022, which was filed with the SEC on February 14, 2023.
See Key Elements of our Business Strategy section above for discussion of recent developments related to Ready
Wyoming, Colorado Electric's Clean Energy Plan, and South Dakota Electric and Wyoming Electric's IRP.
All amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in amounts may result due to
rounding.
On January 11, 2024, Wyoming Electric set a new winter peak load of 314 MW, surpassing the previous winter
peaks of 301 MW set on December 26, 2023, 299 MW set on October 31, 2023, and 281 MW set in December
Consolidated Summary and Overview
Operating income (loss):
Electric Utilities
Gas Utilities
Corporate and Other (a)
Operating Income
Interest expense, net
Other income (expense), net
Income tax (expense)
Net income
Net income attributable to non-controlling
interest
Net income available for common stock
Total earnings per share of common stock,
Diluted
(a)
Includes inter-segment eliminations.
2023 Compared to 2022
$
$
$
For the Years Ended December 31,
2023
2022
2023 vs 2022
Variance
2021
2022 vs 2021
Variance
(in millions, except per share amounts)
248.8 $
228.8
(4.9)
472.7
(167.9)
(3.2)
(25.6)
276.0
214.3 $
244.2
(3.3)
455.2
(161.0)
1.8
(25.2)
270.8
(13.8)
262.2 $
(12.4)
258.4 $
34.5 $
(15.4)
(1.6)
17.5
(6.9)
(5.0)
(0.4)
5.2
(1.4)
3.8 $
202.7 $
211.2
(4.5)
409.4
(152.4)
1.4
(7.2)
251.3
(14.5)
236.7 $
11.6
33.0
1.2
45.8
(8.6)
0.4
(18.0)
19.5
2.1
21.7
3.91 $
3.97 $
(0.06) $
3.74 $
0.23
The variance to the prior year included the following:
•
•
•
•
Electric Utilities’ operating income increased $34.5 million primarily due to new rates and rider recovery, a one-time
gain on the planned sale of Northern Iowa Windpower assets, a gain on a strategic sale of land in Wyoming to a
customer to support continued load growth, and a one-time recovery from our business interruption insurance
related to the 2021 Wygen I unplanned outage partially offset by unfavorable weather, higher depreciation expense
and higher employee-related expenses;
Gas Utilities’ operating income decreased $15.4 million primarily due to unfavorable weather, a prior year one-time
true-up of carrying costs accrued on Winter Storm Uri regulatory assets and higher operating expenses partially
offset by new rates and rider recovery and retail customer growth and demand;
Interest expense increased $6.9 million due to higher interest rates partially offset by increased interest income on
higher cash and cash equivalents balances; and
Other expense, net increased $5.0 million primarily due to higher benefit plan non-service costs driven by higher
discount rates and higher costs for our non-qualified deferred compensation plan driven by market performance.
Segment Operating Results
Non-GAAP Financial Measure
The following discussion includes financial information prepared in accordance with GAAP, as well as another financial measure,
Electric and Gas Utility margin, that is considered a “non-GAAP financial measure.” 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. Electric and Gas Utility margin (revenue less cost of sales) is a non-GAAP financial measure due to the exclusion of
operation and maintenance expenses, depreciation and amortization expenses, and property and production taxes from the
measure.
39
10-KFORM 10-K |
Electric Utility margin is calculated as operating revenue less cost of fuel and purchased power. Gas Utility margin is calculated
as operating revenue less cost of natural gas sold. Our Electric and Gas Utility margin is impacted by the fluctuations in power
and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact Electric and Gas Utility
margin as a percentage of revenue, they only impact total Electric and Gas Utility margin if the costs cannot be passed through
to our customers.
Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin
measures. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as
an indicator of operating performance.
Electric Utilities
Operating results for the years ended December 31 for the Electric Utilities were as follows (in millions):
2023
2022
2023 vs 2022
Variance
2021
2022 vs 2021
Variance
Revenue:
Electric - regulated
Other - non-regulated
Total revenue
Fuel and Purchased Power:
Electric - regulated
Other - non-regulated
Total fuel and purchased power
Electric Utility margin (non-GAAP)
Operations and maintenance
Depreciation and amortization
Taxes - property and production
$
817.4 $
47.6
865.0
852.2 $
48.0
900.2
(34.8) $
(0.4)
(35.2)
800.7 $
41.5
842.2
198.3
1.8
200.1
664.9
236.2
142.6
37.3
416.1
261.7
4.6
266.3
633.9
244.8
135.9
38.9
419.6
(63.4)
(2.8)
(66.2)
31.0
(8.6)
6.7
(1.6)
(3.5)
244.5
3.5
248.0
594.2
224.5
131.5
35.5
391.5
Operating income
$
248.8 $
214.3 $
34.5 $
202.7 $
51.5
6.5
58.0
17.2
1.1
18.3
39.7
20.3
4.4
3.4
28.1
11.6
2023 Compared to 2022
Electric Utility margin increased over the prior year as a result of:
New rates and rider recovery
Wygen I revenue recovery under business interruption insurance (a)
Integrated Generation (b)
Transmission services
Weather
Retail customer usage
Other
(in millions)
29.4
5.0
3.3
3.2
(6.2)
(4.4)
0.7
31.0
$
$
(a)
(b)
In 2021, Wygen I experienced an unplanned outage which resulted in lost revenue. A claim for these losses was submitted under our
business interruption insurance policy. During the third quarter of 2023, we recovered $5.0 million from our business interruption
insurance which was recognized as Revenue. See Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for further information.
Primarily driven by favorable mining contract pricing and increased Black Hills Colorado IPP fired-engine hours.
Operations and maintenance expense decreased primarily due to a one-time $7.7 million gain on the planned sale of Northern
Iowa Windpower assets, a $3.9 million gain on a strategic sale of land in Wyoming to a customer to support continued load
growth, and $2.9 million of lower outside services expenses partially offset by $8.7 million of higher employee-related expenses.
Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures.
Taxes - property and production were comparable to the same period in the prior year.
40
10-K| FORM 10-K
Electric Utility margin is calculated as operating revenue less cost of fuel and purchased power. Gas Utility margin is calculated
as operating revenue less cost of natural gas sold. Our Electric and Gas Utility margin is impacted by the fluctuations in power
and natural gas purchases and other fuel supply costs. However, while these fluctuating costs impact Electric and Gas Utility
margin as a percentage of revenue, they only impact total Electric and Gas Utility margin if the costs cannot be passed through
to our customers.
Our Electric and Gas Utility margin measure may not be comparable to other companies’ Electric and Gas Utility margin
measures. Furthermore, this measure is not intended to replace operating income as determined in accordance with GAAP as
Operating results for the years ended December 31 for the Electric Utilities were as follows (in millions):
2023
2022
2023 vs 2022
Variance
2021
2022 vs 2021
Variance
$
817.4 $
47.6
865.0
852.2 $
48.0
900.2
(34.8) $
(0.4)
(35.2)
800.7 $
41.5
842.2
an indicator of operating performance.
Electric Utilities
Revenue:
Electric - regulated
Other - non-regulated
Total revenue
Fuel and Purchased Power:
Electric - regulated
Other - non-regulated
Total fuel and purchased power
Electric Utility margin (non-GAAP)
Operations and maintenance
Depreciation and amortization
Taxes - property and production
198.3
1.8
200.1
664.9
236.2
142.6
37.3
416.1
261.7
4.6
266.3
633.9
244.8
135.9
38.9
419.6
(63.4)
(2.8)
(66.2)
31.0
(8.6)
6.7
(1.6)
(3.5)
Operating income
$
248.8 $
214.3 $
34.5 $
202.7 $
2023 Compared to 2022
Electric Utility margin increased over the prior year as a result of:
New rates and rider recovery
Wygen I revenue recovery under business interruption insurance (a)
Integrated Generation (b)
Transmission services
Weather
Other
Retail customer usage
51.5
6.5
58.0
17.2
1.1
18.3
39.7
20.3
4.4
3.4
28.1
11.6
29.4
5.0
3.3
3.2
(6.2)
(4.4)
0.7
31.0
244.5
3.5
248.0
594.2
224.5
131.5
35.5
391.5
$
$
(a)
In 2021, Wygen I experienced an unplanned outage which resulted in lost revenue. A claim for these losses was submitted under our
business interruption insurance policy. During the third quarter of 2023, we recovered $5.0 million from our business interruption
insurance which was recognized as Revenue. See Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K for further information.
(b)
Primarily driven by favorable mining contract pricing and increased Black Hills Colorado IPP fired-engine hours.
Operations and maintenance expense decreased primarily due to a one-time $7.7 million gain on the planned sale of Northern
Iowa Windpower assets, a $3.9 million gain on a strategic sale of land in Wyoming to a customer to support continued load
growth, and $2.9 million of lower outside services expenses partially offset by $8.7 million of higher employee-related expenses.
Depreciation and amortization increased primarily due to higher asset base driven by prior and current year capital expenditures.
Taxes - property and production were comparable to the same period in the prior year.
Operating Statistics
For the year ended December 31,
Residential
Commercial
Industrial
Municipal
Subtotal Retail Revenue - Electric
Contract Wholesale
Off-system/Power Marketing Wholesale
Other (a)
Total Regulated
Non-Regulated (b)
Total Revenue and Quantities Sold
Other Uses, Losses or Generation, net (c)
Total Energy
$
$
Revenue (in millions)
2022
2023
2021
224.9 $
259.8
159.4
17.5
661.6
22.0
42.5
91.2
817.3
47.7
865.0 $
246.7 $
277.9
166.4
20.5
711.5
25.9
48.6
66.2
852.2
48.0
900.2 $
244.6
276.0
149.0
19.1
688.7
16.1
41.7
54.2
800.7
41.5
842.2
Quantities Sold (GWh)
2022
2023
2021
1,438.5
2,074.4
2,094.8
150.9
5,758.6
579.1
737.9
-
7,075.6
120.6
7,196.2
463.5
7,659.7
1,513.1
2,087.8
1,912.5
159.3
5,672.7
654.0
643.2
-
6,969.9
293.0
7,262.9
450.0
7,712.9
1,494.0
2,075.7
1,751.4
162.9
5,484.0
574.1
638.9
-
6,697.0
269.6
6,966.6
475.3
7,441.9
(a)
(b)
(c)
Primarily related to transmission revenues from the Common Use System.
Includes Integrated Generation and non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech
Services.
Includes company uses and line losses.
For the year ended December 31,
Colorado Electric
South Dakota Electric
Wyoming Electric
Integrated Generation
Total Revenue and Quantities Sold
Revenue (in millions)
2022
2023
2021
Quantities Sold (GWh)
2022
2021
2023
$
$
285.7 $
321.1
212.2
46.0
865.0 $
321.1 $
335.2
197.7
46.2
900.2 $
302.9
319.4
180.4
39.5
842.2
2,397.2
2,554.3
2,124.1
120.6
7,196.2
2,440.0
2,626.2
1,903.7
293.0
7,262.9
2,574.0
2,389.4
1,733.6
269.6
6,966.6
Quantities Generated and Purchased by Fuel Type (GWh)
Generated:
Coal
Natural Gas
Wind (a)
(in millions)
Total Generated
Purchased:
Coal, Natural Gas, Diesel Oil and Other Market Purchases
Wind and Solar
Total Purchased
Total Generated and Purchased
For the year ended December 31,
2022
2023
2021
2,683.4
2,021.4
678.5
5,383.3
1,842.9
433.5
2,276.4
7,659.7
2,708.8
1,454.2
875.8
5,038.8
2,280.8
393.3
2,674.1
7,712.9
(a) Wind generation decreased due to the sale of Northern Iowa Windpower assets in March 2023.
Quantities Generated and Purchased (GWh)
Generated:
For the year ended December 31,
2022
2021
2023
Colorado Electric
South Dakota Electric
Wyoming Electric
Integrated Generation
Total Generated
Purchased:
Colorado Electric
South Dakota Electric
Wyoming Electric
Integrated Generation
Total Purchased
Total Generated and Purchased
653.9
2,018.5
908.3
1,802.5
5,383.2
588.2
604.6
1,028.5
55.2
2,276.5
7,659.7
474.4
1,890.0
905.8
1,768.6
5,038.8
1,005.4
826.4
757.2
85.1
2,674.1
7,712.9
2,546.9
1,817.2
842.6
5,206.7
1,866.4
368.8
2,235.2
7,441.9
412.1
1,980.7
883.6
1,842.4
5,118.8
1,027.7
563.6
643.9
87.9
2,323.1
7,441.9
41
10-KFORM 10-K |
Degree Days
Heating Degree Days:
Colorado Electric
South Dakota Electric
Wyoming Electric
Combined (a)
Cooling Degree Days:
Colorado Electric
South Dakota Electric
Wyoming Electric
Combined (a)
2023
For the year ended December 31,
2022
2021
Actual
Variance from
Normal
Actual
Variance from
Normal
Actual
Variance from
Normal
5,330
6,969
6,783
6,185
1,046
497
329
713
1%
(4)%
(1)%
(1)%
(10)%
(21)%
(30)%
(15)%
5,551
7,495
7,051
6,518
1,362
814
701
1,040
9%
6%
3%
6%
9%
27%
47%
18%
5,023
6,819
6,702
5,974
1,245
827
604
973
(11)%
(5)%
(6)%
(7)%
39%
30%
74%
40%
(a)
Degree days are calculated based on a weighted average of total customers by state.
Contracted generating facilities availability by fuel type (a)
Coal
Natural gas and diesel oil
Wind
Total availability
Wind Capacity Factor
For the year ended December 31,
2021
2022
2023
86.7%
91.5%
93.7%
95.5%
96.1%
92.1%
95.8%
93.7%
92.5%
93.2%
94.4%
92.6%
37.4%
34.7%
34.0%
(a)
Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
Gas Utilities
Operating results for the years ended December 31 for the Gas Utilities were as follows (in millions):
2023
2022
2023 vs 2022
Variance
2021
2022 vs 2021
Variance
Revenue:
Natural gas - regulated
Other - non-regulated services
$
Total revenue
1,399.1 $
85.1
1,484.2
1,584.6 $
84.5
1,669.1
(185.5) $
0.6
(184.9)
1,051.6 $
73.3
1,124.9
Cost of natural gas sold:
Natural gas - regulated
Other - non-regulated services
Total cost of natural gas sold
Gas Utility margin (non-GAAP)
Operations and maintenance
Depreciation and amortization
Taxes - property and production
760.2
23.0
783.2
701.0
328.7
113.9
29.6
472.2
942.1
23.0
965.1
704.0
317.3
114.7
27.8
459.8
(181.9)
—
(181.9)
(3.0)
11.4
(0.8)
1.8
12.4
480.3
14.4
494.7
630.2
290.2
104.2
24.6
419.0
Operating income
$
228.8 $
244.2 $
(15.4) $
211.2 $
533.0
11.2
544.2
461.8
8.6
470.4
73.8
27.1
10.5
3.2
40.8
33.0
42
10-K| FORM 10-K
(a)
Degree days are calculated based on a weighted average of total customers by state.
Contracted generating facilities availability by fuel type (a)
5,330
6,969
6,783
6,185
1,046
497
329
713
1%
(4)%
(1)%
(1)%
(10)%
(21)%
(30)%
(15)%
5,551
7,495
7,051
6,518
1,362
814
701
1,040
9%
6%
3%
6%
9%
27%
47%
18%
5,023
6,819
6,702
5,974
1,245
827
604
973
(11)%
(5)%
(6)%
(7)%
39%
30%
74%
40%
2021
86.7%
95.5%
95.8%
93.2%
34.0%
For the year ended December 31,
2023
93.7%
92.1%
92.5%
92.6%
37.4%
2022
91.5%
96.1%
93.7%
94.4%
34.7%
(a)
Availability and Wind Capacity Factor are calculated using a weighted average based on capacity of our generating fleet.
Heating Degree Days:
Colorado Electric
South Dakota Electric
Wyoming Electric
Combined (a)
Cooling Degree Days:
Colorado Electric
South Dakota Electric
Wyoming Electric
Combined (a)
Coal
Wind
Natural gas and diesel oil
Total availability
Wind Capacity Factor
Gas Utilities
Revenue:
Operating results for the years ended December 31 for the Gas Utilities were as follows (in millions):
2023
2022
2023 vs 2022
Variance
2021
2022 vs 2021
Variance
Natural gas - regulated
$
Other - non-regulated services
Total revenue
1,399.1 $
85.1
1,484.2
1,584.6 $
84.5
1,669.1
(185.5) $
0.6
(184.9)
1,051.6 $
73.3
1,124.9
Cost of natural gas sold:
Natural gas - regulated
Other - non-regulated services
Total cost of natural gas sold
Gas Utility margin (non-GAAP)
Operations and maintenance
Depreciation and amortization
Taxes - property and production
760.2
23.0
783.2
701.0
328.7
113.9
29.6
472.2
942.1
23.0
965.1
704.0
317.3
114.7
27.8
459.8
(181.9)
—
(181.9)
(3.0)
11.4
(0.8)
1.8
12.4
480.3
14.4
494.7
630.2
290.2
104.2
24.6
419.0
Operating income
$
228.8 $
244.2 $
(15.4) $
211.2 $
533.0
11.2
544.2
461.8
8.6
470.4
73.8
27.1
10.5
3.2
40.8
33.0
Degree Days
2023
2022
2021
Gas Utility margin decreased over the prior year as a result of:
For the year ended December 31,
Variance from
Variance from
Variance from
Actual
Normal
Actual
Normal
Actual
Normal
2023 Compared to 2022
New rates and rider recovery
Retail customer growth and demand
Weather
Prior year true-up of Winter Storm Uri carrying costs (a)
Mark-to-market on non-utility natural gas commodity contracts
Other
(in millions)
19.8
7.6
(14.5)
(10.3)
(3.5)
(2.1)
(3.0)
$
$
(a)
In certain jurisdictions, we have commission approval to recover carrying costs on Winter Storm Uri regulatory assets which offset
increased interest expense. Additionally, the carrying costs accrued during the year ended December 31, 2022 included a one-time, $10.3
million true-up to reflect commission authorized rates.
Operations and maintenance expense increased primarily due to $14.8 million of higher employee-related expenses partially
offset by $5.0 million of lower outside services expenses.
Depreciation and amortization was comparable to the prior year.
Taxes - property and production were comparable to the prior year.
Operating Statistics
Revenue
(in millions)
For the year ended December 31,
2021
2022
2023
Quantities Sold and Transported
(Dth in millions)
For the year ended December 31,
2021
2022
2023
Residential
Commercial
Industrial
Other
Total Distribution
$
839.2 $
340.1
33.2
9.1
1,221.6
940.2 $
398.6
63.0
8.7
1,410.5
Transportation and Transmission
177.5
174.1
613.5
242.1
33.4
3.8
892.8
158.8
Total Regulated
1,399.1
1,584.6
1,051.6
Non-regulated Services (a)
85.1
84.5
73.3
60.1
29.4
5.7
—
95.2
159.8
255.0
—
Total Revenue and Quantities Sold$
1,484.2 $
1,669.1 $
1,124.9
255.0
66.9
32.4
7.7
—
107.0
160.9
267.9
—
267.9
60.1
29.1
6.2
—
95.4
154.6
250.0
—
250.0
(a)
Includes Black Hills Energy Services and non-regulated services under the Service Guard Comfort Plan, Tech Services and HomeServe.
Revenue
(in millions)
For the year ended December 31,
2021
2022
2023
Quantities Sold and Transported
(Dth in millions)
For the year ended December 31,
2021
2022
2023
$
Arkansas Gas
Colorado Gas
Iowa Gas
Kansas Gas
Nebraska Gas
Wyoming Gas
Total Revenue and Quantities Sold$
268.9 $
313.6
213.6
155.6
366.1
166.4
1,484.2 $
311.3 $
320.9
283.9
191.4
384.8
176.8
1,669.1 $
218.5
208.0
171.7
121.6
273.4
131.7
1,124.9
30.2
32.8
37.9
35.5
82.2
36.4
255.0
32.3
34.3
40.9
38.6
85.1
36.7
267.9
31.5
32.3
38.0
34.5
81.0
32.7
250.0
43
10-KFORM 10-K |
Heating Degree Days
Arkansas Gas (a)
Colorado Gas
Iowa Gas
Kansas Gas (a)
Nebraska Gas
Wyoming Gas
Combined (b)
2023
For the year ended December 31,
2022
2021
Actual
3,197
5,916
5,921
4,387
5,579
7,385
6,006
Variance From
Normal
(17)%
(4)%
(12)%
(8)%
(8)%
8%
(4)%
Actual
3,844
6,325
7,037
4,968
6,220
7,644
6,536
Variance From
Normal
2%
4%
7%
7%
4%
12%
5%
Actual
3,565
5,866
6,239
4,508
5,599
7,074
5,948
Variance From
Normal
(12)%
(11)%
(8)%
(8)%
(9)%
(7)%
(8)%
(a)
(b)
Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on Gas Utility margins.
Heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather
normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November
through April.
Corporate and Other
Corporate and Other operating results, including inter-segment eliminations, for the years ended December 31 were as follows:
(in millions)
Operating (loss)
2023 Compared to 2022
2023
2022
2023 vs 2022
Variance
2021
2022 vs 2021
Variance
$
(4.9) $
(3.3) $
(1.6) $
(4.5) $
1.2
Operating (loss) was comparable to the prior year.
Consolidated Interest Expense, Other Income (Expense) and Income Tax (Expense)
(in millions)
Interest expense, net
Other income (expense), net
Income tax (expense)
2023 Compared to 2022
$
2023
2022
(167.9) $
(3.2)
(25.6)
(161.0) $
1.8
(25.2)
2023 vs 2022
Variance
2021
2022 vs 2021
Variance
(6.9) $
(5.0)
(0.4)
(152.4) $
1.4
(7.2)
(8.6)
0.4
(18.0)
Interest expense, net increased due to higher interest rates partially offset by increased interest income on higher cash and cash
equivalents balances.
Other (expense), net increased primarily due to higher benefit plan non-service costs driven by higher discount rates and higher
costs for our non-qualified deferred compensation plan which were driven by market performance.
Income tax (expense) and the effective tax rate were comparable to the same period in the prior year. The effective tax rate was
8.5% for both 2023 and 2022. The effective tax rate was comparable primarily due to a $8.2 million tax benefit from a current
year Nebraska income tax rate decrease offset by $6.5 million of lower tax benefits from various current and prior year state tax
rate changes and $3.6 million of lower wind PTCs resulting from the March 2023 sale of Northern Iowa Windpower assets. See
Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.
OVERVIEW
Liquidity and Capital Resources
Our company requires significant cash to support and grow our businesses. Our primary sources of cash are generated from our
operating activities, Revolving Credit Facility, CP Program, ATM and ability to access the public and private capital markets
through debt and equity securities offerings when necessary. This cash is used for, among other things, working capital, capital
expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations
and redemption of outstanding debt and equity securities when required or financially appropriate.
We experience significant cash requirements during peak months of the winter heating season due to higher natural gas
consumption, during periods of high natural gas prices, and during the construction season, which typically peaks in spring and
summer.
44
10-K| FORM 10-K
Heating Degree Days
Actual
Normal
Actual
Normal
Actual
Arkansas Gas (a)
Colorado Gas
Iowa Gas
Kansas Gas (a)
Nebraska Gas
Wyoming Gas
Combined (b)
3,197
5,916
5,921
4,387
5,579
7,385
6,006
(17)%
(4)%
(12)%
(8)%
(8)%
8%
(4)%
3,844
6,325
7,037
4,968
6,220
7,644
6,536
2%
4%
7%
7%
4%
12%
5%
3,565
5,866
6,239
4,508
5,599
7,074
5,948
Normal
(12)%
(11)%
(8)%
(8)%
(9)%
(7)%
(8)%
(a)
(b)
Arkansas and Kansas have weather normalization mechanisms that mitigate the weather impact on Gas Utility margins.
Heating degree days are calculated based on a weighted average of total customers by state excluding Kansas due to its weather
normalization mechanism. Arkansas Gas is partially excluded based on the weather normalization mechanism in effect from November
Corporate and Other operating results, including inter-segment eliminations, for the years ended December 31 were as follows:
2023
2022
2023 vs 2022
Variance
2021
2022 vs 2021
Variance
$
(4.9) $
(3.3) $
(1.6) $
(4.5) $
1.2
Operating (loss) was comparable to the prior year.
Consolidated Interest Expense, Other Income (Expense) and Income Tax (Expense)
through April.
Corporate and Other
(in millions)
Operating (loss)
2023 Compared to 2022
(in millions)
Interest expense, net
Other income (expense), net
Income tax (expense)
2023 Compared to 2022
equivalents balances.
Interest expense, net increased due to higher interest rates partially offset by increased interest income on higher cash and cash
Other (expense), net increased primarily due to higher benefit plan non-service costs driven by higher discount rates and higher
costs for our non-qualified deferred compensation plan which were driven by market performance.
Income tax (expense) and the effective tax rate were comparable to the same period in the prior year. The effective tax rate was
8.5% for both 2023 and 2022. The effective tax rate was comparable primarily due to a $8.2 million tax benefit from a current
year Nebraska income tax rate decrease offset by $6.5 million of lower tax benefits from various current and prior year state tax
rate changes and $3.6 million of lower wind PTCs resulting from the March 2023 sale of Northern Iowa Windpower assets. See
Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.
Liquidity and Capital Resources
OVERVIEW
summer.
Our company requires significant cash to support and grow our businesses. Our primary sources of cash are generated from our
operating activities, Revolving Credit Facility, CP Program, ATM and ability to access the public and private capital markets
through debt and equity securities offerings when necessary. This cash is used for, among other things, working capital, capital
expenditures, dividends, pension funding, investments in or acquisitions of assets and businesses, payment of debt obligations
and redemption of outstanding debt and equity securities when required or financially appropriate.
We experience significant cash requirements during peak months of the winter heating season due to higher natural gas
consumption, during periods of high natural gas prices, and during the construction season, which typically peaks in spring and
For the year ended December 31,
2023
2022
2021
Variance From
Variance From
Variance From
We believe that our cash on hand, operating cash flows, existing borrowing capacity and ability to complete new debt and equity
financings, taken in their entirety, provide sufficient capital resources to fund our ongoing operating requirements, regulatory
liabilities, debt maturities, anticipated dividends, and anticipated capital expenditures discussed in this section.
The following table provides an informational summary of our liquidity and capital structure as of December 31 (dollars in
millions):
Cash and cash equivalents
Available capacity under Revolving Credit Facility and CP Program (a)
Available liquidity
Capital structure
Short-term debt
Long-term debt
Total debt
Total stockholders' equity (excludes non-controlling interest)
Total capitalization
Debt to capitalization
Net debt to capitalization (b)
Long-term debt to total debt
$
$
$
$
2023
2022
86.6
746.3
832.9
600.0
3,801.2
4,401.2
3,215.3
7,616.5
$
$
$
$
57.8%
57.3%
86.4%
21.4
189.8
211.2
1,060.6
3,607.3
4,667.9
2,994.9
7,662.8
60.9%
60.8%
77.3%
(a)
(b)
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 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for
more information.
Net debt to capitalization ratio is net of Cash and cash equivalents for both Total debt and Total capitalization.
$
2023
2022
(167.9) $
(3.2)
(25.6)
(161.0) $
1.8
(25.2)
2023 vs 2022
Variance
2021
2022 vs 2021
Variance
(6.9) $
(5.0)
(0.4)
(152.4) $
1.4
(7.2)
(8.6)
0.4
(18.0)
CASH FLOW ACTIVITIES
The following tables summarize our cash flows for the years ended December 31 (in millions):
Operating Activities:
Net income
Non-cash adjustments to Net income
Total earnings
Changes in certain operating assets and liabilities:
Accounts receivable and other current assets
Accounts payable and accrued liabilities
Regulatory assets and liabilities
Net inflow (outflow) from changes in certain operating assets
and liabilities
2023 vs
2022
2021
2022 vs
2021
2023
2022
$
276.0 $
313.5
589.5
270.8 $
295.7
566.5
5.2 $
17.8
23.0
251.2 $
276.6
527.8
255.9
(109.9)
236.8
382.8
(259.9)
89.4
203.9
33.4
515.8
(199.3)
32.9
349.4
(78.9)
10.6
(524.2)
(592.5)
19.6
19.1
38.7
(181.0)
78.8
728.1
625.9
(15.2)
649.4
Other operating activities
Net cash provided by (used in) operating activities
(27.9)
944.4 $
$
(15.1)
584.8 $
(12.8)
359.6 $
0.1
(64.6) $
2023 Compared to 2022
Net cash provided by operating activities was $359.6 million higher which was attributable to:
•
•
Total earnings (net income plus non-cash adjustments) were $23.0 million higher than prior year primarily as a result
of increased Electric and Gas Utility margins due to new rates and increased rider revenues partially offset by higher
operating expenses and higher interest expense.
Net inflows from changes in certain operating assets and liabilities were $349.4 million higher than prior year,
primarily attributable to:
Cash inflows increased by approximately $515.8 million as a result of changes in accounts receivable and
other current assets primarily due to higher collections on pass-through revenues and lower natural gas in
storage inventories driven by fluctuations in commodity prices and timing of injections and withdrawals;
45
10-KFORM 10-K |
Cash outflows increased by approximately $199.3 million as a result of decreases in accounts payable and
other current liabilities primarily driven by fluctuations in commodity prices, payment timing of natural gas
and power purchases and changes in other working capital requirements; and
Cash inflows increased by approximately $32.9 million as a result of changes in our regulatory assets and
liabilities primarily due to higher recoveries of deferred gas and fuel cost adjustments driven by fluctuations
in commodity prices.
•
Cash outflows increased $12.8 million from other operating activities primarily due to higher costs from cloud
computing arrangements.
Investing Activities:
2023
2022
2023 vs 2022
2021
Capital expenditures
Other investing activities
Net cash (used in) investing activities
$
$
(555.6) $
18.9
(536.7) $
(604.4) $
0.5
(603.9) $
48.8 $
18.4
67.2 $
2023 Compared to 2022
Net cash used in investing activities was $67.2 million lower which was attributable to:
(677.5) $
13.3
(664.2) $
2022 vs 2021
73.1
(12.8)
60.3
•
•
Cash outflows from capital expenditures (which are net of $33.8 million contributions in aid of construction)
decreased $48.8 million as a result of lower programmatic safety, reliability and integrity spending at our Gas and
Electric Utilities and higher receipts related to contributions in aid of construction driven by strategic projects in
Wyoming;
Cash inflows increased $18.4 million for other investing activities primarily due to proceeds from the sale of Northern
Iowa Windpower assets and the strategic sale of land in Wyoming.
Financing Activities:
2023
2022
2023 vs 2022
2021
Dividends paid on common stock
Common stock issued
Short-term and long-term debt (repayments), net
Distributions to non-controlling interests
Other financing activities
Net cash provided by (used in) financing activities $
$
(168.1) $
118.3
(260.6)
(18.3)
(13.0)
(341.7) $
(156.7) $
90.1
115.4
(17.4)
0.9
32.3 $
(11.4) $
28.2
(376.0)
(0.9)
(13.9)
(374.0) $
2023 Compared to 2022
Net cash used in financing activities was $374.0 million higher which was primarily attributable to:
(145.0) $
119.0
777.7
(15.7)
(4.1)
731.9 $
2022 vs 2021
(11.7)
(28.9)
(662.3)
(1.7)
5.0
(699.6)
•
•
•
•
Cash outflows increased $11.4 million due to increased dividends paid on common stock;
Cash inflows increased $28.2 million due to higher issuances of common stock;
Net outflows from changes in short-term and long-term debt (repayments) borrowings increased $376.0 million due
to:
Cash outflows increased $651.0 million as a result of net repayment activity under our Revolving Credit
Facility and CP Program;
Cash outflow of $525.0 million due to repayment of our senior unsecured notes on their November 30, 2023
maturity date; and
Cash inflow of $800.0 million from the March 7, 2023 and September 15, 2023 debt offerings.
Cash outflows increased by $13.9 million for other financing activities primarily due to financing costs from the
March 7, 2023 and September 15, 2023 debt offerings.
46
10-K| FORM 10-K
Cash outflows increased by approximately $199.3 million as a result of decreases in accounts payable and
other current liabilities primarily driven by fluctuations in commodity prices, payment timing of natural gas
and power purchases and changes in other working capital requirements; and
Cash inflows increased by approximately $32.9 million as a result of changes in our regulatory assets and
liabilities primarily due to higher recoveries of deferred gas and fuel cost adjustments driven by fluctuations
in commodity prices.
CAPITAL RESOURCES
Shelf Registration Statement
We maintain an effective shelf registration statement with the SEC under which we may issue, from time to time, an unspecified
amount of senior debt securities, subordinate debt securities, common stock, preferred stock, warrants and other securities. See
Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for recent updates regarding our
shelf registration statement.
Cash outflows increased $12.8 million from other operating activities primarily due to higher costs from cloud
Short-term Debt
We have a $750 million Revolving Credit Facility that matures on July 19, 2026, with two one-year extension options (subject to
consent from lenders). 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. We
also have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding
under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million.
The Revolving Credit Facility prohibits us from paying cash dividends if a default or an event of default exists prior to, or would
result after, paying a dividend. Although these contractual restrictions exist, we do not anticipate triggering any default measures
or restrictions.
The Revolving Credit Facility contains cross-default provisions that could result in a default under such agreements if BHC or its
material subsidiaries failed to 1) make timely payments of debt obligations; or 2) triggered other default provisions under any
debt agreement totaling, in the aggregate principal amount of $50 million or more that permit the acceleration of debt maturities
or mandatory debt prepayment.
See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for more information on our
Revolving Credit Facility and CP Program.
Cash inflows increased $18.4 million for other investing activities primarily due to proceeds from the sale of Northern
Iowa Windpower assets and the strategic sale of land in Wyoming.
Utility Money Pool
As a utility holding company, we are required to establish a cash management program to address lending and borrowing
activities between our utilities and the Company. We have established utility money pool agreements which address these
requirements. These agreements are on file with the FERC and appropriate state regulators. Under the utility money pool
agreements, our utilities may, at their option, borrow and extend short-term loans to the utility money pool at market-based rates.
While the utility money pool may borrow funds from the Company (as ultimate parent company), the money pool arrangement
does not allow loans from our utility subsidiaries to the Company (as ultimate parent company) or to non-regulated affiliates.
Long-term Debt
For information on our long-term debt, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K.
Covenant Requirements
The Revolving Credit Facility and Wyoming Electric’s financing agreements contain covenant requirements. We were in
compliance with these covenants as of December 31, 2023. See additional information in Note 8 of the Notes to Consolidated
Financial Statements in this Annual Report on Form 10-K.
Equity
For information regarding equity, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form
10-K.
Cash outflows increased $651.0 million as a result of net repayment activity under our Revolving Credit
Future Financing Plans
We will continue to assess debt and equity needs to support our capital investment plans and other strategic objectives. 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, debt offerings, the issuance of common stock
under our ATM program or in an opportunistic block trade. We also plan to re-finance our $600 million, 1.0375%, senior
unsecured notes due August 2024, at or before maturity date.
47
•
•
•
•
•
•
•
computing arrangements.
Investing Activities:
Capital expenditures
Other investing activities
Net cash (used in) investing activities
2023 Compared to 2022
2023
2022
2023 vs 2022
2021
2022 vs 2021
$
$
(555.6) $
(604.4) $
18.9
0.5
(536.7) $
(603.9) $
48.8 $
18.4
67.2 $
(677.5) $
13.3
(664.2) $
73.1
(12.8)
60.3
Net cash used in investing activities was $67.2 million lower which was attributable to:
Cash outflows from capital expenditures (which are net of $33.8 million contributions in aid of construction)
decreased $48.8 million as a result of lower programmatic safety, reliability and integrity spending at our Gas and
Electric Utilities and higher receipts related to contributions in aid of construction driven by strategic projects in
Wyoming;
Financing Activities:
Dividends paid on common stock
Common stock issued
Short-term and long-term debt (repayments), net
Distributions to non-controlling interests
Other financing activities
2023
2022
2023 vs 2022
2021
2022 vs 2021
$
(168.1) $
(156.7) $
(11.4) $
(145.0) $
118.3
(260.6)
(18.3)
(13.0)
90.1
115.4
(17.4)
0.9
28.2
(376.0)
(0.9)
(13.9)
119.0
777.7
(15.7)
(4.1)
(11.7)
(28.9)
(662.3)
(1.7)
5.0
(699.6)
Net cash provided by (used in) financing activities $
(341.7) $
32.3 $
(374.0) $
731.9 $
2023 Compared to 2022
Net cash used in financing activities was $374.0 million higher which was primarily attributable to:
Cash outflows increased $11.4 million due to increased dividends paid on common stock;
Cash inflows increased $28.2 million due to higher issuances of common stock;
Net outflows from changes in short-term and long-term debt (repayments) borrowings increased $376.0 million due
to:
Facility and CP Program;
maturity date; and
Cash outflow of $525.0 million due to repayment of our senior unsecured notes on their November 30, 2023
Cash inflow of $800.0 million from the March 7, 2023 and September 15, 2023 debt offerings.
Cash outflows increased by $13.9 million for other financing activities primarily due to financing costs from the
March 7, 2023 and September 15, 2023 debt offerings.
10-KFORM 10-K | CREDIT RATINGS
Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the
cost and availability of external funds through both short and long-term financing. In order to operate and grow our business, we
need to consistently maintain the ability to raise capital on favorable terms. Access to funds is dependent upon factors such as
general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows
from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and
credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing
market rates for companies with comparable credit ratings. We note that credit ratings are not recommendations to buy, sell, or
hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be
evaluated independently of any other rating.
The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2023:
Rating Agency
S&P (a)
Moody’s (b)
Fitch (c)
Senior Unsecured Rating
BBB+
Baa2
BBB+
Outlook
Stable
Stable
Stable
(a)
(b)
(c)
On February 17, 2023, S&P reported BBB+ rating and maintained a Stable outlook.
On December 21, 2023, Moody's reported our Baa2 rating and maintained a Stable outlook.
On January 26, 2024, Fitch reported BBB+ rating and revised to a Negative outlook.
Certain fees and interest rates under our Revolving Credit Facility are based on our credit ratings at all three rating agencies. If
all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates
will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will
be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level
below. Therefore, if Fitch or S&P downgrades our senior unsecured debt, we will be required to pay higher fees and interest
rates under our Revolving Credit Facility.
The following table represents the credit ratings of South Dakota Electric at December 31, 2023:
S&P (a)
Fitch (b)
Rating Agency
(a)
(b)
On February 17, 2023, S&P reported A rating
On January 26, 2024, Fitch reported A rating
Senior Secured Rating
A
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.
CAPITAL REQUIREMENTS
Capital Expenditures
Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital
expenditure program during the next five years. See above in Key Elements of our Business Strategy for forecasted capital
expenditure requirements. A significant portion of our capital expenditures are for safety, reliability and integrity of our system
and is included in utility rate base and eligible for recovery from our utility customers with regulatory approval. Those capital
expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.
Our historical capital expenditures by reportable segment are shown in Note 16 of the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K.
Repayments of Indebtedness
For information relating to repayments of our short- and long-term debt and associated interest payments, see Note 8 of the
Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
48
10-K| FORM 10-K Financing for operational needs and capital expenditure requirements, not satisfied by operating cash flows, depends upon the
cost and availability of external funds through both short and long-term financing. In order to operate and grow our business, we
need to consistently maintain the ability to raise capital on favorable terms. Access to funds is dependent upon factors such as
general economic and capital market conditions, regulatory authorizations and policies, the Company’s credit ratings, cash flows
from routine operations and the credit ratings of counterparties. After assessing the current operating performance, liquidity and
credit ratings of the Company, management believes that the Company will have access to the capital markets at prevailing
market rates for companies with comparable credit ratings. We note that credit ratings are not recommendations to buy, sell, or
hold securities and may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be
evaluated independently of any other rating.
The following table represents the credit ratings, outlook and risk profile of BHC at December 31, 2023:
Rating Agency
Senior Unsecured Rating
BBB+
Baa2
BBB+
Outlook
Stable
Stable
Stable
S&P (a)
Moody’s (b)
Fitch (c)
(a)
(b)
(c)
On February 17, 2023, S&P reported BBB+ rating and maintained a Stable outlook.
On December 21, 2023, Moody's reported our Baa2 rating and maintained a Stable outlook.
On January 26, 2024, Fitch reported BBB+ rating and revised to a Negative outlook.
Certain fees and interest rates under our Revolving Credit Facility are based on our credit ratings at all three rating agencies. If
all of our ratings are at the same level, or if two of our ratings are the same level and one differs, these fees and interest rates
will be based on the ratings that are at the same level. If all of our ratings are at different levels, these fees and interest rates will
be based on the middle level. Currently, our Fitch and S&P ratings are at the same level, and our Moody’s rating is one level
below. Therefore, if Fitch or S&P downgrades our senior unsecured debt, we will be required to pay higher fees and interest
rates under our Revolving Credit Facility.
The following table represents the credit ratings of South Dakota Electric at December 31, 2023:
S&P (a)
Fitch (b)
(a)
(b)
On February 17, 2023, S&P reported A rating
On January 26, 2024, Fitch reported A rating
CAPITAL REQUIREMENTS
Capital Expenditures
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.
Capital expenditures are a substantial portion of our cash requirements each year and we continue to forecast a robust capital
expenditure program during the next five years. See above in Key Elements of our Business Strategy for forecasted capital
expenditure requirements. A significant portion of our capital expenditures are for safety, reliability and integrity of our system
and is included in utility rate base and eligible for recovery from our utility customers with regulatory approval. Those capital
expenditures also earn a rate of return authorized by the commissions in the jurisdictions in which we operate.
Our historical capital expenditures by reportable segment are shown in Note 16 of the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K.
Repayments of Indebtedness
For information relating to repayments of our short- and long-term debt and associated interest payments, see Note 8 of the
Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
CREDIT RATINGS
Unconditional Purchase Obligations
We have unconditional purchase obligations which include the energy and capacity costs associated with our PPAs,
transmission services agreements, and natural gas capacity, transportation and storage agreements. Additionally, our Gas
Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas
price curves. For additional information. see Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on
Form 10-K.
Defined Benefit Pension Plan
We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The unfunded status of the Pension
Plan is defined as the amount the projected benefit obligation exceeds the plan assets. The unfunded status of the Pension Plan
is $39.4 million as of December 31, 2023, compared to $35.2 million as of December 31, 2022. We do not have required
contributions, however, we expect to make $2.3 million in contributions to our Pension Plan in 2024. See further information in
Note 13 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Common Stock Dividends
Future cash dividends, if any, will be dependent on our results of operations, financial position, cash flows, reinvestment
opportunities and other factors, and will be evaluated and approved by our Board of Directors.
Additionally, there are certain statutory limitations that could affect future cash dividends paid. Federal law places limits on the
ability of public utilities within a holding company structure to declare dividends. Specifically, under the Federal Power Act, a
public utility may not pay dividends from any funds properly included in a capital account. The utility subsidiaries’ dividends may
be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See additional information in Note
8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
On January 26, 2024, our Board of Directors declared a quarterly dividend of $0.65 per share, equivalent to an annual dividend
rate of $2.60 per share. The table below provides our dividends paid (in millions), dividend payout ratio and dividends paid per
share for the three years ended December 31:
Rating Agency
Senior Secured Rating
A
A
Common Stock Dividends Paid
Dividend Payout Ratio
Dividends Per Share
2023
2022
2021
168.1 $
64%
2.50 $
156.7 $
61%
2.41 $
145.0
61%
2.29
$
$
Our three-year compound annualized dividend growth rate was 4.8%.
Collateral Requirements
Our Utilities maintain wholesale commodity contracts for the purchases and sales of electricity and natural gas which have
performance assurance provisions that allow the counterparty to require collateral postings under certain conditions, including
when requested on a reasonable basis due to a deterioration in our financial condition or nonperformance. A significant
downgrade in our credit ratings, such as a downgrade to a level below investment grade, could result in counterparties requiring
collateral postings under such adequate assurance provisions. The amount of credit support that we may be required to provide
at any point in the future is dependent on the amount of the initial transaction, changes in the market price, open positions and
the amounts owed by or to the counterparty. At December 31, 2023, we had sufficient liquidity to cover collateral that could be
required to be posted under these contracts. The cash collateral we were required to post at December 31, 2023 was not
material. See Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Guarantees
We provide various guarantees, which represent off-balance sheet commitments, supporting certain of our subsidiaries under
specified agreements or transactions. For more information on these guarantees, see Note 3 of the Notes to Consolidated
Financial Statements in this Annual Report on Form 10-K.
49
10-KFORM 10-K |
Critical Accounting Estimates
We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a
particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are
also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make
certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. We
continue to closely monitor the macroeconomic environment and related impacts on our critical accounting estimates including,
but not limited to, collectability of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-
lived assets, and contingent liabilities. These estimates and assumptions affect the reported amounts of assets and liabilities at
the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual
results may differ from our estimates and to the extent there are material differences between these estimates, judgments or
assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the
most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates
and related disclosures with our Audit Committee.
The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description
and Significant Accounting Policies” of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Regulation
Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state
utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our
retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on
an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or
may not match our related costs and allowed return on invested capital at any given time.
Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations
associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders and
historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains
appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.
To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and
purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers,
and a state regulatory commission subsequently determines that such costs should not have been paid by the customers, we
may be required to refund such costs.
As of December 31, 2023 and 2022, we had total regulatory assets of $480.1 million and $653.0 million, respectively, and total
regulatory liabilities of $566.6 million and $518.6 million, respectively. See Note 2 of the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K for further information.
Goodwill
We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that
indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns with our
financial planning process.
Accounting standards for testing goodwill for impairment require the application of either a qualitative or quantitative assessment
to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. Under either
the qualitative or quantitative assessment, the estimated fair value of a reporting unit is compared with its carrying amount,
including goodwill. If the carrying amount exceeds fair value, then an impairment loss would be recognized in an amount equal to
that excess, limited to the amount of goodwill allocated to that reporting unit.
50
10-K| FORM 10-K Critical Accounting Estimates
We prepare our consolidated financial statements in conformity with GAAP. In many cases, the accounting treatment of a
particular transaction is specifically dictated by GAAP and does not require management’s judgment in application. There are
also areas which require management’s judgment in selecting among available GAAP alternatives. We are required to make
certain estimates, judgments and assumptions that we believe are reasonable based upon the information available. We
continue to closely monitor the macroeconomic environment and related impacts on our critical accounting estimates including,
but not limited to, collectability of customer receivables, recoverability of regulatory assets, impairment risk of goodwill and long-
lived assets, and contingent liabilities. These estimates and assumptions affect the reported amounts of assets and liabilities at
the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. Actual
results may differ from our estimates and to the extent there are material differences between these estimates, judgments or
assumptions and actual results, our financial statements will be affected. We believe the following accounting estimates are the
most critical in understanding and evaluating our reported financial results. We have reviewed these critical accounting estimates
and related disclosures with our Audit Committee.
The following discussion of our critical accounting estimates should be read in conjunction with Note 1, “Business Description
and Significant Accounting Policies” of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Regulation
Our regulated Electric and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state
utility commissions. This regulatory treatment does not provide any assurance as to achievement of desired earnings levels. Our
retail electric and gas utility rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on
an analysis of our costs, as reviewed and approved in a regulatory proceeding. The rates that we are allowed to charge may or
may not match our related costs and allowed return on invested capital at any given time.
Management continually assesses the probability of future recoveries associated with regulatory assets and future obligations
associated with regulatory liabilities. Factors such as the current regulatory environment, recently issued rate orders and
historical precedents are considered. As a result, we believe that the accounting prescribed under rate-based regulation remains
appropriate and our regulatory assets are probable of recovery in current rates or in future rate proceedings.
To some degree, each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and
purchased power costs) outside of a base rate review. To the extent we are able to pass through such costs to our customers,
and a state regulatory commission subsequently determines that such costs should not have been paid by the customers, we
may be required to refund such costs.
As of December 31, 2023 and 2022, we had total regulatory assets of $480.1 million and $653.0 million, respectively, and total
regulatory liabilities of $566.6 million and $518.6 million, respectively. See Note 2 of the Notes to Consolidated Financial
Statements in this Annual Report on Form 10-K for further information.
Goodwill
financial planning process.
We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that
indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns with our
Accounting standards for testing goodwill for impairment require the application of either a qualitative or quantitative assessment
to analyze whether or not goodwill has been impaired. Goodwill is tested for impairment at the reporting unit level. Under either
the qualitative or quantitative assessment, the estimated fair value of a reporting unit is compared with its carrying amount,
including goodwill. If the carrying amount exceeds fair value, then an impairment loss would be recognized in an amount equal to
that excess, limited to the amount of goodwill allocated to that reporting unit.
Application of the goodwill impairment test requires judgment, including the identification of reporting units and determining the
fair value of the reporting unit. We have determined that the reporting units for goodwill impairment testing are our operating
segments, or components of an operating segment, that constitute a business for which discrete financial information is available
and for which the CODM regularly reviews the operating results. We estimate the fair value of our reporting units using a
combination of an income approach, which estimates fair value based on discounted future cash flows, and a market approach,
which estimates fair value based on market comparables within the utility and energy industries. These valuations require
significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our internal five-year business
plans and adjusted as appropriate for our view of market participant assumptions, with long range cash flows estimated using a
terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the determination of an appropriate
weighted-average cost of capital or discount rate; and 4) the utilization of market information such as recent sales transactions
for comparable assets within the utility and energy industries. Varying by reporting unit, weighted average cost of capital in the
range of 6.9% to 7.3% and long-term growth rate projections of 1.75% were utilized in the goodwill impairment test performed as
of October 1, 2023. Although 1.75% was used for a long-term growth rate projection, the short-term projected growth rate is
higher with planned recovery of capital investments through rider mechanisms and rate reviews. Under the market approach, we
estimate fair value using multiples derived from comparable sales transactions and enterprise value to EBITDA for comparative
peer companies for each respective reporting unit. These multiples are applied to operating data for each reporting unit to arrive
at an indication of fair value. In addition, we add a reasonable control premium when calculating fair value utilizing the peer
multiples, which is estimated as the premium that would be received in a sale in an orderly transaction between market
participants.
The estimates and assumptions used in our impairment assessments are based on available market information and we believe
they are reasonable. However, variations in any of the assumptions could result in materially different calculations of fair value
and determinations of whether or not an impairment is indicated.
For the years ended December 31, 2023, 2022, and 2021, there were no impairment losses recorded. At December 31, 2023,
the fair value exceeded the carrying value at all reporting units.
See Item 1A - Risk Factors and Note 1 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K
for additional information.
Income Taxes
The Company and its subsidiaries file consolidated federal income tax returns. Each entity records income taxes as if it were a
separate taxpayer for both federal and state income tax purposes and consolidating adjustments are allocated to the
subsidiaries based on separate company computations of taxable income or loss.
The Company uses the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred
income taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the
financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences
are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax
return in a different period than they are reported in the financial statements.
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or
all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. If we determine
that we will be unable to realize all or part of our deferred tax assets in the future, an adjustment to the deferred tax asset would
be made in the period such determination was made. These adjustments may increase or decrease earnings. Although we
believe our assumptions, judgments and estimates are reasonable, changes in tax laws or our interpretations of tax laws and the
resolution of current and any future tax audits could significantly impact the amounts provided for income taxes in our
consolidated financial statements.
See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional information.
51
10-KFORM 10-K | ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our activities in the regulated and non-regulated energy industries 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 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 services, wholesale electric power marketing activities and fuel
procurement for several of our gas-fired generation assets. Market fluctuations may occur due to unpredictable factors
such as the COVID-19 pandemic, weather (e.g. Winter Storm Uri), geopolitical events, market speculation, recession,
inflation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and
Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital
markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.
Credit risk is associated with financial loss resulting from non-performance of contractual obligations by a counterparty.
To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. The
Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee. These policies
relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments,
prohibited activities and employee conduct. We report any issues or concerns pertaining to the Risk Policies and Procedures to
the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets at
least quarterly and as necessary, to review our business and credit activities and to ensure that these activities are conducted
within the authorized policies.
Commodity Price Risk
Electric and Gas Utilities
Our utilities have various provisions that allow them to pass the prudently-incurred cost of energy through to the customer. To
the extent energy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis
to reflect billed amounts to match the actual energy cost we incurred. In Colorado, South Dakota and Wyoming, we have ECA or
PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our tariffs. In
Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming, we have GCA provisions that adjust natural gas rates when our
natural gas costs are higher or lower than the energy cost included in our tariffs. These adjustments are subject to periodic
prudence reviews by the state regulatory commissions. If state regulatory commissions decide to discontinue these tariff-based
adjustment mechanisms, or there are delays in the timing of recovery under these mechanisms, we may be more exposed to
commodity price risk.
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 regulatory 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.
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 utility commission guidelines. When the related costs are recovered
through our rates, the hedging activity is recognized in the Consolidated Statements of Income. See additional information in
Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Wholesale Power
We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load
requirements associated with serving our electric customers that are considered derivative instruments and do not qualify for the
normal purchase and normal sales exception for derivative accounting. Changes in the fair value of these commodity derivatives
are recognized in the Consolidated Statements of Income.
There is a potential risk that our wholesale power sales could exceed our current generating capacity, which may arise from
unplanned plant outages or from unanticipated load demands. To manage such risk, we restrict wholesale off-system sales to
amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load
requirements plus a required reserve margin.
52
10-K| FORM 10-K ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Our activities in the regulated and non-regulated energy industries 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 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 services, wholesale electric power marketing activities and fuel
procurement for several of our gas-fired generation assets. Market fluctuations may occur due to unpredictable factors
such as the COVID-19 pandemic, weather (e.g. Winter Storm Uri), geopolitical events, market speculation, recession,
inflation, pipeline constraints, and other factors that may impact natural gas and electric energy supply and demand; and
Interest rate risk associated with future debt, including reduced access to liquidity during periods of extreme capital
markets volatility, such as the 2008 financial crisis and the COVID-19 pandemic.
Credit risk is associated with financial loss resulting from non-performance of contractual obligations by a counterparty.
To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. The
Black Hills Corporation Risk Policies and Procedures have been approved by our Executive Risk Committee. These policies
relate to numerous matters including governance, control infrastructure, authorized commodities and trading instruments,
prohibited activities and employee conduct. We report any issues or concerns pertaining to the Risk Policies and Procedures to
the Audit Committee of our Board of Directors. The Executive Risk Committee, which includes senior level executives, meets at
least quarterly and as necessary, to review our business and credit activities and to ensure that these activities are conducted
within the authorized policies.
Commodity Price Risk
Electric and Gas Utilities
Our utilities have various provisions that allow them to pass the prudently-incurred cost of energy through to the customer. To
the extent energy prices are higher or lower than amounts in our current billing rates, adjustments are made on a periodic basis
to reflect billed amounts to match the actual energy cost we incurred. In Colorado, South Dakota and Wyoming, we have ECA or
PCA provisions that adjust electric rates when energy costs are higher or lower than the costs included in our tariffs. In
Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming, we have GCA provisions that adjust natural gas rates when our
natural gas costs are higher or lower than the energy cost included in our tariffs. These adjustments are subject to periodic
prudence reviews by the state regulatory commissions. If state regulatory commissions decide to discontinue these tariff-based
adjustment mechanisms, or there are delays in the timing of recovery under these mechanisms, we may be more exposed to
commodity price risk.
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 regulatory 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.
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 utility commission guidelines. When the related costs are recovered
through our rates, the hedging activity is recognized in the Consolidated Statements of Income. See additional information in
Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
Wholesale Power
We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load
requirements associated with serving our electric customers that are considered derivative instruments and do not qualify for the
normal purchase and normal sales exception for derivative accounting. Changes in the fair value of these commodity derivatives
are recognized in the Consolidated Statements of Income.
There is a potential risk that our wholesale power sales could exceed our current generating capacity, which may arise from
unplanned plant outages or from unanticipated load demands. To manage such risk, we restrict wholesale off-system sales to
amounts by which our anticipated generating capabilities and purchased power resources exceed our anticipated load
requirements plus a required reserve margin.
Black Hills Energy Services
To support our Choice Gas Program customers, we buy and sell natural gas 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. A portion of our over-the-counter swaps have been designated
as cash flow hedges to mitigate the commodity price risk associated with fixed price forward contracts to supply 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.
At December 31, 2023 and 2022, a 10% change in market prices for our derivative instruments would not materially impact pre-
tax income, the fair values of our derivative assets and liabilities, or OCI.
See additional commodity risk and derivative information in Note 9 of the Notes to Consolidated Financial Statements in this
Annual Report on Form 10-K.
Interest Rate Risk
Periodically, we have engaged in activities to manage risks associated with changes in interest rates. We have utilized pay-fixed
interest rate swap agreements to reduce exposure to interest rate fluctuations associated with floating rate debt obligations and
anticipated debt refinancings. At December 31, 2023, we had no interest rate swaps in place. Further details of past swap
agreements are set forth in Note 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
At December 31, 2023, over 99% of our debt is fixed rate debt, which limits our exposure to variable interest rate fluctuations. A
hypothetical 100 basis point increase in the benchmark rate on our variable rate debt would have increased annual pretax
interest expense by approximately $0.9 million and $4.1 million for the years ended December 31, 2023 and 2022, respectively.
See Note 8 for further information on cash amounts outstanding under short- and long-term variable rate borrowings.
We are subject to interest rate risk associated with our pension and post-retirement benefit obligations. Changes in interest rates
impact the liabilities associated with these benefit plans as well as the amount of income or expense recognized for these plans.
Declines in the value of the plan assets could diminish the funded status of the pension plans and potentially increase the
requirements to make cash contributions to these plans. See additional information in Note 13 of the Notes to Consolidated
Financial Statements in this Annual Report on Form 10-K.
Credit Risk
We have adopted the Black Hills Corporation Credit Policy that establishes guidelines, controls and limits to manage and
mitigate credit risk within risk tolerances established by the Board of Directors. 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 customer’s
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.
See more information in Notes 1 and 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.
53
10-KFORM 10-K | ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Report on Internal Control Over Financial Reporting
We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-
15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a
process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined
to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of
any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial
Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2023,
based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission “COSO”. This evaluation included review of the documentation of controls,
evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this
evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of
December 31, 2023.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Black Hills Corporation’s financial
statements, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial
reporting as of December 31, 2023. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial
reporting is included herein.
Black Hills Corporation
54
10-K| FORM 10-K ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Report on Internal Control Over Financial Reporting
We are responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-
15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is a
process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined
to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Because
of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of
any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of
changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial
Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2023,
based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission “COSO”. This evaluation included review of the documentation of controls,
evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls and a conclusion on this
evaluation. Based on our evaluation, we have concluded that our internal control over financial reporting was effective as of
December 31, 2023.
Deloitte & Touche LLP, an independent registered public accounting firm, as auditors of Black Hills Corporation’s financial
statements, has issued an attestation report on the effectiveness of Black Hills Corporation's internal control over financial
reporting as of December 31, 2023. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial
reporting is included herein.
Black Hills Corporation
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Black Hills Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Black Hills Corporation and subsidiaries (the "Company") as
of December 31, 2023 and 2022, the related consolidated statements of income, comprehensive income, equity, and cash flows,
for each of the three years in the period ended December 31, 2023, and the related notes (collectively referred to as the
"financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the
Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in
the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of
America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Company's internal control over financial reporting as of December 31, 2023, based on criteria established in
Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated February 14, 2024, expressed an unqualified opinion on the Company's internal control over
financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on
the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are
required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable
rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to
error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included
evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that
was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that
are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and
we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the
accounts or disclosures to which it relates.
Regulatory Accounting — Impact of Rate Regulation on the Financial Statements — Refer to Notes 1 and 2 to the
Financial Statements.
Critical Audit Matter Description
The Company is subject to cost-of-service regulation and earnings oversight by state and federal utility commissions
(collectively, the “Commissions”), which have jurisdiction over the Company’s electric rates in Colorado, Montana, South Dakota
and Wyoming and natural gas rates in Arkansas, Colorado, Iowa, Kansas, Nebraska and Wyoming. Management has
determined it meets the requirements under accounting principles generally accepted in the United States of America to prepare
its financial statements applying the specialized rules to account for the effects of cost-based rate regulation. Accounting for the
economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and
equipment; regulatory assets and liabilities; revenue; operating expenses; and income tax benefit (expense).
55
10-KFORM 10-K | Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the
Company's costs, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of
prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the
future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on
invested capital included in rates and any refunds that may be required. While the Company has indicated its regulatory assets
are probable of recovery in current rates or in future proceedings, there is a risk that the Commissions will not judge all costs to
have been prudently incurred or that the rate regulation process in which rates are determined will not always result in rates that
produce a full recovery of costs and the return on invested capital.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to
support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in
assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the
likelihood of (1) recovery in future rates of incurred costs, and (2) a refund or future rate reduction to be provided to customers.
Given the uncertainty of future decisions by the Commissions, auditing these judgments required specialized knowledge of
accounting for rate regulation and the rate setting process due to its inherent complexities.
How the Critical Audit Matter Was Addressed in the Audit
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•
•
•
•
•
We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future
rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) refunds or future
reductions in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls
over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring
and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future
reduction in rates.
We read relevant regulatory orders issued by the Commissions, filings made by the Company, and other publicly available
information, as appropriate, to assess the likelihood of recovery in future rates or of a future reduction in rates based on
precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external
information and compared it to the Company’s recorded regulatory asset and liability balances for completeness and for
any evidence that might contradict management’s assertions.
We obtained and evaluated an analysis from management regarding probability of recovery for regulatory assets or refund
or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, as applicable, to assess
management’s assertion that amounts are probable of recovery or of a future reduction in rates.
We inspected minutes of the board of directors to identify any evidence that may contradict management’s assertions
regarding probability of recovery or refunds. We also inquired of management regarding current year rate filings and new
regulatory assets or liabilities.
We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and
regulatory developments.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 14, 2024
We have served as the Company's auditor since 2002.
56
10-K| FORM 10-K
Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the
Company's costs, as reviewed and approved in a regulatory proceeding. Rate regulation is premised on the full recovery of
prudently incurred costs and a reasonable rate of return on invested capital. Decisions to be made by the Commissions in the
future will impact the accounting for regulated operations, including decisions about the amount of allowable costs and return on
invested capital included in rates and any refunds that may be required. While the Company has indicated its regulatory assets
are probable of recovery in current rates or in future proceedings, there is a risk that the Commissions will not judge all costs to
have been prudently incurred or that the rate regulation process in which rates are determined will not always result in rates that
produce a full recovery of costs and the return on invested capital.
We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to
support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in
assessing the impact of future regulatory orders on the financial statements. Management judgments include assessing the
likelihood of (1) recovery in future rates of incurred costs, and (2) a refund or future rate reduction to be provided to customers.
Given the uncertainty of future decisions by the Commissions, auditing these judgments required specialized knowledge of
accounting for rate regulation and the rate setting process due to its inherent complexities.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors of Black Hills Corporation
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Black Hills Corporation and subsidiaries (the “Company”) as of
December 31, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee
of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal
Control — Integrated Framework (2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated financial statements as of and for the year ended December 31, 2023, of the Company and our
report dated February 14, 2024, expressed an unqualified opinion on those financial statements.
How the Critical Audit Matter Was Addressed in the Audit
Basis for Opinion
Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:
•
•
•
•
•
We tested the effectiveness of management’s controls over the evaluation of the likelihood of (1) the recovery in future
rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) refunds or future
reductions in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls
over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring
and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future
reduction in rates.
We read relevant regulatory orders issued by the Commissions, filings made by the Company, and other publicly available
information, as appropriate, to assess the likelihood of recovery in future rates or of a future reduction in rates based on
precedents of the Commissions’ treatment of similar costs under similar circumstances. We evaluated the external
information and compared it to the Company’s recorded regulatory asset and liability balances for completeness and for
any evidence that might contradict management’s assertions.
We obtained and evaluated an analysis from management regarding probability of recovery for regulatory assets or refund
or future reduction in rates for regulatory liabilities not yet addressed in a regulatory order, as applicable, to assess
management’s assertion that amounts are probable of recovery or of a future reduction in rates.
We inspected minutes of the board of directors to identify any evidence that may contradict management’s assertions
regarding probability of recovery or refunds. We also inquired of management regarding current year rate filings and new
We evaluated the Company’s disclosures related to the impacts of rate regulation, including the balances recorded and
regulatory assets or liabilities.
regulatory developments.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 14, 2024
We have served as the Company's auditor since 2002.
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report
on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over
financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk
that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the
assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ DELOITTE & TOUCHE LLP
Minneapolis, Minnesota
February 14, 2024
57
10-KFORM 10-K |
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
December 31,
2023
December 31,
2022
(in millions, except per share amounts)
December 31,
2021
Revenue
$
2,331.3 $
2,551.8 $
1,949.1
Operating expenses:
Fuel, purchased power and cost of natural gas sold
Operations and maintenance
Depreciation and amortization
Taxes - property and production
Total operating expenses
Operating income
Other income (expense):
Interest expense incurred net of amounts capitalized
Interest income
Other income (expense), net
Total other income (expense)
Income before income taxes
Income tax (expense)
Net income
Net income attributable to non-controlling interest
Net income available for common stock
Earnings per share of common stock:
Earnings per share, Basic
Earnings per share, Diluted
Weighted average common shares outstanding:
Basic
Diluted
982.9
552.0
256.8
66.9
1,858.6
1,230.6
548.4
250.9
66.7
2,096.6
741.9
501.7
236.0
60.1
1,539.7
472.7
455.2
409.4
(180.0)
12.1
(3.2)
(171.1)
301.6
(25.6)
276.0
(13.8)
262.2 $
(162.6)
1.6
1.8
(159.2)
296.0
(25.2)
270.8
(12.4)
258.4 $
3.91 $
3.91 $
3.98 $
3.97 $
67.0
67.1
64.9
65.0
(154.1)
1.7
1.4
(151.0)
258.4
(7.2)
251.2
(14.5)
236.7
3.74
3.74
63.2
63.3
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
58
10-K| FORM 10-K
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Revenue
Operating expenses:
Fuel, purchased power and cost of natural gas sold
Operations and maintenance
Depreciation and amortization
Taxes - property and production
Total operating expenses
Operating income
Other income (expense):
Interest expense incurred net of amounts capitalized
Interest income
Other income (expense), net
Total other income (expense)
Income before income taxes
Income tax (expense)
Net income
Net income attributable to non-controlling interest
Net income available for common stock
Earnings per share of common stock:
Earnings per share, Basic
Earnings per share, Diluted
Weighted average common shares outstanding:
Basic
Diluted
December 31,
December 31,
December 31,
2023
2022
2021
(in millions, except per share amounts)
$
2,331.3 $
2,551.8 $
1,949.1
Net income
Year ended
December 31,
2023
December 31,
2022
(in millions)
December 31,
2021
$
276.0 $
270.8 $
251.2
Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $0, $(1.5),
and $(0.7), respectively)
Reclassification adjustment of benefit plan liability - net loss (net of tax of
$0, $(0.2), and $(0.7), respectively)
Reclassification adjustment of benefit plan liability - prior service cost (net
of tax of $0, $0, and $0, respectively)
472.7
455.2
409.4
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest
rate swaps (net of tax of $(0.7), $(0.7), and $(0.7), respectively)
Net unrealized gains (losses) on commodity derivatives (net of tax of $1.1,
$0.2, and $(1.0), respectively)
Reclassification of net realized (gains) losses on settled commodity
derivatives (net of tax of $(0.7), $0.7, and $0.5, respectively)
Other comprehensive income (loss), net of tax
(0.3)
0.2
—
2.2
(3.6)
2.3
0.8
4.6
0.5
(0.1)
2.1
(0.6)
(2.0)
4.5
2.0
1.7
(0.1)
2.2
3.0
(1.5)
7.3
Comprehensive income
Less: comprehensive income attributable to non-controlling interest
Comprehensive income available for common stock
276.8
(13.8)
263.0 $
275.3
(12.4)
262.9 $
258.5
(14.5)
244.0
$
See Note 11 for additional disclosures related to Comprehensive Income.
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
982.9
552.0
256.8
66.9
1,858.6
1,230.6
548.4
250.9
66.7
2,096.6
741.9
501.7
236.0
60.1
1,539.7
(180.0)
12.1
(3.2)
(171.1)
301.6
(25.6)
276.0
(13.8)
(162.6)
1.6
1.8
(159.2)
296.0
(25.2)
270.8
(12.4)
262.2 $
258.4 $
3.91 $
3.91 $
3.98 $
3.97 $
67.0
67.1
64.9
65.0
(154.1)
1.7
1.4
(151.0)
258.4
(7.2)
251.2
(14.5)
236.7
3.74
3.74
63.2
63.3
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
59
10-KFORM 10-K |
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash and equivalents
Accounts receivable, net
Materials, supplies and fuel
Derivative assets, current
Income tax receivable, net
Regulatory assets, current
Other current assets
Total current assets
Property, plant and equipment
Less accumulated depreciation and depletion
Total property, plant and equipment, net
Other assets:
Goodwill
Intangible assets, net
Regulatory assets, non-current
Other assets, non-current
Total other assets, non-current
TOTAL ASSETS
As of
December 31,
2023
December 31,
2022
(in millions)
$
$
86.6 $
6.4
350.3
160.9
—
18.5
175.7
28.2
826.6
8,917.2
(1,797.9)
7,119.3
1,299.5
8.4
304.4
62.2
1,674.5
9,620.4 $
21.4
5.6
508.2
207.4
0.6
17.6
260.3
50.6
1,071.7
8,374.8
(1,576.8)
6,798.0
1,299.5
9.6
392.7
46.7
1,748.5
9,618.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
60
10-K| FORM 10-K
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
BLACK HILLS CORPORATION
CONSOLIDATED BALANCE SHEETS
(Continued)
ASSETS
Current assets:
Cash and cash equivalents
Restricted cash and equivalents
Accounts receivable, net
Materials, supplies and fuel
Derivative assets, current
Income tax receivable, net
Regulatory assets, current
Other current assets
Total current assets
Property, plant and equipment
Less accumulated depreciation and depletion
Total property, plant and equipment, net
Other assets:
Goodwill
Intangible assets, net
Regulatory assets, non-current
Other assets, non-current
Total other assets, non-current
TOTAL ASSETS
As of
December 31,
December 31,
2023
2022
(in millions)
$
86.6 $
6.4
350.3
160.9
—
18.5
175.7
28.2
826.6
8,917.2
(1,797.9)
7,119.3
1,299.5
8.4
304.4
62.2
1,674.5
9,620.4 $
21.4
5.6
508.2
207.4
0.6
17.6
260.3
50.6
1,071.7
8,374.8
(1,576.8)
6,798.0
1,299.5
9.6
392.7
46.7
1,748.5
9,618.2
$
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable
Accrued liabilities
Derivative liabilities, current
Regulatory liabilities, current
Notes payable
Current maturities of long-term debt
Total current liabilities
Long-term debt, net of current maturities
Deferred credits and other liabilities:
Deferred income tax liabilities, net
Regulatory liabilities, non-current
Benefit plan liabilities
Other deferred credits and other liabilities
Total deferred credits and other liabilities
Commitments, contingencies and guarantees (Note 3)
Equity:
Stockholders’ equity -
Common stock $1.00 par value; 100,000,000 shares authorized; issued: 68,265,042
and 66,140,396, respectively
Additional paid-in capital
Retained earnings
Treasury stock at cost - 68,073 and 36,726, respectively
Accumulated other comprehensive income (loss)
Total stockholders’ equity
Non-controlling interest
Total equity
As of
December 31,
2023
December 31,
2022
(in millions, except share amounts)
$
186.4 $
293.3
6.5
98.9
—
600.0
1,185.1
3,801.2
548.0
467.7
123.9
188.7
1,328.3
68.3
2,007.7
1,158.2
(4.1)
(14.8)
3,215.3
90.5
3,305.8
310.0
243.5
6.6
46.0
535.6
525.0
1,666.7
3,607.3
508.9
472.6
116.7
156.1
1,254.3
66.1
1,882.7
1,064.1
(2.4)
(15.6)
2,994.9
95.0
3,089.9
TOTAL LIABILITIES AND TOTAL EQUITY
$
9,620.4 $
9,618.2
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
61
10-KFORM 10-K |
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year ended
Operating activities:
Net income
Adjustments to reconcile net income to net cash provided by (used in)
operating activities:
December 31,
2023
December 31,
2022
(in millions)
December 31,
2021
$
276.0 $
270.8 $
251.2
Depreciation, depletion and amortization
Deferred financing cost amortization
Stock compensation
Deferred income taxes
Employee benefit plans
Other adjustments, net
Change in certain operating assets and liabilities:
Materials, supplies and fuel
Accounts receivable and other current assets
Accounts payable and other current liabilities
Regulatory assets
Regulatory liabilities
Other operating activities, net
Net cash provided by (used in) operating activities
Investing activities:
Property, plant and equipment additions
Other investing activities
Net cash (used in) investing activities
Financing activities:
Dividends paid on common stock
Common stock issued
Term Loan - borrowings
Term Loan - repayments
Net borrowings (payments) of Revolving Credit Facility and CP Program
Long-term debt - issuance
Long-term debt - repayments
Distributions to non-controlling interests
Other financing activities
Net cash provided by (used in) financing activities
Net change in cash, restricted cash and cash equivalents
Cash, restricted cash and cash equivalents beginning of year
Cash, restricted cash and cash equivalents end of year
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)
Income taxes
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at December 31
Increase in capitalized assets associated with asset retirement
obligations
$
$
$
$
$
256.8
10.1
7.0
25.4
11.5
2.7
51.4
204.5
(109.9)
236.8
—
(27.9)
944.4
(555.6)
18.9
(536.7)
(168.1)
118.3
—
—
(535.6)
800.0
(525.0)
(18.3)
(13.0)
(341.7)
66.0
27.0
93.0 $
250.9
9.8
8.6
25.6
5.5
(4.7)
(75.4)
(184.5)
89.4
203.9
—
(15.1)
584.8
(604.4)
0.5
(603.9)
(156.7)
90.1
—
—
115.4
—
—
(17.4)
0.9
32.3
13.2
13.8
27.0 $
236.0
7.0
9.7
7.3
9.6
7.0
(35.7)
(43.2)
10.6
(514.7)
(9.5)
0.1
(64.6)
(677.5)
13.3
(664.2)
(145.0)
119.0
800.0
(800.0)
186.1
600.0
(8.4)
(15.7)
(4.1)
731.9
3.1
10.7
13.8
(157.3) $
(1.0) $
(152.5) $
0.8 $
(142.7)
1.5
52.4 $
3.8 $
59.3 $
14.0 $
68.8
2.1
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
62
10-K| FORM 10-K
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF EQUITY
Common Stock
Treasury Stock
(in millions except share amounts)
Balance at December 31, 2020
Net income
Other comprehensive income, net of tax
Dividends on common stock ($2.29 per share)
Share-based compensation
Issuance of common stock
Issuance costs
Distributions to non-controlling interest
Balance at December 31, 2021
Net income
Other comprehensive income, net of tax
Dividends on common stock ($2.41 per share)
Share-based compensation
Issuance of common stock
Issuance costs
Distributions to non-controlling interest
Balance at December 31, 2022
Net income
Other comprehensive income, net of tax
Dividends on common stock ($2.50 per share)
Share-based compensation
Issuance of common stock
Issuance costs
Distributions to non-controlling interest
Balance at December 31, 2023
Shares
62,827,179 $
—
—
—
153,719
1,812,197
—
—
64,793,095 $
—
—
—
39,546
1,307,755
—
—
66,140,396 $
—
—
—
93,257
2,031,389
—
—
68,265,042 $
Value
Shares
Value
Additional
Paid in Capital
Retained
Earnings
AOCI
Non
controlling
Interest
Total
62.8
—
—
—
0.2
1.8
—
—
64.8
—
—
—
—
1.3
—
—
66.1
—
—
—
0.1
2.1
—
—
68.3
32,492 $
—
—
—
21,586
—
—
—
54,078 $
—
—
—
(17,352)
—
—
—
36,726 $
—
—
—
31,347
—
—
—
68,073 $
(2.1) $
—
—
—
(1.4)
—
—
—
(3.5) $
—
—
—
1.1
—
—
—
(2.4) $
—
—
—
(1.7)
—
—
—
(4.1) $
1,657.3 $
—
—
—
9.2
118.1
(1.2)
—
1,783.4 $
—
—
—
10.5
89.9
(1.1)
—
1,882.7 $
—
—
—
8.8
117.9
(1.7)
—
2,007.7 $
870.7 $
236.7
—
(145.0)
—
—
—
—
962.4 $
258.4
—
(156.7)
—
—
—
—
1,064.1 $
262.2
—
(168.1)
—
—
—
—
1,158.2 $
(27.4) $
—
7.3
—
—
—
—
—
(20.1) $
—
4.5
—
—
—
—
—
(15.6) $
—
0.8
—
—
—
—
—
(14.8) $
101.2 $
14.5
—
—
—
—
—
(15.7)
100.0 $
12.4
—
—
—
—
—
(17.4)
95.0 $
13.8
—
—
—
—
—
(18.3)
90.5 $
2,662.5
251.2
7.3
(145.0)
8.0
119.9
(1.2)
(15.7)
2,887.0
270.8
4.5
(156.7)
11.6
91.2
(1.1)
(17.4)
3,089.9
276.0
0.8
(168.1)
7.2
120.0
(1.7)
(18.3)
3,305.8
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
BLACK HILLS CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
December 31,
December 31,
December 31,
2023
2022
(in millions)
2021
$
276.0 $
270.8 $
251.2
Adjustments to reconcile net income to net cash provided by (used in)
Year ended
Operating activities:
Net income
operating activities:
Depreciation, depletion and amortization
Deferred financing cost amortization
Stock compensation
Deferred income taxes
Employee benefit plans
Other adjustments, net
Change in certain operating assets and liabilities:
Materials, supplies and fuel
Accounts receivable and other current assets
Accounts payable and other current liabilities
Regulatory assets
Regulatory liabilities
Other operating activities, net
Net cash provided by (used in) operating activities
Investing activities:
Property, plant and equipment additions
Other investing activities
Net cash (used in) investing activities
Financing activities:
Dividends paid on common stock
Common stock issued
Term Loan - borrowings
Term Loan - repayments
Net borrowings (payments) of Revolving Credit Facility and CP Program
Long-term debt - issuance
Long-term debt - repayments
Distributions to non-controlling interests
Other financing activities
Net cash provided by (used in) financing activities
Net change in cash, restricted cash and cash equivalents
Cash, restricted cash and cash equivalents beginning of year
Cash, restricted cash and cash equivalents end of year
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)
Income taxes
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at December 31
Increase in capitalized assets associated with asset retirement
obligations
$
$
$
$
$
256.8
10.1
7.0
25.4
11.5
2.7
51.4
204.5
(109.9)
236.8
—
(27.9)
944.4
(555.6)
18.9
(536.7)
(168.1)
118.3
—
—
(535.6)
800.0
(525.0)
(18.3)
(13.0)
(341.7)
66.0
27.0
93.0 $
250.9
9.8
8.6
25.6
5.5
(4.7)
(75.4)
(184.5)
89.4
203.9
—
(15.1)
584.8
(604.4)
0.5
(603.9)
(156.7)
90.1
115.4
—
—
—
—
(17.4)
0.9
32.3
13.2
13.8
27.0 $
236.0
7.0
9.7
7.3
9.6
7.0
(35.7)
(43.2)
10.6
(514.7)
(9.5)
0.1
(64.6)
(677.5)
13.3
(664.2)
(145.0)
119.0
800.0
(800.0)
186.1
600.0
(8.4)
(15.7)
(4.1)
731.9
3.1
10.7
13.8
(157.3) $
(1.0) $
(152.5) $
0.8 $
(142.7)
1.5
52.4 $
3.8 $
59.3 $
14.0 $
68.8
2.1
The accompanying Notes to Consolidated Financial Statements are an integral part of these Consolidated Financial Statements.
63
10-KFORM 10-K |
BLACK HILLS CORPORATION
Notes to Consolidated Financial Statements
December 31, 2023, 2022 and 2021
(1) BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. 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 operating segments are presented as
Corporate and Other.
Use of Estimates and Basis of Presentation
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that
affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and
circumstances or additional information may result in revised estimates and actual results could differ materially from those
estimates.
Principles of Consolidation
The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned
and controlled subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary,
thus controlling the VIE, have been consolidated. All intercompany balances and transactions have been eliminated in
consolidation.
We use the proportionate consolidation method to account for our ownership interest in any jointly-owned facility. See Note 6 for
additional information.
Non-controlling Interests
We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidation. ASC 810 requires that
the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that non-
controlling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the
amounts attributable to the non-controlling interest net income (loss) of those subsidiaries are reported separately in the
consolidated statements of income and comprehensive income. See Note 12 for additional information.
Variable Interest Entities
We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary.
GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, non-
controlling interest and results of activities of a VIE in its consolidated financial statements.
A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest
holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits
of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary
beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and non-
controlling interests at fair value and subsequently account for the VIE as if it were consolidated.
Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and
assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance
and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the
purpose of the arrangement. Black Hills Colorado IPP is a VIE. See Note 12 for additional information.
Cash, Cash Equivalents and Restricted Cash
We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We
maintain cash accounts for various specified purposes, which are classified as restricted cash.
64
10-K| FORM 10-K BLACK HILLS CORPORATION
Notes to Consolidated Financial Statements
December 31, 2023, 2022 and 2021
Revenue Recognition
(1) BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES
Business Description
Black Hills Corporation is a customer-focused, growth-oriented utility company headquartered in Rapid City, South Dakota. 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 operating segments are presented as
Corporate and Other.
Use of Estimates and Basis of Presentation
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that
affect the reported amounts of certain assets and liabilities and disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during the reporting period. Changes in facts and
circumstances or additional information may result in revised estimates and actual results could differ materially from those
estimates.
Principles of Consolidation
consolidation.
additional information.
Non-controlling Interests
Variable Interest Entities
The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned
and controlled subsidiaries. Furthermore, VIEs in which the Company has an ownership interest and is the primary beneficiary,
thus controlling the VIE, have been consolidated. All intercompany balances and transactions have been eliminated in
We use the proportionate consolidation method to account for our ownership interest in any jointly-owned facility. See Note 6 for
We account for changes in our controlling interests of subsidiaries according to ASC 810, Consolidation. ASC 810 requires that
the Company record such changes as equity transactions, recording no gain or loss on such a sale. GAAP requires that non-
controlling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet. In addition, the
amounts attributable to the non-controlling interest net income (loss) of those subsidiaries are reported separately in the
consolidated statements of income and comprehensive income. See Note 12 for additional information.
Our revenue contracts generally provide for performance obligations that are fulfilled and transfer control to customers over time,
represent a series of distinct services that are substantially the same, involve the same pattern of transfer to the customer and
provide a right to consideration from our customers in an amount that corresponds directly with the value to the customer for the
performance completed to date. Therefore, we recognize revenue in the amount to which we have a right to invoice. Our primary
types of revenue contracts are:
•
•
Regulated natural gas and electric utility services tariffs - Our Utilities have regulated operations, as defined by ASC
980, Regulated Operations, that provide services to regulated customers under tariff rates, charges, terms and
conditions of service and prices determined by the jurisdictional regulators designated for our service territories. Our
regulated services primarily encompass single performance obligations for delivery of either commodity natural gas,
commodity electricity, natural gas transportation or electric transmission services. These service revenues are
variable based on quantities delivered, influenced by seasonal business and weather patterns. Tariffs are only
permitted to be changed through a rate-setting process involving the state or federal regulatory commissions to
establish contractual rates between the utility and its customers. All of our Utilities’ regulated sales are subject to
regulatory-approved tariffs.
Power sales agreements - Our Electric Utilities segment has long-term wholesale power sales agreements with
other load-serving entities, including affiliates, for the sale of excess power from owned generating units. These
agreements include a combination of “take or pay” arrangements, where the customer is obligated to pay for the
energy regardless of whether it actually takes delivery, as well as “requirements only” arrangements, where the
customer is only obligated to pay for the energy the customer needs. In addition to these long-term contracts, we
also sell excess energy to other load-serving entities on a short-term basis. The pricing for all of these arrangements
is included in the executed contracts or confirmations, reflecting the standalone selling price and is variable based
on energy delivered. Certain energy sale and purchase transactions with the same counterparty and at the same
delivery point are netted to reflect the economic substance of the arrangement.
The majority of our revenue contracts are based on variable quantities delivered. Any fixed consideration contracts with an
expected duration of one year or more are immaterial to our consolidated revenues. Variable consideration constraints in the
form of discounts, rebates, credits, price concessions, incentives, performance bonuses, penalties or other similar items are not
material for our revenue contracts. We are the principal in our revenue contracts, as we have control over the services prior to
those services being transferred to the customer.
Revenue Not in Scope of ASC 606
Other revenues included in the tables in Note 4 include our revenue accounted for under separate accounting guidance,
including lease revenue under ASC 842, Leases, derivative revenue under ASC 815, Derivatives and Hedging, and alternative
revenue programs revenue under ASC 980, Regulated Operations.
We evaluate arrangements and contracts with other entities to determine if they are VIEs and if we are the primary beneficiary.
GAAP provides a framework for identifying VIEs and determining when a company should include the assets, liabilities, non-
controlling interest and results of activities of a VIE in its consolidated financial statements.
Significant Judgments and Estimates
Unbilled Revenue
A VIE should be consolidated if a party with an ownership, contractual or other financial interest in the VIE (a variable interest
holder) has the power to direct the VIE’s most significant activities and the obligation to absorb losses or right to receive benefits
of the VIE that could be significant to the VIE. A variable interest holder that consolidates the VIE is called the primary
beneficiary. Upon consolidation, the primary beneficiary generally must initially record all of the VIE’s assets, liabilities and non-
controlling interests at fair value and subsequently account for the VIE as if it were consolidated.
Our evaluation of whether our interest qualifies as the primary beneficiary of a VIE involves significant judgments, estimates and
assumptions and includes a qualitative analysis of the activities that most significantly impact the VIE’s economic performance
and whether the Company has the power to direct those activities, the design of the entity, the rights of the parties and the
purpose of the arrangement. Black Hills Colorado IPP is a VIE. See Note 12 for additional information.
To the extent that deliveries have occurred, but a bill has not been issued, our Utilities accrue an estimate of the revenue since
the latest billing. This estimate is calculated based upon several factors including billings through the last billing cycle in a month
and prices in effect in our jurisdictions. Each month, the estimated unbilled revenue amounts are trued-up and recorded in
Accounts receivable, net on the accompanying Consolidated Balance Sheets.
Contract Balances
The nature of our primary revenue contracts provides an unconditional right to consideration upon service delivery; therefore, no
customer contract assets or liabilities exist. The unconditional right to consideration is represented by the balance in our
Accounts receivable, which is further discussed below.
Cash, Cash Equivalents and Restricted Cash
We consider all highly liquid investments with an original maturity of three months or less to be cash and cash equivalents. We
maintain cash accounts for various specified purposes, which are classified as restricted cash.
See Note 4 for additional information.
Accounts Receivable and Allowance for Credit Losses
Accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses, and do not bear
interest. We maintain an allowance for credit losses which reflects our estimate of uncollectible trade receivables. We regularly
review our trade receivable allowance by considering such factors as historical experience, credit worthiness, the age of the
receivable balances and current economic conditions that may affect collectability.
65
10-KFORM 10-K | In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for credit losses to
reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our
estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include,
but are not limited to, customer credit issues, expected losses, the level of commodity prices, customer deposits and general
economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the
contract has expired.
We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each
other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the
right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master
netting agreement between counterparties.
Following is a summary of accounts receivable as of December 31 (in millions):
Billed Accounts Receivable
Unbilled Revenue
Less Allowance for Credit Losses
Accounts Receivable, net
2023
2022
$
$
198.5 $
154.0
(2.2)
350.3 $
267.6
243.6
(3.0)
508.2
Changes to allowance for credit losses for the years ended December 31, were as follows (in millions):
Balance at
Beginning of Year
Additions
Charged to Costs
and Expenses
Recoveries and
Other Additions
Write-offs and
Other Deductions
Balance at
End of Year
2023
2022
2021
$
$
$
3.0 $
2.1 $
7.0 $
Materials, Supplies and Fuel
8.7 $
9.1 $
2.4 $
4.1 $
3.5 $
3.6 $
(13.6) $
(11.7) $
(10.9) $
2.2
3.0
2.1
Materials and supplies represent parts and supplies for our business operations. Fuel represents diesel oil and gas used by our
electric generating facilities to produce power. Natural gas in storage primarily represents gas purchased for use by our gas
customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the
lower-of-cost or net realizable value. The value of our natural gas in storage fluctuates with seasonal volume requirements of our
business and the commodity price of natural gas.
The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated
Balance Sheets as of December 31 (in millions):
Materials and supplies
Fuel
Natural gas in storage
Total materials, supplies and fuel
Property, Plant and Equipment
2023
2022
$
$
105.9 $
7.7
47.3
160.9 $
99.7
3.1
104.6
207.4
Property, plant and equipment are stated at cost, which includes construction-related direct labor and material costs, indirect
construction costs including labor and related costs of departments associated with supporting construction activities, and
AFUDC. Additions to and significant replacements of property are charged to property, plant and equipment at cost. We also
classify our Cushion Gas as Property, plant and equipment. Ordinary repairs and maintenance of property, except as allowed
under rate regulations, are charged to operations as incurred.
We receive contributions in aid of construction (CIACs) from third parties that are generally intended to defray all or a portion of
the costs for certain capital projects. Such CIAC costs are recorded as a reduction to Property, plant, and equipment.
The cost of regulated utility property, plant and equipment retired, or otherwise disposed in the ordinary course of business, less
salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs related to our regulated
properties that do not have legal retirement obligations are reclassified from accumulated depreciation and reflected as
regulatory liabilities. Retirement or disposal of all other operating assets result in gains or losses recognized as a reduction to
Operations and maintenance expense.
See Note 5 for additional information.
66
10-K| FORM 10-K
In specific cases where we are aware of a customer’s inability or reluctance to pay, we record an allowance for credit losses to
reduce the net receivable balance to the amount we reasonably expect to collect. However, if circumstances change, our
estimate of the recoverability of accounts receivable could be affected. Circumstances which could affect our estimates include,
but are not limited to, customer credit issues, expected losses, the level of commodity prices, customer deposits and general
economic conditions. Accounts are written off once they are deemed to be uncollectible or the time allowed for dispute under the
contract has expired.
We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each
other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the
right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master
netting agreement between counterparties.
Following is a summary of accounts receivable as of December 31 (in millions):
Billed Accounts Receivable
Unbilled Revenue
Less Allowance for Credit Losses
Accounts Receivable, net
2023
2022
$
$
198.5 $
154.0
(2.2)
350.3 $
267.6
243.6
(3.0)
508.2
Changes to allowance for credit losses for the years ended December 31, were as follows (in millions):
Additions
2023
2022
2021
$
$
$
3.0 $
2.1 $
7.0 $
Materials, Supplies and Fuel
8.7 $
9.1 $
2.4 $
4.1 $
3.5 $
3.6 $
(13.6) $
(11.7) $
(10.9) $
2.2
3.0
2.1
Materials and supplies represent parts and supplies for our business operations. Fuel represents diesel oil and gas used by our
electric generating facilities to produce power. Natural gas in storage primarily represents gas purchased for use by our gas
customers. All of our Materials, supplies and fuel are recorded using the weighted-average cost method and are valued at the
lower-of-cost or net realizable value. The value of our natural gas in storage fluctuates with seasonal volume requirements of our
business and the commodity price of natural gas.
The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated
Balance Sheets as of December 31 (in millions):
Materials and supplies
Fuel
Natural gas in storage
Total materials, supplies and fuel
Property, Plant and Equipment
$
$
105.9 $
7.7
47.3
160.9 $
99.7
3.1
104.6
207.4
Property, plant and equipment are stated at cost, which includes construction-related direct labor and material costs, indirect
construction costs including labor and related costs of departments associated with supporting construction activities, and
AFUDC. Additions to and significant replacements of property are charged to property, plant and equipment at cost. We also
classify our Cushion Gas as Property, plant and equipment. Ordinary repairs and maintenance of property, except as allowed
under rate regulations, are charged to operations as incurred.
We receive contributions in aid of construction (CIACs) from third parties that are generally intended to defray all or a portion of
the costs for certain capital projects. Such CIAC costs are recorded as a reduction to Property, plant, and equipment.
The cost of regulated utility property, plant and equipment retired, or otherwise disposed in the ordinary course of business, less
salvage plus retirement costs, is charged to accumulated depreciation. Estimated removal costs related to our regulated
properties that do not have legal retirement obligations are reclassified from accumulated depreciation and reflected as
regulatory liabilities. Retirement or disposal of all other operating assets result in gains or losses recognized as a reduction to
Operations and maintenance expense.
See Note 5 for additional information.
Depreciation
Depreciation provisions for property, plant and equipment are generally computed on a straight-line basis based on the
applicable estimated service life of the various classes of property. The composite depreciation method is applied to regulated
utility property. Depreciation studies are conducted periodically to update composite rates and are approved by state utility
commissions and/or the FERC when required. Capitalized mining costs and coal leases are amortized on a unit-of-production
method based on volumes produced and estimated reserves. For certain non-regulated power plant components, depreciation is
computed on a unit-of-production methodology based on plant hours run.
AFUDC
Included in the cost of regulated construction projects is AFUDC, when applicable, which represents the approximate composite
cost of borrowed funds and a return on equity used to finance a regulated utility project. The following table presents AFUDC
amounts (in millions) for the years ended December 31:
AFUDC Borrowed
AFUDC Equity
Interest expense incurred, net of amounts capitalized
Other income (expense), net
$
6.0 $
0.4
5.6 $
0.6
4.1
0.6
Income Statement Location
2023
2022
2021
We also capitalize interest, when applicable, on undeveloped leasehold costs and certain non-regulated construction projects. In
addition, asset retirement costs associated with tangible long-lived regulated utility assets are recognized as liabilities with an
increase to the carrying amounts of the related long-lived regulated utility assets in the period incurred. The amounts capitalized
are included in Property, plant and equipment on the accompanying Consolidated Balance Sheets.
Balance at
Charged to Costs
Beginning of Year
and Expenses
Recoveries and
Other Additions
Write-offs and
Other Deductions
Balance at
End of Year
Asset Retirement Obligations
Accounting standards for AROs associated with long-lived assets require that the present value of retirement costs for which we
have a legal obligation be recorded as liabilities with an equivalent amount added to the asset cost and depreciated over an
appropriate period. The associated ARO accretion expense for our non-regulated operations, and regulated operations without a
corresponding recovery mechanism, is included within Depreciation, depletion and amortization on the accompanying
Consolidated Statements of Income. The accounting for the obligation for regulated operations with a regulatory mechanism has
no income statement impact due to the deferral of the adjustments through the establishment of a regulatory asset or a
regulatory liability.
We initially record liabilities for the present value of retirement costs for which we have a legal obligation, with an equivalent
amount added to the asset cost. The asset is then depreciated or depleted over the appropriate useful life and the liability is
accreted over time by applying an interest method of allocation. Any difference in the actual cost of the settlement of the liability
and the recorded amount is recognized as a gain or loss in the results of operations at the time of settlement for our non-
regulated operations. See Note 7 for additional information.
2023
2022
Goodwill and Intangible Assets
Goodwill and intangible assets with indefinite lives are not amortized, but the carrying values are reviewed upon an indicator of
impairment or at least annually. Intangible assets with a finite life are amortized over their estimated useful lives.
We perform a goodwill impairment test on an annual basis or upon the occurrence of events or changes in circumstances that
indicate that the asset might be impaired. Our annual goodwill impairment testing date is as of October 1, which aligns our
testing date with our financial planning process.
The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components
of an operating segment.
Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting
units. These valuations require significant judgments, including, but not limited to: 1) estimates of future cash flows, based on our
internal five-year business plans and adjusted as appropriate for our view of market participant assumptions, with long range
cash flows estimated using a terminal value calculation; 2) estimates of long-term growth rates for our businesses; 3) the
determination of an appropriate weighted-average cost of capital or discount rate; and 4) the utilization of market information
such as recent sales transactions for comparable assets within the utility and energy industries.
We believe that goodwill reflects the inherent value of the relatively stable, long-lived cash flows of our Utilities businesses,
considering the regulatory environment, and the long-lived cash flow and rate base growth opportunities at our Utilities, and
those businesses vertically integrated. Goodwill amounts have not changed since 2016.
67
10-KFORM 10-K |
As of December 31, 2023 and 2022, Goodwill balances were as follows (in millions):
Goodwill
$
257.3 $
1,042.2 $
1,299.5
Electric Utilities
Gas Utilities
Total
Our intangible assets represent contract intangibles, easements, rights-of-way, customer listings and trademarks. The finite-lived
intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being
amortized from 2 years to 41 years. Changes to intangible assets for the years ended December 31, were as follows (in
millions):
Intangible assets, net, beginning balance
Amortization expense (a)
Intangible assets, net, ending balance
$
$
2023
2022
2021
9.6 $
(1.2)
8.4 $
10.8 $
(1.2)
9.6 $
11.9
(1.1)
10.8
(a)
Amortization expense for existing intangible assets is expected to be $1.2 million for each year of the next five years.
Accrued Liabilities
The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance
Sheets as of December 31 (in millions):
Accrued employee compensation, benefits and withholdings
Accrued property taxes
Customer deposits and prepayments
Accrued interest
Other (none of which is individually significant)
Total accrued liabilities
Fair Value Measurements
Financial Instruments
2023
2022
$
$
74.8 $
52.7
76.0
46.3
43.5
293.3 $
62.9
52.4
47.7
33.8
46.7
243.5
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.
68
10-K| FORM 10-K
As of December 31, 2023 and 2022, Goodwill balances were as follows (in millions):
Goodwill
$
257.3 $
1,042.2 $
1,299.5
Electric Utilities
Gas Utilities
Total
Our intangible assets represent contract intangibles, easements, rights-of-way, customer listings and trademarks. The finite-lived
intangible assets are amortized using a straight-line method based on estimated useful lives; these assets are currently being
amortized from 2 years to 41 years. Changes to intangible assets for the years ended December 31, were as follows (in
millions):
Intangible assets, net, beginning balance
Amortization expense (a)
Intangible assets, net, ending balance
Accrued Liabilities
$
$
2023
2022
2021
9.6 $
(1.2)
8.4 $
10.8 $
(1.2)
9.6 $
11.9
(1.1)
10.8
(a)
Amortization expense for existing intangible assets is expected to be $1.2 million for each year of the next five years.
The following amounts by major classification are included in Accrued liabilities on the accompanying Consolidated Balance
Sheets as of December 31 (in millions):
Accrued employee compensation, benefits and withholdings
Accrued property taxes
Customer deposits and prepayments
Accrued interest
Other (none of which is individually significant)
Total accrued liabilities
Fair Value Measurements
Financial Instruments
2023
2022
$
$
74.8 $
52.7
76.0
46.3
43.5
293.3 $
62.9
52.4
47.7
33.8
46.7
243.5
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.
Valuation Methodologies for Derivatives
The wholesale electric energy and natural gas commodity contracts for our Utilities 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 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.
See Notes 10 and 13 for additional information.
Derivatives and Hedging Activities
All our derivatives are measured at fair value and recognized as either assets or liabilities on the Consolidated Balance Sheets,
except for derivative contracts that qualify for and are elected under the normal purchase and normal sales exception. Normal
purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the
normal course of business over a reasonable amount of time and pricing is clearly and closely related to the asset being
purchased or sold. Normal purchase and sales contracts are recognized when the underlying physical transaction is completed
under the accrual basis of accounting.
In addition, certain derivative contracts approved by regulatory authorities are either recovered or refunded through customer
rates. Any changes in the fair value of these approved derivative contracts are deferred as a regulatory asset or regulatory
liability pursuant to ASC 980, Regulated Operations.
We also have some derivatives that qualify for hedge accounting and are designated as cash flow hedges. The gain or loss on
these designated derivatives is deferred in AOCI and reclassified into earnings when the corresponding hedged transaction is
recognized in earnings. Changes in the fair value of all other derivative contracts are recognized in earnings.
We utilize master netting agreements which consist of an agreement between two parties who have multiple contracts with each
other that provide for the net settlement of all contracts in the event of default on or termination of any one contract. When the
right of offset exists, accounting standards permit the netting of receivables and payables under a legally enforceable master
netting agreement between counterparties. Accounting standards also permit offsetting of fair value amounts recognized for the
right to reclaim, or the obligation to return, cash collateral against fair value amounts recognized for derivative instruments
executed with the same counterparty. We reflect the offsetting of net derivative positions with fair value amounts for cash
collateral with the same counterparty when a legal right of offset exists. Therefore, the gross amounts are not indicative of either
our actual credit or net economic exposures.
The cash impacts of settled derivatives are recorded as operating activities on the Consolidated Statements of Cash Flows.
See Notes 9, 10 and 11 for additional information.
Debt Discounts, Premiums and Deferred Financing Costs
Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the
issuance of debt. Debt discounts, premiums and deferred financing costs are amortized over the estimated useful life of the
related debt. Unamortized discounts, premiums and deferred financing costs are presented on the balance sheet as an
adjustment to the related debt liabilities. See Note 8 for additional information.
Regulatory Accounting
Our regulated Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory
commissions. Our Utilities account for income and expense items in accordance with accounting standards for regulated
operations. These accounting policies differ in some respects from those used by our non-regulated businesses. Under these
regulated operations accounting standards:
•
•
Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the
expected ability to recover the costs in future rates.
Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on
the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in
rates prior to the costs being incurred.
69
10-KFORM 10-K |
Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and
liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are
considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our
regulatory assets are probable of recovery in current rates or in future rate proceedings.
If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment and may be
required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of
operations, financial position or cash flows.
See Note 2 for additional information.
Income Taxes
The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. The Company and its
subsidiaries file consolidated federal income tax returns. Each subsidiary records both federal and state income taxes as if it
were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company
computations of taxable income or loss.
We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income
taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the
financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences
are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax
return in a different period than they are reported in the financial statements.
It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net
income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method,
which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax
expense over the estimated useful lives of the underlying property that gave rise to the credit.
We recognize interest income or interest expense and penalties related to income tax matters in Income tax expense on the
Consolidated Statements of Income.
We have elected to account for transferable clean energy tax credits, including PTCs and ITCs within the provision for income
taxes.
We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards
for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income
tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 15 for additional information.
Earnings per Share of Common Stock
Basic earnings per share is computed by dividing Net income available for common stock by the weighted average number of
common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares
outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted
stock and performance shares under our equity compensation plans.
A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in
millions, except earnings per share amounts):
Net income available for common stock
Weighted average shares - basic
Dilutive effect of equity compensation
Weighted average shares - diluted
Net income available for common stock, per share - Diluted
2023
2022
2021
262.2 $
258.4 $
236.7
67.0
0.1
67.1
64.9
0.1
65.0
3.91 $
3.97 $
63.2
0.1
63.3
3.74
$
$
The following securities were excluded from the diluted earnings per share computation for the years ended December 31
because of their anti-dilutive nature:
Equity compensation
Anti-dilutive shares excluded from computation of earnings per share
2023
2022
2021
46,275
46,275
—
—
13,101
13,101
70
10-K| FORM 10-K
Management continually assesses the probability of future recoveries and obligations associated with regulatory assets and
liabilities. Factors such as the current regulatory environment, recently issued rate orders, and historical precedents are
considered. As a result, we believe that the accounting prescribed under rate-based regulation remains appropriate and our
regulatory assets are probable of recovery in current rates or in future rate proceedings.
If changes in the regulatory environment occur, we may no longer be eligible to apply this accounting treatment and may be
required to eliminate regulatory assets and liabilities from our balance sheet. Such changes could adversely affect our results of
operations, financial position or cash flows.
See Note 2 for additional information.
Income Taxes
The Company is subject to federal income tax as well as income tax in various state and local jurisdictions. The Company and its
subsidiaries file consolidated federal income tax returns. Each subsidiary records both federal and state income taxes as if it
were a separate taxpayer and consolidating expense adjustments are allocated to the subsidiaries based on separate company
computations of taxable income or loss.
Share-Based Compensation
We account for our share-based compensation arrangements in accordance with ASC 718, Compensation-Stock Compensation,
by recognizing compensation costs for all share-based awards over the respective service period for employee services received
in exchange for an award of equity or equity-based compensation. Awards that will be settled in stock are accounted for as
equity and the compensation expense is based on the grant date fair value. Awards that are settled in cash are accounted for as
liabilities and the compensation expense is re-measured each period based on the current market price and performance
achievement measures. See Note 14 for additional information.
Pension and Other Postretirement Plans
We recognize on our Consolidated Balance Sheets an asset or liability reflecting the funded status of pension and other
postretirement plans with current-year changes in actuarial gains or losses recognized in AOCI, except for those plans at certain
of our regulated utilities that can recover portions of their pension and postretirement obligations through future rates. All plan
assets are recorded at fair value. We follow the measurement date provisions of ASC 715, Compensation-Retirement Benefits,
which require a year-end measurement date of plan assets and obligations for all defined benefit plans.
We use the asset and liability method in accounting for income taxes. Under the asset and liability method, deferred income
taxes are recognized at currently enacted income tax rates, to reflect the tax effect of temporary differences between the
Recently Issued Accounting Standards
financial and tax basis of assets and liabilities as well as operating loss and tax credit carryforwards. Such temporary differences
Improvements to Reportable Segment Disclosures, ASU 2023-07
are the result of provisions in the income tax law that either require or permit certain items to be reported on the income tax
return in a different period than they are reported in the financial statements.
It is our policy to apply the flow-through method of accounting for ITCs. Under the flow-through method, ITCs are reflected in net
income as a reduction to income tax expense in the year they qualify. An exception to this general policy is the deferral method,
which applies to our regulated businesses. Such a method results in the ITC being amortized as a reduction to income tax
expense over the estimated useful lives of the underlying property that gave rise to the credit.
We recognize interest income or interest expense and penalties related to income tax matters in Income tax expense on the
Consolidated Statements of Income.
In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segment Disclosures, which expands public
entities’ segment disclosures by requiring disclosure of significant segment expenses that are regularly reviewed by the CODM
and included within each reported measure of segment profit or loss, an amount and description of its composition for other
segment items, and interim disclosures of a reportable segment’s profit or loss and assets. The ASU also allows, in addition to
the measure that is most consistent with GAAP, the disclosure of additional measures of segment profit or loss that are used by
the CODM in assessing segment performance and deciding how to allocate resources. The ASU is effective for our Annual
Report on Form 10-K for the fiscal year ended December 31, 2024, and subsequent interim periods, with early adoption
permitted. We do not expect the ASU to have an impact on our financial position, results of operations and cash flows; however,
are currently evaluating the impact on our consolidated financial statement disclosures.
We have elected to account for transferable clean energy tax credits, including PTCs and ITCs within the provision for income
Improvements to Income Tax Disclosures, ASU 2023-09
taxes.
In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which expands public entities’
annual disclosures by requiring disclosure of tax rate reconciliation amounts and percentages for specific categories, income
taxes paid disaggregated by federal and state taxes, and income tax expense disaggregated by federal and state taxes
jurisdiction. The ASU is effective for our Annual Report on Form 10-K for the fiscal year ended December 31, 2025, with early
adoption permitted. We do not expect the ASU to have an impact on our financial position, results of operations and cash flows;
however, are currently evaluating the impact on our consolidated financial statement disclosures.
We account for uncertainty in income taxes recognized in the financial statements in accordance with the accounting standards
for income taxes. The unrecognized tax benefit is classified in Other deferred credits and other liabilities or in Deferred income
tax liabilities, net on the accompanying Consolidated Balance Sheets. See Note 15 for additional information.
Earnings per Share of Common Stock
Basic earnings per share is computed by dividing Net income available for common stock by the weighted average number of
common shares outstanding during each year. Diluted earnings per share is computed by including all dilutive common shares
outstanding during each year. Diluted common shares are primarily due to equity units, outstanding stock options, restricted
stock and performance shares under our equity compensation plans.
A reconciliation of share amounts used to compute earnings per share is as follows for the years ended December 31 (in
millions, except earnings per share amounts):
Net income available for common stock
Weighted average shares - basic
Dilutive effect of equity compensation
Weighted average shares - diluted
2023
2022
2021
262.2 $
258.4 $
236.7
67.0
0.1
67.1
64.9
0.1
65.0
63.2
0.1
63.3
3.74
$
$
Net income available for common stock, per share - Diluted
3.91 $
3.97 $
The following securities were excluded from the diluted earnings per share computation for the years ended December 31
because of their anti-dilutive nature:
Equity compensation
Anti-dilutive shares excluded from computation of earnings per share
2023
2022
2021
46,275
46,275
—
—
13,101
13,101
71
10-KFORM 10-K |
(2) REGULATORY MATTERS
We had the following regulatory assets and liabilities as of December 31 (in millions):
Regulatory assets
Winter Storm Uri (a)
Deferred energy and fuel cost adjustments (b)
Deferred gas cost adjustments (b)
Gas price derivatives (b)
Deferred taxes on AFUDC (b)
Employee benefit plans and related deferred taxes (c)
Environmental (b)
Loss on reacquired debt (b)
Deferred taxes on flow-through accounting (b)
Decommissioning costs (b)
Other regulatory assets (b)
Total regulatory assets
Less current regulatory assets
Regulatory assets, non-current
Regulatory liabilities
Deferred energy and gas costs (b)
Employee benefit plans and related deferred taxes (c)
Cost of removal (b)
Excess deferred income taxes (c)
Other regulatory liabilities (c)
Total regulatory liabilities
Less current regulatory liabilities
Regulatory liabilities, non-current
2023
2022
$
$
$
$
199.6 $
55.1
4.1
5.1
7.1
89.3
2.9
17.4
74.7
2.4
22.4
480.1
(175.7)
304.4 $
88.9 $
36.2
181.9
247.1
12.5
566.6
(98.9)
467.7 $
348.0
72.6
12.2
8.8
7.3
89.3
1.3
19.2
69.5
3.5
21.3
653.0
(260.3)
392.7
41.7
38.9
175.6
254.8
7.6
518.6
(46.0)
472.6
(a)
(b)
(c)
Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. See further information below.
Recovery/repayment of costs, but we are not allowed a rate of return.
In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.
Regulatory assets represent items we expect to recover from customers through probable future rates.
Winter Storm Uri - Our Utilities have received commission approval to recover incremental fuel, purchased power and
natural gas costs associated with Winter Storm Uri. In certain jurisdictions, we also received commission approval to
recover carrying costs. As of December 31, 2023, we estimate that our remaining Winter Storm Uri regulatory asset has a
weighted-average recovery period of 2.2 years.
Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity
delivered to our Electric Utilities’ customers that is either higher or lower than the current rates and will be recovered or
refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved
by the appropriate state regulatory commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual
filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory
commissions.
Deferred Gas Cost Adjustments - Our regulated Gas Utilities have GCA provisions that allow them to pass the cost of gas
on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-
recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded
as a regulatory asset or liability, respectively. Our Gas Utilities file periodic monthly, quarterly, semi-annual and/or annual
filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory
commissions.
Gas Price Derivatives - Our regulated Gas Utilities, as allowed or required by state regulatory commissions, have entered
into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations
in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities.
Gas price derivatives at December 31, 2023 are hedged over a maximum forward term of two years.
72
10-K| FORM 10-K
(2) REGULATORY MATTERS
We had the following regulatory assets and liabilities as of December 31 (in millions):
Regulatory assets
Winter Storm Uri (a)
Deferred energy and fuel cost adjustments (b)
Deferred gas cost adjustments (b)
Gas price derivatives (b)
Deferred taxes on AFUDC (b)
Employee benefit plans and related deferred taxes (c)
Environmental (b)
Loss on reacquired debt (b)
Deferred taxes on flow-through accounting (b)
Decommissioning costs (b)
Other regulatory assets (b)
Total regulatory assets
Less current regulatory assets
Regulatory assets, non-current
Regulatory liabilities
Deferred energy and gas costs (b)
Employee benefit plans and related deferred taxes (c)
Cost of removal (b)
Excess deferred income taxes (c)
Other regulatory liabilities (c)
Total regulatory liabilities
Less current regulatory liabilities
Regulatory liabilities, non-current
2023
2022
$
199.6 $
348.0
55.1
4.1
5.1
7.1
89.3
2.9
17.4
74.7
2.4
22.4
480.1
(175.7)
304.4 $
88.9 $
36.2
181.9
247.1
12.5
566.6
(98.9)
467.7 $
72.6
12.2
8.8
7.3
89.3
1.3
19.2
69.5
3.5
21.3
653.0
(260.3)
392.7
41.7
38.9
175.6
254.8
7.6
518.6
(46.0)
472.6
$
$
$
(a)
(b)
(c)
Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. See further information below.
Recovery/repayment of costs, but we are not allowed a rate of return.
In addition to recovery or repayment of costs, we are allowed a return on a portion of this amount or a reduction in rate base.
Regulatory assets represent items we expect to recover from customers through probable future rates.
Winter Storm Uri - Our Utilities have received commission approval to recover incremental fuel, purchased power and
natural gas costs associated with Winter Storm Uri. In certain jurisdictions, we also received commission approval to
recover carrying costs. As of December 31, 2023, we estimate that our remaining Winter Storm Uri regulatory asset has a
weighted-average recovery period of 2.2 years.
Deferred Energy and Fuel Cost Adjustments - Deferred energy and fuel cost adjustments represent the cost of electricity
delivered to our Electric Utilities’ customers that is either higher or lower than the current rates and will be recovered or
refunded in future rates. Deferred energy and fuel cost adjustments are recorded and recovered or amortized as approved
by the appropriate state regulatory commission. Our Electric Utilities file periodic quarterly, semi-annual and/or annual
filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory
commissions.
commissions.
Deferred Gas Cost Adjustments - Our regulated Gas Utilities have GCA provisions that allow them to pass the cost of gas
on to their customers. The GCA is based on forecasts of the upcoming gas costs and recovery or refund of prior under-
recovered or over-recovered costs. To the extent that gas costs are under-recovered or over-recovered, they are recorded
as a regulatory asset or liability, respectively. Our Gas Utilities file periodic monthly, quarterly, semi-annual and/or annual
filings to recover these costs based on the respective cost mechanisms approved by their applicable state regulatory
Gas Price Derivatives - Our regulated Gas Utilities, as allowed or required by state regulatory commissions, have entered
into certain exchange-traded natural gas futures and options to reduce our customers’ underlying exposure to fluctuations
in gas prices. Gas price derivatives represent our unrealized positions on our commodity contracts supporting our utilities.
Gas price derivatives at December 31, 2023 are hedged over a maximum forward term of two years.
Deferred Taxes on AFUDC - The equity component of AFUDC is considered a permanent difference for tax purposes with
the tax benefit being flowed through to customers as prescribed or allowed by regulators. If, based on a regulator’s action,
it is probable the utility will recover the future increase in taxes payable represented by this flow-through treatment through
a rate revenue increase, a regulatory asset is recognized. This regulatory asset is a temporary difference for which a
deferred tax liability must be recognized. Accounting standards for income taxes specifically address AFUDC-equity and
require a gross-up of such amounts to reflect the revenue requirement associated with a rate-regulated environment.
Employee Benefit Plans and Related Deferred Taxes - Employee benefit plans include the unrecognized prior service
costs and net actuarial loss associated with our defined benefit pension plan and post-retirement benefit plans in
regulatory assets rather than in AOCI. In addition, this regulatory asset includes the income tax effect of the adjustment
required under accounting for compensation - defined benefit plans, to record the full pension and post-retirement benefit
obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate
regulated environment.
Environmental - Environmental costs associated with certain former manufactured gas plant sites. These costs are first
offset by recognition of insurance proceeds and settlements with other third parties. Any remaining cost will be requested
for recovery in future rate filings. Recovery for these specific environmental costs has not yet been approved by the
applicable state regulatory commission and therefore, the recovery period is unknown at this time.
Loss on Reacquired Debt - Loss on reacquired debt is recovered over the remaining life of the original issue or, if
refinanced, over the life of the new issue.
Deferred Taxes on Flow-Through Accounting - Under flow-through accounting, the income tax effects of certain tax items
are reflected in our cost of service for the customer and result in lower utility rates in the year in which the tax benefits are
realized. A regulatory asset was established to reflect that future increases in income taxes payable will be recovered from
customers as the temporary differences reverse. As a result of this regulatory treatment, we continue to record a net tax
benefit for costs considered currently deductible for tax purposes but are capitalized for book purposes.
Decommissioning Costs - South Dakota Electric and Colorado Electric received approval in 2014 for recovery of the
remaining net book values and decommissioning costs of their decommissioned coal plants. In 2018, Arkansas Gas
received approval to record Liquefied Natural Gas Plant decommissioning costs as a regulatory asset and received
approval in 2020 to begin recovering those costs over three years.
Regulatory liabilities represent items we expect to refund to customers through probable future decreases in rates.
Deferred Energy and Gas Costs - Deferred energy and gas costs that have been over-recovered through customer rates
and will be returned to customers in future periods.
Employee Benefit Plans and Related Deferred Taxes - Employee benefit plans represent the cumulative excess of
pension and retiree healthcare costs recovered in rates over pension expense recorded in accordance with ASC 715,
Compensation-Retirement Benefits. In addition, this regulatory liability includes the income tax effect of the adjustment
required under ASC 715, Compensation-Retirement Benefits, to record the full pension and post-retirement benefit
obligations. Such income tax effect has been grossed-up to account for the revenue requirement associated with a rate
regulated environment.
Cost of Removal - Cost of removal represents the estimated cumulative net provisions for future removal costs for which
there is no legal obligation for removal included in depreciation expense.
Excess Deferred Income Taxes - The revaluation of the regulated utilities' deferred tax assets and liabilities due to the
passage of the TCJA was recorded as excess deferred income taxes to be refunded to customers primarily using the
normalization principles as prescribed in the TCJA. A majority of the excess deferred taxes are subject to the average rate
assumption method, as prescribed by the IRS, and will generally be amortized as a reduction of customer rates over the
remaining lives of the related assets.
Recent Regulatory Activity
Arkansas Gas
On December 4, 2023, Arkansas Gas filed a rate review with the APSC seeking recovery of significant infrastructure investments
in its 7,200-mile natural gas pipeline system. The rate review requests $44.1 million in new annual revenue with a capital
structure of 48% equity and 52% debt and a return on equity of 10.5%. The request seeks to finalize rates in the fourth quarter of
2024.
73
10-KFORM 10-K |
Colorado Gas
RMNG Rate Review
On July 12, 2023, the CPUC approved a settlement agreement for RMNG's rate review filed on October 7, 2022. The agreement
is expected to generate $8.2 million in new annual revenue and established a weighted average cost of capital of 6.93% with a
capital structure that reflects an equity range of 50% to 52% and a debt range of 50% to 48% and a return on equity range of
9.5% to 9.7%. The settlement also shifted $8.3 million of SSIR revenue to base rates and terminated the SSIR. New rates were
effective July 15, 2023.
Colorado Gas Rate Review
On May 9, 2023, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its
10,000-mile natural gas pipeline system. In the fourth quarter of 2023, Colorado Gas reached a settlement agreement with the
CPUC staff and various intervenors for a general rate increase, which is subject to CPUC approval. The settlement is expected
to generate $20.2 million of new annual revenue with a capital structure of 50.87% equity and 49.13% debt and a return on
equity of 9.3%. If approved, new rates will be effective in February 2024.
Wyoming Gas
On May 18, 2023, Wyoming Gas filed a rate review with the WPSC seeking recovery of significant infrastructure investments in
its 6,400-mile natural gas pipeline system. On January 17, 2024, the WPSC approved a settlement agreement for a general rate
increase which is expected to generate $13.9 million in new annual revenue with a capital structure of 51% equity and 49% debt
and a return on equity of 9.85%. New rates were effective February 1, 2024. The agreement also included approval of a four-
year extension of the Wyoming Integrity Rider.
Wyoming Electric
On June 1, 2022, Wyoming Electric filed a rate review with the WPSC seeking recovery of significant infrastructure investments
in its 1,330-mile electric distribution and 59-mile electric transmission systems. On January 26, 2023, the WPSC approved a
settlement agreement with intervening parties for a general rate increase. The settlement is expected to generate $8.7 million in
new annual revenue with a capital structure of 52% equity and 48% debt and a return on equity of 9.75%. New rates were
effective March 1, 2023. The agreement also included approval of a new rider that will be filed annually to recover transmission
investments and expenses.
(3) COMMITMENTS, CONTINGENCIES AND GUARANTEES
Unconditional Purchase Obligations
We have various PPAs and transmission service agreements, which extend to 2032, to support our Electric Utilities' capacity and
energy needs beyond our regulated power plants' generation.
Our Utilities purchase natural gas, including transportation and storage capacity, to meet customers' needs under short-term and
long-term purchase contracts. These contracts extend to 2044.
The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services and
natural gas transportation and storage agreements (in millions):
PPAs (a)
Transmission
Services
Agreements
Natural gas supply,
transportation and
storage agreements
Future commitments for the year ending December 31,
2024
2025
2026
2027
2028
Thereafter
Total future commitments
____________________
(a) This schedule does not reflect renewable energy PPA future obligations since these agreements vary based on weather conditions.
12.2 $
—
—
—
—
—
12.2 $
2.7 $
—
—
—
—
—
2.7 $
$
$
163.0
135.0
110.8
79.5
58.0
95.2
641.5
74
10-K| FORM 10-K
Colorado Gas
RMNG Rate Review
effective July 15, 2023.
Colorado Gas Rate Review
Wyoming Gas
On May 9, 2023, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its
10,000-mile natural gas pipeline system. In the fourth quarter of 2023, Colorado Gas reached a settlement agreement with the
CPUC staff and various intervenors for a general rate increase, which is subject to CPUC approval. The settlement is expected
to generate $20.2 million of new annual revenue with a capital structure of 50.87% equity and 49.13% debt and a return on
equity of 9.3%. If approved, new rates will be effective in February 2024.
On May 18, 2023, Wyoming Gas filed a rate review with the WPSC seeking recovery of significant infrastructure investments in
its 6,400-mile natural gas pipeline system. On January 17, 2024, the WPSC approved a settlement agreement for a general rate
increase which is expected to generate $13.9 million in new annual revenue with a capital structure of 51% equity and 49% debt
and a return on equity of 9.85%. New rates were effective February 1, 2024. The agreement also included approval of a four-
year extension of the Wyoming Integrity Rider.
Wyoming Electric
On June 1, 2022, Wyoming Electric filed a rate review with the WPSC seeking recovery of significant infrastructure investments
in its 1,330-mile electric distribution and 59-mile electric transmission systems. On January 26, 2023, the WPSC approved a
settlement agreement with intervening parties for a general rate increase. The settlement is expected to generate $8.7 million in
new annual revenue with a capital structure of 52% equity and 48% debt and a return on equity of 9.75%. New rates were
effective March 1, 2023. The agreement also included approval of a new rider that will be filed annually to recover transmission
investments and expenses.
(3) COMMITMENTS, CONTINGENCIES AND GUARANTEES
Unconditional Purchase Obligations
We have various PPAs and transmission service agreements, which extend to 2032, to support our Electric Utilities' capacity and
energy needs beyond our regulated power plants' generation.
Our Utilities purchase natural gas, including transportation and storage capacity, to meet customers' needs under short-term and
long-term purchase contracts. These contracts extend to 2044.
The following is a schedule of unconditional purchase obligations required under the power purchase, transmission services and
natural gas transportation and storage agreements (in millions):
Future commitments for the year ending December 31,
2024
2025
2026
2027
2028
Thereafter
Total future commitments
____________________
PPAs (a)
Transmission
Services
Agreements
Natural gas supply,
transportation and
storage agreements
$
$
2.7 $
12.2 $
—
—
—
—
—
—
—
—
—
—
2.7 $
12.2 $
163.0
135.0
110.8
79.5
58.0
95.2
641.5
(a) This schedule does not reflect renewable energy PPA future obligations since these agreements vary based on weather conditions.
On July 12, 2023, the CPUC approved a settlement agreement for RMNG's rate review filed on October 7, 2022. The agreement
is expected to generate $8.2 million in new annual revenue and established a weighted average cost of capital of 6.93% with a
capital structure that reflects an equity range of 50% to 52% and a debt range of 50% to 48% and a return on equity range of
9.5% to 9.7%. The settlement also shifted $8.3 million of SSIR revenue to base rates and terminated the SSIR. New rates were
We lease from third parties certain office and operation center facilities, communication tower sites, equipment and materials
storage. Our leases have remaining terms ranging from less than one year to 32 years, including options to extend that are
reasonably certain to be exercised. Our operating and finance leases were not material to the Company’s Consolidated Financial
statements.
Lease Agreements
Lessee
Lessor
We lease to third parties certain generating station ground leases, communication tower sites and a natural gas pipeline. These
leases have remaining terms ranging from less than one year to 31 years. Lease revenue was not material for the years ended
December 31, 2023, 2022 and 2021.
As of December 31, 2023, scheduled maturities of operating lease payments to be received in future years were as follows (in
millions):
2024
2025
2026
2027
2028
Thereafter
Total lease receivables
Environmental Matters
Operating Leases
2.2
$
2.2
2.0
1.9
1.9
48.3
58.5
$
We are subject to costs resulting from a number of federal, state and local laws and regulations which affect future planning and
existing operations. Laws and regulations can result in increased capital expenditures, operating and other costs as a result of
compliance, remediation and monitoring obligations. Due to the environmental issues discussed below, we may be required to
modify, curtail, replace or cease operating certain facilities or operations to comply with statutes, regulations and other
requirements of regulatory bodies.
Reclamation Liability
For our Pueblo Airport Generation site, we posted a bond with the State of Colorado to cover the costs of remediation for a
waste water containment pond permitted to provide wastewater storage and processing for this zero-discharge facility. The
reclamation liability is recorded at the present value of the estimated future cost to reclaim the land.
Under our land leases for our wind generation facilities, we are required to reclaim land where we have placed wind turbines.
The reclamation liabilities are recorded at the present value of the estimated future cost to reclaim the land.
Under its mining permit, WRDC is required to reclaim all land where it has mined reserves. The reclamation liability is recorded
at the present value of the estimated future cost to reclaim the land.
See Note 7 for additional information.
Manufactured Gas Plant
In 2008, we acquired whole and partial liabilities for former manufactured gas plant sites in Nebraska and Iowa, which were
previously used to convert coal to natural gas. The acquisition provided for an insurance recovery, now valued at $1.4 million
recorded in Other assets, non-current on our Consolidated Balance Sheets, which will be used to help offset remediation costs.
We also have a $2.7 million regulatory asset for manufactured gas plant sites; see Note 2 for additional information. As of
December 31, 2023, we had $4.1 million and $0.6 million accrued for remediation of the manufactured gas plant sites in Iowa
and Nebraska, respectively. Iowa's liabilities are included in Accrued Liabilities and Nebraska's liabilities are included in Other
deferred credits and other liabilities on our Consolidated Balance Sheets. The remediation cost estimate could change materially
due to results of further investigations, actions of environmental agencies or the financial viability of other responsible parties.
75
10-KFORM 10-K |
Contingencies and Legal Proceedings
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted
under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities
are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts
required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with
applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements.
We record gain contingencies when realized and expected recoveries under applicable insurance contracts when we are
assured of recovery.
GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (U.S. 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. We continue to believe this lawsuit has no merit and will vigorously defend it. At this
time, we do not believe any losses from this matter will have a material impact on our financial position, results of operations and
cash flows.
Gain Contingency -- Wygen 1 Business Interruption Insurance Recovery
In September 2021, Wygen I experienced an unplanned outage that continued until December 2021. For the year ended
December 31, 2021, the outage resulted in lost revenues at our subsidiaries Black Hills Wyoming and WRDC. A claim for these
losses was submitted under our business interruption insurance policy. During the third quarter of 2023 we recovered $5.0
million from our business interruption insurance, which was recognized as Revenue in our Consolidated Statements of Income
for year ended December 31, 2023.
Indemnification
In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as
information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our
directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not
contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In
certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies
that may provide coverage against certain claims under these indemnities.
Guarantees
We have entered into various parent company-level guarantees providing financial or performance assurance to third parties on
behalf of certain of our subsidiaries. These guarantees do not represent incremental consolidated obligations, but rather,
represent guarantees of subsidiary obligations to allow those subsidiaries to conduct business without posting other forms of
assurance. The agreements, which are off-balance sheet commitments, include support for business operations, indemnification
for reclamation and surety bonds. The guarantees were entered into in the normal course of business. To the extent liabilities
are incurred as a result of activities covered by these guarantees, such liabilities are included in our Consolidated Balance
Sheets.
We had the following guarantees in place as of (in millions):
Nature of Guarantee
Indemnification for reclamation/surety bonds
Guarantees supporting business transactions
Total guarantees
Maximum Exposure at
December 31, 2023
100.9
462.9
563.8
$
$
76
10-K| FORM 10-K
Contingencies and Legal Proceedings
In the normal course of business, we are subject to various lawsuits, actions, proceedings, claims and other matters asserted
under laws and regulations. We believe the amounts provided in the consolidated financial statements to satisfy alleged liabilities
are adequate in light of the probable and estimable contingencies. However, there can be no assurance that the actual amounts
required to satisfy alleged liabilities from various legal proceedings, claims and other matters discussed, and to comply with
applicable laws and regulations will not exceed the amounts reflected in the consolidated financial statements.
We record gain contingencies when realized and expected recoveries under applicable insurance contracts when we are
assured of recovery.
Colorado)
GT Resources, LLC v. Black Hills Corporation, Case No. 2020CV30751 (U.S. District Court for the City and County of Denver,
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. We continue to believe this lawsuit has no merit and will vigorously defend it. At this
time, we do not believe any losses from this matter will have a material impact on our financial position, results of operations and
cash flows.
Gain Contingency -- Wygen 1 Business Interruption Insurance Recovery
In September 2021, Wygen I experienced an unplanned outage that continued until December 2021. For the year ended
December 31, 2021, the outage resulted in lost revenues at our subsidiaries Black Hills Wyoming and WRDC. A claim for these
losses was submitted under our business interruption insurance policy. During the third quarter of 2023 we recovered $5.0
million from our business interruption insurance, which was recognized as Revenue in our Consolidated Statements of Income
for year ended December 31, 2023.
Indemnification
In the normal course of business, we enter into agreements that include indemnification in favor of third parties, such as
information technology agreements, purchase and sale agreements and lease contracts. We have also agreed to indemnify our
directors, officers and employees in accordance with our articles of incorporation, as amended. Certain agreements do not
contain any limits on our liability and therefore, it is not possible to estimate our potential liability under these indemnifications. In
certain cases, we have recourse against third parties with respect to these indemnities. Further, we maintain insurance policies
that may provide coverage against certain claims under these indemnities.
Guarantees
Sheets.
We have entered into various parent company-level guarantees providing financial or performance assurance to third parties on
behalf of certain of our subsidiaries. These guarantees do not represent incremental consolidated obligations, but rather,
represent guarantees of subsidiary obligations to allow those subsidiaries to conduct business without posting other forms of
assurance. The agreements, which are off-balance sheet commitments, include support for business operations, indemnification
for reclamation and surety bonds. The guarantees were entered into in the normal course of business. To the extent liabilities
are incurred as a result of activities covered by these guarantees, such liabilities are included in our Consolidated Balance
We had the following guarantees in place as of (in millions):
Nature of Guarantee
Indemnification for reclamation/surety bonds
Guarantees supporting business transactions
Total guarantees
Maximum Exposure at
December 31, 2023
100.9
462.9
563.8
$
$
(4) REVENUE
The following tables depict the disaggregation of revenue, including intercompany revenue, from contracts with customers by
customer type and timing of revenue recognition for each of the reportable segments, for the years ended December 31, 2023,
2022 and 2021. Sales tax and other similar taxes are excluded from revenues.
Year ended December 31, 2023
Customer types:
Retail
Transportation
Wholesale
Market - off-system sales
Transmission/Other
Revenue from contracts with customers
Other revenues
Total revenues
Timing of revenue recognition:
Services transferred at a point in time
Services transferred over time
Revenue from contracts with customers
Year ended December 31, 2022
Customer types:
Retail
Transportation
Wholesale
Market - off-system sales
Transmission/Other
Revenue from contracts with customers
Other revenues
Total revenues
Timing of revenue recognition:
Services transferred at a point in time
Services transferred over time
Revenue from contracts with customers
Year ended December 31, 2021
Customer types:
Retail
Transportation
Wholesale
Market - off-system sales
Transmission/Other
Revenue from contracts with customers
Other revenues
Total revenues
Timing of revenue recognition:
Services transferred at a point in time
Services transferred over time
Revenue from contracts with customers
Electric Utilities
Gas Utilities
Inter-segment
Eliminations
Total
$
$
$
$
697.7 $
—
34.2
50.9
71.4
854.2
10.8
865.0 $
31.5 $
822.7
854.2 $
(in millions)
1,248.8 $
176.8
—
0.4
39.4
1,465.4
18.8
1,484.2 $
— $
1,465.4
1,465.4 $
— $
(0.5)
—
—
(17.4)
(17.9)
—
(17.9) $
— $
(17.9)
(17.9) $
1,946.5
176.3
34.2
51.3
93.4
2,301.7
29.6
2,331.3
31.5
2,270.2
2,301.7
Electric Utilities
Gas Utilities
Inter-segment
Eliminations
Total
$
$
$
$
739.7 $
—
44.8
48.6
61.5
894.6
5.6
900.2 $
30.4 $
864.2
894.6 $
(in millions)
1,453.3 $
173.3
—
0.8
37.9
1,665.3
3.8
1,669.1 $
— $
1,665.3
1,665.3 $
— $
(0.4)
—
—
(16.6)
(17.0)
(0.5)
(17.5) $
— $
(17.0)
(17.0) $
2,193.0
172.9
44.8
49.4
82.8
2,542.9
8.9
2,551.8
30.4
2,512.5
2,542.9
Electric Utilities
Gas Utilities
Inter-segment
Eliminations
Total
$
$
$
$
711.5 $
—
30.8
41.7
52.9
836.9
5.3
842.2 $
27.1 $
809.8
836.9 $
(in millions)
913.7 $
158.1
—
0.4
39.4
1,111.6
13.3
1,124.9 $
— $
1,111.6
1,111.6 $
— $
(0.4)
—
—
(17.2)
(17.6)
(0.4)
(18.0) $
— $
(17.6)
(17.6) $
1,625.2
157.7
30.8
42.1
75.1
1,930.9
18.2
1,949.1
27.1
1,903.8
1,930.9
77
10-KFORM 10-K |
(5) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment at December 31 consisted of the following (dollars in millions):
Electric Utilities
Electric plant:
Production
Electric transmission
Electric distribution
Integrated Generation
Plant acquisition adjustment (a)
General
Total electric plant in service
Construction work in progress
Total electric plant
Less accumulated depreciation and
depletion
Electric plant net of accumulated
depreciation and depletion
2023
2022
Lives (in years)
Property, Plant
and Equipment
Weighted
Average Useful
Life (in years)
Property, Plant
and Equipment
Weighted
Average Useful
Life (in years) Minimum
Maximum
$
1,492.8
737.4
1,146.9
720.0
4.9
291.7
4,393.7
123.1
4,516.8
$
40
48
47
30
32
27
1,482.1
632.9
1,082.5
713.5
4.9
274.8
4,190.7
153.0
4,343.7
(1,207.7)
(1,104.1)
$
3,309.1
$
3,239.6
41
48
47
31
32
27
32
42
45
19
32
24
45
51
50
38
32
28
____________________
(a) The plant acquisition adjustment, which relates to the acquisition of our ownership interest in Wyodak Plant, is included in rate base and is
being recovered with 7 years remaining.
2023
2022
Lives (in years)
Property, Plant
and Equipment
Weighted
Average Useful
Life (in years)
Property, Plant
and Equipment
Weighted
Average Useful
Life (in years)
$
$
Minimum
Gas Utilities
Gas plant:
Production
Gas transmission
Gas distribution
Cushion gas - not depreciable (a)
Storage
General
Total gas plant in service
Construction work in progress
Total gas plant
Less accumulated depreciation
Gas plant net of accumulated depreciation $
____________________
(a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. In 2022, assets
classified as Cushion gas - depreciable were fully depreciated and removed from gross plant in service and accumulated depreciation.
17.8
695.4
2,620.2
63.1
65.8
497.4
3,959.7
52.0
4,011.7
(471.0)
3,540.7
21.0
759.5
2,860.0
58.2
71.4
571.8
4,341.9
39.2
4,381.1
(588.3)
3,792.8
47
72
61
N/A
49
25
45
58
57
N/A
41
23
24
32
48
N/A
36
20
45
58
57
N/A
42
22
$
Maximum
2023
2022
Lives (in years)
Corporate
Total plant in service
Construction work in progress
Total gross property, plant and equipment
Less accumulated depreciation
Total net of accumulated depreciation
Property, Plant
and Equipment
5.7
$
13.6
19.3
(1.9)
17.4
$
Weighted
Average Useful
Life (in years)
10
Property, Plant
and Equipment
5.7
$
13.7
19.4
(1.8)
17.6
$
Weighted
Average Useful
Life (in years)
11
Minimum
4
Maximum
23
78
10-K| FORM 10-K
Property, plant and equipment at December 31 consisted of the following (dollars in millions):
2023
Weighted
2022
Lives (in years)
Weighted
Property, Plant
Average Useful
Property, Plant
Average Useful
and Equipment
Life (in years)
and Equipment
Life (in years) Minimum
Maximum
$
$
Electric Utilities
Electric plant:
Production
Electric transmission
Electric distribution
Integrated Generation
Plant acquisition adjustment (a)
General
Total electric plant in service
Construction work in progress
Total electric plant
Less accumulated depreciation and
depletion
Electric plant net of accumulated
depreciation and depletion
____________________
Gas Utilities
Gas plant:
Production
Gas transmission
Gas distribution
Storage
General
Cushion gas - not depreciable (a)
Total gas plant in service
Construction work in progress
Total gas plant
Less accumulated depreciation
Gas plant net of accumulated depreciation $
____________________
40
48
47
30
32
27
45
58
57
N/A
42
22
1,492.8
737.4
1,146.9
720.0
4.9
291.7
4,393.7
123.1
4,516.8
21.0
759.5
2,860.0
58.2
71.4
571.8
4,341.9
39.2
4,381.1
(588.3)
3,792.8
(1,207.7)
(1,104.1)
$
3,309.1
$
3,239.6
2023
Weighted
2022
Lives (in years)
Weighted
Property, Plant
Average Useful
Property, Plant
Average Useful
and Equipment
Life (in years)
and Equipment
Life (in years)
Minimum
Maximum
41
48
47
31
32
27
45
58
57
N/A
41
23
32
42
45
19
32
24
45
51
50
38
32
28
24
32
48
N/A
36
20
47
72
61
N/A
49
25
(a) Depreciation of Cushion Gas is determined by the respective regulatory jurisdiction in which the Cushion Gas resides. In 2022, assets
classified as Cushion gas - depreciable were fully depreciated and removed from gross plant in service and accumulated depreciation.
2023
Weighted
2022
Lives (in years)
Weighted
Property, Plant
Average Useful
Property, Plant
Average Useful
and Equipment
Life (in years)
and Equipment
Life (in years)
Minimum
Maximum
10
11
4
23
Corporate
Total plant in service
Construction work in progress
Total gross property, plant and equipment
Less accumulated depreciation
Total net of accumulated depreciation
5.7
13.6
19.3
(1.9)
17.4
1,482.1
632.9
1,082.5
713.5
4.9
274.8
4,190.7
153.0
4,343.7
17.8
695.4
2,620.2
63.1
65.8
497.4
3,959.7
52.0
4,011.7
(471.0)
3,540.7
5.7
13.7
19.4
(1.8)
17.6
$
$
$
$
$
$
$
(5) PROPERTY, PLANT AND EQUIPMENT
(6) JOINTLY OWNED FACILITIES
Our consolidated financial statements include our share of several jointly-owned facilities as described below. Our share of the
facilities’ expenses is reflected in the appropriate categories of operating expenses in the Consolidated Statements of Income.
Each owner of the facility is responsible for financing its investment in the jointly-owned facilities.
At December 31, 2023, our interests in jointly-owned generating facilities and transmission systems were (in millions):
Wyodak Plant (a)
Transmission Tie
Wygen III (b)
Wygen I (c)
Ownership
Interest
Plant in Service
Construction
Work in
Progress
Less
Accumulated
Depreciation
Plant Net of
Accumulated
Depreciation
20%$
35%$
52%$
76.5%$
122.3 $
24.5 $
145.3 $
116.0 $
— $
0.3 $
0.3 $
0.8 $
(73.4) $
(7.8) $
(32.2) $
(60.1) $
48.9
17.0
113.4
56.7
(a)
(b)
(c)
In addition to supplying South Dakota Electric with coal for its share of the Wyodak Plant, our mine supplies PacifiCorp’s share of the coal
under a separate long-term agreement through December 31, 2026, with an annual renewal option for one-year extensions. This coal
supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.
South Dakota Electric retains responsibility for plant operations. WRDC supplies fuel to Wygen III for the life of the plant.
Black Hills Wyoming retains responsibility for plant operations. WRDC supplies fuel to Wygen I for the life of the plant.
(a) The plant acquisition adjustment, which relates to the acquisition of our ownership interest in Wyodak Plant, is included in rate base and is
being recovered with 7 years remaining.
(7) ASSET RETIREMENT OBLIGATIONS
We have identified legal obligations related to reclamation of mining sites; removal of fuel tanks, transformers containing
polychlorinated biphenyls, an evaporation pond; and reclamation of wind turbine sites at our Electric Utilities segment. In
addition, we have identified legal obligations related to retirement of gas pipelines, wells and compressor stations at our Gas
Utilities and removal of asbestos at our Utilities. We periodically review and update estimated costs related to these AROs. The
actual cost may vary from estimates due to regulatory requirements, changes in technology and increased labor, materials and
equipment costs.
The following tables present the details of AROs which are included on the accompanying Consolidated Balance Sheets in Other
deferred credits and other liabilities (in millions):
December 31,
2022
Liabilities
Incurred
Liabilities
Settled
Accretion
Revisions to
Prior
Estimates
December 31,
2023
Electric Utilities
Gas Utilities (a)
Total
$
$
27.6 $
61.3
88.9 $
— $
6.7
6.7 $
— $
—
— $
1.2 $
2.3
3.5 $
(0.1) $
(2.8)
(2.9) $
28.7
67.5
96.2
December 31,
2021
Liabilities
Incurred
Liabilities
Settled
Accretion
Revisions to
Prior
Estimates
December 31,
2022
Electric Utilities
Gas Utilities (a)
Total
$
$
30.1 $
45.5
75.6 $
— $
—
— $
(3.0) $
(0.2)
(3.2) $
1.4 $
2.0
3.4 $
(0.9) $
14.0
13.1 $
27.6
61.3
88.9
(a)
The Revisions to Prior Estimates were primarily driven by changes in estimates associated with natural gas wells and compressor
stations.
We also have legally required AROs related to certain assets within our electric transmission and distribution systems. These
retirement obligations are pursuant to an easement or franchise agreement and are only required if we discontinue our utility
service under such easement or franchise agreement. Accordingly, it is not possible to estimate a time period when these
obligations could be settled, and therefore, a liability for the cost of these obligations cannot be measured at this time.
79
10-KFORM 10-K |
(8) FINANCING
Shelf Registration Statement
We maintain an effective shelf registration statement with the SEC under which we may issue, from time to time, an unspecified
amount of senior debt securities, subordinate debt securities, common stock, preferred stock, warrants and other securities. In
anticipation of the approaching expiration of our previous shelf registration statement on Form S-3 originally filed on August 4,
2020 (Registration No. 333-240320), we filed a new shelf registration statement on Form S-3 on June 16, 2023 (Registration No.
333-272739).
Short-term debt
Revolving Credit Facility and CP Program
On May 9, 2023, we amended and restated our corporate Revolving Credit Facility, which replaced LIBOR as a benchmark
interest rate with the SOFR. The adoption of SOFR as a benchmark interest rate was in advance of the scheduled elimination of
LIBOR as a benchmark interest rate on June 30, 2023. No other significant terms or conditions, including borrowing capacity,
credit spreads or financial covenants were modified under these amendments and restatements.
We have a $750 million Revolving Credit Facility that matures on July 19, 2026, with two one-year extension options (subject to
consent from lenders). 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.
Borrowings continue to be available under a base rate or various SOFR rate options. The interest costs associated with the
letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our
Corporate credit rating from S&P, Fitch and Moody's for our senior unsecured long-term debt. Based on our current credit
ratings, the margins for base rate borrowings, SOFR borrowings and letters of credit were 0.125%, 1.125% and 1.125%,
respectively, at December 31, 2023. Based on our credit ratings, the commitment fee on unused amounts was 0.175%.
We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding
under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The
notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or
are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the
note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our
unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration
exemption.
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 at December 31 (dollars in millions):
Amount outstanding
Letters of credit (a)
Available capacity
Weighted average interest rates
$
2023
2022
— $
3.7
746.3
N/A
535.6
24.6
189.8
4.88%
(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 for the years ended December 31 was as follows (in millions):
Maximum amount outstanding (based on daily outstanding balances)
Average amount outstanding (based on daily outstanding balances)
Weighted average interest rates
Deferred Financing Costs on the Revolving Credit Facility
$
2023
2022
548.7 $
81.7
4.91%
572.3
390.7
2.11%
Total accumulated deferred financing costs on the Revolving Credit Facility of $8.9 million are being amortized over its estimated
useful life and were included in Interest expense on the accompanying Consolidated Statements of Income. See below for
additional details.
80
10-K| FORM 10-K We maintain an effective shelf registration statement with the SEC under which we may issue, from time to time, an unspecified
amount of senior debt securities, subordinate debt securities, common stock, preferred stock, warrants and other securities. In
anticipation of the approaching expiration of our previous shelf registration statement on Form S-3 originally filed on August 4,
2020 (Registration No. 333-240320), we filed a new shelf registration statement on Form S-3 on June 16, 2023 (Registration No.
(8) FINANCING
Shelf Registration Statement
333-272739).
Short-term debt
Revolving Credit Facility and CP Program
On May 9, 2023, we amended and restated our corporate Revolving Credit Facility, which replaced LIBOR as a benchmark
interest rate with the SOFR. The adoption of SOFR as a benchmark interest rate was in advance of the scheduled elimination of
LIBOR as a benchmark interest rate on June 30, 2023. No other significant terms or conditions, including borrowing capacity,
credit spreads or financial covenants were modified under these amendments and restatements.
We have a $750 million Revolving Credit Facility that matures on July 19, 2026, with two one-year extension options (subject to
consent from lenders). 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.
Borrowings continue to be available under a base rate or various SOFR rate options. The interest costs associated with the
letters of credit or borrowings and the commitment fee under the Revolving Credit Facility are determined based upon our
Corporate credit rating from S&P, Fitch and Moody's for our senior unsecured long-term debt. Based on our current credit
ratings, the margins for base rate borrowings, SOFR borrowings and letters of credit were 0.125%, 1.125% and 1.125%,
respectively, at December 31, 2023. Based on our credit ratings, the commitment fee on unused amounts was 0.175%.
We have a $750 million, unsecured CP Program that is backstopped by the Revolving Credit Facility. Amounts outstanding
under the Revolving Credit Facility and the CP Program, either individually or in the aggregate, cannot exceed $750 million. The
notes issued under the CP Program may have maturities not to exceed 397 days from the date of issuance and bear interest (or
are sold at par less a discount representing an interest factor) based on, among other things, the size and maturity date of the
note, the frequency of the issuance and our credit ratings. Under the CP Program, any borrowings rank equally with our
unsecured debt. Notes under the CP Program are not registered and are offered and issued pursuant to a registration
exemption.
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 at December 31 (dollars in millions):
2023
2022
$
— $
3.7
746.3
N/A
535.6
24.6
189.8
4.88%
Amount outstanding
Letters of credit (a)
Available capacity
Weighted average interest rates
Facility.
(a)
Letters of credit are off-balance sheet commitments that reduce the borrowing capacity available on our corporate Revolving Credit
Revolving Credit Facility and CP Program borrowing activity for the years ended December 31 was as follows (in millions):
Maximum amount outstanding (based on daily outstanding balances)
Average amount outstanding (based on daily outstanding balances)
$
Weighted average interest rates
2023
2022
548.7 $
81.7
4.91%
572.3
390.7
2.11%
Deferred Financing Costs on the Revolving Credit Facility
Total accumulated deferred financing costs on the Revolving Credit Facility of $8.9 million are being amortized over its estimated
useful life and were included in Interest expense on the accompanying Consolidated Statements of Income. See below for
additional details.
Long-term debt
Long-term debt outstanding was as follows (dollars in millions):
Interest Rate at
December 31,
2023
Balance Outstanding
December 31,
2023
December 31,
2022
Due Date
November 30, 2023
August 23, 2024
January 15, 2026
January 15, 2027
March 15, 2028
October 15, 2029
June 15, 2030
May 1, 2033
May 15, 2034
September 15, 2046
October 15, 2049
N/A
1.04%
3.95%
3.15%
5.95%
3.05%
2.50%
4.35%
6.15%
4.20%
3.88%
August 15, 2032
November 1, 2039
October 20, 2044
7.23%
6.13%
4.43%
March 1, 2027
November 20, 2037
October 20, 2044
3.93%
6.67%
4.53%
Corporate
Senior unsecured notes due 2023
Senior unsecured notes due 2024
Senior unsecured notes due 2026
Senior unsecured notes due 2027
Senior unsecured notes due 2028
Senior unsecured notes, due 2029
Senior unsecured notes, due 2030
Senior unsecured notes due 2033
Senior unsecured notes due 2034
Senior unsecured notes, due 2046
Senior unsecured notes, due 2049
Total Corporate debt
Less unamortized debt discount
Total Corporate debt, net
South Dakota Electric
First Mortgage Bonds due 2032
First Mortgage Bonds due 2039
First Mortgage Bonds due 2044
Total South Dakota Electric debt
Less unamortized debt discount
Total South Dakota Electric debt, net
Wyoming Electric
Industrial development revenue bonds due 2027(a) (b)
First Mortgage Bonds due 2037
First Mortgage Bonds due 2044
Total Wyoming Electric debt
Less unamortized debt discount
Total Wyoming Electric debt, net
Total long-term debt
Less current maturities
Less unamortized deferred financing costs (c)
Long-term debt, net of current maturities and deferred
financing costs
$
— $
600.0
300.0
400.0
350.0
400.0
400.0
400.0
450.0
300.0
300.0
3,900.0
(8.9)
3,891.1
75.0
180.0
85.0
340.0
(0.1)
339.9
10.0
110.0
75.0
195.0
—
195.0
525.0
600.0
300.0
400.0
—
400.0
400.0
400.0
—
300.0
300.0
3,625.0
(5.3)
3,619.7
75.0
180.0
85.0
340.0
(0.1)
339.9
10.0
110.0
75.0
195.0
—
195.0
4,426.0
(600.0)
(24.8)
4,154.6
(525.0)
(22.3)
$
3,801.2 $
3,607.3
(a)
(b)
(c)
Variable interest rate.
A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the $10 million bonds due March 1, 2027. In
the case of default, we hold the assumption of liability for drawings on Wyoming Electric’s Letter of Credit attached to these bonds.
Includes deferred financing costs associated with our Revolving Credit Facility of $1.1 million and $1.8 million as of December 31, 2023
and December 31, 2022, respectively.
Scheduled maturities of long-term debt and associated interest payments by year are shown below (in millions):
2024
2025
Payments Due by Period
2027
2028
2026
Thereafter
Total
Principal payments on Long-term
debt including current maturities
(a)
$
Interest payments on Long-term
debt (a)
600.0 $
— $
300.0 $
410.0 $
350.0 $
2,775.0 $
4,435.0
179.0
168.1
162.2
149.6
132.9
1,052.2
1,844.0
(a)
Long-term debt amounts do not include deferred financing costs or discounts or premiums on debt. Estimated interest payments on
variable rate debt are calculated by utilizing the applicable rates as of December 31, 2023.
81
10-KFORM 10-K |
Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in
compliance with at December 31, 2023. See below for additional information.
Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures
securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in
amounts limited by property, earnings and other provisions of the mortgage indentures.
Debt Transactions
On September 15, 2023, we completed a public debt offering of $450 million, 6.15% senior unsecured notes due May 15, 2034.
Proceeds from the offering, which were net of $7.6 million of deferred financing costs, along with available cash were used to
repay all of our $525 million principal amount outstanding notes on their November 30, 2023 maturity date and for other general
corporate purposes.
On March 7, 2023, we completed a public debt offering of $350 million, 5.95% five year senior unsecured notes due March 15,
2028. The proceeds from the offering, which were net of $4.2 million of deferred financing costs, were used to repay notes
outstanding under our CP Program and for other general corporate purposes.
Debt Covenants
Revolving Credit Facility
We were in compliance with all of our Revolving Credit Facility covenants as of December 31, 2023. 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 December 31, 2023, our Consolidated Indebtedness to Capitalization
Ratio was 0.58 to 1.00.
Wyoming Electric
Wyoming Electric was in compliance with all covenants within its financing agreements as of December 31, 2023. Wyoming
Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2023, Wyoming
Electric's debt to capitalization ratio was 0.51 to 1.00.
Dividend Restrictions
Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends when a default or
event of default occurs.
Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions
made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain
statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our
subsidiaries.
Our Utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal
Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2023, the amount of restricted net
assets at our Utilities that may not be distributed to our utility holding company in the form of a loan or dividend was
approximately $142.6 million.
South Dakota Electric and Wyoming Electric are generally limited to the amount of dividends allowed to be paid to our utility
holding company under certain financing agreements.
Equity
Although our aforementioned shelf registration statement does not limit our issuance capacity, our ability to issue securities is
limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions
imposed by federal and state regulatory authorities. Our articles of incorporation authorize the issuance of 100 million shares of
common stock and 25 million shares of preferred stock. As of December 31, 2023, we had approximately 68 million shares of
common stock outstanding and no shares of preferred stock outstanding.
82
10-K| FORM 10-K Debt Transactions
corporate purposes.
Debt Covenants
Revolving Credit Facility
Ratio was 0.58 to 1.00.
Wyoming Electric
Dividend Restrictions
event of default occurs.
subsidiaries.
Equity
Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in
At-the-Market Equity Offering Program
compliance with at December 31, 2023. See below for additional information.
Substantially all of the tangible utility property of South Dakota Electric and Wyoming Electric is subject to the lien of indentures
securing their first mortgage bonds. First mortgage bonds of South Dakota Electric and Wyoming Electric may be issued in
amounts limited by property, earnings and other provisions of the mortgage indentures.
On September 15, 2023, we completed a public debt offering of $450 million, 6.15% senior unsecured notes due May 15, 2034.
Proceeds from the offering, which were net of $7.6 million of deferred financing costs, along with available cash were used to
repay all of our $525 million principal amount outstanding notes on their November 30, 2023 maturity date and for other general
On March 7, 2023, we completed a public debt offering of $350 million, 5.95% five year senior unsecured notes due March 15,
2028. The proceeds from the offering, which were net of $4.2 million of deferred financing costs, were used to repay notes
outstanding under our CP Program and for other general corporate purposes.
We were in compliance with all of our Revolving Credit Facility covenants as of December 31, 2023. 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 December 31, 2023, our Consolidated Indebtedness to Capitalization
Wyoming Electric was in compliance with all covenants within its financing agreements as of December 31, 2023. Wyoming
Electric is required to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2023, Wyoming
Electric's debt to capitalization ratio was 0.51 to 1.00.
As previously disclosed, on August 4, 2020, we entered into an Amended and Restated Equity Distribution Sales Agreement
("Previous Sales Agreement") to sell shares of common stock up to an aggregate of $400 million, from time to time, through our
ATM program utilizing our shelf registration statement. In conjunction with the new shelf registration statement filing discussed
above, we entered into a new Equity Distribution Sales Agreement ("Sales Agreement") on June 16, 2023. We also terminated
the Previous Sales Agreement on June 16, 2023. The Sales Agreement is similar to the Previous Sales Agreement and allows
us to sell shares of common stock up to an aggregate of $400 million through our ATM program.
ATM activity for the years ended December 31 was as follows (in millions, except Average price per share amounts):
December 31,
2023
December 31,
2022
December 31,
2021
August 4, 2020 ATM Program
Proceeds, (net of issuance costs of $(0.5), $(0.9) and $(1.1), respectively) $
Number of shares issued
June 16, 2023 ATM Program
Proceeds, (net of issuance costs of $(0.7), $0, $0, respectively
Number of shares issued
$
Total activity under both ATM Programs
Proceeds, (net of issuance costs of $(1.2), $(0.9) and $(1.1), respectively) $
Number of shares issued
Average price per share
$
Shareholder Dividend Reinvestment and Stock Purchase Plan
48.5 $
0.8
70.2 $
1.2
118.7 $
2.0
59.04 $
90.3 $
1.3
118.8
1.8
— $
—
90.3 $
1.3
69.74 $
—
—
118.8
1.8
66.18
Effective as of July 7, 2023, we terminated our DRSPP. On July 10, 2023, we filed a post-effective amendment to amend the
Registration Statement on Form S-3 (File No. 333-240319) filed with the SEC on August 4, 2020. The filing of this post-effective
amendment de-registered all shares of common stock that were issuable under the DRSPP but not sold as of July 7, 2023. With
the termination of the DRSPP, a direct stock purchase plan is being offered which will allow shareholders to continue making
share transactions. This plan is sponsored and administered solely by EQ Shareowner Services, our transfer agent.
Our Revolving Credit Facility and other debt obligations contain restrictions on the payment of cash dividends when a default or
(9) RISK MANAGEMENT AND DERIVATIVES
Market and Credit Risk Disclosures
Due to our holding company structure, substantially all of our operating cash flows are provided by dividends paid or distributions
made by our subsidiaries. The cash to pay dividends to our shareholders is derived from these cash flows. As a result, certain
statutory limitations or regulatory or financing agreements could affect the levels of distributions allowed to be made by our
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.
Our Utilities are generally limited to the amount of dividends allowed to be paid to our utility holding company under the Federal
Power Act and settlement agreements with state regulatory jurisdictions. As of December 31, 2023, the amount of restricted net
assets at our Utilities that may not be distributed to our utility holding company in the form of a loan or dividend was
approximately $142.6 million.
South Dakota Electric and Wyoming Electric are generally limited to the amount of dividends allowed to be paid to our utility
holding company under certain financing agreements.
Although our aforementioned shelf registration statement does not limit our issuance capacity, our ability to issue securities is
limited to the authority granted by our Board of Directors, certain covenants in our financing arrangements and restrictions
imposed by federal and state regulatory authorities. Our articles of incorporation authorize the issuance of 100 million shares of
common stock and 25 million shares of preferred stock. As of December 31, 2023, we had approximately 68 million shares of
common stock outstanding and no shares of preferred stock outstanding.
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 the COVID-19 pandemic, weather (e.g. Winter Storm Uri), geopolitical events, market
speculation, 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, such as the 2008 financial crisis and the COVID-19 pandemic.
•
•
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.
83
10-KFORM 10-K |
We perform periodic credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s
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. Our credit exposure at December 31, 2023 was concentrated primarily among retail utility
customers, investment grade companies, cooperative utilities and federal agencies.
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 (Loss) are detailed below and within Note 10.
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 state regulatory commission guidelines. When the related costs are recovered
through our rates, the hedging activity is recognized in the Consolidated Statements of Income.
We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load
requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for
the normal purchase and normal sales exception to derivative accounting. Changes in the fair value of these commodity
derivatives are recognized in the Consolidated Statements of Income.
To support our Choice Gas Program customers, we buy, sell and deliver natural gas 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 January 2024
through October 2025. 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 natural gas derivative commodity instruments held by our utilities are
comprised of both short and long positions. We had the following net long positions as of:
Units
MMBtus
Natural gas futures purchased
MMBtus
Natural gas options purchased, net
MMBtus
Natural gas basis swaps purchased
Natural gas over-the-counter swaps, net (b) MMBtus
Natural gas physical commitments, net (c)
MMBtus
December 31, 2023
December 31, 2022
Notional
Amounts
650,000
2,850,000
1,050,000
3,890,000
12,582,415
Maximum Term
(months) (a)
3
3
3
21
10
Notional
Amounts
630,000
1,790,000
900,000
4,460,000
17,864,412
Maximum Term
(months) (a)
3
3
3
24
12
(a)
(b)
(c)
Term reflects the maximum forward period hedged.
As of December 31, 2023, 2,101,700 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.
Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP.
We have certain derivative contracts which contain credit provisions. These credit provisions may require the Company to post
collateral when credit exposure to the Company is in excess of a negotiated line of unsecured credit. At December 31, 2023, the
Company posted $2.0 million related to such provisions, which is included in Other current assets on the Consolidated Balance
Sheets.
84
10-K| FORM 10-K
We perform periodic credit evaluations of our customers and adjust credit limits based upon payment history and the customer’s
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. Our credit exposure at December 31, 2023 was concentrated primarily among retail utility
customers, investment grade companies, cooperative utilities and federal agencies.
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 (Loss) are detailed below and within Note 10.
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 state regulatory commission guidelines. When the related costs are recovered
through our rates, the hedging activity is recognized in the Consolidated Statements of Income.
We periodically have wholesale power purchase and sale contracts used to manage purchased power costs and load
requirements associated with serving our electric customers that are considered derivative instruments due to not qualifying for
the normal purchase and normal sales exception to derivative accounting. Changes in the fair value of these commodity
derivatives are recognized in the Consolidated Statements of Income.
To support our Choice Gas Program customers, we buy, sell and deliver natural gas 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 January 2024
through October 2025. 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 natural gas derivative commodity instruments held by our utilities are
comprised of both short and long positions. We had the following net long positions as of:
Natural gas futures purchased
Natural gas options purchased, net
Natural gas basis swaps purchased
Natural gas over-the-counter swaps, net (b) MMBtus
Natural gas physical commitments, net (c)
MMBtus
Units
MMBtus
MMBtus
MMBtus
Term reflects the maximum forward period hedged.
December 31, 2023
December 31, 2022
Maximum Term
(months) (a)
Maximum Term
(months) (a)
Notional
Amounts
650,000
2,850,000
1,050,000
3,890,000
12,582,415
3
3
3
21
10
Notional
Amounts
630,000
1,790,000
900,000
4,460,000
17,864,412
3
3
3
24
12
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 December 31, 2023, the
Company posted $2.0 million related to such provisions, which is included in Other current assets on the Consolidated Balance
(a)
(b)
(c)
Sheets.
Derivatives by Balance Sheet Classification
The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in
millions):
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives
Noncurrent commodity derivatives
Liability derivative instruments:
Current commodity derivatives
Noncurrent commodity derivatives
Total derivatives designated as hedges
Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives
Noncurrent commodity derivatives
Liability derivative instruments:
Current commodity derivatives
Noncurrent commodity derivatives
Total derivatives not designated as hedges
Derivatives Designated as Hedge Instruments
Balance Sheet Location
2023
2022
Derivative assets - current
Other assets, non-current
Derivative liabilities - current
Other deferred credits and other liabilities
Derivative assets - current
Other assets, non-current
Derivative liabilities - current
Other deferred credits and other liabilities
$
$
$
$
— $
—
(2.7)
(0.2)
(2.9) $
— $
—
(3.8)
(0.1)
(3.9) $
0.1
0.2
(1.7)
—
(1.4)
0.5
0.3
(4.9)
—
(4.1)
The impact of cash flow hedges on our Consolidated Statements of Comprehensive Income and Consolidated Statements of
Income is presented below for the years ended December 31, 2023, 2022 and 2021. 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.
2023
2022
2021
Derivatives in Cash Flow
Hedging Relationships
Interest rate swaps
Commodity derivatives
Total
$
$
Amount of Gain/(Loss)
Recognized in OCI
(in millions)
2.8 $
2.9 $
Income Statement
Location
2.8 Interest expense
(1.6)
1.3 $
(3.5)
(0.7) $
2.0
4.8
Fuel, purchased power and
cost of natural gas sold
$
$
2023
2021
2022
Amount of Gain/(Loss)
Reclassified from AOCI into
Income
(in millions)
(2.8) $
(2.9) $
(2.9)
(3.0)
(5.9) $
2.7
(0.1) $
2.1
(0.8)
As of December 31, 2023, $5.9 million of net losses related to our interest rate swaps and commodity derivatives are expected
to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized
gains or losses will change during future periods.
Derivatives Not Designated as Hedge Instruments
The following table summarizes the impacts of derivative instruments not designated as hedge instruments on our Consolidated
Statements of Income for the years ended December 31, 2023, 2022 and 2021. 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 gross
profit we realized when the underlying physical and financial transactions were settled.
As of December 31, 2023, 2,101,700 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.
Volumes exclude derivative contracts that qualify for the normal purchase, normal sales exception permitted by GAAP.
Derivatives Not Designated as Hedging
Instruments
Location of Gain/(Loss) on Derivatives
Recognized in Income
2023
2022
Amount of Gain/(Loss) on
Derivatives Recognized in Income
(in millions)
2021
Commodity derivatives - Natural Gas
Fuel, purchased power and cost of natural
gas sold
$
$
(4.2) $
(4.2) $
(0.8) $
(0.8) $
2.6
2.6
85
10-KFORM 10-K |
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 a Regulatory asset related to these
financial instruments used in our Gas Utilities were $5.1 million and $8.8 million at December 31, 2023 and 2022, respectively.
For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated
Statements of Income.
(10) FAIR VALUE MEASUREMENTS
Recurring Fair Value Measurements
Derivatives
Valuation methodologies for our derivatives are detailed within Note 1. 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 December 31, 2023
Level 1
Level 2
Level 3
(in millions)
Cash Collateral
and
Counterparty
Netting (a)
Total
$
$
$
$
— $
— $
— $
— $
1.9 $
1.9 $
10.1 $
10.1 $
— $
— $
— $
— $
(1.9) $
(1.9) $
(3.3) $
(3.3) $
Assets:
Commodity derivatives
Total
Liabilities:
Commodity derivatives
Total
(a)
As of December 31, 2023, $1.9 million of our commodity derivative gross assets and $3.3 million of our commodity derivative gross
liabilities, as well as related gross collateral amounts, were subject to master netting agreements.
As of December 31, 2022
Level 1
Level 2
Level 3
(in millions)
Cash Collateral
and
Counterparty
Netting (a)
Total
$
$
$
$
— $
— $
— $
— $
5.4 $
5.4 $
11.4 $
11.4 $
— $
— $
— $
— $
(4.3) $
(4.3) $
(4.8) $
(4.8) $
Assets:
Commodity derivatives
Total
Liabilities:
Commodity derivatives
Total
—
—
6.8
6.8
1.1
1.1
6.6
6.6
(a)
As of December 31, 2022, $4.3 million of our commodity derivative assets and $4.8 million of our commodity derivative liabilities, as well
as related gross collateral amounts, were subject to master netting agreements.
Pension and Postretirement Plan Assets
A discussion of the fair value of our Pension and Postretirement Plan assets is included in Note 13.
Other Fair Value Measurements
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.
86
10-K| FORM 10-K
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 a Regulatory asset related to these
financial instruments used in our Gas Utilities were $5.1 million and $8.8 million at December 31, 2023 and 2022, respectively.
For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated
Statements of Income.
(10) FAIR VALUE MEASUREMENTS
Recurring Fair Value Measurements
Derivatives
Valuation methodologies for our derivatives are detailed within Note 1. 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 December 31, 2023
Cash Collateral
and
Counterparty
Netting (a)
Total
Level 1
Level 2
Level 3
(in millions)
$
$
$
$
$
$
$
$
— $
— $
— $
— $
— $
— $
— $
— $
1.9 $
1.9 $
10.1 $
10.1 $
5.4 $
5.4 $
11.4 $
11.4 $
— $
— $
— $
— $
— $
— $
— $
— $
(1.9) $
(1.9) $
(3.3) $
(3.3) $
(4.3) $
(4.3) $
(4.8) $
(4.8) $
—
—
6.8
6.8
1.1
1.1
6.6
6.6
As of December 31, 2022
Cash Collateral
and
Counterparty
Netting (a)
Total
Level 1
Level 2
Level 3
(in millions)
Assets:
Total
Liabilities:
Total
Commodity derivatives
Commodity derivatives
Assets:
Total
Liabilities:
Total
Commodity derivatives
Commodity derivatives
(a)
As of December 31, 2023, $1.9 million of our commodity derivative gross assets and $3.3 million of our commodity derivative gross
liabilities, as well as related gross collateral amounts, were subject to master netting agreements.
The following table presents the carrying amounts and fair values of financial instruments not recorded at fair value on the
Consolidated Balance Sheets at December 31 (in millions):
Long-term debt, including current maturities (a)
$
4,401.2 $
4,215.6 $
4,132.3 $
3,760.8
(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.
2023
Carrying
Amount
Fair Value
2022
Carrying
Amount
Fair Value
(11) OTHER COMPREHENSIVE INCOME
We record deferred gains (losses) in AOCI related to interest rate swaps designated as cash flow hedges, commodity contracts
designated as cash flow hedges and the amortization of components of our defined benefit plans. Deferred gains (losses) for our
commodity contracts designated as cash flow hedges are recognized in earnings upon settlement, while deferred gains (losses)
related to our interest rate swaps are recognized in earnings as they are amortized.
The following table details reclassifications out of AOCI and into Net income. The amounts in parentheses below indicate
decreases to Net income in the Consolidated Statements of Income for the period, net of tax (in millions):
Location on the Consolidated
Statements of Income
Amount Reclassified from AOCI
December 31,
December 31,
2022
2023
Gains and (losses) on cash flow hedges:
Interest rate swaps
Commodity contracts
Interest expense
Fuel, purchased power and cost of
natural gas sold
Income tax
Income tax benefit (expense)
Total reclassification adjustments related to cash
flow hedges, net of tax
Amortization of components of defined benefit
plans:
Prior service cost
Actuarial gain (loss)
Income tax
Total reclassification adjustments related to
defined benefit plans, net of tax
Total reclassifications
Operations and maintenance
Operations and maintenance
Income tax benefit (expense)
$
$
$
$
$
(2.9) $
(3.0)
(5.9)
1.4
(4.5) $
— $
(0.2)
(0.2)
—
(0.2) $
(4.7) $
(2.8)
2.7
(0.1)
—
(0.1)
0.1
(0.8)
(0.7)
0.2
(0.5)
(0.6)
Balances by classification included within AOCI, net of tax on the accompanying Consolidated Balance Sheets were as follows
(in millions):
(a)
As of December 31, 2022, $4.3 million of our commodity derivative assets and $4.8 million of our commodity derivative liabilities, as well
as related gross collateral amounts, were subject to master netting agreements.
Pension and Postretirement Plan Assets
Other Fair Value Measurements
A discussion of the fair value of our Pension and Postretirement Plan assets is included in Note 13.
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.
Derivatives Designated as
Cash Flow Hedges
Interest Rate
Swaps
Commodity
Derivatives
Employee Benefit
Plans
Total
As of December 31, 2021
Other comprehensive income (loss)
before reclassifications
Amounts reclassified from AOCI
As of December 31, 2022
Other comprehensive income (loss)
before reclassifications
Amounts reclassified from AOCI
As of December 31, 2023
$
$
$
(10.4) $
—
2.1
(8.3) $
—
2.2
(6.1) $
1.5 $
(0.6)
(2.1)
(1.2) $
(3.6)
2.3
(2.5) $
(11.2) $
4.6
0.5
(6.1) $
(0.3)
0.2
(6.2) $
(20.1)
4.0
0.5
(15.6)
(3.9)
4.7
(14.8)
87
10-KFORM 10-K |
(12) VARIABLE INTEREST ENTITY
Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo,
Colorado. In 2016, Black Hills Electric Generation sold a 49.9%, non-controlling interest in Black Hills Colorado IPP to a third-
party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy
through 2031 to Colorado Electric.
Net income available for common stock for the years ended December 31, 2023, 2022 and 2021 was reduced by $13.8 million,
$12.4 million, and $14.5 million, respectively, attributable to this non-controlling interest. The net income allocable to the non-
controlling interest holder is based on ownership interest with the exception of certain agreed upon adjustments. Distributions of
net income attributable to this non-controlling interest are due within 30 days following the end of a quarter but may be withheld
as necessary by Black Hills Electric Generation.
Black Hills Colorado IPP has been determined to be a VIE in which the Company has a variable interest. Black Hills Electric
Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and
manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills
Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate
Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-
existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash
flows from operations are sufficient to support its ongoing operations.
We have recorded the following assets and liabilities on our Consolidated Balance Sheets related to the VIE described above as
of December 31 (in millions):
Assets:
Current assets
Property, plant and equipment
Liabilities:
Current liabilities
(13) EMPLOYEE BENEFIT PLANS
Defined Contribution Plans
2023
2022
15.1 $
166.8 $
12.8
178.8
4.8 $
5.4
$
$
$
We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of
their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides
employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.
The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not
currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age
and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the
participant has 5 years of service with the Company.
Defined Benefit Pension Plan
We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain
eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average
earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain
employees who did not meet age and service-based criteria.
The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy.
The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations
to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a
portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets
consist primarily of equity, fixed income and hedged investments.
88
10-K| FORM 10-K
(12) VARIABLE INTEREST ENTITY
Black Hills Colorado IPP owns and operates a 200 MW, combined-cycle natural gas generating facility located in Pueblo,
Colorado. In 2016, Black Hills Electric Generation sold a 49.9%, non-controlling interest in Black Hills Colorado IPP to a third-
party buyer. Black Hills Electric Generation is the operator of the facility, which is contracted to provide capacity and energy
through 2031 to Colorado Electric.
Net income available for common stock for the years ended December 31, 2023, 2022 and 2021 was reduced by $13.8 million,
$12.4 million, and $14.5 million, respectively, attributable to this non-controlling interest. The net income allocable to the non-
controlling interest holder is based on ownership interest with the exception of certain agreed upon adjustments. Distributions of
net income attributable to this non-controlling interest are due within 30 days following the end of a quarter but may be withheld
as necessary by Black Hills Electric Generation.
Black Hills Colorado IPP has been determined to be a VIE in which the Company has a variable interest. Black Hills Electric
Generation has been determined to be the primary beneficiary of the VIE as Black Hills Electric Generation is the operator and
manager of the generation facility and, as such, has the power to direct the activities that most significantly impact Black Hills
Colorado IPP’s economic performance. Black Hills Electric Generation, as the primary beneficiary, continues to consolidate
Black Hills Colorado IPP. Black Hills Colorado IPP has not received financial or other support from the Company outside of pre-
existing contractual arrangements during the reporting period. Black Hills Colorado IPP does not have any debt and its cash
flows from operations are sufficient to support its ongoing operations.
We have recorded the following assets and liabilities on our Consolidated Balance Sheets related to the VIE described above as
2023
2022
15.1 $
166.8 $
12.8
178.8
4.8 $
5.4
$
$
$
of December 31 (in millions):
Assets:
Current assets
Property, plant and equipment
Liabilities:
Current liabilities
(13) EMPLOYEE BENEFIT PLANS
Defined Contribution Plans
We sponsor a 401(k) retirement savings plan (the 401(k) Plan). Participants in the 401(k) Plan may elect to invest a portion of
their eligible compensation in the 401(k) Plan up to the maximum amounts established by the IRS. The 401(k) Plan provides
employees the opportunity to invest up to 50% of their eligible compensation on a pre-tax or after-tax basis.
The 401(k) Plan provides a Company matching contribution for all eligible participants. Certain eligible participants who are not
currently accruing a benefit in the Pension Plan also receive a Company retirement contribution based on the participant’s age
and years of service. Vesting of all Company and matching contributions occurs at 20% per year with 100% vesting when the
participant has 5 years of service with the Company.
Defined Benefit Pension Plan
We have one defined benefit pension plan, the Black Hills Retirement Plan (Pension Plan). The Pension Plan covers certain
eligible employees of the Company. The benefits for the Pension Plan are based on years of service and calculations of average
earnings during a specific time period prior to retirement. The Pension Plan is closed to new employees and frozen for certain
employees who did not meet age and service-based criteria.
The Pension Plan assets are held in a Master Trust. Our Board of Directors has approved the Pension Plan’s investment policy.
The objective of the investment policy is to manage assets in such a way that will allow the eventual settlement of our obligations
to the Pension Plan’s beneficiaries. To meet this objective, our pension assets are managed by an outside adviser using a
portfolio strategy that will provide liquidity to meet the Pension Plan’s benefit payment obligations. The Pension Plan’s assets
consist primarily of equity, fixed income and hedged investments.
The expected rate of return on the Pension Plan assets is determined by reviewing the historical and expected returns of both
equity and fixed income markets, taking into account asset allocation, the correlation between asset class returns and the mix of
active and passive investments. The Pension Plan utilizes a dynamic asset allocation where the target range to return-seeking
and liability-hedging assets is determined based on the funded status of the Plan. As of December 31, 2023, the expected rate
of return on pension plan assets was based on the targeted asset allocation range of 20% to 28% return-seeking assets and
72% to 80% liability-hedging assets.
Our Pension Plan is funded in compliance with the federal government’s funding requirements.
Plan Assets
The percentages of total plan asset by investment category for our Pension Plan at December 31 were as follows:
Return-seeking Assets
Equity
Real estate
Hedge funds
Fixed income
Total
Liability-hedging Assets
Fixed income
Cash
Total
Total Assets
2023
14%
5%
3%
2%
24%
2023
74%
2%
76%
100%
2022
14%
7%
3%
2%
26%
2022
72%
2%
74%
100%
Supplemental Non-qualified Defined Benefit Plans
We have various supplemental retirement plans for key executives of the Company. The plans are non-qualified defined benefit
and defined contribution plans (Supplemental Plans). The Supplemental Plans are subject to various vesting schedules and are
funded on a cash basis as benefits are paid.
Non-pension Defined Benefit Postretirement Healthcare Plan
BHC sponsors a retiree healthcare plan (Healthcare Plan) for employees who meet certain age and service requirements at
retirement. Healthcare Plan benefits are subject to premiums, deductibles, co-payment provisions and other limitations. A portion
of the Healthcare Plan for participating business units are pre-funded via VEBA trusts. Pre-65 retirees as well as a grandfathered
group of post-65 retirees receive their retiree medical benefits through the Black Hills self-insured retiree medical plans.
Healthcare coverage for post-65 Medicare-eligible retirees is provided through an individual market healthcare exchange. We
fund the Healthcare Plan on a cash basis as benefits are paid. The Healthcare Plan provides for partial pre-funding via VEBA
trusts. Assets related to this pre-funding are held in trust and are for the benefit of the union and non-union employees located in
the states of Arkansas, Iowa and Kansas. We do not pre-fund the Healthcare Plan for those employees outside Arkansas, Iowa
and Kansas.
Plan Contributions
Contributions to the Pension Plan are cash contributions made directly to the Master Trust. Healthcare and Supplemental Plan
contributions are made in the form of benefit payments. Healthcare benefits include company and participant paid premiums.
Contributions for the years ended December 31 were as follows (in millions):
Defined Contribution Plan
Company retirement contributions
Company matching contributions
Defined Benefit Plans
Defined Benefit Pension Plan
Non-Pension Defined Benefit Postretirement Healthcare Plan
Supplemental Non-Qualified Defined Benefit Plans
2023
2022
$
$
$
$
$
12.7 $
17.1 $
— $
5.4 $
3.5 $
11.9
16.2
—
6.1
3.1
We do not have any required contributions to our Pension Plan in 2024; however, we expect to make $2.3 million in
contributions.
89
10-KFORM 10-K |
Fair Value Measurements
The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a
recurring basis (in millions):
December 31, 2023
Level 1 Level 2 Level 3
Total
Investments
Measured at
Fair Value
NAV (a)
Total
Investments
Pension Plan
Common Collective Trust - Cash and Cash Equivalents
Common Collective Trust - Equity
Common Collective Trust - Fixed Income
Common Collective Trust - Real Estate
Hedge Funds
Total investments measured at fair value
Non-pension Defined Benefit Postretirement Healthcare
Plan
Cash and Cash Equivalents
Total investments measured at fair value
$ — $
6.7 $ — $
6.7 $ — $
—
—
—
—
42.7
234.5
—
—
—
—
—
—
42.7
234.5
—
—
—
—
16.4
8.1
$ — $ 283.9 $ — $
283.9 $ 24.5 $
8.0
8.0 $
$
—
— $ — $
—
8.0
8.0
$
6.7
42.7
234.5
16.4
8.1
308.4
8.0
8.0
December 31, 2022
Level 1 Level 2 Level 3
Total
Investments
Measured at
Fair Value
NAV (a)
Total
Investments
Pension Plan
Common Collective Trust - Cash and Cash Equivalents
Common Collective Trust - Equity
Common Collective Trust - Fixed Income
Common Collective Trust - Real Estate
Hedge Funds
Total investments measured at fair value
Non-pension Defined Benefit Postretirement Healthcare
Plan
Cash and Cash Equivalents
Total investments measured at fair value
$ — $
6.4 $ — $
6.4 $ — $
—
—
—
—
45.1
242.0
—
—
—
—
—
—
45.1
242.0
—
—
—
—
21.5
8.1
$ — $ 293.5 $ — $
293.5 $ 29.6 $
7.8
7.8 $
$
—
— $ — $
—
7.8
7.8
$
6.4
45.1
242.0
21.5
8.1
323.1
7.8
7.8
(a)
Certain investments that are measured at fair value using NAV per share (or its equivalent) for practical expedient have not been
classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit
reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair
value of plan assets above.
Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of
these assets, is as follows:
Pension Plan
Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Pension Plan,
which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by
the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the
valuation dates. The Pension Plan’s investments in common collective trust funds, with the exception of shares of the common
collective trust-real estate are categorized as Level 2.
90
10-K| FORM 10-K
Fair Value Measurements
recurring basis (in millions):
The following tables set forth, by level within the fair value hierarchy, the assets that were accounted for at fair value on a
Common Collective Trust - Cash and Cash Equivalents
$ — $
6.7 $ — $
6.7 $ — $
Pension Plan
Common Collective Trust - Equity
Common Collective Trust - Fixed Income
Common Collective Trust - Real Estate
Hedge Funds
December 31, 2023
Total
Investments
Measured at
Level 1 Level 2 Level 3
Fair Value
NAV (a)
Investments
Total
—
—
—
—
42.7
234.5
—
—
—
—
—
—
42.7
234.5
—
—
—
—
16.4
8.1
Total investments measured at fair value
$ — $ 283.9 $ — $
283.9 $ 24.5 $
Non-pension Defined Benefit Postretirement Healthcare
Plan
Cash and Cash Equivalents
Total investments measured at fair value
8.0
—
—
$
8.0 $
— $ — $
8.0
8.0
$
Common Collective Trust - Cash and Cash Equivalents
$ — $
6.4 $ — $
6.4 $ — $
Pension Plan
Common Collective Trust - Equity
Common Collective Trust - Fixed Income
Common Collective Trust - Real Estate
Hedge Funds
December 31, 2022
Total
Investments
Measured at
Level 1 Level 2 Level 3
Fair Value
NAV (a)
Investments
Total
—
—
—
—
45.1
242.0
—
—
—
—
—
—
45.1
242.0
—
—
—
—
21.5
8.1
Total investments measured at fair value
$ — $ 293.5 $ — $
293.5 $ 29.6 $
Non-pension Defined Benefit Postretirement Healthcare
Plan
Cash and Cash Equivalents
Total investments measured at fair value
7.8
—
—
$
7.8 $
— $ — $
7.8
7.8
$
(a)
Certain investments that are measured at fair value using NAV per share (or its equivalent) for practical expedient have not been
classified in the fair value hierarchy. The fair value amounts presented in these tables for these investments are intended to permit
reconciliation of the fair value hierarchy to the amounts presented in the reconciliation of changes in the plan’s benefit obligations and fair
Additional information about assets of the benefit plans, including methods and assumptions used to estimate the fair value of
value of plan assets above.
these assets, is as follows:
Pension Plan
Common Collective Trust Funds: These funds are valued based upon the redemption price of units held by the Pension Plan,
which is based on the current fair value of the common collective trust funds’ underlying assets. Unit values are determined by
the financial institution sponsoring such funds by dividing the fund’s net assets at fair value by its units outstanding at the
valuation dates. The Pension Plan’s investments in common collective trust funds, with the exception of shares of the common
collective trust-real estate are categorized as Level 2.
6.7
42.7
234.5
16.4
8.1
308.4
8.0
8.0
6.4
45.1
242.0
21.5
8.1
323.1
7.8
7.8
The following investments are measured at NAV and are not classified in the fair value hierarchy, in accordance with accounting
guidance:
Common Collective Trust-Real Estate Funds: These funds are valued based on various factors of the underlying real estate
properties, including market rent, market rent growth, occupancy levels, etc. As part of the trustee’s valuation process,
properties are externally appraised generally on an annual basis. The appraisals are conducted by reputable independent
appraisal firms and signed by appraisers that are members of the Appraisal Institute, with professional designation of
Member, Appraisal Institute. All external appraisals are performed in accordance with the Uniform Standards of Professional
Appraisal Practices. We receive monthly statements from the trustee, along with the annual schedule of investments and
rely on these reports for pricing the units of the fund.
Hedge Funds: These funds represent investments in other investment funds that seek a return utilizing a number of diverse
investment strategies. The strategies, when combined, aim to reduce volatility and risk while attempting to deliver positive
returns under all market conditions. Amounts are reported on a one-month lag. The fair value of hedge funds is determined
using net asset value per share based on the fair value of the hedge fund’s underlying investments. 10% of the shares may
be redeemed at the end of each month with a 15-day notice and full redemptions are available at the end of each quarter
with 60-day notice and is limited to a percentage of the total net assets value of the fund. The net asset values are based on
the fair value of each fund’s underlying investments. There are no unfunded commitments related to these hedge funds.
Non-pension Defined Benefit Postretirement Healthcare Plan
Cash and Cash Equivalents: This represents an investment in Northern Institutional Government Assets Portfolio, which is a
government money market fund. As shares held reflect quoted prices in an active market, they are categorized as Level 1.
Components of Net Periodic Expense
The following table provides a reconciliation of components of the net periodic expense (in millions):
For the years ended December 31,
Service cost
Interest cost
Expected return on assets
Net amortization of prior service cost
Recognized net actuarial loss (gain)
Net periodic expense
Defined Benefit
Pension Plan
2022
2023
2021
$
$
2.5 $
17.5
(18.7)
(0.1)
2.0
3.2 $
3.9 $
10.8
(18.5)
(0.1)
6.1
2.2 $
5.0 $
9.3
(20.8)
—
7.3
0.8 $
Supplemental
Non-qualified Defined
Benefit Plans
2022
2021
2023
Non-pension Defined Benefit
Postretirement Healthcare Plan
2022
2023
2021
3.1 $
1.5
—
—
—
4.6 $
(0.8) $
0.8
—
—
0.3
0.3 $
3.1 $
0.7
—
—
1.8
5.6 $
1.5 $
2.4
(0.2)
—
—
3.7 $
1.9 $
1.3
(0.1)
(0.3)
0.1
2.9 $
2.2
1.0
(0.1)
(0.4)
0.5
3.2
Service costs are recorded in Operations and maintenance expense while non-service costs are recorded in Other expense on
the Consolidated Statements of Income.
Actuarial gains and losses are amortized using a straight-line method over the average remaining service period of active plan
participants or over the average remaining lifetime of the remaining plan participants if the plan is viewed as “all or almost all”
inactive participants.
91
10-KFORM 10-K |
Other Plan Information
The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan
assets, amounts recognized on our Consolidated Balance Sheets, accumulated benefit obligation and elements of AOCI (in
millions):
Defined
Benefit
Pension
Plan
Supplemental
Non-qualified
Defined
Benefit Plans
Non-pension
Defined Benefit
Postretirement
Healthcare Plan
Defined
Benefit
Pension
Plan
Supplemental
Non-qualified
Defined
Benefit Plans
Non-pension
Defined Benefit
Postretirement
Healthcare Plan
2023
2022
341.8 $
46.7 $
51.1 $
350.2 $
45.2 $
49.7
Accumulated benefit obligation at
December 31
Change in benefit obligation:
Projected benefit obligation at beginning
of year
$
$
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid
Plan participants’ contributions
Projected benefit obligation at end of year
Change in fair value of plan assets:
Fair value of plan assets at beginning of
year
Investment income (loss)
Employer contributions
Retiree contributions
Benefits paid
Fair value of plan assets at end of year
Funded status - deficiency
Amounts recognized on our
Consolidated Balance Sheets as of
December 31:
Regulatory assets
Current liabilities
Non-current assets
Non-current liabilities
Regulatory liabilities
$
$
358.4 $
2.5
17.5
11.6
(41.9)
—
348.1
323.1
27.4
—
—
(41.9)
308.6
39.5 $
79.9 $
—
—
39.4
2.9
Amounts recognized in AOCI, net of tax
as of December 31:
Net (gain) loss
Prior service cost (gain)
$
5.0 $
—
45.2 $
3.1
1.5
0.3
(3.4)
—
46.7
—
—
3.5
—
(3.5)
—
46.7 $
— $
2.4
—
44.3
—
1.8 $
—
49.7 $
1.5
2.4
1.7
(5.3)
1.1
51.1
7.8
0.2
4.3
1.1
(5.4)
8.0
43.1 $
4.8 $
4.2
1.3
40.2
5.5
478.3 $
3.9
10.8
(97.9)
(36.7)
—
358.4
458.4
(98.6)
—
—
(36.7)
323.1
35.3 $
78.7 $
—
—
35.2
2.8
(0.7) $
0.1
5.2 $
(0.1)
55.3 $
(0.8)
0.8
(7.0)
(3.1)
—
45.2
—
—
3.1
—
(3.1)
—
45.2 $
— $
2.2
—
43.0
—
1.6 $
—
63.5
1.9
1.3
(12.3)
(6.1)
1.4
49.7
8.0
—
4.5
1.4
(6.1)
7.8
41.9
3.8
4.4
1.0
38.5
6.2
(0.7)
0.1
(0.6)
Total amounts included in AOCI, net of tax
not yet recognized as components of net
periodic expense
$
5.0 $
1.8 $
(0.6) $
5.1 $
1.6 $
In 2012, we froze our Pension Plan and closed it to new participants. Since then, we have implemented various de-risking
strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more
liability-hedged portfolio. As a result, capital markets volatility had a limited impact to our unfunded status.
92
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N/A
N/A
N/A
N/A
2023
2023
2021
2023
2021
2021
5.00%
N/A
—
N/A
5.00%
Defined Benefit
Pension Plan
2022
Supplemental
Non-qualified Defined
Benefit Plans
2022
Non-pension Defined
Benefit Postretirement
Healthcare Plan
2022
4.99% 5.17% 2.88% 4.93% 5.13% 2.77% 4.97% 5.14% 2.79%
—
3.04% 3.06% 3.08%
5.17% 2.88% 2.56% 5.13% 2.77% 2.41% 5.14% 2.79% 2.41%
3.10% 1.70% 1.80%
N/A
6.00% 4.25% 4.50%
N/A
N/A
—
3.06% 3.08% 3.34%
Other Plan Information
millions):
The following tables provide a reconciliation of the employee benefit plan obligations and fair value of employee benefit plan
assets, amounts recognized on our Consolidated Balance Sheets, accumulated benefit obligation and elements of AOCI (in
Assumptions
Weighted-average assumptions used to
determine benefit obligations:
Discount rate
Rate of increase in compensation levels
Weighted-average assumptions used to
determine net periodic benefit cost for plan year:
Discount rate (a)
Expected long-term rate of return on assets (b)
Rate of increase in compensation levels
Accumulated benefit obligation at
December 31
Change in benefit obligation:
Projected benefit obligation at beginning
of year
Service cost
Interest cost
Actuarial (gain) loss
Benefits paid
Plan participants’ contributions
Projected benefit obligation at end of year
Change in fair value of plan assets:
Fair value of plan assets at beginning of
year
Investment income (loss)
Employer contributions
Retiree contributions
Benefits paid
Fair value of plan assets at end of year
Funded status - deficiency
Amounts recognized on our
Consolidated Balance Sheets as of
December 31:
Regulatory assets
Current liabilities
Non-current assets
Non-current liabilities
Regulatory liabilities
as of December 31:
Net (gain) loss
Prior service cost (gain)
Amounts recognized in AOCI, net of tax
Total amounts included in AOCI, net of tax
not yet recognized as components of net
periodic expense
$
$
$
$
$
$
Defined
Benefit
Pension
Plan
Supplemental
Non-qualified
Defined
Benefit Plans
Non-pension
Defined Benefit
Postretirement
Healthcare Plan
Defined
Benefit
Pension
Plan
Supplemental
Non-qualified
Defined
Benefit Plans
Non-pension
Defined Benefit
Postretirement
Healthcare Plan
2023
2022
341.8 $
46.7 $
51.1 $
350.2 $
45.2 $
49.7
358.4 $
45.2 $
49.7 $
478.3 $
55.3 $
2.5
17.5
11.6
(41.9)
—
348.1
323.1
27.4
—
—
(41.9)
308.6
39.5 $
—
—
39.4
2.9
3.1
1.5
0.3
(3.4)
—
46.7
—
—
3.5
—
(3.5)
—
46.7 $
2.4
—
44.3
—
1.5
2.4
1.7
(5.3)
1.1
51.1
7.8
0.2
4.3
1.1
(5.4)
8.0
4.2
1.3
40.2
5.5
3.9
10.8
(97.9)
(36.7)
—
358.4
458.4
(98.6)
—
—
(36.7)
323.1
—
—
35.2
2.8
43.1 $
35.3 $
(0.8)
0.8
(7.0)
(3.1)
—
45.2
—
—
3.1
—
(3.1)
—
45.2 $
2.2
—
43.0
—
79.9 $
— $
4.8 $
78.7 $
— $
5.0 $
—
1.8 $
—
(0.7) $
0.1
5.2 $
(0.1)
1.6 $
—
63.5
1.9
1.3
(12.3)
(6.1)
1.4
49.7
8.0
—
4.5
1.4
(6.1)
7.8
41.9
3.8
4.4
1.0
38.5
6.2
(0.7)
0.1
(0.6)
In 2012, we froze our Pension Plan and closed it to new participants. Since then, we have implemented various de-risking
strategies including lump sum buyouts, the purchase of annuities and the reduction of return-seeking assets over time to a more
liability-hedged portfolio. As a result, capital markets volatility had a limited impact to our unfunded status.
(a)
(b)
The estimated discount rate for the Defined Benefit Pension Plan is 5.0% for the calculation of the 2024 net periodic pension costs.
The expected rate of return on plan assets for the Defined Benefit Pension Plan is 6.0% for the calculation of the 2024 net periodic
pension cost.
The healthcare benefit obligation at December 31 was determined as follows:
Trend Rate - Medical
Pre-65 for next year - All Plans
Pre-65 Ultimate trend rate - Black Hills Corp
Trend Year
Post-65 for next year - All Plans
Post-65 Ultimate trend rate - Black Hills Corp
Trend Year
2023
2022
6.69%
4.50%
2034
5.81%
4.50%
2034
7.00%
4.50%
2031
6.00%
4.50%
2031
The following benefit payments to employees, which reflect future service, are expected to be paid (in millions):
Defined Benefit Pension
Plan
Supplemental Non-qualified
Defined Benefit Plans
Non-pension Defined
Benefit Postretirement
Healthcare Plan
2024
2025
2026
2027
2028
2029 - 2033
$
$
24.5 $
25.4
26.0
25.9
26.2
129.7 $
2.4 $
2.8
2.8
2.7
2.6
11.7 $
5.2
5.0
4.9
4.8
4.6
21.4
5.0 $
1.8 $
(0.6) $
5.1 $
1.6 $
(14) SHARE-BASED COMPENSATION PLANS
Our Amended and Restated 2015 Omnibus Incentive Plan allows for the granting of stock, restricted stock, restricted stock units,
stock options, performance shares and performance share units. We had 2,132,275 shares available to grant at December 31,
2023.
Compensation expense is determined using the grant date fair value estimated in accordance with the provisions of accounting
standards for stock compensation and is recognized over the vesting periods of the individual awards. As of December 31, 2023,
total unrecognized compensation expense related to non-vested stock awards was $10.6 million and is expected to be
recognized over a weighted-average period of 1.7 years. Stock-based compensation expense, which is included in Operations
and maintenance on the accompanying Consolidated Statements of Income, was as follows for the years ended December 31
(in millions):
Stock-based compensation expense
$
7.0 $
8.6 $
9.7
2023
2022
2021
93
10-KFORM 10-K |
Restricted Stock
The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant.
The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over three
years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.
A summary of the status of the restricted stock and restricted stock units at December 31, 2023, was as follows:
Balance at January 1, 2023
Granted
Vested
Forfeited
Balance at December 31, 2023
Restricted Stock
Weighted-Average Grant Date Fair
Value
178,129 $
110,198
(97,084)
(26,556)
164,687 $
67.23
63.33
67.56
65.10
64.81
The weighted-average grant-date fair value of restricted stock granted, and the total fair value of shares vested during the years
ended December 31, were as follows:
Weighted-Average Grant Date Fair Value
Total Fair Value of Shares Vested
(in millions)
2023
2022
2021
$
$
$
63.33 $
69.03 $
65.64 $
5.9
6.4
5.4
As of December 31, 2023, there was $6.3 million of unrecognized compensation expense related to non-vested restricted stock
that is expected to be recognized over a weighted-average period of 1.6 years.
Performance Share Units
Beginning in 2021, certain officers of the Company, and its subsidiaries, were granted performance share units which have a
three-year vesting period, do not have voting rights until vested, and are subject to three specified conditions. A market condition
of relative total shareholder return and two equally weighted performance metrics of average earnings per share and the
average cost to serve. Beginning in 2023, the metric of natural gas emissions reduction by 2035 was added, resulting in three
equally weighted performance metrics. The units are paid 100% in common stock should conditions be met and can range from
0% to 200% of the target award. Dividend equivalents are accrued during the vesting period and paid out based on the final
number of shares awarded. In the event of participant’s death or retirement at age 55 or older, shares awarded vest on a pro-
rata basis commensurate with the months of service performed over the three-year period.
Performance Share Units - Market Condition
The fair value of each share unit is based on the Company’s closing price at December 31 of the year prior to the award and a
Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on the Company’s TSR
for a three-year performance period relative to the designated peer group beginning January 1 of the award year. The significant
assumptions included in the company's Monte Carlo simulations were as follows:
Fair value of share units award
Risk-free rate
Black Hills Corporation’s common stock volatility
Volatility range for the peer group
Performance Share Units - Performance Condition
2023
$77.95
3.84%
31%
24-39%
2022
$74.48
0.97%
30%
22-67%
A performance condition share unit vests at the end of the three-year performance period if the specified performance conditions
are achieved. The conditions are based on the Company’s average earnings per share, the average cost to serve and natural
gas emissions reductions by 2035. The grant-date fair value for an individual outcome of a performance condition is determined
by the closing common share price on the grant date or, beginning in 2023, the average ten-day closing common share price
preceding the grant date.
94
10-K| FORM 10-K
Restricted Stock
The following table summarizes the performance share unit activity for the year ended December 31, 2023:
The fair value of restricted stock and restricted stock unit awards equals the market price of our stock on the date of grant.
The shares carry a restriction on the ability to sell the shares until the shares vest. The shares substantially vest over three
years, contingent on continued employment. Compensation expense related to the awards is recognized over the vesting period.
A summary of the status of the restricted stock and restricted stock units at December 31, 2023, was as follows:
Restricted Stock
Value
Weighted-Average Grant Date Fair
Nonvested at January 1, 2023
Granted
Forfeited
Nonvested at December 31, 2023
Performance Share Units -
Market Condition
Performance Share Units -
Performance Condition
Share Units
Weighted-Average
Fair Value per
Share Unit
Share Units
Weighted-Average
Fair Value per Share
Unit
68,474 $
50,440
(8,167)
110,747 $
69.91
77.95
73.43
73.31
45,666 $
21,615
(4,627)
62,654 $
66.19
71.50
68.03
67.88
The weighted-average grant-date fair value of restricted stock granted, and the total fair value of shares vested during the years
ended December 31, were as follows:
Performance Share Plan
Weighted-Average Grant Date Fair Value
Total Fair Value of Shares Vested
(in millions)
Prior to 2021, certain officers of the Company and its subsidiaries became participants in a market-based performance share
award plan. Performance shares are awarded based on our total shareholder return over designated performance periods as
measured against a selected peer group. In addition, certain stock price performance must be achieved for a payout to occur.
The final value of the performance shares will vary according to the number of shares of common stock that are ultimately
granted based upon the actual level of attainment of the performance criteria.
As of December 31, 2023, there was $6.3 million of unrecognized compensation expense related to non-vested restricted stock
These performance share awards were paid 50% in cash and 50% in common stock.
that is expected to be recognized over a weighted-average period of 1.6 years.
The outstanding performance periods at December 31, 2023 were as follows:
As of December 31, 2023, there was $4.0 million of unrecognized compensation expense related to outstanding performance
share/units that is expected to be recognized over a weighted-average period of 1.8 years.
On January 25, 2024, the Compensation Committee of our Board of Directors confirmed a payout equal to 16.21% of target
shares valued at $0.5 million. The payout was fully accrued at December 31, 2023.
178,129 $
110,198
(97,084)
(26,556)
164,687 $
63.33 $
69.03 $
65.64 $
67.23
63.33
67.56
65.10
64.81
5.9
6.4
5.4
Balance at January 1, 2023
Granted
Vested
Forfeited
Balance at December 31, 2023
2023
2022
2021
$
$
$
Performance Share Units
Grant Date
January 1, 2020
Performance Period
January 1, 2020 - December 31, 2022
Target Grant of
Shares
35,571
Possible Payout Range of
Target
Minimum
0%
Maximum
200%
A summary of the status of the Performance Share Plan at December 31, 2023 was as follows:
Equity Portion
Liability Portion
Performance Shares balance at beginning of period
Granted
Forfeited
Vested
Performance Shares balance at end of period
Weighted-
Average
Grant Date
Shares
18,105 $
—
—
(18,105)
— $
Fair Value (a)
81.42
—
—
81.42
—
Weighted-
Average Fair
Value at
December 31,
2023
Shares
18,105
—
—
(18,105)
— $
—
(a)
The grant date fair values for the performance shares granted in 2020 were determined by Monte Carlo simulation using a blended
volatility of 18%, comprised of 50% historical volatility and 50% implied volatility and the average risk-free interest rate of the three-year
United States Treasury security rate in effect as of the grant date.
Performance plan payouts have been as follows (in millions, except stock issued):
Beginning in 2021, certain officers of the Company, and its subsidiaries, were granted performance share units which have a
three-year vesting period, do not have voting rights until vested, and are subject to three specified conditions. A market condition
of relative total shareholder return and two equally weighted performance metrics of average earnings per share and the
average cost to serve. Beginning in 2023, the metric of natural gas emissions reduction by 2035 was added, resulting in three
equally weighted performance metrics. The units are paid 100% in common stock should conditions be met and can range from
0% to 200% of the target award. Dividend equivalents are accrued during the vesting period and paid out based on the final
number of shares awarded. In the event of participant’s death or retirement at age 55 or older, shares awarded vest on a pro-
rata basis commensurate with the months of service performed over the three-year period.
Performance Share Units - Market Condition
The fair value of each share unit is based on the Company’s closing price at December 31 of the year prior to the award and a
Monte Carlo simulation. The Monte Carlo simulation is used to estimate expected share payout based on the Company’s TSR
for a three-year performance period relative to the designated peer group beginning January 1 of the award year. The significant
assumptions included in the company's Monte Carlo simulations were as follows:
Fair value of share units award
Risk-free rate
Black Hills Corporation’s common stock volatility
Volatility range for the peer group
Performance Share Units - Performance Condition
2023
$77.95
3.84%
31%
24-39%
2022
$74.48
0.97%
30%
22-67%
A performance condition share unit vests at the end of the three-year performance period if the specified performance conditions
are achieved. The conditions are based on the Company’s average earnings per share, the average cost to serve and natural
gas emissions reductions by 2035. The grant-date fair value for an individual outcome of a performance condition is determined
by the closing common share price on the grant date or, beginning in 2023, the average ten-day closing common share price
preceding the grant date.
Performance Period
January 1, 2020 to December 31, 2022
January 1, 2019 to December 31, 2021
January 1, 2018 to December 31, 2020
Year Paid
2023
2022
2021
Stock Issued
Cash Paid
4,958 $
7,582 $
27,515 $
Total Intrinsic Value
0.7
1.0
3.3
0.3 $
0.5 $
1.6 $
95
10-KFORM 10-K |
(15) INCOME TAXES
IRS Revenue Procedure 2023-15
On April 14, 2023, the IRS released Revenue Procedure 2023-15 “Amounts paid to improve tangible property.” The Revenue
Procedure provides a safe harbor method of accounting that taxpayers may use to determine whether costs to repair, maintain,
replace, or improve natural gas transmission and distribution property must be capitalized. The revenue procedure may be
adopted in tax years ending after May 1, 2023. We are currently assessing the Revenue Procedure to determine its impact on
our tax repairs deduction.
Income Tax Expense (Benefit)
Income tax expense (benefit) from continuing operations for the years ended December 31 was (in millions):
Current:
Federal
State
Current income tax (benefit)
Deferred:
Federal
State
Deferred income tax expense
Income tax expense
Effective Tax Rates
2023
2022
2021
$
$
(0.8) $
1.0
0.2
30.9
(5.5)
25.4
25.6 $
(0.5) $
0.1
(0.4)
23.2
2.4
25.6
25.2 $
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
Federal statutory rate
State income tax (net of federal tax effect) (a)
Non-controlling interest (b)
Tax credits
Flow-through adjustments (c)
Amortization of excess deferred income taxes (d)
TCJA bill credits (e)
Other
Effective Tax Rate
2023
2022
2021
21.0%
(0.8)
(1.0)
(6.2)
(1.7)
(3.0)
—
0.2
8.5%
21.0%
0.5
(0.9)
(7.7)
(1.4)
(2.5)
(0.4)
(0.1)
8.5%
0.6
(0.7)
(0.1)
2.2
5.1
7.3
7.2
21.0%
1.2
(1.2)
(8.4)
(3.2)
(3.1)
(3.6)
0.1
2.8%
(a)
(b)
(c)
(d)
(e)
The state effective tax rate contains the tax expense attributable to multiple statutory state rate changes in the Company's state
jurisdictions. For the year ended December 31, 2023, we recognized an $8.2 million tax benefit from a Nebraska income tax rate
decrease.
The effective tax rate reflects the income attributable to the non-controlling interest in Black Hills Colorado IPP for which a tax provision
was not recorded.
Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction
for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created
between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the
recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory
treatment, we continue to record tax benefits consistent with the flow-through method.
Primarily TCJA - see Note 2 for additional information.
Primarily related to one-time bill credits of TCJA benefits delivered to Colorado Electric and Nebraska Gas customers in 2021. These bill
credits, which resulted in a reduction in revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net
income for the year ended December 31, 2021.
96
10-K| FORM 10-K
(15) INCOME TAXES
IRS Revenue Procedure 2023-15
our tax repairs deduction.
Income Tax Expense (Benefit)
Current:
Federal
State
Deferred:
Federal
State
Current income tax (benefit)
Deferred income tax expense
Income tax expense
Effective Tax Rates
On April 14, 2023, the IRS released Revenue Procedure 2023-15 “Amounts paid to improve tangible property.” The Revenue
Procedure provides a safe harbor method of accounting that taxpayers may use to determine whether costs to repair, maintain,
replace, or improve natural gas transmission and distribution property must be capitalized. The revenue procedure may be
adopted in tax years ending after May 1, 2023. We are currently assessing the Revenue Procedure to determine its impact on
Income tax expense (benefit) from continuing operations for the years ended December 31 was (in millions):
2023
2022
2021
The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:
$
$
(0.8) $
1.0
0.2
30.9
(5.5)
25.4
25.6 $
21.0%
(0.8)
(1.0)
(6.2)
(1.7)
(3.0)
—
0.2
8.5%
(0.5) $
0.1
(0.4)
23.2
2.4
25.6
25.2 $
21.0%
0.5
(0.9)
(7.7)
(1.4)
(2.5)
(0.4)
(0.1)
8.5%
0.6
(0.7)
(0.1)
2.2
5.1
7.3
7.2
21.0%
1.2
(1.2)
(8.4)
(3.2)
(3.1)
(3.6)
0.1
2.8%
Federal statutory rate
State income tax (net of federal tax effect) (a)
Non-controlling interest (b)
Tax credits
Flow-through adjustments (c)
Amortization of excess deferred income taxes (d)
TCJA bill credits (e)
Other
Effective Tax Rate
decrease.
was not recorded.
(b)
(c)
(d)
(e)
(a)
The state effective tax rate contains the tax expense attributable to multiple statutory state rate changes in the Company's state
jurisdictions. For the year ended December 31, 2023, we recognized an $8.2 million tax benefit from a Nebraska income tax rate
The effective tax rate reflects the income attributable to the non-controlling interest in Black Hills Colorado IPP for which a tax provision
Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction
for repair costs and certain indirect costs. We recorded a deferred income tax liability in recognition of the temporary difference created
between book and tax treatment and flowed the tax benefit through to tax expense. A regulatory asset was established to reflect the
recovery of future increases in taxes payable from customers as the temporary differences reverse. As a result of this regulatory
treatment, we continue to record tax benefits consistent with the flow-through method.
Primarily TCJA - see Note 2 for additional information.
Deferred Tax Assets and Liabilities
The temporary differences, which gave rise to the net deferred tax liability, for the years ended December 31 were as follows (in
millions):
Deferred tax assets:
Regulatory liabilities
State tax credits
Federal NOL
State NOL
Partnership
Credit Carryovers
Other deferred tax assets
Less: Valuation allowance
Total deferred tax assets
Deferred tax liabilities:
Accelerated depreciation, amortization and other property-related differences
Regulatory assets
Goodwill
State deferred tax liability
Other deferred tax liabilities
Total deferred tax liabilities
Net deferred tax liability
Net Operating Loss and Tax Credit Carryforwards
2023
2022
$
74.0 $
22.8
146.6
16.5
12.2
110.1
33.7
(15.4)
400.5
(686.2)
(65.6)
(67.8)
(84.5)
(44.4)
(948.5)
$
(548.0) $
74.7
22.8
192.0
23.0
12.8
90.9
45.4
(15.5)
446.1
(645.7)
(94.4)
(57.9)
(98.2)
(58.8)
(955.0)
(508.9)
2023
2022
2021
At December 31, 2023, we have federal NOL and state NOL and tax credit carryforwards that will expire at various dates as
follows (in millions):
Federal NOL Carryforward
Federal NOL Carryforward
Federal Tax Credit Carryforward
State NOL Carryforward (a)
State Tax Credit Carryforward
$
$
$
$
$
Amounts
111.0
587.3
110.1
325.3
22.8
Expiration Dates
2036-2037
No expiration
2028-2043
2024-2042
2024-2038
(a)
The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes.
As of December 31, 2023, we had a $1.0 million valuation allowance against the state NOL carryforwards. Our 2023 analysis of
the ability to utilize such NOLs resulted in no increase in the valuation allowance. If the valuation allowance is adjusted due to
higher or lower than anticipated utilization of the NOLs, the offsetting amount will affect tax expense.
As of December 31, 2023, we had a $14.4 million valuation allowance against the state ITC carryforwards. Our 2023 analysis of
the ability to utilize such ITC resulted in a slight decrease in the valuation allowance.
Unrecognized Tax Benefits
Primarily related to one-time bill credits of TCJA benefits delivered to Colorado Electric and Nebraska Gas customers in 2021. These bill
credits, which resulted in a reduction in revenue, were offset by a reduction in income tax expense and resulted in a minimal impact to Net
The following table reconciles the total amounts of unrecognized tax benefits, without interest, at the beginning and end of the
period included in Other deferred credits and other liabilities on the accompanying Consolidated Balance Sheets (in millions):
income for the year ended December 31, 2021.
Changes in Uncertain Tax Positions:
Beginning balance
Additions for prior year tax positions
Reductions for prior year tax positions
Additions for current year tax positions
Ending balance
$
$
2023
2022
2021
11.9 $
—
(0.3)
2.1
13.7 $
10.6 $
—
(0.8)
2.1
11.9 $
8.4
0.5
(0.7)
2.4
10.6
The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $6.5
million.
97
10-KFORM 10-K |
We recognized no interest expense associated with income taxes for the years ended December 31, 2023, 2022 and 2021. We
had no accrued interest (before tax effect) associated with income taxes at December 31, 2023 and 2022.
As of December 31, 2023, we do not have any tax positions for which it is reasonably possible that the total amount of
unrecognized tax benefits will significantly increase or decrease on or before December 31, 2024.
We are subject to federal income tax as well as income tax in various state and local jurisdictions. As of December 31, 2023, tax
years for 2020, 2021, and 2022 are subject to examination by the tax authorities. With few exceptions, we are no longer subject
to U.S. or state exam for years before 2020. Tax years 2017 and 2018 was open as of December 31, 2023.
(16) BUSINESS SEGMENT INFORMATION
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 operating
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 represents 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 CODM assesses the performance of our operating segments based on operating income. Our CODM reviews capital
expenditures by operating segment rather than any individual or total asset amount. Our operating segments are equivalent to
our reportable segments.
Segment information was as follows (in millions):
Year ended December 31, 2023
Revenue -
External Customers
Inter-segment
Total revenue
Fuel, purchased power and cost of natural gas sold
Operations and maintenance
Depreciation, depletion and amortization
Taxes - property and production
Operating income (loss)
Interest expense, net
Other income (expense), net
Income tax (expense)
Net income
Net income attributable to non-controlling interest
Net income available for common stock
Consolidating Income Statement
Electric
Utilities
Gas Utilities
Corporate
and Other
Total
$
$
853.6 $
11.4
865.0
200.1
236.2
142.6
37.3
248.8 $
1,477.7 $
6.5
1,484.2
783.2
328.7
113.9
29.6
228.8 $
— $
(17.9)
(17.9)
(0.4)
(12.9)
0.3
—
(4.9) $
$
2,331.3
—
2,331.3
982.9
552.0
256.8
66.9
472.7
(167.9)
(3.2)
(25.6)
276.0
(13.8)
262.2
98
10-K| FORM 10-K
We recognized no interest expense associated with income taxes for the years ended December 31, 2023, 2022 and 2021. We
had no accrued interest (before tax effect) associated with income taxes at December 31, 2023 and 2022.
As of December 31, 2023, we do not have any tax positions for which it is reasonably possible that the total amount of
unrecognized tax benefits will significantly increase or decrease on or before December 31, 2024.
We are subject to federal income tax as well as income tax in various state and local jurisdictions. As of December 31, 2023, tax
years for 2020, 2021, and 2022 are subject to examination by the tax authorities. With few exceptions, we are no longer subject
to U.S. or state exam for years before 2020. Tax years 2017 and 2018 was open as of December 31, 2023.
(16) BUSINESS SEGMENT INFORMATION
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 operating
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.
Iowa, Kansas, Nebraska and Wyoming.
Our Gas Utilities segment consists of the operating results of our regulated natural gas utility subsidiaries in Arkansas, Colorado,
Corporate and Other represents 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 CODM assesses the performance of our operating segments based on operating income. Our CODM reviews capital
expenditures by operating segment rather than any individual or total asset amount. Our operating segments are equivalent to
our reportable segments.
Segment information was as follows (in millions):
Year ended December 31, 2023
Revenue -
External Customers
Inter-segment
Total revenue
Fuel, purchased power and cost of natural gas sold
Operations and maintenance
Depreciation, depletion and amortization
Taxes - property and production
Operating income (loss)
Interest expense, net
Other income (expense), net
Income tax (expense)
Net income
Net income attributable to non-controlling interest
Net income available for common stock
Consolidating Income Statement
Electric
Utilities
Gas Utilities
Corporate
and Other
Total
$
853.6 $
11.4
865.0
200.1
236.2
142.6
37.3
1,477.7 $
6.5
1,484.2
783.2
328.7
113.9
29.6
$
248.8 $
228.8 $
(4.9) $
— $
(17.9)
(17.9)
(0.4)
(12.9)
0.3
—
$
2,331.3
—
2,331.3
982.9
552.0
256.8
66.9
472.7
(167.9)
(3.2)
(25.6)
276.0
(13.8)
262.2
Year ended December 31, 2022
Revenue -
External Customers
Inter-segment
Total revenue
Fuel, purchased power and cost of natural gas sold
Operations and maintenance
Depreciation, depletion and amortization
Taxes - property and production
Operating income (loss)
Interest expense, net
Other income (expense), net
Income tax (expense)
Net income
Net income attributable to non-controlling interest
Net income available for common stock
Year ended December 31, 2021
Revenue -
External Customers
Inter-segment
Total revenue
Fuel, purchased power and cost of natural gas sold
Operations and maintenance
Depreciation, depletion and amortization
Taxes - property and production
Operating income (loss)
Interest expense, net
Other income (expense), net
Income tax (expense)
Net income
Net income attributable to non-controlling interest
Net income available for common stock
$
$
$
$
Consolidating Income Statement
Electric
Utilities
Gas Utilities
Corporate
and Other
Total
888.4 $
11.8
900.2
266.3
244.8
135.9
38.9
214.3 $
1,663.4 $
5.7
1,669.1
965.1
317.3
114.7
27.8
244.2 $
— $
(17.5)
(17.5)
(0.8)
(13.7)
0.3
—
(3.3) $
$
2,551.8
—
2,551.8
1,230.6
548.4
250.9
66.7
455.2
(161.0)
1.8
(25.2)
270.8
(12.4)
258.4
Consolidating Income Statement
Electric
Utilities
Gas Utilities
Corporate
and Other
Total
830.7 $
11.5
842.2
248.0
224.5
131.5
35.5
202.7 $
1,118.4 $
6.5
1,124.9
494.7
290.2
104.2
24.6
211.2 $
— $
(18.0)
(18.0)
(0.8)
(13.0)
0.3
—
(4.5) $
$
1,949.1
—
1,949.1
741.9
501.7
236.0
60.1
409.4
(152.4)
1.4
(7.2)
251.2
(14.5)
236.7
Capital Expenditures (a) for the years ended December 31,
2023
2022
2021
Electric Utilities
Gas Utilities
Corporate and Other
Total capital expenditures
$
$
210.7 $
371.9
7.3
589.9 $
243.1 $
349.5
5.1
597.7 $
285.8
383.3
10.5
679.6
(a)
Includes accruals for property, plant and equipment as disclosed in the Supplemental Cash Flow Information to the Consolidated
Statement of Cash Flows.
(17) SUBSEQUENT EVENTS
Except as described in Note 2, there have been no events subsequent to December 31, 2023 which would require recognition in
the Consolidated Financial Statements or disclosures.
99
10-KFORM 10-K |
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure 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 (Exchange Act)) as of December 31, 2023.
Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
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, as amended, 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 December 31, 2023, there were no changes in the Company’s internal control over financial reporting
(as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect,
the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting is presented on Page 56 of this Annual Report on Form 10-K.
ITEM 9B. 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 December 31, 2023.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3),
407(d)(4), 407(d)(5) and 408(b) of Regulation S-K, is set forth in the Proxy Statement for our 2024 Annual Meeting of
Shareholders, which is incorporated herein by reference. Information about our Executive Officers is reported in Part 1 of this
Annual Report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Information required under this item is set forth in the Proxy Statement for our 2024 Annual Meeting of Shareholders, which is
incorporated herein by reference.
100
10-K| FORM 10-K ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure 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 (Exchange Act)) as of December 31, 2023.
Based on their evaluation, they have concluded that our disclosure controls and procedures are effective.
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, as amended, 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 December 31, 2023, there were no changes in the Company’s internal control over financial reporting
(as defined in Rule 13a-15(f) under the Exchange Act) that have materially affected, or are reasonably likely to materially affect,
the Company’s internal control over financial reporting.
Management’s Report on Internal Control over Financial Reporting is presented on Page 56 of this Annual Report on Form 10-K.
ITEM 9B. 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 December 31, 2023.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Information required under this item with respect to directors and information required by Items 401, 405, 406, 407(c)(3),
407(d)(4), 407(d)(5) and 408(b) of Regulation S-K, is set forth in the Proxy Statement for our 2024 Annual Meeting of
Shareholders, which is incorporated herein by reference. Information about our Executive Officers is reported in Part 1 of this
Annual Report on Form 10-K.
ITEM 11. EXECUTIVE COMPENSATION
Information required under this item is set forth in the Proxy Statement for our 2024 Annual Meeting of Shareholders, which is
incorporated herein by reference.
STOCKHOLDER MATTERS
Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for
our 2024 Annual Meeting of Shareholders, which is incorporated herein by reference.
EQUITY COMPENSATION PLAN INFORMATION
The following table includes information as of December 31, 2023 with respect to our equity compensation plans which includes
the Amended and Restated 2015 Omnibus Incentive Plan.
Plan category
Number of securities to be
issued upon exercise of
outstanding options,
warrants and rights
Weighted-average
exercise price of
outstanding options,
warrants and rights
(a)
(b)
Number of securities
remaining available for
future issuance under
equity compensation plans
(excluding securities
reflected in column (a))
(c)
Equity compensation plans
approved by security holders
Equity compensation plans not
approved by security holders
Total
$
$
290,266 (1) $
—
290,266
$
— (1) $
—
— $
2,132,275 (2)
—
2,132,275
(1)
(2)
290,266 full value awards outstanding as of December 31, 2023, comprised of restricted stock units, performance shares, short-term
incentive plan (STIP) units and Director common stock units. In addition, 148,163 shares of unvested restricted stock were outstanding as
of December 31, 2023, which are not included in the table above because they have already been issued. We do not have any
outstanding options, warrants or rights.
Shares available for issuance are from the 2015 Amended and Restated Omnibus Incentive Plan. The 2015 Amended and Restated
Omnibus Incentive Plan permits grant of stock options, stock appreciation rights, restricted stock, restricted stock units, performance
shares, performance units, cash-based awards and other stock-based awards.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Information regarding certain relationships and related transactions and director independence is set forth in the Proxy
Statement for our 2024 Annual Meeting of Shareholders, which is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information regarding principal accounting fees and services billed to us by our principal accountant, Deloitte & Touche LLP
(PCAOB ID No. 34) is set forth in the Proxy Statement for our 2024 Annual Meeting to Shareholders, which is incorporated
herein by reference.
101
10-KFORM 10-K | PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
Documents filed as part of this report
1.
Consolidated Financial Statements
Financial statements required under this item are included in Item 8 of Part II
2.
Schedules
All other schedules have been omitted because of the absence of the conditions under which they are required or because the
required information is included in our consolidated financial statements and notes thereto. Consolidated valuation and qualifying
accounts are detailed within Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
3.
Exhibits
Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior
filing, as indicated. Items constituting a board of director or management compensatory plan are designated by a cross (†).
Exhibit
Number
Description
2.1
2.2
2.3
3.1
3.2
4.1
4.1-1
4.1-2
4.1-3
4.1-4
4.1-5
4.1-6
4.1-7
4.1-8
Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and
Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer, dated as of July 12,
2015 (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed on July 14, 2015).
First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas
Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills
Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015).
Option Agreement, by and among, Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the
Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 8-K filed
on July 14, 2015).
Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 8-K filed on
February 5, 2018).
Amended and Restated Bylaws of the Registrant dated April 24, 2023 (filed as Exhibit 3.2 to the Registrant’s
Form 8-K filed on May 3, 2023).
Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as
successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q
for the quarterly period ended June 30, 2003).
First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for
the quarterly period ended June 30, 2003).
Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K
filed on May 14, 2009).
Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on
July 15, 2010).
Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8-
K filed on November 18, 2013).
Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K
filed on January 13, 2016).
Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K
filed on August 19, 2016).
Seventh Supplemental Indenture dated as of August 17, 2018 (filed as Exhibit 4.2 to the Registrant’s Form 8-
K filed on August 17, 2018).
Eighth Supplemental Indenture dated as of October 3, 2019 (filed as Exhibit 4.1 to the Registrant’s Form 8-K
filed on October 4, 2019).
102
10-K| FORM 10-K PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
Documents filed as part of this report
1.
Consolidated Financial Statements
Financial statements required under this item are included in Item 8 of Part II
2.
Schedules
3.
Exhibits
Exhibit
Number
All other schedules have been omitted because of the absence of the conditions under which they are required or because the
required information is included in our consolidated financial statements and notes thereto. Consolidated valuation and qualifying
accounts are detailed within Note 1 of the Notes to the Consolidated Financial Statements in this Annual Report on Form 10-K.
Exhibits filed herewithin are designated by an asterisk (*). All exhibits not so designated are incorporated by reference to a prior
filing, as indicated. Items constituting a board of director or management compensatory plan are designated by a cross (†).
Description
2.1
2.2
2.3
3.1
3.2
4.1
4.1-1
4.1-2
4.1-3
4.1-4
4.1-5
4.1-6
4.1-7
4.1-8
Purchase and Sale Agreement by and among Alinda Gas Delaware LLC, Alinda Infrastructure Fund I, L.P. and
Aircraft Services Corporation, as Sellers, and Black Hills Utility Holdings, Inc., as Buyer, dated as of July 12,
2015 (filed as Exhibit 2.1 to the Registrant’s Form 8-K filed on July 14, 2015).
First Amendment to Purchase and Sale Agreement effective December 10, 2015, by and among, Alinda Gas
Delaware LLC, Alinda Infrastructure Fund I, L.P. and Aircraft Services Corporation, as Sellers, and Black Hills
Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 10-K for 2015).
Option Agreement, by and among, Aircraft Services Corporation, as ASC, SourceGas Holdings LLC, as the
Company and Black Hills Utility Holdings, Inc., as Buyer (filed as Exhibit 2.2 to the Registrant’s Form 8-K filed
on July 14, 2015).
February 5, 2018).
Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 8-K filed on
Amended and Restated Bylaws of the Registrant dated April 24, 2023 (filed as Exhibit 3.2 to the Registrant’s
Form 8-K filed on May 3, 2023).
Indenture dated as of May 21, 2003 between the Registrant and Wells Fargo Bank, National Association (as
successor to LaSalle Bank National Association), as Trustee (filed as Exhibit 4.1 to the Registrant’s Form 10-Q
for the quarterly period ended June 30, 2003).
the quarterly period ended June 30, 2003).
Second Supplemental Indenture dated as of May 14, 2009 (filed as Exhibit 4 to the Registrant’s Form 8-K
Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on
filed on May 14, 2009).
July 15, 2010).
filed on January 13, 2016).
filed on August 19, 2016).
K filed on August 17, 2018).
filed on October 4, 2019).
Fourth Supplemental Indenture dated as of November 19, 2013 (filed as Exhibit 4 to the Registrant’s Form 8-
K filed on November 18, 2013).
Fifth Supplemental Indenture dated as of January 13, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K
Sixth Supplemental Indenture dated as of August 19, 2016 (filed as Exhibit 4.1 to the Registrant’s Form 8-K
Seventh Supplemental Indenture dated as of August 17, 2018 (filed as Exhibit 4.2 to the Registrant’s Form 8-
Eighth Supplemental Indenture dated as of October 3, 2019 (filed as Exhibit 4.1 to the Registrant’s Form 8-K
4.1-9
4.1-10
4.1-11
4.1-12
4.2
4.2-1
4.2-2
4.2-3
4.3
4.3-1
4.3-2
4.4
4.5
10.1†
10.1-1†
10.1-2†
Ninth Supplemental Indenture dated as of June 17, 2020 (filed as Exhibit 4.1 to the Registrant’s Form 8-K
filed on June 17, 2020).
Tenth Supplemental Indenture dated as of August 26, 2021 (filed as Exhibit 4.1 to the Registrant’s Form 8-K
filed on August 26, 2021).
Eleventh Supplemental Indenture dated as of March 7, 2023 (filed as Exhibit 4.1 to the Registrant's Form 8-K
filed on March 7, 2023).
Twelfth Supplemental Indenture dated as of September 15, 2023 (filed as Exhibit 4.1 to the Registrant's
Form 8-K filed on September 15, 2023).
Restated and Amended Indenture of Mortgage and Deed of Trust of Black Hills Corporation (now called Black
Hills Power, Inc.) dated as of September 1, 1999 (filed as Exhibit 4.19 to the Registrant’s Post-Effective
Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
First Supplemental Indenture, dated as of August 13, 2002, between Black Hills Power, Inc. and The Bank of
New York Mellon (as successor to JPMorgan Chase Bank), as Trustee (filed as Exhibit 4.20 to the
Registrant’s Post-Effective Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (No.
333-150669)).
Second Supplemental Indenture, dated as of October 27, 2009, between Black Hills Power, Inc. and The
Bank of New York Mellon (filed as Exhibit 4.21 to the Registrant’s Post-Effective Amendment No. 2 to the
Registrant’s Registration Statement on Form S-3 (No. 333-150669)).
Third Supplemental Indenture, dated as of October 1, 2014, between Black Hills Power, Inc. and The Bank of
New York Mellon (filed as Exhibit 10.1 to the Registrant’s Form 8-K filed on October 2, 2014).
Restated Indenture of Mortgage, Deed of Trust, Security Agreement and Financing Statement, amended and
restated as of November 20, 2007, between Cheyenne Light, Fuel and Power Company and Wells Fargo
Bank, National Association (filed as Exhibit 10.2 to the Registrant’s Form 8-K filed on October 2, 2014).
First Supplemental Indenture, dated as of September 3, 2009, between Cheyenne Light, Fuel and Power
Company and Wells Fargo Bank, National Association (filed as Exhibit 10.3 to the Registrant’s Form 8-K filed
on October 2, 2014).
Second Supplemental Indenture, dated as of October 1, 2014, between Cheyenne Light, Fuel and Power
Company and Wells Fargo Bank, National Association (filed as Exhibit 10.4 to the Registrant’s Form 8-K filed
on October 2, 2014).
Form of Stock Certificate for Common Stock, Par Value $1.00 Per Share (filed as Exhibit 4.2 to the
Registrant’s Form 10-K for 2000).
Description of Securities (filed as Exhibit 4.5 to the Registrant's Form 10-K for 2019)
Amended and Restated Pension Equalization Plan of Black Hills Corporation dated November 6, 2001 (filed
as Exhibit 10.11 to the Registrant’s Form 10-K/A for 2001).
First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for
2002).
Grandfather Amendment to the Amended and Restated Pension Equalization Plan of Black Hills Corporation
(filed as Exhibit 10.2 to the Registrant’s Form 10-K for 2008).
First Supplemental Indenture dated as of May 21, 2003 (filed as Exhibit 4.2 to the Registrant’s Form 10-Q for
10.2†
Restoration Plan of Black Hills Corporation (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2008).
10.2-1†
10.3†
10.3-1†
10.4†
10.5†
10.5-1†
10.5-2†
10.6†
First Amendment to the Restoration Plan of Black Hills Corporation dated July 24, 2011 (filed as Exhibit 10.2
to the Registrant’s Form 10-Q for the quarterly period ended June 30, 2011).
Black Hills Corporation Non-qualified Deferred Compensation Plan as Amended and Restated effective
January 1, 2011 (filed as Exhibit 10.4 to the Registrant’s Form 10-K for 2010).
First Amendment to the Black Hills Corporation Nonqualified Deferred Compensation Plan as Amended and
Restated effective January 1, 2011 (filed as Exhibit 10.5 to the Registrant’s Form 10-K for 2018).
Black Hills Corporation Post-2018 Nonqualified Deferred Compensation Plan (filed as Exhibit 10.4 to the
Registrant's Form 10-K for 2022).
Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the Registrant’s
Proxy Statement filed April 13, 2005).
First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008).
Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26,
2010).
Black Hills Corporation Amended and Restated 2015 Omnibus Incentive Plan effective January 24, 2023 (filed
as Exhibit 10.6 to the Registrant's Form 10-K for 2022).
103
10-KFORM 10-K | 10.7†
10.8†
10.9†
10.10†
10.11†
10.12†
10.13†
10.14†
10.15†
10.16†
10.17†
10.18†
10.19†
10.19-1†
10.19-2†
10.19-3†
10.19-4†
10.19-5†
10.19-6†
10.20†
10.21
10.22
10.22-1
10.23†
10.24†
Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014
(filed as Exhibit 10.7 to the Registrant’s Form 10-K for 2013).
Form of Stock Option Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.8 to
Registrant’s Form 10-K for 2015).
Form of Restricted Stock Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on
or after April 28, 2015 (filed as Exhibit 10.10 to Registrant’s Form 10-K for 2015).
Form of Restricted Stock Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on
or after January 26, 2021. (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2020)
Form of Restricted Stock Unit Award Agreement for 2015 Omnibus Plan effective for awards granted on or
after April 28, 2015 (filed as Exhibit 10.12 to the Registrant’s Form 10-K for 2015).
Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2016 (filed
as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2017 (filed
as Exhibit 10.12 to the Registrant's Form 10-K for 2019).
Form of Short-term Incentive Plan for Officers Award Agreement effective for awards granted on or after
January 1, 2021 (filed as Exhibit 10.16 to the Registrant's Form 10-K for 2020).
Form of Performance Unit Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on
or after January 1, 2021. (filed as Exhibit 10.17 to the Registrant's Form 10-K for 2020)
Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3,
2004).
Change in Control Agreement dated November 15, 2022 between Black Hills Corporation and Linden R.
Evans.
Change in Control Agreements dated November 15, 2022 between Black Hills Corporation and its non-CEO
Senior Executive Officers.
Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed
as Exhibit 10.23 to the Registrant’s Form 10-K for 2008).
First Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2011 (filed
as Exhibit 10.16 to the Registrant’s Form 10-K for 2010).
Second Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2013
(filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2012).
Third Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2015 (filed
as Exhibit 10.16 to the Registrant’s Form 10-K for 2014).
Fourth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2017
(filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2016).
Fifth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2018 (filed
as Exhibit 10.16 to the Registrant’s Form 10-K for 2017).
Sixth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2019 (filed
as Exhibit 10.18 to the Registrant’s Form 10-K for 2018).
Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees (filed as Exhibit 10.8 to the
Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
Equity Distribution Sales Agreement dated June 16, 2023 among Black Hills Corporation and the several
Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on June 20, 2023).
Fourth Amended and Restated Credit Agreement dated as of July 19, 2021 (relating to $750 million Revolving
Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks,
and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8-
K filed on July 19, 2021).
First Amendment to Fourth Amended and Restated Credit Agreement dated as of May 9, 2023 (relating to
$750 million Revolving Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions
party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to
the Registrant's Form 10-Q filed on August 3, 2023).
Letter Agreement between Black Hills Corporation and Jennifer C. Landis (filed as Exhibit 10.1 to Form 10-Q
filed May 4, 2023).
Non-Employee Director Equity Compensation Plan effective January 1, 2022 (filed as Exhibit 10.25 to the
Registrant's Form 10-K filed on February 15, 2022).
104
10-K| FORM 10-K 10.7†
Form of Stock Option Agreement for Omnibus Plan effective for awards granted on or after January 1, 2014
(filed as Exhibit 10.7 to the Registrant’s Form 10-K for 2013).
10.8†
Form of Stock Option Agreement effective for awards granted on or after April 28, 2015 (filed as Exhibit 10.8 to
Registrant’s Form 10-K for 2015).
10.9†
Form of Restricted Stock Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on
or after April 28, 2015 (filed as Exhibit 10.10 to Registrant’s Form 10-K for 2015).
10.10†
Form of Restricted Stock Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on
or after January 26, 2021. (filed as Exhibit 10.11 to the Registrant's Form 10-K for 2020)
10.11†
Form of Restricted Stock Unit Award Agreement for 2015 Omnibus Plan effective for awards granted on or
after April 28, 2015 (filed as Exhibit 10.12 to the Registrant’s Form 10-K for 2015).
10.12†
Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2016 (filed
as Exhibit 10.6 to the Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
10.13†
Form of Performance Share Award Agreement effective for awards granted on or after January 1, 2017 (filed
as Exhibit 10.12 to the Registrant's Form 10-K for 2019).
10.14†
Form of Short-term Incentive Plan for Officers Award Agreement effective for awards granted on or after
January 1, 2021 (filed as Exhibit 10.16 to the Registrant's Form 10-K for 2020).
10.15†
Form of Performance Unit Award Agreement for 2015 Omnibus Incentive Plan effective for awards granted on
or after January 1, 2021. (filed as Exhibit 10.17 to the Registrant's Form 10-K for 2020)
10.16†
Form of Indemnification Agreement (filed as Exhibit 10.5 to the Registrant’s Form 8-K filed on September 3,
2004).
Evans.
10.17†
Change in Control Agreement dated November 15, 2022 between Black Hills Corporation and Linden R.
10.18†
Change in Control Agreements dated November 15, 2022 between Black Hills Corporation and its non-CEO
Senior Executive Officers.
10.19†
Outside Directors Stock Based Compensation Plan as Amended and Restated effective January 1, 2009 (filed
as Exhibit 10.23 to the Registrant’s Form 10-K for 2008).
10.19-1†
First Amendment to the Outside Directors Stock Based Compensation Plan effective January 1, 2011 (filed
as Exhibit 10.16 to the Registrant’s Form 10-K for 2010).
10.19-2†
Second Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2013
(filed as Exhibit 10.15 to the Registrant’s Form 10-K for 2012).
10.19-3†
Third Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2015 (filed
as Exhibit 10.16 to the Registrant’s Form 10-K for 2014).
10.19-4†
Fourth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2017
(filed as Exhibit 10.4 to the Registrant’s Form 10-Q for the quarterly period ended September 30, 2016).
10.19-5†
Fifth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2018 (filed
as Exhibit 10.16 to the Registrant’s Form 10-K for 2017).
10.19-6†
Sixth Amendment to the Outside Director’s Stock Based Compensation Plan effective January 1, 2019 (filed
as Exhibit 10.18 to the Registrant’s Form 10-K for 2018).
10.20†
Form of Non-Disclosure and Non-Solicitation Agreement for Certain Employees (filed as Exhibit 10.8 to the
Registrant’s Form 10-Q for the quarterly period ended March 31, 2016).
10.21
Equity Distribution Sales Agreement dated June 16, 2023 among Black Hills Corporation and the several
Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on June 20, 2023).
10.22
Fourth Amended and Restated Credit Agreement dated as of July 19, 2021 (relating to $750 million Revolving
Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions party thereto, as Banks,
and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to the Registrant’s Form 8-
K filed on July 19, 2021).
10.22-1
First Amendment to Fourth Amended and Restated Credit Agreement dated as of May 9, 2023 (relating to
$750 million Revolving Credit Facility), among Black Hills Corporation, as Borrower, the financial institutions
party thereto, as Banks, and U.S. Bank, National Association, as Administrative Agent (filed as Exhibit 10.1 to
the Registrant's Form 10-Q filed on August 3, 2023).
Letter Agreement between Black Hills Corporation and Jennifer C. Landis (filed as Exhibit 10.1 to Form 10-Q
10.23†
filed May 4, 2023).
10.24†
Non-Employee Director Equity Compensation Plan effective January 1, 2022 (filed as Exhibit 10.25 to the
Registrant's Form 10-K filed on February 15, 2022).
10.25†
10.26
10.27
10.28†
10.29†
10.30*†
10.31*†
19*
21*
23.1*
31.1*
31.2*
32.1*
32.2*
95*
97*†
Form of Restricted Stock Unit Award Agreement (Non-Employee Director) effective for awards granted on or
after January 1, 2022 (filed as Exhibit 10.26 to the Registrant's Form 10-K filed on February 15, 2022).
Coal Leases between WRDC and the Federal Government
-Dated May 1, 1959 (filed as Exhibit 5(i) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(h) to the Registrant’s Form 10-K for 1989)
-Dated April 1, 1961 (filed as Exhibit 5(j) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(i) to Registrant’s Form 10-K for 1989)
-Dated October 1, 1965 (filed as Exhibit 5(k) to the Registrant’s Form S-7, File No. 2-60755)
-Modified January 22, 1990 (filed as Exhibit 10(j) to the Registrant’s Form 10-K for 1989).
Assignment of Mining Leases and Related Agreement effective May 27, 1997, between WRDC and Kerr-
McGee Coal Corporation (filed as Exhibit 10(u) to the Registrant’s Form 10-K for 1997).
Form of Restricted Stock Award Agreement for the Amended and Restated 2015 Omnibus Incentive Plan
effective for awards granted on or after January 24, 2023 (filed as Exhibit 10.30 to the Registrant's Form 10-K
for 2022).
Form of Performance Unit Award Agreement for the Amended and Restated 2015 Omnibus Incentive Plan
effective for awards granted on or after January 1, 2023 (filed as Exhibit 10.29 to the Registrant's Form 10-K
for 2022).
Form of Short-term Incentive Plan Award Agreement for the Amended and Restated 2015 Omnibus Incentive
Plan effective for awards granted on or after January 1, 2024.
Form of Performance Unit Award Agreement for the Amended and Restated 2015 Omnibus Incentive Plan
effective for awards granted on or after January 1, 2024.
Insider Trading Policy
List of Subsidiaries of Black Hills Corporation.
Consent of Independent Registered Public Accounting Firm.
Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as
adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as
adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section
906 of the Sarbanes-Oxley Act of 2002.
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002.
Mine Safety and Health Administration Safety Data
Mandatory Compensation Recovery Policy dated December 1, 2023
101.INS*
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because
its XBRL tags are embedded within the Inline XBRL document
101.SCH*
Inline XBRL Taxonomy Extension Schema with Embedded Linkbases Document
104*
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
ITEM 16. FORM 10-K SUMMARY
None.
105
10-KFORM 10-K | Pursuant to the requirements of Section 13 or 15(d) 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.
SIGNATURES
BLACK HILLS CORPORATION
By:
/S/ LINDEN R. EVANS
Linden R. Evans, President and Chief Executive Officer
Dated:
February 14, 2024
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons
on behalf of the Registrant and in the capacities and on the dates indicated.
/S/ STEVEN R. MILLS
Steven R. Mills
/S/ LINDEN R. EVANS
Linden R. Evans, President
and Chief Executive Officer
Director and
Chairman
Director and
Principal Executive Officer
February 14, 2024
February 14, 2024
/S/ KIMBERLY F. NOONEY
Principal Financial and
February 14, 2024
Kimberly F. Nooney, Senior Vice President
Accounting Officer
and Chief Financial Officer
/S/ BARRY M. GRANGER
Barry M. Granger
/S/ TONY A. JENSEN
Tony A. Jensen
Director
Director
February 14, 2024
February 14, 2024
/S/ KATHLEEN S. MCALLISTER
Director
February 14, 2024
Kathleen S. McAllister
/S/ ROBERT P. OTTO
Robert P. Otto
Director
February 14, 2024
/S/ SCOTT M. PROCHAZKA
Director
February 14, 2024
Scott M. Prochazka
/S/ REBECCA B. ROBERTS
Director
February 14, 2024
Director
Director
February 14, 2024
February 14, 2024
Rebecca B. Roberts
/S/ MARK A. SCHOBER
Mark A. Schober
/S/ TERESA A. TAYLOR
Teresa A. Taylor
106
10-K| FORM 10-K INVESTOR INFORMATION
Common Stock
Transfer Agent, Registrar &
Dividend Disbursing Agent
EQ Shareowner Services
P.O. Box 64854
St. Paul, MN 55164-0854
800-468-9716
www.shareowneronline.com
Senior Unsecured Notes
— Black Hills Corporation
Computershare Trust Company, N.A.
Corporate Trust
WF 8113
P.O. Box 1450
Minneapolis, MN 55485
First Mortgage Bonds
— Black Hills Power, Inc.
The Bank of New York Mellon
Corporate Trust, CF
101 Barclay 7 West
New York, NY 10286
First Mortgage Bonds
— Cheyenne Light,
Fuel & Power
Computershare Trust Company, N.A.
Corporate Trust
WF 8113
P.O. Box 1450
Minneapolis, MN 55485
Industrial Development
Revenue Bonds — Cheyenne
Light, Fuel & Power
Trustee & Paying Agent
Corporate Trust Services
US Bank National Association
EP-MN-WN3L
60 Livingston Avenue
St. Paul, MN 55107
Corporate Offices
Black Hills Corporation
P.O. Box 1400
7001 Mount Rushmore Road
Rapid City, SD 57709
605-721-1700
www.blackhillscorp.com
2024 Annual Meeting
The Annual Meeting of
Shareholders will be held at
Horizon Point, the Company’s
corporate headquarters at 7001
Mount Rushmore Road, Rapid
City, South Dakota, at 9:30 a.m.
local time on Tuesday, April 23,
2024. Prior to the meeting, formal
notice, proxy statement and proxy
will be mailed to shareholders.
Market for Equity Securities
The Company’s Common Stock
($1 par value) is traded on the
New York Stock Exchange.
Quotations for the Common Stock
are reported under the symbol
BKH. The continued interest
and support of equity owners
are appreciated. The Company
has declared Common Stock
dividends payable in each year
since its incorporation in 1941.
Regular quarterly dividends when
declared are normally payable on
March 1, June 1, September 1 and
December 1.
Internet Account Access
Registered shareholders
can access their accounts
electronically at
www.shareowneronline.com.
Shareowner Online allows
shareholders to view their
account balance, dividend
information, reinvestment details
and much more. The transfer
agent maintains stockholder
account access.
Direct Deposit of Dividends
We encourage you to consider
the direct deposit of your
dividends. With direct deposit,
your quarterly dividend payment
can be automatically transferred
on the dividend payment date
to the bank, savings and loan,
or credit union of your choice.
Direct deposit assures payments
are credited to shareholders’
accounts without delay. A form
is attached to your dividend
check where you can request
information about this method
of payment. Questions regarding
direct deposit should be directed
to EQ Shareowner Services.
Dividend Reinvestment and
Direct Stock Purchase Plan
A Dividend Reinvestment and
Direct Stock Purchase Plan
provides interested investors the
opportunity to purchase shares
of the Company’s Common Stock
and to reinvest all or a percentage
of their dividends. For complete
details, including enrollment,
contact the transfer agent,
EQ Shareowner Services.
Plan information is also available
at www.shareowneronline.com.
Website Access to Reports
The reports we file with the
Securities and Exchange
Commission are available free
of charge at our website www.
blackhillscorp.com as soon as
reasonably practicable after they
are filed. In addition, the charters
of our Audit, Governance and
Compensation Committees are
located on our website along
with our Code of Business
Conduct, Code of Ethics for
our Chief Executive Officer and
Senior Finance Officer, Corporate
Governance Guidelines of our
Board of Directors, and Policy for
Director Independence.
2023 Annual Report | Proxy Statement | Form 10-K | www.blackhillscorp.com