BLACK HILLS CORP /SD/ - Annual Report: 2022 (Form 10-K)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

10-K

Table of Contents

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, 2022

☐ 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.

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, 2022, was $4,702,221,557


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, 2023
Common stock, $1.00 par value	66,103,478	shares

Documents Incorporated by Reference

Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2023 Annual Meeting of Stockholders to be held on April 26, 2023, are incorporated by reference in Part III of this Form 10-K.

TABLE OF CONTENTS


		Page
GLOSSARY OF TERMS AND ABBREVIATIONS		4
WEBSITE ACCESS TO REPORTS		10
FORWARD-LOOKING INFORMATION		10
Part I
ITEM 1.	BUSINESS	11
	History and Organization	11
	Electric Utilities	11
	Gas Utilities	14
	Utility Regulation Characteristics	16
	Environmental Matters	20
	Human Capital Resources	21
ITEM 1A.	RISK FACTORS	23
ITEM 1B.	UNRESOLVED STAFF COMMENTS	30
ITEM 2.	PROPERTIES	30
ITEM 3.	LEGAL PROCEEDINGS	30
ITEM 4.	MINE SAFETY DISCLOSURES	30
INFORMATION ABOUT OUR EXECUTIVE OFFICERS		31
Part II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	32
ITEM 6.	RESERVED	33
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33
	Executive Summary	33
	Key Elements of our Business Strategy	34
	Recent Developments	38
	Results of Operations - Consolidated Summary and Overview	39
	Non-GAAP Financial Measure	40
	Electric Utilities	41
	Gas Utilities	44
	Corporate and Other	46
	Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)	46
	Liquidity and Capital Resources	47
	Cash Flow Activities	47
	Capital Resources	49
	Credit Ratings	50
	Capital Requirements	50
	Critical Accounting Estimates	52
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	54



ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	56
	Management’s Report on Internal Controls Over Financial Reporting	56
	Reports of Independent Registered Public Accounting Firm	57
	Consolidated Statements of Income	60
	Consolidated Statements of Comprehensive Income	61
	Consolidated Balance Sheets	62
	Consolidated Statements of Cash Flows	64
	Consolidated Statements of Equity	65
	Notes to Consolidated Financial Statements	66
	Note 1. Business Description and Significant Accounting Policies	66
	Note 2. Regulatory Matters	74
	Note 3. Commitments, Contingencies and Guarantees	78
	Note 4. Revenue	80
	Note 5. Property, Plant and Equipment	82
	Note 6. Jointly Owned Facilities	83
	Note 7. Asset Retirement Obligations	83
	Note 8. Financing	84
	Note 9. Risk Management and Derivatives	88
	Note 10. Fair Value Measurements	91
	Note 11. Other Comprehensive Income	93
	Note 12. Variable Interest Entity	94
	Note 13. Employee Benefit Plans	94
	Note 14. Share-based Compensation Plans	100
	Note 15. Income Taxes	103
	Note 16. Business Segment Information	106
	Note 17. Subsequent Events	108
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	108
ITEM 9A.	CONTROLS AND PROCEDURES	108
ITEM 9B.	OTHER INFORMATION	108
ITEM 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	108
Part III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	108
ITEM 11.	EXECUTIVE COMPENSATION	109
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	109
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	110
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	110
Part IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	110
ITEM 16.	FORM 10-K SUMMARY	113
SIGNATURES		114

Table of Contents

GLOSSARY OF TERMS AND ABBREVIATIONS

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


AC	Alternating Current
AFUDC	Allowance for Funds Used During Construction
AOCI	Accumulated Other Comprehensive Income (Loss)
APSC	Arkansas Public Service Commission
Arkansas Gas	Black Hills Energy Arkansas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Arkansas (doing business as Black Hills Energy).
ARO	Asset Retirement Obligation
ASC	Accounting Standards Codification
ASU	Accounting Standards Update as issued by the FASB
ATM	At-the-market equity offering program
Availability	The availability factor of a power plant is the percentage of the time that it is available to provide energy.
BHC	Black Hills Corporation; the Company
BHSC	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 utility companies
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 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 Generation
Blockchain Interruptible Service (BCIS) Tariff	A WPSC-approved tariff applicable to prospective new Wyoming Electric blockchain customers. The tariff allows customers to negotiate rates and terms and conditions for interruptible electric utility service of 10 MW or greater that would be interconnected with Wyoming Electric’s system. Agreements under the BCIS tariff must be filed with the WPSC prior to the first customer billing, be at least 2 years in duration and include specific pricing for all electricity purchased (with pricing terms subject to renegotiation every three years). BCIS customers shall not participate in the PCA to the extent of service received under the tariff.
Btu	British thermal unit
Busch Ranch I	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.

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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.
CACJA Adjustment	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.
CFTC	United States Commodity Futures Trading Commission
Cheyenne Light	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	Cheyenne Prairie Generating Station 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).
Chief Operating Decision Maker (CODM)	Chief Executive Officer
Choice Gas Program	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.
City of Gillette	Gillette, Wyoming
Clean Energy Plan	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% by 2030. The preferred resource portfolio calls for the addition of 149 MW of wind, 258 MW of solar and 50 MW of battery storage to Colorado Electric’s system. The final mix of resources would be determined by the results of a competitive solicitation starting in 2023. Colorado legislation allows electric utilities to own up to 50% of the renewable generation assets added to comply with the Clean Energy Plan.
CO2	Carbon dioxide
Colorado Electric	Black Hills Colorado Electric, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing electric service to customers in Colorado (doing business as Black Hills Energy).
Colorado Gas	Black Hills Colorado Gas, Inc., an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Colorado (doing business as Black Hills Energy).
Common Use System	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.
Consolidated Indebtedness to Capitalization Ratio	Any Indebtedness outstanding at such time, divided by capital at such time. Capital being consolidated net-worth (excluding non-controlling interest) plus consolidated indebtedness (including letters of credit and certain guarantees issued) as defined within the current Revolving Credit Facility.
Cooling Degree Day	A cooling degree day is equivalent to each degree that the average of the high and 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.
Corriedale	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.
COVID-19	The official name for the 2019 novel coronavirus disease announced on February 11, 2020, by the World Health Organization, that is causing a global pandemic.
CP Program	Commercial Paper Program
CPUC	Colorado Public Utilities Commission
CSAPR	Cross-State Air Pollution Rule

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CT	Combustion Turbine
CTII	The 40 MW Gillette CT, a simple-cycle, gas-fired combustion turbine owned by the City of Gillette.
Cushion Gas	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.
CVA	Credit Valuation Adjustment
DC	Direct Current
Dividend Payout Ratio	Annual dividends paid on common stock divided by net income from continuing operations available for common stock
DRSPP	Dividend Reinvestment and Stock Purchase Plan
DSM	Demand Side Management
Dth	Dekatherm. A unit of energy equal to 10 therms or one million British thermal units (MMBtu).
EBITDA	Earnings before interest, taxes, depreciation and amortization, a non-GAAP measure.
ECA	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	Energy Efficiency Cost Recovery is an adjustment mechanism that allows us to recover from customers the costs associated with providing energy efficiency programs.
EIA	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.
EGU	Electric generating unit
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	United States Environmental Protection Agency
EV	Electric Vehicle
EWG	Exempt Wholesale Generator
FASB	Financial Accounting Standards Board
FERC	United States Federal Energy Regulatory Commission
Fitch	Fitch Ratings Inc.
GAAP	Accounting principles generally accepted in the United States of America
GCA	Gas Cost Adjustment is an adjustment that allows us to pass the prudently-incurred cost of gas and certain services through to customers.
GHG	Greenhouse gases
Global Settlement	Settlement with a utility’s commission where the revenue requirement is agreed upon, but the specific adjustments used by each party to arrive at the amount are not specified in public rate orders.
Happy Jack	Happy Jack Wind Farm, LLC, owned by Duke Energy Generation Services
Heating Degree Day	A heating degree day is equivalent to each degree that the average of the high and the low temperatures for a day is below 65 degrees. The colder the climate, the greater the number of heating degree days. Heating degree days are used in the utility industry to measure the relative coldness of weather and to compare relative temperatures between one geographic area and another. Normal degree days are based on the National Weather Service data for selected locations.
HomeServe	We offer HomeServe products to our natural gas residential customers interested in purchasing additional home repair service plans.
Integrated Generation	Non-regulated power generation and mining businesses that are vertically integrated within our Electric Utilities segment.

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Iowa Gas	Black Hills Iowa Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Iowa (doing business as Black Hills Energy).
IPP	Independent Power Producer
IRA	Inflation Reduction Act of 2022
IRC	Internal Revenue Code
IRP	Integrated Resource Plan
IRS	United States Internal Revenue Service
ITC	Investment Tax Credit
IUB	Iowa Utilities Board
Kansas Gas	Black Hills Kansas Gas Utility Company, LLC, a direct, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Kansas (doing business as Black Hills Energy).
KCC	Kansas Corporation Commission
kV	Kilovolt
LIBOR	London Interbank Offered Rate
Mcf	Thousand cubic feet
Mcfd	Thousand cubic feet per day
MDU	Montana-Dakota Utilities Co., a subsidiary of MDU Resources Group, Inc.
MEAN	Municipal Energy Agency of Nebraska
MISO	Midcontinent Independent System Operator, Inc.
MMBtu	Million British thermal units
Moody’s	Moody’s Investors Service, Inc.
MSHA	United States Department of Labor’s Mine Safety and Health Administration
MW	Megawatts
MWh	Megawatt-hours
N/A	Not Applicable
NAAQS	National Ambient Air Quality Standards
NAV	Net Asset Value
Nebraska Gas	Black Hills Nebraska Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Nebraska (doing business as Black Hills Energy).
Neil Simpson II	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, Wyoming energy complex.
NERC	North American Electric Reliability Corporation
NOx	Nitrogen oxide
NOL	Net Operating Loss
Northern Iowa Windpower	Northern Iowa Windpower, LLC, a 87.1 MW wind farm located near Joice, Iowa, owned by Black Hills Electric Generation and operated by a third-party. We sell the wind energy generated in the MISO market.
NPSC	Nebraska Public Service Commission
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OSHA	United States Department of Labor’s Occupational Safety & Health Administration
OSM	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.
PCA	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.

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PCCA	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.
Peak View	The 60.8 MW wind farm owned by Colorado Electric.
PHMSA	United States Department of Transportation Pipeline and Hazardous Materials Safety Administration
PPA	Power Purchase Agreement
PRPA	Platte River Power Authority
PSA	Power Sales Agreement
PTC	Production Tax Credit
Pueblo Airport Generation	The 440 MW 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.
PUHCA 2005	Public Utility Holding Company Act of 2005
Ready	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.
Ready Wyoming	A 260-mile, multi-phase transmission expansion project in Wyoming. This transmission project will 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 will help Wyoming Electric maintain top-quartile reliability and enable economic development in the Cheyenne, Wyoming region.
Renewable Ready	Voluntary renewable energy subscription program for large commercial, industrial and governmental customers in South Dakota and Wyoming.
RESA	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.
Revolving Credit Facility	Our $750 million credit facility used to fund working capital needs, letters of credit and other corporate purposes, which was amended and restated on July 19, 2021, and now terminates on July 19, 2026.
RMNG	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).
RNG	Renewable natural gas
RTO	Regional Transmission Organization
SDPUC	South Dakota Public Utilities Commission
SEC	United States Securities and Exchange Commission
Service Guard Comfort Plan	Appliance protection plan that provides home appliance repair services through on-going monthly service agreements to residential utility customers.
Silver Sage	Silver Sage Windpower, LLC, owned by Duke Energy Generation Services
SO2	Sulfur dioxide
S&P	S&P Global Ratings, a division of S&P Global Inc.
SourceGas Transaction	On February 12, 2016, Black Hills Utility Holdings acquired SourceGas pursuant to a purchase and sale agreement executed on July 12, 2015 for approximately $1.89 billion, which included the assumption of $760 million in debt at closing.
South Dakota Electric	Black Hills Power, Inc., a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in Montana, South Dakota and Wyoming (doing business as Black Hills Energy).
SPP	Southwest Power Pool, a regional transmission organization (RTO) that oversees the bulk electric grid and wholesale power market in the central United States.
SSIR	System Safety and Integrity Rider
System Peak Demand	Represents the highest point of retail customer usage for a single hour.
TCA	Transmission Cost Adjustment is an annual adjustment mechanism that allows us to recover from customers eligible transmission investments prior to the next rate review.

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TCAM	Transmission Cost Adjustment Mechanism is a WPSC-approved tariff based on a formulaic approach that determines the recovery of Wyoming Electric's transmisson costs.
TCJA	Tax Cuts and Jobs Act enacted on December 22, 2017
Tech Services	Non-regulated product lines delivered by our Utilities that 1) provide electrical system construction services to large industrial customers of our electric utilities, and 2) serve gas transportation customers throughout its service territory by constructing and maintaining customer-owned gas infrastructure facilities, typically through one-time contracts.
TFA	Transmission Facility Adjustment is an annual adjustment mechanism that allows us to recover charges for qualifying new and modified transmission facilities from customers.
Transmission Tie	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.
TSA	United States Department of Homeland Security’s Transportation Security Administration
Utilities	Black Hills’ Electric and Gas Utilities
VEBA	Voluntary Employee Benefit Association
VIE	Variable Interest Entity
WEIS	Western Energy Imbalance Service
Wind Capacity Factor	Measures the amount of electricity a wind turbine produces in a given time period relative to its maximum potential
Winter Storm Uri	February 2021 winter weather event that caused extreme cold temperatures in the central United States and led to unprecedented fluctuations in customer demand and market pricing for natural gas and energy.
Working Capacity	Total gas storage capacity minus cushion gas
WPSC	Wyoming Public Service Commission
WRDC	Wyodak Resources Development Corp., a direct, wholly-owned subsidiary of Black Hills Non-regulated Holdings, providing coal supply primarily to five on-site, mine-mouth generating facilities (doing business as Black Hills Energy).
Wygen I	A mine-mouth, coal-fired generating facility with a total capacity of 90 MW located at our Gillette, Wyoming energy complex. Black Hills Wyoming owns 76.5% of the facility and Municipal Energy Agency of Nebraska (MEAN) owns the remaining 23.5%.
Wygen II	A mine-mouth, coal-fired power plant owned by Wyoming Electric with a total capacity of 95 MW located at our Gillette, Wyoming energy complex.
Wygen III	A mine-mouth, coal-fired power plant operated by South Dakota Electric with a total capacity of 116 MW located at our Gillette, Wyoming energy complex. South Dakota Electric owns 52% of the power plant, MDU owns 25% and the City of Gillette owns the remaining 23%.
Wyodak Plant	The 402.3 MW mine-mouth, coal-fired generating facility located at our Gillette, Wyoming energy complex, jointly owned by PacifiCorp (80%) and South Dakota Electric (20%). Our WRDC mine supplies all of the fuel for the facility.
Wyoming Electric	Cheyenne Light, Fuel and Power Company, a direct, wholly-owned subsidiary of Black Hills Corporation, providing electric service to customers in the Cheyenne, Wyoming area (doing business as Black Hills Energy).
Wyoming Gas	Black Hills Wyoming Gas, LLC, an indirect, wholly-owned subsidiary of Black Hills Utility Holdings, providing natural gas services to customers in Wyoming (doing business as Black Hills Energy).

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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.

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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 220,000 electric utility customers in Colorado, Montana, South Dakota and Wyoming. We also own and operate non-regulated power generation and mining assets that are vertically integrated into and primarily contracted to our Electric Utilities. Our Electric Utilities own 1,482 MW of generation and 9,024 miles of electric transmission and distribution lines.

Our Gas Utilities segment serves approximately 1,107,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Our Gas Utilities own and operate 4,713 miles of intrastate gas transmission pipelines and 42,222 miles of gas distribution mains and service lines, seven natural gas storage sites, more than 50,000 horsepower of compression and over 515 miles of gathering lines.

Electric Utilities

We conduct electric utility operations through our Colorado, South Dakota and Wyoming subsidiaries. Our electric generating facilities and power purchase agreements provide for the supply of electricity principally to our retail customers. Additionally, we sell excess power to other utilities and marketing companies, including our affiliates. We also provide non-regulated services to our retail customers under the Service Guard Comfort Plan and Tech Services.

Additionally, we own and operate non-regulated power generation and mining assets that are vertically integrated into and primarily support our Electric Utilities. Nearly all of these operations are located at our electric generating complexes and are physically integrated into our Electric Utilities’ operations.


	As of December 31,
Retail Customers	2022		2021		2020
Residential		188,921		186,852		184,872
Commercial		30,404		30,326		30,225
Industrial		82		81		83
Other		1,024		1,010		1,017
Total Electric Retail Customers at End of Year		220,431		218,269		216,197


	As of December 31,
Retail Customers	2022		2021		2020
Colorado Electric		100,573		99,709		98,735
South Dakota Electric		75,169		74,509		73,700
Wyoming Electric		44,689		44,051		43,762
Total Electric Retail Customers at End of Year		220,431		218,269		216,197

Capacity and Demand. System Peak Demand for the Electric Utilities’ retail customers for each of the last three years are listed below:


	System Peak Demand (in MW)
	2022 (a)		2021				2020
	Summer	Winter	Summer		Winter		Summer		Winter
Colorado Electric	410	334		407		279		401		297
South Dakota Electric	403	355		397		299		378		304
Wyoming Electric	294	281		274		246		271		246

____________________

(a)

In December 2022, each of our Electric Utilities set new winter peak loads. In July 2022, South Dakota Electric and Wyoming Electric set new all-time and summer 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.

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As of December 31, 2022, our Electric Utilities’ ownership interests in electric generating plants were as follows:


Unit	Fuel Type	Location	Ownership Interest % (d)	Owned Nameplate Capacity (MW)		In Service Date
Colorado Electric:
Busch Ranch I (a)	Wind	Pueblo, Colorado	50%		14.5	2012
Peak View (b) (c)	Wind	Pueblo, Colorado	100%		60.8	2016
Pueblo Airport Generation #1-2	Gas	Pueblo, Colorado	100%		200.0	2011
Pueblo Airport Generation CT #6	Gas	Pueblo, Colorado	100%		40.0	2016
AIP Diesel	Oil	Pueblo, Colorado	100%		10.0	2001
Diesel #1 and #3-5	Oil	Pueblo, Colorado	100%		8.0	1964
Diesel #1-5	Oil	Rocky Ford, Colorado	100%		10.0	1964
South Dakota Electric:
Cheyenne Prairie	Gas	Cheyenne, Wyoming	58%		58.0	2014
Corriedale (c)	Wind	Cheyenne, Wyoming	62%		32.5	2020
Wygen III	Coal	Gillette, Wyoming	52%		60.3	2010
Neil Simpson II	Coal	Gillette, Wyoming	100%		90.0	1995
Wyodak Plant	Coal	Gillette, Wyoming	20%		80.5	1978
Neil Simpson CT	Gas	Gillette, Wyoming	100%		40.0	2000
Lange CT	Gas	Rapid City, South Dakota	100%		40.0	2002
Ben French Diesel #1-5	Oil	Rapid City, South Dakota	100%		10.0	1965
Ben French CTs #1-4	Gas/Oil	Rapid City, South Dakota	100%		100.0	1977-1979
Wyoming Electric:
Cheyenne Prairie	Gas	Cheyenne, Wyoming	42%		42.0	2014
Cheyenne Prairie CT	Gas	Cheyenne, Wyoming	100%		40.0	2014
Corriedale (c)	Wind	Cheyenne, Wyoming	38%		20.0	2020
Wygen II	Coal	Gillette, Wyoming	100%		95.0	2008
Integrated Generation:
Wygen I	Coal	Gillette, Wyoming	76.5%		68.9	2003
Pueblo Airport Generation #4-5	Gas	Pueblo, Colorado	50.1% (e)		200.0	2012
Busch Ranch I (a)	Wind	Pueblo, Colorado	50%		14.5	2012
Busch Ranch II (c)	Wind	Pueblo, Colorado	100%		59.4	2019
Northern Iowa Windpower (c)	Wind	Joice, Iowa	100%		87.1	2019
Total MW Capacity					1,481.5

____________________

(a)

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.

(b)

The PTCs for Peak View flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins.

(c)

This facility qualifies for PTCs at $26/MWh under IRC 45 during the 10-year period beginning on the date the facility was originally placed in service.

(d)

Jointly owned facilities are discussed in Note 6 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

(e)

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 December 31 was as follows:


Power Supply	2022			2021			2020
Coal		35.1	%		34.2	%		40.3	%
Natural Gas and Diesel Oil (a)		18.8	%		24.4	%		25.0	%
Wind		11.4	%		11.3	%		8.8	%
Total Generated		65.3	%		69.9	%		74.1	%
Coal, Natural Gas, Oil and Other Market Purchases		29.6	%		25.1	%		21.1	%
Wind Purchases		5.1	%		5.0	%		4.8	%
Total Purchased		34.7	%		30.1	%		25.9	%
Total		100.0	%		100.0	%		100.0	%

____________________

(a)

The diesel-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.

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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)	2022		2021		2020
Coal	$	12.76	$	11.55	$	11.38
Natural Gas and Diesel Oil		37.09		33.65		8.59
Total Generated Weighted Average Fuel Cost		17.57		17.40		9.09
Coal, Natural Gas, Oil and Other Market Purchases		66.35		64.85		40.80
Wind Purchases		33.78		34.69		42.06
Total Purchased Power Weighted Average Cost		61.56		59.84		41.03
Total Weighted Average Fuel and Purchased Power Cost	$	32.82	$	30.17	$	17.36

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 2022.

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., $1.09 per MMBtu for year ended December 31, 2022) 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, 2022, we estimated our recoverable reserves to be approximately 174 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 47 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, 2022, our Electric Utilities owned the electric transmission and distribution lines shown below:


Utility	State	Transmission (a) (in Line Miles)		Distribution (in Line Miles)
Colorado Electric	Colorado		598		3,198
South Dakota Electric (b)	South Dakota, Wyoming		1,235		2,587
Wyoming Electric	Wyoming		59		1,347
			1,892		7,132

____________________

(a)

Electric transmission line miles include voltages of 69 kV and above.

(b)

South Dakota Electric transmission line miles include 43 miles within the Common Use System.

Material transmission services agreements are disclosed 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 performance. 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.

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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 the WRDC mine. Rail transport market opportunities for WRDC are limited due to the lower heating value (Btu) of the coal, combined with the fact that the WRDC mine is served by only one railroad, resulting in less competitive transportation rates. Additionally, coal competes with other energy sources, such as natural gas, 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 approximately 1,107,000 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 52,600 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.


	As of December 31,
Retail Customers	2022		2021		2020
Residential		864,038		853,908		844,999
Commercial		85,203		84,234		83,135
Industrial		2,189		2,158		2,235
Transportation		155,685		153,929		152,568
Total Natural Gas Retail Customers at End of Year		1,107,115		1,094,229		1,082,937


	As of December 31,
Retail Customers	2022		2021		2020
Arkansas Gas		183,270		180,216		178,281
Colorado Gas		208,060		202,747		197,817
Iowa Gas		162,801		161,905		160,952
Kansas Gas		118,599		117,862		116,973
Nebraska Gas		301,007		298,832		296,778
Wyoming Gas		133,378		132,667		132,136
Total Natural Gas Retail Customers at End of Year		1,107,115		1,094,229		1,082,937

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 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.

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The following table summarizes certain information regarding our company-owned regulated underground gas storage facilities as of December 31, 2022:


	Working Capacity (Mcf)		Cushion Gas (Mcf)		Total Capacity (Mcf)		Maximum Daily Withdrawal Capability (Mcfd)
Arkansas Gas		9,273,700		13,433,040		22,706,740		196,000
Colorado Gas		2,361,495		6,164,715		8,526,210		30,000
Wyoming Gas		5,733,900		17,545,600		23,279,500		36,000
Total		17,369,095		37,143,355		54,512,450		262,000

The following table summarizes certain information regarding our system infrastructure as of December 31, 2022:


	Intrastate Gas Transmission Pipelines (in line miles)		Gas Distribution Mains (in line miles)		Gas Distribution Service Lines (in line miles)
Arkansas Gas		877		5,070		1,330
Colorado Gas		699		7,088		2,372
Iowa Gas		173		2,879		2,503
Kansas Gas		331		3,004		1,388
Nebraska Gas		1,317		8,558		2,796
Wyoming Gas		1,316		3,563		1,671
Total		4,713		30,162		12,060

Seasonal Variations of Business. Our Gas Utilities are seasonal businesses and weather patterns may impact their operating performance. 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 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.

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Utility Regulation Characteristics

Our Utilities are subject to regulation by a number of federal, state and other organizations, including, but not limited to, the following:

•

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.

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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 (a)	CO	9.37%	7.43%	48%/52%	$539.6	1/2017	ECA, TCA, PCCA, EECR/DSM, RESA	90%
	CO	9.37%	6.02%	67%/33%	$57.9	1/2017	CACJA Adjustment Rider	N/A
South Dakota Electric	WY	9.90%	8.13%	47%/53%	$46.8	10/2014	ECA	65%
	SD	Global Settlement	7.76%	Global Settlement	$543.9	10/2014	ECA, TFA, EIA	70%
	FERC	10.80%	8.76%	43%/57%	$177.8 (b)	2/2009	FERC Transmission Tariff	N/A
Wyoming Electric (a) (c)	WY	9.75%	7.48%	48%/52%	$506.4	3/2023	PCA, EECR/DSM, Rate Base Recovery on Acquisition Adjustment, TCAM	N/A

____________________

(a)

For both Colorado Electric and Wyoming Electric, transmission investments are recovered through retail rates rather than FERC Transmission Tariffs. Effective September 1, 2022, a formulaic approach determines the revenue component of Colorado Electric's open access transmission tariff.

(b)

Includes $160.7 million in 2022 rate base for the 2022 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.

(c)

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:

Cost Recovery Mechanisms

 
Electric Utility Jurisdiction

Environmental
Cost

EECR/DSM

Transmission
Expense

Fuel
Cost

Transmission
Capital

Purchased
Power

RESA

Colorado Electric

☑

☑

☑

☑

☑

☑

South Dakota Electric (SD) (a)

☑

☑

☑

☑

☑

South Dakota Electric (WY) (b)

☑

☑

☑

☑

South Dakota Electric (FERC) (c)

☑

Wyoming Electric (d)

☑

☑

☑

☑

☑

____________________

(a)

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.

(b)

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.

(c)

South Dakota Electric has an approved FERC Transmission Tariff based on a formulaic approach that determines the revenue component of South Dakota Electric’s open access transmission tariff.

(d)

Wyoming Electric has a WPSC-approved transmission tariff based on a formulaic approach that determines the recovery of Wyoming Electric's transmission costs.

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Gas Utilities

The following table provides regulatory information for each of our Gas 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
Arkansas Gas (a)	AR	9.60%	6.20% (b)	55%/45%	$674.6 (c)	10/2022	GCA, Safety and Integrity Rider, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado Gas (a)	CO	9.20%	6.56%	50%/50%	$303.20	1/2022	GCA, SSIR, EECR/DSM
RMNG	CO	9.90%	6.71%	53%/47%	$118.70	6/2018	SSIR, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa Gas (a)	IA	9.60%	6.75%	50%/50%	$300.90	1/2022	GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing
Kansas Gas (a)	KS	Global Settlement	Global Settlement	Global Settlement	Global Settlement	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%	$504.20	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 (d)	WY	9.40%	6.98%	50%/50%	$354.40	3/2020	GCA, EECR, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program

____________________

(a)

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)

Arkansas Gas return on rate base is adjusted to remove certain liabilities from rate review capital structure for comparison with other subsidiaries.

(c)

Arkansas Gas rate base is adjusted to include certain liabilities for comparison with other subsidiaries.

(d)

The Choice Gas Program mechanisms are applicable to only a portion of Nebraska Gas and Wyoming Gas customers.

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The following table summarizes the mechanisms we have in place for each of our Gas Utilities:


Gas Utility Jurisdiction	Cost Recovery Mechanisms
Gas Utility Jurisdiction	EECR/DSM	Integrity Additions	Bad Debt	Weather Normal	Pension Recovery	Gas Cost (b)	Revenue Decoupling
Arkansas Gas	☑	☑		☑		☑	☑
Colorado Gas	☑	☑				☑
RMNG (a)		☑
Iowa Gas	☑	☑				☑
Kansas Gas		☑	☑	☑	☑	☑
Nebraska Gas		☑	☑			☑
Wyoming Gas	☑	☑				☑

____________________

(a)

RMNG, which is an intrastate transmission pipeline that provides natural gas transmission and wholesale services in western Colorado, has an SSIR mechanism which allows recovery of investments through December 31, 2021. The other cost recovery mechanisms are not applicable to RMNG.

(b)

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.

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 public 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 three EWGs, Wygen I, Pueblo Airport Generation (facilities #4-5) and Northern Iowa Windpower. Each of these three 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.

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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. We have implemented several of these directives and are evaluating the potential effect of several others on our operations and facilities, as well as the potential cost of implementation, 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.

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. In a January 2021 decision, the U.S. Court of Appeals for the D.C. Circuit issued a decision vacating and remanding the Affordable Clean Energy rule. Four petitions for review of the D.C. Circuit’s opinion were subsequently granted by the U.S. Supreme Court on October 29, 2021, consolidated under West Virginia v. EPA et al. On June 30, 2022, the U.S. Supreme Court released its opinion in favor of West Virginia and aligned parties. The decision clarifies that there are limits on how the EPA may regulate GHGs absent further direction from the U.S. Congress. The court concluded that emission caps that would cause generation shifting from fossil-fuel-fired power plants to renewable energy facilities would require specific congressional authorization and that such authorization had not been given under the Clean Air Act. The decision by the U.S. Supreme Court may affect the EPA’s development of any new regulations to address CO2 emissions from coal- and natural gas-fired power plants; however, at this time, we cannot predict the impact of any such regulations or the decision by the U.S. Supreme Court on the results of operations, financial position, and liquidity. The EPA has indicated that it intends to issue a proposed rule in early 2023 with a new set of emission guidelines for states to follow in submitting state plans to establish and implement standards of performance for GHG emissions from existing fossil fuel-fired electric generating units. 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 rule focuses on reductions of NOx, which is a precursor to ozone formation, for states that do not have an approved State Implementation Plan (SIP). On January 31, 2023, the EPA finalized a notice which disapproved 19 SIPs, partially disapproved two other SIPs and deferred action until December 2023 on two SIPs, which included Wyoming. The EPA action on January 31, 2023 was a necessary prerequisite for the EPA to finalize a proposed Good Neighbor Rule by the March 15, 2023 deadline. The EPA also released a new air quality modeling that indicated two states (including Wyoming), which were previously within scope of the Good Neighbor Rule, no longer exceeded the cross-state ozone emissions threshold. It is likely that the EPA will rely on this new air quality modeling as part of the final Good Neighbor Rule. Based on the new air quality modeling, Wyoming will not be required to purchase additional NOx allowances during the 2023 ozone season. Until the EPA takes action on Wyoming's SIP, which is anticipated in December 2023, we cannot determine our future CSAPR compliance costs or impacts on our operations, but they could be material. However, we anticipate that any costs incurred as a result of the proposed rule would be recoverable through our regulatory mechanisms.

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.

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Human Capital Resources

Overview

We are committed to supporting operational excellence by attracting, motivating, retaining and encouraging the development of a highly qualified and diverse employee team. Our employees’ drive and dedication to their work, and their commitment to the safety of our customers and their fellow employees, allows us to successfully grow and manage our business year over year.


Our Team	As of December 31, 2022	As of December 31, 2021
Total employees	2,982	2,884
Women in executive leadership positions (a)	33%	30%
Gender diversity (women as a % of total employees)	25%	26%
Represented by a union	25%	25%
Military veterans	11%	14%
Ethnic diversity (non-white employees as a % of total)	14%	12%

	For the year ended December 31, 2022	For the year ended December 31, 2021
Number of external hires	487	214
External hires gender diversity (as a % of total external hires)	30%	25%
External hires ethnic diversity (as a % of total external hires)	23%	20%
Turnover rate (b)	13%	11%
Retirement rate	3%	3%

____________________

(a)

Executive leadership positions are defined as positions with Vice President, Senior Vice President or Chief in their title.

(b)

Includes voluntary and involuntary separations but excludes internships.

Total Employees


	Number of Employees
	As of December 31, 2022
Electric Utilities		442
Gas Utilities		1,226
Corporate and Other		1,314
Total		2,982

At December 31, 2022, approximately 19% of our total employees and 21% 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, 2022, 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	Number of Employees		Union Affiliation	Expiration Date of Collective Bargaining Agreement
Colorado Electric		105	IBEW Local 667	April 15, 2023
South Dakota Electric		130	IBEW Local 1250	March 31, 2027
Wyoming Electric		35	IBEW Local 111	June 30, 2024
Total Electric Utilities		270

Iowa Gas		129	IBEW Local 204	January 31, 2026
Kansas Gas		18	Communications Workers of America, AFL-CIO Local 6407	December 31, 2024
Nebraska Gas		83	IBEW Local 244	March 13, 2025
Nebraska Gas		137	CWA Local 7476	October 30, 2023
Wyoming Gas		15	IBEW Local 111	June 30, 2024
Wyoming Gas		82	CWA Local 7476	October 30, 2023
Total Gas Utilities		464

Total		734

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Attraction

Attracting talent to join our team is critical to our ability to serve over 1.3 million customers safely and efficiently. We continuously evaluate our recruitment strategies to determine their effectiveness to attract and build a high-performing, diverse workforce. Our diversity recruiting strategies support our efforts to attract qualified individuals with targeted efforts to reach underrepresented talent pools. Our internship program and our partnerships and participation in outreach programs with local schools and colleges attract students to careers in energy. Our commitment to equitable and inclusive hiring practices, including pay equity, further supports our vision of attracting, developing and retaining a high-performing workforce driven by improving life with energy.

Diversity & Inclusion

We believe in the benefits of diversity, equity and inclusion. We believe that a diverse workforce will assist us in executing our strategic business plans, including our growth strategy. Workforce diversity trends, which include gender and diverse new hires, promotions and turnover, are monitored at regular intervals throughout the year.

Development and Retention

Retaining and developing team members is critical to our continued success. Our retention efforts include competitive compensation programs, monitoring employee engagement, career development resources for all employees and internal training programs. Our compensation programs are designed to be strategically aligned, externally competitive, internally equitable, personally motivating, cost effective and legally compliant. We continuously 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 resources include management onboarding, leadership development programs, mentoring programs, individual development assessments 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 through established standards of knowledge, skills, abilities and performance.

Employee Safety and Wellness

Safety is one of our company values, a top priority in all we do and deeply embedded in our culture. We are committed to consistently outperforming utility industry averages in key safety metrics. 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 75% and continue to see long-term, sustained improvements in our safety practices and performance.


	For the year ended December 31, 2022
Total Case Incident Rate (incidents per 200,000 hours worked)		1.39
Preventable Motor Vehicle Incident Rate (vehicle accidents per 1 million miles driven)		1.33
% of injuries reported within 1 day		90.8	%

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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, including our growth strategy. Our plans and strategy include building sustainable operations and supporting the Energy Transition; consistently outperforming utility industry averages in key safety metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas customer load; and pursuing operational efficiencies. 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: availability of low cost 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 Electric and Gas 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 Electric and Gas 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.

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.

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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 natural gas, 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.

Our business, financial condition, results of operations and prospects may be materially adversely affected due to adverse results of litigation.

Material legal proceedings are summarized in Note 3 of Notes to Consolidated Financial Statement in this Annual Report on Form 10-K. Unfavorable resolution of legal or administrative proceedings in which we are involved or other future legal or administrative proceedings could have an adverse effect on our financial operating results, including earnings, cash flow and liquidity.

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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 higher turnover, 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, 2022, approximately 19% of our employees were eligible for retirement. Our ability to avoid or minimize supply interruptions, 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.

Our plans and strategy include building sustainable operations and supporting the Energy Transition; consistently outperforming utility industry averages in key safety metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas customer load; and pursuing operating efficiencies. As part of our strategic plan, 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.

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 performance. To the extent weather conditions are affected by climate change, fluctuations in 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. Unmitigated impacts of 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) intended to reduce GHG emissions. 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 sustainable companies and consumers preference for renewable energy could impact our reputation and overall access to capital and/or adequate insurance policies.

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. railroad 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. Russian invasion of Ukraine).

An inability to successfully manage challenges in our supply chain network could materially affect our financial operating results including earnings, cash flow and liquidity.

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Cyberattacks, 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. Cyberattacks, 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. Recent geopolitical conflicts (e.g. Russia's invasion of Ukraine) have increased the risk of cyberattack. Any disruption of these 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 cyberattacks, 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.

We have instituted security measures and safeguards to protect our operational systems and information technology assets, including certain safeguards required by FERC. Despite our implementation of security measures and safeguards, all of our technology systems may still be vulnerable to disability, failures or unauthorized access.

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 above);

•

Acts of sabotage, terrorism or other malicious 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;

•

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;

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•

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.

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 utility businesses 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 utility businesses 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 utility operations 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.

•

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 of energy and 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.

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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, 2022. 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 forced 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.

Widespread public health crises and epidemics or pandemics could negatively affect our business operations, results of operations, financial condition and cash flows.

We are subject to the impacts of widespread public health crises, epidemics and pandemics, including, but not limited to, impacts on the global, national or local economies, capital and credit markets, our workforce, customers and suppliers. There is no assurance that our businesses will be able to operate without material adverse impacts depending on the nature of the public health crisis, epidemic or pandemic. The ultimate severity, duration and impact of public health crises, epidemics and pandemics cannot be predicted. Additionally, there is no assurance that vaccines, or other treatments, are or will be widely available or effective, or that the public will be willing to participate, in an effort to contain the spread of disease. Actions taken in response to such crises by federal, state and local government or regulatory agencies may adversely affect our financial operating results including earnings, cash flow and liquidity.

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+ (Stable 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.

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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.

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.

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.

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.

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.

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 8 of the Notes to Consolidated Financial Statements of this Annual Report on Form 10-K for further information

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Costs associated with our healthcare plans and other benefits could increase significantly.

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, or liquidity.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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.

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INFORMATION ABOUT OUR EXECUTIVE OFFICERS

Linden R. Evans, age 60, 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 21 years of experience with the Company.

Brian G. Iverson, age 60, 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 19 years of experience with the Company.

Erik D. Keller, age 59, 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.

Richard W. Kinzley, age 57, has been Senior Vice President and Chief Financial Officer since 2015. He served as Vice President - Corporate Controller from 2013 to 2014, Vice President - Strategic Planning and Development from 2008 to 2013, and as Director of Corporate Development from 2000 to 2008. Mr. Kinzley has 23 years of experience with the Company. As previously announced, Mr. Kinzley intends to retire in mid-2023 He will continue to serve in his current position until March 31, 2023, after which Kimberly F. Nooney, the Company’s Vice President, Treasurer, will succeed Mr. Kinzley and Mr. Kinzley will continue as Senior Vice President until his retirement to provide for a reasonable transition period.

Jennifer C. Landis, age 48, has been Senior Vice President - Chief Human Resources Officer since February 1, 2017. She served as Vice President of Human Resources from April 2016 through January 2017, Director of Corporate Human Resources and Talent Management from 2013 to April 2016, and Director of Organization Development from 2008 to 2013. Ms. Landis has 21 years of experience with the Company.

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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, 2023, we had 3,403 common shareholders of record and 70,195 beneficial owners, representing all 50 states, the District of Columbia and 6 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, 2017, 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.


	Years ended December 31,
	2017		2018		2019		2020		2021		2022
Black Hills Corporation	$	100.00	$	107.97	$	138.83	$	112.34	$	133.55	$	137.65
S&P 500		100.00		95.62		125.72		148.85		191.58		156.88
S&P 500 Utilities		100.00		104.11		131.54		132.18		155.53		157.97
Performance Peer Group (a)		100.00		103.67		130.41		128.89		150.96		152.70

____________________

(a)

Performance Peer Group represents the Edison Electric Institute Index, which was used in our 2022 Proxy Statement filed with the SEC on March 17, 2022.

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 2022.

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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.

ISSUER PURCHASES OF EQUITY SECURITIES

The following table contains monthly information about our acquisitions of equity securities for the three months ended December 31, 2022:


Period	Total Number of Shares Purchased (a)		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
October 1, 2022 - October 31, 2022		2	$	67.73		—		—
November 1, 2022 - November 30, 2022		294	$	64.75		—		—
December 1, 2022 - December 31, 2022		10,035	$	68.87		—		—
Total		10,331	$	68.75		—		—

____________________

(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 vision to be the Energy Partner of Choice directs our strategy to invest in the safety, sustainability and growth of our eight-state service territory, including Arkansas, Colorado, Iowa, Kansas, Montana, Nebraska, South Dakota and Wyoming, and to meet our essential objective of providing safe, reliable and cost-effective electricity and natural gas.

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 139 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.

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, and remaining focused on our human capital through diversity and inclusion.

Our emphasis is on consistently outperforming utility industry averages in key safety metrics; modernizing utility infrastructure; transforming the customer experience; growing our electric and natural gas customer load; and pursuing operating efficiencies. These areas of focus will present the company with significant investment needs as we harden our infrastructure systems, meet customer growth and fulfill customer expectations for cleaner energy services. It will also allow us to better understand our customer and community needs while providing more intuitive and cost-effective solutions.

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Key Elements of our Business Strategy

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 1,482 MW of generation capacity and 9,024 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.

We rigorously comply with all applicable federal, state and local regulations and strive to consistently meet industry best practice standards. A key component of our modernization effort is the development of programs by our Electric and Gas Utilities to systematically and proactively replace aging infrastructure on a system-wide basis.

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. On October 11, 2022, the WPSC approved a CPCN submitted by Wyoming Electric to construct the transmission expansion project. Construction of the project is expected to take place in multiple phases or segments from 2023 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.

As of December 31, 2022, we estimate our five-year capital investment to be approximately $3.5 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 2022 and forecasted capital expenditures for the next five years from 2023 through 2027 are as follows (in millions). Minor differences may result due to rounding.


	Actual (a)		Forecasted
Capital Expenditures By Segment:	2022		2023		2024		2025		2026		2027
(in millions)
Electric Utilities	$	243	$	212	$	348	$	268	$	184	$	163
Gas Utilities		349		386		452		412		393		444
Corporate and Other		5		17		19		20		19		18
Incremental projects (b)		-		-		-		-		104		75
Total	$	598	$	615	$	819	$	700	$	700	$	700

(a)

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.

(b)

These represent projects that 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. 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 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.

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Rate Base 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, except Northern Iowa Windpower, are contracted to our Electric Utilities under long-term contracts and are located at our utility-generating complexes, including Busch Ranch, Pueblo Airport Generation, and the Gillette, Wyoming energy complex, and are physically integrated into our Electric Utilities’ operations.

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 coal mine. We operate and own majority interests in four of the five power plants and own 20% of the fifth power plant. Our coal mine 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., $1.09 per MMBtu for year ended December 31, 2022) 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. 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 includes Scope 1 emissions from distribution system main and service lines. On August 31, 2022, we announced a new "Net Zero by 2035" target for our Gas Utilities, which doubles the previous target of a 50% reduction by 2035 and expands 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 Gas Utilities distribution system mains and services by more than 33% and achieved a one-third reduction from our Electric Utilities (a nearly 10% reduction since announcing our goal in 2020 for our Electric Utilities). 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.

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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. To support this interest:

•

We created the Renewable Ready program for South Dakota Electric and Wyoming Electric customers. In support of this program, we created and received approvals for new, voluntary renewable energy tariffs to serve certain commercial, industrial and governmental customer requests for renewable energy resources. To meet the renewable energy commitments under the new tariffs, in November 2020, we completed construction and placed into service the Corriedale wind project, a 52.5 MW wind energy project near Cheyenne, Wyoming.

•

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 natural gas in 2025 and consideration of up to 10 MW of battery storage.

•

On January 13, 2023, Colorado Electric submitted a unanimous settlement for its Clean Energy Plan filed May 25, 2022, with the CPUC. If approved, the plan would add approximately 400 MW of new clean energy resources needed to reduce carbon emissions 80% by 2030. A final decision from the CPUC is expected in the first quarter of 2023.

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 on August 16, 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; include energy storage, EVs, RNG, and carbon capture and sequestration; and allow 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 and as having 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.

Explore opportunities as an energy solutions provider. Another strategic initiative is to grow our business through creative 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. A few recent examples of our initiatives to grow our business through creative solutions include:

•

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 (to be owned by third parties) which are expected to be completed by the end of 2023. The renewable energy from these PPAs will be used to serve our expanding partnerships with data centers.

•

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, a five-year agreement to deliver up to 45 MW with an option to expand service up to 75 MW to a new customer in Cheyenne, Wyoming, under this Tariff. Energy will be sourced through the electric energy market and delivered through our Electric Utilities’ infrastructure. Under the agreement, the customer will be responsible for costs of service, and the load will be interruptible to prioritize the needs of Wyoming Electric’s existing retail customers.

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•

During the first quarter of 2022, Colorado Electric agreed to join SPP’s WEIS Market. On September 26, 2022, South Dakota Electric and Wyoming Electric also agreed to join the WEIS Market. South Dakota Electric and Wyoming Electric will join Colorado Electric in integrating into the WEIS Market in April 2023 and expects to continue studying long-term solutions for joining or developing an organized wholesale market. The expansion allows the utilities to participate in a real-time market.

Additionally, we are pursuing two important initiatives in the form of sustainable energy solutions for electric vehicles and RNG. These two programs support our near-term sustainable strategy and contribute to the achievement of our aspirational greenhouse gas emissions reduction goals.

•

Electric Vehicles: We expect EV market share to increase over the next one to three years, commensurate with a significant uptick in vehicle range and product offerings and marked decrease in EV purchase prices. In addition to future load growth opportunities, we are investigating behind-the-meter solutions for customers. In January 2022, the CPUC approved a transportation electrification plan for Colorado Electric including the implementation of EV and charger rebates and EV rates.

•

Renewable Natural Gas: In 2021, we developed a voluntary RNG and carbon offset program to help our residential and small business natural gas customers offset up to 100% or more of the emissions associated with their own natural gas usage. In 2022, we filed for approval to launch these programs in three of our states, receiving regulatory approval for the program from both the KCC and the NPSC in Q4 2022. We intend to begin offering the program to customers in 2023, as well as completing additional regulatory filings with commissions in our other natural gas states.

Our teams are also evaluating multiple RNG investment opportunities and exploring value generation with our natural gas storage assets. We also continue to expand our RNG interconnections, with six projects actively injecting RNG into our natural gas system. In 2022, we created a new non-regulated business, BHERR, which will drive new growth by investing capital into infrastructure assets that provide a pathway for RNG to enter the market. BHERR builds on our expertise and experience in both RNG and natural gas asset operations, and aligns with market demand and the path to a cleaner energy future.

Execute disciplined capital allocation and explore small strategic opportunities. We are planning a disciplined capital investment program of approximately $600 million during the next year to improve our cash flows and reduce our debt to total capitalization ratio. By carefully managing capital, we plan to continue to strengthen our balance sheet and enhance our liquidity. With this goal in mind, we will continue to evaluate smaller scale acquisitions of private utility infrastructure systems and small municipal systems that can be easily incorporated into our existing utility systems.

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. 2022 represented our 52nd consecutive year of increasing dividends. In January 2023, our Board of Directors declared a quarterly dividend of $0.625 per share, equivalent to an annual dividend of $2.50 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.

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Recent Developments

Macroeconomic Trends

We are monitoring adverse macroeconomic trends including potential recession, inflationary pressures on the prices of commodities, materials, outside services and employee costs; supply chain constraints; rising interest rates and a competitive and tight labor market. To date, we have experienced moderate net impacts from these trends. However, if current macroeconomic conditions continue or deteriorate in 2023, adverse impacts to our businesses may be magnified.

Higher commodity energy costs continue to have an effect on customer bills and deferred energy costs. Our utilities have regulatory mechanisms that allow them to pass prudently incurred costs of energy through to the customer, which mitigates our exposure. Customer billing rates are adjusted periodically to reflect changes in our cost of energy. As a result of increased customer billings, we incurred higher bad debt expense.

Higher deferred energy costs and rising interest rates have led to increased interest expense and increased short-term variable rate borrowings, which include our Revolving Credit Facility and CP Program. However, the increased interest expense for the year ended December 31, 2022 was limited since 88% of our debt at December 31, 2022, is fixed rate debt. Rising discount rates and recent capital markets volatility had a limited impact to the unfunded status of the BHC Pension Plan when 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 2023 capital investment program, we have contracted materials for the majority 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 continuity of our system. We have also evaluated each of our forecasted projects and will prioritize depending on future constraints. Project delays may occur if costs rise significantly or if materials are not available.

Inflationary pressures and supply chain constraints have increased our operating expenses, which included higher outside services expenses (i.e., consulting and contractor rates), materials expenses and vehicle expenses driven by higher fuel prices.

We are faced with increased competition for employee and contractor talent in the current labor market. To date, we have seen a limited net increase in total employee costs due to increased employee and contractor costs related to attraction and retention of talent mostly offset by workforce attrition.

More detailed discussion of the future uncertainties can be found in Item 1A - Risk Factors.

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, Wyoming Electric's BCIS tariff, Colorado Electric's Clean Energy Plan filing, and the Electric Utilities joining the WEIS Market.

•

In December 2022, each of our Electric Utilities set new winter peak loads:

•

On December 22, 2022, Colorado Electric set a new winter peak load of 334 MW, surpassing the previous winter peak of 313 MW set in October 2018.

•

On December 21, 2022, South Dakota Electric set a new winter peak load of 355 MW, surpassing the previous winter peaks of 327 MW set on January 5, 2022 and 326 MW set in February 2021.

•

On December 21, 2022, Wyoming Electric set a new winter peak load of 281 MW, surpassing the previous peaks of 263 MW set on November 17, 2022, 262 MW set on February 23, 2022, 252 MW set on January 5, 2022 and 247 MW set in December 2019.

•

In December 2022, WRDC entered into a new agreement with PacifiCorp, effective January 1, 2023, to continue as the sole supplier of coal (fuel) to the Wyodak Plant through December 31, 2026 with a one-year extension option to December 31, 2027. Pricing and other terms of the new fuel supply agreement are similar to the previous contract which ended December 31, 2022.

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•

In July 2022, South Dakota Electric and Wyoming Electric both set new all-time and summer peak loads:

•

On July 21, 2022, Wyoming Electric set a new all-time and summer peak load of 294 MW, surpassing the previous peaks of 288 MW set on July 18, 2022, 282 MW set on June 13, 2022 and 274 MW set in July 2021.

•

On July 18, 2022, South Dakota Electric set a new all-time and summer peak load of 403 MW, surpassing the previous summer peak of 397 MW set in July 2021.

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 and RMNG.

•

See Key Elements of our Business Strategy section above for discussion of recent developments related to our Gas Utilities' voluntary RNG and carbon offset programs.

Corporate and Other

•

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 that was acquired by a BHC subsidiary in 2003. We believe we have meritorious defenses to the verdict and have appealed the verdict. See additional information in Note 3 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for further information.

Results of Operations

Our discussion and analysis for the year ended December 31, 2022 compared to 2021 is included herein. For discussion and analysis for the year ended December 31, 2021 compared to 2020, 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, 2021, which was filed with the SEC on February 15, 2022.

Segment information does not include intercompany eliminations and all amounts are presented on a pre-tax basis unless otherwise indicated. Minor differences in amounts may result due to rounding.

Consolidated Summary and Overview


	For the Years Ended December 31,
	2022			2021			2020
	(in thousands, except per share amounts)
Operating income (loss):
Electric Utilities	$	214,258		$	202,676		$	210,974
Gas Utilities		244,160			211,157			215,889
Corporate and Other		(3,174	)		(4,404	)		1,440
Operating Income		455,244			409,429			428,303

Interest expense, net		(160,989	)		(152,404	)		(143,470	)
Impairment of investment		—			—			(6,859	)
Other income (expense), net		1,708			1,404			(2,293	)
Income tax (expense)		(25,205	)		(7,169	)		(32,918	)
Net income		270,758			251,260			242,763
Net income attributable to non-controlling interest		(12,371	)		(14,516	)		(15,155	)
Net income available for common stock	$	258,387		$	236,744		$	227,608

Total earnings per share of common stock, Diluted	$	3.97		$	3.74		$	3.65

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2022 Compared to 2021

The variance to the prior year included the following:

•

Electric Utilities’ operating income increased $12 million primarily due to increased rider revenues, prior year impacts related to the Wygen I unplanned outage and Colorado Electric’s TCJA-related bill credits to customers, increased transmission services revenue and off-system excess energy sales partially offset by higher operating expenses and lower pricing on the new Wygen I PPA;

•

Gas Utilities’ operating income increased $33 million primarily due to new rates and rider recovery, favorable weather, carrying costs on our Winter Storm Uri regulatory asset, prior year Black Hills Energy Services Winter Storm Uri costs, customer growth partially offset by higher operating expenses;

•

Corporate and Other expenses decreased $1.2 million primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments;

•

Interest expense increased $8.6 million due to higher interest rates on higher short-term debt balances;

•

Income tax expense increased $18 million driven by higher pre-tax income and a higher effective tax rate primarily due to prior year tax benefits from Colorado Electric and Nebraska Gas TCJA-related bill credits and decreased flow-through tax benefits driven by prior year repairs and gain deferral partially offset by tax benefits from various state tax rate changes; and

•

Net income attributable to non-controlling interest decreased $2.1 million due to lower net income from Black Hills Colorado IPP primarily driven by lower fired-engine hours and a planned outage.

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.

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.

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Electric Utilities

Operating results for the years ended December 31 for the Electric Utilities were as follows (in thousands):


	2022		2021		2022 vs 2021 Variance		2020		2021 vs 2020 Variance

Revenue:
Electric - regulated	$	852,141	$	800,747	$	51,394	$	699,712	$	101,035
Other - non-regulated		48,021		41,511		6,510		39,145		2,366
Total revenue		900,162		842,258		57,904		738,857		103,401

Fuel and Purchased Power:
Electric - regulated		261,726		244,504		17,222		136,374		108,130
Other - non-regulated		4,558		3,514		1,044		2,198		1,316
Total fuel and purchased power		266,284		248,018		18,266		138,572		109,446

Electric Utility margin (non-GAAP)		633,878		594,240		39,638		600,285		(6,045	)

Operations and maintenance		283,654		260,036		23,618		265,679		(5,643	)
Depreciation and amortization		135,966		131,528		4,438		123,632		7,896
Total operating expenses		419,620		391,564		28,056		389,311		2,253

Operating income	$	214,258	$	202,676	$	11,582	$	210,974	$	(8,298	)

2022 Compared to 2021

Electric Utility margin increased over the prior year as a result of:


	(in millions)
New rates and rider recovery	$	11.2
Prior year TCJA-related bill credits (a)		9.3
Prior year Wygen I unplanned outage		8.5
Transmission services and off-system excess energy sales		7.6
Integrated Generation (b)		5.7
Weather		3.2
Retail load growth		1.2
Lower pricing on new Wygen I PPA		(8.5	)
Other		1.4
	$	39.6

(a)

In February 2021, Colorado Electric delivered TCJA-related bill credits to its customers. These bill credits were offset by a reduction in income tax expense and resulted in a minimal impact to Net income.

(b)

Primarily driven by favorable market pricing on contracts and off-system sales.

Operations and maintenance expense increased due to $10.3 million of higher generation-related expenses primarily due to higher fuel and materials costs and increased royalties on higher mining revenues, $4.5 million of higher outside services expenses primarily driven by higher contractor and consultant rates, $3.4 million of increased property taxes due to an expiration of an abatement and a higher asset base driven by recent capital expenditures, $3.4 million of higher cloud computing licensing costs, and $1.1 million of increased bad debt expense primarily attributable to higher customer billings.

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

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Operating Statistics


	Revenue (in thousands)						Quantities Sold (MWh)
For the year ended December 31,	2022		2021		2020		2022		2021		2020

Residential	$	246,651	$	244,589	$	221,530		1,513,092		1,494,028		1,477,515
Commercial		277,981		275,998		239,166		2,087,800		2,075,690		1,974,043
Industrial		166,374		149,040		131,154		1,912,529		1,751,344		1,794,795
Municipal		20,497		19,092		16,860		159,248		162,903		158,222
Subtotal Retail Revenue - Electric		711,503		688,719		608,710		5,672,669		5,483,965		5,404,575
Contract Wholesale		25,869		16,128		17,847		654,016		574,137		492,637
Off-system/Power Marketing Wholesale		48,578		41,682		15,511		643,189		638,923		437,288
Other (a)		66,191		54,218		57,644		—		—		—
Total Regulated		852,141		800,747		699,712		6,969,874		6,697,025		6,334,500
Non-Regulated (b)		48,021		41,511		39,145		293,026		269,558		258,399
Total Revenue and Quantities Sold		900,162		842,258		738,857		7,262,900		6,966,583		6,592,899
Other Uses, Losses or Generation, net (c)								450,010		475,280		406,422
Total Energy								7,712,910		7,441,863		6,999,321

(a)

Primarily related to transmission revenues from the Common Use System.

(b)

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

(c)

Includes company uses and line losses.


	Electric Revenue (in thousands)						Quantities Sold (MWh)
For the year ended December 31,	2022		2021		2020		2022		2021		2020
Colorado Electric	$	321,113	$	302,896	$	252,094		2,439,954		2,574,016		2,243,034
South Dakota Electric		335,211		319,362		280,431		2,626,175		2,389,407		2,363,776
Wyoming Electric		197,673		180,413		169,179		1,903,745		1,733,602		1,727,690
Integrated Generation		46,166		39,587		37,153		293,026		269,558		258,399
Total Revenue and Quantities Sold	$	900,162	$	842,258	$	738,857		7,262,900		6,966,583		6,592,899


	For the year ended December 31,
Quantities Generated and Purchased by Fuel Type (MWh)	2022		2021		2020
Generated:
Coal		2,708,804		2,546,926		2,817,846
Natural Gas and Oil		1,454,164		1,817,133		1,753,568
Wind		875,843		842,616		614,236
Total Generated		5,038,811		5,206,675		5,185,650
Purchased:
Coal, Natural Gas, Oil and Other Market Purchases		2,280,776		1,866,382		1,478,536
Wind		393,323		368,806		335,135
Total Purchased		2,674,099		2,235,188		1,813,671
Total Generated and Purchased		7,712,910		7,441,863		6,999,321

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	For the year ended December 31,
Quantities Generated and Purchased (MWh)	2022		2021		2020
Generated:
Colorado Electric		474,401		412,127		265,552
South Dakota Electric		1,889,981		1,980,660		1,901,009
Wyoming Electric		905,796		883,596		851,522
Integrated Generation		1,768,633		1,842,377		2,085,042
Total Generated		5,038,811		5,118,760		5,103,125
Purchased:
Colorado Electric		1,005,446		1,027,728		714,139
South Dakota Electric		826,392		563,603		489,457
Wyoming Electric		757,191		643,857		610,075
Integrated Generation		85,070		87,915		82,525
Total Purchased		2,674,099		2,323,103		1,896,196

Total Generated and Purchased		7,712,910		7,441,863		6,999,321


	For the year ended December 31,
Degree Days	2022			2021			2020
	Actual		Variance from Normal	Actual		Variance from Normal	Actual		Variance from Normal
Heating Degree Days:
Colorado Electric		5,551	9%		5,023	(11)%		5,103	(9)%
South Dakota Electric		7,495	6%		6,819	(5)%		6,910	(3)%
Wyoming Electric		7,051	3%		6,702	(6)%		6,771	(5)%
Combined (a)		6,518	6%		5,974	(7)%		6,056	(6)%

Cooling Degree Days:
Colorado Electric		1,362	9%		1,245	39%		1,384	54%
South Dakota Electric		814	27%		827	30%		682	7%
Wyoming Electric		701	47%		604	74%		594	71%
Combined (a)		1,040	18%		973	40%		985	41%

(a)

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


	For the year ended December 31,
Contracted generating facilities availability by fuel type (a)	2022			2021			2020
Coal (b)		91.5	%		86.7	%		94.3	%
Natural gas and diesel oil		96.1	%		95.5	%		84.6	%
Wind		93.7	%		95.8	%		95.1	%
Total availability		94.4	%		93.2	%		89.2	%

Wind Capacity Factor		34.7	%		34.0	%		31.8	%

(a)

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

(b)

2021 included planned outages at Neil Simpson II, Wygen II, and Wygen III and unplanned outages at Wygen I, Neil Simpson II and Wyodak Plant.

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Gas Utilities

Operating results for the years ended December 31 for the Gas Utilities were as follows (in thousands):


	2022		2021		2022 vs 2021 Variance		2020		2021 vs 2020 Variance
Revenue:
Natural gas - regulated	$	1,584,634	$	1,051,610	$	533,024	$	900,637	$	150,973
Other - non-regulated services		84,456		73,255		11,201		74,033		(778	)
Total revenue		1,669,089		1,124,865		544,224		974,670		150,195

Cost of natural gas sold:
Natural gas - regulated		942,148		480,293		461,855		347,611		132,682
Other - non-regulated services		22,960		14,445		8,515		7,034		7,411
Total cost of natural gas sold		965,108		494,738		470,370		354,645		140,093

Gas Utility margin (non-GAAP)		703,982		630,127		73,855		620,025		10,102

Operations and maintenance		345,143		314,810		30,333		303,577		11,233
Depreciation and amortization		114,679		104,160		10,519		100,559		3,601
Total operating expenses		459,822		418,970		40,852		404,136		14,834

Operating income	$	244,160	$	211,157	$	33,003	$	215,889	$	(4,732	)

2022 Compared to 2021

Gas Utility margin increased over the prior year as a result of:


	(in millions)
New rates and rider recovery	$	30.0
Weather		18.5
Carrying costs on Winter Storm Uri regulatory asset (a)		17.9
Prior year Black Hills Energy Services Winter Storm Uri costs (b)		8.2
Customer growth and increased usage per customer		3.7
Mark-to-market on non-utility natural gas commodity contracts		(3.3	)
Other		(1.1	)
	$	73.9

(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. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

(b)

Black Hills Energy Services offers fixed contract pricing for non-regulated gas supply services to our regulated natural gas customers. The increased cost of natural gas sold during Winter Storm Uri was not recoverable through a regulatory mechanism.

Operations and maintenance expense increased due to $11.6 million of higher outside services and materials expenses driven primarily by higher contractor and consultant fees, $5.0 million of increased bad debt expense primarily attributable to higher customer billings, $4.6 million of higher cloud computing licensing costs, $3.2 million of higher property taxes driven by a higher asset base on recent capital expenditures, $2.1 million of higher vehicle expense driven by higher fuel costs, $1.6 million of higher employee-related expenses and $1.2 million increased travel and training expenses.

Depreciation and amortization increased primarily due to a higher asset base driven by prior and current year capital expenditures.

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Operating Statistics


	Revenue (in thousands)						Quantities Sold and Transported (Dth)
	For the year ended December 31,						For the year ended December 31,
	2022		2021		2020		2022		2021		2020

Residential	$	940,201	$	613,475	$	527,518		66,915,630		60,080,805		61,962,171
Commercial		398,585		242,115		193,017		32,362,343		29,091,657		28,784,319
Industrial		63,035		33,368		24,014		7,667,231		6,260,235		6,881,354
Other		8,693		3,816		582		—		—		—
Total Distribution		1,410,514		892,774		745,131		106,945,204		95,432,697		97,627,844

Transportation and Transmission		174,120		158,836		155,506		160,917,802		154,570,280		149,062,476

Total Regulated		1,584,634		1,051,610		900,637		267,863,006		250,002,977		246,690,320

Non-regulated Services (a)		84,456		73,255		74,033		—		—		—

Total Revenue and Quantities Sold	$	1,669,089	$	1,124,865	$	974,670		267,863,006		250,002,977		246,690,320

(a)

Includes Black Hills Energy Services and non-regulated services under the Service Guard Comfort Plan, Tech Services and HomeServe.


	Revenue (in thousands)						Quantities Sold and Transported (Dth)
	For the year ended December 31,						For the year ended December 31,
	2022		2021		2020		2022		2021		2020

Arkansas Gas	$	311,239	$	218,497	$	184,849		32,282,324		31,478,303		28,572,621
Colorado Gas		320,890		208,019		186,085		34,343,485		32,247,042		32,077,083
Iowa Gas		283,938		171,673		137,982		40,883,742		38,022,801		36,824,548
Kansas Gas		191,392		121,603		101,118		38,630,944		34,475,799		33,732,897
Nebraska Gas		384,823		273,361		246,381		85,050,323		81,035,572		80,202,783
Wyoming Gas		176,807		131,712		118,255		36,672,188		32,743,460		35,280,388
Total Revenue and Quantities Sold	$	1,669,089	$	1,124,865	$	974,670		267,863,006		250,002,977		246,690,320


	For the year ended December 31,
	2022			2021			2020
Heating Degree Days	Actual		Variance From Normal	Actual		Variance From Normal	Actual		Variance From Normal
Arkansas Gas (a)		3,844	2%		3,565	(12)%		3,442	(15)%
Colorado Gas		6,325	4%		5,866	(11)%		6,068	(8)%
Iowa Gas		7,037	7%		6,239	(8)%		6,504	(4)%
Kansas Gas (a)		4,968	7%		4,508	(8)%		4,648	(5)%
Nebraska Gas		6,220	4%		5,599	(9)%		5,853	(5)%
Wyoming Gas		7,644	12%		7,074	(7)%		7,289	(4)%
Combined (b)		6,536	5%		5,948	(8)%		6,038	(6)%

(a)

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

(b)

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.

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Corporate and Other

Corporate and Other operating results for the years ended December 31 were as follows (in thousands):


(in thousands)	2022			2021			2022 vs 2021 Variance		2020		2021 vs 2020 Variance

Operating income (loss)	$	(3,174	)	$	(4,404	)	$	1,230	$	1,440	$	(5,844	)

2022 Compared to 2021

The variance in Operating income (loss) was primarily due to an allocation of a 2020 employee cost true-up in the first quarter of 2021, which was offset in our business segments.

Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)


(in thousands)	2022			2021			2022 vs 2021 Variance			2020			2021 vs 2020 Variance

Interest expense, net	$	(160,989	)	$	(152,404	)	$	(8,585	)	$	(143,470	)	$	(8,934	)
Impairment of investment		—			—			—			(6,859	)		6,859
Other income (expense), net		1,708			1,404			304			(2,293	)		3,697
Income tax (expense)		(25,205	)		(7,169	)		(18,036	)		(32,918	)		25,749

2022 Compared to 2021

Interest expense, net

The increase in Interest expense, net was due to higher interest rates on higher short-term debt balances. See Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

Other income (expense), net

Other income (expense), net was comparable to the prior year primarily due to lower costs for our non-qualified benefit plans which were driven by market performance mostly offset by a prior year recognition of death benefits from Company-owned life insurance and higher non-service pension costs primarily driven by a higher discount rate.

Income tax benefit (expense)

Income tax expense increased due to higher pre-tax income and a higher effective tax rate. For the year ended December 31, 2022, the effective tax rate was 8.5% compared to 2.8% in 2021. The higher effective tax rate was primarily due to $10 million of prior year tax benefits from Colorado Electric TCJA-related bill credits to customers (which were offset by reduced revenue) and $5.4 million decreased flow-through tax benefits driven by prior year repairs and gain deferral partially offset by $4.0 million of current year tax benefits from various state rate changes, and $1.8 million of increased tax benefits from federal PTCs driven by a current year PTC rate increase (inflation adjustment). See Note 15 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for additional details.

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Liquidity and Capital Resources

OVERVIEW

Our company requires significant cash to support and grow our businesses. Our primary sources of cash are generated from our operating activities, five-year 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.

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 financial position as of December 31 (dollars in thousands):


Financial Position Summary	2022			2021
Cash and cash equivalents	$	21,430		$	8,921
Restricted cash and equivalents	$	5,555		$	4,889
Notes payable	$	535,600		$	420,180
Current maturities of long-term debt	$	525,000		$	—
Long-term debt (a)	$	3,607,340		$	4,126,923
Stockholders’ equity	$	2,994,913		$	2,787,094

Ratios
Long-term debt ratio (b)		55	%		60	%
Total debt ratio (c)		61	%		62	%

(a)

Carrying value of long-term debt is net of deferred financing costs.

(b)

Long-term debt as a percentage of long-term debt and stockholders' equity combined.

(c)

Total debt (notes payable, current maturities of long-term debt and long-term debt) as a percentage of total debt and stockholders' equity combined.

CASH FLOW ACTIVITIES

The following tables summarize our cash flows for the years ended December 31 (in thousands):

Operating Activities:


	2022			2021			2022 vs. 2021			2020			2021 vs. 2020
Cash earnings (net income plus non-cash adjustments)	$	566,392		$	527,705		$	38,687		$	549,092			(21,387	)
Changes in certain operating assets and liabilities:
Accounts receivable and other current assets		(259,851	)		(78,877	)	$	(180,974	)		(8,088	)		(70,789	)
Accounts payable and accrued liabilities		89,405			10,660			78,745			24,659			(13,999	)
Regulatory assets and liabilities		203,869			(524,220	)		728,089			(15,753	)		(508,467	)
		33,423			(592,437	)		625,860			818			(593,255	)
Contributions to defined benefit pension plans		—			—			—			(12,700	)		12,700
Other operating activities		(15,014	)		167			(15,181	)		4,653			(4,486	)
Net cash provided by (used in) operating activities	$	584,801		$	(64,565	)	$	649,366		$	541,863		$	(606,428	)

2022 Compared to 2021

Cash earnings (income from continuing operations plus non-cash adjustments) were $39 million higher than prior year primarily due to increased Electric and Gas Utility margins due to new rates and rider revenues and prior year impacts from Winter Storm Uri.

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Net inflows from changes in certain operating assets and liabilities were $626 million higher than prior year, primarily attributable to:

•

Cash inflows increased by approximately $728 million primarily as a result of changes in our regulatory assets and liabilities primarily driven by prior year incremental fuel, purchased power and natural gas costs due to Winter Storm Uri and current year recovery of a portion of Winter Storm Uri incremental and carrying costs from customers;

•

Cash outflows increased by approximately $181 million primarily as a result of changes in accounts receivable and other current assets driven by increased revenue due to higher commodity prices and colder weather and increased purchases of natural gas in storage;

•

Cash inflows increased by approximately $79 million as a result of changes in accounts payable and other current liabilities driven by payment timing related to natural gas and power purchases and other working capital requirements;

Cash outflows increased $15.2 million from other operating activities primarily due to higher cloud computing licensing costs, increased payments on settled commodity derivatives and higher preliminary survey charges.

Investing Activities:


	2022			2021			2022 vs. 2021			2020			2021 vs. 2020
Capital expenditures	$	(604,365	)	$	(677,492	)	$	73,127		$	(767,404	)	$	89,912
Other investing activities		485			13,262			(12,777	)		5,740			7,522
Net cash provided by (used in) investing activities	$	(603,880	)	$	(664,230	)	$	60,350		$	(761,664	)	$	97,434

2022 Compared to 2021

Capital expenditures of approximately $604 million in 2022 compared to $677 million in 2021. Lower current year expenditures are driven by lower programmatic safety, reliability and integrity spending at our Gas and Electric Utilities; and

Cash inflows decreased $13 million for other investing activities which was primarily driven by prior year sales of transmission assets and facilities, none of which were individually material.

Financing Activities:


	2022			2021			2022 vs. 2021			2020			2021 vs. 2020
Dividends paid on common stock	$	(156,723	)	$	(145,023	)	$	(11,700	)	$	(135,439	)	$	(9,584	)
Common stock issued		90,044			118,979			(28,935	)		99,278			19,701
Short-term and long-term debt borrowings, net		115,420			777,704			(662,284	)		275,943			501,761
Distributions to non-controlling interests		(17,418	)		(15,749	)		(1,669	)		(15,839	)		90
Other financing activities		931			(4,045	)		4,976			(7,061	)		3,016
Net cash provided by (used in) financing activities	$	32,254		$	731,866		$	(699,612	)	$	216,882		$	514,984

2022 Compared to 2021

Net cash provided by financing activities decreased $700 million primarily due to prior year financing activities related to Winter Storm Uri.

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CAPITAL RESOURCES

Short-term Debt

Revolving Credit Facility and CP Program

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.

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 our other utilities 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, 2022. See additional information in Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Equity

Shelf Registration

We have a shelf registration statement on file with the SEC under which we may issue, from time to time, senior debt securities, subordinated debt securities, common stock, preferred stock, warrants and other securities. Although the 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. The shelf registration expires in August 2023. 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, 2022, we had approximately 66 million shares of common stock outstanding and no shares of preferred stock outstanding.

ATM

Our ATM allows us to sell shares of our common stock with an aggregate value of up to $400 million. The shares may be offered from time to time pursuant to a sales agreement dated August 4, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC.

For additional information regarding equity, see Note 8 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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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, the issuance of common stock under our ATM program or in an opportunistic block trade. In the first quarter of 2023, we plan to re-finance a portion of our short-term borrowings into long-term debt. We also plan to re-finance our $525 million, 4.25%, senior unsecured notes due November 30, 2023, at or before maturity date. Additionally, we plan to renew our ATM and shelf registration at or before shelf expiration in August 2023.

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, 2022:


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

(a)

On August 26, 2022, S&P reported BBB+ rating and maintained a Stable outlook.

(b)

On December 20, 2022, Moody's reported our Baa2 rating and maintained a Stable outlook.

(c)

On October 6, 2022, Fitch reported BBB+ rating and maintained a Stable 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, 2022:


Rating Agency		Senior Secured Rating
S&P (a)		A
Fitch (b)		A

(a)

On March 31, 2022, S&P reported A rating.

(b)

On October 6, 2022, Fitch reported A rating.

We do not have any trigger 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.

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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.

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 $35 million as of December 31, 2022, compared to $20 million as of December 31, 2021. The increase in the unfunded status of the Pension Plan was primarily driven by an increase in the discount rate. We do not have required contributions and we do not expect to make contributions to our Pension Plan in 2023. 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 25, 2023, our Board of Directors declared a quarterly dividend of $0.625 per share, equivalent to an annual dividend rate of $2.50 per share. The table below provides our dividends paid (in thousands), dividend payout ratio and dividends paid per share for the three years ended December 31:


	2022			2021			2020
Common Stock Dividends Paid	$	156,723		$	145,023		$	135,439
Dividend Payout Ratio		61	%		61	%		60	%
Dividends Per Share	$	2.41		$	2.29		$	2.17

Our three-year compound annualized dividend growth rate was 5.5%.

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, 2022, 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, 2022 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.

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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, 2022 and 2021, we had total regulatory assets of $653 million and $797 million, respectively, and total regulatory liabilities of $519 million and $503 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.

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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 7.0% and long-term growth rate projections of 1.75% were utilized in the goodwill impairment test performed as of October 1, 2022. 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.

At October 1, 2022, fair value exceeded the carrying value at all reporting units. However, the Gas Utilities reporting unit’s fair value exceeded its carrying value by less than 10% and could be at risk for impairment if adverse macroeconomic conditions persist or deteriorate. The decrease in the fair value cushion of the Gas Utilities reporting unit when compared to the prior year was primarily due to an increase in the weighted average cost of capital.

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, 2022, 2021, and 2020, there were no impairment losses recorded. At December 31, 2022, 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our activities in the regulated and non-regulated energy sectors 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.

A potential risk related to wholesale power sales is the price risk arising from the sale of power that exceeds our generating capacity. These potential short positions can 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.

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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, 2022 and 2021, 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, 2022, 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, 2022, 88% 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 $4.1 million and $2.7 million for the years ended December 31, 2022 and 2021, 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 Critical Accounting Estimates in Item 7 and 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 ongoing 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, 2022 was concentrated primarily among retail utility customers, investment grade companies, cooperative utilities and federal agencies.

See more information in Notes 1 and 9 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

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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, 2022, 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, 2022.

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, 2022. Deloitte & Touche LLP's report on Black Hills Corporation's internal control over financial reporting is included herein.

Black Hills Corporation

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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, 2022 and 2021, the related consolidated statements of income, comprehensive income, shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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, 2023, 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).

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Rates are regulated on a state-by-state basis by the relevant state regulatory commissions based on an analysis of the 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 a reasonable 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, procedural memorandums, 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 precedence 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 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, 2023

We have served as the Company's auditor since 2002.

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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, 2022, 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, 2022, 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, 2022, of the Company and our report dated February 14, 2023, expressed an unqualified opinion on those financial statements.

Basis for Opinion

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, 2023

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF INCOME


	December 31, 2022			December 31, 2021			December 31, 2020
	(in thousands, except per share amounts)

Revenue	$	2,551,816		$	1,949,102		$	1,696,941

Operating expenses:
Fuel, purchased power and cost of natural gas sold		1,230,550			741,934			492,404
Operations and maintenance		548,430			501,690			495,404
Depreciation, depletion and amortization		250,909			235,953			224,457
Taxes - property and production		66,683			60,096			56,373
Total operating expenses		2,096,572			1,539,673			1,268,638

Operating income		455,244			409,429			428,303

Other income (expense):
Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)		(162,584	)		(154,112	)		(144,931	)
Interest income		1,595			1,708			1,461
Impairment of investment		—			—			(6,859	)
Other income (expense), net		1,708			1,404			(2,293	)
Total other income (expense)		(159,281	)		(151,000	)		(152,622	)
Income before income taxes		295,963			258,429			275,681
Income tax expense		(25,205	)		(7,169	)		(32,918	)
Net income		270,758			251,260			242,763
Net income attributable to non-controlling interest		(12,371	)		(14,516	)		(15,155	)
Net income available for common stock	$	258,387		$	236,744		$	227,608

Earnings per share of common stock:
Earnings per share, Basic	$	3.98		$	3.74		$	3.65
Earnings per share, Diluted	$	3.97		$	3.74		$	3.65

Weighted average common shares outstanding:
Basic		64,858			63,219			62,378
Diluted		65,021			63,325			62,439

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

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


Year ended	December 31, 2022			December 31, 2021			December 31, 2020
	(in thousands)
Net income	$	270,758		$	251,260		$	242,763

Other comprehensive income (loss), net of tax:
Benefit plan liability adjustments - net gain (loss) (net of tax of $(1,505), $(664) and $191, respectively)		4,604			1,959			(1,062	)
Reclassification adjustment of benefit plan liability - net loss (net of tax of $(226), $(665) and $(958), respectively)		525			1,726			1,429
Reclassification adjustment of benefit plan liability - prior service cost (net of tax of $28, $27 and $23, respectively)		(65	)		(71	)		(80	)
Derivative instruments designated as cash flow hedges:
Reclassification of net realized (gains) losses on settled/amortized interest rate swaps (net of tax of $(721), $(677) and $(287), respectively)		2,129			2,174			2,564
Net unrealized gains (losses) on commodity derivatives (net of tax of $193, $(980) and $14, respectively)		(631	)		3,023			(47	)
Reclassification of net realized (gains) losses on settled commodity derivatives (net of tax of $663, $502 and $(96), respectively)		(2,045	)		(1,549	)		505
Other comprehensive income (loss), net of tax		4,517			7,262			3,309

Comprehensive income		275,275			258,522			246,072
Less: comprehensive income attributable to non-controlling interest		(12,371	)		(14,516	)		(15,155	)
Comprehensive income available for common stock	$	262,904		$	244,006		$	230,917

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.

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS


	As of
	December 31, 2022			December 31, 2021
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	21,430		$	8,921
Restricted cash and equivalents		5,555			4,889
Accounts receivable, net		508,192			321,652
Materials, supplies and fuel		207,421			150,979
Derivative assets, current		582			4,373
Income tax receivable, net		17,637			18,017
Regulatory assets, current		260,312			270,290
Other current assets		50,579			29,012
Total current assets		1,071,708			808,133

Property, plant and equipment		8,374,790			7,856,573
Less accumulated depreciation and depletion		(1,576,842	)		(1,407,397	)
Total property, plant and equipment, net		6,797,948			6,449,176

Other assets:
Goodwill		1,299,454			1,299,454
Intangible assets, net		9,589			10,770
Regulatory assets, non-current		392,669			526,309
Other assets, non-current		46,862			38,054
Total other assets, non-current		1,748,574			1,874,587
TOTAL ASSETS	$	9,618,230		$	9,131,896

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

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BLACK HILLS CORPORATION

CONSOLIDATED BALANCE SHEETS

(Continued)


	As of
	December 31, 2022			December 31, 2021
	(in thousands, except share amounts)
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	310,020		$	217,761
Accrued liabilities		243,457			244,759
Derivative liabilities, current		6,600			1,439
Regulatory liabilities, current		46,013			17,574
Notes payable		535,600			420,180
Current maturities of long-term debt		525,000			—
Total current liabilities		1,666,690			901,713

Long-term debt, net of current maturities		3,607,340			4,126,923

Deferred credits and other liabilities:
Deferred income tax liabilities, net		508,941			465,388
Regulatory liabilities, non-current		472,560			485,377
Benefit plan liabilities		116,742			123,925
Other deferred credits and other liabilities		156,062			141,447
Total deferred credits and other liabilities		1,254,305			1,216,137

Commitments, contingencies and guarantees (Note 3)

Equity:
Stockholders’ equity -
Common stock $1.00 par value; 100,000,000 shares authorized; issued: 66,140,396 and 64,793,095, respectively		66,140			64,793
Additional paid-in capital		1,882,653			1,783,436
Retained earnings		1,064,122			962,458
Treasury stock at cost - 36,726 and 54,078, respectively		(2,435	)		(3,509	)
Accumulated other comprehensive income (loss)		(15,567	)		(20,084	)
Total stockholders’ equity		2,994,913			2,787,094
Non-controlling interest		94,982			100,029
Total equity		3,089,895			2,887,123
TOTAL LIABILITIES AND TOTAL EQUITY	$	9,618,230		$	9,131,896

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

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS


Year ended	December 31, 2022			December 31, 2021			December 31, 2020
	(in thousands)
Operating activities:
Net income	$	270,758		$	251,260		$	242,763
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization		250,909			235,953			224,457
Deferred financing cost amortization		9,843			6,968			7,883
Impairment of investment		—			—			6,859
Stock compensation		8,551			9,655			5,373
Deferred income taxes		25,592			7,261			38,091
Employee benefit plans		5,459			9,590			11,997
Other adjustments, net		(4,720	)		7,018			11,669
Change in certain operating assets and liabilities:
Materials, supplies and fuel		(75,403	)		(35,707	)		2,755
Accounts receivable and other current assets		(184,448	)		(43,170	)		(10,843	)
Accounts payable and other current liabilities		89,405			10,660			24,659
Regulatory assets		203,869			(514,687	)		(5,047	)
Regulatory liabilities		—			(9,533	)		(10,706	)
Contributions to defined benefit pension plans		—			—			(12,700	)
Other operating activities, net		(15,014	)		167			4,653
Net cash provided by (used in) operating activities		584,801			(64,565	)		541,863
Investing activities:
Property, plant and equipment additions		(604,365	)		(677,492	)		(767,404	)
Other investing activities		485			13,262			5,740
Net cash (used in) investing activities		(603,880	)		(664,230	)		(761,664	)
Financing activities:
Dividends paid on common stock		(156,723	)		(145,023	)		(135,439	)
Common stock issued		90,044			118,979			99,278
Term Loan - borrowings		—			800,000			—
Term Loan - repayments		—			(800,000	)		—
Net borrowings (payments) of Revolving Credit Facility and CP Program		115,420			186,140			(115,460	)
Long-term debt - issuance		—			600,000			400,000
Long-term debt - repayments		—			(8,436	)		(8,597	)
Distributions to non-controlling interests		(17,418	)		(15,749	)		(15,839	)
Other financing activities		931			(4,045	)		(7,061	)
Net cash provided by financing activities		32,254			731,866			216,882
Net change in cash, restricted cash and cash equivalents		13,175			3,071			(2,919	)
Cash, restricted cash and cash equivalents beginning of year		13,810			10,739			13,658
Cash, restricted cash and cash equivalents end of year	$	26,985		$	13,810		$	10,739
Supplemental cash flow information:
Cash (paid) refunded during the period:
Interest (net of amounts capitalized)	$	(152,546	)	$	(142,685	)	$	(136,549	)
Income taxes	$	771		$	1,521		$	2,172
Non-cash investing and financing activities:
Accrued property, plant and equipment purchases at December 31	$	59,347		$	68,758		$	72,215
Increase in capitalized assets associated with asset retirement obligations	$	14,032		$	2,109		$	4,774

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

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BLACK HILLS CORPORATION

CONSOLIDATED STATEMENTS OF EQUITY


	Common Stock				Treasury Stock
(in thousands except share amounts)	Shares		Value		Shares			Value			Additional Paid in Capital			Retained Earnings			AOCI			Non controlling Interest			Total
Balance at December 31, 2019		61,480,658	$	61,481	$	3,956		$	(267	)	$	1,552,788		$	778,776		$	(30,655	)	$	101,946		$	2,464,069
Net income		—		—		—			—			—			227,608			—			15,155			242,763
Other comprehensive income, net of tax		—		—		—			—			—			—			3,309			—			3,309
Dividends on common stock ($2.17 per share)		—		—		—			—			—			(135,439	)		—			—			(135,439	)
Share-based compensation		123,578		123		28,536			(1,852	)		6,923			—			—			—			5,194
Issuance of common stock		1,222,943		1,223		—			—			98,777			—			—			—			100,000
Issuance costs		—		—		—			—			(1,203	)		—			—			—			(1,203	)
Implementation of ASU 2016-13 Financial Instruments - Credit Losses		—		—		—			—			—			(207	)		—			—			(207	)
Distributions to non-controlling interest		—		—		—			—			—			—			—			(15,839	)		(15,839	)
Balance at December 31, 2020		62,827,179	$	62,827	$	32,492		$	(2,119	)	$	1,657,285		$	870,738		$	(27,346	)	$	101,262		$	2,662,647
Net income		—		—		—			—			—			236,744			—			14,516			251,260
Other comprehensive income, net of tax		—		—		—			—			—			—			7,262			—			7,262
Dividends on common stock ($2.29 per share)		—		—		—			—			—			(145,023	)		—			—			(145,023	)
Share-based compensation		153,719		154		21,586			(1,390	)		9,256			—			—			—			8,020
Issuance of common stock		1,812,197		1,812		—			—			118,112			—			—			—			119,924
Issuance costs		—		—		—			—			(1,217	)		—			—			—			(1,217	)
Other		—		—		—			—			—			(1	)		—			—			(1	)
Distributions to non-controlling interest		—		—		—			—			—			—			—			(15,749	)		(15,749	)
Balance at December 31, 2021		64,793,095	$	64,793		54,078		$	(3,509	)	$	1,783,436		$	962,458		$	(20,084	)	$	100,029		$	2,887,123
Net income		—		—		—			—			—			258,387			—			12,371			270,758
Other comprehensive income, net of tax		—		—		—			—			—			—			4,517			—			4,517
Dividends on common stock ($2.41 per share)		—		—		—			—			—			(156,723	)		—			—			(156,723	)
Share-based compensation		39,546		39		(17,352	)		1,074			10,481			—			—			—			11,594
Issuance of common stock		1,307,755		1,308		—			—			89,889			—			—			—			91,197
Issuance costs		—		—		—			—			(1,153	)		—			—			—			(1,153	)
Distributions to non-controlling interest		—		—		—			—			—			—			—			(17,418	)		(17,418	)
Balance at December 31, 2022		66,140,396	$	66,140		36,726		$	(2,435	)	$	1,882,653		$	1,064,122		$	(15,567	)	$	94,982		$	3,089,895

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

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BLACK HILLS CORPORATION

Notes to Consolidated Financial Statements

December 31, 2022, 2021 and 2020

(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.

COVID-19 Pandemic

In March 2020, the World Health Organization categorized COVID-19 as a pandemic and the President of the United States declared the outbreak a national emergency. The U.S. government has deemed electric and natural gas utilities to be critical infrastructure sectors that provide essential services during this emergency. As a provider of essential services, the Company has an obligation to provide services to our customers. The Company remains focused on protecting the health of our customers, employees and the communities in which we operate while assuring the continuity of our business operations.

The Company’s Consolidated Financial Statements reflect estimates and assumptions made by management that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the Consolidated Financial Statements and reported amounts of revenue and expenses during the reporting periods presented. The Company considered the impacts of COVID-19 on the assumptions and estimates used and determined that, for the years ended December 31, 2022, 2021 and 2020, there were no material adverse impacts on the Company’s results of operations.

Principles of Consolidation

The consolidated financial statements include the accounts of Black Hills Corporation and its wholly-owned and majority-owned and controlled subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. For additional information on intercompany revenues, see Note 16.

Our Consolidated Statements of Income include operating activity of acquired companies beginning with their acquisition date. We use the proportionate consolidation method to account for our ownership interest in any jointly-owned electric utility generation facility, wind farm or transmission tie. See Note 6 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 additional information in Note 12.

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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.

Revenue Recognition

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.

Significant Judgments and Estimates

Unbilled Revenue

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.

Additional information is included in Note 4.

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Accounts Receivable and Allowance for Credit Losses

Accounts receivable for our Electric and Gas Utilities business segments primarily consists of sales to residential, commercial, industrial, transportation and other customers, all of which do not bear interest. These accounts receivable are stated at billed and estimated unbilled amounts, net of allowance for credit losses. Accounts receivable for our power generation and mining businesses consists of amounts due from sales of electric energy and capacity and coal primarily to affiliates or regional utilities.

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.

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. 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.

Following is a summary of accounts receivable as of December 31 (in thousands):


	2022			2021
Billed Accounts Receivable	$	267,571		$	181,027
Unbilled Revenue		243,574			142,738
Less Allowance for Credit Losses		(2,953	)		(2,113	)
Accounts Receivable, net	$	508,192		$	321,652

Changes to allowance for credit losses for the years ended December 31, were as follows (in thousands):


	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
2022	$	2,113	$	9,110	$	3,529	$	(11,799	)	$	2,953
2021	$	7,003	$	2,444	$	3,560	$	(10,894	)	$	2,113
2020	$	2,444	$	8,927	$	4,728	$	(9,096	)	$	7,003

Materials, Supplies and Fuel

The following amounts by major classification are included in Materials, supplies and fuel on the accompanying Consolidated Balance Sheets as of December 31 (in thousands):


	2022		2021
Materials and supplies	$	99,734	$	86,400
Fuel		3,115		1,267
Natural gas in storage		104,572		63,312
Total materials, supplies and fuel	$	207,421	$	150,979

Materials and supplies represent parts and supplies for business segments. Fuel represents diesel oil and gas used by our Electric Utilities 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.

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Property, Plant and Equipment

Additions to property, plant and equipment are recorded at cost. 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 thousands) for the years ended December 31:


	Income Statement Location	2022		2021		2020
AFUDC Borrowed	Interest expense incurred net of amounts capitalized (including amortization of debt issuance costs, premiums and discounts)	$	5,638	$	4,068	$	5,617
AFUDC Equity	Other income (expense), net		644		593		318

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. We also classify our Cushion Gas as 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 assets result in gains or losses recognized as a component of operating income. Ordinary repairs and maintenance of property, except as allowed under rate regulations, are charged to operations as incurred.

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. 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.

See Note 5 for additional information.

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. Additional information is included in Note 7.

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.

The Company has determined that the reporting units for its goodwill impairment test are its operating segments, or components of an operating segment.

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Our goodwill impairment analysis includes an income approach and a market approach to estimate the fair value of our reporting units. This analysis requires the input of several critical assumptions, including future growth rates, cash flow projections, operating cost escalation rates, rates of return, a risk-adjusted discount rate, timing and level of success in regulatory rate proceedings, the cost of debt and equity capital, long-term earnings and merger multiples for comparable companies.

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. As of December 31, 2022 and 2021, Goodwill balances were as follows (in thousands):


	Electric Utilities		Gas Utilities		Total
Goodwill	$	257,244	$	1,042,210	$	1,299,454

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 3 years to 37 years. Changes to intangible assets for the years ended December 31, were as follows (in thousands):


	2022			2021			2020
Intangible assets, net, beginning balance	$	10,770		$	11,944		$	13,266
Amortization expense (a)		(1,181	)		(1,174	)		(1,322	)
Intangible assets, net, ending balance	$	9,589		$	10,770		$	11,944

(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 thousands):


	2022		2021
Accrued employee compensation, benefits and withholdings	$	62,890	$	74,387
Accrued property taxes		52,430		50,874
Customer deposits and prepayments		47,655		48,814
Accrued interest		33,798		33,680
Other (none of which is individually significant)		46,684		37,004
Total accrued liabilities	$	243,457	$	244,759

Fair Value Measurements

Financial Instruments

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.

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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 CVA 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.

Additional information on fair value measurements is included in Notes 10 and 13.

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.

See additional information in Notes 9, 10 and 11.

Deferred Financing Costs

Deferred financing costs include loan origination fees, underwriter fees, legal fees and other costs directly attributable to the issuance of debt. Deferred financing costs are amortized over the estimated useful life of the related debt. These costs are presented on the balance sheet as an adjustment to the related debt liabilities. See additional information in Note 8.

Regulatory Accounting

Our regulated Electric Utilities and Gas Utilities are subject to cost-of-service regulation and earnings oversight from federal and state regulatory commissions. Our Electric and Gas 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.

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•

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.

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 further information.

Income Taxes

The Company and its subsidiaries file consolidated federal income tax returns. Each entity 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 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 thousands):


	2022		2021		2020
Net income available for common stock	$	258,387	$	236,744	$	227,608
Weighted average shares - basic		64,858		63,219		62,378
Dilutive effect of:
Equity compensation		163		106		61
Weighted average shares - diluted		65,021		63,325		62,439
Net income available for common stock, per share - Diluted	$	3.97	$	3.74	$	3.65

The following securities were excluded from the diluted earnings per share computation for the years ended December 31 because of their anti-dilutive nature (in thousands):


	2022		2021		2020
Equity compensation		-		13		60
Anti-dilutive shares excluded from computation of earnings per share		-		13		60

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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 detail on non-controlling interests.

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 additional information in Note 14.

Recently Issued Accounting Standards

Facilitation of the Effects of Reference Rate Reform on Financial Reporting, ASU 2020-04

In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which was subsequently amended by ASU 2021-01 and ASU 2022-06. The standard provides relief for companies preparing for discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform if certain criteria are met. The amendments in this update are elective and are effective upon the ASU issuance through December 31, 2024. We are currently evaluating if we will apply the optional guidance as we assess the impact of the discontinuance of LIBOR on our current arrangements. We do not expect the ASU to have a material impact on our financial position, results of operations and cash flows.

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(2)

REGULATORY MATTERS

We had the following regulatory assets and liabilities as of December 31 (in thousands):


	2022			2021
Regulatory assets
Winter Storm Uri (a)	$	347,980		$	509,025
Deferred energy and fuel cost adjustments (b)		72,580			59,973
Deferred gas cost adjustments (b)		12,147			9,488
Gas price derivatives (b)		8,793			2,584
Deferred taxes on AFUDC (b)		7,333			7,457
Employee benefit plans and related deferred taxes (c)		89,259			88,923
Environmental (b)		1,343			1,385
Loss on reacquired debt (b)		19,213			21,011
Deferred taxes on flow-through accounting (b)		69,529			63,243
Decommissioning costs (b)		3,472			5,961
Other regulatory assets (b)		21,332			27,549
Total regulatory assets		652,981			796,599
Less current regulatory assets		(260,312	)		(270,290	)
Regulatory assets, non-current	$	392,669		$	526,309

Regulatory liabilities
Deferred energy and gas costs (b)	$	24,030		$	6,113
Employee benefit plan costs and related deferred taxes (c)		34,258			32,241
Cost of removal (b)		175,614			179,976
Excess deferred income taxes (c)		254,833			264,042
Other regulatory liabilities (c)		29,838			20,579
Total regulatory liabilities		518,573			502,951
Less current regulatory liabilities		(46,013	)		(17,574	)
Regulatory liabilities, non-current	$	472,560		$	485,377

(a)

Timing of Winter Storm Uri incremental cost recovery and associated carrying costs vary by jurisdiction. See further information below.

(b)

Recovery of costs, but we are not allowed a rate of return.

(c)

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 - See discussion below for Winter Storm Uri regulatory asset information.

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, 2022 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.

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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 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 Plan Costs 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 an excess deferred income tax to be refunded to customers primarily using the normalization principles as prescribed in the TCJA. See Note 15 for additional information.

Recent Regulatory Activity

Winter Storm Uri

In February 2021, Winter Storm Uri caused a substantial increase in heating and energy demand and contributed to unforeseeable and unprecedented market prices for natural gas and electricity. As a result, we incurred significant incremental fuel, purchased power and natural gas costs.

Our Utilities submitted Winter Storm Uri cost recovery applications in our state jurisdictions seeking to recover $546 million of these incremental costs through separate tracking mechanisms over a weighted-average recovery period of 3.5 years. In these applications, we sought approval to recover carrying costs. We have received final commission approval for all of our Winter Storm Uri cost recovery applications, which will allow our Utilities to recover incremental fuel, purchased power and natural gas costs.

For the years ended December 31, 2022 and 2021, our Utilities collected $174 million and $40 million, respectively, of Winter Storm Uri incremental costs and carrying costs from customers. As of December 31, 2022, we estimate that our remaining Winter Storm Uri regulatory asset has a weighted-average recovery period of 2.6 years.

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For years ended December 31, 2022 and 2021, $22 million and $4.1 million, respectively, of carrying costs were accrued and recorded to a regulatory asset. The carrying costs accrued during the year ended December 31, 2022 included a one-time, $10 million true-up recorded in the second quarter to reflect commission authorized rates.

TCJA

On December 30, 2020, an administrative law judge approved a settlement of Colorado Electric’s plan to provide $9.3 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in February 2021.

On January 26, 2021, the NPSC approved Nebraska Gas’s plan to provide $2.9 million of TCJA-related bill credits to its customers. The bill credits, which represent a disposition of excess deferred income tax benefits resulting from the TCJA, were delivered to customers in June 2021.

As part of Kansas Gas’ 2021 rate review settlement agreement, Kansas Gas will deliver $9.1 million, or approximately $3.0 million of TCJA and state tax reform benefits to customers annually, for three years starting in 2022. For the year ended December 31, 2022, Kansas Gas delivered TCJA and state tax reform benefits to customers of $2.9 million.

These Colorado Electric, Kansas Gas and Nebraska Gas tax benefits delivered to customers, 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 years ended December 31, 2022 and 2021.

Arkansas Gas

On December 10, 2021, Arkansas Gas filed a rate review with the APSC seeking recovery of significant infrastructure investments in its 7,200-mile natural gas pipeline system. On October 10, 2022, the APSC approved a partial settlement agreement with all intervening parties for a general rate increase and authorized a capital structure of 45% equity and 55% debt and a return on equity of 9.6%. The APSC’s decision shifts approximately $10 million of rider revenue to base rates and is expected to generate $8.8 million of new annual revenue. The APSC also approved a new comprehensive safety and integrity rider which replaces three former riders. New rates were effective on October 21, 2022.

Wyoming Electric

On June 1, 2022, Wyoming Electric filed a rate review with the WPSC seeking recovery of significant infrastructure investments in its 1330-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 will be effective on March 1, 2023. The agreement also includes approval of a new rider that will be filed annually to recover transmission investment and expenses.

Colorado Gas

RMNG Rate Review

On October 7, 2022, RMNG filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 600-mile natural gas pipeline system. The rate review requests $12.3 million in new annual revenue based on a future test year with a capital structure of 52% equity and 48% debt and a return on equity of 12.3%. The rate review also requests a $7.7 million shift of SSIR revenues to base rates. The request seeks to finalize rates in the third quarter of 2023.

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Colorado Gas Rate Reviews and SSIR

On June 1, 2021, Colorado Gas filed a rate review with the CPUC seeking recovery of significant infrastructure investments in its 7,000-mile natural gas pipeline system. In the fourth quarter of 2021, Colorado Gas reached a settlement agreement with the CPUC staff and various intervenors for a general rate increase, which was subsequently approved by an administrative law judge. New rates were effective January 1, 2022, and the settlement is expected to generate $6.5 million of new annual revenue. The new revenue is based on a return on equity of 9.2% and a capital structure of 50.3% equity and 49.7% debt.

On September 11, 2020, in accordance with the final Order from the rate review filed on February 1, 2019, Colorado Gas filed a SSIR proposal with the CPUC that would recover safety and integrity focused investments in its system for five years. On July 6, 2021, Colorado Gas received approval from the CPUC for its SSIR proposal to recover these investments for three years effective January 1, 2022. The return on SSIR investments will be the current weighted-average cost of long-term debt.

Iowa Gas

Rate Review

On June 1, 2021, Iowa Gas filed a rate review with the IUB seeking recovery of significant infrastructure investments in its 5,000-mile natural gas pipeline system. On December 28, 2021, the IUB approved a settlement agreement with all intervening parties for a general rate increase. The settlement shifted $2.2 million of rider revenue to base rates and is expected to generate $3.7 million in new annual revenue with a capital structure of 50% equity and 50% debt and a return on equity of 9.6%. Final rates were enacted on January 1, 2022 and replaced interim rates effective June 11, 2021.

Kansas Gas

Rate Review

On May 7, 2021, Kansas Gas filed a rate review and rider renewal with the KCC seeking recovery of significant infrastructure investments in its 4,600-mile natural gas pipeline system. On December 30, 2021, Kansas Gas received approval from the KCC on its Global Settlement agreement with KCC staff and various intervenors for a general rate increase and renewal of its safety and integrity rider. The settlement shifted $6.6 million of rider revenue to base rates, effective January 1, 2022, and also allowed rider renewal for at least five more years.

South Dakota Electric

FERC Formula Rate

The annual rate determination process is governed by the FERC formula rate protocols established in the filed FERC joint-access transmission tariff. Effective January 1, 2022, the annual revenue requirement for the FERC Transmission Formula Rate was $30 million and included estimated weighted average capital additions of $30 million for 2021 and 2022 combined.

Black Hills Wyoming and Wyoming Electric

Wygen I FERC Filing

On October 15, 2020, the FERC approved a settlement agreement that represents a resolution of all issues in the joint application filed by Wyoming Electric and Black Hills Wyoming on August 2, 2019 for approval of a new 60 MW PPA. Under the terms of the settlement, Wyoming Electric will continue to receive 60 MW of capacity and energy from the Wygen I power plant. The new agreement commenced on January 1, 2022, replaced the existing PPA and will expire after 11 years.

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(3)

COMMITMENTS, CONTINGENCIES AND GUARANTEES

Unconditional Purchase Obligations

We have various PPAs and transmission service agreements, which extend to 2030, 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 thousands):



	PPAs (a)		Transmission Services Agreements		Natural gas supply, transportation and storage agreements (b)
Future commitments for the year ending December 31,
2023	$	11,175	$	12,320	$	130,031
2024		2,738		-		98,881
2025		-		-		72,662
2026		-		-		45,102
2027		-		-		14,862
Thereafter		-		-		56,595
Total future commitments	$	13,913	$	12,320	$	418,133

___________________________

(a) This schedule does not reflect renewable energy PPA future obligations since these agreements vary based on weather conditions.

(b) Our Gas Utilities have commitments to purchase physical quantities of natural gas under contracts indexed to various forward natural gas price curves. A portion of our gas purchases are purchased under evergreen contracts and are therefore, for purposes of this disclosure, carried out for 60 days.

Lease Agreements

Lessee

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 33 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.

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 34 years. Lease revenue was not material for the years ended December 31, 2022, 2021 and 2020.

As of December 31, 2022, scheduled maturities of operating lease payments to be received in future years were as follows (in thousands):


	Operating Leases
2023	$	2,381
2024		2,125
2025		2,070
2026		1,881
2027		1,845
Thereafter		49,387
Total lease receivables	$	59,689

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Environmental Matters

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 of $4.1 million 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 Processing

In 2008, we acquired whole and partial liabilities for former manufactured gas processing 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 $1.3 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 $1.3 million regulatory asset for manufactured gas processing sites; see Note 2 for additional information.

As of December 31, 2022, we had $2.6 million accrued for remediation of Iowa’s manufactured gas processing site as the landowner. As of December 31, 2022, we had $0.6 million accrued for remediation of Nebraska’s manufactured gas processing site as the land owner. These 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.

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.

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.

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 believe we have meritorious defenses to the verdict and have appealed the verdict. At this time, we believe that the liability related to this matter, if any, is not reasonably estimable.

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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.

See Note 8 for additional information on our off-balance sheet Letters of Credit commitment.

We had the following guarantees in place as of (in thousands):


	Maximum Exposure at
Nature of Guarantee	December 31, 2022
Indemnification for reclamation/surety bonds	$	107,314
Guarantees supporting business transactions	$	484,968
	$	592,282

(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, 2022, 2021 and 2020. Sales tax and other similar taxes are excluded from revenues.


Year ended December 31, 2022	Electric Utilities		Gas Utilities		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	739,734	$	1,453,266	$	—		$	2,193,000
Transportation		—		173,275		(413	)		172,862
Wholesale		44,832		—		—			44,832
Market - off-system sales		48,578		829		—			49,407
Transmission/Other		61,470		37,879		(16,594	)		82,755
Revenue from contracts with customers		894,614		1,665,249		(17,007	)		2,542,856
Other revenues		5,548		3,841		(429	)		8,960
Total revenues	$	900,162	$	1,669,090	$	(17,436	)	$	2,551,816

Timing of revenue recognition:
Services transferred at a point in time	$	30,454	$	—	$	—		$	30,454
Services transferred over time		864,160		1,665,249		(17,007	)		2,512,402
Revenue from contracts with customers	$	894,614	$	1,665,249	$	(17,007	)	$	2,542,856


Year ended December 31, 2021	Electric Utilities		Gas Utilities		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	711,448	$	913,725	$	—		$	1,625,173
Transportation		—		158,053		(428	)		157,625
Wholesale		30,848		—		—			30,848
Market - off-system sales		41,682		396		—			42,078
Transmission/Other		52,945		39,365		(17,200	)		75,110
Revenue from contracts with customers		836,923		1,111,539		(17,628	)		1,930,834
Other revenues		5,335		13,326		(393	)		18,268
Total revenues	$	842,258	$	1,124,865	$	(18,021	)	$	1,949,102

Timing of revenue recognition:
Services transferred at a point in time	$	27,141	$	—	$	—		$	27,141
Services transferred over time		809,782		1,111,539		(17,628	)		1,903,693
Revenue from contracts with customers	$	836,923	$	1,111,539	$	(17,628	)	$	1,930,834

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Year ended December 31, 2020	Electric Utilities		Gas Utilities		Inter-company Revenues			Total
Customer types:	(in thousands)
Retail	$	636,902	$	765,922	$	—		$	1,402,824
Transportation		—		154,581		(526	)		154,055
Wholesale		24,845		—		—			24,845
Market - off-system sales		15,512		260		—			15,772
Transmission/Other		55,422		43,658		(15,772	)		83,308
Revenue from contracts with customers		732,681		964,421		(16,298	)		1,680,804
Other revenues		6,176		10,249		(288	)		16,137
Total revenues	$	738,857	$	974,670	$	(16,586	)	$	1,696,941

Timing of revenue recognition:
Services transferred at a point in time	$	27,089	$	—	$	—		$	27,089
Services transferred over time		705,592		964,421		(16,298	)		1,653,715
Revenue from contracts with customers	$	732,681	$	964,421	$	(16,298	)	$	1,680,804

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(5)

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment at December 31 consisted of the following (dollars in thousands):


	2022				2021				Lives (in years)
Electric Utilities	Property, Plant and Equipment			Weighted Average Useful Life (in years)	Property, Plant and Equipment			Weighted Average Useful Life (in years)	Minimum	Maximum
Electric plant:
Production	$	1,482,081		41	$	1,452,055		41	32	46
Electric transmission		632,872		48		546,126		49	40	51
Electric distribution		1,082,535		47		1,000,619		47	45	50
Integrated Generation		713,519		31		720,490		30	19	38
Plant acquisition adjustment (a)		4,870		32		4,870		32	32	32
General		274,857		27		266,935		28	24	31
Total electric plant in service		4,190,734				3,991,095
Construction work in progress		152,953				181,451
Total electric plant		4,343,687				4,172,546
Less accumulated depreciation and depletion		(1,104,056	)			(1,016,738	)
Electric plant net of accumulated depreciation and depletion	$	3,239,631			$	3,155,808

____________________

(a) The plant acquisition adjustment is included in rate base and is being recovered with 8 years remaining.


	2022				2021				Lives (in years)
Gas Utilities	Property, Plant and Equipment			Weighted Average Useful Life (in years)	Property, Plant and Equipment			Weighted Average Useful Life (in years)	Minimum	Maximum
Gas plant:
Production	$	17,843		45	$	14,841		40	24	47
Gas transmission		695,345		58		645,550		58	32	72
Gas distribution		2,620,174		57		2,394,352		53	48	60
Cushion gas - depreciable (a)		—		N/A		3,539		28	N/A	N/A
Cushion gas - not depreciable (a)		63,137		N/A		42,478		N/A	N/A	N/A
Storage		65,781		41		56,289		38	36	48
General		497,407		23		474,964		21	3	25
Total gas plant in service		3,959,687				3,632,013
Construction work in progress		52,041				37,860
Total gas plant		4,011,728				3,669,873
Less accumulated depreciation		(471,013	)			(389,115	)
Gas plant net of accumulated depreciation	$	3,540,715			$	3,280,758

____________________

(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.


	2022				2021				Lives (in years)
Corporate	Property, Plant and Equipment			Weighted Average Useful Life (in years)	Property, Plant and Equipment			Weighted Average Useful Life (in years)	Minimum	Maximum
Total plant in service	$	5,685		11	$	5,694		10	4	24
Construction work in progress		13,690				8,460
Total gross property, plant and equipment		19,375				14,154
Less accumulated depreciation		(1,773	)			(1,544	)
Total net of accumulated depreciation	$	17,602			$	12,610

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(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, 2022, our interests in jointly-owned generating facilities and transmission systems were (in thousands):


	Ownership Interest			Plant in Service		Construction Work in Progress		Less Accumulated Depreciation			Plant Net of Accumulated Depreciation
Wyodak Plant (a)		20	%	$	121,769	$	93	$	(70,884	)	$	50,978
Transmission Tie		35	%	$	24,482	$	300	$	(7,375	)	$	17,407
Wygen III (b)		52	%	$	143,818	$	1,051	$	(29,634	)	$	115,235
Wygen I (c)		76.5	%	$	114,811	$	1,579	$	(56,553	)	$	59,837

(a)

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. This coal supply agreement is collateralized by a mortgage on and a security interest in some of WRDC’s coal reserves.

(b)

South Dakota Electric retains responsibility for plant operations. Our mine supplies fuel to Wygen III for the life of the plant.

(c)

Black Hills Wyoming retains responsibility for plant operations. Our mine supplies fuel to Wygen I for the life of the plant.

(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 thousands):


	December 31, 2021		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates			December 31, 2022
Electric Utilities	$	30,089	$	—	$	(3,003	)	$	1,353	$	(856	)	$	27,583
Gas Utilities (a)		45,455		—		(158	)		2,016		14,032			61,345
Total	$	75,544	$	—	$	(3,161	)	$	3,369	$	13,176		$	88,928


	December 31, 2020		Liabilities Incurred		Liabilities Settled			Accretion		Revisions to Prior Estimates		December 31, 2021
Electric Utilities	$	29,157	$	—	$	(978	)	$	1,315	$	595	$	30,089
Gas Utilities (a)		42,274		—		(66	)		1,733		1,514		45,455
Total	$	71,431	$	—	$	(1,044	)	$	3,048	$	2,109	$	75,544

(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.

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(8)

FINANCING

Short-term debt

Revolving Credit Facility and CP Program

On July 19, 2021, we amended and restated our corporate Revolving Credit Facility, maintaining total commitments of $750 million and extending the term through July 19, 2026 with two one year extension options (subject to consent from lenders). This Revolving Credit Facility is similar to the former revolving credit facility, which 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 Eurodollar 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, Eurodollar borrowings and letters of credit were 0.125%, 1.125% and 1.125%, respectively, at December 31, 2022. Based on our credit ratings, a 0.175% commitment fee was charged on the unused amount at December 31, 2022.

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 thousands):


	2022			2021
Amount outstanding	$	535,600		$	420,180
Letters of credit (a)		24,626			27,209
Available capacity		189,774			302,611
Weighted average interest rates		4.88	%		0.30	%

(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 thousands):


	2022			2021
Maximum amount outstanding (based on daily outstanding balances)	$	572,300		$	440,000
Average amount outstanding (based on daily outstanding balances)		390,653			258,392
Weighted average interest rates		2.11	%		0.22	%

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.

Term Loan

On February 24, 2021, we entered into a nine-month, $800 million unsecured term loan to provide additional liquidity and to meet our cash needs related to the incremental fuel, purchased power and natural gas costs from Winter Storm Uri. The term loan carried no prepayment penalty and was subject to the same covenant requirements as our Revolving Credit Facility. We repaid $200 million of this term loan in the first quarter of 2021. Proceeds from the August 26, 2021 public debt offering (discussed below) were used to repay the remaining balance on this term loan.

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Long-term debt

Long-term debt outstanding was as follows (dollars in thousands):


		Interest Rate at	Balance Outstanding
	Due Date	December 31, 2022	December 31, 2022			December 31, 2021
Corporate
Senior unsecured notes due 2023	November 30, 2023	4.25%	$	525,000		$	525,000
Senior unsecured notes due 2024	August 23, 2024	1.04%		600,000			600,000
Senior unsecured notes due 2026	January 15, 2026	3.95%		300,000			300,000
Senior unsecured notes due 2027	January 15, 2027	3.15%		400,000			400,000
Senior unsecured notes, due 2029	October 15, 2029	3.05%		400,000			400,000
Senior unsecured notes, due 2030	June 15, 2030	2.50%		400,000			400,000
Senior unsecured notes due 2033	May 1, 2033	4.35%		400,000			400,000
Senior unsecured notes, due 2046	September 15, 2046	4.20%		300,000			300,000
Senior unsecured notes, due 2049	October 15, 2049	3.88%		300,000			300,000
Total Corporate debt				3,625,000			3,625,000
Less unamortized debt discount				(5,259	)		(6,125	)
Total Corporate debt, net				3,619,741			3,618,875
South Dakota Electric
First Mortgage Bonds due 2032	August 15, 2032	7.23%		75,000			75,000
First Mortgage Bonds due 2039	November 1, 2039	6.13%		180,000			180,000
First Mortgage Bonds due 2044	October 20, 2044	4.43%		85,000			85,000
Total South Dakota Electric debt				340,000			340,000
Less unamortized debt discount				(69	)		(74	)
Total South Dakota Electric debt, net				339,931			339,926
Wyoming Electric
Industrial development revenue bonds due 2027(a) (b)	March 1, 2027	3.68%		10,000			10,000
First Mortgage Bonds due 2037	November 20, 2037	6.67%		110,000			110,000
First Mortgage Bonds due 2044	October 20, 2044	4.53%		75,000			75,000
Total Wyoming Electric debt				195,000			195,000
Less unamortized debt discount				—			—
Total Wyoming Electric debt, net				195,000			195,000
Total long-term debt				4,154,672			4,153,801
Less current maturities				(525,000	)		—
Less unamortized deferred financing costs (c)				(22,332	)		(26,878	)
Long-term debt, net of current maturities and deferred financing costs			$	3,607,340		$	4,126,923

(a)

Variable interest rate.

(b)

A reimbursement agreement is in place with Wells Fargo on behalf of Wyoming Electric for the 2009A bonds of $10 million 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.

(c)

Includes deferred financing costs associated with our Revolving Credit Facility of $1.8 million and $2.5 million as of December 31, 2022 and December 31, 2021, respectively.

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Scheduled maturities of long-term debt and associated interest payments by year are shown below (in thousands):


	Payments Due by Period
	2023		2024		2025		2026		2027		Thereafter		Total
Principal payments on Long-term debt including current maturities (a)	$	525,000	$	600,000	$	—	$	300,000	$	410,000	$	2,325,000	$	4,160,000
Interest payments on Long-term debt (a)		148,125		125,813		119,591		113,666		101,134		994,804		1,603,133

(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, 2022.

We plan to re-finance our $525 million, 4.25%, senior unsecured notes due November 30, 2023, at or before maturity date. In the event we are unable to refinance these senior unsecured notes, we have sufficient alternative measures available to manage cash flows such that our current plans to manage liquidity would be sufficient to meet our obligations in the foreseeable future.

Our debt securities contain certain restrictive financial covenants, all of which the Company and its subsidiaries were in compliance with at December 31, 2022. 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 August 26, 2021, we completed a public debt offering which consisted of $600 million, 1.037% three-year senior unsecured notes due August 23, 2024. The notes include an optional redemption provision and may be redeemed, in whole or in part, without premium, on or after February 23, 2022. The proceeds from the offering, which were net of $3.7 million of deferred financing costs, were used to repay amounts outstanding under our term loan entered into on February 24, 2021.

On June 17, 2020, we completed a public debt offering which consisted of $400 million of 2.50% 10-year senior unsecured notes due June 15, 2030. The proceeds were used to repay short-term debt and for working capital and general corporate purposes.

Amortization of Deferred Financing Costs

Our deferred financing costs and associated amortization expense included in Interest expense on the accompanying Consolidated Statements of Income were as follows (in thousands):


Deferred Financing Costs Remaining at		Amortization Expense for the years ended December 31,
December 31, 2022		2022		2021		2020
$	22,332	$	4,549	$	3,769	$	3,272

Debt Covenants

Revolving Credit Facility

Under our Revolving Credit Facility, 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 any of these covenants would constitute an event of default that entitles the lenders to terminate their remaining commitments and accelerate all principal and interest outstanding.

We were in compliance with our covenants at December 31, 2022 as shown below:


	As of December 31, 2022			Covenant Requirement
Consolidated Indebtedness to Capitalization Ratio		60.9	%	Less than	65	%

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Wyoming Electric

Covenants within Wyoming Electric's financing agreements require Wyoming Electric to maintain a debt to capitalization ratio of no more than 0.60 to 1.00. As of December 31, 2022, we were in compliance with these financial covenants.

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, 2022, 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 $155 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

At-the-Market Equity Offering Program

On August 3, 2020, we filed a shelf registration and DRSPP with the SEC. In conjunction with these shelf filings, we renewed the ATM. The renewed ATM program, which allows us to sell shares of our common stock, is the same as the prior program other than the aggregate value increased from $300 million to $400 million and a forward sales option was incorporated. This forward sales option allows us to sell our shares through the ATM program at the current trading price without actually issuing any shares to satisfy the sale until a future date. Under the ATM, shares may be offered from time to time pursuant to a sales agreement dated August 3, 2020. Shares of common stock are offered pursuant to our shelf registration statement filed with the SEC.

ATM activity for the years ended December 31 was as follows (net proceeds and issuance costs in millions):


	December 31, 2022		December 31, 2021		December 31, 2020
Number of shares issued		1,307,755		1,812,197		-
Average price per share	$	69.74	$	66.18	$	-
Proceeds, (net of issuance costs of $(0.9), $(1.1) and $0 respectively)	$	90.3	$	118.8	$	-

February 2020 Equity Issuance

On February 27, 2020, we issued 1.2 million shares of common stock to a single investor through an underwritten registered transaction at a price of $81.77 per share for proceeds of $99 million, net of $1.0 million of issuance costs. The shares of common stock were offered pursuant to our shelf registration statement filed with the SEC.

Shareholder Dividend Reinvestment and Stock Purchase Plan

We have a DRSPP under which shareholders may purchase additional shares of common stock through dividend reinvestment and/or optional cash payments at 100% of the recent average market price. We have the option of issuing new shares or purchasing the shares on the open market. We issued new shares until March 1, 2018, after which we began purchasing shares on the open market. At December 31, 2022, there were 74,198 shares of unissued stock available for future offering under the DRSPP.

Preferred Stock

Our articles of incorporation authorize the issuance of 25 million shares of preferred stock of which we had no shares of preferred stock outstanding as of December 31, 2022 and 2021.

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RISK MANAGEMENT AND DERIVATIVES

Market and Credit Risk Disclosures

Our activities in the energy industry expose us to a number of risks in the normal operations of our businesses. Depending on the activity, we are exposed to varying degrees of market risk and credit risk. To manage and mitigate these identified risks, we have adopted the Black Hills Corporation Risk Policies and Procedures. Valuation methodologies for our derivatives are detailed within Note 1.

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

•

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.

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.

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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 2023 through December 2024. 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:


		December 31, 2022				December 31, 2021
	Units	Notional Amounts		Maximum Term (months) (a)		Notional Amounts		Maximum Term (months) (a)
Natural gas futures purchased	MMBtus		630,000		3		590,000		3
Natural gas options purchased, net	MMBtus		1,790,000		3		3,100,000		3
Natural gas basis swaps purchased	MMBtus		900,000		3		870,000		3
Natural gas over-the-counter swaps, net (b)	MMBtus		4,460,000		24		4,570,000		34
Natural gas physical commitments, net (c)	MMBtus		17,864,412		12		16,416,677		24

(a)

Term reflects the maximum forward period hedged.

(b)

As of December 31, 2022, 1,646,200 MMBtus of natural gas over-the-counter swaps purchased were designated as cash flow hedges.

(c)

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, 2022, the Company posted $2.9 million related to such provisions, which is included in Other current assets on the Consolidated Balance Sheets.

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Derivatives by Balance Sheet Classification

As required by accounting standards for derivatives and hedges, fair values within the following tables are presented on a gross basis aside from the netting of asset and liability positions. Netting of positions is permitted in accordance with accounting standards for offsetting and under terms of our master netting agreements that allow us to settle positive and negative positions.

The following tables present the fair value and balance sheet classification of our derivative instruments as of December 31, (in thousands):


	Balance Sheet Location	2022			2021
Derivatives designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets - current	$	118		$	2,017
Noncurrent commodity derivatives	Other assets, non-current		198			18
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities - current		(1,703	)		—
Total derivatives designated as hedges		$	(1,387	)	$	2,035

Derivatives not designated as hedges:
Asset derivative instruments:
Current commodity derivatives	Derivative assets - current	$	464		$	2,356
Noncurrent commodity derivatives	Other assets, non-current		337			804
Liability derivative instruments:
Current commodity derivatives	Derivative liabilities - current		(4,897	)		(1,439	)
Noncurrent commodity derivatives	Other deferred credits and other liabilities		(18	)		(20	)
Total derivatives not designated as hedges		$	(4,114	)	$	1,701

Derivatives Designated as Hedge Instruments

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, 2022, 2021 and 2020. 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.


	2022			2021		2020			2022			2021			2020
Derivatives in Cash Flow Hedging Relationships	Amount of Gain/(Loss) Recognized in OCI							Income Statement Location	Amount of Gain/(Loss) Reclassified from AOCI into Income
	(in thousands)								(in thousands)
Interest rate swaps	$	2,850		$	2,851	$	2,851	Interest expense	$	(2,850	)	$	(2,851	)	$	(2,851	)
Commodity derivatives		(3,532	)		1,952		540	Fuel, purchased power and cost of natural gas sold		2,708			2,051			(601	)
Total	$	(682	)	$	4,803	$	3,391		$	(142	)	$	(800	)	$	(3,452	)

As of December 31, 2022, $4.5 million of net losses related to our interest rate swaps and commodity derivatives are expected to be reclassified from AOCI into earnings within the next 12 months. As market prices fluctuate, estimated and actual realized gains or losses will change during future periods.

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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, 2022, 2021 and 2020. 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.


		2022			2021			2020
Derivatives Not Designated as Hedging Instruments	Income Statement Location	Amount of Gain/(Loss) on Derivatives Recognized in Income
		(in thousands)
Commodity derivatives - Electric	Fuel, purchased power and cost of natural gas sold	$	—		$	(144	)	$	144
Commodity derivatives - Natural Gas	Fuel, purchased power and cost of natural gas sold		(797	)		2,599			1,640
		$	(797	)	$	2,455		$	1,784

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 $8.8 million and $2.6 million at December 31, 2022 and 2021, respectively. For our Electric Utilities, the unrealized gains and losses arising from these derivatives are recognized in the Consolidated Statements of Income.

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FAIR VALUE MEASUREMENTS

Recurring Fair Value Measurements

Derivatives

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, 2022
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)			Total
	(in thousands)
Assets:
Commodity derivatives - Gas Utilities	$	—		5,407	$	—		(4,290	)	$	1,117
Total	$	—	$	5,407	$	—	$	(4,290	)	$	1,117

Liabilities:
Commodity derivatives - Gas Utilities	$	—		11,455	$	—		(4,837	)	$	6,618
Total	$	—	$	11,455	$	—	$	(4,837	)	$	6,618

(a)

As of December 31, 2022, $4.3 million of our commodity derivative gross assets and $4.8 million of our commodity derivative gross liabilities, as well as related gross collateral amounts, were subject to master netting agreements.

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	As of December 31, 2021
	Level 1		Level 2		Level 3		Cash Collateral and Counterparty Netting (a)			Total
Assets:
Commodity derivatives - Gas Utilities	$	—		7,569	$	—	$	(2,374	)	$	5,195
Total	$	—	$	7,569	$	—	$	(2,374	)	$	5,195

Liabilities:
Commodity derivatives - Gas Utilities	$	—	$	3,273	$	—	$	(1,814	)	$	1,459
Total	$	—	$	3,273	$	—	$	(1,814	)	$	1,459

(a)

As of December 31, 2021, $2.4 million of our commodity derivative assets and $1.8 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.

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 thousands):


	2022				2021
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-term debt, including current maturities (a)	$	4,132,340	$	3,760,848	$	4,126,923	$	4,570,619

(a)

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

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OTHER COMPREHENSIVE INCOME

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

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


	Location on the Consolidated	Amount Reclassified from AOCI
	Statements of Income	December 31, 2022			December 31, 2021
Gains and (losses) on cash flow hedges:
Interest rate swaps	Interest expense	$	(2,850	)	$	(2,851	)
Commodity contracts	Fuel, purchased power and cost of natural gas sold		2,708			2,051
			(142	)		(800	)
Income tax	Income tax benefit (expense)		58			175
Total reclassification adjustments related to cash flow hedges, net of tax		$	(84	)	$	(625	)

Amortization of components of defined benefit plans:
Prior service cost	Operations and maintenance	$	93		$	98

Actuarial gain (loss)	Operations and maintenance		(751	)		(2,391	)
			(658	)		(2,293	)
Income tax	Income tax benefit (expense)		198			638
Total reclassification adjustments related to defined benefit plans, net of tax		$	(460	)	$	(1,655	)

Total reclassifications		$	(544	)	$	(2,280	)

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


	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2021	$	(10,384	)	$	1,476		$	(11,176	)	$	(20,084	)
Other comprehensive income (loss)
before reclassifications		—			(631	)		4,604			3,973
Amounts reclassified from AOCI		2,129			(2,045	)		460			544
As of December 31, 2022	$	(8,255	)	$	(1,200	)	$	(6,112	)	$	(15,567	)

	Derivatives Designated as Cash Flow Hedges
	Interest Rate Swaps			Commodity Derivatives			Employee Benefit Plans			Total
As of December 31, 2020	$	(12,558	)	$	2		$	(14,790	)	$	(27,346	)
Other comprehensive income (loss)
before reclassifications		—			3,023			1,959			4,982
Amounts reclassified from AOCI		2,174			(1,549	)		1,655			2,280
As of December 31, 2021	$	(10,384	)	$	1,476		$	(11,176	)	$	(20,084	)

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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.

The accounting for a partial sale of a subsidiary in which control is maintained and the subsidiary continues to be consolidated is specified under ASC 810, Consolidation. The partial sale is required to be recorded as an equity transaction with no resulting gain or loss on the sale. GAAP requires that non-controlling interests in subsidiaries and affiliates be reported in the equity section of a company’s balance sheet.

Net income available for common stock for the years ended December 31, 2022, 2021 and 2020 was reduced by $12 million, $15 million, and $15 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 thousands):


	2022		2021
Assets:
Current assets	$	12,761	$	13,220
Property, plant and equipment of variable interest entities, net	$	178,761	$	189,079

Liabilities:
Current liabilities	$	5,394	$	5,841

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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.

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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, 2022, 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	2022	2021
Equity	14%	15%
Real estate	7%	7%
Fixed income	2%	3%
Hedge funds	3%	3%
Total	26%	28%

Liability-hedging Assets	2022	2021
Fixed income	72%	71%
Cash	2%	1%
Total	74%	72%

Total Assets	100%	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 thousands):


	2022		2021
Defined Contribution Plan
Company retirement contributions	$	11,885	$	11,332
Company matching contributions	$	16,187	$	15,938


	2022		2021
Defined Benefit Plans
Defined Benefit Pension Plan	$	-	$	-
Non-Pension Defined Benefit Postretirement Healthcare Plan	$	6,131	$	6,432
Supplemental Non-Qualified Defined Benefit Plans	$	3,061	$	2,576

We do not have any required contributions to our Pension Plan in 2023 and do not intend to make any contributions.

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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 thousands):


Pension Plan	December 31, 2022
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV (a)		Total Investments
Common Collective Trust - Cash and Cash Equivalents	$	-	$	6,374	$	-	$	6,374	$	-	$	6,374
Common Collective Trust - Equity		-		45,087		-		45,087		-		45,087
Common Collective Trust - Fixed Income		-		242,025		-		242,025		-		242,025
Common Collective Trust - Real Estate		-		-		-		-		21,572		21,572
Hedge Funds		-		-		-		-		8,084		8,084
Total investments measured at fair value	$	-	$	293,486	$	-	$	293,486	$	29,656	$	323,142


Pension Plan	December 31, 2021
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		NAV (a)		Total Investments
Common Collective Trust - Cash and Cash Equivalents	$	-	$	6,009	$	-	$	6,009	$	-	$	6,009
Common Collective Trust - Equity		-		70,262		-		70,262		-		70,262
Common Collective Trust - Fixed Income		-		339,219		-		339,219		-		339,219
Common Collective Trust - Real Estate		-		-		-		-		30,407		30,407
Hedge Funds		-		-		-		-		12,490		12,490
Total investments measured at fair value	$	-	$	415,490	$	-	$	415,490	$	42,897	$	458,387

(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.


Non-pension Defined Benefit Postretirement Healthcare Plan	December 31, 2022
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		Total Investments
Cash and Cash Equivalents	$	7,752	$	-	$	-	$	7,752	$	7,752
Total investments measured at fair value	$	7,752	$	-	$	-	$	7,752	$	7,752


Non-pension Defined Benefit Postretirement Healthcare Plan	December 31, 2021
	Level 1		Level 2		Level 3		Total Investments Measured at Fair Value		Total Investments
Cash and Cash Equivalents	$	7,972	$	-	$	-	$	7,972	$	7,972
Total investments measured at fair value	$	7,972	$	-	$	-	$	7,972	$	7,972

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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.

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.

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 in the Consolidated Balance Sheets, accumulated benefit obligation, and reconciliation of components of the net periodic expense and elements of AOCI (in thousands):

Employee Benefit Plan Obligations


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31,	2022			2021			2022			2021			2022			2021
Change in benefit obligation:
Projected benefit obligation at beginning of year	$	478,262		$	514,008		$	55,260		$	55,054		$	63,484		$	70,238
Service cost (a)		3,927			5,038			(801	)		3,149			1,968			2,237
Interest cost		10,819			9,313			834			706			1,285			1,058
Actuarial (gain) loss		(97,960	)		(14,037	)		(7,007	)		(1,073	)		(12,300	)		(5,165	)
Amendments		-			(561	)		-			-			-			-
Benefits paid		(36,663	)		(35,499	)		(3,061	)		(2,576	)		(6,131	)		(6,432	)
Plan participants’ contributions		-			-			-			-			1,419			1,548
Projected benefit obligation at end of year	$	358,385		$	478,262		$	45,225		$	55,260		$	49,725		$	63,484

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Fair Value Employee Benefit Plan Assets


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans						Non-pension Defined Benefit Postretirement Healthcare Plan (a)
As of December 31,	2022			2021			2022			2021			2022			2021
Change in fair value of plan assets:
Beginning fair value of plan assets	$	458,387		$	473,721		$	-		$	-		$	7,972		$	8,165
Investment income (loss)		(98,585	)		20,165			-			-			4			(35	)
Employer contributions		-			-			3,061			2,576			4,488			4,726
Retiree contributions		-			-			-			-			1,419			1,548
Benefits paid		(36,661	)		(35,499	)		(3,061	)		(2,576	)		(6,131	)		(6,432	)
Ending fair value of plan assets	$	323,141		$	458,387		$	-		$	-		$	7,752		$	7,972

(a)

Assets of VEBA trusts.

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.

Amounts Recognized in the Consolidated Balance Sheets


	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31,	2022		2021		2022		2021		2022		2021
Regulatory assets	$	78,654	$	67,403	$	-	$	-	$	3,788	$	11,660
Current liabilities	$	-	$	-	$	2,231	$	2,156	$	4,427	$	4,584
Non-current assets	$	-	$	-	$	-	$	-	$	959	$	-
Non-current liabilities	$	35,243	$	19,872	$	42,994	$	53,104	$	38,505	$	50,949
Regulatory liabilities	$	2,804	$	3,830	$	-	$	-	$	6,198	$	2,447

Accumulated Benefit Obligation


	Defined Benefit Pension Plan				Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31,	2022		2021		2022		2021		2022		2021
Accumulated Benefit Obligation	$	350,187	$	466,505	$	45,225	$	55,260	$	49,725	$	63,484

Components of Net Periodic Expense


	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Plans							Non-pension Defined Benefit Postretirement Healthcare Plan
For the years ended December 31,	2022			2021			2020			2022			2021		2020		2022			2021			2020
Service cost	$	3,927		$	5,038		$	5,411		$	(801	)	$	3,149	$	1,579	$	1,968		$	2,237		$	2,056
Interest cost		10,819			9,313			13,426			834			706		1,099		1,285			1,058			1,649
Expected return on assets		(18,523	)		(20,876	)		(22,591	)		-			-		-		(125	)		(136	)		(182	)
Net amortization of prior service cost		(68	)		-			-			-			-		2		(289	)		(434	)		(546	)
Recognized net actuarial loss (gain)		6,092			7,315			8,372			276			1,754		1,702		64			466			20
Net periodic expense	$	2,247		$	790		$	4,618		$	309		$	5,609	$	4,382	$	2,903		$	3,191		$	2,997

Service costs are recorded in Operations and maintenance expense while nonservice costs were 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.

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AOCI Amounts (After-Tax)


	Defined Benefit Pension Plan						Supplemental Non-qualified Defined Benefit Plans				Non-pension Defined Benefit Postretirement Healthcare Plan
As of December 31,	2022			2021			2022		2021		2022			2021
Net (gain) loss	$	5,179		$	4,398		$	1,565	$	7,159	$	(667	)	$	(308	)
Prior service cost (gain)		(39	)		(46	)		-		-		74			(27	)
Total amounts included in AOCI, after-tax not yet recognized as components of net periodic expense	$	5,140		$	4,352		$	1,565	$	7,159	$	(593	)	$	(335	)

Assumptions


	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Plans									Non-pension Defined Benefit Postretirement Healthcare Plan
Weighted-average assumptions used to determine benefit obligations:	2022			2021			2020			2022			2021			2020			2022			2021			2020
Discount rate		5.17	%		2.88	%		2.56	%		5.13	%		2.77	%		2.41	%		5.14	%		2.79	%		2.41	%
Rate of increase in compensation levels		3.06	%		3.08	%		3.34	%		—			5.00	%		5.00	%	N/A			N/A			N/A


	Defined Benefit Pension Plan									Supplemental Non-qualified Defined Benefit Plans									Non-pension Defined Benefit Postretirement Healthcare Plan
Weighted-average assumptions used to determine net periodic benefit cost for plan year:	2022			2021			2020			2022			2021			2020			2022			2021			2020
Discount rate (a)		2.88	%		2.56	%		3.27	%		2.77	%		2.41	%		3.14	%		2.79	%		2.41	%		3.15	%
Expected long-term rate of return on assets (b)		4.25	%		4.50	%		5.25	%	N/A			N/A			N/A				1.70	%		1.80	%		2.35	%
Rate of increase in compensation levels		3.08	%		3.34	%		3.49	%		—			5.00	%		5.00	%	N/A			N/A			N/A

(a)

The estimated discount rate for the Defined Benefit Pension Plan is 5.2% for the calculation of the 2023 net periodic pension costs.

(b)

The expected rate of return on plan assets for the Defined Benefit Pension Plan is 6.0% for the calculation of the 2023 net periodic pension cost.

The healthcare benefit obligation at December 31 was determined as follows:


	2022			2021
Trend Rate - Medical
Pre-65 for next year - All Plans		7.00	%		6.05	%
Pre-65 Ultimate trend rate - Black Hills Corp		4.50	%		4.50	%
Trend Year	2031			2030

Post-65 for next year - All Plans		6.00	%		5.10	%
Post-65 Ultimate trend rate - Black Hills Corp		4.50	%		4.50	%
Trend Year	2031			2030

The following benefit payments to employees, which reflect future service, are expected to be paid (in thousands):


	Defined Benefit Pension Plan		Supplemental Non-qualified Defined Benefit Plans		Non-pension Defined Benefit Postretirement Healthcare Plan
2023	$	26,889	$	2,231	$	5,600
2024	$	26,882	$	2,417	$	5,313
2025	$	27,870	$	2,764	$	5,022
2026	$	28,182	$	2,790	$	4,883
2027	$	28,166	$	2,727	$	4,769
2028 -2032	$	140,416	$	12,184	$	21,147

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SHARE-BASED COMPENSATION PLANS

On April 26, 2022, our shareholders approved the Amended and Restated 2015 Omnibus Incentive Plan (the "Amended Plan"), which was adopted by our Board of Directors and became effective on February 24, 2022. The Amended Plan increased the number of shares available for issuance under the 2015 Plan from 1,200,000 to a total of 2,900,000. The Amended Plan allows for the granting of stock, restricted stock, restricted stock units, stock options, performance shares and performance share units. We had 2,213,716 shares available to grant at December 31, 2022.

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, 2022, total unrecognized compensation expense related to non-vested stock awards was approximately $12 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 thousands):


	2022		2021		2020
Stock-based compensation expense	$	8,551	$	9,655	$	5,373

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, 2022, was as follows:


	Restricted Stock			Weighted-Average Grant Date Fair Value
	(in thousands)
Balance at January 1, 2022		219		$	67.64
Granted		70			69.03
Vested		(94	)		69.64
Forfeited		(16	)		66.03
Balance at December 31, 2022		179		$	67.23

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 thousands)
2022	$	69.03	$	6,436
2021	$	65.64	$	5,400
2020	$	69.49	$	6,722

As of December 31, 2022, there was $7.5 million of unrecognized compensation expense related to non-vested restricted stock that is expected to be recognized over a weighted-average period of 1.7 years.

Performance Share Plan

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.

These performance awards are paid 50% in cash and 50% in common stock. The cash portion accrued is classified as a liability and the stock portion is classified as equity. In the event of a change-in-control, performance awards are paid 100% in cash. If it is determined that a change-in-control is probable, the equity portion of $1.4 million at December 31, 2022 would be reclassified as a liability.

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The outstanding performance periods at December 31, 2022 were as follows (shares in thousands):


				Possible Payout Range of Target
Grant Date	Performance Period	Target Grant of Shares		Minimum	Maximum
January 1, 2020	January 1, 2020 - December 31, 2022		36	0%	200%

A summary of the status of the Performance Share Plan at December 31, 2022 was as follows:


	Equity Portion					Liability Portion
				Weighted-Average Grant Date					Weighted-Average Fair Value at
	Shares			Fair Value (a)		Shares			December 31, 2022
	(in thousands)					(in thousands)
Performance Shares balance at beginning of period		36		$	68.14		36
Granted		—			—		—
Forfeited		—			—		—
Vested		(18	)		68.72		(18	)
Performance Shares balance at end of period		18		$	81.42		18		$	32.74

(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.

The weighted-average grant-date fair value of performance share awards granted was as follows in the years ended:


	Weighted Average Grant Date Fair Value
December 31, 2020	$	81.42

Performance plan payouts have been as follows (in thousands):


Performance Period	Year Paid	Stock Issued		Cash Paid		Total Intrinsic Value
January 1, 2019 to December 31, 2021	2022		8	$	519	$	1,038
January 1, 2018 to December 31, 2020	2021		28	$	1,647	$	3,294
January 1, 2017 to December 31, 2019	2020		14	$	1,100	$	2,199

On January 25, 2023, the Compensation Committee of our Board of Directors determined that the Company’s total shareholder return for the January 1, 2020 to December 31, 2022 performance period was at the 26th percentile of its peer group and confirmed a payout equal to 27% of target shares, valued at $0.7 million. The payout was fully accrued at December 31, 2022.

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. 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 over the three-year period.

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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.


	2022	2021
Fair value of share units award	74.48	64.97
Three-year risk-free rate	0.97%	0.17%
Black Hills Corporation’s common stock volatility	30%	33%
Volatility range for the peer group	22-67%	25-76%

Performance Share Units - Performance Condition

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 and the average cost to serve. 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.

The following table summarizes the performance share unit activity for the year ended December 31, 2022:


	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
Nonvested at January 1, 2022		32,903	$	64.97		21,948	$	61.45
Granted		35,571		74.48		23,718		70.57
Nonvested at December 31, 2022		68,474	$	69.91		45,666	$	66.19

As of December 31, 2022, there was $4.1 million of unrecognized compensation expense related to outstanding performance share/unit plans that is expected to be recognized over a weighted-average period of 1.7 years.

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INCOME TAXES

Winter Storm Uri

As discussed in Note 2 above, our Utilities received final commission approval for all of our Winter Storm Uri cost recovery applications, which will allow full recovery of our $546 million of incremental fuel, purchased power and natural gas costs. We will recover these costs from customers over several years, which will increase our taxable income on our tax returns by the amounts collected for each respective year. The incremental costs from Winter Storm Uri were deductible in our 2021 tax return and created a net deferred tax liability, which had balances as of December 31, 2022 and 2021 of $85 million and $124 million, respectively. The deferred tax liability is reversed with the same timing as the costs are recovered from our customers.

The income tax deduction recognized from Winter Storm Uri created a $509 million NOL in our 2021 federal income tax return and a $375 million NOL in our state income tax returns. Our federal NOL carryforwards related to Winter Storm Uri and other recent adjustments no longer expire due to the TCJA; however, our state NOL carryforwards expire at various dates from 2023 to 2041. We do not anticipate material changes to our valuation allowance against the state NOL carryforwards from Winter Storm Uri. Therefore, we did not record an additional valuation allowance against the state NOL carryforwards as of December 31, 2022 and 2021.

TCJA

On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the TCJA. The TCJA reduced the U.S. federal corporate tax rate from 35% to 21%. As such, the Company remeasured the deferred income taxes at the 21% federal tax rate as of December 31, 2017. The entities subject to regulatory construct have made their best estimate regarding the probability of settlements of net regulatory liabilities established pursuant to the TCJA. The amount of the settlements may change based on decisions and actions by the federal and state utility commissions, which could have a material impact on the Company’s future results of operations, cash flows or financial position. 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. For the years ended December 31, 2022, 2021 and 2020, respectively, the Company has amortized, or provided bill credits for, $11 million, $23 million and $13 million of the regulatory liability. The portion that was eligible for amortization under the average rate assumption method in 2021 but is awaiting resolution of the treatment of these amounts in future regulatory proceedings has not been recognized and may be refunded in customer rates at any time in accordance with the resolution of pending or future regulatory proceedings.

Beginning in 2022, the TJCA modified IRC 174 which changes how taxpayers account for research and development costs. After the IRC 174 modification, taxpayers must amortize specified research and experimental expenditures performed in the United States ratably over five years instead of deducting research and experimental expenditures. This modification did not have a material impact for the year ended December 31, 2022.

Income Tax Expense (Benefit)

Income tax expense (benefit) from continuing operations for the years ended December 31 was (in thousands):


	2022			2021			2020
Current:
Federal	$	(467	)	$	574		$	(6,020	)
State		80			(666	)		847
Current income tax (benefit)		(387	)		(92	)		(5,173	)
Deferred:
Federal		23,205			2,170			35,672
State		2,387			5,091			2,419
Deferred income tax expense		25,592			7,261			38,091

Income tax expense	$	25,205		$	7,169		$	32,918

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Effective Tax Rates

The effective tax rate differs from the federal statutory rate for the years ended December 31, as follows:


	2022			2021			2020
Federal statutory rate		21.0	%		21.0	%		21.0	%
State income tax (net of federal tax effect) (a)		0.5			1.2			2.4
Non-controlling interest (b)		(0.9	)		(1.2	)		(1.2	)
Tax credits		(7.7	)		(8.4	)		(9.2	)
Flow-through adjustments (c)		(1.4	)		(3.2	)		(1.6	)
Uncertain Tax Benefits		—			0.3			1.5
Valuation Allowance		—			—			0.7
Other tax differences		(0.1	)		(0.2	)		0.6
Amortization of excess deferred income tax expense (d)		(2.5	)		(3.1	)		(2.3	)
TCJA bill credits (e)		(0.4	)		(3.6	)		—
Effective Tax Rate		8.5	%		2.8	%		11.9	%

(a)

The state effective tax rate contains the tax expense attributable to multiple statutory state rate reductions in the Company's state jurisdictions.

(b)

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.

(c)

Flow-through adjustments related primarily to accounting method changes for tax purposes that allow us to take a current tax deduction for repair costs, certain indirect costs and gain deferral. 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.

(d)

Primarily TCJA - see above.

(e)

Primarily related to one-time bill credits of TCJA benefits which were 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.

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 thousands):


	2022			2021
Deferred tax assets:
Regulatory liabilities	$	74,728		$	77,099
State tax credits		22,817			23,342
Federal NOL		191,992			227,535
State NOL		23,031			33,639
Partnership		12,755			13,395
Credit Carryovers		90,881			68,646
Other deferred tax assets		45,407			31,996
Less: Valuation allowance		(15,476	)		(14,719	)
Total deferred tax assets		446,135			460,933

Deferred tax liabilities:
Accelerated depreciation, amortization and other property-related differences		(645,762	)		(597,284	)
Regulatory assets		(94,433	)		(124,582	)
Goodwill		(57,884	)		(45,471	)
State deferred tax liability		(98,200	)		(109,136	)
Other deferred tax liabilities		(58,797	)		(49,848	)
Total deferred tax liabilities		(955,076	)		(926,321	)

Net deferred tax liability	$	(508,941	)	$	(465,388	)

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Net Operating Loss and Tax Credit Carryforwards

At December 31, 2022, we have federal NOL and state NOL and tax credit carryforwards that will expire at various dates as follows (in thousands):


	Amounts		Expiration Dates
Federal NOL Carryforward	$	330,085	2023 to 2037
Federal NOL Carryforward	$	584,161	No expiration

State NOL Carryforward (a)	$	408,269	2023 to 2041
State Tax Credit Carryforward	$	22,817	2023 to 2041

(a)

The carryforward balance is reflected on the basis of apportioned tax losses to jurisdictions imposing state income taxes.

As of December 31, 2022, we had a $1.1 million valuation allowance against the state NOL carryforwards. Our 2022 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, 2022, we had a $14 million valuation allowance against the state ITC carryforwards. Our 2022 analysis of the ability to utilize such ITC resulted in a $0.8 million increase in the valuation allowance, which resulted in an increase to tax expense of $0.6 million. The remaining $0.2 million increase is attributable to our regulated business and is being accounted for under the deferral method whereby the credits are amortized to expense over the estimated useful life of the underlying asset that generated the credit. The valuation allowance adjustment was primarily attributable to expiring state ITC credits.

Unrecognized Tax Benefits

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 thousands):


Changes in Uncertain Tax Positions:	2022			2021			2020
Beginning balance	$	10,554		$	8,383		$	4,165
Additions for prior year tax positions		7			448			3,788
Reductions for prior year tax positions		(773	)		(732	)		(1,313	)
Additions for current year tax positions		2,097			2,455			1,743
Ending balance	$	11,885		$	10,554		$	8,383

The total amount of unrecognized tax benefits that, if recognized, would impact the effective tax rate is approximately $5.7 million.

We recognized no interest expense associated with income taxes for the years ended December 31, 2022, 2021 and 2020. We had no accrued interest (before tax effect) associated with income taxes at December 31, 2022 and 2021.

The Company is subject to federal income tax as well as income tax in various state and local jurisdictions.

As of December 31, 2022, 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, 2023.

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(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.

Our CODM assesses the performance of our operating segments based on operating income. Our operating segments are equivalent to our reportable segments.

Segment information was as follows (in thousands):


	Consolidating Income Statement
Year ended December 31, 2022	Electric Utilities		Gas Utilities		Corporate			Inter-Company Eliminations			Total

Revenue -
Contracts with customers	$	882,899	$	1,659,957	$	—		$	—		$	2,542,856
Other revenues		5,548		3,412		—			—			8,960
		888,447		1,663,369		—			—			2,551,816
Inter-company operating revenue -
Contracts with customers		11,715		5,292		538			(17,545	)		—
Other revenues		—		429		368,201			(368,630	)		—
		11,715		5,721		368,739			(386,175	)		—
Total revenue		900,162		1,669,090		368,739			(386,175	)		2,551,816

Fuel, purchased power and cost of natural gas sold		266,284		965,108		(11	)		(831	)		1,230,550
Operations and maintenance, including taxes		283,654		345,143		309,773			(323,457	)		615,113
Depreciation, depletion and amortization		135,966		114,679		26,964			(26,700	)		250,909
Operating income (loss)	$	214,258	$	244,160	$	32,013		$	(35,187	)	$	455,244

Interest expense, net												(160,989	)
Impairment of investment												—
Other income (expense), net												1,708
Income tax benefit (expense)												(25,205	)
Net income												270,758
Net income attributable to non-controlling interest												(12,371	)
Net income available for common stock											$	258,387

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	Consolidating Income Statement
Year ended December 31, 2021	Electric Utilities		Gas Utilities		Corporate		Inter-Company Eliminations			Total

Revenue -
Contracts with customers	$	825,404	$	1,105,430	$	—	$	—		$	1,930,834
Other revenues		5,336		12,932		—		—			18,268
		830,740		1,118,362		—		—			1,949,102
Inter-company operating revenue -
Contracts with customers		11,518		6,110		196		(17,824	)		—
Other revenues		—		393		356,151		(356,544	)		—
		11,518		6,503		356,347		(374,368	)		—
Total revenue		842,258		1,124,865		356,347		(374,368	)		1,949,102

Fuel, purchased power and cost of natural gas sold		248,018		494,738		96		(918	)		741,934
Operations and maintenance, including taxes		260,036		314,810		293,265		(306,325	)		561,786
Depreciation, depletion and amortization		131,528		104,160		26,838		(26,573	)		235,953
Operating income (loss)	$	202,676	$	211,157	$	36,148	$	(40,552	)	$	409,429

Interest expense, net											(152,404	)
Impairment of investment											—
Other income (expense), net											1,404
Income tax benefit (expense)											(7,169	)
Net income											251,260
Net income attributable to non-controlling interest											(14,516	)
Net income available for common stock										$	236,744


	Consolidating Income Statement
Year ended December 31, 2020	Electric Utilities		Gas Utilities		Corporate		Inter-Company Eliminations			Total

Revenue -
Contracts with customers	$	721,108	$	959,696	$	—	$	—		$	1,680,804
Other revenues		6,175		9,962		—		—			16,137
		727,283		969,658		—		—			1,696,941
Inter-company operating revenue -
Contracts with customers		11,574		4,724		167		(16,465	)		—
Other revenues		—		288		352,976		(353,264	)		—
		11,574		5,012		353,143		(369,729	)		—
Total revenue		738,857		974,670		353,143		(369,729	)		1,696,941

Fuel, purchased power and cost of natural gas sold		138,572		354,645		83		(896	)		492,404
Operations and maintenance, including taxes		265,679		303,577		284,501		(301,980	)		551,777
Depreciation, depletion and amortization		123,632		100,559		25,150		(24,884	)		224,457
Operating income (loss)	$	210,974	$	215,889	$	43,409	$	(41,969	)	$	428,303

Interest expense, net											(143,470	)
Impairment of investment											(6,859	)
Other income (expense), net											(2,293	)
Income tax benefit (expense)											(32,918	)
Net income											242,763
Net income attributable to non-controlling interest											(15,155	)
Net income available for common stock										$	227,608

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Total Assets (net of intercompany eliminations) as of December 31,	2022		2021
Electric Utilities	$	3,929,721	$	3,796,662
Gas Utilities		5,578,282		5,246,370
Corporate and Other		110,227		88,864
Total assets	$	9,618,230	$	9,131,896


Capital Expenditures (a) for the years ended December 31,	2022		2021		2020
Electric Utilities	$	243,133	$	285,770	$	288,683
Gas Utilities		349,438		383,320		449,209
Corporate and Other		5,097		10,500		17,500
Total capital expenditures	$	597,668	$	679,590	$	755,392

(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, 2022 which would require recognition in the Consolidated Financial Statements or disclosures.

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, 2022. 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, 2022, 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.

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) and 407(d)(5) of Regulation S-K, is set forth in the Proxy Statement for our 2023 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.

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ITEM 11. EXECUTIVE COMPENSATION

Information required under this item is set forth in the Proxy Statement for our 2023 Annual Meeting of Shareholders, which is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information regarding the security ownership of certain beneficial owners and management is set forth in the Proxy Statement for our 2023 Annual Meeting of Shareholders, which is incorporated herein by reference.

EQUITY COMPENSATION PLAN INFORMATION

The following table includes information as of December 31, 2022 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			Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)			(b)			(c)
Equity compensation plans approved by security holders	$	255,588	(1)	$	-	(1)	$	2,213,716	(2)
Equity compensation plans not approved by security holders	---				-		---
Total	$	255,588		$	-		$	2,213,716

(1)

255,588 full value awards outstand as of December 31, 2022, comprised of restricted stock units, performance shares, short-term incentive plan (STIP) units and Director common stock units. In addition, 163,387 shares of unvested restricted stock were outstanding as of December 31, 2022, which are not included in the table above because they have already been issued. We do not have any outstanding options, warrant or rights.

(2)

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.

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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 2023 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 2023 Annual Meeting to Shareholders, which is incorporated herein by reference.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

Documents filed as part of this report

Consolidated Financial Statements

Financial statements required under this item are included in Item 8 of Part II

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.

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	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).
2.2	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).
2.3	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).
3.1	Restated Articles of Incorporation of the Registrant (filed as Exhibit 3 to the Registrant’s Form 8-K filed on February 5, 2018).
3.2	Amended and Restated Bylaws of the Registrant dated April 24, 2017 (filed as Exhibit 3 to the Registrant’s Form 8-K filed on April 28, 2017).
4.1	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).
4.1.1	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).
4.1.2	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).
4.1.3	Third Supplemental Indenture dated as of July 16, 2010 (filed as Exhibit 4 to Registrant’s Form 8-K filed on July 15, 2010).
4.1.4	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).

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4.1.5	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).
4.1.6	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).
4.1.7	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).
4.1.8	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).
4.1.9	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).
4.1.10	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).
4.2	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)).
4.2.1	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)).
4.2.2	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)).
4.2.3	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).
4.3	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).
4.3.1	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).
4.3.2	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).
4.4	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).
4.5	Description of Securities (filed as Exhibit 4.5 to the Registrant's Form 10-K for 2019)
10.1†	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).
10.1.1†	First Amendment to Pension Equalization Plan (filed as Exhibit 10.10 to the Registrant’s Form 10-K for 2002).
10.1.2†	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).
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†	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).
10.3†	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).
10.3.1†	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).
10.4*†	Black Hills Corporation Post-2018 Nonqualified Deferred Compensation Plan.
10.5†	Black Hills Corporation 2005 Omnibus Incentive Plan (”Omnibus Plan”) (filed as Appendix A to the Registrant’s Proxy Statement filed April 13, 2005).
10.5.1†	First Amendment to the Omnibus Plan (filed as Exhibit 10.11 to the Registrant’s Form 10-K for 2008).
10.5.2†	Second Amendment to the Omnibus Plan (filed as Exhibit 10 to the Registrant’s Form 8-K filed on May 26, 2010).

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10.6*†	Black Hills Corporation Amended and Restated 2015 Omnibus Incentive Plan effective Janaury 24, 2023.
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).
10.17*†	Change in Control Agreement dated November 15, 2022 between Black Hills Corporation and Linden R. Evans.
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 August 4, 2020 among Black Hills Corporation and the several Agents named therein (filed as Exhibit 1.1 to the Registrant’s Form 8-K filed on August 4, 2020).
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).
10.23	Credit Agreement dated as of February 24, 2021 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 February 25, 2021).
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 Februrary 15, 2022).
10.25	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).
10.26	Coal Leases between WRDC and the Federal Government

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	-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).
10.27	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).
10.28*†	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, 2023.
10.29*†	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.
10.30*†	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.
21*	List of Subsidiaries of Black Hills Corporation.
23.1*	Consent of Independent Registered Public Accounting Firm.
31.1*	Certification of Chief Executive Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
31.2*	Certification of Chief Financial Officer pursuant to Rule 13a - 14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes - Oxley Act of 2002.
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
95*	Mine Safety and Health Administration Safety Data
101.INS*	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH*	Inline XBRL Taxonomy Extension Schema Document
101.CAL*	Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	Inline XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE*	Inline XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

ITEM 16. FORM 10-K SUMMARY

None.

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SIGNATURES

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.


		BLACK HILLS CORPORATION

		By:	/S/ LINDEN R. EVANS
		Linden R. Evans, President and Chief Executive Officer
Dated:	February 14, 2023

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	Director and	February 14, 2023
Steven R. Mills	Chairman

/S/ LINDEN R. EVANS	Director and	February 14, 2023
Linden R. Evans, President	Principal Executive Officer
and Chief Executive Officer

/S/ RICHARD W. KINZLEY	Principal Financial and	February 14, 2023
Richard W. Kinzley, Senior Vice President	Accounting Officer
and Chief Financial Officer

/S/ BARRY M. GRANGER	Director	February 14, 2023
Barry M. Granger

/S/ TONY A. JENSEN	Director	February 14, 2023
Tony A. Jensen

/S/ KATHLEEN S. MCALLISTER	Director	February 14, 2023
Kathleen S. McAllister

/S/ ROBERT P. OTTO	Director	February 14, 2023
Robert P. Otto

/S/ SCOTT M. PROCHAZKA	Director	February 14, 2023
Scott M. Prochazka

/S/ REBECCA B. ROBERTS	Director	February 14, 2023
Rebecca B. Roberts

/S/ MARK A. SCHOBER	Director	February 14, 2023
Mark A. Schober

/S/ TERESA A. TAYLOR	Director	February 14, 2023
Teresa A. Taylor

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