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, 2021

Or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to _______________

Commission File Number 001-31303

BLACK HILLS CORPORATION

Incorporated in South Dakota    IRS Identification Number 46-0458824

7001 Mount Rushmore Road

Rapid City, South Dakota 57702

Registrant’s telephone number (605) 721-1700

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol	Name of each exchange on which registered
Common stock of $1.00 par value	BKH	New York Stock Exchange

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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. ☒

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, 2021, was $4,135,954,577

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, 2022
Common stock, $1.00 par value	64,738,725	shares

Documents Incorporated by Reference

Portions of the registrant’s Definitive Proxy Statement being prepared for the solicitation of proxies in connection with the 2022 Annual Meeting of Stockholders to be held on April 26, 2022, 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		9
FORWARD-LOOKING INFORMATION		9
Part I
ITEM 1.	BUSINESS	10
	History and Organization	10
	Electric Utilities	10
	Gas Utilities	15
	Utility Regulation Characteristics	18
	Environmental Matters	18
	Human Capital Resources	19
ITEM 1A.	RISK FACTORS	21
ITEM 1B.	UNRESOLVED STAFF COMMENTS	27
ITEM 2.	PROPERTIES	27
ITEM 3.	LEGAL PROCEEDINGS	27
ITEM 4.	MINE SAFETY DISCLOSURES	27
INFORMATION ABOUT OUR EXECUTIVE OFFICERS		28
Part II
ITEM 5.	MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	29
ITEM 6.	RESERVED	30
ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30
	Executive Summary	30
	Key Elements of our Business Strategy	31
	Recent Developments	34
	Results of Operations - Consolidated Summary and Overview	36
	Non-GAAP Financial Measure	37
	Electric Utilities	38
	Gas Utilities	42
	Corporate and Other	44
	Consolidated Interest Expense, Impairment of Investment, Other Income (Expense) and Income Tax Benefit (Expense)	45
	Liquidity and Capital Resources	46
	Cash Flow Activities	46
	Capital Resources	47
	Credit Ratings	49
	Capital Requirements	50
	Critical Accounting Estimates	51
ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	54

2

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	75
	Note 3. Commitments, Contingencies and Guarantees	79
	Note 4. Revenue	84
	Note 5. Property, Plant and Equipment	85
	Note 6. Jointly Owned Facilities	86
	Note 7. Asset Retirement Obligations	88
	Note 8. Financing	88
	Note 9. Risk Management and Derivatives	92
	Note 10. Fair Value Measurements	95
	Note 11. Other Comprehensive Income	97
	Note 12. Variable Interest Entity	95
	Note 13. Employee Benefit Plans	98
	Note 14. Share-based Compensation Plans	105
	Note 15. Income Taxes	107
	Note 16. Business Segment Information	111
	Note 17. Subsequent Events	114
ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	114
ITEM 9A.	CONTROLS AND PROCEDURES	114
ITEM 9B.	OTHER INFORMATION	114
ITEM 9C.	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	114
Part III
ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	115
ITEM 11.	EXECUTIVE COMPENSATION	115
ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	115
ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE	115
ITEM 14.	PRINCIPAL ACCOUNTANT FEES AND SERVICES	115
Part IV
ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES	115
ITEM 16.	FORM 10-K SUMMARY	119
SIGNATURES		120

3

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 Obligations
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 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
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.
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.
CARES Act	Coronavirus Aid, Relief, and Economic Security Act, signed on March 27, 2020, which is a tax and spending package intended to provide additional economic relief and address the impact of the COVID-19 pandemic.
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 Colorado Springs	Colorado Springs, Colorado
City of Gillette	Gillette, Wyoming

4

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
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.
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
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.

5

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.
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
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
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
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.

6

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.
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.
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 285-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).
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.
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.
Top of Iowa	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.

7

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 DC 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
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).

8

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 the COVID-19 pandemic or Winter Storm Uri, 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.

9

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. In the fourth quarter of 2021, we integrated our power generation and mining businesses within the Electric Utilities segment. The alignment is consistent with the current way our CODM evaluates the performance of the business and makes decisions related to the allocation of resources. Comparative periods presented reflect this change. See further segment information in Note 16 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Our Electric Utilities segment generates, transmits and distributes electricity to approximately 218,000 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 our Electric Utilities. Our Electric Utilities own 1,481.5 MW of generation and 8,899 miles of electric transmission and distribution lines.

Our Gas Utilities segment serves approximately 1,094,000 natural gas utility customers in Arkansas, Colorado, Iowa, Kansas, Nebraska, and Wyoming. Our Gas Utilities own and operate 4,732 miles of intrastate gas transmission pipelines and 41,644 miles of gas distribution mains and service lines, six 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	2021	2020	2019
Residential	186,852	184,872	183,232
Commercial	30,326	30,225	29,921
Industrial	81	83	83
Other	1,010	1,017	1,024
Total Electric Retail Customers at End of Year	218,269	216,197	214,260

	As of December 31,
Retail Customers	2021	2020	2019
Colorado Electric	99,709	98,735	97,890
South Dakota Electric	74,509	73,700	73,052
Wyoming Electric	44,051	43,762	43,318
Total Electric Retail Customers at End of Year	218,269	216,197	214,260

10

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)
	2021		2020		2019
	Summer	Winter	Summer	Winter	Summer	Winter
Colorado Electric	407	279	401	297	422	297
South Dakota Electric	397	299	378	304	335	320
Wyoming Electric	274	246	271	246	265	247

As of December 31, 2021, 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)	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
Top of Iowa (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 Peak View facility qualifies for PTCs at $25/MWh under IRC 45 during the 10-year period beginning November 2016. The PTCs for this facility flow back to customers through a rider mechanism as a reduction to Colorado Electric’s margins.

(c)    This facility qualifies for PTCs at $25/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.

11

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	2021		2020		2019
Coal	34.2	%	40.3	%	40.0	%
Natural Gas and Diesel Oil (a)	24.4		25.0		22.2
Wind	11.3		8.8		5.8
Total Generated	69.9		74.1		68.0
Coal, Natural Gas, Oil and Other Market Purchases	25.1		21.1		29.1
Wind Purchases	5.0		4.8		2.9
Total Purchased	30.1		25.9		32.0
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%, 0.0% and 0.1% for the years ended December 31, 2021, 2020, and 2019, respectively.

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)	2021		2020		2019
Coal	$	11.55	$	11.38	$	12.42
Natural Gas and Diesel Oil (a)	33.65		8.59		11.04
Total Generated Weighted Average Fuel Cost	17.40		9.09		12.48
Coal, Natural Gas, Oil and Other Market Purchases (a)	64.85		40.80		44.16
Wind Purchases	34.69		42.06		49.19
Total Purchased Power Weighted Average Cost	59.84		41.03		44.62
Total Weighted Average Fuel and Purchased Power Cost	$	30.17	$	17.36	$	22.76

____________________

(a)    The 2021 increase in prices paid for fuel and purchased power was primarily driven by unforeseeable and unprecedented market prices for natural gas and electricity during Winter Storm Uri. See further information in the Recent Developments section of Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K.

Power Purchase and Power Sales Agreements. 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. We also have various long-term PSAs. Key contracts are disclosed 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. 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 3.5 million tons of coal in 2021.

The mine provides low-sulfur coal directly to these five power plants via a conveyor belt system, minimizing transportation costs. On average, the fuel can be delivered to the adjacent power plants at less than $1.00 per MMBtu, providing very cost competitive fuel to our power plants 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, 2021, we estimated our recoverable reserves to be approximately 178 million tons, based on a life-of-mine engineering study utilizing currently available drilling data and geological information prepared by internal engineering studies. The recoverable reserve life is equal to approximately 51 years at the current production levels.

12

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, 2021, 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	3,157
South Dakota Electric (b)	South Dakota, Wyoming	1,192	2,566
Wyoming Electric	Wyoming	59	1,327
		1,849	7,050

____________________

(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 in often greater in the winter.

Competition. We generally have limited competition for the retail generation and distribution of electricity in our service areas. Various legislative or regulatory restructuring and competitive initiatives have been discussed in several of the states in which our utilities operate. These initiatives would be aimed at increasing competition or providing for distributed generation. To date, these initiatives have not had a material impact on our utilities. In Colorado, our electric utility is subject to rules which may require competitive bidding for generation supply. Because of these rules, we face competition from other utilities and non-affiliated IPPs for the right to supply electric energy and capacity for Colorado Electric when resource plans require additional resources. Additionally, electrification initiatives in our service territories could increase demand for electricity and increase customer growth.

The independent power industry consists of many strong and capable competitors, some of which may have more extensive operations or greater financial resources than we possess. With respect to the merchant power sector, FERC has taken steps to increase access to the national transmission grid by utility and non-utility purchasers and sellers of electricity to foster competition within the wholesale electricity markets. Our non-regulated power generation businesses could face greater competition if utilities are permitted to robustly invest in power generation assets. Conversely, state regulatory rules 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 strategy for our mining business 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.

Rates and Regulation. Our Electric Utilities are subject to the jurisdiction of the public utilities 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.

13

The following table provides regulatory information for each of our Electric Utilities:

Subsidiary	Jurisdic-tion	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	Clean Air Clean Jobs Act 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%	$148.4 (b)	2/2009	FERC Transmission Tariff	N/A
Wyoming Electric (a)	WY	9.90%	7.98%	46%/54%	$376.8	10/2014	PCA, EECR/DSM, Rate Base Recovery on Acquisition Adjustment	N/A

____________________

(a)    For both Colorado Electric and Wyoming Electric, transmission investments are recovered through retail rates rather than FERC Transmission Tariffs.

(b)    Includes $131.3 million in 2021 rate base for the 2021 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.

The regulatory provisions for recovering the costs to supply electricity vary by state. We have cost adjustment mechanisms for our Electric Utilities that allow us to pass the prudently-incurred cost of 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 states allow for recovery of new capital investment placed in service between base rate reviews through approved rider tariffs. These tariffs allow the utility a return on the investment.

A summary of mechanisms we have in place are shown in the table below:

Electric Utility Jurisdiction	Cost Recovery Mechanisms
	Environmental Cost	Energy Efficiency	Transmission Expense	Fuel Cost	Transmission Capital	Purchased Power	RESA
Colorado Electric		þ	þ	þ	þ	þ	þ
South Dakota Electric (SD) (a)	þ		þ	þ	þ	þ
South Dakota Electric (WY) (b)		þ	þ	þ		þ
South Dakota Electric (FERC) (c)					þ
Wyoming Electric		þ	þ	þ		þ

____________________

(a)    South Dakota Electric’s Environmental Cost (EIA) and Transmission Capital (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.

Tariff Filings. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for tariff filings and additional information regarding current electric regulatory activity.

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.

14

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 1,094,000 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 52,400 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	2021	2020	2019
Residential	853,908	844,999	831,351
Commercial	84,234	83,135	82,912
Industrial	2,158	2,235	2,208
Transportation	153,929	152,568	149,971
Total Natural Gas Retail Customers at End of Year	1,094,229	1,082,937	1,066,442

	As of December 31,
Retail Customers	2021	2020	2019
Arkansas	180,216	178,281	174,447
Colorado	202,747	197,817	191,950
Iowa	161,905	160,952	159,641
Kansas	117,862	116,973	115,846
Nebraska	298,832	296,778	293,576
Wyoming	132,667	132,136	130,982
Total Natural Gas Retail Customers at End of Year	1,094,229	1,082,937	1,066,442

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.

The following table summarizes certain information regarding our company-owned regulated underground gas storage facilities as of December 31, 2021:

State	Working Capacity (Mcf)	Cushion Gas (Mcf)	Total Capacity (Mcf)	Maximum Daily Withdrawal Capability (Mcfd)
Arkansas	9,273,700	12,318,040	21,591,740	196,000
Colorado	2,361,495	6,164,715	8,526,210	30,000
Wyoming	5,733,900	17,145,600	22,879,500	36,000
Total	17,369,095	35,628,355	52,997,450	262,000

15

The following table summarizes certain information regarding our system infrastructure as of December 31, 2021:

State	Intrastate Gas Transmission Pipelines (in line miles)	Gas Distribution Mains (in line miles)	Gas Distribution Service Lines (in line miles)
Arkansas	874	4,972	1,275
Colorado	693	6,990	2,303
Iowa	172	2,863	2,486
Kansas	330	2,980	1,374
Nebraska	1,311	8,443	2,773
Wyoming	1,352	3,532	1,653
Total	4,732	29,780	11,864

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 customer 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 a charge for transporting the gas through our distribution network.

Rates and Regulation. Our Gas Utilities are subject to the jurisdiction of the public utility commissions in the states where they operate. These commissions oversee services and facilities, rates and charges, accounting, valuation of property, depreciation rates and various other matters. The public utility commissions determine the rates we are allowed to charge for our utility services. 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.

Our Gas Utilities are authorized to use natural gas cost recovery mechanisms allowing rate adjustments reflecting changes in the wholesale cost of natural gas and recovery of all the costs prudently incurred in purchasing gas for customers. In addition to natural gas cost recovery mechanisms, other recovery mechanisms, which vary by utility, allow us to recover certain costs or earn a return on capital investments, such as energy efficiency plan costs and system safety and integrity investments.

16

The following table provides regulatory information for each of our natural gas utilities:

Subsidiary	Jurisdic-tion	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 (c)	AR	9.61%	6.82% (a)	51%/49%	$451.5 (b)	10/2018	GCA, Main Replacement Program, At-Risk Meter Relocation Program, Legislative or Regulatory Mandated Expenditures, EECR, Weather Normalization Adjustment, Billing Determinant Adjustment
Colorado Gas (c)	CO	9.20%	6.56%	50%/50%	$303.2	1/2022	GCA, SSIR, EECR/DSM
RMNG	CO	9.90%	6.71%	53%/ 47%	$118.7	6/2018	SSIR, Liquids/Off-system/Market Center Services Revenue Sharing
Iowa Gas (c)	IA	9.60%	6.75%	50%/50%	$300.9	1/2022	GCA, EECR, System Safety and Maintenance Adjustment Rider, Gas Supply Optimization revenue sharing
Kansas Gas (c)	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%	$504.2	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
Wyoming Gas (d)	WY	9.40%	6.98%	50%/50%	$354.4	3/2020	GCA, EECR, Rate Base Recovery on Acquisition Adjustment, Wyoming Integrity Rider, Choice Gas Program

____________________

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

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

(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.

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

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. Some of the mechanisms we have in place include the following:

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

____________________

(a)    RMNG, which is an intrastate transmission pipeline that provides natural gas transmission and wholesale services in western Colorado, has an SSIR recovery mechanism. The other cost recovery mechanisms are not applicable to RMNG.

Tariff Filings. See Note 2 of the Notes to Consolidated Financial Statements in this Annual Report on Form 10-K for information regarding current natural gas regulatory activity.

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.

17

Utility Regulation Characteristics

Federal Regulation

Energy Policy Act. 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.

Federal Power Act. 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. 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 Top of Iowa. Each of these three EWGs have been granted market-based rate authority.

Environmental Matters

In November 2020, we announced clean energy goals to reduce GHG emissions that are based on prudent and proven solutions while minimizing cost impacts to 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. That decision, if not successfully appealed or reconsidered, would allow the EPA to proceed with alternate regulation of coal-fired power plants, either reviving the Clean Power Plan or proposing additional regulation. Compliance could result in significant investment.

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.

18

Human Capital Resources

Overview

Black Hills Corporation is 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 Black Hills Corporation to successfully grow and manage our business year over year. The impacts of COVID-19 to our businesses and employees are discussed in the Recent Developments within Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Annual Report on Form 10-K.

Our Team	As of December 31, 2021	As of December 31, 2020
Total employees	2,884	3,011
Women in executive leadership positions (a)	30%	31%
Gender diversity (women as a % of total employees)	26%	26%
Represented by a union	25%	25%
Military veterans	14%	16%
Ethnic diversity (non-white employees as a % of total)	12%	11%
	For the year ended December 31, 2021	For the year ended December 31, 2020
Number of external hires	214	299
External hires gender diversity (as a % of total external hires)	25%	29%
External hires ethnic diversity (as a % of total external hires)	20%	16%
Turnover rate (b)	11%	8%
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, 2021
Electric Utilities	420
Gas Utilities	1,191
Corporate and Other	1,273
Total	2,884

At December 31, 2021, approximately 20% of our total employees and 22% 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, 2021, 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.

19

Utility	Number of Employees	Union Affiliation	Expiration Date of Collective Bargaining Agreement
Colorado Electric	94	IBEW Local 667	April 15, 2023
South Dakota Electric	128	IBEW Local 1250	March 31, 2022
Wyoming Electric	25	IBEW Local 111	June 30, 2024
Total Electric Utilities	247
Iowa Gas	132	IBEW Local 204	January 31, 2026
Kansas Gas	16	Communications Workers of America, AFL-CIO Local 6407	December 31, 2024
Nebraska Gas	92	IBEW Local 244	March 13, 2022
Nebraska Gas	140	CWA Local 7476	October 30, 2023
Wyoming Gas	15	IBEW Local 111	June 30, 2024
Wyoming Gas	78	CWA Local 7476	October 30, 2023
Total Gas Utilities	473
Total	720

Attraction

Continuous attraction of qualified team members is critical to our ability to serve our 1.3 million customers safely and efficiently. We actively recruit qualified candidates and continuously evaluate our interviewing and hiring practices to ensure equitable pay and processes. Our attraction efforts include the use of multiple nation-wide job boards, local college and high school outreach programs, a robust college internship program and participation in national and local job fairs. We have targeted diversity initiatives specific to recruiting groups, such as women, minorities and veterans, to fulfill our vision of continuing to build a thriving workforce, which is best able to support our communities, our customers and our shareholders.

Diversity & Inclusion

At Black Hills Corporation, 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, including diverse new hires, promotions and turnover, are monitored at regular intervals.

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 trainings 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, 2021
Total Case Incident Rate (incidents per 200,000 hours worked)	1.06
Preventable Motor Vehicle Incident Rate (vehicle accidents per 1 million miles driven)	1.81
Proactive Safety and Wellness Participation Rate (a)	71%

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(a)    Measures the employee engagement rate in a fitness tracking system used for the Company’s well-being program.

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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 RISKS

Our continued success is dependent on execution of our strategic business plans including our growth strategy.

Our 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 operating efficiencies. Our current plans and strategy may be negatively impacted by disruptive forces and innovations in the marketplace, 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: weather conditions, effective management of projects, availability of qualified construction personnel including contractors, changes in commodity and other prices, availability and inflationary 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.

Customer growth and usage in our service territories may fluctuate with economic conditions, emerging technologies, political influences or responses to price increases.

Our financial operating results are impacted by energy demand in our service territories. Customer growth and usage may be impacted by a number of factors, including 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 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 could materially affect our financial operating results including earnings, cash flow and liquidity.

REGULATORY, LEGISLATIVE AND LEGAL RISKS

We may be subject to future laws, regulations or actions associated with climate change, including those relating to fossil-fuel generation and GHG emissions, which could increase our operating costs or restrict our market opportunities.

We own and operate regulated and non-regulated electric power plants that burn fossil fuels (natural gas and coal) and a surface mine that extracts and sells coal. We also purchase, store and deliver natural gas to our customers. These business activities are subject to evolving public concern regarding fossil fuels, GHG emissions (such as carbon dioxide and methane) and their impact on the climate.

There is uncertainty surrounding climate regulation due to legal challenges to some current regulations and anticipated new federal and/or state climate legislation and regulation. 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 results of operations, financial condition or cash flows.

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Future GHG constraints designed to minimize emissions from natural gas could likewise result in increased costs and affect the demand for natural gas as well as the prices charged to customers and the competitive position of natural gas among fuel alternatives. Certain cities in our operational footprint are focused on electrification and are considering initiatives that may restrict the direct use of natural gas in homes and businesses. Any such initiatives and legislation could have a negative impact on our results of operations, financial condition and cash flows.

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 results of operations, financial condition and cash flows.

Each of our Electric and Gas Utilities are permitted to recover certain costs (such as increased fuel and purchased power costs, including incremental costs from Winter Storm Uri, 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 results of operations, financial condition and cash flows.

Costs could significantly increase to achieve or maintain compliance with existing or future environmental laws, regulations or requirements.

Our business segments are subject to numerous environmental laws and regulations affecting many aspects of present and future operations, including air emissions (i.e. SO2, NOx, volatile organic compounds, particulate matter and GHG), water quality, wastewater discharges, solid waste and hazardous waste. These laws and regulations may result in increased capital, operating and other costs. These laws and regulations generally require the business segments to obtain and comply with a wide variety of environmental licenses, permits, inspections and other government approvals. Compliance with environmental laws and regulations may require significant expenditures, including expenditures for cleanup costs and damages arising from contaminated properties. Failure or inability to comply with evolving environmental regulations may result in the imposition of fines, penalties and injunctive measures affecting operating assets.

Our business segments may not be successful in recovering increased capital and operating costs incurred to comply with new environmental regulations through existing regulatory rate structures and contracts with customers. More stringent environmental laws or regulations could result in additional costs of operation for existing facilities or impede the development of new facilities. Although it is not expected that the costs to comply with current environmental regulations will have a material adverse effect on our business segments’ financial position, results of operations or cash flows, future environmental compliance costs could have a significant negative impact.

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, 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 each 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.

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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. Similar to the TCJA, sweeping legislation or regulation could be enacted by any of these governmental authorities which may affect our tax burden. Changes may include numerous provisions that affect businesses, including changes to corporate tax rates, business-related exclusions, and deductions and credits. The outcome of regulatory proceedings regarding the extent to which a change in corporate tax rate will affect our utility customers and the time period over which that change will occur could significantly impact future earnings and cash flows. Separately, a challenge by a taxing authority, changes in taxing authorities’ administrative interpretations, decisions, policies and positions, our ability to utilize tax benefits such as carryforwards or tax credits, or a deviation from other tax-related assumptions may cause actual financial results to deviate from previous estimates.

OPERATING RISKS

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:

•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. Severe weather events, such as snow and ice storms (e.g., Winter Storm Uri), fires, tornadoes, strong winds, significant thunderstorms, flooding and drought, could negatively impact operations, including our ability to provide energy safely, reliably and profitably and our ability to complete construction, expansion or refurbishment of facilities as planned. Climate change may intensify these events or increase the frequency of occurrence;

•Acts of sabotage, terrorism or other malicious attacks. Damage to our facilities due to deliberate acts could lead to outages or other adverse effects;

•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;

•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;

•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;

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•Supply chain disruptions. We rely on various suppliers in our supply chain for the materials necessary to execute on our capital investment program. Our supply chain, material costs, and capital investment program may be negatively impacted by unanticipated price increases due to factors exacerbated by the COVID-19 pandemic, such as inflation, including wage inflation, or due to supply restrictions beyond our control or the control of our suppliers;

•Labor and labor relations. The cost of recruiting and retaining skilled technical labor or the unavailability of such resources could have a negative impact on our operations. There is competition and a tightening market for skilled employees. During the COVID-19 pandemic and subsequent recovery, there is a national trend of increased employee turnover. Our ability to transition and replace our retirement-eligible utility employees is a risk; at December 31, 2021, approximately 22% of our Electric Utilities and Gas Utilities 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 are represented by unions; and

•Public opposition. Opposition by members of public or special-interest groups could negatively impact our ability to operate our businesses.

The ongoing operation of our business involves the risks described above, in addition to risks associated with threats to our overall business model, such as electrification initiatives. Any of these risks could cause us to experience negative financial results and damage to our reputation and public confidence. These risks could 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.

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 ven